ITEM 1. BUSINESS
BACKGROUND
PPL Corporation, headquartered in Allentown, Pennsylvania, is an energy and utility holding company that was incorporated in 1994. Through its subsidiaries, PPL generates electricity from power plants in the northeastern, northwestern and southeastern U.S.; markets wholesale or retail energy primarily in the northeastern and northwestern portions of the U.S.; delivers electricity to customers in Pennsylvania, Kentucky, Virginia, Tennessee and the U.K. and natural gas to customers in Kentucky.
In 2011 and 2010, PPL completed two acquisitions:
·
On April 1, 2011, PPL, through its indirect, wholly owned subsidiary, PPL WEM, completed its acquisition of all the outstanding ordinary share capital of Central Networks East plc and Central Networks Limited, the sole owner of Central Networks West plc, together with certain other related assets and liabilities (collectively referred to as Central Networks and subsequently renamed WPD Midlands), from subsidiaries of E.ON AG. The consideration for the acquisition consisted of cash of $5.8 billion, including the repayment of $1.7 billion of affiliate indebtedness owed to subsidiaries of E.ON AG and $800 million of long-term debt assumed through consolidation. WPD Midlands operates two regulated distribution networks that serve five million end-users in the Midlands area of England.
·
On November 1, 2010, PPL acquired all of the limited liability company interests of E.ON U.S. LLC from a wholly owned subsidiary of E.ON AG. Upon completion of the acquisition, E.ON U.S. LLC was renamed LG&E and KU Energy LLC (LKE). LKE is engaged in regulated utility operations through its subsidiaries, LG&E and KU. The consideration for the acquisition consisted of cash of $6.8 billion, including the repayment of $4.3 billion of affiliate indebtedness owed to subsidiaries of E.ON AG, and $800 million of debt assumed through consolidation.
·
See Note 10 to the Financial Statements for additional information on both acquisitions.
The acquisitions of WPD Midlands and LKE: (1) substantially reapportion the mix of PPL's regulated and competitive businesses by increasing the regulated portion of its business; (2) strengthen PPL's credit profile; and (3) enhance rate-regulated growth opportunities as the regulated businesses make investments to meet environmental compliance requirements and improve infrastructure and customer reliability. The investment in regulated assets also provides earnings stability through regulated returns and the ability to recover prudently incurred capital investments, in contrast to the competitive supply business where earnings and cash flows are subject to market conditions. At December 31, 2011, PPL had:
·
$12.7 billion in operating revenues (including eight months from WPD Midlands, which are recorded on a one-month lag)
·
10.5 million end-users of its utility services (including 5 million end-users served by the WPD Midlands companies)
·
Approximately 19,000 MW of generation
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Approximately 18,000 full-time employees
In January 2011, PPL Energy Supply distributed its 100% membership interest in PPL Global to its parent, PPL Energy Funding (the parent holding company of PPL Energy Supply and PPL Global with no other material operations), to better align PPL's organizational structure with the manner in which it manages its businesses and reports segment information in its consolidated financial statements. The distribution separated the U.S.-based competitive energy marketing and supply business from the U.K.-based regulated electricity distribution business. See Note 9 to the Financial Statements for additional information.
At December 31, 2011 PPL's principal subsidiaries are shown below (* denotes an SEC registrant; LKE, LG&E and KU became SEC registrants effective June 1, 2011):
In addition to PPL Corporation, the other SEC registrants included in this filing are:
PPL Energy Supply, LLC, headquartered in Allentown, Pennsylvania, is an indirect wholly owned subsidiary of PPL formed in 2000 and is an energy company engaged through its subsidiaries in the generation and marketing of electricity, primarily in the northeastern and northwestern power markets of the U.S. PPL Energy Supply's major operating subsidiaries are PPL EnergyPlus and PPL Generation. As noted above, in January 2011, PPL Energy Supply distributed its 100% membership interest in PPL Global to its parent, PPL Energy Funding. For 2010 and 2009, the operating results of PPL Global, which represents the International Regulated segment, are classified as Discontinued Operations. At December 31, 2011, PPL Energy Supply owned or controlled 10,508 MW of electric power generation capacity and is implementing capital projects at certain of its existing generation facilities in Pennsylvania and Montana to provide 191 MW of additional generating capacity by the end of 2013.
PPL Electric Utilities Corporation, headquartered in Allentown, Pennsylvania, is a direct subsidiary of PPL incorporated in 1920 and a regulated public utility. PPL Electric delivers electricity in its Pennsylvania service territory and provides electricity supply to retail customers in that territory as a PLR under the Customer Choice Act.
LG&E and KU Energy LLC, headquartered in Louisville, Kentucky, is a holding company with regulated utility operations through its subsidiaries, LG&E and KU, and is a wholly owned subsidiary of PPL. LKE, formed in 2003, is the successor to a Kentucky entity incorporated in 1989.
Louisville Gas and Electric Company, headquartered in Louisville, Kentucky, is a regulated utility engaged in the generation, transmission, distribution and sale of electricity and the distribution and sale of natural gas in Kentucky. LG&E was incorporated in Kentucky in 1913. At December 31, 2011, LG&E owned 3,352 MW of electric power generation capacity and, subject to certain regulatory approvals, is implementing capital projects at certain of its existing generation facilities to provide 483 MW of additional generating capacity by 2016. LG&E also anticipates retiring 563 MW of generating capacity by the end of 2015 to meet certain environmental regulations. LG&E and KU jointly dispatch their generation units with the lowest cost generation used to serve their retail native load.
Kentucky Utilities Company, headquartered in Lexington, Kentucky, is a regulated utility engaged in the generation, transmission, distribution and sale of electricity in Kentucky, Virginia and Tennessee. KU was incorporated in Kentucky in 1912 and Virginia in 1991. KU serves its Virginia customers under the Old Dominion Power name while its Kentucky and Tennessee customers are served under the KU name. At December 31, 2011, KU owned 4,833 MW of electric power generation capacity and, subject to certain regulatory approvals, is implementing capital projects at certain of its existing generation facilities to provide 652 MW of additional generating capacity by 2016. KU also anticipates retiring 234 MW of generating capacity by the end of 2015 to meet certain environmental regulations. KU and LG&E jointly dispatch their generation units with the lowest cost generation used to serve their retail native load.
PPL's utility subsidiaries, and to a lesser extent, certain of its competitive supply subsidiaries, are subject to extensive regulation by the FERC including: wholesale sales of power and related transactions, electric transmission service, accounting practices, issuances and sales of securities, acquisitions and sales of utility properties and payments of dividends. PPL and LKE are subject to certain FERC regulations as holding companies under PUHCA and the Federal Power Act,
including with respect to accounting and record-keeping, inter-system sales of non-power goods and services and acquisitions of securities in, or mergers with, certain types of electric utility companies.
Successor and Predecessor Financial Presentation (LKE, LG&E and KU)
LKE's, LG&E's and KU's Financial Statements and related financial and operating data include the periods before and after PPL's acquisition of LKE on November 1, 2010 and have been segregated to present pre-acquisition activity as the Predecessor and post-acquisition activity as the Successor. Predecessor activity covers the time period prior to November 1, 2010. Successor activity covers the time period after October 31, 2010. Certain accounting and presentation methods were changed to acceptable alternatives to conform to PPL's accounting policies, and the cost bases of certain assets and liabilities were changed as of November 1, 2010 as a result of the application of push-down accounting. Consequently, the financial position, results of operations and cash flows for the Successor periods are not comparable to the Predecessor periods; however, the core operations of LKE, LG&E and KU have not changed as a result of the acquisition.
Segment Information
(PPL)
Following the November 1, 2010 acquisition of LKE, PPL is organized into four reportable segments: Kentucky Regulated, International Regulated, Pennsylvania Regulated and Supply. There were no changes to reportable segments in 2011.
(PPL Energy Supply)
In 2011, PPL Energy Supply operated in a single reportable segment. Prior to 2011, PPL Energy Supply's segments consisted of Supply and International Regulated. In January 2011, PPL Energy Supply distributed its 100% membership interest in PPL Global to its parent, PPL Energy Funding, to better align PPL's organizational structure with the manner in which it manages its businesses and reports segment information in its consolidated financial statements. For 2010 and 2009, the operating results of PPL Global, which represent the International Regulated segment, are classified as discontinued operations.
(PPL Electric, LKE, LG&E and KU)
PPL Electric, LKE, LG&E and KU each operate in a single reportable segment.
(PPL and PPL Energy Supply)
See Note 2 to the Financial Statements for financial information about the segments and geographic financial data.
·
Kentucky Regulated Segment (PPL)
Consists of the operations of LKE, which owns and operates regulated public utilities engaged in the generation, transmission, distribution and sale of electricity and the distribution and sale of natural gas, representing primarily the activities of LG&E and KU. The Kentucky Regulated segment also includes interest expense related to the 2010 Equity Units that were issued to partially finance the acquisition of LKE.
(PPL, LKE, LG&E and KU)
LKE became a wholly owned subsidiary of PPL on November 1, 2010. LG&E and KU are engaged in the regulated generation, transmission, distribution and sale of electricity in Kentucky and, in KU's case, Virginia and Tennessee. LG&E also engages in the distribution and sale of natural gas in Kentucky. LG&E provides electric service to approximately 394,000 customers in Louisville and adjacent areas in Kentucky, covering approximately 700 square miles in 9 counties. LG&E provides natural gas service to approximately 319,000 customers in its electric service area and 7 additional counties in Kentucky. KU provides electric service to approximately 512,000 customers in 77 counties in central, southeastern and western Kentucky; approximately 29,000 customers in 5 counties in southwestern Virginia; and fewer than 10 customers in Tennessee, covering approximately 4,800 non-contiguous square miles. KU also sells wholesale electricity to 12 municipalities in Kentucky under load following contracts. In Virginia, KU operates under the name Old Dominion Power Company.
Acquisition by PPL
In September 2010, the KPSC approved a settlement agreement among PPL and all of the intervening parties to PPL's joint application to the KPSC for approval of its acquisition of ownership and control of LKE. In the settlement agreement, the parties agreed that LG&E and KU would commit that no base rate increases would take effect before January 1, 2013. The rate increases for LG&E and KU that took effect on August 1, 2010 (as described below) are not impacted by the settlement. Under the terms of the settlement, LG&E and KU retain the right to seek approval for the deferral of "extraordinary and uncontrollable costs." Interim rate adjustments will continue to be permissible during that period through existing fuel, environmental and demand side management recovery mechanisms. The agreement also substitutes an acquisition savings shared deferral mechanism for the previous commitment that LG&E and KU file a synergies plan with the KPSC post-closing. This mechanism, which will be in place until the earlier of five years or the first day of the year in which a base rate increase becomes effective, permits LG&E and KU to each earn up to a 10.75% return on equity. Any earnings above a 10.75% return on equity will be shared with customers on a 50%/50% basis. The KPSC Order and the settlement agreement contained a number of other commitments by LG&E and KU with regard to operations, workforce, community involvement and other matters.
In October 2010, both the VSCC and the TRA approved the transfer of control of LKE to PPL. Certain of these Orders contained additional commitments with regard to operations, workforce, community involvement and other matters.
Also in October 2010, the FERC approved the application for the transfer of control of the utilities. The approval includes various conditional commitments, such as a continuation of certain existing undertakings with intervenors in prior cases, an agreement not to terminate certain KU municipal customer contracts prior to January 2017, an exclusion of any transaction-related costs from wholesale energy and tariff customer rates to the extent that LG&E and KU have agreed not to seek recovery of the same transaction-related cost from retail customers and agreements to coordinate with intervenors in certain open or ongoing matters.
See Note 6 to the Financial Statements for additional information on regulatory matters related to the acquisition.
Franchises and Licenses
LG&E and KU provide electric delivery service, and LG&E provides natural gas distribution service, in their various service territories pursuant to certain franchises, licenses, statutory service areas, easements and other rights or permissions granted by state legislatures, cities or municipalities or other entities.
Competition
There are currently no other electric public utilities operating within the electric service areas of LKE. Neither the Kentucky General Assembly nor the KPSC has adopted or approved a plan or timetable for retail electric industry competition in Kentucky. The nature or timing of any legislative or regulatory actions regarding industry restructuring and their impact on LKE, which may be significant, cannot currently be predicted. Virginia, formerly a deregulated jurisdiction, has enacted legislation which implemented a hybrid model of cost-based regulation. KU's operations in Virginia have been and remain regulated.
Alternative energy sources such as electricity, oil, propane and other fuels provide indirect competition for natural gas revenues of LKE. Marketers may also compete to sell natural gas to certain large end-users. LG&E's natural gas tariffs include gas price pass-through mechanisms relating to its sale of natural gas as a commodity; therefore, customer natural gas purchases from alternative suppliers do not generally impact profitability. However, some large industrial and commercial customers may physically bypass LG&E's facilities and seek delivery service directly from interstate pipelines or other natural gas distribution systems.
In April 2010, the KPSC commenced a proceeding to investigate the regulatory, financial and operational aspects of natural gas retail competition programs and the potential benefits to Kentucky consumers. A number of entities, including LG&E, were parties to the proceeding. In December 2010, the KPSC issued an Order in the proceeding declining to endorse natural gas competition at the retail level, noting the existence of a number of transition or oversight costs and an uncertain level of economic benefits in such programs. With respect to existing natural gas transportation programs available to large commercial or industrial users, the Order indicates that the KPSC will review utilities' current tariff structures, user thresholds and other terms and conditions of such programs, as part of such utilities' next regular natural gas rate cases.
Operating Revenues
LG&E serves approximately 394,000 electricity customers, and its electric transmission and distribution system territory covers more than 700 square miles in 9 counties. KU serves approximately 541,000 electricity customers, and its transmission and distribution system territory covers more than 4,800 non-contiguous square miles in 82 counties. LG&E purchases, transports, distributes or stores natural gas for approximately 319,000 customers in Kentucky. LG&E's natural gas service area covers more than 3,600 square miles in 16 counties. In 2011, 27% of LG&E's annual natural gas throughput was purchased by large commercial and industrial customers directly from alternate suppliers for delivery through LG&E's distribution system.
(PPL)
Details of operating revenues for the Kentucky Regulated segment by customer class for the year ended December 31, 2011 and the two months ended December 31, 2010 are shown below.
(LKE, LG&E and KU)
Details of operating revenues by customer class are shown below.
(a)
Includes wholesale and transmission revenues.
(b)
Includes intercompany power sales and transmission revenues, which are eliminated upon consolidation at LKE.
(PPL, LKE, LG&E and KU)
Power Supply
At December 31, 2011, LKE owned, controlled or had an ownership interest in generating capacity (summer rating) of 8,185 MW, of which 3,352 MW related to LG&E and 4,833 MW related to KU, in Kentucky, Indiana, and Ohio. See "Item 2. Properties - Kentucky Regulated Segment" for a complete list of LKE's generating facilities.
The system capacity of LKE's owned or controlled generation is based upon a number of factors, including the operating experience and physical condition of the units, and may be revised periodically to reflect changes in circumstances.
During 2011, LKE's power plants generated the following amounts of electricity.
(a)
The Midwestern generation represents power generated by and purchased from OVEC.
(b)
This generation represents a 1% increase for LKE, a 7% decrease for LG&E and an 8% increase for KU from 2010 output.
A significant portion of LG&E's and KU's generated electricity was used to supply its retail and municipal customer base.
LG&E and KU jointly dispatch their generation units with the lowest cost generation used to serve their retail native load. When LG&E has excess generation capacity after serving its own retail native load and its generation cost is lower than that of KU, KU purchases electricity from LG&E. When KU has excess generation capacity after serving its own retail native load and its generation cost is lower than that of LG&E, LG&E purchases electricity from KU.
See "Item 2. Properties - Kentucky Regulated Segment" for additional information regarding LG&E's and KU's plans for capital projects, subject to certain regulatory approvals, that are expected to provide 483 MW and 652 MW of additional electric generating capacity by 2016. LG&E and KU also anticipate retiring 563 MW and 234 MW of generating capacity by the end of 2015 to meet certain environmental regulations.
Fuel Supply
Coal is expected to be the predominant fuel used by LG&E and KU for baseload generation for the foreseeable future, with natural gas and oil being used for intermediate and peaking capacity and flame stabilization in coal-fired boilers.
Fuel inventory is maintained at levels estimated to be necessary to avoid operational disruptions at coal-fired generating units. Reliability of coal deliveries can be affected from time to time by a number of factors including fluctuations in demand, coal mine production issues and other supplier or transporter operating difficulties.
LG&E and KU have entered into coal supply agreements with various suppliers for coal deliveries through 2016 and normally augment their coal supply agreements with spot market purchases.
For their existing units, LG&E and KU expect for the foreseeable future to purchase most of their coal from western Kentucky, southern Indiana, southern Illinois and Ohio. The use of high sulfur coal will increase in 2012 due to the installation of scrubbers at KU's E.W. Brown plant. In 2012 and beyond, LG&E and KU may purchase certain quantities of ultra-low sulfur content coal from Wyoming for blending at TC2. Coal is delivered to the generating plants by barge, truck and rail.
(PPL, LKE and LG&E)
Natural Gas Supply
Five underground natural gas storage fields, with a current working natural gas capacity of approximately 15 Bcf, are used in providing natural gas service to LG&E's firm sales customers. By using natural gas storage facilities, LG&E avoids the costs typically associated with more expensive pipeline transportation capacity to serve peak winter heating loads. Natural gas is stored during the summer season for withdrawal during the following winter heating season. Without this storage capacity, LG&E would be required to purchase additional natural gas and pipeline transportation services during winter months when customer demand increases and the prices for natural gas supply and transportation services are typically at their highest. Several suppliers under contracts of varying duration provide competitively priced natural gas. At December 31, 2011, LG&E had an 11 Bcf inventory balance of natural gas stored underground with a carrying value of $53 million.
LG&E has a portfolio of supply arrangements of varying terms with a number of suppliers designed to meet its firm sales obligations. These natural gas supply arrangements include pricing provisions that are market-responsive. In tandem with pipeline transportation services, these natural gas supplies provide the reliability and flexibility necessary to serve LG&E's natural gas customers.
LG&E purchases natural gas supply transportation services from two pipelines. LG&E has contracts with one pipeline that are subject to termination by LG&E between 2013 and 2018. Total winter capacity under these contracts is 195,000 MMBtu/day and summer capacity is 88,000 MMBtu/day. LG&E has a contract with the other pipeline that expires in October 2012. Total winter and summer capacity under this contract is 51,000 MMBtu/day during both seasons. That contract has been renegotiated through 2014 for a total capacity of 20,000 MMBtu/day during both the winter and summer seasons beginning in November 2012.
(PPL, LKE, LG&E and KU)
Rates and Regulation
LG&E is subject to the jurisdiction of the KPSC and the FERC, and KU is subject to the jurisdiction of the KPSC, the FERC, the VSCC and the TRA. LG&E and KU operate under a FERC-approved open access transmission tariff. LG&E and KU contract with the Tennessee Valley Authority, to act as their transmission reliability coordinator, and Southwest Power Pool, Inc. (SPP), to function as their independent transmission operator, pursuant to FERC requirements. The contract with SPP expires on August 31, 2012. LG&E and KU have received FERC approval to transfer from SPP to TranServ International, Inc. as their independent transmission operator beginning September 1, 2012. Approval from the KPSC is also required, and an application requesting approval was filed in January 2012.
LG&E's and KU's Kentucky base rates are calculated based on a return on capitalization (common equity, long-term debt and notes payable) including certain adjustments to exclude non-regulated investments and environmental compliance costs recovered separately through the ECR mechanism. As such, regulatory assets generally earn a return.
KU's Virginia base rates are calculated based on a return on rate base (net utility plant plus working capital less deferred taxes and miscellaneous deductions). All regulatory assets and liabilities, except the levelized fuel factor, are excluded from the return on rate base utilized in the calculation of Virginia base rates; therefore, no return is earned on the related assets.
KU's rates to municipal customers for wholesale requirements are calculated based on annual updates to a rate formula that utilizes a return on rate base (net utility plant plus working capital less deferred taxes and miscellaneous deductions). All regulatory assets and liabilities are excluded from the return on rate base utilized in the development of municipal rates; therefore, no return is earned on the related assets.
See Note 6 to the Financial Statements for additional information on cost recovery mechanisms.
Kentucky Rate Case
In January 2010, LG&E and KU filed applications with the KPSC requesting increases in electric base rates of approximately 12%, or $95 million for LG&E and $135 million for KU annually. In addition, LG&E requested an increase in its natural gas base rates of approximately 8%, or $23 million annually. In June 2010, LG&E and KU and all of the intervenors, except the Attorney General, agreed to a stipulation providing for increases in LG&E's electric base rates of $74 million annually, LG&E's natural gas base rates of $17 million annually and KU's electric base rates of $98 million annually. All parties, except the Attorney General, jointly filed a request with the KPSC to approve such stipulation. An Order in the proceeding
was issued in July 2010, approving all of the provisions in the stipulation. The KPSC Order determined a return on equity range of 9.75% to 10.75% to be reasonable and noted that the stipulation was within such range. The new rates became effective on August 1, 2010.
(PPL, LKE and KU)
Virginia Rate Case
In April 2011, KU filed an application with the VSCC requesting an increase in electric base rates for its Virginia jurisdictional customers of $9 million annually, or 14%. In September 2011, a settlement stipulation was reached between KU and the VSCC Staff and filed with the VSCC for consideration. In October 2011, the VSCC approved the stipulation with two modifications that were accepted by KU. The VSCC issued an Order closing the proceeding in October 2011. The approved revenue increase was $7 million annually, based on a return on equity of 10.3%, with new base rates effective November 1, 2011.
FERC Wholesale Rate Case
In September 2008, KU filed an application with the FERC for increases in electric base rates applicable to wholesale power sales contracts or interchange agreements involving, collectively, 12 Kentucky municipalities. The application requested a shift from an all-in stated unit charge rate to an unbundled formula rate. This application was approved by the FERC, and annual adjustments are made to the rates charged to the Kentucky municipalities with applications being submitted each May and revised rates taking effect on July 1. In May 2011, KU submitted to the FERC the annual adjustments to the formula rate which incorporated certain proposed decreases. These rates became effective as of July 1, 2011, with no issues raised by the wholesale requirements customers or the FERC.
·
International Regulated Segment (PPL)
Includes WPD, a regulated electricity distribution company in the U.K.
WPD, through indirect wholly owned subsidiaries, operates four of the 15 distribution networks providing electricity service in the U.K. With the April 2011 acquisition of WPD Midlands, the total number of end-users served has more than doubled totaling 7.8 million across 21,585 square miles in Wales, southwest and central England. See Note 10 to the Financial Statements for additional information on the acquisition.
Details of revenue by category for the years ended December 31 are shown below.
(a)
The amounts for 2011 are not comparable to 2010 or 2009 as WPD Midlands was acquired in April 2011. 2011 includes eight months of activity as WPD Midlands' results are recorded on a one-month lag.
WPD's energy-related businesses revenues include ancillary activities that support the distribution business, including telecommunications and real estate. WPD's telecommunication revenues are from the rental of fiber optic cables primarily attached to WPD's overhead electricity distribution network. WPD also provides meter services to businesses across the U.K.
Franchise and Licenses
WPD is authorized by Ofgem to provide electric distribution services within its concession areas and service territories, subject to certain conditions and obligations. For instance, WPD is subject to Ofgem regulation of the prices it can charge and the quality of service it must provide, and WPD can be fined or have its licenses revoked if it does not meet the mandated standard of service.
Competition
Although WPD operates in non-exclusive concession areas in the U.K., it currently faces little competition with respect to end-users connected to its network. WPD's four distribution businesses, WPD (South West), WPD (South Wales), WPD (West Midlands) and WPD (East Midlands), are thus regulated monopolies which operate under regulatory price controls.
Revenue and Regulation
The operations of WPD (South West), WPD (South Wales), WPD (East Midlands) and WPD (West Midlands) are regulated by Ofgem under the direction of the Gas and Electricity Markets Authority. The Electricity Act 1989 provides the fundamental legal framework of electricity companies and established licenses that required each of the Distribution Network Operators (DNOs) to develop, maintain and operate efficient distribution networks. Ofgem has established a price control mechanism that restricts the amount of revenue that can be earned by regulated business and provides for an increase or reduction in revenues based on incentives or penalties for exceeding or underperforming against pre-established targets.
This regulatory structure is an incentive-based regulatory structure in comparison to the U.S. utility businesses which operate under a cost-based regulatory framework. Under the UK regulatory structure, electricity distribution revenues are currently set every five years, but extending to eight years in the next price control period beginning in April 2015. The revenue that DNOs can earn in each of the five years is the sum of: i) the regulator's view of efficient operating costs, ii) a return on the capital from the RAV plus an annual adjustment for the inflation determined by Retail Price Index (RPI) for the prior calendar year, iii) a return of capital from the RAV (i.e. depreciation), and iv) certain pass-through costs over which the DNO has no control. Additionally, incentives are provided for a range of activities including exceeding certain reliability and customer service targets.
WPD is currently operating under DPCR5 which was completed in December 2009 and is effective for the period from April 1, 2010 through March 31, 2015. Ofgem allowed WPD (South West) and WPD (South Wales) an average increase in total revenues, before inflationary adjustments, of 6.9% in each of the five years and WPD Midlands an average increase in total revenues, before inflationary adjustments, of 4.5% in each of the five years. The revenue increase includes reimbursement for higher operating and capital costs to be incurred driven by additional requirements. In DPCR5, Ofgem decoupled WPD's allowed revenue from volume delivered over the five-year price control period. However, in any fiscal period WPD's revenue could be negatively affected if its tariffs and the volume delivered do not fully recover the allowed revenue for a given period. Any under recovery would be recovered in the next regulatory year, but would not be recorded as a receivable in the current period. Any over recovery would be reflected in the current period as a liability and would not be included in revenue.
In addition to providing a base revenue allowance, Ofgem has established incentive mechanisms to provide significant opportunities to enhance overall returns by improving network efficiency, reliability and customer service. Some of the more significant incentive mechanisms under DPCR5 include:
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Interruptions Incentive Scheme (IIS) - This incentive has two major components: 1) Customer interruptions and 2) Customer minutes lost and is designed to incentivize the DNOs to invest and operate their networks to manage and reduce both the frequency and duration of power outages experienced by customers. The target for each DNO is based on an average of the data from the prior price control period.
Beginning April 1, 2012, an additional customer satisfaction incentive mechanism will be implemented that will include a customer satisfaction survey, a complaints metric and a measure of stakeholder engagement. This incentive will replace the customer response telephone performance incentive that was effective April 1, 2010.
·
Line Loss Incentive - This incentive existed in the prior price control review and is designed to incentivize DNOs to invest in lower loss equipment, to change the way they operate their systems to reduce losses, and to detect theft and unregistered meters. The targets for each of WPD's four DNOs are set based on their performance during DPCR4. In DPCR5, Ofgem introduced a two year lag in reporting losses to allow for all settlement data to be received. WPD has a $170 million liability recorded at December 31, 2011, calculated in accordance with an accepted methodology, related to the close-out of line losses for the prior price control period, DPCR4. Ofgem is currently consulting on the methodology used to calculate the final line loss incentive/penalty for DPCR4. In October 2011, Ofgem issued a consultation paper citing two potential changes to the methodology, both of which would result in a reduction of the liability; however, it is uncertain at this time whether any changes will be made. Ofgem is expected to make a decision before the end of 2012.
·
Information Quality Incentive (IQI) - The IQI is designed to incentivize the DNOs to provide good quality information when they submit their business plans to Ofgem during the price control process and to execute the plan they submitted. The IQI eliminates the distinction between capital expenditure and operating expense and instead looks at total expenditure. Total expenditure is allocated 85% to "slow pot" which is added to RAV and recovered over 20 years through the regulatory depreciation of the RAV and 15% to "fast pot" which is recovered during the current price control review period. The IQI then provides for incentives or penalties at the end of DPCR5 based on the ratio of actual expenditures to the expenditures submitted to Ofgem that were the basis for the revenues allowed during the five-year price control review period.
At the beginning of DPCR5, WPD was awarded $301 million in incentive revenue of which $222 million will be included in revenue throughout the current price control period with the balance recovered over subsequent price control periods. Additional incentive revenue primarily from the IIS of $30 million related to performance for the regulatory year ended March 31, 2011 and will be included in revenues for the 2012-2013 regulatory year.
In October 2010, Ofgem announced a new pricing model that will be effective for the U.K. electricity distribution sector, including WPD, beginning April 2015. The model, known as RIIO (Revenues = Incentives + Innovation + Outputs), is intended to encourage investment in regulated infrastructure. Key components of the model are: an extension of the price review period to eight years, increased emphasis on outputs and incentives, enhanced stakeholder engagement including network customers, a stronger incentive framework to encourage more efficient investment and innovation, expansion of the current Low Carbon Network Fund to stimulate innovation and continued use of a single weighted average cost of capital. Ofgem has also indicated that the depreciation of the RAV for RAV additions after April 1, 2015 will change from 20 years to 45 years. At this time, management does not expect the effect of RIIO to be significant to WPD's financial results. See "Item 1A.
ITEM 1A. RISK FACTORS
The Registrants face various risks associated with their businesses. Our businesses, financial condition, cash flows or results of operations could be materially adversely affected by any of these risks. In addition, this report also contains forward-looking and other statements about our businesses that are subject to numerous risks and uncertainties. See "Forward-Looking Information," "Item 1. Business," "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" and Note 15 to the Financial Statements for more information concerning the risks described below and for other risks, uncertainties and factors that could impact our businesses and financial results.
As used in this Item 1A., the terms "we," "our" and "us" generally refer to PPL and its consolidated subsidiaries taken as a whole, or to PPL Energy Supply and its consolidated subsidiaries taken as a whole within the Supply segment discussions, or PPL Electric and its consolidated subsidiaries taken as a whole within the Pennsylvania Regulated segment discussion, or LKE and its consolidated subsidiaries taken as a whole within the Kentucky Regulated segment discussion.
Risks Related to All Segments
(PPL, PPL Energy Supply, PPL Electric, LKE, LG&E and KU)
We plan to selectively pursue growth of generation, transmission and distribution capacity, which involves a number of uncertainties and may not achieve the desired financial results.
We plan to pursue expansion of our generation, transmission and distribution capacity over the next several years through power uprates at certain of our existing power plants, the potential construction of new power plants, the potential acquisition of existing plants, the potential construction or acquisition of transmission and distribution projects and capital investments to upgrade transmission and distribution infrastructure. We will rigorously scrutinize opportunities to expand our generating capability and may determine not to proceed with any expansion. These types of projects involve numerous risks. Any planned power uprates could result in cost overruns, reduced plant efficiency and higher operating and other costs. With respect to the construction of new plants, the acquisition of existing plants, or the construction or acquisition of transmission and distribution projects, we may be required to expend significant sums for preliminary engineering, permitting, resource exploration, legal and other expenses before it can be established whether a project is feasible, economically attractive or capable of being financed. Expansion in our regulated businesses is dependent on future load or service requirements and subject to applicable regulatory processes. The success of both a new or acquired project would likely be contingent, among other things, upon the negotiation of satisfactory operating contracts, obtaining acceptable financing and maintaining acceptable credit ratings, as well as receipt of required and appropriate governmental approvals. If we were unable to complete construction or expansion of a project, we may not be able to recover our investment in the project. Furthermore, we might be unable to operate any new or acquired plants as efficiently as projected, which could result in higher than projected operating and other costs and reduced earnings.
Adverse conditions in the economic and financial markets in which we operate could adversely affect our financial condition and results of operations.
Adverse conditions in the financial markets during 2008 and the associated contraction of liquidity in the wholesale energy markets contributed significantly to declines in wholesale energy prices, significantly impacting our earnings during the second half of 2008 and the first half of 2009. The breadth and depth of these negative economic conditions had a wide-ranging impact on the U.S. and international business environment, including our businesses. As a result of the economic downturn, demand for energy commodities has declined significantly. This reduced demand will continue to impact the key domestic wholesale energy markets we serve (such as PJM) and our Pennsylvania and Kentucky utility businesses. The combination of lower demand for power and natural gas and other fuels has put downward price pressure on wholesale energy markets in general, further impacting our energy marketing results. In general, current economic and commodity market conditions will continue to challenge predictability regarding our unhedged future energy margins, liquidity and overall financial condition.
Our businesses are heavily dependent on credit and capital, among other things, for capital expenditures and providing collateral to support hedging in our energy marketing business. Global bank credit capacity declined and the cost of renewing or establishing new credit facilities increased significantly in 2008, primarily as a result of general credit concerns nationwide, thereby introducing uncertainties as to our businesses' ability to enter into long-term energy commitments or reliably estimate the longer-term cost and availability of credit. Although bank credit conditions have improved since mid-2009, and we currently expect to have adequate access to needed credit and capital based on current conditions, deterioration in the financial markets could adversely affect our financial condition and liquidity. Additionally, regulations to be adopted to implement the Dodd-Frank Act may impose requirements on our businesses and the businesses of others with whom we
contract such as banks or other counterparties, or simply result in increased costs to conduct our business or access sources of capital and liquidity upon which the conduct of our businesses is dependent.
Our operating revenues could fluctuate on a seasonal basis, especially as a result of extreme weather conditions.
Our businesses are subject to seasonal demand cycles. For example, in some markets demand for, and market prices of, electricity peak during hot summer months, while in other markets such peaks occur in cold winter months. As a result, our overall operating results in the future may fluctuate substantially on a seasonal basis if weather conditions such as heat waves, extreme cold, unseasonably mild weather or severe storms occur. The patterns of these fluctuations may change depending on the type and location of our facilities and the terms of our contracts to sell electricity.
Operating expenses could be affected by weather conditions, including storms, as well as by significant man-made or accidental disturbances, including terrorism or natural disasters.
Weather and these other factors can significantly affect our profitability or operations by causing outages, damaging infrastructure and requiring significant repair costs. Storm outages and damage often directly decrease revenues or increase expenses, due to reduced usage and higher restoration charges. In addition, weather and other disturbances may affect capital markets and general economic conditions and impact future growth.
Our businesses are subject to physical, market and economic risks relating to potential effects of climate change.
Climate change may produce changes in weather or other environmental conditions, including temperature or precipitation levels, and thus may impact consumer demand for electric power. Temperature increases could result in increased overall electricity consumption or peaks and precipitation changes could result in altered availability of water for hydro generation or plant cooling operations. These or other meteorological changes could lead to increased operating costs, capital expenses or power purchase costs. Greenhouse gas regulation could increase the cost of electric power, particularly power generated by fossil-fuels, and such increases could have a depressive effect on regional economies. Reduced economic and consumer activity in our service areas -- both generally and specific to certain industries and consumers accustomed to previously lower cost power -- could reduce demand for the power we generate, market and deliver. Also, demand for our energy-related services could be similarly lowered should consumers' preferences or market factors move toward favoring energy efficiency, low-carbon power sources or reduced electric usage generally.
We cannot predict the outcome of the legal proceedings and investigations currently being conducted with respect to our current and past business activities. An adverse determination could have a material adverse effect on our financial condition, results of operations or cash flows.
We are involved in legal proceedings, claims and litigation and subject to ongoing state and federal investigations arising out of our business operations, the most significant of which are summarized in "Legal Matters," "Regulatory Issues" and "Environmental Matters - Domestic" in Note 15 to the Financial Statements. We cannot predict the ultimate outcome of these matters, nor can we reasonably estimate the costs or liabilities that could potentially result from a negative outcome in each case.
We could be negatively affected by rising interest rates, downgrades to our bond credit ratings or other negative developments in our ability to access capital markets.
In the ordinary course of business, we are reliant upon adequate long-term and short-term financing means to fund our significant capital expenditures, debt interest or maturities and operating needs. As a capital-intensive business, we are sensitive to developments in interest rate levels; credit rating considerations; insurance, security or collateral requirements; market liquidity and credit availability and refinancing opportunities necessary or advisable to respond to credit market changes. Changes in these conditions could result in increased costs and decreased liquidity to our regulated utility businesses.
A downgrade in our credit ratings could negatively affect our ability to access capital and increase the cost of maintaining our credit facilities and any new debt.
Credit ratings assigned by Moody's, Fitch and S&P to our businesses and their financial obligations have a significant impact on the cost of capital incurred by our businesses. Although we do not expect these ratings to limit our ability to fund short-term liquidity needs or access new long-term debt, any ratings downgrade could increase our short-term borrowing costs and negatively affect our ability to fund short-term liquidity needs and access new long-term debt. See "Item 7. Management's
Discussion and Analysis of Financial Condition and Results of Operations - Financial Condition - Liquidity and Capital Resources - Ratings Triggers" for additional information on the impact of a downgrade in our credit rating.
Significant increases in our operation and maintenance expenses, including health care and pension costs, could adversely affect our future earnings and liquidity.
We continually focus on limiting and reducing where possible our operation and maintenance expenses. However, we expect to continue to face increased cost pressures in our operations. Increased costs of materials and labor may result from general inflation, increased regulatory requirements (especially in respect of environmental regulations), the need for higher-cost expertise in the workforce or other factors. In addition, pursuant to collective bargaining agreements, we are contractually committed to provide specified levels of health care and pension benefits to certain current employees and retirees. We provide a similar level of benefits to our management employees. These benefits give rise to significant expenses. Due to general inflation with respect to such costs, the aging demographics of our workforce and other factors, we have experienced significant health care cost inflation in recent years, and we expect our health care costs, including prescription drug coverage, to continue to increase despite measures that we have taken and expect to take to require employees and retirees to bear a higher portion of the costs of their health care benefits. In addition, we expect to continue to incur significant costs with respect to the defined benefit pension plans for our employees and retirees. The measurement of our expected future health care and pension obligations, costs and liabilities is highly dependent on a variety of assumptions, most of which relate to factors beyond our control. These assumptions include investment returns, interest rates, health care cost trends, benefit improvements, salary increases and the demographics of plan participants. If our assumptions prove to be inaccurate, our future costs and cash contribution requirements to fund these benefits could increase significantly.
We may be required to record impairment charges in the future for certain of our investments, which could adversely affect our earnings.
Under GAAP, we are required to test our recorded goodwill for impairment on an annual basis, or more frequently if events or circumstances indicate that these assets may be impaired. Although no goodwill impairments were recorded based on our annual review in the fourth quarter of 2011, we are unable to predict whether future impairment charges may be necessary.
We also review our long-lived assets, including equity investments, for impairment when events or circumstances indicate that the carrying value of these assets may not be recoverable. See Notes 9 and 18 to the Financial Statements for additional information on impairment charges taken during the reporting periods. We are unable to predict whether impairment charges, or other losses on sales of other assets or businesses, may occur in future years.
We may incur liabilities in connection with discontinued operations.
In connection with various divestitures, we have indemnified or guaranteed parties against certain liabilities and with respect to certain transactions. These indemnities and guarantees relate to, among other things, liabilities which may arise with respect to the period during which we or our subsidiaries operated the divested business, and to certain ongoing contractual relationships and entitlements with respect to which we or our subsidiaries made commitments in connection with the divestiture.
We are subject to liability risks relating to our generation, transmission and distribution businesses.
The conduct of our physical and commercial operations subjects us to many risks, including risks of potential physical injury, property damage or other financial liability, caused to or caused by employees, customers, contractors, vendors, contractual or financial counterparties and other third parties.
Our facilities may not operate as planned, which may increase our expenses or decrease our revenues and, thus, have an adverse effect on our financial performance.
Operation of power plants, transmission and distribution facilities, information technology systems and other assets and activities subjects us to a variety of risks, including the breakdown or failure of equipment, accidents, security breaches, viruses or outages affecting information technology systems, labor disputes, obsolescence, delivery/transportation problems and disruptions of fuel supply and performance below expected levels. These events may impact our ability to conduct our businesses efficiently or lead to increased costs, expenses or losses. Operation of our delivery systems below our expectations may result in lost revenue or increased expense, including higher maintenance costs which may not be recoverable from customers. Planned and unplanned outages at our power plants may require us to purchase power at then-current market prices to satisfy our commitments or, in the alternative, pay penalties and damages for failure to satisfy them.
Although we maintain customary insurance coverage for certain of these risks, no assurance can be given that such insurance coverage will be sufficient to compensate us fully in the event losses occur.
The operation of our businesses is subject to cyber-based security and integrity risk.
Numerous functions affecting the efficient operation of our businesses are dependent on the secure and reliable storage, processing and communication of electronic data and the use of sophisticated computer hardware and software systems. The operation of our generation plants, including the Susquehanna nuclear plant, and of our energy and fuel trading businesses, as well as our transmission and distribution operations are all reliant on cyber-based technologies and, therefore, subject to the risk that such systems could be the target of disruptive actions, principally by terrorists or vandals, or otherwise be compromised by unintentional events. As a result, operations could be interrupted, property could be damaged and customer information lost or stolen, causing us to incur significant losses of revenues, other substantial liabilities and damages and costs to replace or repair damaged equipment.
We are subject to risks associated with federal and state tax laws and regulations.
Changes in tax law as well as the inherent difficulty in quantifying potential tax effects of business decisions could negatively impact our results of operations. We are required to make judgments in order to estimate our obligations to taxing authorities. These tax obligations include income, property, sales and use and employment-related taxes. We also estimate our ability to utilize tax benefits and tax credits. Due to the revenue needs of the jurisdictions in which our businesses operate, various tax and fee increases may be proposed or considered. We cannot predict whether such tax legislation or regulation will be introduced or enacted or the effect of any such changes on our businesses. If enacted, any changes could increase tax expense and could have a significant negative impact on our results of operations and cash flows.
We are subject to the risk that our workforce and its knowledge base may become depleted in coming years.
PPL is experiencing an increase in attrition due primarily to the number of retiring employees. Over the next five years, 38% of PPL's workforce is projected to leave the company, with the risk that critical knowledge will be lost and that it may be difficult to replace departed personnel due to a declining trend in the number of available workers and an increase in competition for such workers.
(PPL, PPL Energy Supply and LKE)
Risk Related to Registrant Holding Companies
PPL's, PPL Energy Supply's and LKE's cash flows and ability to meet their obligations with respect to indebtedness and under guarantees, and PPL's ability to pay dividends, largely depends on the financial performance of their subsidiaries and, as a result, is effectively subordinated to all existing and future liabilities of those subsidiaries.
PPL, PPL Energy Supply and LKE are holding companies and conduct their operations primarily through subsidiaries. Substantially all of the consolidated assets of these Registrants are held by such subsidiaries. Accordingly, their cash flows and ability to meet their debt and guaranty obligations, as well as PPL's ability to pay dividends, are largely dependent upon the earnings of those subsidiaries and the distribution or other payment of such earnings in the form of dividends, distributions, loans or advances or repayment of loans and advances. The subsidiaries are separate and distinct legal entities and have no obligation to pay any amounts due from their parents or to make any funds available for such a payment. The ability of the subsidiaries of the Registrants to pay dividends or distributions to such Registrants in the future will depend on the subsidiaries' future earnings and cash flows and the needs of their businesses, and may be restricted by their obligations to holders of their outstanding debt and other creditors, as well as any contractual or legal restrictions in effect at such time, including the requirements of state corporate law applicable to payment of dividends and distributions, and regulatory requirements, including restrictions on the ability of PPL Electric, LG&E and KU to pay dividends under Section 305(a) of the Federal Power Act.
Because PPL, PPL Energy Supply and LKE are holding companies, their debt and guaranty obligations are effectively subordinated to all existing and future liabilities of their subsidiaries. Therefore, PPL's, PPL Energy Supply's and LKE's rights and the rights of their creditors, including rights of any debt holders, to participate in the assets of any of their subsidiaries, in the event that such a subsidiary is liquidated or reorganized, will be subject to the prior claims of such subsidiary's creditors. Although certain agreements to which certain subsidiaries are parties limit their ability to incur additional indebtedness, PPL, PPL Energy Supply and LKE and their subsidiaries retain the ability to incur substantial additional indebtedness and other liabilities. In addition, if PPL elects to receive distributions of earnings from its foreign
operations, PPL may incur U.S. income taxes, net of any available foreign tax credits, on such amounts. Distributions to PPL from its international projects are, in some countries, also subject to withholding taxes.
(PPL, PPL Electric, LKE, LG&E and KU)
Risks Related to Domestic Regulated Utility Operations
Our domestic regulated utility businesses face many of the same risks, in addition to those risks that are unique to the Kentucky Regulated segment and the Pennsylvania Regulated segment. Set forth below are risk factors common to both domestic regulated segments, followed by sections identifying separately the risks specific to each of these segments.
Our profitability is highly dependent on our ability to recover the costs of providing energy and utility services to our customers and earn an adequate return on our capital investments. Regulators may not approve the rates we request.
We currently provide services to our utility customers at rates approved by one or more federal or state regulatory commissions, including those commissions referred to below. While such regulation is generally premised on the recovery of prudently incurred costs and a reasonable rate of return on invested capital, the rates that we may charge our regulated generation, transmission and distribution customers are subject to authorization of the applicable regulatory authorities. There can be no assurance that such regulatory authorities will consider all of our costs to have been prudently incurred or that the regulatory process by which rates are determined will always result in rates that achieve full recovery of our costs or an adequate return on our capital investments. While our rates are generally regulated based on an analysis of our costs incurred in a base year, the rates we are allowed to charge may or may not match our costs at any given time. With respect to PPL's November 1, 2010 acquisition of LKE, each of LG&E and KU has agreed with the KPSC, subject to certain limited exceptions such as fuel and environmental cost recoveries, that no base rate increases would take effect for their Kentucky retail customers before January 1, 2013. Our regulated utility businesses are subject to substantial capital expenditure requirements over the next several years, which will require rate increase requests to the regulators. If our costs are not adequately recovered through rates, it could have an adverse affect on our business, results of operations, cash flows or financial condition.
Our domestic utility businesses are subject to significant and complex governmental regulation.
Various federal and state entities, including but not limited to the FERC, KPSC, VSCC, TRA and PUC regulate many aspects of the domestic utility operations of PPL, including:
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the rates that we may charge and the terms and conditions of our service and operations;
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financial and capital structure matters;
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siting, construction and operation of facilities;
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mandatory reliability and safety standards and other standards of conduct;
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accounting, depreciation and cost allocation methodologies;
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tax matters;
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affiliate restrictions;
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acquisition and disposal of utility assets and securities; and
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various other matters.
Such regulations or changes thereto may subject us to higher operating costs or increased capital expenditures and failure to comply could result in sanctions or possible penalties. In any rate-setting proceedings, federal or state agencies, intervenors and other permitted parties may challenge our rate requests, and ultimately reduce, alter or limit the rates we seek.
We could be subject to higher costs and/or penalties related to mandatory reliability standards.
Under the Energy Policy Act of 2005, owners and operators of the bulk power transmission system are now subject to mandatory reliability standards promulgated by the NERC and enforced by the FERC. Compliance with reliability standards may subject us to higher operating costs and/or increased capital expenditures, and violations of these standards could result in substantial penalties which may not be recoverable from customers.
Changes in transmission and wholesale power market structures could increase costs or reduce revenues.
Wholesale revenues fluctuate with regional demand, fuel prices and contracted capacity. Changes to transmission and wholesale power market structures and prices may occur in the future, are not predictable and may result in unforeseen
effects on energy purchases and sales, transmission and related costs or revenues. These can include commercial or regulatory changes affecting power pools, exchanges or markets in which PPL participates.
Our domestic regulated businesses undertake significant capital projects and these activities are subject to unforeseen costs, delays or failures, as well as risk of inadequate recovery of resulting costs.
The domestic regulated utility businesses are capital intensive and require significant investments in energy generation (in the case of LG&E and KU) and transmission, distribution and other infrastructure projects, such as projects for environmental compliance and system reliability. The completion of these projects without delays or cost overruns is subject to risks in many areas, including:
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approval, licensing and permitting;
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land acquisition and the availability of suitable land;
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skilled labor or equipment shortages;
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construction problems or delays, including disputes with third party intervenors;
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increases in commodity prices or labor rates;
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contractor performance;
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environmental considerations and regulations;
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weather and geological issues; and
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political, labor and regulatory developments.
Failure to complete our capital projects on schedule or on budget, or at all, could adversely affect our financial performance, operations and future growth if such expenditures are not granted rate recovery by our regulators.
Risks Specific to Kentucky Regulated Segment
(PPL, LKE, LG&E and KU)
The costs of compliance with, and liabilities under, environmental laws are significant and are subject to continuing changes.
Extensive federal, state and local environmental laws and regulations are applicable to LG&E's and KU's generation business, including its air emissions, water discharges and the management of hazardous and solid waste, among other business-related activities; and the costs of compliance or alleged non-compliance cannot be predicted but could be material. In addition, our costs may increase significantly if the requirements or scope of environmental laws, regulations or similar rules are expanded or changed. Costs may take the form of increased capital or operating and maintenance expenses, monetary fines, penalties or forfeitures or other restrictions. Many of these environmental law considerations are also applicable to the operations of our key suppliers, or customers, such as coal producers and industrial power users, and may impact the costs of their products or demand for our services.
On-going changes in environmental regulations or their implementation requirements and our compliance strategies relating thereto entail a number of uncertainties.
The environmental standards governing LG&E's and KU's businesses, particularly as applicable to coal-fired generation and related activities, continue to be subject to uncertainties due to ongoing rulemakings and other regulatory developments, legislative activities, and litigation. The uncertainties associated with these developments introduce risks to our management of operations and regulatory compliance. Environmental developments, including revisions to applicable standards, changes in compliance deadlines, and invalidation of rules on appeal may require major changes in compliance strategies, operations or assets or adjustments to prior plans. Depending on the extent, frequency and timing of such changes, the companies may be subject to inconsistent requirements under multiple regulatory programs, compressed windows for decision-making and short compliance deadlines that may require aggressive schedules for construction, permitting, and other regulatory approvals. Under such circumstances, the companies may face higher risks of unsuccessful implementation of environmental-related business plans, noncompliance with applicable environmental rules, or increased costs of implementation.
Risks Specific to Pennsylvania Regulated Segment
(PPL and PPL Electric)
We may be subject to higher transmission costs and other risks as a result of PJM's regional transmission expansion plan (RTEP) process.
PJM and the FERC have the authority to require upgrades or expansion of the regional transmission grid, which can result in substantial expenditures for transmission owners. As discussed in Note 8 to the Financial Statements, we expect to make substantial expenditures to construct the Susquehanna-Roseland transmission line that PJM has determined is necessary for the reliability of the regional transmission grid. Although the FERC has granted our request for incentive rate treatment of such facilities, we cannot be certain that all costs that we may incur will be recoverable. In addition, the date when these facilities will be in service, which can be significantly impacted by delays related to public opposition or other factors, is subject to the outcome of future events that are not all within our control. As a result, we cannot predict the ultimate financial or operational impact of this project or other RTEP projects on PPL Electric.
We could be subject to higher costs and/or penalties related to Pennsylvania Conservation and Energy Efficiency Programs.
Act 129 became effective in October 2008. This law created requirements for energy efficiency and conservation programs and for the use of smart metering technology, imposed new PLR electricity supply procurement rules, provided remedies for market misconduct, and made changes to the existing Alternative Energy Portfolio Standard. The law also requires electric utilities to meet specified goals for reduction in customer electricity usage and peak demand by specified dates (2011 and 2013). Utilities not meeting these requirements of Act 129 are subject to significant penalties that cannot be recovered in rates. Numerous factors outside of our control could prevent compliance with these requirements and result in penalties to us. See "Regulatory Issues - Energy Policy Act of 2005 - Reliability Standards" in Note 15 to the Financial Statements for additional information.
Cost recovery remains subject to political risks.
Although prior initiatives have not resulted in the enactment of such legislation, the possibility remains that certain Pennsylvania legislators could introduce legislation to reinstate generation rate caps or otherwise limit cost recovery through rates for Pennsylvania utilities. If such legislation were introduced and ultimately enacted, PPL Electric could face severe financial consequences including operating losses and significant cash flow shortfalls. In addition, continuing uncertainty regarding PPL Electric's ability to recover its market supply and other costs of operating its business could adversely affect its credit quality, financing costs and availability of credit facilities necessary to operate its business.
(PPL)
Risks Related to International Regulated Segment
Our U.K. delivery business is subject to risks with respect to rate regulation and operational performance.
Our U.K. delivery business is rate regulated and operates under an incentive-based regulatory framework. In addition, its ability to manage operational risk is critical to its financial performance. Disruption to the distribution network could reduce profitability both directly through the higher costs for network restoration and also through the system of penalties and rewards that Ofgem has in place relating to customer service levels.
In December 2009, Ofgem completed its rate review for the five-year period from April 1, 2010 through March 31, 2015, thus reducing regulatory rate risk in the International Regulated segment until the next rate review which will be effective April 1, 2015. The regulated income of the International Regulated segment and also the RAV are to some extent linked to movements in the Retail Price Index (RPI). Reductions in the RPI would adversely impact revenues and the debt/RAV ratio.
Our U.K. distribution business exposes us to risks related to U.K. laws and regulations, taxes, economic conditions, foreign currency exchange rate fluctuations, and political conditions and policies of the U.K. government. These risks may reduce the results of operations from our U.K. distribution business.
The acquisition, financing, development and operation of projects in the U.K. entail significant financial risks including:
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changes in laws or regulations relating to U.K. operations, including tax laws and regulations;
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changes in government policies, personnel or approval requirements;
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changes in general economic conditions affecting the U.K.;
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regulatory reviews of tariffs for distribution companies;
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severe weather and natural disaster impacts on the electric sector and our assets;
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changes in labor relations;
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limitations on foreign investment or ownership of projects and returns or distributions to foreign investors;
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limitations on the ability of foreign companies to borrow money from foreign lenders and lack of local capital or loans;
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fluctuations in foreign currency exchange rates and in converting U.K. revenues to U.S. dollars, which can increase our expenses and/or impair our ability to meet such expenses, and difficulty moving funds out of the country in which the funds were earned; and
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compliance with U.S. foreign corrupt practices laws.
The WPD Midlands acquisition may not achieve its intended results, including anticipated cost savings, efficiencies and other benefits.
Although we completed the WPD Midlands acquisition with the expectation that it will result in various benefits, including a significant amount of cost savings and other financial and operational benefits, there can be no assurance regarding the extent to which we will be able to realize these cost-savings or other benefits. Achieving the anticipated benefits, including cost savings, is subject to a number of uncertainties, including whether the businesses acquired can be operated in the manner we intend. Events outside of our control, including but not limited to regulatory changes or developments in the U.K., could also adversely affect our ability to realize the anticipated benefits from the WPD Midlands acquisition. Thus, the integration process may be unpredictable, subject to delays or changed circumstances, and we can give no assurance that the acquired businesses will perform in accordance with our expectations. Additional unanticipated costs may also arise during the integration process. The integration of the WPD (East Midlands) and WPD (West Midlands) businesses may place an additional burden on our management and internal resources, and the diversion of management's attention during the integration and restructuring process could have an adverse effect on our business, financial condition and expected operating results.
The WPD Midlands acquisition exposes us to additional risks and uncertainties with respect to the acquired businesses and their operations.
The WPD Midlands acquisition will rebalance our business mix to a greater percentage of regulated operations. While we believe this should help mitigate our exposure to downturns in the wholesale power markets, it will increase our dependence on rate-of-return regulation. Although we are already exposed to risks relating to rate-of-return regulation, the WPD Midlands acquisition will increase these risks.
The acquired businesses will generally be subject to risks similar to those to which we are subject to in our pre-acquisition U.K. businesses. These include:
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There are various changes being contemplated by Ofgem to the current electricity distribution, gas transmission and gas distribution regulatory frameworks in the U.K. and there can be no assurance as to the effects such changes will have on our U.K. regulated businesses in the future, including the acquired businesses. In particular, in October 2010, Ofgem announced a new regulatory framework that is expected to become effective in April 2015 for the electricity distribution sector in the U.K. The framework, known as RIIO (Revenues = Incentives + Innovation + Outputs), focuses on sustainability, environmental-focused output measures, promotion of low carbon energy networks and financing of new investments. The new regulatory framework is expected to have a wide-ranging effect on electricity distribution companies operating in the U.K., including changes to price controls and price review periods. Our U.K. regulated businesses' compliance with this new regulatory framework may result in significant additional capital expenditures, increases in operating and compliance costs and adjustments to our pricing models.
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Ofgem has formal powers to propose modifications to each distribution license. We are not currently aware of any planned modification to any of our U.K. regulated businesses distribution licenses that would result in a material adverse change to the U.K. regulated businesses and PPL. There can, however, be no assurance that a restrictive modification will not be introduced in the future, which could have an adverse effect on the operations and financial condition of the U.K. regulated businesses and PPL.
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A failure to operate our U.K. networks properly could lead to compensation payments or penalties, or a failure to make capital expenditures in line with agreed investment programs could lead to deterioration of the network. While our U.K. regulated businesses' investment programs are targeted to maintain asset conditions over a five-year period and reduce customer interruptions and customer minutes lost over that period, no assurance can be provided that these regulatory requirements will be met.
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A failure by any of our U.K. regulated businesses to comply with the terms of a distribution license may lead to the issuance of an enforcement order by Ofgem that could have an adverse impact on PPL. Ofgem has powers to levy fines of up to 10 percent of revenue for any breach of a distribution license or, in certain circumstances, such as insolvency, the distribution license itself may be revoked. Unless terminated in the circumstances mentioned above, a distribution license continues indefinitely until revoked by Ofgem following no less than 25 years' written notice.
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We will be subject to increased foreign currency exchange rate risks because a greater portion of our cash flows and reported earnings will be generated by our U.K. business operations. These risks relate primarily to changes in the relative value of the British pound sterling and the U.S. dollar between the time we initially invest U.S. dollars in our U.K. businesses and the time that cash is repatriated to the U.S. from the U.K., including cash flows from our U.K. businesses that may be distributed as future dividends to our shareholders. In addition, our consolidated reported earnings on a U.S. GAAP basis may be subject to increased earnings translation risk, which is the result of the conversion of earnings as reported in our U.K. businesses on a British pound sterling basis to a U.S. dollar basis in accordance with U.S. GAAP requirements.
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Environmental costs and liabilities associated with aspects of the acquired businesses may differ from those of our existing business.
Risks Related to Supply Segment
(PPL and PPL Energy Supply)
We face intense competition in our energy supply business, which may adversely affect our ability to operate profitably.
Unlike our regulated utility businesses, our energy supply business is dependent on our ability to operate in a competitive environment and is not assured of any rate of return on capital investments through a predetermined rate structure. Competition is impacted by electricity and fuel prices, new market entrants, construction by others of generating assets and transmission capacity, technological advances in power generation, the actions of environmental and other regulatory authorities and other factors. These competitive factors may negatively impact our ability to sell electricity and related products and services, as well as the prices that we may charge for such products and services, which could adversely affect our results of operations and our ability to grow our business.
We sell our available energy and capacity into the competitive wholesale markets through contracts of varying duration. Competition in the wholesale power markets occurs principally on the basis of the price of products and, to a lesser extent, on the basis of reliability and availability. We believe that the commencement of commercial operation of new electric facilities in the regional markets where we own or control generation capacity and the evolution of demand side management resources will continue to increase competition in the wholesale electricity market in those regions, which could have an adverse effect on the prices we receive for electricity.
We also face competition in the wholesale markets for electricity capacity and ancillary services. We primarily compete with other electricity suppliers based on our ability to aggregate supplies at competitive prices from different sources and to efficiently utilize transportation from third-party pipelines and transmission from electric utilities and ISOs. We also compete against other energy marketers on the basis of relative financial condition and access to credit sources, and our competitors may have greater financial resources than we have.
Competitors in the wholesale power markets in which PPL Generation subsidiaries and PPL EnergyPlus operate include regulated utilities, industrial companies, non-utility generators and competitive subsidiaries of regulated utilities. In the past, the PUHCA significantly restricted mergers and acquisitions and other investments in the electric utility sector. Entirely new competitors, including financial institutions, have entered the energy markets as a result of the repeal of the original PUHCA in 2006. The repeal of the original PUHCA also may lead to consolidation in our industry, resulting in competitors with significantly greater financial resources than we have.
Adverse changes in commodity prices and related costs may decrease our future energy margins, which could adversely affect our earnings and cash flows.
Our energy margins, or the amount by which our revenues from the sale of power exceed our costs to supply power, are impacted by changes in market prices for electricity, fuel, fuel transportation, emission allowances, RECs, electricity transmission and related congestion charges and other costs. Unlike most commodities, the limited ability to store electric power requires that it must be consumed at the time of production. As a result, wholesale market prices for electricity may fluctuate substantially over relatively short periods of time and can be unpredictable. Among the factors that influence such prices are:
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supply and demand for electricity available from current or new generation resources;
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variable production costs, primarily fuel (and the associated fuel transportation costs) and emission allowance expense for the generation resources used to meet the demand for electricity;
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transmission capacity and service into, or out of, markets served;
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changes in the regulatory framework for wholesale power markets;
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liquidity in the wholesale electricity market, as well as general creditworthiness of key participants in the market; and
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weather and economic conditions impacting demand for or the price of electricity or the facilities necessary to deliver electricity.
We do not always hedge against risks associated with electricity and fuel price volatility.
We attempt to mitigate risks associated with satisfying our contractual electricity sales obligations by either reserving generation capacity to deliver electricity or purchasing the necessary financial or physical products and services through competitive markets to satisfy our net firm sales contracts. We also routinely enter into contracts, such as fuel and electricity purchase and sale commitments, to hedge our exposure to fuel requirements and other electricity-related commodities. However, based on economic and other considerations, we may decide not to hedge the entire exposure of our operations from commodity price risk. To the extent we do not hedge against commodity price risk, our results of operations and financial position may be adversely affected.
We are exposed to operational, price and credit risks associated with selling and marketing products in the wholesale and retail electricity markets.
We purchase and sell electricity in wholesale markets under market-based tariffs authorized by FERC throughout the U.S. and also enter into short-term agreements to market available electricity and capacity from our generation assets with the expectation of profiting from market price fluctuations. If we are unable to deliver firm capacity and electricity under these agreements, we could be required to pay damages. These damages would generally be based on the difference between the market price to acquire replacement capacity or electricity and the contract price of any undelivered capacity or electricity. Depending on price volatility in the wholesale electricity markets, such damages could be significant. Extreme weather conditions, unplanned generation facility outages, environmental compliance costs, transmission disruptions, and other factors could affect our ability to meet our obligations, or cause significant increases in the market price of replacement capacity and electricity.
Our wholesale power agreements typically include provisions requiring us to post collateral for the benefit of our counterparties if the market price of energy varies from the contract prices in excess of certain pre-determined amounts. We currently believe that we have sufficient credit to fulfill our potential collateral obligations under these power contracts. Our obligation to post collateral could exceed the amount of our facilities or our ability to increase our facilities could be limited by financial markets or other factors. See Note 7 to the Financial Statements for a discussion of PPL's credit facilities.
We also face credit risk that parties with whom we contract in both the wholesale and retail markets will default in their performance, in which case we may have to sell our electricity into a lower-priced market or make purchases in a higher-priced market than existed at the time of contract. Whenever feasible, we attempt to mitigate these risks using various means, including agreements that require our counterparties to post collateral for our benefit if the market price of energy varies from the contract price in excess of certain pre-determined amounts. However, there can be no assurance that we will avoid counterparty nonperformance risk, which could adversely impact our ability to meet our obligations to other parties, which could in turn subject us to claims for damages.
The load following contracts that PPL EnergyPlus is awarded do not provide for specific levels of load and actual load significantly below or above our forecasts could adversely affect our energy margins.
We generally hedge our load following obligations with energy purchases from third parties, and to a lesser extent with our own generation. If the actual load is significantly lower than the expected load, we may be required to resell power at a lower price than was contracted for to supply the load obligation, resulting in a financial loss. Alternatively, a significant increase in load could adversely affect our energy margins because we are required under the terms of the load following contracts to provide the energy necessary to fulfill increased demand at the contract price, which could be lower than the cost to procure additional energy on the open market. Therefore, any significant decrease or increase in load compared with our forecasts could have a material adverse effect on our results of operations or financial position.
We may experience disruptions in our fuel supply, which could adversely affect our ability to operate our generation facilities.
We purchase fuel from a number of suppliers. Disruption in the delivery of fuel and other products consumed during the production of electricity (such as coal, natural gas, oil, water, uranium, lime, limestone and other chemicals), including disruptions as a result of weather, transportation difficulties, global demand and supply dynamics, labor relations, environmental regulations or the financial viability of our fuel suppliers, could adversely affect our ability to operate our facilities, which could result in lower sales and/or higher costs and thereby adversely affect our results of operations.
Our risk management policy and programs relating to electricity and fuel prices, interest rates, foreign currency and counterparty credit and non-performance risks may not work as planned, and we may suffer economic losses despite such programs.
We actively manage the market risk inherent in our generation and energy marketing activities, as well as our debt, foreign currency and counterparty credit positions. We have implemented procedures to monitor compliance with our risk management policy and programs, including independent validation of transaction and market prices, verification of risk and transaction limits, portfolio stress tests, sensitivity analyses and daily portfolio reporting of various risk management metrics. Nonetheless, our risk management programs may not work as planned. For example, actual electricity and fuel prices may be significantly different or more volatile than the historical trends and assumptions upon which we based our risk management calculations. Additionally, unforeseen market disruptions could decrease market depth and liquidity, negatively impacting our ability to enter into new transactions. We enter into financial contracts to hedge commodity basis risk, and as a result are exposed to the risk that the correlation between delivery points could change with actual physical delivery. Similarly, interest rates or foreign currency exchange rates could change in significant ways that our risk management procedures were not designed to address. As a result, we cannot always predict the impact that our risk management decisions may have on us if actual events result in greater losses or costs than our risk models predict or greater volatility in our earnings and financial position.
In addition, our trading, marketing and hedging activities are exposed to counterparty credit risk and market liquidity risk. We have adopted a credit risk management policy and program to evaluate counterparty credit risk. However, if counterparties fail to perform, the risk of which has increased due to the economic downturn, we may be forced to enter into alternative arrangements at then-current market prices. In that event, our financial results are likely to be adversely affected.
Our costs to comply with existing and new environmental laws are expected to continue to be significant, and we plan to incur significant capital expenditures for pollution control improvements that, if delayed, would adversely affect our profitability and liquidity.
Our business is subject to extensive federal, state and local statutes, rules and regulations relating to environmental protection. To comply with existing and future environmental requirements and as a result of voluntary pollution control measures we may take, we have spent and expect to spend substantial amounts in the future on environmental control and compliance.
In order to comply with existing and proposed federal and state environmental laws and regulations primarily governing air emissions from coal-fired plants, in 2005 PPL began a program to install scrubbers and other pollution control equipment (primarily aimed at sulfur dioxide, particulate matter and nitrogen oxides with co-benefits for mercury emissions reduction). The cost to install this equipment was approximately $1.6 billion. The scrubbers at our Montour and Brunner Island plants are now in service. Many states and environmental groups have challenged certain federal laws and regulations relating to air emissions as not being sufficiently strict. As a result, it is possible that state and federal regulations will be adopted that would impose more stringent restrictions than are currently in effect, which could require us to significantly increase capital expenditures for additional pollution control equipment.
We may not be able to obtain or maintain all environmental regulatory approvals necessary for our planned capital projects which are necessary to our business. If there is a delay in obtaining any required environmental regulatory approval or if we
fail to obtain, maintain or comply with any such approval, operations at our affected facilities could be halted, reduced or subjected to additional costs. Furthermore, at some of our older generating facilities it may be uneconomic for us to install necessary pollution control equipment, which could cause us to retire those units.
For more information regarding environmental matters, including existing and proposed federal, state and local statutes, rules and regulations to which we are subject, see "Environmental Matters - Domestic" in Note 15 to the Financial Statements.
We rely on transmission and distribution assets that we do not own or control to deliver our wholesale electricity. If transmission is disrupted, or not operated efficiently, or if capacity is inadequate, our ability to sell and deliver power may be hindered.
We depend on transmission and distribution facilities owned and operated by utilities and other energy companies to deliver the electricity and natural gas we sell in the wholesale market, as well as the natural gas we purchase for use in our electric generation facilities. If transmission is disrupted (as a result of weather, natural disasters or other reasons) or not operated efficiently by ISOs and RTOs, in applicable markets, or if capacity is inadequate, our ability to sell and deliver products and satisfy our contractual obligations may be hindered, or we may be unable to sell products at the most favorable terms.
The FERC has issued regulations that require wholesale electric transmission services to be offered on an open-access, non-discriminatory basis. Although these regulations are designed to encourage competition in wholesale market transactions for electricity, there is the potential that fair and equal access to transmission systems will not be available or that transmission capacity will not be available in the amounts we require. We cannot predict the timing of industry changes as a result of these initiatives or the adequacy of transmission facilities in specific markets or whether ISOs and RTOs in applicable markets will efficiently operate transmission networks and provide related services.
Despite federal and state deregulation initiatives, our supply business is still subject to extensive regulation, which may increase our costs, reduce our revenues, or prevent or delay operation of our facilities.
Our generation subsidiaries sell electricity into the wholesale market. Generally, our generation subsidiaries and our marketing subsidiaries are subject to regulation by the FERC. The FERC has authorized us to sell generation from our facilities and power from our marketing subsidiaries at market-based prices. The FERC retains the authority to modify or withdraw our market-based rate authority and to impose "cost of service" rates if it determines that the market is not competitive, that we possess market power or that we are not charging just and reasonable rates. Any reduction by the FERC in the rates we may receive or any unfavorable regulation of our business by state regulators could materially adversely affect our results of operations. See "FERC Market-Based Rate Authority" in Note 15 to the Financial Statements for information regarding recent court decisions that could impact the FERC's market-based rate authority program.
In addition, the acquisition, construction, ownership and operation of electricity generation facilities require numerous permits, approvals, licenses and certificates from federal, state and local governmental agencies. We may not be able to obtain or maintain all required regulatory approvals. If there is a delay in obtaining any required regulatory approvals or if we fail to obtain or maintain any required approval or fail to comply with any applicable law or regulation, the operation of our assets and our sales of electricity could be prevented or delayed or become subject to additional costs.
If market deregulation is reversed or discontinued, our business prospects and financial condition could be materially adversely affected.
In some markets, state legislators, government agencies and other interested parties have made proposals to change the use of market-based pricing, re-regulate areas of these markets that have previously been competitive or permit electricity delivery companies to construct or acquire generating facilities. The ISOs that oversee the transmission systems in certain wholesale electricity markets have from time to time been authorized to impose price limitations and other mechanisms to address extremely high prices in the power markets. These types of price limitations and other mechanisms may reduce profits that our wholesale power marketing and trading business would have realized under competitive market conditions absent such limitations and mechanisms. Although we generally expect electricity markets to continue to be competitive, other proposals to re-regulate our industry may be made, and legislative or other actions affecting the electric power restructuring process may cause the process to be delayed, discontinued or reversed in states in which we currently, or may in the future, operate. See "New Jersey Capacity Legislation" in Note 15 to the Financial Statements.
Changes in technology may negatively impact the value of our power plants.
A basic premise of our generation business is that generating electricity at central power plants achieves economies of scale and produces electricity at relatively low prices. There are alternate technologies to produce electricity, most notably fuel
cells, micro turbines, windmills and photovoltaic (solar) cells, the development of which has been expanded due to global climate change concerns. Research and development activities are ongoing to seek improvements in alternate technologies. It is possible that advances will reduce the cost of alternate methods of electricity production to a level that is equal to or below that of certain central station production. Also, as new technologies are developed and become available, the quantity and pattern of electricity usage (the "demand") by customers could decline, with a corresponding decline in revenues derived by generators. These alternative energy sources could result in a decline to the dispatch and capacity factors of our plants. As a result of all of these factors, the value of our generation facilities could be significantly reduced.
We are subject to certain risks associated with nuclear generation, including the risk that our Susquehanna nuclear plant could become subject to increased security or safety requirements that would increase capital and operating expenditures, uncertainties regarding spent nuclear fuel, and uncertainties associated with decommissioning our plant at the end of its licensed life.
Nuclear generation accounted for about 28% of our 2011 generation output. The risks of nuclear generation generally include:
·
the potential harmful effects on the environment and human health from the operation of nuclear facilities and the storage, handling and disposal of radioactive materials;
·
limitations on the amounts and types of insurance commercially available to cover losses and liabilities that might arise in connection with nuclear operations; and
·
uncertainties with respect to the technological and financial aspects of decommissioning nuclear plants at the end of their licensed lives. The licenses for our two nuclear units expire in 2042 and 2044. See Note 21 to the Financial Statements for additional information on the ARO related to the decommissioning.
The NRC has broad authority under federal law to impose licensing requirements, including security, safety and employee-related requirements for the operation of nuclear generation facilities. In the event of noncompliance, the NRC has authority to impose fines or shut down a unit, or both, depending upon its assessment of the severity of the situation, until compliance is achieved. In addition, revised security or safety requirements promulgated by the NRC could necessitate substantial capital or operating expenditures at our Susquehanna nuclear plant. There also remains substantial uncertainty regarding the temporary storage and permanent disposal of spent nuclear fuel, which could result in substantial additional costs to PPL that cannot be predicted. In addition, although we have no reason to anticipate a serious nuclear incident at our Susquehanna plant, if an incident did occur, any resulting operational loss, damages and injuries could have a material adverse effect on our results of operations, cash flows or financial condition. See Note 15 to the Financial Statements for a discussion of nuclear insurance.
ITEM 1B.
ITEM 1B. UNRESOLVED STAFF COMMENTS
PPL Corporation, PPL Energy Supply, LLC, PPL Electric Utilities Corporation, LG&E and KU Energy LLC, Louisville Gas and Electric Company and Kentucky Utilities Company
None.
ITEM 2.
ITEM 2. PROPERTIES
(PPL, LKE, LG&E and KU)
Kentucky Regulated Segment
LG&E's and KU's properties consist primarily of regulated generation facilities, electric transmission and distribution assets and natural gas transmission and distribution assets in Kentucky. The electric generating capacity at December 31, 2011 was:
(a)
LG&E and KU's properties are primarily located in Kentucky, with the exception of the units owned by OVEC. Clifty Creek is located in Indiana and Kyger Creek is located in Ohio.
(b)
The capacity of generation units is based on a number of factors, including the operating experience and physical conditions of the units, and may be revised periodically to reflect changed circumstances.
(c)
TC1 and TC2 are jointly owned with Illinois Municipal Electric Agency and Indiana Municipal Power Agency. Each owner is entitled to its proportionate share of the units' total output and funds its proportionate share of capital, fuel and other operating costs. See Note 14 to the Financial Statements for additional information.
(d)
LKE took care, custody and control of TC2 on January 22, 2011, and has dispatched the unit to meet customer demand since that date. See Note 15 to the Financial Statements for additional information.
(e)
This unit is owned by OVEC. LKE has a power purchase agreement that entitles LKE to its proportionate share of the unit's total output and LKE funds its proportionate share of fuel and other operating costs. See Note 15 to the Financial Statements for additional information.
(f)
Includes a leasehold interest. See Note 11 to the Financial Statements for additional information.
(g)
There is an inlet air cooling system attributable to these units. This inlet air cooling system is not jointly owned; however, it is used to increase production on the units to which it relates, resulting in an additional 10 MW of capacity for LG&E and an additional 88 MW of capacity for KU.
For a description of LG&E's and KU's service areas, see "Item 1. Business - Background." At December 31, 2011, LG&E's transmission system included in the aggregate, 45 substations (32 of which are shared with the distribution system) with a total capacity of 7 million kVA and 916 circuit miles of lines. The distribution system included 97 substations (32 of which are shared with the transmission system) with a total capacity of 5 million kVA, 3,887 miles of overhead lines and 2,371 miles of underground wires. KU's transmission system included 133 substations (55 of which are shared with the distribution system) with a total capacity of 13 million kVA and 4,078 circuit miles of lines. The distribution system included 478
substations (55 of which are shared with the transmission system) with transformer capacity of 7 million kVA, 14,112 miles of overhead lines and 2,265 miles of underground conduit.
LG&E's natural gas transmission system includes 4,290 miles of gas distribution mains and 386 miles of gas transmission mains, consisting of 254 miles of gas transmission pipeline, 123 miles of gas transmission storage lines, 6 miles of gas combustion turbine lines, and 3 miles of gas transmission pipeline in regulator facilities. Five underground natural gas storage fields, with a total working natural gas capacity of approximately 15 Bcf, are used in providing natural gas service to ultimate consumers. KU's service area includes an additional 11 miles of gas transmission pipeline providing gas supply to natural gas combustion turbine electrical generating units.
Substantially all of LG&E's and KU's respective real and tangible personal property located in Kentucky and used or to be used in connection with the generation, transmission and distribution of electricity and, in the case of LG&E, the storage and distribution of natural gas, is subject to the lien of either the LG&E 2010 Mortgage Indenture or the KU 2010 Mortgage Indenture. See Note 7 to the Financial Statements for additional information.
LG&E and KU continuously reexamine development projects based on market conditions and other factors to determine whether to proceed with the projects, sell, cancel or expand them or pursue other options. At December 31, 2011, LG&E and KU planned to implement the following incremental capacity increases and decreases at the following plants located in Kentucky.
(a)
The capacity of generating units is based on a number of factors, including the operating experience and physical condition of the units, and may be revised periodically to reflect changed circumstances.
(b)
The expected in-service dates are subject to receipt of required approvals, permits and other contingencies.
(c)
LG&E and KU anticipate retiring these units at the end of 2015. See Notes 8 and 15 to the Financial Statements for additional information.
(d)
In September 2011, LG&E and KU requested approval to build this unit at the existing Cane Run site. See Note 8 to the Financial Statements for additional information.
(e)
In September 2011, LG&E and KU requested approval to purchase three existing natural gas combustion units. See Note 8 to the Financial Statements for additional information.
(PPL)
International Regulated Segment
For a description of WPD's service territory, see "Item 1. Business - Background." At December 31, 2011, WPD had electric distribution lines in public streets and highways pursuant to legislation and rights-of-way secured from property owners. WPD's distribution system in the U.K. includes 1,602 substations with a total capacity of 61 million kVA, 57,472 circuit miles of overhead lines and 79,755 cable miles of underground conductors.
(PPL and PPL Electric)
Pennsylvania Regulated Segment
For a description of PPL Electric's service territory, see "Item 1. Business - Background." At December 31, 2011, PPL Electric had electric transmission and distribution lines in public streets and highways pursuant to franchises and rights-of-
way secured from property owners. PPL Electric's transmission system included 60 substations with a total capacity of 17 million kVA and 6,727 pole miles. PPL Electric's distribution system included 321 substations with a total capacity of 15 million kVA, 33,145 circuit miles of overhead lines and 7,407 cable miles of underground conductors. All of PPL Electric's facilities are located in Pennsylvania. Substantially all of PPL Electric's distribution properties and certain transmission properties are subject to the lien of the PPL Electric 2001 Mortgage Indenture.
See Note 8 to the Financial Statements for information on the construction of the Susquehanna-Roseland 500-kilovolt transmission line.
(PPL and PPL Energy Supply)
Supply Segment
PPL Energy Supply's electric generating capacity (summer rating) at December 31, 2011 was:
(a)
The capacity of generation units is based on a number of factors, including the operating experience and physical conditions of the units, and may be revised periodically to reflect changed circumstances.
(b)
Facility not owned by PPL Energy Supply, but there is a tolling agreement in place through 2021.
(c)
Represents the leasehold interest held by PPL Montana. See Note 11 to the Financial Statements for additional information.
(d)
This unit is jointly owned. Each owner is entitled to their proportionate share of the unit's total output and funds their proportionate share of fuel and other operating costs. See Note 14 to the Financial Statements for additional information.
(e)
Includes facilities owned, controlled or for which PPL Energy Supply has the rights to the output.
Amounts guaranteed by PPL Montour and PPL Brunner Island in connection with an $800 million secured energy marketing and trading facility are secured by liens on the generating facilities owned by PPL Montour and PPL Brunner Island. See Note 7 to the Financial Statements for additional information.
PPL Energy Supply continuously reexamines development projects based on market conditions and other factors to determine whether to proceed with the projects, sell, cancel or expand them, execute tolling agreements or pursue other options. At December 31, 2011, PPL Energy Supply subsidiaries planned to implement the following incremental capacity increases.
(a)
The capacity of generating units is based on a number of factors, including the operating experience and physical condition of the units, and may be revised periodically to reflect changed circumstances.
(b)
The expected in-service dates are subject to receipt of required approvals, permits and other contingencies.
(c)
This project includes installation of two additional large turbine-generators and the replacement of four existing runners.
(d)
This project includes installation of enhanced compressor and turbine hardware and control logic optimization that will increase output and improve heat rate.
(e)
This project involves the reconstruction of a powerhouse.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
See Notes 5, 6 and 15 to the Financial Statements for information regarding legal, tax litigation, regulatory and environmental proceedings and matters.
ITEM 4.
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
PART II
ITEM 5.
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY,
RELATED STOCKHOLDER MATTERS AND
ISSUER PURCHASES OF EQUITY SECURITIES
See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Financial Condition - Liquidity and Capital Resources - Forecasted Uses of Cash" for information regarding certain restrictions on the ability to pay dividends for PPL, PPL Electric, LKE, LG&E and KU.
PPL Corporation
Additional information for this item is set forth in the sections entitled "Quarterly Financial, Common Stock Price and Dividend Data," "Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters" and "Shareowner and Investor Information" of this report. At January 31, 2012, there were 68,702 common stock shareowners of record.
In 2011, PPL terminated the program to repurchase its common stock in open market purchases, pre-arranged trading plans or privately negotiated transactions. There were no purchases by PPL of its common stock during the fourth quarter of 2011.
PPL Energy Supply, LLC
There is no established public trading market for PPL Energy Supply's membership interests. PPL Energy Funding, a direct wholly owned subsidiary of PPL, owns all of PPL Energy Supply's outstanding membership interests. Distributions on the membership interests will be paid as determined by PPL Energy Supply's Board of Managers.
PPL Energy Supply made cash distributions to PPL Energy Funding of $316 million in 2011 and $4.7 billion in 2010. In 2010, PPL Energy Supply received cash contributions of $3.6 billion and distributed $4.7 billion to PPL Energy Funding. The cash contributions received from its parent related primarily to the funds received by PPL in June 2010 from the issuance of common stock and 2010 Equity Units. These funds were invested by a subsidiary of PPL Energy Supply until they were returned to PPL Energy Funding in October 2010 to be available to partially fund PPL's acquisition of LKE and pay certain acquisition-related fees and expenses. See Note 9 to the Financial Statements regarding the distribution, including $325 million of cash, of PPL Energy Supply's membership interests in PPL Global to PPL Energy Funding in January 2011.
PPL Electric Utilities Corporation
There is no established public trading market for PPL Electric's common stock, as PPL owns 100% of the outstanding common shares. Dividends paid to PPL on those common shares are determined by PPL Electric's Board of Directors. PPL Electric paid common stock dividends to PPL of $92 million in 2011 and $71 million in 2010.
LG&E and KU Energy LLC
There is no established public trading market for LKE's membership interests. PPL owns all of LKE's outstanding membership interests. Distributions on the membership interests will be paid as determined by LKE's Board of Directors. LKE made cash distributions to PPL of $533 million in 2011 (including $248 million from the proceeds of a note issuance) and $100 million in 2010. LKE made cash distributions to E.ON US Investments Corp. of $87 million in 2010.
Louisville Gas and Electric Company
There is no established public trading market for LG&E's common stock, as LKE owns 100% of the outstanding common shares. Dividends paid to LKE on those common shares are determined by LG&E's Board of Directors. LG&E paid common stock dividends to LKE of $83 million in 2011 and $55 million in 2010.
Kentucky Utilities Company
There is no established public trading market for KU's common stock, as LKE owns 100% of the outstanding common shares. Dividends paid to LKE on those common shares are determined by KU's Board of Directors. KU paid common stock dividends to LKE of $124 million in 2011 and $50 million in 2010.
ITEM 6.
ITEM 6. SELECTED FINANCIAL AND OPERATING DATA
PPL Energy Supply, LLC, PPL Electric Utilities Corporation, LG&E and KU Energy LLC, Louisville Gas and Electric Company and Kentucky Utilities Company
Item 6 is omitted as PPL Energy Supply, PPL Electric, LKE, LG&E and KU meet the conditions set forth in General Instructions (I)(1)(a) and (b) of Form 10-K.
(a)
The earnings each year were affected by several items that management considers special. See "Results of Operations - Segment Results" in "Item 7.
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
The information provided in this Item 7 should be read in conjunction with PPL's Consolidated Financial Statements and the accompanying Notes. Capitalized terms and abbreviations are explained in the glossary. Dollars are in millions unless otherwise noted.
"Management's Discussion and Analysis of Financial Condition and Results of Operations" includes the following information:
·
"Overview" provides a description of PPL and its business strategy. "Financial and Operational Developments" includes a review of Net Income Attributable to PPL Corporation and discusses certain events that are important to understanding PPL's results of operations and financial condition.
·
"Results of Operations" provides a summary of PPL's earnings, a review of results by reportable segment and a description of key factors by segment expected to impact future earnings. This section ends with "Statement of Income Analysis," which includes explanations of significant changes in principal items on PPL's Statements of Income, comparing 2011, 2010 and 2009.
·
"Financial Condition - Liquidity and Capital Resources" provides an analysis of PPL's liquidity position and credit profile. This section also includes a discussion of rating agency decisions and capital expenditure projections.
·
"Financial Condition - Risk Management - Energy Marketing & Trading and Other" provides an explanation of PPL's risk management programs relating to market and credit risk.
·
"Application of Critical Accounting Policies" provides an overview of the accounting policies that are particularly important to the results of operations and financial condition of PPL and that require its management to make significant estimates, assumptions and other judgments of matters inherently uncertain.
Overview
Introduction
PPL is an energy and utility holding company with headquarters in Allentown, Pennsylvania. Through subsidiaries, PPL generates electricity from power plants in the northeastern, northwestern and southeastern U.S., markets wholesale and retail energy primarily in the northeastern and northwestern portions of the U.S., delivers electricity to customers in Pennsylvania, Kentucky, Virginia, Tennessee and the U.K. and delivers natural gas to customers in Kentucky.
In 2011 and 2010, PPL completed two acquisitions.
* On April 1, 2011, PPL, through its indirect, wholly owned subsidiary PPL WEM, completed its acquisition of all of the outstanding ordinary share capital of Central Networks East plc and Central Networks Limited, the sole owner of Central Networks West plc, together with certain other related assets and liabilities (collectively referred to as Central Networks and subsequently renamed WPD Midlands), from subsidiaries of E.ON AG. The consideration for the acquisition consisted of cash of $5.8 billion, including the repayment of $1.7 billion of affiliate indebtedness owed to subsidiaries of E.ON AG, and $800 million of long-term debt assumed through consolidation. WPD Midlands operates two regulated distribution networks that serve five million end-users in the Midlands area of England.
* On November 1, 2010, PPL completed the acquisition of all of the limited liability company interests of E.ON U.S. LLC from a wholly owned subsidiary of E.ON AG. Upon completion of the acquisition, E.ON U.S. LLC was renamed LG&E and KU Energy LLC (LKE). LKE is engaged in regulated utility operations through its subsidiaries, LG&E and KU. The consideration for the acquisition consisted of cash of $6.8 billion, including the repayment of $4.3 billion of affiliate indebtedness owed to subsidiaries of E.ON AG, and $800 million of debt assumed through consolidation.
See Note 10 to the Financial Statements for additional information on the acquisitions.
At December 31, 2011, PPL had:
·
$12.7 billion in operating revenues (including eight months from WPD Midlands, which are recorded on a one-month lag)
·
10.5 million end-users of its utility services (including five million end-users served by the WPD Midlands companies)
·
Approximately 19,000 MW of generation
·
Approximately 18,000 full-time employees
In January 2011, PPL Energy Supply distributed its 100% membership interest in PPL Global to its parent, PPL Energy Funding (the parent holding company of PPL Energy Supply and PPL Global with no other material operations), to better align PPL's organizational structure with the manner in which it manages its businesses and reports segment information in its consolidated financial statements. The distribution separated the U.S.-based competitive energy marketing and supply business from the U.K.-based regulated electricity distribution business.
PPL's principal subsidiaries are shown below (* denotes an SEC registrant; LKE, LG&E and KU became SEC registrants effective June 1, 2011):
Business Strategy
PPL's overall strategy is to achieve stable, long-term growth in its regulated electricity delivery businesses through efficient operations and strong customer and regulatory relations, and disciplined optimization of energy supply margins while mitigating volatility in both cash flows and earnings. In pursuing this strategy, PPL acquired LKE in November 2010 and WPD Midlands in April 2011. These acquisitions have reduced PPL's overall business risk profile and reapportioned the mix of PPL's regulated and competitive businesses by increasing the regulated portion of its business and enhancing rate-regulated growth opportunities as the regulated businesses make investments to improve infrastructure and customer reliability.
The increase in regulated assets is expected to provide earnings stability through regulated returns and the ability to recover costs of capital investments, in contrast to the competitive energy supply business where earnings and cash flows are subject to commodity market volatility. Following the LKE and WPD Midlands acquisitions, approximately 70% of PPL's assets are in its regulated businesses. The pro forma impacts of the acquisitions of LKE and WPD Midlands on income from continuing operations (after income taxes) attributable to PPL for 2011 and 2010 are as follows.
Note: Pro forma and actual amounts exclude non-recurring items identified in Note 10 to the Financial Statements.
Results for periods prior to the acquisitions of LKE and WPD Midlands are not comparable with, or indicative of, results for periods subsequent to the acquisitions.
With the purchase of WPD Midlands and the related growth of the portion of PPL's overall earnings translated from British pounds sterling, the related foreign currency risk is more substantial. The U.K. subsidiaries also have currency exposure to the U.S. dollar to the extent they have U.S. dollar denominated debt. To manage these risks, PPL generally uses contracts such as forwards, options and cross currency swaps that contain characteristics of both interest rate and foreign currency exchange contracts.
PPL's strategy for its competitive energy supply business is to optimize the value from its unregulated generation and marketing portfolio. PPL endeavors to do this by matching energy supply with load, or customer demand, under contracts of varying durations with creditworthy counterparties to capture profits while effectively managing exposure to energy and fuel price volatility, counterparty credit risk and operational risk.
To manage financing costs and access to credit markets, a key objective of PPL's business strategy is to maintain a strong credit profile. PPL continually focuses on maintaining an appropriate capital structure and liquidity position. In addition, PPL has adopted financial and operational risk management programs that, among other things, are designed to monitor and manage its exposure to earnings and cash flow volatility related to changes in energy and fuel prices, interest rates, counterparty credit quality and the operating performance of its generating units.
Financial and Operational Developments
Net Income Attributable to PPL Corporation
Net Income Attributable to PPL Corporation for 2011, 2010 and 2009 was $1.5 billion, $938 million and $407 million. Earnings in 2011 increased 59% over 2010 and earnings in 2010 increased 130% over 2009. These changes reflect the following after-tax impacts by segment:
(a)
Primarily consists of an impairment charge recorded related to the sale of certain non-core generation facilities and discontinued cash flow hedges and ineffectiveness.
(b)
See "Statement of Income Analysis - Margins" for additional information, including a reconciliation of this non-GAAP financial measure to operating income.
See "Results of Operations" below for further discussion and analysis of the consolidated results of operations, as well as a discussion of each of PPL's business segments.
Acquisition of WPD Midlands
On April 1, 2011, PPL completed its acquisition of WPD Midlands. The service territories of PPL WW and WPD Midlands are contiguous and cost savings, efficiencies and other benefits are expected from the combined operation of these entities.
The cash consideration of $5.8 billion was primarily funded by borrowings under the 2011 Bridge Facility. Permanent financing was completed in the second quarter of 2011 to repay 2011 Bridge Facility borrowings, pay certain acquisition-related fees and raise additional capital for general corporate purposes. See Note 7 to the Financial Statements for additional information related to the financings.
Pursuant to WPD's previously described intention to combine the operations of PPL WW and WPD Midlands, approximately 740 employees of WPD Midlands will receive separation benefits from the companies as a new regional structure is implemented. The total separation benefits payable in connection with the reorganization are $104 million, including $58 million of severance compensation, $45 million of early retirement deficiency costs (ERDC) and $1 million in outplacement services.
In connection with the reorganization, WPD Midlands recorded $93 million of the total separation benefits in 2011, of which $48 million relates to severance compensation and $45 million relates to ERDC. Based on the expected timing of when employees will separate from the companies, WPD Midlands expects to record the remaining portion of severance compensation in 2012. The separation benefits recorded in 2011 are included in "Other operation and maintenance" on the Statement of Income. Severance compensation costs of $21 million are accrued in "Other current liabilities" and ERDC costs of $45 million reduced "Other noncurrent assets" on the Balance Sheet at December 31, 2011.
Goodwill of $2.4 billion was recorded as a result of the purchase price allocation. PPL incurred acquisition-related costs of $258 million, pre-tax, for 2011 which includes, among other items, the separation benefits discussed above, employee relocation costs, contract termination costs, advisory, accounting and legal fees, taxes and certain financing costs, including gains on hedges and foreign currency losses on the 2011 Bridge Facility.
See Note 10 to the Financial Statements for additional information related to the acquisition.
Susquehanna Turbine Blade Replacement
In April 2011, during the PPL Susquehanna Unit 2 refueling and generation uprate outage, a planned inspection of the Unit 2 turbine revealed cracks in certain of its low pressure turbine blades. Replacement of these blades was required, but was not anticipated as part of the original scope of this outage. The necessary replacement work extended the Unit 2 outage by six weeks. As a precaution, PPL Susquehanna also took Unit 1 out of service in mid-May to inspect the turbine blades in that unit. This inspection revealed cracks in blades similar to those found in Unit 2. The duration of the Unit 1 outage, in which turbine blades were replaced, was also about six weeks. The after-tax earnings impact, including reduced energy-sales margins and repair expense for both units, was $63 million.
Spent Nuclear Fuel Litigation
In May 2011, PPL Susquehanna entered into a settlement agreement with the U.S. Government relating to PPL Susquehanna's lawsuit, seeking damages for the Department of Energy's failure to accept spent nuclear fuel from the PPL Susquehanna plant. Under the settlement agreement, PPL Susquehanna received $50 million, pre-tax, for its share of claims to partially offset its expenses incurred to store spent nuclear fuel at the Susquehanna plant through September 2009, and recognized a credit to "Fuel" expense in 2011. PPL Susquehanna also will be eligible to receive payment of annual claims for allowed costs that are incurred through the December 2013 termination of the settlement agreement. In exchange, PPL Susquehanna has waived any claims against the U.S. Government for costs paid or injuries sustained related to storing spent nuclear fuel at the Susquehanna plant through December 31, 2013. See Note 15 to the Financial Statements for additional information.
Tax Rate Change
In July 2011, the U.K.'s Finance Act of 2011 was enacted. The most significant change to the law was a reduction in the U.K.'s statutory income tax rate. The statutory tax rate was changed from 27% to 26%, effective April 1, 2011 and from 26% to 25%, effective April 1, 2012. As a result of these changes, in 2011, PPL reduced its net deferred tax liabilities and recognized a $69 million deferred tax benefit to reflect both rate decreases.
Bankruptcy of SMGT
In October 2011, SMGT, a Montana cooperative and purchaser of electricity under a long-term supply contract with PPL EnergyPlus expiring in June 2019 (SMGT Contract), filed for protection under Chapter 11 of the U.S. Bankruptcy Code in the U.S. Bankruptcy Court in Montana. At December 31, 2011, damages related to SMGT accepting less power than provided in the SMGT Contract totaled approximately $11 million, all of which has been fully reserved. No assurance can be given as to the collectability of these damages.
The SMGT Contract provides for fixed volume purchases on a monthly basis at established prices. A trustee has been appointed for SMGT's estate in the bankruptcy proceeding and PPL EnergyPlus has been involved in preliminary discussions with the trustee concerning possible modifications to the SMGT Contract as part of the bankruptcy reorganization. Pursuant to a stipulation entered into by SMGT and PPL EnergyPlus, since the date of its Chapter 11 filing through January 2012, SMGT has continued to purchase electricity from PPL EnergyPlus at the price specified in the SMGT Contract, and has made timely payments for such purchases, but at lower volumes than as prescribed in the SMGT Contract. In January 2012, the trustee notified PPL EnergyPlus that SMGT would not purchase electricity under the SMGT Contract for the month of February. In addition, the trustee requested PPL EnergyPlus to leave the SMGT Contract in place to permit SMGT to purchase electricity in the event its requirements were not met by third-party providers from whom the trustee intends to purchase power on behalf of SMGT, at prices more favorable than under the SMGT Contract, for future periods. PPL EnergyPlus is evaluating the trustee's request.
At the present time, PPL cannot predict whether SMGT will be successful in its attempts to reorganize its business under Chapter 11 of the U.S. Bankruptcy Code or the extent to which the SMGT Contract may be modified as part of a successful Chapter 11 reorganization and, in either case, PPL cannot presently predict the extent to which it will be able to market to third parties any amount of power that SMGT ultimately does not continue to purchase from PPL EnergyPlus.
Storm Recovery
PPL Electric experienced several PUC-reportable storms during 2011 resulting in total restoration costs of $84 million, of which $54 million were recorded in "Other operation and maintenance" on the Statement of Income. However, a PPL subsidiary has a $10 million reinsurance policy with a third party insurer, for which a receivable was recorded with an offsetting credit to "Other operation and maintenance" on the Statement of Income. In December 2011, PPL Electric received orders from the PUC granting permission to defer qualifying storm costs in excess of insurance recoveries associated with Hurricane Irene and a late October snowstorm. Based on the PUC orders, PPL Electric recorded a regulatory asset of $25 million in December 2011. PPL Electric will seek recovery of these costs in its next general base rate proceeding.
Tax Litigation
In 1997, the U.K. imposed a Windfall Profits Tax (WPT) on privatized utilities, including WPD. PPL filed its tax returns for years subsequent to its 1997 and 1998 claims for refund on the basis that the U.K. WPT was creditable. In September 2010, the U.S. Tax Court (Tax Court) ruled in PPL's favor in a dispute with the IRS, concluding that the U.K. WPT is a creditable tax for U.S. tax purposes. As a result and with the finalization of other issues, PPL recorded a $42 million tax benefit in 2010. In January 2011, the IRS appealed the Tax Court's decision to the U.S. Court of Appeals for the Third Circuit (Third Circuit). In December 2011, the Third Circuit issued its opinion reversing the Tax Court's decision and holding that the U.K. WPT is not a creditable tax. As a result of the Third Circuit's adverse determination, PPL recorded a $39 million expense in 2011. On February 27, 2012, PPL filed with the Third Circuit a petition for rehearing of its opinion on this matter.
CSAPR
In July 2011, the EPA signed the CSAPR, which finalizes and renames the Clean Air Transport Rule (Transport Rule) proposed in August 2010, and made revisions to the rule on February 7, 2012. This rule applies to PPL's Pennsylvania and Kentucky coal plants. The CSAPR is meant to facilitate attainment of ambient air quality standards for ozone and fine particulates by requiring reductions in sulfur dioxide and nitrogen oxide emissions.
In December 2011, the U.S. Court of Appeals for the District of Columbia (Court) stayed implementation of the CSAPR and left CAIR in effect pending a final resolution on the merits of the validity of the rule. Oral argument on the various challenges to the CSAPR is scheduled for April 2012, and a final decision on the validity of the rule could be issued as early as May 2012.
With respect to the Kentucky coal-fired generating plants, the stay of the CSAPR will initially only impact the unit dispatch order. With the return of the CAIR and the Kentucky companies' significant number of sulfur dioxide allowances, those units will be dispatched with lower operating cost, but slightly higher sulfur dioxide and nitrogen oxide emissions. However, a key component of the Court's final decision, even if the CSAPR is upheld, will be whether the ruling delays the implementation of the CSAPR by one year for both Phases I and II, or instead still requires the significant sulfur dioxide and nitrogen oxide reductions associated with Phase II to begin in 2014. LG&E's and KU's CSAPR compliance strategy is based on over-compliance during Phase I to generate allowances sufficient to cover the expected shortage during the first two years of Phase II (2014 and 2015) when additional pollution control equipment will be installed. Should Phase I of the CSAPR be shortened to one year, it will be more difficult and costly to provide enough excess allowances in one year to meet the shortage projected for 2014 and 2015.
PPL's Pennsylvania coal-fired generating plants can meet both the CAIR and the proposed CSAPR sulfur dioxide emission requirements with the existing scrubbers that went in-service in 2008 and 2009. For nitrogen oxide, under both the CAIR and the proposed CSAPR, PPL would need to buy allowances or make operational changes, the cost of which is not anticipated to be significant.
See Note 15 to the Financial Statements for additional information on the CSAPR.
Pending Bluegrass CTs Acquisition and NGCC Construction
In September 2011, LG&E and KU filed a CPCN with the KPSC requesting approval to build a 640 MW NGCC at the existing Cane Run plant site. In conjunction with this request and to meet new, stricter EPA regulations, LG&E and KU anticipate retiring six older coal-fired electric generating units. These units are located at the Cane Run, Green River and Tyrone plants, which have a combined summer rating of 797 MW. LG&E and KU also requested approval to purchase the Bluegrass CTs, which are expected to provide up to 495 MW of peak generation supply.
LG&E and KU anticipate that the NGCC construction and the acquisition of the Bluegrass CTs could require up to $800 million in capital costs including related transmission projects. Formal requests for recovery of the costs associated with the NGCC construction and the acquisition of the Bluegrass CTs were not included in the CPCN filing with the KPSC but are expected to be included in future rate proceedings. The KPSC issued an Order on the procedural schedule in the CPCN filing that has discovery scheduled through early February 2012. A KPSC order on the CPCN filing is anticipated in the second quarter of 2012. See Note 8 to the Financial Statements for additional information.
ECR Filing - Environmental Upgrades
In June 2011, in order to achieve compliance with new and pending mandated federal EPA regulations, LG&E and KU filed ECR plans with the KPSC requesting approval to install environmental upgrades for certain of their coal-fired plants and for recovery of the expected $2.5 billion in associated capital costs, as well as operating expenses incurred. The ECR plans detailed upgrades that will be made to certain of their coal-fired generating plants to continue to be compliant with EPA regulations. In November 2011, LG&E and KU filed a unanimous settlement agreement, stipulation, and recommendation with the KPSC. In December 2011, LG&E and KU received KPSC approval in their proceedings relating to the ECR plans. The KPSC Order approved the terms of the November 2011 settlement agreement entered into between LG&E and KU and the parties to the ECR proceedings. The KPSC Order authorized the installation of environmental upgrades at certain plants during 2012-2016 representing approximate capital costs of $2.3 billion. In connection with the approved projects, the KPSC Order allowed recovery through the ECR rate mechanism of the capital costs and operating expenses of the projects and granted CPCNs for their construction. The KPSC Order also confirmed an existing 10.63% authorized return on equity for projects remaining from earlier ECR plans and provided for an authorized return on equity of 10.10% for the approved projects in the 2011 ECR proceedings. The KPSC Order noted KU's consent to defer the requested approval for certain environmental upgrades at its E.W. Brown generating plant, which represented approximately $200 million in capital costs. KU retained the right to operate and dispatch the E.W. Brown generating plant in accordance with applicable environmental standards and the right to request approval of the deferred projects and related costs in future regulatory proceedings. See Note 6 to the Financial Statements for additional information.
Legislation - Regulatory Procedures and Mechanisms
In June 2011, the Pennsylvania House Consumer Affairs Committee approved legislation that would authorize the PUC to approve regulatory procedures and mechanisms to provide for more timely recovery of a utility's costs. Such alternative ratemaking procedures and mechanisms are important to PPL Electric as it begins a period of significant increasing capital investment related to the asset optimization program focused on the replacement of aging distribution assets. Those procedures and mechanisms include, but are not limited to, the use of a fully projected future test year and an automatic
adjustment clause to recover certain capital costs and related operating expenses. In October 2011, the legislation was passed by the Pennsylvania House of Representatives (Pennsylvania House). In January 2012, the Senate Consumer Affairs Committee adopted significant amendments to the legislation. The amended legislation authorizes the PUC to approve only two specific ratemaking mechanisms -- a fully projected future test year and a distribution system improvement charge. In addition, the amendments impose a number of conditions on the use of such a charge. In January 2012, the Pennsylvania Senate passed the amended legislation and in February 2012, the Pennsylvania House agreed to those amendments. The Governor signed the bill (Act 11 of 2012), which will become effective April 14, 2012. Utilities cannot file a petition with the PUC before January 1, 2013 requesting permission to establish the charge.
FERC Formula Rates
In March 2012, PPL Electric plans to file a request with the FERC seeking recovery, over a 34-year period beginning in June 2012, of its unrecovered regulatory asset related to the deferred state tax liability that existed at the time of the transition from the flow-through treatment of state income taxes to full normalization. This change in tax treatment occurred in 2008 as a result of prior FERC initiatives that transferred regulatory jurisdiction of certain transmission assets from the PUC to the FERC. A regulatory asset of $51 million related to this transition, classified as taxes recoverable through future rates, is included in "Other Noncurrent Assets - Regulatory assets" on the Balance Sheet. PPL Electric believes recoverability of this regulatory asset is probable based on FERC precedent in similar cases; however, it is reasonably possible that the FERC may limit the recovery of all or part of the claimed asset.
Montana Hydroelectric Litigation
In June 2011, the U.S. Supreme Court granted PPL Montana's petition to review the March 2010 Montana Supreme Court decision, which substantially affirmed the June 2008 Montana District Court decision to award the State of Montana retroactive compensation for PPL Montana's hydroelectric facilities' use and occupancy of certain Montana riverbeds. Oral argument was held in December 2011. On February 22, 2012, the U.S. Supreme Court issued a decision overturning the Montana Supreme Court decision and remanded the case to the Montana Supreme Court for further proceedings consistent with the U.S. Supreme Court's opinion. As a result, PPL Montana reversed its total loss accrual of $89 million, which had been recorded prior to the U.S. Supreme Court decision. PPL Montana believes the U.S. Supreme Court decision resolves certain questions of liability in this case in favor of PPL Montana and leaves open for reconsideration by Montana courts, consistent with the findings of the U.S. Supreme Court, certain other questions. The State of Montana has 30 days from February 22, 2012 to petition the U.S. Supreme Court for a rehearing. PPL Montana has concluded it is no longer probable, but it remains reasonably possible, that a loss has been incurred. While unable to estimate a range of loss, PPL Montana believes that any such amount would not be material. See Note 15 to the Financial Statements for additional information.
Ofgem Pricing Model
In October 2010, Ofgem announced a pricing model that will be effective for the U.K. electricity distribution sector, including WPD, beginning April 2015. The model, known as RIIO (Revenues = Incentives + Innovation + Outputs), is intended to encourage investment in regulated infrastructure. Key components of the model are: an extension of the price review period from five to eight years, increased emphasis on outputs and incentives, enhanced stakeholder engagement including network customers, a stronger incentive framework to encourage more efficient investment and innovation, expansion of the current Low Carbon Network Fund to stimulate innovation and continued use of a single weighted average cost of capital. At this time, management does not expect the impact of this pricing model to be significant to WPD's operating results.
Ofgem Review of Line Loss Calculation
WPD has a $170 million liability recorded at December 31, 2011, calculated in accordance with an accepted methodology, related to the close-out of line losses for the prior price control period, DPCR4. Ofgem is currently consulting on the methodology used to calculate the final line loss incentive/penalty for the DPCR4. In October 2011, Ofgem issued a consultation paper citing two potential changes to the methodology, both of which would result in a reduction of the liability; however, it is uncertain at this time whether any changes will be made. Ofgem is expected to make a decision before the end of 2012.
Results of Operations
The "Statement of Income Analysis" explains the year-to-year changes in significant earnings components, including certain income statement line items, Kentucky Gross Margins, Pennsylvania Gross Delivery Margins by component and Unregulated Gross Energy Margins by region.
On April 1, 2011, PPL completed its acquisition of WPD Midlands. As PPL is consolidating WPD Midlands on a one-month lag, consistent with its accounting policy on consolidation of foreign subsidiaries, eight months of WPD Midlands' results of operations are included in PPL's results for 2011, with no comparable amounts for 2010. When discussing PPL's results of
operations for 2011 compared with 2010, the results of WPD Midlands are isolated for purposes of comparability. WPD Midlands' results are included within "Segment Results - International Regulated Segment." See Note 10 to the Financial Statements for additional information regarding the acquisition.
On November 1, 2010, PPL completed its acquisition of LKE. LKE's results of operations are included in PPL's results for the full year of 2011, while 2010 includes LKE's operating results for the two months ended December 31, 2010. When discussing PPL's results of operations for 2011 compared with 2010 and 2010 compared with 2009, the results of LKE are isolated for purposes of comparability. LKE's results are shown separately within "Segment Results - Kentucky Regulated Segment." See Note 10 to the Financial Statements for additional information regarding the acquisition.
Tables analyzing changes in amounts between periods within "Segment Results" and "Statement of Income Analysis" are presented on a constant U.K. foreign currency exchange rate basis, where applicable, in order to isolate the impact of the change in the exchange rate on the item being explained. Results computed on a constant U.K. foreign currency exchange rate basis are calculated by translating current year results at the prior year weighted-average U.K. foreign currency exchange rate.
When comparing 2011 and 2010 with 2009, certain line items on PPL's financial statements were impacted by the Customer Choice Act, Act 129 and other related issues. Overall, the expiration at the end of 2009 of generation rate caps and the PLR contracts between PPL EnergyPlus and PPL Electric had a significant positive impact on PPL's 2010 results of operations, financial condition and cash flows.
The primary impacts of the expiration of the generation rate caps and the PLR contracts are reflected in PPL's Unregulated Gross Energy Margins. See "Statement of Income Analysis - Margins - Non-GAAP Financial Measures" for an explanation of this non-GAAP financial measure. In 2010, PPL sold the majority of its generation supply to unaffiliated parties under various wholesale and retail contracts at prevailing market rates at the time the contracts were executed. In 2009, the majority of generation produced by PPL's generation plants was sold to PPL Electric as PLR supply under predetermined capped rates.
Regarding PPL's Pennsylvania regulated electric delivery operations, the expiration of generation rate caps, the resulting competitive solicitations for power supply, the migration of customers to alternative suppliers, the Customer Choice Act and Act 129 had minimal impact on Pennsylvania Gross Delivery Margins, as approved recovery mechanisms allow for cost recovery of associated expenses, including the cost of energy provided as a PLR. However, PPL Electric's 2010 Pennsylvania Gross Delivery Margins were negatively impacted by the expiration of CTC recovery in December 2009. PPL Electric remains the delivery provider for all customers in its service territory and charges a regulated rate for its electricity delivery service. See "Statement of Income Analysis - Margins - Reconciliation of Non-GAAP Financial Measures" for additional information.
The changes in Net Income Attributable to PPL Corporation from year to year were, in part, attributable to the acquisition of LKE and WPD Midlands and certain items that management considers special. Details of these special items are provided within the review of each segment's earnings.
Segment Results
Net Income Attributable to PPL Corporation by segment and for "Unallocated Costs" was:
(a)
As a result of the LKE acquisition on November 1, 2010, the Kentucky Regulated segment includes two months of results in 2010.
(b)
As a result of the WPD Midlands acquisition on April 1, 2011, the International Regulated segment includes eight months of WPD Midlands' results in 2011. Similar to PPL WW, WPD Midlands' results are recorded on a one-month lag.
(c)
2010 includes $22 million, after tax ($31 million, pre-tax), of certain third-party acquisition-related costs, including advisory, accounting, and legal fees associated with the acquisition of LKE that are recorded in "Other Income (Expense) - net" on the Statement of Income. 2010 also includes $52 million, after tax ($80 million, pre-tax), of 2010 Bridge Facility costs that are recorded in "Interest Expense" on the Statement of Income. These costs are considered special items by management. See Notes 7 and 10 to the Financial Statements for additional information on the acquisition and related financing.
Kentucky Regulated Segment
The Kentucky Regulated segment consists primarily of LKE's results from the operation of regulated electricity generation, transmission and distribution assets, primarily in Kentucky, as well as in Virginia and Tennessee. This segment also includes LKE's results from the regulated distribution and sale of natural gas in Kentucky.
Net Income Attributable to PPL Corporation includes the following results:
(a)
Represents the results of operations for the two-month period from acquisition through December 31, 2010.
(b)
Includes interest expense of $70 million in 2011 and $31 million in 2010, pre-tax, related to the 2010 Equity Units and certain interest rate swaps.
The following after-tax amounts, which management considers special items, also impacted the Kentucky Regulated segment's results.
2012 Outlook
Excluding special items, PPL projects lower segment earnings in 2012 compared with 2011, primarily driven by higher operation and maintenance expense and higher depreciation, which are expected to be partially offset by higher margins.
Earnings beyond 2011 are subject to various risks and uncertainties. See "Forward-Looking Information," "Item 1. Business," "Item 1A. Risk Factors," the rest of this Item 7 and Notes 6 and 15 to the Financial Statements for a discussion of the risks, uncertainties and factors that may impact future earnings.
International Regulated Segment
The International Regulated segment consists primarily of the electric distribution operations in the U.K. As a result of the WPD Midlands acquisition on April 1, 2011, the International Regulated segment includes eight months of WPD Midlands' results in 2011. Similar to PPL WW, WPD Midlands' results are recorded on a one-month lag.
Net Income Attributable to PPL Corporation includes the following results:
(a)
2011 includes allocated interest expense of $38 million (pre-tax) related primarily to the 2011 Equity Units.
(b)
Represents the operations of WPD Midlands since the acquisition date, recorded on a one-month lag, including revenue from external customers of $790 million (pre-tax). This amount excludes acquisition-related costs incurred by WPD Midlands.
The changes in the components of the International Regulated segment's results between these periods were due to the following factors. The segment's results are adjusted for certain items that management considers special. See additional detail of these special items in the table below. The amounts for PPL WW are presented on a constant U.K. foreign currency exchange rate basis in order to isolate the impact of the change in the exchange rate.
PPL WW
·
Utility revenues increased in 2011 compared with 2010, primarily reflecting the impact of the April 2011 and 2010 price increases that resulted in $76 million of additional revenue.
Utility revenues increased in 2010 compared with 2009, reflecting the impact of the April 2010 and 2009 price increases that resulted in $52 million of additional revenue and an increase in volume that resulted in $7 million of additional revenue. These amounts were partially offset by $17 million of lower regulatory recovery due to a revised estimate of network electricity line losses.
·
Other operation and maintenance expense increased in 2011 compared with 2010, primarily due to $10 million of higher pension expense resulting from an increase in amortization of actuarial losses and $9 million of higher network maintenance expense, partially offset by $8 million of internal PPL WW costs billed to WPD Midlands.
Other operation and maintenance expense increased in 2010 compared with 2009, primarily due to $32 million of higher pension expense resulting from an increase in amortization of actuarial losses, $5 million of higher network maintenance expense and $3 million of higher direct costs.
·
Interest expense increased in 2011 compared with 2010, primarily due to $11 million of higher interest expense arising from a March 2010 debt issuance and $5 million of higher interest expense related to higher inflation rates on index-linked Senior Unsecured Notes.
Interest expense increased in 2010 compared with 2009, primarily due to $25 million of higher interest expense arising from a March 2010 debt issuance and $23 million of higher interest expense related to higher inflation rates on index-linked Senior Unsecured Notes.
·
Income taxes increased in 2011 compared with 2010, primarily due to a $46 million benefit recorded in 2010 for realized capital losses that offset a gain relating to a business activity sold in 1999 and $15 million due to higher pre-tax income.
Income taxes decreased in 2010 compared with 2009, primarily due to $46 million of realized capital losses that offset a gain relating to a business activity sold in 1999 and $14 million of lower income taxes due to lower pre-tax income, partially offset by a $29 million foreign tax benefit related to the resolution of a tax dispute and foreign currency exchange losses.
U.S.
·
Interest expense increased in 2011 compared with 2010, due to $34 million of interest expense on the 2011 Equity Units and $4 million on the 2011 Bridge Facility.
·
Income taxes decreased in 2011 compared with 2010, primarily due to a $41 million tax benefit resulting from changes in the taxable amount of planned U.K. cash repatriations, a tax benefit of $28 million from U.K. pension plan contributions and lower income taxes due to lower pre-tax income. These tax benefits were partially offset by $24 million of favorable 2010 adjustments to uncertain tax benefits primarily related to Windfall Profits Tax and $11 million of higher income taxes on interest income related to acquisition financing.
Income taxes increased in 2010 compared with 2009, primarily due to $60 million of income tax resulting from changes in the taxable amount of planned U.K. cash repatriations, partially offset by $23 million of adjustments to uncertain tax benefits, primarily related to Windfall Profits Tax.
Foreign Currency Exchange Rates
·
Changes in foreign currency exchange rates positively impacted the segment's earnings for 2011 compared with 2010 and 2010 compared with 2009. The weighted-average exchange rates for the British pound sterling, including the effects of currency hedges, were approximately $1.60 in 2011, $1.57 in 2010 and $1.49 in 2009.
The following after-tax amounts, which management considers special items, also impacted the International Regulated segment's results.
(a)
Represents unrealized gains (losses) on contracts that economically hedge anticipated earnings denominated in GBP.
(b)
Represents fees incurred in connection with establishing the 2011 Bridge Facility. See Note 7 to the Financial Statements for additional information.
(c)
Represents the foreign currency loss on the repayment of the 2011 Bridge Facility, including a pre-tax foreign currency loss of $15 million associated with proceeds received on the U.S. dollar-denominated senior notes issued by PPL WEM in April 2011 that were used to repay a portion of PPL WEM's borrowing under the 2011 Bridge Facility. The foreign currency risk was economically hedged with forward contracts to purchase GBP, which resulted in pre-tax gains of $55 million.
(d)
Represents a combination of ineffectiveness associated with closed out interest rate swaps and a charge recorded as a result of certain interest rate swaps failing hedge effectiveness testing.
(e)
Tax on the transfer of ownership of property in the U.K., which is not tax deductible for income tax purposes.
(f)
Primarily represents severance compensation, early retirement deficiency costs and outplacement services for employees separating from the WPD Midlands companies as a result of a reorganization to transition the WPD Midlands companies to the same operating structure as WPD (South West) and WPD (South Wales). Also includes severance compensation and early retirement deficiency costs associated with certain employees who separated from the WPD Midlands companies, but were not part of the reorganization.
(g)
Includes $34 million, pre-tax, of advisory, accounting and legal fees which are reflected in "Other Income (Expense) - net" on the Statements of Income. Includes $37 million, pre-tax, of costs, primarily related to the termination of certain contracts, rebranding costs and relocation costs that were recorded to "Other operation and maintenance" expense on the Statements of Income, and $6 million, pre-tax, of costs associated with the integration of certain information technology assets, that were recorded in "Depreciation" on the Statements of Income.
(h)
Relates primarily to enhanced pension and severance benefits as a result of a 2009 workforce reduction.
(i)
The U.K.'s Finance Act of 2011, enacted in July 2011, reduced the U.K. statutory income tax rate from 27% to 26% retroactive to April 1, 2011 and will further reduce the rate from 26% to 25% effective April 1, 2012. As a result, PPL reduced its net deferred tax liabilities and recognized a deferred tax benefit during 2011 related to both rate decreases. WPD Midlands' portion of the deferred tax benefit is $35 million. The U.K.'s Finance Act of 2010, enacted in July 2010, reduced the U.K. statutory income tax rate from 28% to 27% effective April 1, 2011. As a result, WPD reduced its net deferred tax liabilities and recognized a deferred tax benefit during 2010.
(j)
In 2010, the U.S. Tax Court ruled in PPL's favor in a pending dispute with the IRS concluding that the 1997 U.K. Windfall Profits Tax (WPT) imposed on all U.K. privatized utilities, including PPL's U.K. subsidiary, is a creditable tax for U.S. Federal income tax purposes. As a result, PPL recorded an income tax benefit in 2010. In January 2011, the IRS appealed the U.S. Tax Court's decision to the Court of Appeals for the Third Circuit (Third Circuit). In December 2011, the Third Circuit issued its opinion reversing the Tax Court's decision and holding that the WPT is not a creditable tax. As a result of the Third Circuit's adverse determination, PPL recorded a $39 million expense in 2011. On February 27, 2012, PPL filed with the Third Circuit a petition for rehearing of its opinion on this matter.
2012 Outlook
Excluding special items, PPL projects higher segment earnings in 2012 compared with 2011, primarily driven by a full year of earnings from WPD Midlands and higher electricity delivery revenue. Partially offsetting these positive earnings factors are higher income taxes, higher operation and maintenance expense, higher depreciation, higher financing costs and a less favorable currency exchange rate.
Earnings beyond 2011 are subject to various risks and uncertainties. See "Forward-Looking Information," "Item 1. Business," "Item 1A. Risk Factors," the rest of this Item 7 and Notes 6 and 15 to the Financial Statements for a discussion of the risks, uncertainties and factors that may impact future earnings.
Pennsylvania Regulated Segment
The Pennsylvania Regulated segment includes the regulated electric delivery operations of PPL Electric.
Net Income Attributable to PPL Corporation includes the following results:
The changes in the components of the Pennsylvania Regulated segment's results between these periods were due to the following factors. The segment's results are adjusted for certain items that management considers special. See additional detail of these special items in the table below.
·
See "Statement of Income Analysis - Margins - Changes in Non-GAAP Financial Measures" for an explanation of Pennsylvania Gross Delivery Margins.
·
Other operation and maintenance increased in 2010 compared with 2009, primarily due to $18 million in higher payroll-related costs and $20 million in higher contractor costs, primarily related to vegetation management.
·
Depreciation was higher in 2011 compared with 2010 and 2010 compared with 2009, primarily due to PP&E additions as a part of ongoing efforts to replace aging infrastructure.
·
Interest expense decreased in 2010 compared with 2009, primarily due to a $16 million reduction driven by lower average debt balances in 2010 compared with 2009.
·
Income taxes were higher in 2011 compared with 2010, due to the $26 million impact of higher pre-tax income, partially offset by a $14 million tax benefit related to the impact of flow-through regulated tax depreciation that is primarily related to the Pennsylvania Department of Revenue interpretive guidance regarding 100% bonus depreciation.
Income taxes were lower in 2010 compared with 2009, due to the $14 million impact of lower pre-tax income and a $7 million tax benefit relating to a favorable 2010 U.S. Tax Court ruling regarding street lighting assets.
The following after-tax amounts, which management considers special items, also impacted the Pennsylvania Regulated segment's results.
(a)
Charge related to a workforce reduction, mainly consisting of enhanced pension and severance benefits.
(b)
During 2009, PPL Electric received consent from the IRS to change its method of accounting for certain expenditures for tax purposes. PPL Electric deducted the resulting IRC Sec. 481 amount on its 2008 federal income tax return and recorded a $3 million adjustment to federal and state income tax expense resulting from the reversal of prior years' state income tax benefits related to regulated depreciation.
2012 Outlook
Excluding special items, PPL projects lower segment earnings in 2012 compared with 2011, primarily driven by higher operation and maintenance expenses, higher income taxes, and higher depreciation, which are expected to be partially offset by higher delivery revenue.
In late March 2012, PPL Electric expects to file a request with the PUC seeking an increase in its distribution rates beginning in January 2013. PPL Electric cannot predict the outcome of this matter.
Earnings beyond 2011 are subject to various risks and uncertainties. See "Forward-Looking Information," "Item 1. Business," "Item 1A. Risk Factors," the rest of this Item 7 and Notes 6 and 15 to the Financial Statements for a discussion of the risks, uncertainties and factors that may impact future earnings.
Supply Segment
The Supply segment primarily consists of the energy marketing and trading activities, as well as the competitive generation and development operations of PPL Energy Supply. In 2011, 2010 and 2009, PPL Energy Supply subsidiaries completed the sale of several businesses, which have been classified as Discontinued Operations. See Note 9 to the Financial Statements for additional information.
Net Income Attributable to PPL Corporation includes the following results:
(a)
Includes the impact from energy-related economic activity. See "Commodity Price Risk (Non-trading) - Economic Activity" in Note 19 to the Financial Statements for additional information.
The changes in the components of the Supply segment's results between these periods were due to the following factors. The segment's results are adjusted for certain items that management considers special. See additional detail of these special items in the table below.
·
See "Statement of Income Analysis - Margins - Changes in Non-GAAP Financial Measures" for an explanation of Unregulated Gross Energy Margins.
·
Other operation and maintenance increased in 2011 compared with 2010, primarily due to higher costs at PPL Susquehanna of $27 million, largely due to unplanned outages, the refueling outage and payroll, higher costs at eastern fossil and hydro units of $23 million, largely due to outages, and higher costs at western fossil and hydro units of $12 million, largely resulting from insurance recoveries received in 2010.
Other operation and maintenance increased in 2010 compared with 2009, primarily due to higher costs at PPL Susquehanna of $34 million largely due to higher payroll-related costs, higher outage costs, and higher project costs.
·
Depreciation increased in 2010 compared with 2009, primarily due to the $21 million impact from environmental equipment at Brunner Island that was placed in service in 2009 and early 2010.
·
Other income (expense) - net was higher in 2011 compared with 2010, due to a $22 million gain on the accelerated amortization of the fair value adjustment to the debt recorded in connection with previously settled fair value hedges. The accelerated amortization was the result of the July 2011 redemption of Senior Secured Bonds.
Other income (expense) - net was lower in 2010 compared with 2009, due to a $29 million gain recognized in 2009 related to the tender offers to purchase debt that resulted from reclassifying net gains on related cash flow hedges from AOCI into earnings, partially offset by a $15 million decrease in other-than-temporary impairment charges, primarily due to stronger returns on investments in NDT funds in 2010.
·
Income taxes decreased in 2011 compared with 2010, primarily due to the $204 million impact of lower pre-tax income and a $26 million reduction in deferred tax liabilities related to a change in the Pennsylvania estimated state tax rate. These decreases were partially offset by $101 million in Pennsylvania net operating loss valuation allowance adjustments, primarily related to lower projected future taxable income, driven in part by the impact of bonus depreciation, $16 million in favorable adjustments to uncertain tax benefits recorded in 2010 and an $11 million decrease in the domestic manufacturing deduction tax benefit resulting from revised bonus depreciation estimates.
Income taxes increased in 2010 compared with 2009, primarily due to the $348 million impact of higher pre-tax income, partially offset by a $52 million in Pennsylvania net operating loss valuation allowance adjustments, primarily related to higher projected future taxable income, $10 million in investment tax credits associated with the Holtwood and Rainbow projects, $11 million in favorable adjustments to uncertain tax benefits recorded in 2010 and $8 million of higher tax benefits from the domestic manufacturing deduction.
The following after-tax amounts, which management considers special items, also impacted the Supply segment's results.
(a)
See "Reconciliation of Economic Activity" below.
(b)
Gains recorded on the sale of the Maine hydroelectric generation business. See Note 9 to the Financial Statements for additional information.
(c)
Consists primarily of the initial impairment charge recorded when the business was classified as held for sale. See Note 9 to the Financial Statements for additional information.
(d)
Primarily represents impairment charges of sulfur dioxide emission allowances.
(e)
Relates primarily to enhanced pension and severance benefits as a result of a 2009 workforce reduction.
(f)
In July 2010, in order to raise additional cash for the LKE acquisition, certain full-requirement sales contracts were monetized that resulted in cash proceeds of $249 million. See "Monetization of Certain Full-Requirement Sales Contracts" in Note 19 to the Financial Statements for additional information. $343 million of pre-tax gains were recorded to "Wholesale energy marketing" and $557 million of pre-tax losses were recorded to "Energy purchases" on the Statements of Income.
(g)
As a result of the expected net proceeds from the anticipated sale of certain non-core generation facilities, coupled with the monetization of certain full-requirement sales contracts, debt that had been planned to be issued by PPL Energy Supply in 2010 was no longer needed. As a result, hedge accounting associated with interest rate swaps entered into by PPL in anticipation of a debt issuance by PPL Energy Supply was discontinued.
(h)
In October 2010, PPL Energy Supply made borrowings under its Syndicated Credit Facility in order to enable a subsidiary to make loans to certain affiliates to provide interim financing of amounts required by PPL to partially fund PPL's acquisition of LKE. Subsequent to the repayment of such borrowing, the capacity was reduced, and as a result, PPL Energy Supply wrote off deferred fees in 2010.
(i)
In 2009, PPL Montana adjusted its previously recorded accrual related to hydroelectric litigation, of which $5 million, pre-tax, related to prior periods. In March 2010, the Montana Supreme Court substantially affirmed a June 2008 Montana District Court decision regarding lease payments for the use of certain Montana streambeds. In 2010, PPL Montana recorded a pre-tax charge of $56 million, representing estimated rental compensation for years prior to 2010, including interest. Of this total charge $47 million, pre-tax, was recorded to "Other operation and maintenance" and $9 million, pre-tax, was recorded to "Interest Expense" on the Statements of Income. In August 2010, PPL Montana filed a petition for a writ of certiorari with the U.S. Supreme Court requesting the Court's review of this matter. In June 2011, the U.S. Supreme Court granted PPL Montana's petition. In February 2012, the U.S. Supreme Court overturned the Montana Supreme Court decision and remanded the case to the Montana Supreme Court for further proceedings consistent with the U.S. Supreme Court's opinion. Prior to the U.S. Supreme Court decision, $4 million, pre-tax, of interest expense on the rental compensation covered by the court decision was accrued in 2011. As a result of the U.S. Supreme Court decision, PPL Montana reversed its total pre-tax loss accrual of $89 million, which had been recorded prior to the U.S. Supreme Court decision, of which $79 million pre-tax is considered a special item because it represented $65 million of rent for periods prior to 2011 and $14 million of interest accrued on the portion covered by the prior court decision. These amounts were credited to "Other operation and maintenance" and "Interest Expense" on the Statement of Income.
(j)
In May 2011, PPL Susquehanna entered into a settlement agreement with the U.S. Government relating to PPL Susquehanna's lawsuit, seeking damages for the Department of Energy's failure to accept spent nuclear fuel from the PPL Susquehanna plant. PPL Susquehanna recorded credits to fuel expense to recognize recovery, under the settlement agreement, of certain costs to store spent nuclear fuel at the Susquehanna plant. This special item represents amounts recorded in 2011 to cover the costs incurred from 1998 through December 2010.
(k)
Represents income tax expense recorded as a result of the provisions within Health Care Reform which eliminated the tax deductibility of retiree health care costs to the extent of federal subsidies received by plan sponsors that provide retiree prescription drug benefits equivalent to Medicare Part D Coverage.
(l)
During 2009, PPL Energy Supply received consent from the IRS to change its method of accounting for certain expenditures for tax purposes. PPL Energy Supply deducted the resulting IRC Sec. 481 amount on its 2008 federal income tax return and recorded a $21 million adjustment to federal and state income tax expense resulting from the reduction in federal income tax benefits related to the domestic manufacturing deduction and certain state tax benefits related to state net operating losses.
(m)
In October 2011, a wholesale customer, SMGT, filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy code. The customer has continued to purchase electricity at the price specified in the supply contract, and has made timely payments for such purchases, but at lower volumes than as prescribed in the contract. As of December 31, 2011, the damage claim totaled $11 million pre-tax, which was fully reserved.
(n)
In January 2012, PPL received $7 million pre-tax, related to electricity delivered to a wholesale customer in 2008 and 2009, recorded in "Wholesale energy marketing-Realized." The additional revenue results from several transmission projects approved at PJM for recovery that were not initially anticipated at the time of the electricity auctions and therefore were not included in the auction pricing. A FERC order was issued in 2011 approving the disbursement of these supply costs by the wholesale customer to the suppliers, therefore, PPL accrued its share of this additional revenue in 2011.
Reconciliation of Economic Activity
The following table reconciles unrealized pre-tax gains (losses) from the table within "Commodity Price Risk (Non-trading) - Economic Activity" in Note 19 to the Financial Statements to the special item identified as "Adjusted energy-related economic activity, net."
(a)
See Note 19 to the Financial Statements for additional information.
(b)
Adjustment for the net deferral and amortization of option premiums over the delivery period of the item that was hedged or upon realization. Option premiums are recorded in "Wholesale energy marketing - Realized" and "Energy purchases - Realized" on the Statements of Income.
(c)
See "Components of Monetization of Certain Full-Requirement Sales Contracts" below.
Components of Monetization of Certain Full-Requirement Sales Contracts
The following table provides the components of the "Monetization of Certain Full-Requirement Sales Contracts" special item.
(a)
See "Commodity Price Risk (Non-trading) - Monetization of Certain Full-Requirement Sales Contracts" in Note 19 to the Financial Statements for additional information.
(b)
Includes unrealized losses of $251 million, which are reflected in "Wholesale energy marketing - Unrealized economic activity" and "Energy purchases - Unrealized economic activity" on the Statement of Income. Also includes net realized gains of $37 million, which are reflected in "Wholesale energy marketing - Realized" and "Energy purchases - Realized" on the Statement of Income. This economic activity will continue to be realized through May 2013.
2012 Outlook
Excluding special items, PPL projects lower segment earnings in 2012 compared with 2011. The decrease is primarily driven by lower energy margins as a result of further declines in energy and capacity prices and higher fuel costs, higher operation and maintenance expenses and higher depreciation, which are partially offset by higher baseload generation.
Earnings beyond 2011 are subject to various risks and uncertainties. See "Forward-Looking Information," "Item 1. Business," "Item 1A. Risk Factors," the rest of this Item 7 and Note 15 to the Financial Statements for a discussion of the risks, uncertainties and factors that may impact future earnings.
Statement of Income Analysis --
Margins
Non-GAAP Financial Measures
The following discussion includes financial information prepared in accordance with GAAP, as well as three non-GAAP financial measures: "Kentucky Gross Margins," "Pennsylvania Gross Delivery Margins" and "Unregulated Gross Energy Margins." These measures are not intended to replace "Operating Income," which is determined in accordance with GAAP, as an indicator of overall operating performance. Other companies may use different measures to analyze and to report on the results of their operations. PPL believes that these measures provide additional criteria to make investment decisions. These performance measures are used, in conjunction with other information, internally by senior management and the Board of Directors to manage the Kentucky Regulated, Pennsylvania Regulated and Supply segment operations, analyze each respective segment's actual results compared with budget and, in certain cases, to measure certain corporate financial goals used in determining variable compensation.
PPL's three non-GAAP financial measures include:
·
"Kentucky Gross Margins" is a single financial performance measure of the Kentucky Regulated segment's electricity generation, transmission and distribution operations as well as its distribution and sale of natural gas. In calculating this measure, utility revenues and expenses associated with approved cost recovery tracking mechanisms are offset. Certain costs associated with these mechanisms, primarily ECR and DSM, are recorded as "Other operation and maintenance" expense and the depreciation associated with ECR equipment is recorded as "Depreciation" expense. These mechanisms allow for recovery of certain expenses, returns on capital investments and performance incentives. As a result, this measure represents the net revenues from the Kentucky Regulated segment's operations.
·
"Pennsylvania Gross Delivery Margins" is a single financial performance measure of the Pennsylvania Regulated segment's electric delivery operations, which includes transmission and distribution activities. In calculating this measure, utility revenues and expenses associated with approved recovery mechanisms, including energy provided as a PLR, are offset with minimal impact on earnings. Costs associated with these mechanisms are recorded in "Energy purchases," "Other operation and maintenance-" expense, which is primarily Act 129 costs, and in "Taxes, other than income," which is primarily gross receipts tax. These mechanisms allow for recovery of certain expenses; therefore, certain expenses and revenues offset with minimal impact on earnings. This performance measure includes PLR energy purchases by PPL Electric from PPL EnergyPlus, which are reflected in "PLR intersegment Utility revenue (expense)" in the table below. As a result, this measure represents the net revenues from the Pennsylvania Regulated segment's electric delivery operations.
·
"Unregulated Gross Energy Margins" is a single financial performance measure of the Supply segment's competitive energy non-trading and trading activities. In calculating this measure, the Supply segment's energy revenues, which include operating revenues associated with certain Supply segment businesses that are classified as discontinued operations, are offset by the cost of fuel, energy purchases, certain other operation and maintenance expenses, primarily ancillary charges, gross receipts tax, which is recorded in "Taxes, other than income," and operating expenses associated with certain Supply segment businesses that are classified as discontinued operations. This performance measure is relevant to PPL due to the volatility in the individual revenue and expense lines on the Statements of Income that
comprise "Unregulated Gross Energy Margins." This volatility stems from a number of factors, including the required netting of certain transactions with ISOs and significant swings in unrealized gains and losses. Such factors could result in gains or losses being recorded in either "Wholesale energy marketing" or "Energy purchases" on the Statements of Income. This performance measure includes PLR revenues from energy sales to PPL Electric by PPL EnergyPlus, which are reflected in "PLR intersegment Utility revenue (expense)" in the table below. PPL excludes from "Unregulated Gross Energy Margins" the Supply segment's energy-related economic activity, which includes the changes in fair value of positions used to economically hedge a portion of the economic value of PPL's competitive generation assets, full-requirement sales contracts and retail activities. This economic value is subject to changes in fair value due to market price volatility of the input and output commodities (e.g., fuel and power) prior to the delivery period that was hedged. Also included in this energy-related economic activity is the ineffective portion of qualifying cash flow hedges, the monetization of certain full-requirement sales contracts and premium amortization associated with options. This economic activity is deferred, with the exception of the full-requirement sales contracts that were monetized, and included in unregulated gross energy margins over the delivery period that was hedged or upon realization.
Reconciliation of Non-GAAP Financial Measures
The following tables reconcile "Operating Income" to PPL's three non-GAAP financial measures.
(a)
Represents amounts excluded from Margins.
(b)
As reported on the Statement of Income.
(c)
LKE was acquired on November 1, 2010. Kentucky Gross Margins were not used to measure the financial performance of the Kentucky Regulated segment in 2010.
(d)
Primarily represents WPD's utility revenue. 2010 also includes LKE's utility revenues for the two-month period subsequent to the November 1, 2010 acquisition.
(e)
Primarily related to PLR supply sold by PPL EnergyPlus to PPL Electric.
(f)
Represents energy-related economic activity, as described in "Commodity Price Risk (Non-trading) - Economic Activity" within Note 19 to the Financial Statements. For 2011, "Wholesale energy marketing - Realized" and "Energy purchases - Realized" include a net pre-tax gain of $19 million related to the amortization of option premiums and a net pre-tax loss of $216 million related to the monetization of certain full-requirement sales contracts. 2010 includes a net pre-tax gain of $32 million related to the amortization of option premiums and a net pre-tax gain of $37 million related to the monetization of certain full-requirement sales contracts. 2009 includes a net pre-tax loss of $54 million related to the amortization of option premiums.
(g)
Represents energy-related economic activity, which is subject to wide swings in value due to market price volatility, as described in "Commodity Price Risk (Non-trading) - Economic Activity" within Note 19 to the Financial Statements.
(h)
Includes economic activity related to fuel. 2011 includes credits of $57 million for the spent nuclear fuel litigation settlement.
(i)
Represents the net of certain revenues and expenses associated with certain businesses that are classified as discontinued operations. These revenues and expenses are not reflected in "Operating Income" on the Statements of Income.
Changes in Non-GAAP Financial Measures
The following table shows PPL's three non-GAAP financial measures, as well as the change between periods. The factors that gave rise to the changes are described below the table.
(a)
LKE was acquired on November 1, 2010. Kentucky Gross Margins were not used to measure the financial performance of the Kentucky Regulated segment in 2010.
Kentucky Gross Margins
PPL acquired LKE on November 1, 2010. Margins for 2011 are included in PPL's results without comparable amounts for 2010.
Pennsylvania Gross Delivery Margins
Distribution
The PPL Electric distribution rate case increased rates by approximately 1.6% effective January 1, 2011, which improved residential distribution margins by $68 million. Residential volume variances increased margins by an additional $4 million for 2011, compared with the same period in 2010. Weather had a $3 million unfavorable impact for residential customers for 2011 compared with 2010. Weather-related variances for PPL Electric are calculated based on a ten-year historical average. Lastly, lower demand charges and increased efficiency as a result of Act 129 programs resulted in a $5 million decrease in margins for commercial and industrial customers.
The decrease in 2010 compared with 2009 was primarily due to margins realized in 2009 related to the collection of CTC that ended in December 2009 of $37 million, partially offset by favorable recovery mechanisms for certain energy-related costs of $16 million.
Transmission
The increase in 2010 compared with 2009 was primarily due to increased investment in rate base, an increase in the cost of capital due to an increase in equity and the recovery of additional costs through the FERC formula-based rates.
(a)
Baseload energy and capacity prices were lower in 2011 than 2010; however, prices in 2010 for baseload generation were significantly higher than prices realized under the PLR contract with PPL Electric that expired at the end of 2009.
(b)
Volumes were lower in 2011 compared with 2010 as a result of unplanned outages, economic reductions in coal unit output and the sale of our interest in Safe Harbor Water Power Corporation. Volumes were higher in 2010 compared with 2009 as a result of planned overhauls.
(c)
Lower margins in 2011 compared with 2010 were driven by lower capacity prices, partially offset by higher generation volumes in the first half of 2011. Higher margins in 2010 compared with 2009 were due to higher energy and capacity prices.
(d)
Volumes were lower in 2011 compared with 2010 primarily as a result of the dual-unit turbine blade replacement outages beginning in May 2011. Volumes were lower in 2010 compared with 2009 primarily due to an unplanned outage in July 2010.
(e)
Higher margins in 2011 compared with 2010 were driven by contracts monetized in 2010 and lower customer migration to alternative suppliers in 2011. Lower margins in 2010 compared with 2009 were driven by lower customer demand and higher customer migration to alternative suppliers.
Western U.S.
Western U.S. non-trading margins were higher in 2011 compared with 2010, due to higher net wholesale prices of $58 million, partially offset by lower wholesale volumes of $45 million, primarily due to economic reductions in coal unit output.
Western U.S. non-trading margins were higher in 2010 compared with 2009, primarily due to higher net wholesale prices of $11 million and higher wholesale volumes of $14 million, due to unplanned outages in 2009.
Net Energy Trading Margins
Net energy trading margins decreased during 2011 compared with 2010, as a result of lower margins on power positions of $16 million, partially offset by higher margins on gas positions of $12 million.
Net energy trading margins decreased during 2010 compared with 2009, as a result of lower margins on power and gas positions of $40 million, partially offset by higher trading margins related to FTRs of $22 million.
(a)
The increase in 2011 compared with 2010 is primarily due to the January 1, 2011 increase in distribution rates. See "Pennsylvania Gross Delivery Margins" for further information.
(b)
These changes in revenue had a minimal impact on earnings as the cost of supplying this energy as a PLR is passed through to the customer with no additional mark-up. These revenues are offset primarily with energy purchases in "Pennsylvania Gross Delivery Margins."
(c)
Amounts in each period are not comparable. 2010 includes two months of activity as LKE was acquired in November 2010.
(d)
The increase in 2011 compared with 2010 is due to price increases effective April 1, 2011 and April 1, 2010. The increase in 2010 compared with 2009 is due to price increases effective April 1, 2010 and April 1, 2009.
(e)
The decrease in 2011 compared with 2010 is primarily due to the downturn in the economy and weather. The increase in 2010 compared with 2009 is primarily due to weather.
(f)
Primarily due to a revised estimate of network electricity line losses.
(g)
There are no comparable amounts in 2010 as WPD Midlands was acquired in April 2011. 2011 includes eight months of activity as WPD Midlands' results are recorded on a one-month lag.
(a)
Amounts in each period are not comparable. 2010 includes two months of activity as LKE was acquired in November 2010.
(b)
Relates to costs associated with a PUC-approved energy efficiency and conservation plan. These costs are recovered in customer rates. There are currently 15 Act 129 programs which began in 2010 and continued to ramp up in 2011.
(c)
In March 2010, the Montana Supreme Court substantially affirmed a June 2008 Montana District Court decision regarding lease payments for the use of certain Montana streambeds. As a result, in the first quarter of 2010, PPL Montana recorded a charge of $56 million, representing estimated rental compensation for the first quarter of 2010 and prior years, including interest. The portion of the total charge recorded to "Other operation and maintenance" on the Statement of Income totaled $49 million. In August 2010, PPL Montana filed a petition for a writ of certiorari with the U.S. Supreme Court requesting the Court's review of this matter. In June 2011, the U.S. Supreme Court granted PPL Montana's petition. In February 2012, the U.S. Supreme Court overturned the Montana Supreme Court decision and remanded the case to the Montana Supreme Court for further proceedings consistent with the U.S. Supreme Court's opinion. As a result, PPL Montana reversed its total loss accrual of $89 million, which had been recorded prior to the U.S. Supreme Court decision, of which $75 million was credited to "Other operation and maintenance" on the Statement of Income.
(d)
In 2010, PPL Electric increased its vegetation management around its 230- and 500-kV transmission lines in response to federal reliability requirements for transmission vegetation management.
(e)
2011 compared with 2010 was higher primarily due to $11 million of higher payroll-related costs, $10 million of higher outage costs and $8 million of higher costs from the refueling outage. 2010 compared with 2009 was higher primarily due to $10 million of higher payroll-related costs, $8 million of higher outage costs and $5 million of higher project costs.
(f)
2011 compared with 2010 was higher primarily due to $8 million of lower insurance proceeds. 2010 compared with 2009 was lower primarily due to $10 million of higher insurance proceeds.
(g)
2011 compared with 2010 was higher primarily due to plant outage costs of $13 million.
(h)
Represents the charge related to the February 2009, announcement of workforce reductions that resulted in the elimination of certain management and staff positions.
(i)
2011 compared with 2010 was lower due to lower impairment charges of sulfur dioxide emission allowances. 2010 compared with 2009 was lower primarily due to lower impairment charges of sulfur dioxide emission allowances.
(j)
2011 compared with 2010 was higher primarily due to SMGT filing for protection under Chapter 11 of the U.S. Bankruptcy Code, $11 million of damages billed to SMGT were fully reserved.
(k)
Both periods were higher due to higher pension costs resulting primarily from increased amortization of actuarial losses.
(l)
2011 includes $93 million of severance compensation, early retirement deficiency costs and outplacement services for employees separating from the WPD Midlands companies as a result of a reorganization to transition the WPD Midlands companies to the same operating structure as WPD (South West) and WPD (South Wales) and $35 million of other acquisition related costs.
(m)
There are no comparable amounts in the 2010 period as WPD Midlands was acquired in April 2011. 2011 includes eight months of activity as WPD Midlands' results are recorded on a one-month lag.
Depreciation
The changes in depreciation expense were due to:
(a)
For 2011 compared with 2010, the $20 million increase was partially due to PP&E additions as part of PPL Electric's ongoing efforts to replace aging infrastructure. For 2010 compared with 2009, $21 million of the increase was primarily due to the completion of environmental projects at Brunner Island in 2009 and 2010.
(b)
For 2011 compared with 2010, $32 million of depreciation expense related to TC2, which began to dispatch in January 2011.
(c)
Amounts in each period are not comparable. 2010 includes two months of activity for LKE as it was acquired in November 2010.
(d)
There are no comparable amounts in 2010 for WPD Midlands as it was acquired in April 2011. 2011 includes eight months of activity for WPD Midlands, as its results are recorded on a one-month lag.
Taxes, Other Than Income
The changes in taxes, other than income were due to:
(a)
The decrease in 2010 compared with 2009 was primarily due to a decrease in electricity revenue as customers chose alternative suppliers in 2010. This tax is included in "Unregulated Gross Energy Margins" and "Pennsylvania Gross Delivery Margins" above.
(b)
The decrease in 2011 compared with 2010 was primarily due to the amortization of the PURTA refund. This tax is included in "Pennsylvania Gross Delivery Margins" above.
(c)
The increase in 2011 compared with 2010 was due in part to the expiration of the Keystone Opportunity Zone credit in 2010 and an agreed to change in a capital stock filing position with the state.
(d)
Amounts in each period are not comparable. 2010 includes two months of activity as LKE was acquired in November 2010.
(e)
There are no comparable amounts in the 2010 period as WPD Midlands was acquired in April 2011. 2011 includes 8 months of activity as WPD Midlands' results are recorded on a one-month lag.
(f)
The decrease in 2010 compared with 2009 primarily relates to lower WPD real estate tax expense due to reductions in tax rates.
Other Income (Expense) - net
The $35 million increase in other income (expense) - net in 2011 compared with 2010 was primarily attributable to:
·
a $22 million gain on the accelerated amortization of the fair value adjustment to the debt recorded in connection with previously settled fair value hedges. The accelerated amortization was the result of the July 2011 redemption of PPL Electric's 7.125% Senior Secured Bonds due 2013;
·
$29 million of net losses reclassified from AOCI into earnings in 2010 resulting from the discontinuation of interest rate swaps entered into in anticipation of a debt issuance by PPL Energy Supply;
·
$7 million of increases in gains from economic foreign currency exchange contracts;
·
$31 million of LKE other acquisition-related costs recorded in 2010;
·
$55 million of WPD Midlands other acquisition-related costs recorded in 2011, including U.K. stamp duty tax; and
·
a $57 million foreign currency loss related to the repayment of the 2011 Bridge Facility borrowing, offset by a $55 million gain on foreign currency forward contracts that hedged the repayment of such borrowings.
The $78 million decrease in other income (expense) - net in 2010 compared with 2009 was primarily attributable to:
·
$29 million of net losses reclassified from AOCI into earnings in 2010 resulting from the discontinuation of interest rate swaps entered into in anticipation of a debt issuance by PPL Energy Supply;
·
$31 million of LKE other acquisition-related costs recorded in 2010;
·
a $29 million gain on PPL Energy Supply's tender offers to purchase up to $250 million aggregate principal amount of certain of its outstanding senior notes including net gains on related cash flow hedges that were reclassified from AOCI into earnings in 2009; and
·
a $12 million increase in gains from economic foreign currency exchange contracts.
Other-Than-Temporary Impairments
Other-than-temporary impairments decreased by $15 million in 2010 compared with 2009, primarily due to stronger returns on NDT investments caused by market fluctuations within the financial markets.
Interest Expense
The changes in interest expense were due to:
(a)
Interest related to the June 2010 issuance to support the November 2010 LKE acquisition.
(b)
Interest related to the April 2011 issuance to support the April 2011 WPD Midlands acquisition.
(c)
Amounts in each period are not comparable. 2010 includes two months of activity as LKE was acquired in November 2010.
(d)
There are no comparable amounts in 2010 as WPD Midlands was acquired in April 2011. 2011 includes eight months of activity as WPD Midlands' results are recorded on a one-month lag. 2011 Bridge Facility costs of $23 million are included in "2011 Bridge Facility costs related to the acquisition of WPD Midlands" above.
(e)
In March 2010, the Montana Supreme Court substantially affirmed a June 2008 Montana District Court decision regarding lease payments for the use of certain Montana streambeds. As a result, in the first quarter of 2010, PPL Montana recorded $7 million of interest expense on rental compensation covered by the court decision. In August 2010, PPL Montana filed a petition for a writ of certiorari with the U.S. Supreme Court requesting the Court's review of this matter. In June 2011, the U.S. Supreme Court granted PPL Montana's petition. Oral argument was held in December 2011. PPL Montana continued to accrue interest expense on the rental compensation covered by the court decision. In February 2012, the U.S. Supreme Court overturned the Montana Supreme Court decision and remanded the case to the Montana Supreme Court for further proceedings consistent with the U.S. Supreme Court's opinion. As a result, PPL Montana reversed its total loss accrual of $89 million, which had been recorded prior to the U.S. Supreme Court decision, of which $14 million was credited to "Interest Expense" on the Statement of Income.
Income Taxes
The changes in income taxes were due to:
(a)
Reflects the impact of Pennsylvania Department of Revenue interpretive guidance issued during 2011 on the treatment of bonus depreciation for Pennsylvania income tax purposes. In accordance with Corporation Tax Bulletin 2011-01, Pennsylvania allows 100% bonus depreciation for qualifying assets in the same year bonus depreciation is allowed for federal income tax purposes. Due to the decrease in taxable income related to bonus depreciation and a decrease in projected future taxable income, PPL recorded a $43 million state deferred income tax expense related to deferred tax valuation allowances during 2011.
Additionally, the 100% Pennsylvania bonus depreciation deduction created a current state income tax benefit for the flow-through impact of Pennsylvania regulated state tax depreciation.
Pennsylvania H.B. 1531, enacted during 2009, increased the net operating loss limitation to 20% of taxable income for tax years beginning in 2010. During 2009, based on the projected revenue increase due to the expiration of the Pennsylvania generation rate caps in 2010, PPL recorded a $13 million state deferred income tax benefit related to the reversal of deferred tax valuation allowances for a portion of its Pennsylvania net operating losses. During 2010, PPL recorded an additional $72 million state deferred income tax benefit related to the reversal of deferred tax valuation allowances related to the future projections of taxable income over the remaining carryforward period of the net operating losses.
(b)
During 2011, PPL completed the sale of certain non-core generating assets (see Note 9 to the Financial Statements for additional information). Due to changes in state apportionment resulting in the reduction in the future estimated state tax rate, PPL recorded a deferred tax benefit related to its December 31, 2011 state deferred tax liabilities.
(c)
In December 2010, Congress enacted legislation allowing for 100% bonus depreciation on qualified property. The increased tax depreciation eliminated the income tax benefit related to the domestic manufacturing deduction in 2011.
(d)
In 1997, the U.K. imposed a Windfall Profits Tax on privatized utilities, including WPD. In September 2010, the U.S. Tax Court ruled in PPL's favor in a dispute with the IRS, concluding that the U.K. Windfall Profits Tax is a creditable tax for U.S. tax purposes. As a result and with the finalization of other issues, PPL recorded a $42 million tax benefit in 2010. In January 2011, the IRS appealed the U.S. Tax Court's decision to the U.S. Court of Appeals for the Third Circuit. In December 2011, the Third Circuit issued its opinion reversing the Tax Court's decision and holding that the Windfall Profits Tax is not a creditable tax. As a result of the Third Circuit's adverse determination, PPL recorded a $39 million expense in 2011. On February 27, 2012, PPL filed with the Third Circuit a petition for rehearing of its opinion on this matter.
In 2010, the U.S. Tax Court ruled in PPL's favor in a dispute with the IRS, concluding that street lighting assets are depreciable for tax purposes over seven years. As a result, PPL recorded a $7 million tax benefit to federal and state income tax reserves and related deferred income taxes during 2010.
During 2011, 2010 and 2009 PPL recorded a $6 million, $7 million and $6 million tax benefit to federal and state income tax reserves related to stranded cost securitization.
(e)
During 2011, PPL recorded a $28 million federal income tax benefit related to U.K. pension contributions.
During 2010, PPL recorded additional U.S. income tax expense resulting from increased taxable dividends and certain restructuring of U.K. entities.
(f)
The U.K.'s Finance Act of 2011, enacted during 2011, included reductions in the U.K. statutory income tax rate. The statutory income tax rate was reduced from 27% to 26% retroactive to April 1, 2011 and will be reduced from 26% to 25 % effective April 1, 2012. As a result, PPL reduced its net deferred tax liabilities and recognized a deferred tax benefit of $69 million in 2011. WPD Midlands' portion of the deferred tax benefit is $34 million.
The U.K.'s Finance Act of 2010, enacted during 2010, included a reduction in the U.K. statutory income tax rate. Effective April 1, 2011, the statutory income tax rate was reduced from 28% to 27%. As a result, PPL reduced its net deferred tax liabilities and recognized a deferred tax benefit of $18 million during 2010.
(g)
During 2011, WPD reached an agreement with the HM Revenue & Customs, the U.K. tax authority, related to the amount of the capital losses that resulted from prior years' restructuring in the U.K. and recorded a $147 million foreign tax benefit for the reversal of tax reserves related to the capital losses. Additionally, WPD recorded a $147 million valuation allowance for the amount of capital losses that, more likely than not, will not be realized.
During 2010, PPL recorded a $261 million foreign tax benefit in conjunction with losses resulting from restructuring in the U.K. A portion of these losses offset tax on a deferred gain from a prior year sale of WPD's supply business. WPD recorded a $215 million valuation allowance for the amount of capital losses that, more likely than not, will not be realized.
During 2009, PPL recorded a $46 million foreign tax benefit and a related $46 million tax reserve related to losses resulting from restructuring in the U.K. Additionally, PPL recorded a $29 million foreign tax benefit related to the resolution of a tax dispute and foreign currency exchange losses.
(h)
Amounts in each period are not comparable. 2010 includes two months of activity as LKE was acquired in November 2010.
(i)
There are no comparable amounts in 2010 as WPD Midlands was acquired in April 2011. 2011 includes eight months of activity as WPD Midlands' results are recorded on a one-month lag.
See Note 5 to the Financial Statements for additional information on income taxes.
Discontinued Operations
Income (Loss) from Discontinued Operations (net of income taxes) increased by $19 million in 2011 compared with 2010 and decreased by $10 million in 2010 compared with 2009. Both periods were impacted by after-tax impairment charges recorded in 2010 totaling $62 million related to assets associated with certain non-core generation facilities sold in 2011 that were written down to their estimated fair value (less cost to sell). The impacts of these charges were offset by the net results of certain other discontinued operations. See Note 9 to the Financial Statements for additional information.
Financial Condition
Liquidity and Capital Resources
PPL expects to continue to have adequate liquidity available through operating cash flows, cash and cash equivalents and its credit facilities. Additionally, subject to market conditions, PPL currently plans to access capital markets in 2012.
PPL's cash flows from operations and access to cost-effective bank and capital markets are subject to risks and uncertainties including, but not limited to:
·
changes in electricity, fuel and other commodity prices;
·
operational and credit risks associated with selling and marketing products in the wholesale power markets;
·
potential ineffectiveness of the trading, marketing and risk management policy and programs used to mitigate PPL's risk exposure to adverse changes in electricity and fuel prices, interest rates, foreign currency exchange rates and counterparty credit;
·
unusual or extreme weather that may damage PPL's transmission and distribution facilities or affect energy sales to customers;
·
reliance on transmission and distribution facilities that PPL does not own or control to deliver its electricity and natural gas;
·
unavailability of generating units (due to unscheduled or longer-than-anticipated generation outages, weather and natural disasters) and the resulting loss of revenues and additional costs of replacement electricity;
·
the ability to recover and the timeliness and adequacy of recovery of costs associated with regulated utility businesses;
·
costs of compliance with existing and new environmental laws and with new security and safety requirements for nuclear facilities;
·
any adverse outcome of legal proceedings and investigations with respect to PPL's current and past business activities;
·
deterioration in the financial markets that could make obtaining new sources of bank and capital markets funding more difficult and more costly; and
·
a downgrade in PPL's or its rated subsidiaries' credit ratings that could adversely affect their ability to access capital and increase the cost of credit facilities and any new debt.
See "Item 1A. Risk Factors" for further discussion of risks and uncertainties affecting PPL's cash flows.
At December 31, PPL had the following:
(a)
2010 amount represents tax-exempt bonds issued by Louisville/Jefferson County, Kentucky on behalf of LG&E that were subsequently purchased by LG&E. Such bonds were remarketed to unaffiliated investors in January 2011. See Note 7 to the Financial Statements for further discussion.
At December 31, 2011, $411 million of cash and cash equivalents and $16 million of short-term investments were denominated in GBP. If these amounts would be remitted as dividends, PPL may be subject to additional U.S. taxes, net of allowable foreign tax credits. Historically, dividends paid by foreign subsidiaries have been distributions of the current year's earnings. See Note 5 to the Financial Statements for additional information on undistributed earnings of WPD.
The changes in PPL's cash and cash equivalents position resulted from:
Operating Activities
Net cash provided by operating activities increased by 23%, or $474 million, in 2011 compared with 2010. The increase was the net effect of:
·
operating cash provided by LKE, $743 million, and WPD Midlands, $234 million;
·
cash from components of working capital, $435 million, primarily related to changes in prepaid income and gross receipts taxes; partially offset by
·
reduction in cash from counter party collateral, $172 million:
·
lower gross energy margins, $240 million after-tax:
·
proceeds from monetizing certain full-requirement sales contracts in 2010, $249 million:
·
higher interest payments of $44 million; and
·
increases in other operating outflows of $233 million (including $90 million of higher operation and maintenance expenses and defined benefits funding).
Net cash provided by operating activities increased by 10%, or $181 million in 2010 compared with 2009. The expiration of the long-term power purchase agreements between PPL Electric and PPL EnergyPlus at the end of 2009 enabled PPL
EnergyPlus to sell power at higher market prices and had a positive impact on net income, and specifically on "unregulated gross energy margins" which increased over $600 million, after-tax, in 2010 compared with 2009, and therefore, was the primary driver to the above increase. The positive impact of additional earnings was partially offset by a reduction in the amount of counterparty collateral received and by additional defined benefit plan contributions.
A significant portion of PPL's Supply segment operating cash flows is derived from its competitive baseload generation business activities. PPL employs a formal hedging program for its baseload generation fleet, the primary objective of which is to provide a reasonable level of near-term cash flow and earnings certainty while preserving upside potential of power price increases over the medium term. See Note 19 to the Financial Statements for further discussion. Despite PPL's hedging practices, future cash flows from operating activities from its Supply segment are influenced by commodity prices and therefore, will fluctuate from period to period.
PPL's contracts for the sale and purchase of electricity and fuel often require cash collateral or other credit enhancements, or reductions or terminations of a portion of the entire contract through cash settlement, in the event of a downgrade of PPL's or its subsidiaries' credit ratings or adverse changes in market prices. For example, in addition to limiting its trading ability, if PPL's or its subsidiaries' ratings were lowered to below "investment grade" and there was a 10% adverse movement in energy prices, PPL estimates that, based on its December 31, 2011 positions, it would have had to post additional collateral of approximately $435 million with respect to electricity and fuel contracts. PPL has in place risk management programs that are designed to monitor and manage its exposure to volatility of cash flows related to changes in energy and fuel prices, interest rates, foreign currency exchange rates, counterparty credit quality and the operating performance of its generating units.
Investing Activities
The primary use of cash in investing activities in 2011 was for the acquisition of WPD Midlands. In 2010, the primary use of cash in investing activities was for the acquisition of LKE. In 2009, the primary use of cash in investing activities was for capital expenditures. See "Forecasted Uses of Cash" for detail regarding projected capital expenditures for the years 2012 through 2016.
Net cash used in investing activities was $7.9 billion in 2011 compared with $8.2 billion in 2010. The 2011 amount includes the use of $5.8 billion of cash for the acquisition of WPD Midlands, while 2010 includes $6.8 billion for the acquisition of LKE. See Note 10 to the Financial Statements for additional information regarding the acquisitions. Excluding the impact of the acquisitions, net cash used in investing activities increased by $772 million in 2011 compared with 2010. This increase reflects $890 million of higher capital expenditures and a $228 million net change in restricted cash, partially offset by $219 million of additional proceeds from the sale of certain businesses or facilities and $163 million of proceeds from the sale of investments, other than securities in the nuclear plant decommissioning trust funds. PPL received proceeds of $381 million in 2011 from the sale of certain non-core generation facilities compared with proceeds of $162 million in 2010 from the sale of the Long Island generation business and certain Maine hydroelectric generation facilities. See Note 9 to the Financial Statements for additional information on the sale of these businesses or facilities.
Net cash used in investing activities was $8.2 billion in 2010 compared with $880 million in 2009. The 2010 amount includes the use of $6.8 billion of cash for the acquisition of LKE. See Note 10 to the Financial Statements for additional information regarding this acquisition. Excluding the impact of the acquisition, net cash used in investing activities increased by $537 million in 2010 compared with 2009. This increase reflects $372 million of higher capital expenditures, $133 million net change in restricted cash and $154 million of lower proceeds from the sale of investments, other than securities in the nuclear plant decommissioning trust funds, partially offset by $81 million of additional proceeds from the sale of certain businesses or facilities. PPL received proceeds of $162 million in 2010 for the sale of the Long Island generation business and certain Maine hydroelectric generation facilities compared with proceeds of $81 million in 2009 from the sale of the majority of its Maine hydroelectric generation businesses. See Note 9 to the Financial Statements for additional information on the sale of these businesses or facilities.
Financing Activities
Net cash provided by financing activities was $5.8 billion in 2011 compared with $6.3 billion in 2010, primarily as a result of the issuances of long-term debt and equity related to the acquisition of WPD Midlands in 2011 and the acquisition of LKE in 2010. The change from 2011 to 2010 primarily reflects increased issuances of long-term debt and equity related to the acquisition of WPD Midlands in 2011.
Net cash provided by financing activities was $6.3 billion in 2010 compared with $1.3 billion of cash used in financing activities in 2009. The change from 2009 to 2010 primarily reflects increased issuances of long-term debt and equity related to the acquisition of LKE in 2010 as well as fewer retirements of long-term debt in 2010.
In 2011, cash provided by financing activities primarily consisted of net debt issuances of $4.4 billion and $2.3 billion of net proceeds from the issuance of common stock, partially offset by common stock dividends paid of $746 million and debt issuance and credit facility costs paid of $102 million.
In 2010, cash provided by financing activities primarily consisted of net debt issuances of $4.7 billion and $2.4 billion of net proceeds from the issuance of common stock, partially offset by common stock dividends paid of $566 million and debt issuance and credit facility costs paid of $175 million.
In 2009, cash used in financing activities primarily consisted of net debt retirements of $770 million and common stock dividends paid of $517 million, partially offset by $60 million of common stock sale proceeds.
See "Forecasted Sources of Cash" for a discussion of PPL's plans to issue debt and equity securities, as well as a discussion of credit facility capacity available to PPL. Also see "Forecasted Uses of Cash" for a discussion of plans to pay dividends on common and preferred securities in the future, as well as maturities of long-term debt.
Long-term Debt and Equity Securities
PPL's long-term debt and equity securities activity through December 31, 2011 was:
(a)
Issuances are net of pricing discounts, where applicable and exclude the impact of debt issuance costs.
(b)
Senior unsecured notes of $250 million were redeemed at par prior to their 2046 maturity date and the remaining $500 million were retired upon maturity.
(c)
Retirement reflects amount paid to redeem $400 million aggregate principal amount of first mortgage bonds prior to their 2013 maturity date.
(d)
Notes were retired upon maturity.
(e)
Reflects fair value adjustments resulting from the preliminary purchase price allocation. The principal amount of each issuance is £250 million, which equated to approximately $400 million at the time of closing.
(f)
In April 2011, LKE, LG&E and KU each filed a 2011 Registration Statement with the SEC related to offers to exchange securities issued in November 2010 in transactions not registered under the Securities Act of 1933 with similar but registered securities. The 2011 Registration Statements became effective in June 2011 and the exchanges were completed in July 2011, with substantially all securities being exchanged.
See Note 7 to the Financial Statements for additional information about long-term debt and equity securities.
Forecasted Sources of Cash
PPL expects to continue to have sufficient sources of cash available in the near term, including various credit facilities, a commercial paper program and operating leases. PPL and its subsidiaries currently plan to incur, subject to market
conditions, up to $300 million of long-term indebtedness in 2012, the proceeds of which will be used for general corporate purposes. Additionally, PPL's cash flows will include a full year of WPD Midlands' cash flows in 2012 and forward.
Credit Facilities
At December 31, 2011, PPL's total committed borrowing capacity under credit facilities and the use of this borrowing capacity were:
(a)
In March 2011, PPL Energy Supply's $300 million Structured Credit Facility expired. PPL Energy Supply's obligations under this facility were supported by a $300 million letter of credit issued on PPL Energy Supply's behalf under a separate, but related $300 million 5-year credit agreement, which also expired in March 2011.
PPL Energy Supply's Syndicated Credit Facility contains a financial covenant requiring PPL Energy Supply's debt to total capitalization not to exceed 65%, as calculated in accordance with the facility, and other customary covenants.
(b)
Committed capacity includes a $150 million credit facility related to an asset-backed commercial paper program through which PPL Electric obtains financing by selling and contributing its eligible accounts receivable and unbilled revenue to a special purpose, wholly owned subsidiary on an ongoing basis. The subsidiary pledges these assets to secure loans of up to an aggregate of $150 million from a commercial paper conduit sponsored by a financial institution. At December 31, 2011, based on accounts receivable and unbilled revenue pledged, the amount available for borrowing under the facility was limited to $103 million. In July 2011, PPL Electric and the subsidiary extended the expiration date of the credit agreement related to the asset-backed commercial paper program to July 2012.
PPL Electric's Syndicated Credit Facility contains a financial covenant requiring PPL Electric's debt to total capitalization not to exceed 70%, as calculated in accordance with the credit facility, and other customary covenants.
(c)
In June 2011, LG&E and KU each amended its respective Syndicated Credit Facility such that the fees and the spread to benchmark interest rates for borrowings depend upon the respective company's senior secured long-term debt rating rather than the senior unsecured debt rating. LG&E and KU's Syndicated Credit Facilities each contain a financial covenant requiring LG&E and KU's debt to capitalization not to exceed 70%, as calculated in accordance with the facilities, and other customary covenants.
(d)
In April 2011, KU entered into a new $198 million letter of credit facility that has been used to issue letters of credit to support outstanding tax exempt bonds. The facility contains a financial covenant requiring KU's debt to total capitalization not to exceed 70%, as calculated in accordance with the credit facility. KU pays customary commitment and letter of credit fees under the new facility. The facility matures in April 2014. In August 2011, KU amended its letter of credit facility such that the fees depend upon KU's senior secured long-term debt rating rather than the senior unsecured debt rating.
(e)
In October 2011, PPL Energy Supply, PPL Electric, LG&E and KU each amended its respective Syndicated Credit Facility. The amendments included extending the expiration dates from December 2014 to October 2016. Under these facilities, PPL Energy Supply, PPL Electric, LG&E and KU each continue to have the ability to make cash borrowings and to request the lenders to issue letters of credit.
The commitments under PPL's domestic credit facilities are provided by a diverse bank group, with no one bank and its affiliates providing an aggregate commitment of more than 9% of the total committed capacity.
(f)
In January 2012, WPD (South West) entered into a new £245 million syndicated credit facility to replace its existing £210 million syndicated credit facility. Under the new facility, WPD (South West) has the ability to make cash borrowings but cannot request the lenders to issue letters of credit. WPD (South West) pays customary commitment fees under this facility, and borrowings bear interest at LIBOR-based rates plus a margin. The facility contains financial covenants that require WPD (South West) to maintain an interest coverage ratio of not less than 3.0 times consolidated earnings before income taxes, depreciation and amortization and total net debt not in excess of 85% of its RAV, in each case calculated in accordance with the credit facility.
(g)
In April 2011, following the completion of the acquisition of WPD Midlands, WPD (East Midlands) and WPD (West Midlands) each entered into a £300 million 5-year syndicated credit facility. Under the facilities, WPD (East Midlands) and WPD (West Midlands) each have the ability to make cash borrowings and to request the lenders to issue up to £80 million of letters of credit in lieu of borrowing.
(h)
At December 31, 2011, the unused capacity of WPD's committed credit facilities was approximately $1.1 billion. The commitments under WPD's credit facilities are provided by a diverse bank group with no one bank providing more than 17% of the total committed capacity.
In addition to the financial covenants noted in the table above, the credit agreements governing the above credit facilities contain various other covenants. Failure to comply with the covenants after applicable grace periods could result in acceleration of repayment of borrowings and/or termination of the agreements. PPL monitors compliance with the covenants on a regular basis. At December 31, 2011, PPL was in compliance with these covenants. At this time, PPL believes that these covenants and other borrowing conditions will not limit access to these funding sources.
See Note 7 to the Financial Statements for further discussion of PPL's credit facilities.
Commercial Paper
In October 2011, PPL Energy Supply re-activated its $500 million commercial paper program to provide an additional financing source to fund its short-term liquidity needs, if and when necessary. Commercial paper issuances are supported by PPL Energy Supply's Syndicated Credit Facility. At December 31, 2011, PPL Energy Supply had $400 million of commercial paper outstanding at a weighted-average interest rate of approximately 0.53%.
PPL Electric maintains a commercial paper program for up to $200 million to provide an additional financing source to fund its short-term liquidity needs, if and when necessary. Commercial paper issuances are currently supported by PPL Electric's Syndicated Credit Facility, which expires in October 2016, based on available capacity.
PPL Electric did not issue any commercial paper during 2011. Based on its current cash position and anticipated cash flows, PPL Electric currently does not plan to issue any commercial paper during 2012, but it may do so from time to time, subject to market conditions, to facilitate short-term cash flow needs.
In February 2012, LG&E and KU each established a commercial paper program for up to $250 million to provide an additional financing source to fund their short-term liquidity needs. Commercial paper issuances will be supported by LG&E and KU's Syndicated Credit Facilities.
2011 Bridge Facility
In March 2011, in connection with entering into the agreement to acquire WPD Midlands, PPL entered into a 364-day unsecured bridge financing of up to £3.6 billion solely to (i) fund the acquisition and (ii) pay certain fees and expenses in connection with the acquisition. On April 1, 2011, concurrent with the closing of the WPD Midlands acquisition, PPL Capital Funding borrowed an aggregate of £1.75 billion and PPL WEM borrowed £1.85 billion under the 2011 Bridge Facility. The borrowings bore interest at approximately 2.62%. See Note 10 to the Financial Statements for additional information on the acquisition.
In accordance with the terms of the 2011 Bridge Facility, PPL Capital Funding's borrowings of £1.75 billion were repaid with approximately $2.8 billion of proceeds received from PPL's issuance of common stock and 2011 Equity Units in April 2011, as discussed in "Long-term Debt and Equity Securities" below. Also in April 2011, PPL WEM repaid £650 million of its 2011 Bridge Facility borrowing. Such repayment was funded primarily with proceeds received from PPL WEM's issuance of senior notes, which is also discussed below. In May 2011, PPL WEM repaid the remaining £1.2 billion of borrowings outstanding under the 2011 Bridge Facility, primarily with the proceeds from senior notes issued by WPD (East Midlands) and WPD (West Midlands), also discussed below.
In anticipation of the repayment of a portion of the GBP-denominated borrowings under the 2011 Bridge Facility with U.S. dollar-denominated proceeds received from PPL's issuance of common stock and 2011 Equity Units and PPL WEM's issuance of U.S. dollar-denominated senior notes, PPL entered into forward contracts to purchase GBP in order to economically hedge the foreign currency exchange rate risk related to the repayment. See Note 19 to the Financial Statements for further discussion.
Operating Leases
PPL and its subsidiaries also have available funding sources that are provided through operating leases. PPL's subsidiaries lease office space, land, buildings and certain equipment. These leasing structures provide PPL additional operating and financing flexibility. The operating leases contain covenants that are typical for these agreements, such as maintaining insurance, maintaining corporate existence and timely payment of rent and other fees.
PPL, through its subsidiary PPL Montana, leases a 50% interest in Colstrip Units 1 and 2 and a 30% interest in Unit 3, under four 36-year, non-cancelable operating leases. These operating leases are not recorded on PPL's Balance Sheets. The leases place certain restrictions on PPL Montana's ability to incur additional debt, sell assets and declare dividends. At this time,
PPL believes that these restrictions will not limit access to these funding sources or cause acceleration or termination of the leases. See Note 7 to the Financial Statements for a discussion of other dividend restrictions related to PPL subsidiaries.
See Note 11 to the Financial Statements for further discussion of the operating leases.
Long-term Debt and Equity Securities
PPL and its subsidiaries currently plan to incur, subject to market conditions, up to $300 million of long-term indebtedness in 2012, the proceeds of which will be used for general corporate purposes.
PPL currently plans to issue new shares of common stock in 2012 in an aggregate amount up to $350 million under its DRIP and various employee stock-based compensation and other plans.
Forecasted Uses of Cash
In addition to expenditures required for normal operating activities, such as purchased power, payroll, fuel and taxes, PPL currently expects to incur future cash outflows for capital expenditures, various contractual obligations, payment of dividends on its common and preferred securities and possibly the purchase or redemption of a portion of debt securities.
Capital Expenditures
The table below shows PPL's current capital expenditure projections for the years 2012 through 2016.
(a)
Construction expenditures include capitalized interest and AFUDC, which are expected to be approximately $209 million for the years 2012 through 2016.
(b)
Includes expenditures for certain intangible assets.
(c)
Includes approximately $700 million of currently estimable costs related to LKE's replacement of generation units due to EPA regulations not recoverable through the ECR mechanism. LKE expects to recover these costs over a period equivalent to the related depreciable lives of the assets through future rate proceedings.
(d)
Includes approximately $100 million of currently estimable transmission costs related to LKE's replacement of generation units. LKE expects to recover these costs over a period equivalent to the related depreciable lives of the assets through future rate proceedings.
(e)
Nuclear fuel expenditures include capitalized interest, which is expected to be approximately $25 million for the years 2012 through 2016.
PPL's capital expenditure projections for the years 2012 through 2016 total approximately $18.7 billion. Capital expenditure plans are revised periodically to reflect changes in operational, market and regulatory conditions. For the years presented, this table includes projected costs related to the planned 1,326 MW of incremental capacity increases for both PPL Energy Supply and LKE, PPL Electric's asset optimization program focused on the replacement of aging transmission and distribution assets and the PJM-approved regional transmission line expansion project. This table also includes LKE's environmental projects related to new and anticipated EPA compliance standards (actual costs may be significantly lower or higher depending on the final requirements; certain environmental compliance costs incurred by LG&E and KU in serving KPSC jurisdictional customers are generally eligible for recovery through the ECR mechanism). See Notes 6 and 8 to the Financial Statements for information on LG&E's and KU's ECR plans and the PJM-approved regional transmission line expansion project and the other significant development projects.
PPL plans to fund its capital expenditures in 2012 with cash on hand, cash from operations and proceeds from the issuance of common stock and debt securities.
Contractual Obligations
PPL has assumed various financial obligations and commitments in the ordinary course of conducting its business. At December 31, 2011, the estimated contractual cash obligations of PPL were:
(a)
Reflects principal maturities only based on stated maturity dates, except for PPL Energy Supply's 5.70% REset Put Securities (REPS). See Note 7 to the Financial Statements for a discussion of the remarketing feature related to the REPS, as well as discussion of variable-rate remarketable bonds issued on behalf of PPL Energy Supply, LG&E and KU. PPL does not have any significant capital lease obligations.
(b)
Assumes interest payments through stated maturity, except for the REPS, for which interest is reflected to the put date. The payments herein are subject to change, as payments for debt that is or becomes variable-rate debt have been estimated and payments denominated in British pounds sterling have been translated to U.S. dollars at a current foreign currency exchange rate.
(c)
See Note 11 to the Financial Statements for additional information.
(d)
The amounts include agreements to purchase goods or services that are enforceable and legally binding and specify all significant terms, including: fixed or minimum quantities to be purchased; fixed, minimum or variable price provisions; and the approximate timing of the transaction. Primarily includes PPL's purchase obligations of electricity, coal, nuclear fuel and limestone as well as certain construction expenditures, which are also included in the Capital Expenditures table presented above. Financial swaps and open purchase orders that are provided on demand with no firm commitment are excluded from the amounts presented. In prior years, PPL included certain energy purchase obligations based on forecasted amounts to be purchased. The amounts presented herein are based on actual contract terms.
(e)
The amounts include WPD's contractual deficit pension funding requirements arising from an actuarial valuation performed in March 2010. The U.K. electricity regulator currently allows a recovery of a substantial portion of the contributions relating to the plan deficit; however, WPD cannot be certain that this will continue beyond the current review period, which extends to March 31, 2015. The amounts also include contributions made or committed to be made for 2012 for PPL's and LKE's U.S. pension plans. See Note 13 to the Financial Statements for a discussion of expected contributions.
Also included in the amounts are contract adjustment payments related to the Purchase Contract component of the Equity Units. See Note 7 to the Financial Statements for additional information on the Equity Units.
(f)
At December 31, 2011, total unrecognized tax benefits of $145 million were excluded from this table as PPL cannot reasonably estimate the amount and period of future payments. See Note 5 to the Financial Statements for additional information.
Dividends
PPL views dividends as an integral component of shareowner return and expects to continue to pay dividends in amounts that are within the context of maintaining a capitalization structure that supports investment grade credit ratings. In 2011, PPL declared the annualized dividend rate on its common stock at $1.40 per share. In February 2012, PPL declared an increase to its annualized dividend rate on its common stock to $1.44 per share. Future dividends will be declared at the discretion of the Board of Directors and will depend upon future earnings, cash flows, financial and legal requirements and other relevant factors at the time. As discussed in Note 7 to the Financial Statements, subject to certain exceptions, PPL may not declare or pay any cash dividend on its common stock during any period in which PPL Capital Funding defers interest payments on its 2007 Series A Junior Subordinated Notes due 2067, its 4.625% Junior Subordinated Notes due 2018, or its 4.32% Junior Subordinated Notes due 2019 or until deferred contract adjustment payments on PPL's Purchase Contracts have been paid. No such deferrals have occurred or are currently anticipated.
PPL Electric expects to continue to pay quarterly dividends on its outstanding preference securities, if and as declared by its Board of Directors.
See Note 7 to the Financial Statements for other restrictions related to distributions on capital interests for PPL subsidiaries.
Purchase or Redemption of Debt Securities
PPL will continue to evaluate its outstanding debt securities and may decide to purchase or redeem these securities depending upon prevailing market conditions and available cash.
Rating Agency Decisions
Moody's, S&P and Fitch periodically review the credit ratings on the debt and preferred securities of PPL and its subsidiaries. Based on their respective independent reviews, the rating agencies may make certain ratings revisions or ratings affirmations.
A credit rating reflects an assessment by the rating agency of the creditworthiness associated with an issuer and particular securities that it issues. The credit ratings of PPL and its subsidiaries are based on information provided by PPL and other
sources. The ratings of Moody's, S&P and Fitch are not a recommendation to buy, sell or hold any securities of PPL or its subsidiaries. Such ratings may be subject to revisions or withdrawal by the agencies at any time and should be evaluated independently of each other and any other rating that may be assigned to the securities. A downgrade in PPL's or its subsidiaries' credit ratings could result in higher borrowing costs and reduced access to capital markets.
As a result of the passage of the Dodd-Frank Act PPL is limiting its credit rating disclosure to a description of the actions taken by the rating agencies with respect to PPL's ratings, but without stating what ratings have been assigned to PPL or its subsidiaries, or their securities. The ratings assigned by the rating agencies to PPL and its subsidiaries and their respective securities may be found, without charge, on each of the respective ratings agencies' websites, which ratings together with all other information contained on such rating agency websites is hereby explicitly not incorporated by reference in this report.
The rating agencies took the following actions related to PPL and its subsidiaries in 2011.
Following the announcement of the then-pending acquisition of WPD Midlands in March 2011, the rating agencies took the following actions:
Moody's affirmed all of the ratings for PPL and all of its rated subsidiaries.
S&P revised the outlook for PPL, PPL Capital Funding, PPL Energy Supply, PPL Electric, LKE, LG&E, KU, PPL WW, WPD (South West) and WPD (South Wales); affirmed the issuer and senior unsecured ratings of PPL WW; and lowered the following ratings:
·
the issuer rating of PPL;
·
the senior unsecured and junior subordinated ratings of PPL Capital Funding;
·
the issuer and senior unsecured ratings of PPL Energy Supply;
·
the issuer, senior secured, preference stock, and commercial paper ratings of PPL Electric;
·
the issuer and senior unsecured ratings of LKE;
·
the issuer, senior secured ratings, and short-term ratings of LG&E;
·
the issuer, senior secured ratings, and short-term ratings of KU;
·
the issuer and senior unsecured ratings of WPD (South West); and
·
the issuer and senior unsecured ratings of WPD (South Wales).
Fitch affirmed all of the ratings for PPL, PPL Capital Funding, PPL Energy Supply, PPL Electric, LKE, LG&E and KU.
In April 2011, Moody's and S&P took the following actions following the completion of the acquisition of WPD Midlands.
Moody's:
·
lowered the issuer and senior unsecured debt ratings of WPD (East Midlands) and WPD (West Midlands);
·
affirmed the short-term issuer rating of WPD (East Midlands); and
·
assigned a senior unsecured rating and an outlook to PPL WEM.
S&P:
·
lowered the issuer and senior unsecured debt ratings of WPD (East Midlands) and WPD (West Midlands);
·
assigned issuer ratings to PPL WEM;
·
raised the issuer rating of PPL WW;
·
revised the outlook for PPL and all of its rated subsidiaries;
·
raised the short-term ratings of LG&E, KU, WPD (East Midlands), WPD (West Midlands), PPL WEM, PPL WW, WPD (South West), WPD (South Wales) and PPL Electric; and
·
affirmed all of the long-term ratings for PPL and its rated subsidiaries.
In May 2011, S&P downgraded the long-term rating of four series of pollution control bonds issued on behalf of KU by one notch in connection with the substitution of the letters of credit enhancing these four bonds.
Also in May 2011, Fitch affirmed its rating and maintained its outlook for PPL Montana's Pass Through Certificates due 2020.
In July 2011, S&P upgraded the senior secured rating for PPL Electric's first mortgage bonds following the execution of a supplemental indenture that provided for prospective amendments to PPL Electric's 2001 Mortgage Indenture, as discussed in "Long-term Debt and Equity Securities" above.
In September 2011, Moody's affirmed the following ratings:
·
the issuer ratings for PPL, LG&E, and KU;
·
the senior unsecured ratings for PPL Energy Supply and PPL Capital Funding; and
·
all of the ratings for LKE.
Also in September 2011, S&P assigned a short-term rating to PPL Energy Supply's commercial paper program.
In October 2011, Moody's and Fitch also assigned a short-term rating to PPL Energy Supply's commercial paper program in support of PPL Energy Supply's re-opening of the program.
In October 2011, Fitch affirmed all of the ratings for PPL WW, WPD (South West), and WPD (South Wales).
In November 2011, Fitch affirmed its rating and revised its outlook to negative from stable for PPL Montana's Pass Through Certificates due 2020.
In December 2011, Fitch affirmed the Issuer Default Ratings and individual security ratings of PPL Corp. and each of its domestic subsidiaries.
In January 2012, S&P affirmed its rating and revised its outlook to stable from positive for PPL Montana's Pass Through Certificates due 2020.
Ratings Triggers
As discussed in Note 7 to the Financial Statements, certain of WPD's senior unsecured notes may be put by the holders back to the issuer for redemption if the long-term credit ratings assigned to the notes by Moody's, S&P or Fitch are withdrawn by any of the rating agencies or reduced to a non-investment grade rating of Ba1 or BB+ in connection with a restructuring event. A restructuring event includes the loss of, or a material adverse change to, the distribution license under which WPD (East Midlands), WPD (South West), WPD (South Wales) and WPD (West Midlands) operate. These notes totaled £3.3 billion (approximately $5.1 billion) at December 31, 2011.
PPL and PPL Energy Supply have various derivative and non-derivative contracts, including contracts for the sale and purchase of electricity and fuel, commodity transportation and storage, tolling agreements, and interest rate and foreign currency instruments, which contain provisions requiring PPL and PPL Energy Supply to post additional collateral, or permit the counterparty to terminate the contract, if PPL's or PPL Energy Supply's credit rating were to fall below investment grade. See Note 19 to the Financial Statements for a discussion of "Credit Risk-Related Contingent Features," including a discussion of the potential additional collateral that would have been required for derivative contracts in a net liability position at December 31, 2011. At December 31, 2011, if PPL's and PPL Energy Supply's credit ratings had been below investment grade, PPL would have been required to prepay or post an additional $475 million of collateral to counterparties for both derivative and non-derivative commodity and commodity-related contracts used in its generation, marketing and trading operations and interest rate and foreign currency contracts.
Guarantees for Subsidiaries
PPL guarantees certain consolidated affiliate financing arrangements that enable certain transactions. Some of the guarantees contain financial and other covenants that, if not met, would limit or restrict the consolidated affiliates' access to funds under these financing arrangements, require early maturity of such arrangements or limit the consolidated affiliates' ability to enter into certain transactions. At this time, PPL believes that these covenants will not limit access to relevant funding sources. See Note 15 to the Financial Statements for additional information about guarantees.
Off-Balance Sheet Arrangements
PPL has entered into certain agreements that may contingently require payment to a guaranteed or indemnified party. See Note 15 to the Financial Statements for a discussion of these agreements.
Risk Management - Energy Marketing & Trading and Other
Market Risk
See Notes 1, 18, and 19 to the Financial Statements for information about PPL's risk management objectives, valuation techniques and accounting designations.
The forward-looking information presented below provides estimates of what may occur in the future, assuming certain adverse market conditions and model assumptions. Actual future results may differ materially from those presented. These disclosures are not precise indicators of expected future losses, but only indicators of possible losses at a given confidence level.
Commodity Price Risk (Non-trading)
PPL segregates its non-trading activities into two categories: hedge activity and economic activity. Transactions that are accounted for as hedge activity qualify for hedge accounting treatment. The economic activity category includes transactions that address a specific risk, but were not eligible for hedge accounting or for which hedge accounting was not elected. This activity includes the changes in fair value of positions used to hedge a portion of the economic value of PPL's competitive generation assets and full-requirement sales and retail contracts. This economic activity is subject to changes in fair value due to market price volatility of the input and output commodities (e.g., fuel and power). Although they do not receive hedge accounting treatment, these transactions are considered non-trading activity. The net fair value of economic positions at December 31, 2011 and 2010 was a net liability of $63 million and $391 million. See Note 19 to the Financial Statements for additional information on economic activity.
To hedge the impact of market price volatility on PPL's energy-related assets, liabilities and other contractual arrangements, PPL both sells and purchases physical energy at the wholesale level under FERC market-based tariffs throughout the U.S. and enters into financial exchange-traded and over-the-counter contracts. PPL's non-trading commodity derivative contracts mature at various times through 2019.
The following table sets forth the changes in net fair value of PPL's non-trading commodity derivative contracts. See Notes 18 and 19 to the Financial Statements for additional information.
(a)
Represents the fair value of contracts at the end of the quarter of their inception.
(b)
In June 2010, PPL Energy Supply received market bids for certain full-requirement sales contracts that were monetized in early July. See Note 19 to the Financial Statements for additional information. At June 30, 2010, these contracts were valued based on the bids received (the market approach). In prior periods, the fair value of these contracts was measured using the income approach.
The following table segregates the net fair value of PPL's non-trading commodity derivative contracts at December 31, 2011 based on whether the fair value was determined by prices quoted in active markets for identical instruments or other more subjective means.
PPL sells electricity, capacity and related services and buys fuel on a forward basis to hedge the value of energy from its generation assets. If PPL were unable to deliver firm capacity and energy or to accept the delivery of fuel under its agreements, under certain circumstances it could be required to pay liquidating damages. These damages would be based on the difference between the market price and the contract price of the commodity. Depending on price changes in the wholesale energy markets, such damages could be significant. Extreme weather conditions, unplanned power plant outages, transmission disruptions, nonperformance by counterparties with which it has energy contracts and other factors could affect PPL's ability to meet its obligations, or cause significant increases in the market price of replacement energy. Although PPL attempts to mitigate these risks, there can be no assurance that it will be able to fully meet its firm obligations, that it will not be required to pay damages for failure to perform, or that it will not experience counterparty nonperformance in the future.
Commodity Price Risk (Trading)
PPL's trading contracts mature at various times through 2015. The following table sets forth changes in the net fair value of PPL's trading commodity derivative contracts. See Notes 18 and 19 to the Financial Statements for additional information.
PPL will reverse unrealized losses of approximately $2 million over the next three months as the transactions are realized.
The following table segregates the net fair value of PPL's trading commodity derivative contracts at December 31, 2011 based on whether the fair value was determined by prices quoted in active markets for identical instruments or other more subjective means.
VaR Models
PPL utilizes a VaR model to measure commodity price risk in unregulated gross energy margins for its non-trading and trading portfolios. VaR is a statistical model that attempts to estimate the value of potential loss over a given holding period under normal market conditions at a given confidence level. PPL calculates VaR using a Monte Carlo simulation technique based on a five-day holding period at a 95% confidence level. Given the company's conservative hedging program, PPL's non-trading VaR exposure is expected to be limited in the short term. At December 31, 2011 and December 31, 2010, the VaR for PPL's portfolios using end-of-month results for the period was as follows.
The trading portfolio includes all speculative positions, regardless of the delivery period. All positions not considered speculative are considered non-trading. PPL's non-trading portfolio includes PPL's entire portfolio, including generation, with delivery periods through the next 12 months. Both the trading and non-trading VaR computations exclude FTRs due to the absence of reliable spot and forward markets. The fair value of the non-trading and trading FTR positions was insignificant at December 31, 2011.
Interest Rate Risk
PPL and its subsidiaries have issued debt to finance their operations, which exposes them to interest rate risk. PPL utilizes various financial derivative instruments to adjust the mix of fixed and floating interest rates in its debt portfolio, adjust the duration of its debt portfolio and lock in benchmark interest rates in anticipation of future financing, when appropriate. Risk limits under the risk management program are designed to balance risk exposure to volatility in interest expense and changes in the fair value of PPL's debt portfolio due to changes in the absolute level of interest rates.
At December 31, 2011 and 2010, PPL's potential annual exposure to increased interest expense, based on a 10% increase in interest rates, was not significant.
PPL is also exposed to changes in the fair value of its domestic and international debt portfolios. PPL estimated that a 10% decrease in interest rates at December 31, 2011 would increase the fair value of its debt portfolio by $635 million, compared with $420 million at December 31, 2010.
PPL had the following interest rate hedges outstanding at:
(a)
Includes accrued interest, if applicable.
(b)
Effects of adverse movements decrease assets or increase liabilities, as applicable, which could result in an asset becoming a liability.
(c)
PPL utilizes various risk management instruments to reduce its exposure to the expected future cash flow variability of its debt instruments. These risks include exposure to adverse interest rate movements for outstanding variable rate debt and for future anticipated financing. While PPL is exposed to changes in the fair value of these instruments, any changes in the fair value of such cash flow hedges are recorded in equity. The changes in fair value of these instruments are then reclassified into earnings in the same period during which the item being hedged affects earnings. Sensitivities represent a 10% adverse movement in interest rates. The positions outstanding at December 31, 2011 mature in 2022.
(d)
PPL WEM, through PPL, and PPL WW use cross-currency swaps to hedge the interest payments and principal of their U.S. dollar-denominated senior notes with maturity dates ranging from May 2016 to December 2028. While PPL is exposed to changes in the fair value of these instruments, any change in the fair value of these instruments is recorded in equity and reclassified into earnings in the same period during which the item being hedged affects earnings. Sensitivities represent a 10% adverse movement in both interest rates and foreign currency exchange rates.
(e)
PPL utilizes various risk management instruments to adjust the mix of fixed and floating interest rates in its debt portfolio. The change in fair value of these instruments, as well as the offsetting change in the value of the hedged exposure of the debt, is reflected in earnings. Sensitivities represent a 10% adverse movement in interest rates. The positions outstanding at December 31, 2011 mature in 2047.
(f)
PPL utilizes various risk management instruments to reduce its exposure to the expected future cash flow variability of its debt instruments. These risks include exposure to adverse interest rate movements for outstanding variable rate debt and for future anticipated financing. While PPL is exposed to changes in the fair value of these instruments, any realized changes in the fair value of such economic hedges are recoverable through regulated rates and any subsequent changes in fair value of these derivatives are included in regulatory assets or liabilities. Sensitivities represent a 10% adverse movement in interest rates. The positions outstanding at December 31, 2011 mature through 2033.
Foreign Currency Risk
PPL is exposed to foreign currency risk, primarily through investments in U.K. affiliates. In addition, PPL's domestic operations may make purchases of equipment in currencies other than U.S. dollars. See Note 1 to the Financial Statements for additional information regarding foreign currency translation.
PPL has adopted a foreign currency risk management program designed to hedge certain foreign currency exposures, including firm commitments, recognized assets or liabilities, anticipated transactions and net investments. In addition, PPL enters into financial instruments to protect against foreign currency translation risk of expected earnings.
PPL had the following foreign currency hedges outstanding at:
(a)
Effects of adverse movements decrease assets or increase liabilities, as applicable, which could result in an asset becoming a liability.
(b)
To protect the value of a portion of its net investment in WPD, PPL executes forward contracts to sell GBP.
(c)
To economically hedge the translation of expected income denominated in GBP to U.S. dollars, PPL enters into a combination of average rate forwards and average rate options to sell GBP. The forwards and options outstanding at December 31, 2011 have termination dates ranging from January 2012 through November 2012.
NDT Funds - Securities Price Risk
In connection with certain NRC requirements, PPL Susquehanna maintains trust funds to fund certain costs of decommissioning the Susquehanna nuclear plant. At December 31, 2011, these funds were invested primarily in domestic equity securities and fixed-rate, fixed-income securities and are reflected at fair value on PPL's Balance Sheet. The mix of securities is designed to provide returns sufficient to fund Susquehanna's decommissioning and to compensate for inflationary increases in decommissioning costs. However, the equity securities included in the trusts are exposed to price fluctuation in equity markets, and the values of fixed-rate, fixed-income securities are exposed to changes in interest rates. PPL actively monitors the investment performance and periodically reviews asset allocation in accordance with its nuclear decommissioning trust policy statement. At December 31, 2011, a hypothetical 10% increase in interest rates and a 10% decrease in equity prices would have resulted in an estimated $43 million reduction in the fair value of the trust assets, compared with $45 million at December 31, 2010. See Notes 18 and 23 to the Financial Statements for additional information regarding the NDT funds.
Defined Benefit Plans - Securities Price Risk
See "Application of Critical Accounting Policies - Defined Benefits" for additional information regarding the effect of securities price risk on plan assets.
Credit Risk
Credit risk is the risk that PPL would incur a loss as a result of nonperformance by counterparties of their contractual obligations. PPL maintains credit policies and procedures with respect to counterparty credit (including requirements that counterparties maintain specified credit ratings) and requires other assurances in the form of credit support or collateral in certain circumstances in order to limit counterparty credit risk. However, PPL has concentrations of suppliers and customers among electric utilities, financial institutions and other energy marketing and trading companies. These concentrations may impact PPL's overall exposure to credit risk, positively or negatively, as counterparties may be similarly affected by changes in economic, regulatory or other conditions.
PPL includes the effect of credit risk on its fair value measurements to reflect the probability that a counterparty will default when contracts are out of the money (from the counterparty's standpoint). In this case, PPL would have to sell into a lower-priced market or purchase from a higher-priced market. When necessary, PPL records an allowance for doubtful accounts to reflect the probability that a counterparty will not pay for deliveries PPL has made but not yet billed, which are reflected in "Unbilled revenues" on the Balance Sheets. PPL also has established a reserve with respect to certain receivables from SMGT, which is reflected in accounts receivable on the Balance Sheets. See Note 15 to the Financial Statements for additional information.
In 2009, the PUC approved PPL Electric's PLR procurement plan for the period January 2011 through May 2013. To date, PPL Electric has conducted ten of its 14 planned competitive solicitations.
Under the standard Supply Master Agreement (the Agreement) for the competitive solicitation process, PPL Electric requires all suppliers to post collateral if their credit exposure exceeds an established credit limit. In the event a supplier defaults on its obligation, PPL Electric would be required to seek replacement power in the market. All incremental costs incurred by PPL Electric would be recoverable from customers in future rates. At December 31, 2011, substantially all of the successful bidders under all of the solicitations had an investment grade credit rating from S&P, and were not required to post collateral
under the Agreement. There is no instance under the Agreement in which PPL Electric is required to post collateral to its suppliers.
See "Overview" in this Item 7 and Notes 15, 16, 18 and 19 to the Financial Statements for additional information on the competitive solicitations, the Agreement, credit concentration and credit risk.
Foreign Currency Translation
The value of the British pound sterling fluctuates in relation to the U.S. dollar. In 2011, changes in these exchange rates resulted in a foreign currency translation loss of $51 million, which primarily reflected a $69 million reduction to PP&E offset by a reduction of $18 million to net liabilities. In 2010, changes in these exchange rates resulted in a foreign currency translation loss of $63 million, which primarily reflected a $180 million reduction to PP&E offset by a reduction of $117 million to net liabilities. In 2009, changes in these exchange rates resulted in a foreign currency translation gain of $106 million, which primarily reflected a $225 million increase in PP&E offset by an increase of $119 million to net liabilities. The impact of foreign currency translation is recorded in AOCI.
Related Party Transactions
PPL is not aware of any material ownership interests or operating responsibility by senior management of PPL, PPL Energy Supply, PPL Electric, LKE, LG&E or KU in outside partnerships, including leasing transactions with variable interest entities, or other entities doing business with PPL. See Note 16 to the Financial Statements for additional information on related party transactions.
Acquisitions, Development and Divestitures
PPL continuously evaluates potential acquisitions, divestitures and development. Development projects are continuously reexamined based on market conditions and other factors to determine whether to proceed with the projects, sell, cancel or expand them, execute tolling agreements or pursue other options.
In April 2011, PPL, through its indirect, wholly owned subsidiary PPL WEM, completed its acquisition of WPD Midlands. In November 2010, PPL completed its acquisition of LKE. See Note 10 to the Financial Statements for additional information.
See Notes 8, 9 and 10 to the Financial Statements for additional information on the more significant activities.
Environmental Matters
Protection of the environment is a priority for PPL and a significant element of its business activities. Extensive federal, state and local environmental laws and regulations are applicable to PPL's air emissions, water discharges and the management of hazardous and solid waste, among other areas; and the cost of compliance or alleged non-compliance cannot be predicted with certainty but could be material. In addition, costs may increase significantly if the requirements or scope of environmental laws or regulations, or similar rules, are expanded or changed from prior versions by the relevant agencies. Costs may take the form of increased capital or operating and maintenance expenses; monetary fines, penalties or forfeitures or other restrictions. Many of these environmental law considerations are also applicable to the operations of key suppliers, or customers, such as coal producers, industrial power users, etc., and may impact the cost for their products or their demand for PPL's services. See "Item 1. Business - Environmental Matters" and Note 15 to the Financial Statements for a discussion of environmental matters.
Competition
See "Competition" under each of PPL's reportable segments in "Item 1. Business - Segment Information" and "Item 1A. Risk Factors" for a discussion of competitive factors affecting PPL.
New Accounting Guidance
See Notes 1 and 24 to the Financial Statements for a discussion of new accounting guidance adopted and pending adoption.
Application of Critical Accounting Policies
Financial condition and results of operations are impacted by the methods, assumptions and estimates used in the application of critical accounting policies. The following accounting policies are particularly important to the financial condition or results of operations, and require estimates or other judgments of matters inherently uncertain. Changes in the estimates or other judgments included within these accounting policies could result in a significant change to the information presented in the Financial Statements (these accounting policies are also discussed in Note 1 to the Financial Statements). PPL's senior management has reviewed these critical accounting policies, the following disclosures regarding their application and the estimates and assumptions regarding them, with PPL's Audit Committee.
1) Price Risk Management
See "Price Risk Management" in Note 1 to the Financial Statements, as well as "Risk Management - Energy Marketing & Trading and Other" above.
2) Defined Benefits
Certain PPL subsidiaries sponsor various qualified funded and non-qualified unfunded defined benefit pension plans. Certain PPL subsidiaries also sponsor both funded and unfunded other postretirement plans. These plans are applicable to the majority of the employees of PPL. PPL and certain of its subsidiaries record an asset or liability to recognize the funded status of all defined benefit plans with an offsetting entry to OCI or regulatory assets and liabilities for amounts that are expected to be recovered through regulated customer rates. Consequently, the funded status of all defined benefit plans is fully recognized on the Balance Sheets. See Note 13 to the Financial Statements for additional information about the plans and the accounting for defined benefits.
PPL and its subsidiaries make certain assumptions regarding the valuation of benefit obligations and the performance of plan assets. When accounting for defined benefits, delayed recognition in earnings of differences between actual results and expected or estimated results is a guiding principle. Annual net periodic defined benefit costs are recorded in current earnings based on estimated results. Any differences between actual and estimated results are recorded in OCI or regulatory assets and liabilities for amounts that are expected to be recovered through regulated customer rates. These amounts in AOCI or regulatory assets and liabilities are amortized to income over future periods. The delayed recognition allows for a smoothed recognition of costs over the working lives of the employees who benefit under the plans. The primary assumptions are:
·
Discount Rate - The discount rate is used in calculating the present value of benefits, which is based on projections of benefit payments to be made in the future. The objective in selecting the discount rate is to measure the single amount that, if invested at the measurement date in a portfolio of high-quality debt instruments, would provide the necessary future cash flows to pay the accumulated benefits when due.
·
Expected Return on Plan Assets - Management projects the long-term rates of return on plan assets based on historical performance, future expectations and periodic portfolio rebalancing among the diversified asset classes. These projected returns reduce the net benefit costs PPL records currently.
·
Rate of Compensation Increase - Management projects employees' annual pay increases, which are used to project employees' pension benefits at retirement.
·
Health Care Cost Trend Rate - Management projects the expected increases in the cost of health care.
In selecting a discount rate for its U.S. defined benefit plans, PPL starts with a cash flow analysis of the expected benefit payment stream for its plans. For 2010, these plan-specific cash flows were matched against a spot-rate yield curve to determine the assumed discount rate. To develop the spot-rate yield curve, the full universe of Aa-rated non-callable (or callable with make-whole provisions) bonds, served as the base from which those with the lowest and highest yields were eliminated to develop an appropriate subset of bonds from which the ultimate yield curve would be built. At that time, Management believed this plan-specific cash flow matching model represented the best available tool for estimating the discount rate. Beginning in 2011, PPL utilized a new tool that enhanced this plan-specific cash flow matching methodology by primarily matching the plan-specific cash flows against the coupons and expected maturity values of individually selected bonds. This bond matching process begins with the same subset of the universe of Aa-rated corporate bonds from which those with the lowest and highest yields were eliminated, similar to the yield curve approach. Individual bonds were then selected based on the timing of each plan's cash flows and parameters were established as to the percentage of each individual
bond issue that could be hypothetically purchased and the surplus reinvestment rates to be assumed. This process more accurately approximated the process of settlement of the obligations, which better aligns with the objective of selecting the discount rate. At December 31, 2011, PPL decreased the discount rate for its U.S. pension plans from 5.42% to 5.06% and decreased the discount rate for its other postretirement benefit plans from 5.14% to 4.80%.
In 2011 and 2010, a similar process to the 2010 approach described above was used to select the discount rate for the U.K. pension plans, which used an iBoxx British pounds sterling denominated corporate bond index as its base. This discount rate selection methodology was not modified for the U.K. pension plans because the universe of bonds in the U.K. is not deep enough to adequately support a bond matching process. At December 31, 2011, the discount rate for the U.K. pension plans was decreased from 5.54% to 5.24% as a result of this assessment.
The expected long-term rates of return for PPL's U.S. defined benefit pension and other postretirement benefit plans have been developed using a best-estimate of expected returns, volatilities and correlations for each asset class. PPL management corroborates these rates with expected long-term rates of return calculated by its independent actuary, who uses a building block approach that begins with a risk-free rate of return with factors being added such as inflation, duration, credit spreads and equity risk. Each plan's specific asset allocation is also considered in developing a reasonable return assumption.
Based on PPL's change to a liability-driven investment strategy, PPL's U.S. defined benefit pension assets have shifted into a greater proportion of fixed-income investments. Based on this change in investment strategy, at December 31, 2011, PPL's expected return on plan assets decreased from 7.25% to 7.07% for its U.S. pension plans and decreased from 6.57% to 5.93% for its other postretirement benefit plans. The expected long-term rates of return for PPL's U.K. pension plans have been developed by PPL management with assistance from an independent actuary using a best-estimate of expected returns, volatilities and correlations for each asset class. For the U.K. plans, PPL's expected return on plan assets decreased from 7.86% to 7.17% at December 31, 2011. This decrease was primarily the result of the acquisition of WPD Midlands and its pension plan, which has a greater portion of assets invested in fixed income securities resulting in a lower rate of return.
In selecting a rate of compensation increase, PPL considers past experience in light of movements in inflation rates. At December 31, 2011, PPL's rate of compensation increase changed from 4.88% to 4.02% for its U.S. pension plans and 4.90% to 4.00% for its other postretirement benefit plans. For the U.K. plans, PPL's rate of compensation increase remained at 4.00% at December 31, 2011.
In selecting health care cost trend rates, PPL considers past performance and forecasts of health care costs. At December 31, 2011, PPL's health care cost trend rates were 8.50% for 2012, gradually declining to 5.50% for 2019.
A variance in the assumptions listed above could have a significant impact on accrued defined benefit liabilities or assets, reported annual net periodic defined benefit costs and OCI or regulatory assets and liabilities for LG&E, KU and PPL Electric. While the charts below reflect either an increase or decrease in each assumption, the inverse of this change would impact the accrued defined benefit liabilities or assets, reported annual net periodic defined benefit costs and OCI or regulatory assets and liabilities for LG&E, KU and PPL Electric by a similar amount in the opposite direction. The sensitivities below reflect an evaluation of the change based solely on a change in that assumption and does not include income tax effects.
At December 31, 2011, the defined benefit plans were recorded as follows.
The following chart reflects the sensitivities in the December 31, 2011 Balance Sheet associated with a change in certain assumptions based on PPL's primary defined benefit plans.
(a)
Only impacts other postretirement benefits.
In 2011, PPL recognized net periodic defined benefit costs charged to operating expense of $204 million. This amount represents a $102 million increase from 2010. This increase in expense was primarily attributable to the pension costs of the newly acquired pension plans of WPD Midlands, including separation costs, and a full year of LKE pension costs for 2011.
The following chart reflects the sensitivities in the 2011 Statement of Income (excluding income tax effects) associated with a change in certain assumptions based on PPL's primary defined benefit plans.
(a)
Only impacts other postretirement benefits.
3) Asset Impairment
Impairment analyses are performed for long-lived assets that are subject to depreciation or amortization whenever events or changes in circumstances indicate that a long-lived asset's carrying value may not be recoverable. For these long-lived assets classified as held and used, such events or changes in circumstances are:
·
a significant decrease in the market price of an asset;
·
a significant adverse change in the manner in which an asset is being used or in its physical condition;
·
a significant adverse change in legal factors or in the business climate;
·
an accumulation of costs significantly in excess of the amount originally expected for the acquisition or construction of an asset;
·
a current period operating or cash flow loss combined with a history of losses or a forecast that demonstrates continuing losses; or
·
a current expectation that, more likely than not, an asset will be sold or otherwise disposed of significantly before the end of its previously estimated useful life.
For a long-lived asset classified as held and used, an impairment is recognized when the carrying amount of the asset is not recoverable and exceeds its fair value. The carrying amount is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. If the asset is impaired, an impairment loss is recorded to adjust the asset's carrying value to its estimated fair value. Management must make significant judgments to estimate future cash flows, including the useful lives of long-lived assets, the fair value of the assets and management's intent to use the assets. Alternate courses of action are considered to recover the carrying value of a long-lived asset, and estimated cash flows from the "most likely" alternative are used to assess impairment whenever one alternative is clearly the most likely outcome. If no alternative is clearly the most likely, then a probability-weighted approach is used taking into consideration estimated cash flows from the alternatives. For assets tested for impairment as of the balance sheet date, the estimates of future cash flows used in that test consider the likelihood of possible outcomes that existed at the balance sheet date, including the assessment of the likelihood of a future sale of the assets. That assessment is not revised based on events that occur after the balance sheet date. Changes in assumptions and estimates could result in significantly different results than those identified and recorded in the financial statements.
For a long-lived asset classified as held for sale, an impairment exists when the carrying amount of the asset (disposal group) exceeds its fair value less cost to sell. If the asset (disposal group) is impaired, an impairment loss is recorded to adjust the carrying amount to its fair value less cost to sell. A gain is recognized for any subsequent increase in fair value less cost to sell, but not in excess of the cumulative impairment previously recognized.
For determining fair value, quoted market prices in active markets are the best evidence. However, when market prices are unavailable, the Registrant considers all valuation techniques appropriate under the circumstances and for which market participant inputs can be obtained. Generally discounted cash flows are used to estimate fair value, which incorporates market participant inputs when available. Discounted cash flows are calculated by estimating future cash flow streams and applying appropriate discount rates to determine the present value of the cash flow streams.
See Note 18 to the Financial Statements for a discussion of impairments related to certain intangible assets in 2011.
Goodwill is tested for impairment at the reporting unit level. PPL's reporting units have been determined to be at the operating segment level. A goodwill impairment test is performed annually or more frequently if events or changes in
circumstances indicate that the carrying value of the reporting unit may be greater than the unit's fair value. Additionally, goodwill is tested for impairment after a portion of goodwill has been allocated to a business to be disposed of.
Goodwill is tested for impairment using a two-step approach. In step one, PPL identifies a potential impairment by comparing the estimated fair value of a reporting unit with its carrying value, including goodwill, on the measurement date. If the estimated fair value of a reporting unit exceeds its carrying value, goodwill is not considered impaired. If the carrying value exceeds the estimated fair value, the second step is performed to measure the amount of impairment loss, if any.
The second step requires a calculation of the implied fair value of goodwill, which is determined in the same manner as the amount of goodwill in a business combination. That is, the estimated fair value of a reporting unit is allocated to all of the assets and liabilities of that reporting unit as if the reporting unit had been acquired in a business combination and the estimated fair value of the reporting unit was the price paid to acquire the reporting unit. The excess of the estimated fair value of a reporting unit over the amounts assigned to its assets and liabilities is the implied fair value of goodwill. The implied fair value of the reporting unit's goodwill is then compared with the carrying value of that goodwill. If the carrying value exceeds the implied fair value, an impairment loss is recognized in an amount equal to that excess. The loss recognized cannot exceed the carrying value of the reporting unit's goodwill.
PPL tested the goodwill of its reporting units for impairment in the fourth quarter of 2011 and no impairment was recognized. Management used both discounted cash flows and market multiples, which required significant assumptions, to estimate the fair value of each reporting unit. Applying an appropriate weighting to both the discounted cash flow and market multiple valuations, a decrease in the forecasted cash flows of 10%, an increase in the discount rate by 25 basis points, or a 10% decrease in the multiples would not have resulted in an impairment of goodwill.
In 2010 and 2009, $5 million and $3 million of goodwill allocated to discontinued operations was written off.
4) Loss Accruals
Losses are accrued for the estimated impacts of various conditions, situations or circumstances involving uncertain or contingent future outcomes. For loss contingencies, the loss must be accrued if (1) information is available that indicates it is probable that a loss has been incurred, given the likelihood of the uncertain future events, and (2) the amount of the loss can be reasonably estimated. Accounting guidance defines "probable" as cases in which "the future event or events are likely to occur." The accrual of contingencies that might result in gains is not recorded unless recovery is assured. Potential loss contingencies for environmental remediation, litigation claims, regulatory penalties and other events are continuously assessed.
The accounting aspects of estimated loss accruals include (1) the initial identification and recording of the loss, (2) the determination of triggering events for reducing a recorded loss accrual, and (3) the ongoing assessment as to whether a recorded loss accrual is sufficient. All three of these aspects require significant judgment by management. Internal expertise and outside experts (such as lawyers and engineers) are used, as necessary, to help estimate the probability that a loss has been incurred and the amount (or range) of the loss.
No new significant loss accruals were recorded in 2011.
Certain other events have been identified that could give rise to a loss, but that do not meet the conditions for accrual. Such events are disclosed, but not recorded, when it is "reasonably possible" that a loss has been incurred. See Note 15 to the Financial Statements for disclosure of other potential loss contingencies that have not met the criteria for accrual.
When an estimated loss is accrued, the triggering events for subsequently reducing the loss accrual are identified, where applicable. The triggering events generally occur when the contingency has been resolved and the actual loss is paid or written off, or when the risk of loss has diminished or been eliminated. The following are some of the triggering events that provide for the reduction of certain recorded loss accruals:
·
Allowances for uncollectible accounts are reduced when accounts are written off after prescribed collection procedures have been exhausted, a better estimate of the allowance is determined or underlying amounts are ultimately collected.
·
Environmental and other litigation contingencies are reduced when the contingency is resolved and actual payments are made, a better estimate of the loss is determined or the loss is no longer considered probable.
Loss accruals are reviewed on a regular basis to assure that the recorded potential loss exposures are appropriate. This involves ongoing communication and analyses with internal and external legal counsel, engineers, operation management and other parties.
See Note 15 to the Financial Statements for a discussion of the Montana Hydroelectric Litigation, including the reversal of an $89 million loss accrual, as a result of management's assessment of the February 2012 U.S. Supreme Court decision.
5) Asset Retirement Obligations
PPL is required to recognize a liability for legal obligations associated with the retirement of long-lived assets. The initial obligation is measured at its estimated fair value. A conditional ARO must be recognized when incurred if the fair value of the ARO can be reasonably estimated. An equivalent amount is recorded as an increase in the value of the capitalized asset and allocated to expense over the useful life of the asset. Until the obligation is settled, the liability is increased, through the recognition of accretion expense in the income statement, for changes in the obligation due to the passage of time.
In the case of LG&E and KU, estimated costs of removal for all assets are recovered in rates as a component of depreciation. Since costs of removal are collected in rates prior to payment of such costs, the accrual for these costs of removal is classified as a regulatory liability. The regulatory liability is relieved as costs are incurred. The depreciation and accretion expense related to an ARO are offset with a regulatory credit on the income statement, such that there is no earnings impact. The regulatory asset created by the regulatory credit is relieved when the ARO has been settled.
See Note 21 to the Financial Statements for further discussion of AROs.
In determining AROs, management must make significant judgments and estimates to calculate fair value. Fair value is developed using an expected present value technique based on assumptions of market participants that considers estimated retirement costs in current period dollars that are inflated to the anticipated retirement date and then discounted back to the date the ARO was incurred. Changes in assumptions and estimates included within the calculations of the fair value of AROs could result in significantly different results than those identified and recorded in the financial statements. Estimated ARO costs and settlement dates, which affect the carrying value of the ARO and the related capitalized asset, are reviewed periodically to ensure that any material changes are incorporated into the latest estimate of the ARO. Any change to the capitalized asset, positive or negative, is amortized over the remaining life of the associated long-lived asset.
At December 31, 2011, AROs totaling $497 million were recorded on the Balance Sheet, of which $13 million is included in "Other current liabilities." Of the total amount, $292 million, or 59%, relates to the nuclear decommissioning ARO. The most significant assumptions surrounding AROs are the forecasted retirement costs, the discount rates and the inflation rates. A variance in any of these inputs could have a significant impact on the ARO liabilities.
The following table reflects the sensitivities related to the nuclear decommissioning ARO liability associated with a change in these assumptions as of December 31, 2011. There is no significant change to the annual depreciation expense of the ARO asset or the annual accretion expense of the ARO liability as a result of changing the assumptions. The sensitivities below reflect an evaluation of the change based solely on a change in that assumption.
6) Income Taxes
Significant management judgment is required in developing the provision for income taxes, primarily due to the uncertainty related to tax positions taken or expected to be taken in tax returns and the determination of deferred tax assets, liabilities and valuation allowances.
Significant management judgment is required to determine the amount of benefit recognized related to an uncertain tax position. Tax positions are evaluated following a two-step process. The first step requires an entity to determine whether, based on the technical merits supporting a particular tax position, it is more likely than not (greater than a 50% chance) that the tax position will be sustained. This determination assumes that the relevant taxing authority will examine the tax position and is aware of all the relevant facts surrounding the tax position. The second step requires an entity to recognize in the financial statements the benefit of a tax position that meets the more-likely-than-not recognition criterion. The benefit recognized is measured at the largest amount of benefit that has a likelihood of realization, upon settlement, that exceeds
50%. Management considers a number of factors in assessing the benefit to be recognized, including negotiation of a settlement.
On a quarterly basis, uncertain tax positions are reassessed by considering information known at the reporting date. Based on management's assessment of new information, a tax benefit may subsequently be recognized for a previously unrecognized tax position, a previously recognized tax position may be de-recognized, or the benefit of a previously recognized tax position may be remeasured. The amounts ultimately paid upon resolution of issues raised by taxing authorities may differ materially from the amounts accrued and may materially impact the financial statements in the future.
At December 31, 2011, it was reasonably possible that during the next 12 months the total amount of unrecognized tax benefits could increase by as much as $43 million or decrease by up to $129 million. This change could result from subsequent recognition, derecognition and/or changes in the measurement of uncertain tax positions related to the creditability of foreign taxes, the timing and utilization of foreign tax credits and the related impact on alternative minimum tax and other credits, the timing and/or valuation of certain deductions, intercompany transactions and unitary filing groups. The events that could cause these changes are direct settlements with taxing authorities, litigation, legal or administrative guidance by relevant taxing authorities and the lapse of an applicable statute of limitation.
The balance sheet classification of unrecognized tax benefits and the need for valuation allowances to reduce deferred tax assets also require significant management judgment. Unrecognized tax benefits are classified as current to the extent management expects to settle an uncertain tax position by payment or receipt of cash within one year of the reporting date. Valuation allowances are initially recorded and reevaluated each reporting period by assessing the likelihood of the ultimate realization of a deferred tax asset. Management considers a number of factors in assessing the realization of a deferred tax asset, including the reversal of temporary differences, future taxable income and ongoing prudent and feasible tax planning strategies. Any tax planning strategy utilized in this assessment must meet the recognition and measurement criteria utilized to account for an uncertain tax position. Management also considers the uncertainty posed by political risk and the effect of this uncertainty on the various factors that management takes into account in evaluating the need for valuation allowances. The amount of deferred tax assets ultimately realized may differ materially from the estimates utilized in the computation of valuation allowances and may materially impact the financial statements in the future. See Note 5 to the Financial Statements for income tax disclosures.
7) Regulatory Assets and Liabilities
Certain of PPL's subsidiaries are subject to cost-based rate regulation. As a result, the effects of regulatory actions are required to be reflected in the financial statements. Assets and liabilities are recorded that result from the regulated ratemaking process that may not be recorded under GAAP for non-regulated entities. Regulatory assets generally represent incurred costs that have been deferred because such costs are probable of future recovery in regulated customer rates. Regulatory liabilities are recognized for amounts expected to be returned through future regulated customer rates. In certain cases, regulatory liabilities are recorded based on an understanding or agreement with the regulator that rates have been set to recover costs that are expected to be incurred in the future, and the regulated entity is accountable for any amounts charged pursuant to such rates and not yet expended for the intended purpose.
Management continually assesses whether the regulatory assets are probable of future recovery by considering factors such as changes in the applicable regulatory and political environments, the ability to recover costs through regulated rates, recent rate orders to other regulated entities, and the status of any pending or potential deregulation legislation. Based on this continual assessment, management believes the existing regulatory assets are probable of recovery. This assessment reflects the current political and regulatory climate at the state and federal levels, and is subject to change in the future. If future recovery of costs ceases to be probable, then asset write-offs would be required to be recognized in operating income. Additionally, the regulatory agencies can provide flexibility in the manner and timing of depreciation of PP&E and amortization of regulatory assets.
At December 31, 2011 and 2010, PPL had regulatory liabilities of $1.1 billion. At December 31, 2011 and 2010, PPL had regulatory assets of $1.4 billion and $1.3 billion. All regulatory assets are either currently being recovered under specific rate orders, represent amounts that are expected to be recovered in future rates or benefit future periods based upon established regulatory practices.
In March 2012, PPL Electric plans to file a request with the FERC seeking recovery, over a 34-year period beginning in June 2012, of its unrecovered regulatory asset related to the deferred state tax liability that existed at the time of the transition from the flow-through treatment of state income taxes to full normalization. This change in tax treatment occurred in 2008 as a result of prior FERC initiatives that transferred regulatory jurisdiction of certain transmission assets from the PUC to the FERC. A regulatory asset of $51 million related to this transition, classified as taxes recoverable through future rates, is
included in "Other Noncurrent Assets - Regulatory assets" on the Balance Sheet. PPL Electric believes recoverability of this regulatory asset is probable based on FERC precedent in similar cases; however, it is reasonably possible that the FERC may limit the recovery of all or part of the claimed asset.
See Note 6 to the Financial Statements for additional information on regulatory assets and liabilities.
8) Business Combinations - Purchase Price Allocation
On April 1, 2011, PPL, through its indirect, wholly owned subsidiary, PPL WEM, completed its acquisition of all of the outstanding ordinary share capital of Central Networks East plc and Central Networks Limited, the sole owner of Central Networks West plc, together with certain other related assets and liabilities (collectively referred to as Central Networks and subsequently referred to as WPD Midlands). In accordance with accounting guidance on business combinations, the identifiable assets acquired and the liabilities assumed were measured at fair value at the acquisition date. Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants. The excess of the purchase price over the estimated fair value of the identifiable net assets was recorded as goodwill.
The determination and allocation of fair value to the identifiable assets acquired and liabilities assumed was based on various assumptions and valuation methodologies requiring considerable management judgment, including estimates based on key assumptions of the acquisition, and historical and current market data. Significant variables in these valuations include the discount rates, the number of years on which to base cash flow projections, as well as the assumptions and estimates used to determine cash inflows and outflows.
The fair value of the majority of PP&E was determined utilizing a discounted cash flow approach and corroborated by the RAV, which is a measure of the unrecovered value of the regulated network business in the U.K. For purposes of measuring the fair value of the majority of PP&E, PPL determined that fair value should approximate the RAV at the acquisition date because WPD Midlands' operations are conducted in a regulated environment and the regulator allows for earning a rate of return on and recovery of RAV at rates determined to be fair and reasonable. As there is no current prospect for deregulation in WPD Midlands' operating area, it is expected that these operations will remain in a regulated environment for the foreseeable future; therefore, management has concluded that the use of these assets in the regulatory environment represents their highest and best use and a market participant would measure the fair value of these assets using the regulatory rate of return as the discount rate, thus resulting in fair value approximately equal to the RAV.
The purchase price allocation resulted in goodwill of $2.4 billion that was assigned to the International Regulated segment. This reflects the expected continued growth of a rate-regulated business with a defined service area operating under a constructive regulatory framework, expected cost savings, efficiencies and other benefits resulting from a contiguous service area with WPD (South West) and WPD (South Wales) and the ability to leverage WPD (South West)'s and WPD (South Wales)'s existing management team's high level of performance in capital cost efficiency, system reliability and customer service.
See Note 10 to the Financial Statements for additional information regarding the acquisition.
Other Information
PPL's Audit Committee has approved the independent auditor to provide audit and audit-related services, tax services and other services permitted by Sarbanes-Oxley and SEC rules. The audit and audit-related services include services in connection with statutory and regulatory filings, reviews of offering documents and registration statements, and internal control reviews.
PPL ENERGY SUPPLY, LLC AND SUBSIDIARIES
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
The information provided in this Item 7 should be read in conjunction with PPL Energy Supply's Consolidated Financial Statements and the accompanying Notes. Capitalized terms and abbreviations are explained in the glossary. Dollars are in millions unless otherwise noted.
"Management's Discussion and Analysis of Financial Condition and Results of Operations" includes the following information:
·
"Overview" provides a description of PPL Energy Supply and its business strategy. "Financial and Operational Developments" includes a review of Net Income Attributable to PPL Energy Supply and discusses certain events that are important to understanding PPL Energy Supply's results of operations and financial condition.
·
"Results of Operations" provides a summary of PPL Energy Supply's earnings and a description of key factors expected to impact future earnings. This section ends with "Statement of Income Analysis," which includes explanations of significant changes in principal items on PPL Energy Supply's Statements of Income, comparing 2011, 2010 and 2009.
·
"Financial Condition - Liquidity and Capital Resources" provides an analysis of PPL Energy Supply's liquidity position and credit profile. This section also includes a discussion of rating agency decisions and capital expenditure projections.
·
"Financial Condition - Risk Management - Energy Marketing & Trading and Other" provides an explanation of PPL Energy Supply's risk management programs relating to market and credit risk.
·
"Application of Critical Accounting Policies" provides an overview of the accounting policies that are particularly important to the results of operations and financial condition of PPL Energy Supply and that require its management to make significant estimates, assumptions and other judgments of matters inherently uncertain.
Overview
Introduction
PPL Energy Supply is an energy company with headquarters in Allentown, Pennsylvania. Through its subsidiaries, PPL Energy Supply is primarily engaged in the generation and marketing of electricity in two key markets - the northeastern and northwestern U.S.
In 2011, PPL Energy Supply operated in one reportable segment compared with two reportable segments in previous years - International Regulated and Supply. In January 2011, PPL Energy Supply distributed its 100% membership interest in PPL Global to its direct parent, PPL Energy Funding, to better align PPL's organizational structure with the manner in which it manages its businesses and reports segment information in its consolidated financial statements. The distribution separated the U.S.-based competitive energy marketing and supply business from the U.K.-based regulated electricity distribution business. As a result, effective January 1, 2011, PPL Energy Supply operates in a single business segment. The 2010 and 2009 operating results of the International Regulated segment have been reclassified to "Income (Loss) from Discontinued Operations (net of income taxes)" on the Statements of Income. See Note 9 to the Financial Statements for additional information on the January 2011 distribution.
Business Strategy
PPL Energy Supply's overall strategy is to achieve disciplined optimization of energy supply margins while mitigating volatility in both cash flows and earnings. More specifically, PPL Energy Supply's strategy is to optimize the value from its unregulated generation and marketing portfolio. PPL Energy Supply endeavors to do this by matching energy supply with load, or customer demand, under contracts of varying durations with creditworthy counterparties to capture profits while effectively managing exposure to energy and fuel price volatility, counterparty credit risk and operational risk.
To manage financing costs and access to credit markets, a key objective of PPL Energy Supply's business is to maintain a strong credit profile. PPL Energy Supply continually focuses on maintaining an appropriate capital structure and liquidity
position. In addition, PPL Energy Supply has financial and operational risk management programs that, among other things, are designed to monitor and manage its exposure to earnings and cash flow volatility related to changes in energy and fuel prices, interest rates, counterparty credit quality and the operating performance of its generating units.
Financial and Operational Developments
Net Income Attributable to PPL Energy Supply
Net Income Attributable to PPL Energy Supply for 2011, 2010 and 2009 was $768 million, $861 million and $246 million. Earnings in 2011 decreased 11% from 2010 and earnings in 2010 increased 250% over 2009. These changes reflect the following after-tax impacts:
(a)
See "Statement of Income Analysis - Margins" for additional information, including a reconciliation of this non-GAAP financial measure to operating income.
See "Results of Operations" below for further discussion and analysis of the consolidated results of operations, as well as a discussion of each of PPL's business segments.
Susquehanna Turbine Blade Replacement
In April 2011, during the PPL Susquehanna Unit 2 refueling and generation uprate outage, a planned inspection of the Unit 2 turbine revealed cracks in certain of its low pressure turbine blades. Replacement of these blades was required, but was not anticipated as part of the original scope of this outage. The necessary replacement work extended the Unit 2 outage by six weeks. As a precaution, PPL Susquehanna also took Unit 1 out of service in mid-May to inspect the turbine blades in that unit. This inspection revealed cracks in blades similar to those found in Unit 2. The duration of the Unit 1 outage, in which turbine blades were replaced, was also about six weeks. The after-tax earnings impact, including reduced energy-sales margins and repair expense for both units, was $63 million.
Spent Nuclear Fuel Litigation
In May 2011, PPL Susquehanna entered into a settlement agreement with the U.S. Government relating to PPL Susquehanna's lawsuit, seeking damages for the Department of Energy's failure to accept spent nuclear fuel from the PPL Susquehanna plant. Under the settlement agreement, PPL Susquehanna received $50 million, pre-tax, for its share of claims to partially offset its expenses incurred to store spent nuclear fuel at the Susquehanna plant through September 2009 and recognized a credit to "Fuel" expense in 2011. PPL Susquehanna will also be eligible to receive payment of annual claims for allowed costs that are incurred through the December 2013 termination of the settlement agreement. In exchange, PPL Susquehanna has waived any claims against the U.S. Government for costs paid or injuries sustained related to storing spent nuclear fuel at the Susquehanna plant through December 31, 2013. See Note 15 to the Financial Statements for additional information.
Bankruptcy of SMGT
In October 2011, SMGT, a Montana cooperative and purchaser of electricity under a long-term supply contract with PPL EnergyPlus expiring in June 2019 (SMGT Contract), filed for protection under Chapter 11 of the U.S. Bankruptcy Code in the U.S. Bankruptcy Court in Montana. At December 31, 2011, damages related to SMGT accepting less power than provided in the SMGT Contract totaled approximately $11 million, all of which has been fully reserved. No assurance can be given as to the collectability of these damages.
The SMGT Contract provides for fixed volume purchases on a monthly basis at established prices. A trustee has been appointed for SMGT's estate in the bankruptcy proceeding and PPL EnergyPlus has been involved in preliminary discussions with the trustee concerning possible modifications to the SMGT Contract as part of the bankruptcy reorganization. Pursuant to a stipulation entered into by SMGT and PPL EnergyPlus, since the date of its Chapter 11 filing through January 2012, SMGT has continued to purchase electricity from PPL EnergyPlus at the price specified in the SMGT Contract, and has made timely payments for such purchases, but at lower volumes than as prescribed in the SMGT Contract. In January 2012, the trustee notified PPL EnergyPlus that SMGT would not purchase electricity under the SMGT Contract for the month of February. In addition, the trustee requested PPL EnergyPlus to leave the SMGT Contract in place to permit SMGT to purchase electricity in the event its requirements were not met by third-party providers from whom the trustee intends to purchase power on behalf of SMGT, at prices more favorable than under the SMGT Contract, for future periods. PPL EnergyPlus is evaluating the trustee's request.
At the present time, PPL cannot predict whether SMGT will be successful in its attempts to reorganize its business under Chapter 11 of the U.S. Bankruptcy Code or the extent to which the SMGT Contract may be modified as part of a successful Chapter 11 reorganization and, in either case, PPL cannot presently predict the extent to which it will be able to market to third parties any amount of power that SMGT ultimately does not continue to purchase from PPL EnergyPlus.
CSAPR
In July 2011, the EPA signed the CSAPR, which finalizes and renames the Clean Air Transport Rule (Transport Rule) proposed in August 2010, and made revisions to the rule on February 7, 2012. This rule applies to PPL Energy Supply's coal plants in Pennsylvania. The CSAPR is meant to facilitate attainment of ambient air quality standards for ozone and fine particulates by requiring reductions in sulfur dioxide and nitrogen oxide emissions.
In December 2011, the U.S. Court of Appeals for the District of Columbia (Court) stayed implementation of the CSAPR and left CAIR in effect pending a final resolution on the merits of the validity of the rule. Oral argument on the various challenges to the CSAPR is scheduled for April 2012, and a final decision on the validity of the rule could be issued as early as May 2012.
PPL Energy Supply's coal fired power plants can meet both the CAIR and the proposed CSAPR sulfur dioxide emission requirements with the existing scrubbers that went in-service in 2008 and 2009. For nitrogen oxide, under both the CAIR and the proposed CSAPR, PPL Energy Supply would need to buy allowances or make operational changes, the cost of which is not anticipated to be significant.
See Note 15 to the Financial Statements for additional information on the CSAPR.
Montana Hydroelectric Litigation
In June 2011, the U.S. Supreme Court granted PPL Montana's petition to review the March 2010 Montana Supreme Court decision, which substantially affirmed the June 2008 Montana District Court decision to award the State of Montana retroactive compensation for PPL Montana's hydroelectric facilities' use and occupancy of certain Montana riverbeds. Oral argument was held in December 2011. On February 22, 2012, the U.S. Supreme Court issued a decision overturning the Montana Supreme Court decision and remanded the case to the Montana Supreme Court for further proceedings consistent with the U.S. Supreme Court's opinion. As a result, PPL Montana reversed its total loss accrual of $89 million, which had been recorded prior to the U.S. Supreme Court decision. PPL Montana believes the U.S. Supreme Court decision resolves certain questions of liability in this case in favor of PPL Montana and leaves open for reconsideration by Montana courts, consistent with the findings of the U.S. Supreme Court, certain other questions. The State of Montana has 30 days from February 22, 2012 to petition the U.S. Supreme Court for a rehearing. PPL Montana has concluded it is no longer probable, but it remains reasonably possible, that a loss has been incurred. While unable to estimate a range of loss, PPL Montana believes that any such amount would not be material. See Note 15 to the Financial Statements for additional information.
Results of Operations
When comparing 2011 and 2010 with 2009, certain line items on PPL Energy Supply's financial statements were impacted by the expiration of the generation rate caps and the expiration of the PLR contracts between PPL EnergyPlus and PPL Electric at the end of 2009. Overall, they had a significant positive impact on PPL Energy Supply's results of operations, financial condition and cash flows during 2010.
The primary impact of the expiration of generation rate caps and these contracts is reflected in PPL Energy Supply's Unregulated Gross Energy Margins. See "Statement of Income Analysis - Margins - Non-GAAP Financial Measure" for an explanation of this non-GAAP financial measure. In 2011 and 2010, PPL Energy Supply sold the majority of its generation supply under various contracts at prevailing market rates at the time the contracts were executed. In 2009, the majority of generation produced by PPL Energy Supply's generation plants was sold to PPL Electric's customers as PLR supply under predetermined capped rates.
The changes in the components of Net Income Attributable to PPL Energy Supply between these periods were due to the following factors. PPL Energy Supply's results are adjusted for certain items that management considers special. See additional detail of these special items in the tables below.
·
See "Statement of Income Analysis - Margins - Changes in Non-GAAP Financial Measures" for an explanation of margins.
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Other operation and maintenance increased in 2011 compared with 2010, primarily due to higher costs at PPL Susquehanna of $30 million, largely due to unplanned outages, the refueling outage and payroll, higher costs at eastern fossil and hydro units of $20 million, largely due to outages, and higher costs at western fossil and hydro units of $15 million, largely resulting from insurance recoveries received in 2010.
Other operation and maintenance increased in 2010 compared with 2009, primarily due to higher costs at PPL Susquehanna of $31 million largely due to higher payroll-related costs, higher outage costs, and higher project costs.
·
Depreciation increased in 2010 compared with 2009, primarily due to $21 million impact from environmental equipment at Brunner Island that was placed in service in 2009 and early 2010.
·
Other income (expense) - net was lower in 2010 compared with 2009, due to a $25 million gain recognized in 2009 related to the tender offers to purchase debt that resulted from reclassifying net gains on related cash flow hedges from AOCI into earnings, partially offset by a $15 million decrease in other-than-temporary impairment charges, primarily due to stronger returns on investments in NDT funds in 2010 and a $7 million increase in interest income from affiliates, primarily due to loans to LKE subsidiaries in 2010.
·
Income taxes decreased in 2011 compared with 2010, primarily due to the $196 million impact of lower pre-tax income and a $26 million reduction in deferred tax liabilities related to a change in the Pennsylvania estimated state tax rate. These decreases were partially offset by $74 million in Pennsylvania net operating loss valuation allowance adjustments, primarily related to lower projected future taxable income, driven in part by the impact of bonus depreciation, $13 million
in favorable adjustments to uncertain tax benefits recorded in 2010 and an $11 million decrease in the domestic manufacturing deduction tax benefit resulting from revised bonus depreciation estimates.
Income taxes increased in 2010 compared with 2009, primarily due to the $364 million impact of higher pre-tax income, partially offset by a $52 million in Pennsylvania net operating loss valuation allowance adjustments, primarily related to higher projected future taxable income, $10 million in investment tax credits associated with the Holtwood and Rainbow projects, $8 million in favorable adjustments to uncertain tax benefits recorded in 2010 and $8 million of higher tax benefits from the domestic manufacturing deduction.
Income (loss) from International discontinued operations - International, represents the results of PPL Global which was distributed to PPL Energy Supply's parent, PPL Energy Funding in January 2011. See Note 9 to the Financial Statements for additional information. Income from discontinued operations, excluding special items, decreased in 2010 compared with 2009, primarily due to:
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U.K. utility revenues increased $42 million in 2010 compared with 2009, primarily due to price increases in April 2010 and 2009, partially offset by lower regulatory recovery due to a revised estimate of network electricity losses.
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U.K. other operation and maintenance increased $47 million in 2010 compared with 2009, primarily due to higher pension expense resulting from an increase in amortization of actuarial losses.
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U.K. interest expense increased $50 million in 2010 compared with 2009, primarily due to the $23 million impact from higher inflation rates on index-linked Senior Unsecured Notes and $25 million in interest expense related to the March 2010 debt issuance.
·
U.K. income taxes decreased $26 million in 2010 compared with 2009, primarily due to $45 million in realized capital losses that offset a gain relating to a business activity sold in 1999 and the $14 million impact of lower pre-tax income, partially offset by $31 million in favorable settlements of uncertain tax positions in 2009.
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U.S. income taxes increased in 2010 compared with 2009, primarily due to $60 million in changes in the taxable amount of planned U.K. cash repatriations, partially offset by $23 million in adjustments to uncertain tax benefits.
The following after-tax amounts, which management considers special items, also impacted the results.
(a)
See "Reconciliation of Economic Activity" below.
(b)
Gains recorded on the sale of the Maine hydroelectric generation business. See Note 9 to the Financial Statements for additional information.
(c)
Consists primarily of the initial impairment charge recorded when the business was classified as held for sale. See Note 9 to the Financial Statements for additional information.
(d)
Primarily represents impairment charges of sulfur dioxide emission allowances.
(e)
Relates primarily to enhanced pension and severance benefits as a result of a 2009 workforce reduction.
(f)
In July 2010, in order to raise additional cash for the LKE acquisition, certain full-requirement sales contracts were monetized that resulted in cash proceeds of $249 million. See "Monetization of Certain Full-Requirement Sales Contracts" in Note 19 to the Financial Statements for additional information. $343 million of pre-tax gains were recorded to "Wholesale energy marketing" and $557 million of pre-tax losses were recorded to "Energy purchases" on the Statements of Income.
(g)
In October 2010, PPL Energy Supply made borrowings under its Syndicated Credit Facility in order to enable a subsidiary to make loans to certain affiliates to provide interim financing of amounts required by PPL to partially fund PPL's acquisition of LKE. Subsequent to the repayment of such borrowing, the capacity was reduced, and as a result, PPL Energy Supply wrote off deferred fees in 2010.
(h)
In 2009, PPL Montana adjusted its previously recorded accrual related to hydroelectric litigation, of which $5 million, pre-tax, related to prior periods. In March 2010, the Montana Supreme Court substantially affirmed a June 2008 Montana District Court decision regarding lease payments for the use of certain Montana streambeds. In 2010, PPL Montana recorded a pre-tax charge of $56 million, representing estimated rental compensation for years prior to 2010, including interest. Of this total charge $47 million, pre-tax, was recorded to "Other operation and maintenance" and $9 million, pre-tax, was recorded to "Interest Expense" on the Statements of Income. In August 2010, PPL Montana filed a petition for a writ of certiorari with the U.S. Supreme Court requesting the Court's review of this matter. In June 2011, the U.S. Supreme Court granted PPL Montana's petition. In February 2012, the U.S. Supreme Court overturned the Montana Supreme Court decision and remanded the case to the Montana Supreme Court for further proceedings consistent with the U.S. Supreme Court's opinion. Prior to the U.S. Supreme Court decision, $4 million, pre-tax, of interest expense on the rental compensation covered by the court decision was accrued in 2011. As a result of the U.S. Supreme Court decision, PPL Montana reversed its total pre-tax loss accrual of $89 million, which had been recorded prior to the U.S. Supreme Court decision, of which $79 million pre-tax is considered a special item because it represented $65 million of rent for periods prior to 2011 and $14 million of interest accrued on the portion covered by the prior court decision. These amounts were credited to "Other operation and maintenance" and "Interest Expense" on the Statement of Income.
(i)
In May 2011, PPL Susquehanna entered into a settlement agreement with the U.S. Government relating to PPL Susquehanna's lawsuit, seeking damages for the Department of Energy's failure to accept spent nuclear fuel from the PPL Susquehanna plant. PPL Susquehanna recorded credits to fuel expense to recognize recovery, under the settlement agreement, of certain costs to store spent nuclear fuel at the Susquehanna plant. This special item represents amounts recorded in 2011 to cover the costs incurred from 1998 through December 2010.
(j)
Represents income tax expense recorded as a result of the provisions within Health Care Reform which eliminated the tax deductibility of retiree health care costs to the extent of federal subsidies received by plan sponsors that provide retiree prescription drug benefits equivalent to Medicare Part D Coverage.
(k)
During 2009, PPL Energy Supply received consent from the IRS to change its method of accounting for certain expenditures for tax purposes. PPL Energy Supply deducted the resulting IRC Sec. 481 amount on its 2008 federal income tax return and recorded a $21 million adjustment to federal and state income tax expense resulting from the reduction in federal income tax benefits related to the domestic manufacturing deduction and certain state tax benefits related to state net operating losses.
(l)
In October 2011, a wholesale customer, SMGT, filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy code. The customer has continued to purchase electricity at the price specified in the supply contract, and has made timely payments for such purchases, but at lower volumes than as prescribed in the contract. As of December 31, 2011, the damage claim totaled $11 million pre-tax, which was fully reserved.
(m)
In January 2012, PPL received $7 million pre-tax, related to electricity delivered to a wholesale customer in 2008 and 2009, recorded in "Wholesale energy marketing-Realized." The additional revenue results from several transmission projects approved at PJM for recovery that were not initially anticipated at the time of the electricity auctions and therefore were not included in the auction pricing. A FERC order was issued in 2011 approving the disbursement of these supply costs by the wholesale customer to the suppliers, therefore, PPL accrued its share of this additional revenue in 2011.
Reconciliation of Economic Activity
The following table reconciles unrealized pre-tax gains (losses) from the table within "Commodity Price Risk (Non-trading) - Economic Activity" in Note 19 to the Financial Statements to the special item identified as "Adjusted energy-related economic activity, net."
(a)
See Note 19 to the Financial Statements for additional information.
(b)
Adjustment for the net deferral and amortization of option premiums over the delivery period of the item that was hedged or upon realization. Option premiums are recorded in "Wholesale energy marketing - Realized" and "Energy purchases - Realized" on the Statements of Income.
(c)
See "Components of Monetization of Certain Full-Requirement Sales Contracts" below.
Components of Monetization of Certain Full-Requirement Sales Contracts
The following table provides the components of the "Monetization of Certain Full-Requirement Sales Contracts" special item.
(a)
See "Commodity Price Risk (Non-trading) - Monetization of Certain Full-Requirement Sales Contracts" in Note 19 to the Financial Statements for additional information.
(b)
Includes unrealized losses of $251 million, which are reflected in "Wholesale energy marketing - Unrealized economic activity" and "Energy purchases - Unrealized economic activity" on the Statement of Income. Also includes net realized gains of $37 million, which are reflected in "Wholesale energy marketing - Realized" and "Energy purchases - Realized" on the Statement of Income. This economic activity will continue to be realized through May 2013.
2012 Outlook
Excluding special items, PPL Energy Supply projects lower earnings in 2012 compared with 2011. The decrease is primarily driven by lower energy margins as a result of further declines in energy and capacity prices and higher fuel costs, higher operation and maintenance expenses and higher depreciation, which are partially offset by higher baseload generation.
Earnings beyond 2011 are subject to various risks and uncertainties. See "Forward-Looking Information," "Item 1. Business," "Item 1A. Risk Factors," the rest of this Item 7 and Note 15 to the Financial Statements for a discussion of the risks, uncertainties and factors that may impact future earnings.
Statement of Income Analysis --
Margins
Non-GAAP Financial Measure
The following discussion includes financial information prepared in accordance with GAAP, as well as a non-GAAP financial measure, "Unregulated Gross Energy Margins." "Unregulated Gross Energy Margins" is a single financial performance measure of PPL Energy Supply's competitive energy non-trading and trading activities. In calculating this measure, PPL Energy Supply's energy revenues, which include operating revenues associated with certain PPL Energy Supply businesses that are classified as discontinued operations, are offset by the cost of fuel, energy purchases, certain other operation and maintenance expenses, primarily ancillary charges, gross receipts tax, which is recorded in "Taxes, other than income," and operating expenses associated with certain PPL Energy Supply businesses that are classified as discontinued operations. This performance measure is relevant to PPL Energy Supply due to the volatility in the individual revenue and expense lines on the Statements of Income that comprise "Unregulated Gross Energy Margins." This volatility stems from a number of factors, including the required netting of certain transactions with ISOs and significant swings in unrealized gains and losses. Such factors could result in gains or losses being recorded in either "Wholesale energy marketing" or "Energy purchases" on the Statements of Income. This performance measure includes PLR revenues from energy sales to PPL Electric by PPL EnergyPlus, which are recorded in "Wholesale energy marketing to affiliate" revenue. PPL Energy Supply excludes from "Unregulated Gross Energy Margins" energy-related economic activity, which includes the changes in fair value of positions used to economically hedge a portion of the economic value of PPL Energy Supply's competitive generation assets, full-requirement sales contracts and retail activities. This economic value is subject to changes in fair value due to market price volatility of the input and output commodities (e.g., fuel and power) prior to the delivery period that was hedged. Also included in this energy-related economic activity is the ineffective portion of qualifying cash flow hedges, the monetization of certain full-requirement sales contracts and premium amortization associated with options. This economic activity is deferred, with the exception of the full-requirement sales contracts that were monetized, and included in unregulated gross energy margins over the delivery period that was hedged or upon realization. This measure is not intended to replace "Operating Income," which is determined in accordance with GAAP, as an indicator of overall operating performance. Other companies may use different measures to analyze and to report on the results of their operations. PPL Energy Supply believes that "Unregulated Gross Energy Margins" provides another criterion to make investment decisions. This performance measure is used, in conjunction with other information, internally by senior management and PPL's Board of Directors to manage PPL Energy Supply's operations, analyze actual results compared with budget and measure certain corporate financial goals used in determining variable compensation.
Reconciliation of Non-GAAP Financial Measures
The following table reconciles "Operating Income" to "Unregulated Gross Energy Margins" as defined by PPL Energy Supply for the period ended December 31.
(a)
Represents amounts excluded from Margins.
(b)
As reported on the Statements of Income.
(c)
Represents energy-related economic activity as described in "Commodity Price Risk (Non-trading) - Economic Activity" within Note 19 to the Financial Statements. For 2011, "Wholesale energy marketing - Realized" and "Energy purchases - Realized" include a net pre-tax gain of $19 million related to the amortization of option premiums and a net pre-tax loss of $216 million related to the monetization of certain full-requirement sales contracts. 2010 includes a net pre-tax gain of $32 million related to the amortization of option premiums and a net pre-tax gain of $37 million related to the monetization of certain full-requirement sales contracts. 2009 includes a net pre-tax loss of $54 million related to the amortization of option premiums.
(d)
Represents energy-related economic activity, which is subject to wide swings in value due to market price volatility, as described in "Commodity Price Risk (Non-trading) - Economic Activity" within Note 19 to the Financial Statements.
(e)
Includes economic activity related to fuel. 2011 includes credits of $57 million for the spent nuclear fuel litigation settlement.
(f)
Represents the net of certain revenues and expenses associated with certain businesses that are classified as discontinued operations. These revenues and expenses are not reflected in "Operating Income" on the Statements of Income.
Changes in Non-GAAP Financial Measures
Unregulated Gross Energy Margins are generated through PPL Energy Supply's competitive non-trading and trading activities. PPL Energy Supply's non-trading energy business is managed on a geographic basis that is aligned with its generation fleet. The following table shows PPL Energy Supply's non-GAAP financial measure, Unregulated Gross Energy Margins, for the periods ended December 31, as well as the change between periods. The factors that gave rise to the changes are described below the table.
(a)
Baseload energy and capacity prices were lower in 2011 than 2010; however, prices in 2010 for baseload generation were significantly higher than prices realized under the PLR contract with PPL Electric that expired at the end of 2009.
(b)
Volumes were lower in 2011 compared with 2010 as a result of unplanned outages, economic reductions in coal unit output and the sale of our interest in Safe Harbor Water Power Corporation. Volumes were higher in 2010 compared with 2009 as a result of planned overhauls.
(c)
Lower margins in 2011 compared with 2010 were driven by lower capacity prices, partially offset by higher generation volumes in the first half of 2011. Higher margins in 2010 compared with 2009 were due to higher energy and capacity prices.
(d)
Volumes were lower in 2011 compared with 2010 primarily as a result of the dual-unit turbine blade replacement outages beginning in May 2011. Volumes were lower in 2010 compared with 2009 primarily due to an unplanned outage in July 2010.
(e)
Higher margins in 2011 compared with 2010 were driven by contracts monetized in 2010 and lower customer migration to alternative suppliers in 2011. Lower margins in 2010 compared with 2009 were driven by lower customer demand and higher customer migration to alternative suppliers.
Western U.S.
Western U.S. non-trading margins were higher in 2011 compared with 2010, due to higher net wholesale prices of $58 million, partially offset by lower wholesale volumes of $45 million, primarily due to economic reductions in coal unit output.
Western U.S. non-trading margins were higher in 2010 compared with 2009, primarily due to higher net wholesale prices of $11 million and higher wholesale volumes of $14 million, due to unplanned outages in 2009.
Net Energy Trading Margins
Net energy trading margins decreased during 2011 compared with 2010, as a result of lower margins on power positions of $16 million, partially offset by higher margins on gas positions of $12 million.
Net energy trading margins decreased during 2010 compared with 2009, as a result of lower margins on power and gas positions of $40 million, partially offset by higher trading margins related to FTRs of $22 million.
Other Operation and Maintenance
The changes in other operation and maintenance expenses were due to:
(a)
In March 2010, the Montana Supreme Court substantially affirmed a June 2008 Montana District Court decision regarding lease payments for the use of certain Montana streambeds. As a result, in the first quarter of 2010, PPL Montana recorded a charge of $56 million, representing estimated rental compensation for the first quarter of 2010 and prior years, including interest. The portion of the total charge recorded to "Other operation and maintenance" on the Statement of Income totaled $49 million. In August 2010, PPL Montana filed a petition for a writ of certiorari with the U.S. Supreme Court requesting the Court's review of this matter. In June 2011, the U.S. Supreme Court granted PPL Montana's petition. In February 2012, the U.S. Supreme Court overturned the Montana Supreme Court decision and remanded the case to the Montana Supreme Court for further proceedings consistent with the U.S. Supreme Court's opinion. As a result, PPL Montana reversed its total loss accrual of $89 million, which had been recorded prior to the U.S. Supreme Court decision, of which $75 million was credited to "Other operation and maintenance" on the Statement of Income.
(b)
2011 compared with 2010 was higher primarily due to $11 million of higher payroll-related costs, $10 million of higher outage costs and $8 million of higher costs from the refueling outage. 2010 compared with 2009 was higher primarily due to $10 million of higher payroll-related costs, $8 million of higher outage costs and $5 million higher project costs.
(c)
2011 compared with 2010, was higher primarily due to SMGT filing for protection under Chapter 11 of the U.S. Bankruptcy Code, $11 million of damages billed to SMGT were fully reserved.
(d)
2011 compared with 2010 was higher primarily due to $11 million of lower insurance proceeds. 2010 compared with 2009 was lower primarily due to $13 million of higher insurance proceeds.
(e)
2011 compared with 2010 was higher primarily due to plant outage costs of $13 million.
(f)
2011 compared with 2010 was lower due to lower impairment charges of sulfur dioxide emission allowances. 2010 compared with 2009 was lower primarily due to lower impairment charges of sulfur dioxide emission allowances.
(g)
Represents the charge related to the February 2009, announcement of workforce reductions that resulted in the elimination of certain management and staff positions.
Depreciation
Depreciation increased by $8 million in 2011 compared with 2010, primarily due to PP&E additions. Depreciation increased by $40 million in 2010 compared with 2009. Of the $40 million increase, $21 million was primarily due to the completion of environmental projects at Brunner Island in 2009 and 2010.
Taxes, Other Than Income
Taxes, other than income increased by $25 million in 2011 compared with 2010 primarily due to $16 million of higher Pennsylvania gross receipts tax expense as a result of an increase in retail electricity sales by PPL EnergyPlus. This tax is included in "Unregulated Gross Energy Margins." The increase also includes $8 million of higher Pennsylvania capital stock tax due in part to the expiration of the Keystone Opportunity Zone credit in 2010 and an agreed to change in a capital stock tax filing position with the state.
Taxes, other than income increased by $17 million in 2010 compared with 2009, primarily due to an increase in retail electricity sales by PPL EnergyPlus.
Other Income (Expense) - net
The $22 million decrease in other income (expense) - net in 2010 compared with 2009 was primarily attributable to PPL Energy Supply's $25 million gain on tender offers to purchase up to $250 million aggregate principal amount of certain of its outstanding senior notes including net gains on related cash flow hedges that were reclassified from AOCI into earnings in 2009.
Other-Than-Temporary Impairments
Other-than-temporary impairments decreased by $15 million in 2010 compared with 2009, primarily due to stronger returns on NDT investments caused by market fluctuations within the financial markets.
Interest Income from Affiliates
Interest income from affiliates increased by $7 million in 2010 compared with 2009, primarily due to loans to LKE subsidiaries, which have been fully repaid as of December 31, 2010.
Interest Expense
The changes in interest expense were due to:
(a)
In March 2010, the Montana Supreme Court substantially affirmed a June 2008 Montana District Court decision regarding lease payments for the use of certain Montana streambeds. As a result, in the first quarter of 2010, PPL Montana recorded $7 million of interest expense on rental compensation covered by the court decision. In August 2010, PPL Montana filed a petition for a writ of certiorari with the U.S. Supreme Court requesting the Court's review of this matter. In June 2011, the U.S. Supreme Court granted PPL Montana's petition. Oral argument was held in December 2011. PPL Montana continued to accrue interest expense on the rental compensation covered by the court decision. In February 2012, the U.S. Supreme Court overturned the Montana Supreme Court decision and remanded the case to the Montana Supreme Court for further proceedings consistent with the U.S. Supreme Court's opinion. As a result, PPL Montana reversed its total loss accrual of $89 million, which had been recorded prior to the U.S. Supreme Court decision, of which $14 million was credited to "Interest Expense" on the Statement of Income.
Income Taxes
The changes in income taxes were due to:
(a)
During 2011, the Pennsylvania Department of Revenue issued interpretive guidance on the treatment of bonus depreciation for Pennsylvania income tax purposes. In accordance with Corporation Tax Bulletin 2011-01, Pennsylvania allows 100% bonus depreciation for qualifying assets in the same year bonus depreciation is allowed for Federal income tax purposes. Due to the decrease in taxable income related to bonus depreciation and a decrease in projected future taxable income, PPL Energy Supply recorded $22 million in state deferred income tax expense related to deferred tax valuation allowances during 2011.
Pennsylvania H.B. 1531, enacted in October 2009, increased the net operating loss limitation to 20% of taxable income for tax years beginning in 2010. Based on the projected revenue increase related to the expiration of the generation rate caps, PPL Energy Supply recorded a $52 million state deferred income tax benefit related to the reversal of deferred tax valuation allowances over the remaining carry forward period of the net operating losses during 2010.
(b)
During 2011, PPL Energy Supply completed the sale of certain non-core generating assets (see Note 9 to the Financial Statements for additional information). Due to changes in state apportionment resulting in the reduction in the future estimated state tax rate, PPL Energy Supply recorded a deferred tax benefit related to its December 31, 2011 state deferred tax liabilities.
(c)
During 2010, PPL Energy Supply recorded an increase in tax benefits related to domestic manufacturing deductions due to an increase in domestic taxable income resulting from the expiration of Pennsylvania generation rate caps in 2010. In December 2010, Congress enacted legislation allowing for 100% bonus depreciation on qualified property. The increased tax depreciation deduction related to bonus depreciation significantly reduced the tax benefits related to domestic manufacturing deductions during 2010 and eliminated the tax benefit in 2011.
(d)
During 2011, PPL recorded $22 million in federal and state tax benefits related to the filing of the 2010 federal and state income tax returns. Of that amount, $7 million in tax benefits relate to an additional domestic manufacturing deduction resulting from revised bonus depreciation amounts.
During 2009, PPL Energy Supply received consent from the IRS to change its method of accounting for certain expenditures for tax purposes. PPL Energy Supply deducted the resulting IRC Sec. 481 adjustment on its 2008 federal income tax return and recorded a $21 million adjustment to federal and state income tax expense resulting from the reduction in federal income tax benefits related to the domestic manufacturing deduction and certain state tax benefits related to state net operating losses.
(e)
Beginning in 2013, provisions within Health Care Reform eliminated the tax deductibility of retiree health care costs to the extent of federal subsidies received by plan sponsors that provide retiree prescription drug benefits equivalent to Medicare Part D Coverage. As a result, PPL Energy Supply recorded deferred income tax expense during 2010.
See Note 5 to the Financial Statements for additional information on income taxes.
Discontinued Operations
Income (Loss) from Discontinued Operations (net of income taxes) decreased by $240 million in 2011 compared with 2010 and by $21 million in 2010 compared with 2009. The decrease in 2011 compared with 2010 was primarily due to the presentation of PPL Global as Discontinued Operations as a result of the January 2011 distribution by PPL Energy Supply of its membership interest in PPL Global to its parent, PPL Energy Funding. In 2011, the results of PPL Global are no longer consolidated within PPL Energy Supply. The decrease in 2010 compared with 2009 was primarily attributable to after-tax
impairment charges recorded in 2010 totaling $62 million related to assets associated with certain non-core generation facilities, which were sold in 2011, that were written down to their estimated fair value (less cost to sell). The impacts of these charges were offset by the net results of certain other discontinued operations. See Note 9 to the Financial Statements for additional information.
Financial Condition
Liquidity and Capital Resources
PPL Energy Supply expects to continue to have adequate liquidity available through operating cash flows, cash and cash equivalents and its credit facilities.
PPL Energy Supply's cash flows from operations and access to cost-effective bank and capital markets are subject to risks and uncertainties including, but not limited to:
·
changes in electricity, fuel and other commodity prices;
·
operational and credit risks associated with selling and marketing products in the wholesale power markets;
·
potential ineffectiveness of the trading, marketing and risk management policy and programs used to mitigate PPL Energy Supply's risk exposure to adverse changes in electricity and fuel prices, interest rates and counterparty credit;
·
reliance on transmission and distribution facilities that PPL Energy Supply does not own or control to deliver its electricity and natural gas;
·
unavailability of generating units (due to unscheduled or longer-than-anticipated generation outages, weather and natural disasters) and the resulting loss of revenues and additional costs of replacement electricity;
·
costs of compliance with existing and new environmental laws and with new security and safety requirements for nuclear facilities;
·
any adverse outcome of legal proceedings and investigations with respect to PPL Energy Supply's current and past business activities;
·
deterioration in the financial markets that could make obtaining new sources of bank and capital markets funding more difficult and more costly; and
·
a downgrade in PPL Energy Supply's or its rated subsidiaries' credit ratings that could adversely affect their ability to access capital and increase the cost of credit facilities and any new debt.
See "Item 1A. Risk Factors" for further discussion of risks and uncertainties affecting PPL Energy Supply's cash flows.
At December 31, PPL Energy Supply had the following:
The changes in PPL Energy Supply's cash and cash equivalents position resulted from:
Operating Activities
Net cash provided by operating activities decreased by 58%, or $1.1 billion, in 2011 compared with 2010. This was primarily due to lower gross energy margins of $240 million, after-tax, proceeds from monetizing certain full-requirements sales contracts in 2010 of $249 million, a reduction in cash from counter party collateral of $172 million, increases in other operating outflows of $200 million (including higher operation and maintenance expenses and defined benefits funding of $123 million) and the loss of operating cash from PPL Global ($203 million for 2010). In January 2011, PPL Energy Supply distributed its membership interest in PPL Global to its parent, PPL Energy Funding. See Note 9 to the Financial Statements for additional information on the distribution.
Net cash provided by operating activities increased by 30%, or $427 million, in 2010 compared with 2009. The expiration of the long-term power purchase agreements between PPL Electric and PPL EnergyPlus at the end of 2009 enabled PPL EnergyPlus to sell power at higher market prices and had a positive impact on net income, and specifically on "unregulated gross energy margins" which increased over $600 million, after-tax, in 2010 compared with 2009, and therefore, was the primary driver to the above increase. The positive impact of additional earnings was partially offset by a reduction in the amount of counterparty collateral received and by additional defined benefit plan contributions. In addition, changes in working capital in 2010 compared with 2009 offset the $300 million impact of cash collateral received from PPL Electric in 2009 as discussed below.
A significant portion of PPL Energy Supply's operating cash flows is derived from its baseload generation business activities. PPL Energy Supply employs a formal hedging program for its competitive baseload generation fleet, the primary objective of which is to provide a reasonable level of near-term cash flow and earnings certainty while preserving upside potential of power price increases over the medium term. See Note 19 to the Financial Statements for further discussion. Despite PPL Energy Supply's hedging practices, future cash flows from operating activities are influenced by commodity prices and therefore, will fluctuate from period to period.
PPL Energy Supply's contracts for the sale and purchase of electricity and fuel often require cash collateral or other credit enhancements, or reductions or terminations of a portion of the entire contract through cash settlement, in the event of a downgrade of PPL Energy Supply's or its subsidiary's credit ratings or adverse changes in market prices. For example, in addition to limiting its trading ability, if PPL Energy Supply's or its subsidiary's ratings were lowered to below "investment grade" and there was a 10% adverse movement in energy prices, PPL Energy Supply estimates that, based on its December 31, 2011 positions, it would have had to post additional collateral of approximately $351 million with respect to electricity and fuel contracts. PPL Energy Supply has in place risk management programs that are designed to monitor and manage its exposure to volatility of cash flows related to changes in energy and fuel prices, interest rates, foreign currency exchange rates, counterparty credit quality and the operating performance of its generating units.
Investing Activities
The primary use of cash in investing activities is capital expenditures. See "Forecasted Uses of Cash" for detail regarding projected capital expenditures for the years 2012 through 2016.
Net cash used in investing activities decreased $157 million in 2011 compared with 2010, primarily as a result of a decrease of $348 million in capital expenditures and a $219 million increase in the proceeds received from the sale of businesses, which are discussed in Note 9 to the Financial Statements. The decrease in cash used in investing activities from the above items was partially offset by an increase of $198 million related to notes receivable from affiliates and $212 million from changes in restricted cash and cash equivalents.
Net cash used in investing activities increased $274 million in 2010 compared with 2009, primarily as a result of a decrease of $154 million from proceeds from the sale of other investments, a change of $135 million from restricted cash and cash equivalents, and an increase of $102 million in capital expenditures. The increase in cash used in investing activities from the above items was partially offset by $81 million in proceeds received from the sale of businesses, which are discussed in Note 9 to the Financial Statements, and a change of $28 million in other investing activities.
In January 2011, PPL Energy Supply distributed its 100% membership interest in PPL Global to its parent, PPL Energy Funding. See Note 9 to the Financial Statements for additional information. Excluding PPL Global, PPL Energy Supply's net cash used in investing activities was $544 million and $308 million for 2010 and 2009.
Financing Activities
Net cash used in financing activities was $390 million in 2011 compared with $612 million in 2010 and $1.1 billion in 2009. The decrease from 2010 to 2011 primarily reflects lower net distributions to Member, partially offset by lower net issuances of long-term debt and the distribution of cash included in the net assets of PPL Global to PPL Energy Funding. The change from 2009 to 2010 primarily reflects more long-term debt issuances, increased contributions from and distributions to Member, and less short-term borrowings in 2010.
In 2011, cash used in financing activities primarily consisted of a $325 million distribution of cash included in the net assets of PPL Global to PPL Energy Funding, $316 million in distributions to Member, and net debt retirements of $200 million, partially offset by $461 million in contributions from Member.
In 2010, cash used in financing activities primarily consisted of $4.7 billion in distributions to Member, partially offset by $3.6 billion in contributions from Member and net debt issuances of $509 million. The distributions to and contributions
from Member during 2010 primarily relate to the funds received by PPL in June 2010 from the issuance of common stock and 2010 Equity Units. These funds were invested by a subsidiary of PPL Energy Supply until they were returned to its Member in October 2010 to be available to partially fund PPL's acquisition of LKE and pay certain acquisition-related fees and expenses.
In 2009, cash used in financing activities primarily consisted of $943 million in distributions to Member and net debt retirements of $177 million, partially offset by $50 million in contributions from Member.
See "Forecasted Sources of Cash" for a discussion of PPL Energy Supply's plans to issue debt securities, as well as a discussion of credit facility capacity available to PPL Energy Supply. Also see "Forecasted Uses of Cash" for information regarding maturities of PPL Energy Supply's long-term debt.
PPL Energy Supply's debt financing activity in 2011 was:
(a)
Issuances are net of pricing discounts, where applicable and exclude the impact of debt issuance costs.
See Note 7 to the Financial Statements for more detailed information regarding PPL Energy Supply's financing activities in 2011.
Forecasted Sources of Cash
PPL Energy Supply expects to continue to have sufficient sources of cash available in the near term, including various credit facilities, operating leases and contributions from Member.
Credit Facilities
At December 31, 2011, PPL Energy Supply's total committed borrowing capacity under credit facilities and the use of this borrowing capacity were:
(a)
In October 2011, PPL Energy Supply amended its Syndicated Credit Facility. The amendment included extending the expiration date from December 2014 to October 2016. Under this facility, PPL Energy Supply continues to have the ability to make cash borrowings and to request the lenders to issue letters of credit. This facility contains a financial covenant requiring PPL Energy Supply's debt to total capitalization not to exceed 65%, as calculated in accordance with the facility, and other customary covenants.
(b)
In March 2011, PPL Energy Supply's $300 million Structured Credit Facility expired. PPL Energy Supply's obligations under this facility were supported by a $300 million letter of credit issued on PPL Energy Supply's behalf under a separate, but related $300 million 5-year credit agreement, which also expired in March 2011.
The commitments under PPL Energy Supply's credit facilities are provided by a diverse bank group, with no one bank and its affiliates providing an aggregate commitment of more than 11% of the total committed capacity.
In January 2011, PPL Energy Supply distributed its 100% membership interest in PPL Global to its parent, PPL Energy Funding. See Note 9 to the Financial Statements for additional information.
In addition to the financial covenants noted above, the credit agreements governing the above credit facilities contain various other covenants. Failure to comply with the covenants after applicable grace periods could result in acceleration of repayment of borrowings and/or termination of the agreements. PPL Energy Supply monitors compliance with the covenants
on a regular basis. At December 31, 2011, PPL Energy Supply was in compliance with these covenants. At this time, PPL Energy Supply believes that these covenants and other borrowing conditions will not limit access to these funding sources.
See Note 7 to the Financial Statements for further discussion of PPL Energy Supply's credit facilities.
Commercial Paper
In October 2011, PPL Energy Supply re-activated its $500 million commercial paper program to provide an additional financing source to fund its short-term liquidity needs, if and when necessary. Commercial paper issuances are supported by PPL Energy Supply's Syndicated Credit Facility. At December 31, 2011, PPL Energy Supply had $400 million of commercial paper outstanding at a weighted-average interest rate of approximately 0.53%.
Operating Leases
PPL Energy Supply and its subsidiaries also have available funding sources that are provided through operating leases. PPL Energy Supply's subsidiaries lease office space, land, buildings and certain equipment. These leasing structures provide PPL Energy Supply additional operating and financing flexibility. The operating leases contain covenants that are typical for these agreements, such as maintaining insurance, maintaining corporate existence and timely payment of rent and other fees.
PPL Energy Supply, through its subsidiary PPL Montana, leases a 50% interest in Colstrip Units 1 and 2 and a 30% interest in Unit 3, under four 36-year, non-cancelable operating leases. These operating leases are not recorded on PPL Energy Supply's Balance Sheets. The leases place certain restrictions on PPL Montana's ability to incur additional debt, sell assets and declare dividends. At this time, PPL Energy Supply believes that these restrictions will not limit access to these funding sources or cause acceleration or termination of the leases.
See Note 11 to the Financial Statements for further discussion of the operating leases.
Long-term Debt Securities and Contributions from Member
PPL Energy Supply does not currently plan to issue long-term debt securities in 2012.
From time to time, PPL Energy Supply's Member, PPL Energy Funding, makes capital contributions to PPL Energy Supply. PPL Energy Supply uses these contributions for general corporate purposes.
Forecasted Uses of Cash
In addition to expenditures required for normal operating activities, such as purchased power, payroll, fuel and taxes, PPL Energy Supply currently expects to incur future cash outflows for capital expenditures, various contractual obligations, distributions to its Member and possibly the purchase or redemption of a portion of its debt securities.
Capital Expenditures
The table below shows PPL Energy Supply's current capital expenditure projections for the years 2012 through 2016.
(a)
Construction expenditures include capitalized interest, which is expected to be approximately $134 million for the years 2012 through 2016.
(b)
Includes expenditures for certain intangible assets.
(c)
Nuclear fuel expenditures include capitalized interest, which is expected to be approximately $25 million for the years 2012 through 2016.
PPL Energy Supply's capital expenditure projections for the years 2012 through 2016 total approximately $3.0 billion. Capital expenditure plans are revised periodically to reflect changes in operational, market and regulatory conditions. This table includes projected costs related to the planned 191 MW of incremental capacity increases. See Note 8 to the Financial Statements for information regarding the significant development projects.
PPL Energy Supply plans to fund its capital expenditures in 2012 with cash on hand and cash from operations.
Contractual Obligations
PPL Energy Supply has assumed various financial obligations and commitments in the ordinary course of conducting its business. At December 31, 2011, the estimated contractual cash obligations of PPL Energy Supply were:
(a)
Reflects principal maturities only based on stated maturity dates, except for the 5.70% REset Put Securities (REPS). See Note 7 to the Financial Statements for a discussion of the remarketing feature related to the REPS, as well as discussion of variable-rate remarketable bonds. PPL Energy Supply does not have any significant capital lease obligations.
(b)
Assumes interest payments through stated maturity, except for the REPS, for which interest is reflected to the put date. The payments herein are subject to change, as payments for debt that is or becomes variable-rate debt have been estimated.
(c)
See Note 11 to the Financial Statements for additional information.
(d)
The amounts include agreements to purchase goods or services that are enforceable and legally binding and specify all significant terms, including: fixed or minimum quantities to be purchased; fixed, minimum or variable price provisions; and the approximate timing of the transaction. Primarily includes PPL Energy Supply's purchase obligations of electricity, coal, nuclear fuel and limestone as well as certain construction expenditures, which are also included in the Capital Expenditures table presented above. Financial swaps and open purchase orders that are provided on demand with no firm commitment are excluded from the amounts presented. In prior years, PPL included certain energy purchase obligations based on forecasted amounts to be purchased. The amounts presented herein are based on actual contract terms.
(e)
The amounts represent contributions made or committed to be made for 2012 for PPL's and PPL Energy Supply's U.S. pension plans. See Note 13 to the Financial Statements for a discussion of expected contributions.
(f)
At December 31, 2011, total unrecognized tax benefits of $28 million were excluded from this table as PPL Energy Supply cannot reasonably estimate the amount and period of future payments. See Note 5 to the Financial Statements for additional information.
Distributions to Member
From time to time, as determined by its Board of Managers, PPL Energy Supply makes return of capital distributions to its Member. In January 2011, PPL Energy Supply distributed its membership interest in PPL Global to PPL Energy Supply's parent at a book value of approximately $1.3 billion, which included $325 million of cash and cash equivalents. See Note 9 to the Financial Statements for additional information.
Purchase or Redemption of Debt Securities
PPL Energy Supply will continue to evaluate its outstanding debt securities and may decide to purchase or redeem these securities depending upon prevailing market conditions and available cash.
Rating Agency Decisions
Moody's, S&P and Fitch periodically review the credit ratings on the debt securities of PPL Energy Supply and its subsidiaries. Based on their respective independent reviews, the rating agencies may make certain ratings revisions or ratings affirmations.
A credit rating reflects an assessment by the rating agency of the creditworthiness associated with an issuer and particular securities that it issues. The credit ratings of PPL Energy Supply and its subsidiaries are based on information provided by PPL Energy Supply and other sources. The ratings of Moody's, S&P and Fitch are not a recommendation to buy, sell or hold any securities of PPL Energy Supply or its subsidiaries. Such ratings may be subject to revisions or withdrawal by the agencies at any time and should be evaluated independently of each other and any other rating that may be assigned to the securities. A downgrade in PPL Energy Supply's or its subsidiaries' credit ratings could result in higher borrowing costs and reduced access to capital markets.
As a result of the passage of the Dodd-Frank Act PPL Energy Supply is limiting its credit rating disclosure to a description of the actions taken by the rating agencies with respect to PPL Energy Supply's ratings, but without stating what ratings have been assigned to PPL Energy Supply or its subsidiaries, or their securities. The ratings assigned by the rating agencies to PPL Energy Supply and its subsidiaries and their respective securities may be found, without charge, on each of the
respective ratings agencies' websites, which ratings together with all other information contained on such rating agency websites is, hereby, explicitly not incorporated by reference in this report.
The rating agencies took the following actions related to PPL Energy Supply and its subsidiaries in 2011.
Following the announcement of PPL's then-pending acquisition of WPD Midlands in March 2011, the rating agencies took the following actions:
·
Moody's affirmed its ratings for PPL Energy Supply;
·
S&P revised the outlook and lowered the issuer and senior unsecured ratings of PPL Energy Supply; and
·
Fitch affirmed its ratings for PPL Energy Supply.
In April 2011, following the completion of PPL's acquisition of WPD Midlands, S&P revised the outlook and affirmed its ratings for PPL Energy Supply.
In May 2011, Fitch affirmed its rating and maintained its outlook for PPL Montana's Pass Through Certificates due 2020.
In September 2011, Moody's affirmed its senior unsecured debt rating and outlook for PPL Energy Supply.
Also in September 2011, S&P assigned a short-term rating to PPL Energy Supply's commercial paper program.
In October 2011, Moody's and Fitch also assigned a short-term rating to PPL Energy Supply's commercial paper program in support of PPL Energy Supply's re-opening of the program.
In November 2011, Fitch affirmed its rating and revised its outlook to negative from stable for PPL Montana's Pass Through Certificates due 2020.
In December 2011, Fitch affirmed the Issuer Default Ratings and individual security ratings of PPL Energy Supply.
In January 2012, S&P affirmed its rating and revised its outlook to stable from positive for PPL Montana's Pass Through Certificates due 2020.
Ratings Triggers
PPL Energy Supply has various derivative and non-derivative contracts, including contracts for the sale and purchase of electricity and fuel, commodity transportation and storage, tolling agreements and interest rate instruments, which contain provisions requiring PPL Energy Supply to post additional collateral, or permit the counterparty to terminate the contract, if PPL Energy Supply's credit rating were to fall below investment grade. See Note 19 to the Financial Statements for a discussion of "Credit Risk-Related Contingent Features," including a discussion of the potential additional collateral that would have been required for derivative contracts in a net liability position at December 31, 2011. At December 31, 2011, if PPL Energy Supply's credit rating had been below investment grade, PPL Energy Supply would have been required to prepay or post an additional $391 million of collateral to counterparties for both derivative and non-derivative commodity and commodity-related contracts used in its generation, marketing and trading operations and interest rate contracts.
Guarantees for Subsidiaries
PPL Energy Supply guarantees certain consolidated affiliate financing arrangements that enable certain transactions. Some of the guarantees contain financial and other covenants that, if not met, would limit or restrict the consolidated affiliates' access to funds under these financing arrangements, require early maturity of such arrangements or limit the consolidated affiliates' ability to enter into certain transactions. At this time, PPL Energy Supply believes that these covenants will not limit access to relevant funding sources. See Note 15 to the Financial Statements for additional information about guarantees.
Off-Balance Sheet Arrangements
PPL Energy Supply has entered into certain agreements that may contingently require payment to a guaranteed or indemnified party. See Note 15 to the Financial Statements for a discussion of these agreements.
Risk Management - Energy Marketing & Trading and Other
Market Risk
See Notes 1, 18, and 19 to the Financial Statements for information about PPL Energy Supply's risk management objectives, valuation techniques and accounting designations.
The forward-looking information presented below provides estimates of what may occur in the future, assuming certain adverse market conditions and model assumptions. Actual future results may differ materially from those presented. These disclosures are not precise indicators of expected future losses, but only indicators of possible losses at a given confidence level.
Commodity Price Risk (Non-trading)
PPL Energy Supply segregates its non-trading activities into two categories: hedge activity and economic activity. Transactions that are accounted for as hedge activity qualify for hedge accounting treatment. The economic activity category includes transactions that address a specific risk, but were not eligible for hedge accounting or for which hedge accounting was not elected. This activity includes the changes in fair value of positions used to hedge a portion of the economic value of PPL Energy Supply's competitive generation assets and full-requirement sales and retail contracts. This economic activity is subject to changes in fair value due to market price volatility of the input and output commodities (e.g., fuel and power). Although they do not receive hedge accounting treatment, these transactions are considered non-trading activity. The fair value of economic positions at December 31, 2011 and 2010 was a net liability of $63 million and $389 million. See Note 19 to the Financial Statements for additional information on hedge and economic activity.
To hedge the impact of market price volatility on PPL Energy Supply's energy-related assets, liabilities and other contractual arrangements, PPL Energy Supply both sells and purchases physical energy at the wholesale level under FERC market-based tariffs throughout the U.S. and enters into financial exchange-traded and over-the-counter contracts. PPL Energy Supply's non-trading commodity derivative contracts mature at various times through 2019.
The following table sets forth the changes in net fair value of PPL Energy Supply's non-trading commodity derivative contracts. See Notes 18 and 19 to the Financial Statements for additional information.
(a)
Represents the fair value of contracts at the end of the quarter of their inception.
(b)
In June 2010, PPL Energy Supply received market bids for certain full-requirement sales contracts that were monetized in early July. See Note 19 to the Financial Statements for additional information. At June 30, 2010, these contracts were valued based on the bids received (the market approach). In prior periods, the fair value of these contracts was measured using the income approach.
The following table segregates the net fair value of PPL Energy Supply's non-trading commodity derivative contracts at December 31, 2011, based on whether the fair value was determined by prices quoted in active markets for identical instruments or other more subjective means.
PPL Energy Supply sells electricity, capacity and related services and buys fuel on a forward basis to hedge the value of energy from its generation assets. If PPL Energy Supply were unable to deliver firm capacity and energy or to accept the delivery of fuel under its agreements, under certain circumstances it could be required to pay liquidating damages. These
damages would be based on the difference between the market price and the contract price of the commodity. Depending on price changes in the wholesale energy markets, such damages could be significant. Extreme weather conditions, unplanned power plant outages, transmission disruptions, nonperformance by counterparties with which it has energy contracts and other factors could affect PPL Energy Supply's ability to meet its obligations, or cause significant increases in the market price of replacement energy. Although PPL Energy Supply attempts to mitigate these risks, there can be no assurance that it will be able to fully meet its firm obligations, that it will not be required to pay damages for failure to perform, or that it will not experience counterparty nonperformance in the future.
Commodity Price Risk (Trading)
PPL Energy Supply's trading commodity derivative contracts mature at various times through 2015. The following table sets forth changes in the net fair value of PPL Energy Supply's trading commodity derivative contracts. See Notes 18 and 19 to the Financial Statements for additional information.
(a)
Represents the fair value of contracts at the end of the quarter of their inception.
Unrealized losses of approximately $2 million will be reversed over the next three months as the transactions are realized.
The following table segregates the net fair value of PPL Energy Supply's trading commodity derivative contracts at December 31, 2011, based on whether the fair value was determined by prices quoted in active markets for identical instruments or other more subjective means.
VaR Models
PPL Energy Supply utilizes a VaR model to measure commodity price risk in unregulated gross energy margins for its non-trading and trading portfolios. VaR is a statistical model that attempts to estimate the value of potential loss over a given holding period under normal market conditions at a given confidence level. PPL Energy Supply calculates VaR using a Monte Carlo simulation technique based on a five-day holding period at a 95% confidence level. Given the company's conservative hedging program, PPL's non-trading VaR exposure is expected to be limited in the short term. At December 31, 2011 and December 31, 2010, the VaR for PPL Energy Supply's portfolios using end-of-month results for the period was as follows.
The trading portfolio includes all speculative positions, regardless of the delivery period. All positions not considered speculative are considered non-trading. PPL Energy Supply's non-trading portfolio includes PPL Energy Supply's entire portfolio, including generation, with delivery periods through the next 12 months. Both the trading and non-trading VaR computations exclude FTRs due to the absence of reliable spot and forward markets. The fair value of the non-trading and trading FTR positions was insignificant at December 31, 2011.
Interest Rate Risk
PPL Energy Supply and its subsidiaries have issued debt to finance their operations, which exposes them to interest rate risk. PPL and PPL Energy Supply utilize various financial derivative instruments to adjust the mix of fixed and floating interest rates in PPL Energy Supply's debt portfolio, adjust the duration of its debt portfolio and lock in benchmark interest rates in anticipation of future financing, when appropriate. Risk limits under the risk management program are designed to balance risk exposure to volatility in interest expense and changes in the fair value of PPL Energy Supply's debt portfolio due to changes in the absolute level of interest rates.
At December 31, 2011 and 2010, PPL Energy Supply's potential annual exposure to increased interest expense, based on a 10% increase in interest rates, was not significant.
PPL Energy Supply is also exposed to changes in the fair value of its debt portfolio. PPL Energy Supply estimated that a 10% decrease in interest rates at December 31, 2011 would increase the fair value of its debt portfolio by $53 million, compared with $198 million at December 31, 2010.
PPL Energy Supply had the following interest rate hedges outstanding at:
(a)
Includes accrued interest, if applicable.
(b)
Effects of adverse movements decrease assets or increase liabilities, as applicable, which could result in an asset becoming a liability.
(c)
PPL and PPL Energy Supply utilize various risk management instruments to reduce PPL Energy Supply's exposure to the expected future cash flow variability of PPL Energy Supply's debt instruments. These risks include exposure to adverse interest rate movements for outstanding variable rate debt and for future anticipated financing. While PPL Energy Supply is exposed to changes in the fair value of these instruments, any changes in the fair value of such cash flow hedges are recorded in equity. The changes in fair value of these instruments are then reclassified into earnings in the same period during which the item being hedged affects earnings. Sensitivities represent a 10% adverse movement in interest rates.
(d)
Represents cross-currency swaps used by PPL WW to hedge the interest payments and principal of its U.S. dollar-denominated senior notes with maturity dates ranging from December 2017 to December 2028. In 2010, these swaps were part of PPL Energy Supply's business. As a result of the distribution of PPL Energy Supply's membership interest in PPL Global to PPL Energy Funding, effective January 2011, these swaps are no longer part of PPL Energy Supply's business. While PPL Energy Supply was exposed to changes in the fair value of these instruments, any change in the fair value of these instruments was recorded in equity and reclassified into earnings in the same period during which the item being hedged affected earnings. Sensitivity represents a 10% adverse movement in both interest rates and foreign currency exchange rates.
(e)
PPL and PPL Energy Supply utilize various risk management instruments to adjust the mix of fixed and floating interest rates in PPL Energy Supply's debt portfolio. The change in fair value of these instruments, as well as the offsetting change in the value of the hedged exposure of the debt, is reflected in earnings. Sensitivities represent a 10% adverse movement in interest rates.
Foreign Currency Risk
PPL and PPL Energy Supply have adopted a foreign currency risk management program designed to hedge certain foreign currency exposures, including firm commitments, recognized assets or liabilities, anticipated transactions and net investments, as well as to protect against foreign currency translation risk of expected earnings.
Prior to 2011, PPL Energy Supply's exposure to foreign currency risk was through its investments in U.K. affiliates. In addition, PPL Energy Supply's domestic operations may make purchases of equipment in currencies other than U.S. dollars. See Note 1 to the Financial Statements for additional information regarding foreign currency translation.
PPL and PPL Energy Supply previously entered into contracts to protect the value of a portion of PPL Energy Supply's net investment in WPD and to economically hedge anticipated earnings denominated in GBP. In 2010, these contracts were included in PPL Energy Supply's business. As a result of the distribution of PPL Energy Supply's membership interest in PPL Global to PPL Energy Funding, effective January 2011, these contracts are no longer included in PPL Energy Supply's business.
At December 31, 2011, PPL Energy Supply did not have any foreign currency hedges outstanding. At December 31, 2010, PPL Energy Supply had the following foreign currency hedges outstanding:
(a)
Effects of adverse movements decrease assets or increase liabilities, as applicable, which could result in an asset becoming a liability.
(b)
To protect the value of a portion of PPL Energy Supply's net investment in WPD, PPL executed forward contracts to sell GBP.
(c)
To economically hedge the translation of expected income denominated in GBP to U.S. dollars, PPL entered into a combination of average rate forwards and average rate options to sell GBP.
NDT Funds - Securities Price Risk
In connection with certain NRC requirements, PPL Susquehanna maintains trust funds to fund certain costs of decommissioning the Susquehanna nuclear plant. At December 31, 2011, these funds were invested primarily in domestic equity securities and fixed-rate, fixed-income securities and are reflected at fair value on PPL Energy Supply's Balance Sheet. The mix of securities is designed to provide returns sufficient to fund Susquehanna's decommissioning and to compensate for inflationary increases in decommissioning costs. However, the equity securities included in the trusts are exposed to price fluctuation in equity markets, and the values of fixed-rate, fixed-income securities are exposed to changes in interest rates. PPL actively monitors the investment performance and periodically reviews asset allocation in accordance with its nuclear decommissioning trust policy statement. At December 31, 2011, a hypothetical 10% increase in interest rates and a 10% decrease in equity prices would have resulted in an estimated $43 million reduction in the fair value of the trust assets, compared with $45 million at December 31, 2010. See Notes 18 and 23 to the Financial Statements for additional information regarding the NDT funds.
Defined Benefit Plans - Securities Price Risk
See "Application of Critical Accounting Policies - Defined Benefits" for additional information regarding the effect of securities price risk on plan assets.
Credit Risk
Credit risk is the risk that PPL Energy Supply would incur a loss as a result of nonperformance by counterparties of their contractual obligations. PPL Energy Supply maintains credit policies and procedures with respect to counterparty credit (including requirements that counterparties maintain specified credit ratings) and requires other assurances in the form of credit support or collateral in certain circumstances in order to limit counterparty credit risk. However, PPL Energy Supply has concentrations of suppliers and customers among electric utilities, financial institutions and other energy marketing and trading companies. These concentrations may impact PPL Energy Supply's overall exposure to credit risk, positively or negatively, as counterparties may be similarly affected by changes in economic, regulatory or other conditions.
PPL Energy Supply includes the effect of credit risk on its fair value measurements to reflect the probability that a counterparty will default when contracts are out of the money (from the counterparty's standpoint). In this case, PPL Energy Supply would have to sell into a lower-priced market or purchase from a higher-priced market. When necessary, PPL Energy Supply records an allowance for doubtful accounts to reflect the probability that a counterparty will not pay for deliveries PPL Energy Supply has made but not yet billed, which are reflected in "Unbilled revenues" on the Balance Sheets. PPL Energy Supply also has established a reserve with respect to certain receivables from SMGT, which is reflected in accounts receivable on the Balance Sheets. See Note 15 to the Financial Statements for additional information.
See "Overview" in this Item 7 and Notes 16, 18 and 19 to the Financial Statements for additional information on credit concentration and credit risk.
Foreign Currency Translation
As noted previously, in January 2011, PPL Energy Supply distributed its interest in PPL Global to its parent, PPL Energy Funding. As a result, PPL Energy Supply no longer consolidates any foreign subsidiaries and has no foreign currency translation component within AOCI. The value of the British pound sterling fluctuates in relation to the U.S. dollar. In 2010, changes in these exchange rates resulted in a foreign currency translation loss of $63 million, which primarily reflected a $180 million reduction to PP&E offset by a reduction of $117 million to net liabilities. In 2009, changes in these exchange rates resulted in a foreign currency translation gain of $106 million, which primarily reflected a $225 million increase in
PP&E offset by an increase of $119 million to net liabilities. The impact of foreign currency translation was recorded in AOCI.
Related Party Transactions
PPL Energy Supply is not aware of any material ownership interests or operating responsibility by senior management of PPL Energy Supply in outside partnerships, including leasing transactions with variable interest entities, or other entities doing business with PPL Energy Supply. See Note 16 to the Financial Statements for additional information on related party transactions.
Acquisitions, Development and Divestitures
PPL Energy Supply continuously evaluates potential acquisitions, divestitures and development projects as opportunities arise or are identified. Development projects are continuously reexamined based on market conditions and other factors to determine whether to proceed with the projects, sell, cancel or expand them, execute tolling agreements or pursue other options.
In 2011, the final phase of the Susquehanna uprate project, a 50 MW Unit 2 uprate, was completed. In addition, incremental capacity increases of 191 MW are currently planned, primarily at existing PPL Energy Supply generating facilities. See "Item 2. Properties - Supply Segment" for additional information.
See Notes 8 and 9 to the Financial Statements for additional information on the more significant activities.
Environmental Matters
Protection of the environment is a priority for PPL Energy Supply and a significant element of its business activities. Extensive federal, state and local environmental laws and regulations are applicable to PPL Energy Supply's air emissions, water discharges and the management of hazardous and solid waste, among other areas; and the cost of compliance or alleged non-compliance cannot be predicted with certainty but could be material. In addition, costs may increase significantly if the requirements or scope of environmental laws or regulations, or similar rules, are expanded or changed from prior versions by the relevant agencies. Costs may take the form of increased capital or operating and maintenance expenses; monetary fines, penalties or forfeitures or other restrictions. Many of these environmental law considerations are also applicable to the operations of key suppliers, or customers, such as coal producers, industrial power users, etc., and may impact the cost for their products or their demand for PPL Energy Supply's services. See "Item 1. Business - Environmental Matters" and Note 15 to the Financial Statements for a discussion of environmental matters.
Competition
See "Competition" under the International Regulated and Supply segments in "Item 1. Business - Segment Information" and "Item 1A. Risk Factors" for a discussion of competitive factors affecting PPL Energy Supply.
New Accounting Guidance
See Notes 1 and 24 to the Financial Statements for a discussion of new accounting guidance adopted and pending adoption.
Application of Critical Accounting Policies
Financial condition and results of operations are impacted by the methods, assumptions and estimates used in the application of critical accounting policies. The following accounting policies are particularly important to the financial condition or results of operations, and require estimates or other judgments of matters inherently uncertain. Changes in the estimates or other judgments included within these accounting policies could result in a significant change to the information presented in the Financial Statements (these accounting policies are also discussed in Note 1 to the Financial Statements). PPL's senior management has reviewed these critical accounting policies, the following disclosures regarding their application and the estimates and assumptions regarding them, with PPL's Audit Committee.
1) Price Risk Management
See "Price Risk Management" in Note 1 to the Financial Statements, as well as "Risk Management - Energy Marketing & Trading and Other" above.
2) Defined Benefits
PPL Energy Supply subsidiaries sponsor and participate in various qualified funded and non-qualified unfunded defined benefit pension plans. PPL Energy Supply subsidiaries also sponsor an unfunded other postretirement benefit plan. PPL Energy Supply records the liability and net periodic defined benefit costs of its plans and the allocated portion of those plans sponsored by PPL Services based on participation in those plans. PPL Energy Supply subsidiaries record an asset or liability to recognize the funded status of all defined benefit plans with an offsetting entry to OCI. Consequently, the funded status of all defined benefit plans is fully recognized on the Balance Sheets. See Note 13 to the Financial Statements for additional information about the plans and the accounting for defined benefits.
PPL Services and PPL Energy Supply make certain assumptions regarding the valuation of benefit obligations and the performance of plan assets. When accounting for defined benefits, delayed recognition in earnings of differences between actual results and expected or estimated results is a guiding principle. Annual net periodic defined benefit costs are recorded in current earnings based on estimated results. Any differences between actual and estimated results are recorded in OCI. These amounts in AOCI are amortized to income over future periods. The delayed recognition allows for a smoothed recognition of costs over the working lives of the employees who benefit under the plans. The primary assumptions are:
·
Discount Rate - The discount rate is used in calculating the present value of benefits, which is based on projections of benefit payments to be made in the future. The objective in selecting the discount rate is to measure the single amount that, if invested at the measurement date in a portfolio of high-quality debt instruments, would provide the necessary future cash flows to pay the accumulated benefits when due.
·
Expected Return on Plan Assets - Management projects the long-term rates of return on plan assets based on historical performance, future expectations and periodic portfolio rebalancing among the diversified asset classes. These projected returns reduce the net benefit costs PPL records currently.
·
Rate of Compensation Increase - Management projects employees' annual pay increases, which are used to project employees' pension benefits at retirement.
·
Health Care Cost Trend Rate - Management projects the expected increases in the cost of health care.
In selecting a discount rate for their defined benefit plans, PPL Services and PPL Energy Supply start with a cash flow analysis of the expected benefit payment stream for its plans. For 2010, these plan-specific cash flows were matched against a spot-rate yield curve to determine the assumed discount rate. To develop the spot-rate yield curve, the full universe of Aa-rated non-callable (or callable with make-whole provisions) bonds, served as the base from which those with the lowest and highest yields were eliminated to develop an appropriate subset of bonds from which the ultimate yield curve would be built. At that time, Management believed this plan-specific cash flow matching model represented the best available tool for estimating the discount rate. Beginning in 2011, PPL Services and PPL Energy Supply utilized a new tool that enhanced this plan-specific cash flow matching methodology by primarily matching the plan-specific cash flows against the coupons and expected maturity values of individually selected bonds. This bond matching process begins with the same subset of the universe of Aa-rated corporate bonds from which those with the lowest and highest yields were eliminated, similar to the yield curve approach. Individual bonds were then selected based on the timing of each plan's cash flows and parameters were established as to the percentage of each individual bond issue that could be hypothetically purchased and the surplus reinvestment rates to be assumed. This process more accurately approximated the process of settlement of the obligations, which better aligns with the objective of selecting the discount rate. At December 31, 2011, PPL Services decreased the discount rate for its U.S. pension plans from 5.41% to 5.07% and PPL Energy Supply decreased the discount rate for its pension plan from 5.47% to 5.12%. PPL Services decreased the discount rate for its other postretirement benefit plan from 5.16% to 4.81% and PPL Energy Supply decreased the discount rate for its other postretirement benefit plan from 4.95% to 4.60%.
The expected long-term rates of return for PPL Services and PPL Energy Supply's U.S. defined benefit pension and other postretirement benefit plans have been developed using a best-estimate of expected returns, volatilities and correlations for each asset class. PPL management corroborates these rates with expected long-term rates of return calculated by its independent actuary, who uses a building block approach that begins with a risk-free rate of return with factors being added such as inflation, duration, credit spreads and equity risk. Each plan's specific asset allocation is also considered in developing a reasonable return assumption. Based on PPL's change to a liability-driven investment strategy, PPL's U.S. defined benefit pension assets have shifted into a greater proportion of fixed-income investments. Based on this change in investment strategy, at December 31, 2011, PPL Services' and PPL Energy Supply's expected return on plan assets decreased from 7.25% to 7.00% for their U.S. pension plans and decreased from 6.45% to 5.70% for PPL Services' other postretirement benefit plan.
In selecting a rate of compensation increase, PPL Energy Supply considers past experience in light of movements in inflation rates. At December 31, 2011, PPL Services and PPL Energy Supply's rate of compensation decreased from 4.75% to 4.00% for their U.S. plans.
In selecting health care cost trend rates, PPL Services and PPL Energy Supply consider past performance and forecasts of health care costs. At December 31, 2011, PPL Services' and PPL Energy Supply's health care cost trend rates were 8.50% for 2012, gradually declining to 5.50% for 2019.
A variance in the assumptions listed above could have a significant impact on accrued defined benefit liabilities or assets, reported annual net periodic defined benefit costs and OCI. While the charts below reflect either an increase or decrease in each assumption, the inverse of this change would impact the accrued defined benefit liabilities or assets, reported annual net periodic defined benefit costs and OCI by a similar amount in the opposite direction. The sensitivities below reflect an evaluation of the change based solely on a change in that assumption and does not include income tax effects.
At December 31, 2011, the defined benefit plans were recorded as follows.
The following chart reflects the sensitivities in the December 31, 2011 Balance Sheet associated with a change in certain assumptions based on PPL Services' and PPL Energy Supply's primary defined benefit plans.
(a)
Only impacts other postretirement benefits.
In 2011, PPL Energy Supply was allocated and recognized net periodic defined benefit costs charged to operating expense of $35 million. This amount represents a $1 million decrease from 2010.
The following chart reflects the sensitivities in the 2011 Statement of Income (excluding income tax effects) associated with a change in certain assumptions based on PPL's and PPL Energy Supply's primary defined benefit plans.
3) Asset Impairment
Impairment analyses are performed for long-lived assets that are subject to depreciation or amortization whenever events or changes in circumstances indicate that a long-lived asset's carrying value may not be recoverable. For these long-lived assets classified as held and used, such events or changes in circumstances are:
·
a significant decrease in the market price of an asset;
·
a significant adverse change in the manner in which an asset is being used or in its physical condition;
·
a significant adverse change in legal factors or in the business climate;
·
an accumulation of costs significantly in excess of the amount originally expected for the acquisition or construction of an asset;
·
a current period operating or cash flow loss combined with a history of losses or a forecast that demonstrates continuing losses; or
·
a current expectation that, more likely than not, an asset will be sold or otherwise disposed of significantly before the end of its previously estimated useful life.
For a long-lived asset classified as held and used, an impairment is recognized when the carrying amount of the asset is not recoverable and exceeds its fair value. The carrying amount is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. If the asset is impaired, an impairment loss is recorded to adjust the asset's carrying value to its estimated fair value. Management must make significant judgments to
estimate future cash flows, including the useful lives of long-lived assets, the fair value of the assets and management's intent to use the assets. Alternate courses of action are considered to recover the carrying value of a long-lived asset, and estimated cash flows from the "most likely" alternative are used to assess impairment whenever one alternative is clearly the most likely outcome. If no alternative is clearly the most likely, then a probability-weighted approach is used taking into consideration estimated cash flows from the alternatives. For assets tested for impairment as of the balance sheet date, the estimates of future cash flows used in that test consider the likelihood of possible outcomes that existed at the balance sheet date, including the assessment of the likelihood of a future sale of the assets. That assessment is not revised based on events that occur after the balance sheet date. Changes in assumptions and estimates could result in significantly different results than those identified and recorded in the financial statements.
For a long-lived asset classified as held for sale, an impairment exists when the carrying amount of the asset (disposal group) exceeds its fair value less cost to sell. If the asset (disposal group) is impaired, an impairment loss is recorded to adjust the carrying amount to its fair value less cost to sell. A gain is recognized for any subsequent increase in fair value less cost to sell, but not in excess of the cumulative impairment previously recognized.
For determining fair value, quoted market prices in active markets are the best evidence. However, when market prices are unavailable, the Registrant considers all valuation techniques appropriate under the circumstances and for which market participant inputs can be obtained. Generally discounted cash flows are used to estimate fair value, which incorporates market participant inputs when available. Discounted cash flows are calculated by estimating future cash flow streams and applying appropriate discount rates to determine the present value of the cash flow streams.
See Note 18 to the Financial Statements for a discussion of impairments related to certain intangible assets in 2011.
Goodwill is tested for impairment at the reporting unit level. PPL Energy Supply's reporting unit has been determined to be at the operating segment level. A goodwill impairment test is performed annually or more frequently if events or changes in circumstances indicate that the carrying value of the reporting unit may be greater than the unit's fair value. Additionally, goodwill is tested for impairment after a portion of goodwill has been allocated to a business to be disposed of.
Goodwill is tested for impairment using a two-step approach. In step one, PPL Energy Supply identifies a potential impairment by comparing the estimated fair value of PPL Energy Supply (the goodwill reporting unit) with its carrying value, including goodwill, on the measurement date. If the estimated fair value exceeds its carrying value, goodwill is not considered impaired. If the carrying value exceeds the estimated fair value, the second step is performed to measure the amount of impairment loss, if any.
The second step requires a calculation of the implied fair value of goodwill, which is determined in the same manner as the amount of goodwill in a business combination. That is, the estimated fair value is allocated to all of PPL Energy Supply's assets and liabilities as if PPL Energy Supply had been acquired in a business combination and the estimated fair value of PPL Energy Supply was the price paid. The excess of the estimated fair value of PPL Energy Supply over the amounts assigned to its assets and liabilities is the implied fair value of goodwill. The implied fair value of PPL Energy Supply's goodwill is then compared with the carrying value of that goodwill. If the carrying value exceeds the implied fair value, an impairment loss is recognized in an amount equal to that excess. The loss recognized cannot exceed the carrying value of PPL Energy Supply's goodwill.
PPL Energy Supply tested goodwill for impairment in the fourth quarter of 2011 and no impairment was recognized. Management used both discounted cash flows and market multiples, which required significant assumptions, to estimate the fair value of PPL Energy Supply. Applying an appropriate weighting to both the discounted cash flow and market multiple valuations, a decrease in the forecasted cash flows of 10%, an increase in the discount rate by 25 basis points, or a 10% decrease in the multiples would not have resulted in an impairment of goodwill.
In 2010 and 2009, $5 million and $3 million of goodwill allocated to discontinued operations was written off.
4) Loss Accruals
Losses are accrued for the estimated impacts of various conditions, situations or circumstances involving uncertain or contingent future outcomes. For loss contingencies, the loss must be accrued if (1) information is available that indicates it is probable that a loss has been incurred, given the likelihood of the uncertain future events, and (2) the amount of the loss can be reasonably estimated. Accounting guidance defines "probable" as cases in which "the future event or events are likely to occur." The accrual of contingencies that might result in gains is not recorded unless recovery is assured. Potential loss contingencies for environmental remediation, litigation claims, regulatory penalties and other events are continuously assessed.
The accounting aspects of estimated loss accruals include (1) the initial identification and recording of the loss, (2) the determination of triggering events for reducing a recorded loss accrual, and (3) the ongoing assessment as to whether a recorded loss accrual is sufficient. All three of these aspects require significant judgment by management. Internal expertise and outside experts (such as lawyers and engineers) are used, as necessary, to help estimate the probability that a loss has been incurred and the amount (or range) of the loss.
No new significant loss accruals were recorded in 2011.
Certain other events have been identified that could give rise to a loss, but that do not meet the conditions for accrual. Such events are disclosed, but not recorded, when it is "reasonably possible" that a loss has been incurred. See Note 15 to the Financial Statements for disclosure of other potential loss contingencies that have not met the criteria for accrual.
When an estimated loss is accrued, the triggering events for subsequently reducing the loss accrual are identified, where applicable. The triggering events generally occur when the contingency has been resolved and the actual loss is paid or written off, or when the risk of loss has diminished or been eliminated. The following are some of the triggering events that provide for the reduction of certain recorded loss accruals:
·
Allowances for uncollectible accounts are reduced when accounts are written off after prescribed collection procedures have been exhausted, a better estimate of the allowance is determined or underlying amounts are ultimately collected.
·
Environmental and other litigation contingencies are reduced when the contingency is resolved and actual payments are made, a better estimate of the loss is determined or the loss is no longer considered probable.
Loss accruals are reviewed on a regular basis to assure that the recorded potential loss exposures are appropriate. This involves ongoing communication and analyses with internal and external legal counsel, engineers, operation management and other parties.
See Note 15 to the Financial Statements for a discussion of the Montana Hydroelectric Litigation, including the reversal of an $89 million loss accrual, as a result of management's assessment of the February 2012 U.S. Supreme Court decision.
5) Asset Retirement Obligations
PPL Energy Supply is required to recognize a liability for legal obligations associated with the retirement of long-lived assets. The initial obligation should be measured at its estimated fair value. A conditional ARO must be recognized when incurred if the fair value of the ARO can be reasonably estimated. An equivalent amount should be recorded as an increase in the value of the capitalized asset and allocated to expense over the useful life of the asset. Until the obligation is settled, the liability is increased, through the recognition of accretion expense in the income statement, for changes in the obligation due to the passage of time. See Note 21 to the Financial Statements for further discussion of AROs.
In determining AROs, management must make significant judgments and estimates to calculate fair value. Fair value is developed using an expected present value technique based on assumptions of market participants that considers estimated retirement costs in current period dollars that are inflated to the anticipated retirement date and then discounted back to the date the ARO was incurred. Changes in assumptions and estimates included within the calculations of the fair value of AROs could result in significantly different results than those identified and recorded in the financial statements. Estimated ARO costs and settlement dates, which affect the carrying value of the ARO and the related capitalized asset, are reviewed periodically to ensure that any material changes are incorporated into the latest estimate of the ARO. Any change to the capitalized asset, positive or negative, is amortized over the remaining life of the associated long-lived asset.
At December 31, 2011, AROs totaling $359 million were recorded on the Balance Sheet, of which $10 million is included in "Other current liabilities." Of the total amount, $292 million, or 81%, relates to the nuclear decommissioning ARO. The most significant assumptions surrounding AROs are the forecasted retirement costs, the discount rates and the inflation rates. A variance in any of these inputs could have a significant impact on the ARO liabilities.
The following table reflects the sensitivities related to the nuclear decommissioning ARO liability associated with a change in these assumptions as of December 31, 2011. There is no significant change to the annual depreciation expense of the ARO asset or the annual accretion expense of the ARO liability as a result of changing the assumptions. The sensitivities below reflect an evaluation of the change based solely on a change in that assumption.
6) Income Taxes
Significant management judgment is required in developing the provision for income taxes, primarily due to the uncertainty related to tax positions taken or expected to be taken in tax returns and the determination of deferred tax assets, liabilities and valuation allowances.
Significant management judgment is required to determine the amount of benefit recognized related to an uncertain tax position. Tax positions are evaluated following a two-step process. The first step requires an entity to determine whether, based on the technical merits supporting a particular tax position, it is more likely than not (greater than a 50% chance) that the tax position will be sustained. This determination assumes that the relevant taxing authority will examine the tax position and is aware of all the relevant facts surrounding the tax position. The second step requires an entity to recognize in the financial statements the benefit of a tax position that meets the more-likely-than-not recognition criterion. The benefit recognized is measured at the largest amount of benefit that has a likelihood of realization, upon settlement, that exceeds 50%. Management considers a number of factors in assessing the benefit to be recognized, including negotiation of a settlement.
On a quarterly basis, uncertain tax positions are reassessed by considering information known at the reporting date. Based on management's assessment of new information, a tax benefit may subsequently be recognized for a previously unrecognized tax position, a previously recognized tax position may be de-recognized, or the benefit of a previously recognized tax position may be remeasured. The amounts ultimately paid upon resolution of issues raised by taxing authorities may differ materially from the amounts accrued and may materially impact the financial statements in the future.
At December 31, 2011, it was reasonably possible that during the next 12 months the total amount of unrecognized tax benefits could increase by as much as $1 million or decrease by up to $27 million. This change could result from subsequent recognition, derecognition and/or changes in the measurement of uncertain tax positions related to the timing and utilization of tax credits and the related impact on alternative minimum tax, the timing and/or valuation of certain deductions, intercompany transactions and unitary filing groups. The events that could cause these changes are direct settlements with taxing authorities, litigation, legal or administrative guidance by relevant taxing authorities and the lapse of an applicable statute of limitation.
The balance sheet classification of unrecognized tax benefits and the need for valuation allowances to reduce deferred tax assets also require significant management judgment. Unrecognized tax benefits are classified as current to the extent management expects to settle an uncertain tax position by payment or receipt of cash within one year of the reporting date. Valuation allowances are initially recorded and reevaluated each reporting period by assessing the likelihood of the ultimate realization of a deferred tax asset. Management considers a number of factors in assessing the realization of a deferred tax asset, including the reversal of temporary differences, future taxable income and ongoing prudent and feasible tax planning strategies. Any tax planning strategy utilized in this assessment must meet the recognition and measurement criteria utilized to account for an uncertain tax position. Management also considers the uncertainty posed by political risk and the effect of this uncertainty on the various factors that management takes into account in evaluating the need for valuation allowances. The amount of deferred tax assets ultimately realized may differ materially from the estimates utilized in the computation of valuation allowances and may materially impact the financial statements in the future. See Note 5 to the Financial Statements for income tax disclosures.
Other Information
PPL's Audit Committee has approved the independent auditor to provide audit and audit-related services, tax services and other services permitted by Sarbanes-Oxley and SEC rules. The audit and audit-related services include services in connection with statutory and regulatory filings, reviews of offering documents and registration statements, and internal control reviews. See "Item 14. Principal Accounting Fees and Services" for more information.
PPL ELECTRIC UTILITIES CORPORATION AND SUBSIDIARIES
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
The information provided in this Item 7 should be read in conjunction with PPL Electric's Consolidated Financial Statements and the accompanying Notes. Capitalized terms and abbreviations are explained in the glossary. Dollars are in millions unless otherwise noted.
"Management's Discussion and Analysis of Financial Condition and Results of Operations" includes the following information:
·
"Overview" provides a description of PPL Electric and its business strategy. "Financial and Operational Developments" includes a review of Net Income Available to PPL Corporation and discusses certain events that are important to understanding PPL Electric's results of operations and financial condition.
·
"Results of Operations" provides a summary of PPL Electric's earnings and a description of key factors expected to impact future earnings. This section ends with "Statement of Income Analysis," which includes explanations of significant changes in principal items on PPL Electric's Statements of Income, comparing 2011, 2010 and 2009.
·
"Financial Condition - Liquidity and Capital Resources" provides an analysis of PPL Electric's liquidity position and credit profile. This section also includes a discussion of rating agency decisions and capital expenditure projections.
·
"Financial Condition - Risk Management" provides an explanation of PPL Electric's risk management programs relating to market and credit risk.
·
"Application of Critical Accounting Policies" provides an overview of the accounting policies that are particularly important to the results of operations and financial condition of PPL Electric and that require its management to make significant estimates, assumptions and other judgments of matters inherently uncertain.
Overview
Introduction
PPL Electric is an electricity delivery service provider in eastern and central Pennsylvania with headquarters in Allentown, Pennsylvania. PPL Electric is subject to regulation as a public utility by the PUC, and certain of its transmission activities are subject to the jurisdiction of FERC under the Federal Power Act. PPL Electric delivers electricity in its Pennsylvania service area and provides electricity supply to retail customers in that territory as a PLR under the Customer Choice Act.
Business Strategy
PPL Electric's strategy and principal challenge is to own and operate its electricity delivery business at the most efficient cost while maintaining high quality customer service and reliability. PPL Electric anticipates that it will have significant capital expenditure requirements in the future. In order to manage financing costs and access to credit markets, a key objective for PPL Electric's business is to maintain a strong credit profile. PPL Electric continually focuses on maintaining an appropriate capital structure and liquidity position.
Timely recovery of costs applicable to the replacement of aging distribution assets is required in order to maintain strong cash flows and a strong credit profile. Traditionally, such cost recovery would be pursued through periodic base rate case proceedings with the PUC. As such costs continue to increase, more frequent rate case proceedings may be required or an alternative rate making process would need to be implemented in order to achieve more timely recovery as discussed below in "Legislation - Regulatory Procedures and Mechanisms."
Transmission costs are recovered through a FERC Formula Rate mechanism which is updated annually for costs incurred and assets placed in service. Accordingly, increased costs including the replacement of aging transmission assets and the PJM-approved Regional Transmission Line Expansion Plan are recovered on a timely basis.
Financial and Operational Developments
Net Income Available to PPL Corporation
Net Income Available to PPL Corporation for 2011, 2010 and 2009 was $173 million, $115 million and $124 million. Earnings in 2011 increased 50% over 2010 and earnings in 2010 decreased 7% from 2009. These changes reflect the following after tax impacts:
See "Results of Operations" below for further discussion and analysis of the consolidated results of operations.
Storm Recovery
PPL Electric experienced several PUC-reportable storms during 2011 resulting in total restoration costs of $84 million, of which $54 million were recorded in "Other operation and maintenance" on the Statement of Income. Although PPL Electric has storm insurance with a PPL affiliate, the costs associated with the unusually high number of PUC-reportable storms has exceeded policy limits. Probable insurance recoveries recorded during 2011 were $26.5 million, of which $16 million were included in "Other operation and maintenance" on the Statement of Income. In December 2011, PPL Electric received orders from the PUC granting permission to defer qualifying storm costs in excess of insurance recoveries associated with Hurricane Irene and a late October snowstorm. Based on the PUC orders, PPL Electric recorded a regulatory asset of $25 million in December 2011. PPL Electric will seek recovery of these costs in its next general base rate proceeding.
PUC Investigation of Retail Market
In April 2011, the PUC opened an investigation of Pennsylvania's retail electricity market to be conducted in two phases. Phase one addressed the status of the current retail market and explored potential changes. Questions promulgated by the PUC for this phase of the investigation focus primarily on default service issues. In June 2011, interested parties filed comments and the PUC held a hearing in this phase of the investigation. In July 2011, the PUC entered an order initiating phase two of the investigation to study how best to address issues identified by the PUC as being most relevant to improving the current retail electricity market. The PUC issued a tentative order in October 2011 addressing issues associated with the timing and various other details of the EDCs' default service procurement plans. Parties filed comments to that tentative order. The PUC also held a hearing in this phase of the investigation in November 2011. In December 2011, the PUC issued a final order providing guidance to EDCs on the design of their next default service procurement plan filings. In December 2011, the PUC also issued a tentative order proposing an intermediate work plan to address issues raised in the investigation. Parties filed comments to that tentative order. PPL Electric cannot predict the outcome of the investigation.
Regional Transmission Line Expansion Plan
In 2007, PJM directed the construction of a new 150-mile, 500-kilovolt transmission line between the Susquehanna substation in Pennsylvania and the Roseland substation in New Jersey that it identified as essential to long-term reliability of the Mid-Atlantic electricity grid. PJM determined that the line is needed to prevent potential overloads that could occur on several existing transmission lines in the interconnected PJM system. PJM has directed PPL Electric to construct the portion of the Susquehanna-Roseland line in Pennsylvania and has directed Public Service Electric & Gas Company to construct the portion of the line in New Jersey, in each case by June 1, 2012. PPL Electric's estimated share of the project costs is approximately $500 million.
PPL Electric has experienced delays in obtaining necessary National Park Service approvals for the Susquehanna-Roseland transmission line and anticipates a delay of the line's in-service date to 2015. In 2011, PJM issued an updated assessment of the new line within its 2010 Regional Transmission Expansion Plan, which confirms that the line is needed to prevent overloads on other power lines in the region. PJM has developed a strategy to manage potential reliability problems until the line is built. In October 2011, the project was placed on the initial list of projects for the Rapid Response Team for Transmission (RRTT), an initiative of the White House to facilitate coordination among federal agencies to improve the overall quality and timeliness of electric transmission infrastructure permitting, review and consultation. The RRTT has reaffirmed the issuance date of the National Park Service record of decision for the project. The National Park Service has
stated that it will announce the preferred route for the transmission line in March 2012 with an expected Record of Decision in October 2012. PPL Electric cannot predict what additional actions, if any, PJM might take in the event of a continued delay to its scheduled in-service date for the new line. See Note 8 to the Financial Statements for additional information.
On December 30, 2011, PPL Electric filed a Petition for Declaratory Order requesting FERC to authorize incentive rates for a new 58-mile 230 kV transmission project referred to as the Northeast/Pocono Reliability Project. PPL Electric's request includes two incentives, a 100 basis point incentive adder to its return on equity of 11.68%, and inclusion of 100% prudently incurred construction work in progress costs in rate base with the incentive rate of return. These incentives are specifically tailored to address the risks and challenges PPL Electric will face in building the project. PPL Electric estimates the project costs to be approximately $180 million. In January 2012, the PUC and the Joint Consumer Advocates each filed a protest opposing PPL Electric's request. American Municipal Power, Inc. filed comments. PPL Electric filed responses to the two protests and the comments. PPL Electric cannot predict the outcome of this proceeding.
Legislation - Regulatory Procedures and Mechanisms
In June 2011, the Pennsylvania House Consumer Affairs Committee approved legislation that would authorize the PUC to approve regulatory procedures and mechanisms to provide for more timely recovery of a utility's costs. Such alternative ratemaking procedures and mechanisms are important to PPL Electric as it begins a period of significant increasing capital investment related to the asset optimization program focused on the replacement of aging distribution assets. Those procedures and mechanisms include, but are not limited to, the use of a fully projected future test year and an automatic adjustment clause to recover certain capital costs and related operating expenses. In October 2011, the legislation was passed by the Pennsylvania House of Representatives (Pennsylvania House). In January 2012, the Senate Consumer Affairs Committee adopted significant amendments to the legislation. The amended legislation authorizes the PUC to approve only two specific ratemaking mechanisms -- a fully projected future test year and a distribution system improvement charge. In addition, the amendments impose a number of conditions on the use of such a charge. In January 2012, the Pennsylvania Senate passed the amended legislation and in February 2012, the Pennsylvania House agreed to those amendments. The Governor signed the bill (Act 11 of 2012), which will become effective April 14, 2012. Utilities cannot file a petition with the PUC before January 1, 2013 requesting permission to establish the charge.
FERC Formula Rates
In March 2012, PPL Electric plans to file a request with the FERC seeking recovery, over a 34-year period beginning in June 2012, of its unrecovered regulatory asset related to the deferred state tax liability that existed at the time of the transition from the flow-through treatment of state income taxes to full normalization. This change in tax treatment occurred in 2008 as a result of prior FERC initiatives that transferred regulatory jurisdiction of certain transmission assets from the PUC to the FERC. A regulatory asset of $51 million related to this transition, classified as taxes recoverable through future rates, is included in "Other Noncurrent Assets - Regulatory assets" on the Balance Sheet. PPL Electric believes recoverability of this regulatory asset is probable based on FERC precedent in similar cases; however, it is reasonably possible that the FERC may limit the recovery of all or part of the claimed asset.
Results of Operations
When comparing 2011 and 2010 with 2009, certain line items on PPL Electric's financial statements were impacted by the Customer Choice Act, Act 129 and other related issues. The expiration of generation rate caps, the resulting competitive solicitations for power supply, the migration of customers to alternative suppliers, the Customer Choice Act and Act 129 had minimal impact on Pennsylvania Gross Delivery Margins, as approved recovery mechanisms allow for cost recovery of associated expenses, including the cost of energy provided as a PLR. However, PPL Electric's 2010 Pennsylvania Gross Delivery Margins were negatively impacted by the expiration of CTC recovery in December 2009. PPL Electric continues to remain the delivery provider for all customers in its service territory and charges a regulated rate for the service of delivering electricity.
See "Statement of Income Analysis - Pennsylvania Gross Delivery Margins" for additional information.
The changes in the components of Net Income Available to PPL Corporation between these periods were due to the following factors. PPL Electric's results are adjusted for certain items that management considers special. See additional detail of these special items in the table below.
·
See "Statement of Income Analysis - Margins - Changes in Non-GAAP Financial Measures" for an explanation of Pennsylvania Gross Delivery Margins.
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Other operation and maintenance increased in 2010 compared with 2009, primarily due to $18 million in higher payroll-related costs and $20 million in higher contractor costs, primarily related to vegetation management.
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Depreciation was higher in 2011 compared with 2010 and 2010 compared with 2009, primarily due to PP&E additions as a part of ongoing efforts to replace aging infrastructure.
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Interest expense decreased in 2010 compared with 2009, primarily due to a $16 million reduction driven by lower average debt balances in 2010 compared with 2009.
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Income taxes were higher in 2011 compared with 2010, due to the $26 million impact of higher pre-tax income, partially offset by a $14 million tax benefit related to the impact of flow-through regulated tax depreciation that is primarily related to the Pennsylvania Department of Revenue interpretive guidance regarding 100% bonus depreciation.
Income taxes were lower in 2010 compared with 2009, due to the $14 million impact of lower pre-tax income and a $7 million tax benefit relating to a favorable 2010 U.S. Tax Court ruling regarding street lighting assets.
The following after-tax amounts, which management considers special items, also impacted the results.
(a)
Charge related to a workforce reduction, mainly consisting of enhanced pension and severance benefits.
(b)
During 2009, PPL Electric received consent from the IRS to change its method of accounting for certain expenditures for tax purposes. PPL Electric deducted the resulting IRC Sec. 481 amount on its 2008 federal income tax return and recorded a $3 million adjustment to federal and state income tax expense resulting from the reversal of prior years' state income tax benefits related to regulated depreciation.
2012 Outlook
Excluding special items, PPL Electric projects lower earnings in 2012 compared with 2011, primarily driven by higher operation and maintenance expenses, higher income taxes, and higher depreciation, which are expected to be partially offset by higher delivery revenue.
In late March 2012, PPL Electric expects to file a request with the PUC seeking an increase in its distribution rates beginning in January 2013. PPL Electric cannot predict the outcome of this matter.
Earnings beyond 2011 are subject to various risks and uncertainties. See "Forward-Looking Information," "Item 1. Business," "Item 1A. Risk Factors," the rest of this Item 7 and Notes 6 and 15 to the Financial Statements for a discussion of the risks, uncertainties and factors that may impact future earnings.
Statement of Income Analysis --
Pennsylvania Gross Delivery Margins
Non-GAAP Financial Measure
The following discussion includes financial information prepared in accordance with GAAP, as well as a non-GAAP financial measure, "Pennsylvania Gross Delivery Margins." "Pennsylvania Gross Delivery Margins" is a single financial performance measure of PPL Electric's Pennsylvania regulated electric delivery operations, which includes transmission and distribution activities. In calculating this measure, utility revenues and expenses associated with approved recovery mechanisms, including energy provided as a PLR, are offset with minimal impact on earnings. Costs associated with these mechanisms are recorded in "Energy purchases," "Energy purchases from affiliate," "Other operation and maintenance" expense, which is primarily Act 129 costs, and "Taxes, other than income", which is primarily gross receipts tax. As a result, this measure represents the net revenues from PPL Electric's Pennsylvania regulated electric delivery operations. This measure is not intended to replace "Operating Income," which is determined in accordance with GAAP, as an indicator of overall operating performance. Other companies may use different measures to analyze and to report on the results of their operations. PPL Electric believes that "Pennsylvania Gross Delivery Margins" provides another criterion to make investment decisions. This performance measure is used, in conjunction with other information, internally by senior management and PPL's Board of Directors to manage PPL Electric's operations and analyze actual results to budget.
Reconciliation of Non-GAAP Financial Measures
The following tables reconcile "Operating Income" to "Pennsylvania Gross Delivery Margins" as defined by PPL Electric for the period ended December 31.
(a)
Represents amounts that are excluded from Margins.
(b)
As reported on the Statement of Income.
Changes in Non-GAAP Financial Measures
The following table shows PPL Electric's non-GAAP financial measure, "Pennsylvania Gross Delivery Margins" for the periods ended December 31, as well as the change between periods. The factors that gave rise to the change are described below the table.
Distribution
The PPL Electric distribution rate case increased rates by approximately 1.6% effective January 1, 2011, which improved residential distribution margins by $68 million. Residential volume variances increased margins by an additional $4 million for 2011, compared with the same period in 2010. Weather had a $3 million unfavorable impact for residential customers for 2011 compared with 2010. Weather-related variances for PPL Electric are calculated based on a ten-year historical average. Lastly, lower demand charges and increased efficiency as a result of Act 129 programs resulted in a $5 million decrease in margins for commercial and industrial customers.
The decrease in 2010 compared with 2009 was primarily due to margins realized in 2009 related to the collection of CTC that ended in December 2009 of $37 million, partially offset by favorable recovery mechanisms for certain energy-related costs of $16 million.
Transmission
The increase in 2010 compared with 2009 was primarily due to increased investment in rate base, an increase in the cost of capital due to an increase in equity and the recovery of additional costs through the FERC formula-based rates.
Other Operation and Maintenance
The changes in other operation and maintenance expenses were due to:
(a)
Relates to costs associated with a PUC-approved energy efficiency and conservation plan. These costs are recovered in customer rates. There are currently 15 Act 129 programs which began in 2010 and continued to ramp up in 2011.
(b)
In 2010, PPL Electric increased its vegetation management around its 230- and 500-kV major transmission lines in response to federal reliability requirements for transmission vegetation management.
(c)
Prior to 2010, these charges were assessed to load serving entities (LSE), and PPL Electric was considered the LSE. Beginning in 2010, PPL Electric incurred the bulk of these charges as part of the bundled price of PLR supply from the individual PLR generation suppliers and such costs are reflected in energy purchases.
Taxes, Other Than Income
Taxes, other than income decreased by $34 million in 2011 compared with 2010. This decrease was primarily due to $21 million of lower Pennsylvania gross receipts tax expense due to a decrease in retail electricity revenue as customers continue to select alternative suppliers in 2011. The decrease was also impacted by the amortization of a PURTA refund of $10 million in 2011. Pennsylvania gross receipts tax and the PURTA refund are included in "Pennsylvania Gross Delivery Margins."
Taxes, other than income decreased by $56 million in 2010 compared with 2009. The decrease was primarily due to lower Pennsylvania gross receipts tax expense due to a decrease in electricity revenue as customers chose alternate suppliers in 2010.
Depreciation
Depreciation increased by $10 million in 2011 compared with 2010, primarily due to PP&E additions as part of ongoing efforts to replace aging infrastructure. Depreciation increased by $8 million in 2010 compared with 2009, primarily due to PP&E additions.
Financing Costs
The changes in financing costs, which includes "Interest Expense", "Interest Expense with Affiliate" and "Distributions on Preferred Securities," were due to:
(a)
The decrease in 2011 compared with 2010 was due to the net impact of refinancing $400 million of long-term debt at lower interest rates and issuing $250 million of long-term debt in the third quarter of 2011. The decrease in 2010 compared with 2009 was primarily due to long-term debt retirements in the third quarter of 2009.
(b)
The decrease in 2011 compared with 2010 was primarily due to preferred stock redemption in 2010.
(c)
The increase in 2011 compared with 2010 was primarily due to amortization of loss on reacquired debt associated with the redemption of senior secured bonds in 2011.
Income Taxes
The changes in income taxes were due to:
(a)
In July 2010, the U.S. Tax Court ruled in PPL Electric's favor in a dispute with the IRS, concluding that street lighting assets are depreciable for tax purposes over seven years. As a result, PPL Electric recorded a $7 million tax benefit to federal and state income tax reserves and related deferred income taxes during 2010.
During 2011, 2010 and 2009 PPL Electric recorded a $6 million, $7 million and $6 million tax benefit to federal and state income tax reserves related to stranded cost securitization.
(b)
During 2009, PPL Electric received consent from the IRS to change its method of accounting for certain expenditures for tax purposes. PPL Electric deducted the resulting IRC Sec. 481 amount on its 2008 federal income tax return and recorded a $3 million adjustment to federal and state income tax expense resulting from the reversal of prior years' state income tax benefits related to regulated depreciation.
(c)
In February 2011, the Pennsylvania Department of Revenue issued interpretive guidance on the treatment of bonus depreciation for Pennsylvania income tax purposes. In accordance with Corporation Tax Bulletin 2011-01, Pennsylvania allows 100% bonus depreciation for qualifying assets in the same year bonus depreciation is allowed for Federal income tax purposes. The 100% Pennsylvania bonus depreciation deduction created a current state income tax benefit for the flow-through impact of Pennsylvania regulated state tax depreciation.
See Note 5 to the Financial Statements for additional information on income taxes.
Financial Condition
Liquidity and Capital Resources
PPL Electric continues to focus on maintaining a strong credit profile and liquidity position. PPL Electric expects to continue to have adequate liquidity available through operating cash flows, cash and cash equivalents and its credit facilities.
PPL Electric's cash flows from operations and access to cost-effective bank and capital markets are subject to risks and uncertainties including, but not limited to:
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unusual or extreme weather that may damage PPL Electric's transmission and distribution facilities or affect energy sales to customers;
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the ability to recover and the timeliness and adequacy of recovery of costs associated with regulated utility businesses;
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any adverse outcome of legal proceedings and investigations with respect to PPL Electric's current and past business activities;
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deterioration in the financial markets that could make obtaining new sources of bank and capital markets funding more difficult and more costly; and
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a downgrade in PPL Electric's credit ratings that could adversely affect its ability to access capital and increase the cost of credit facilities and any new debt.
See "Item 1A. Risk Factors" for further discussion of risks and uncertainties affecting PPL Electric's cash flows.
At December 31, PPL Electric had the following:
The changes in PPL Electric's cash and cash equivalents position resulted from:
Operating Activities
Net cash provided by operating activities increased by 98%, or $208 million, in 2011 compared with 2010, primarily due to changes in working capital of $322 million (including lower gross receipts tax payments, a federal income tax refund and changes in over/under collections of the generation supply and transmission service charges). These changes were partially offset by an increase in defined benefit plan contributions of $58 million and $25 million related to storm costs incurred in 2011that has been recorded as a long-term regulatory asset.
Net cash provided by operating activities decreased by 28%, or $82 million, in 2010 compared with 2009. The expiration of the generation rate caps at the end of 2009 had little impact on net income, while increased transmission revenue was almost completely offset by decreased distribution revenue. However, higher tree trimming and payroll costs and additional defined benefit plan contributions were the primary drivers to the decrease in cash provided by operating activities. Also impacting the 2010 operating cash flows was the elimination of the CTC charge of approximately $300 million that was received in 2009. This amount offsets the benefit of not paying the $300 million in cash collateral related to the long-term PLR energy supply agreements with PPL Energy Supply, which expired at the end of 2009.
Investing Activities
The primary use of cash in investing activities is capital expenditures. See "Forecasted Uses of Cash" for detail regarding projected capital expenditures for the years 2012 through 2016.
Net cash used in investing activities was $477 million in 2011 compared with to $403 million in 2010. The change from 2010 to 2011 primarily reflects an increase of $80 million in capital expenditures in 2011.
Net cash used in investing activities was $403 million in 2010 compared with cash provided by investing activities of $6 million in 2009. The change from 2009 to 2010 primarily reflects an increase of $113 million in capital expenditures in 2010 and the receipt of $300 million from an affiliate as repayment of a demand loan in 2009.
Financing Activities
Net cash provided by financing activities was $173 million in 2011 compared with net cash used in financing activities of $90 million in 2010. The change from 2010 to 2011 primarily reflects $187 million of net debt issuances in 2011 and $54 million of preferred stock redemptions in 2010.
Net cash used in financing activities was $90 million in 2010 compared with $298 million in 2009. The change from 2009 to 2010 primarily reflects no debt activity in 2010 compared with net debt retirements of $392 million in 2009, partially offset by lower net contributions from PPL of $142 million in 2010 and $54 million of preferred stock redemptions in 2010.
See "Forecasted Sources of Cash" for a discussion of PPL Electric's plans to issue debt and equity securities, as well as a discussion of credit facility capacity available to PPL Electric. Also see "Forecasted Uses of Cash" for a discussion of PPL Electric's plans to pay dividends on its common and preferred securities, as well as maturities of PPL Electric's long-term debt.
Forecasted Sources of Cash
PPL Electric expects to continue to have sufficient sources of cash available in the near term, including various credit facilities and a commercial paper program.
Credit Facilities
At December 31, 2011, PPL Electric's total committed borrowing capacity under its credit facilities and the use of this borrowing capacity were:
(a)
In October 2011, PPL Electric amended its Syndicated Credit Facility. The amendment included extending the expiration date from December 2014 to October 2016. Under this facility, PPL Electric continues to have the ability to make cash borrowings and to request the lenders to issue letters of
credit. The commitments under this credit facility are provided by a diverse bank group, with no one bank and its affiliates providing an aggregate commitment of more than 6% of the total committed capacity.
PPL Electric's Syndicated Credit Facility contains a financial covenant requiring PPL Electric's debt to total capitalization not to exceed 70%, as calculated in accordance with the credit facility, and other customary covenants.
(b)
PPL Electric obtains financing by selling and contributing its eligible accounts receivable and unbilled revenue to a special purpose, wholly owned subsidiary on an ongoing basis. The subsidiary pledges these assets to secure loans of up to an aggregate of $150 million from a commercial paper conduit sponsored by a financial institution. At December 31, 2011, based on accounts receivable and unbilled revenue pledged, the amount available for borrowing under this facility was limited to $103 million. In July 2011, PPL Electric and the subsidiary extended the expiration date of the credit agreement related to the asset-backed commercial paper program to July 2012.
In addition to the financial covenants noted above, the credit agreements governing the credit facilities contain financial and various other covenants. Failure to comply with the covenants after applicable grace periods could result in acceleration of repayment of borrowings and/or termination of the agreements. PPL Electric monitors compliance with the covenants on a regular basis. At December 31, 2011, PPL Electric was in compliance with these covenants. At this time, PPL Electric believes that these covenants and other borrowing conditions will not limit access to these funding sources.
See Note 7 to the Financial Statements for further discussion of PPL Electric's credit facilities.
Commercial Paper
PPL Electric maintains a commercial paper program for up to $200 million to provide an additional financing source to fund its short-term liquidity needs, if and when necessary. Commercial paper issuances are currently supported by PPL Electric's $200 million syndicated credit facility, which expires in October 2016, based on available capacity.
PPL Electric did not issue any commercial paper during 2011. Based on its current cash position and anticipated cash flows, PPL Electric currently does not plan to issue any commercial paper during 2012, but it may do so from time to time, subject to market conditions, to facilitate short-term cash flow needs.
Contributions from PPL
From time to time PPL may make capital contributions to PPL Electric. PPL Electric may use these contributions for general corporate purposes.
Long-term Debt and Equity Securities
PPL Electric currently does not plan to issue long-term debt securities in 2012.
The Economic Stimulus Package
In April 2010, PPL Electric entered into an agreement with the DOE, in which the agency is to provide funding for one-half of a $38 million smart grid project. The project will use smart grid technology to strengthen reliability, save energy and improve electric service for 60,000 Harrisburg, Pennsylvania area customers. It will also provide benefits beyond the Harrisburg region, helping to speed power restoration across PPL Electric's 29-county service territory. Work on the project is progressing on schedule, and PPL Electric is receiving reimbursements under the grant for costs incurred. The project is scheduled to be completed by the end of September 2012.
Forecasted Uses of Cash
In addition to expenditures required for normal operating activities, such as purchased power, payroll, and taxes, PPL Electric currently expects to incur future cash outflows for capital expenditures, various contractual obligations, payment of dividends on its common and preferred securities and possibly the purchase or redemption of a portion of its debt securities.
Capital Expenditures
The table below shows PPL Electric's current capital expenditure projections for the years 2012 through 2016.
(a)
Construction expenditures include AFUDC, which is expected to be approximately $52 million for the years 2012 through 2016.
(b)
Includes expenditures for intangible assets.
PPL Electric's capital expenditure projections for the years 2012 through 2016 total approximately $3.6 billion. Capital expenditure plans are revised periodically to reflect changes in operational, market and regulatory conditions. The table includes projected costs for the asset optimization program focused on the replacement of aging transmission and distribution assets, and the PJM-approved regional transmission line expansion project. See Note 8 to the Financial Statements for additional information.
PPL Electric plans to fund its capital expenditures in 2012 with cash on hand, cash from operations and equity contributions from PPL.
Contractual Obligations
PPL Electric has assumed various financial obligations and commitments in the ordinary course of conducting its business. At December 31, 2011, the estimated contractual cash obligations of PPL Electric were:
(a)
Reflects principal maturities only based on stated maturity dates. PPL Electric does not have any capital or operating lease obligations.
(b)
Assumes interest payments through stated maturity.
(c)
The amounts include agreements to purchase goods or services that are enforceable and legally binding and specify all significant terms, including: fixed or minimum quantities to be purchased; fixed, minimum or variable price provisions; and the approximate timing of the transaction. Primarily includes PPL Electric's purchase obligations of electricity. Open purchase orders that are provided on demand with no firm commitment are excluded from the amounts presented. In prior years, PPL Electric included certain electricity purchase obligations based on forecasted amounts to be purchased. The amounts presented herein are based on actual contract terms.
(d)
The amounts represent contributions made or committed to be made for 2012 for PPL's U.S. pension plans. See Note 13 to the Financial Statements for a discussion of expected contributions.
(e)
At December 31, 2011, total unrecognized tax benefits of $73 million were excluded from this table as PPL Electric cannot reasonably estimate the amount and period of future payments. See Note 5 to the Financial Statements for additional information.
Dividends
From time to time, as determined by its Board of Directors, PPL Electric pays dividends on its common stock to its parent, PPL.
As discussed in Note 7 to the Financial Statements, PPL Electric may not pay dividends on its common stock, except in certain circumstances, unless full dividends have been paid on the 6.25% Series Preference Stock for the then-current dividend period. PPL Electric does not, at this time, expect that such limitation would significantly impact its ability to declare dividends.
PPL Electric expects to continue to pay quarterly dividends on its outstanding preference securities, as declared by its Board of Directors.
Purchase or Redemption of Debt Securities
PPL Electric will continue to evaluate its outstanding debt securities and may decide to purchase or redeem these securities depending upon prevailing market conditions and available cash.
Rating Agency Decisions
Moody's, S&P and Fitch periodically review the credit ratings on the debt and preferred securities of PPL Electric. Based on their respective independent reviews, the rating agencies may make certain ratings revisions or ratings affirmations.
A credit rating reflects an assessment by the rating agency of the creditworthiness associated with an issuer and particular securities that it issues. The credit ratings of PPL Electric are based on information provided by PPL Electric and other sources. The ratings of Moody's, S&P and Fitch are not a recommendation to buy, sell or hold any securities of PPL Electric.
Such ratings may be subject to revisions or withdrawal by the agencies at any time and should be evaluated independently of each other and any other rating that may be assigned to the securities. A downgrade in PPL Electric's credit ratings could result in higher borrowing costs and reduced access to capital markets.
As a result of the passage of the Dodd-Frank Act, PPL Electric is limiting its credit rating disclosure to a description of the actions taken by the rating agencies with respect to PPL Electric's ratings, but without stating what ratings have been assigned to PPL Electric or its securities. The ratings assigned by the rating agencies to PPL Electric and its respective securities may be found, without charge, on each of the respective ratings agencies' websites, which ratings together with all other information contained on such rating agency websites is, hereby, explicitly not incorporated by reference in this report.
The rating agencies took the following actions related to PPL Electric in 2011.
Following the announcement of the then-pending acquisition of WPD Midlands in March 2011, the rating agencies took the following actions:
·
Moody's affirmed its ratings for PPL Electric;
·
S&P revised the outlook and lowered the issuer, senior secured, preference stock and commercial paper ratings of PPL Electric; and
·
Fitch affirmed its ratings for PPL Electric.
In April 2011, following the completion of PPL's acquisition of WPD Midlands, S&P revised the outlook for PPL Electric, raised its commercial paper rating and affirmed its issuer, senior secured and preference stock ratings.
In July 2011, S&P upgraded the senior secured rating for PPL Electric's first mortgage bonds following the execution of a supplemental indenture that provided for prospective amendments to PPL Electric's 2001 Mortgage Indenture, as discussed in "Long-term Debt Securities" above.
In December 2011, Fitch affirmed the Issuer Default Ratings and individual security ratings of PPL Electric.
Off-Balance Sheet Arrangements
PPL Electric has entered into certain agreements that may contingently require payment to a guaranteed or indemnified party. See Note 15 to the Financial Statements for a discussion of these agreements.
Risk Management
Market Risk
Commodity Price and Volumetric Risk - PLR Contracts
PPL Electric is exposed to market price and volumetric risks from its obligation as PLR. The PUC has approved a cost recovery mechanism that allows PPL Electric to pass through to customers the cost associated with fulfilling its PLR obligation. This cost recovery mechanism substantially eliminates PPL Electric's exposure to market price risk. PPL Electric also mitigates its exposure to volumetric risk by entering into full-requirement energy supply contracts for the majority of its PLR obligations. These supply contracts transfer the volumetric risk associated with the PLR obligation to the energy suppliers.
Interest Rate Risk
PPL Electric has issued debt to finance its operations, which exposes it to interest rate risk. PPL Electric had no potential annual exposure to increased interest expense, based on a 10% increase in interest rates, at December 31, 2011 and 2010. PPL Electric estimated that a 10% decrease in interest rates at December 31, 2011 would increase the fair value of its debt portfolio by $94 million, compared with $66 million at December 31, 2010.
Credit Risk
Credit risk is the risk that PPL Electric would incur a loss as a result of nonperformance by counterparties of their contractual obligations. PPL Electric requires that counterparties maintain specified credit ratings and requires other assurances in the form of credit support or collateral in certain circumstances in order to limit counterparty credit risk. However, PPL Electric has concentrations of suppliers, financial institutions and customers. These concentrations may impact PPL Electric's overall
exposure to credit risk, positively or negatively, as counterparties may be similarly affected by changes in economic, regulatory or other conditions.
In 2009, the PUC approved PPL Electric's PLR procurement plan for the period January 2011 through May 2013. To date, PPL Electric has conducted ten of its 14 planned competitive solicitations.
Under the standard Supply Master Agreement (the Agreement) for the competitive solicitation process, PPL Electric requires all suppliers to post collateral if their credit exposure exceeds an established credit limit. In the event a supplier defaults on its obligation, PPL Electric would be required to seek replacement power in the market. All incremental costs incurred by PPL Electric would be recoverable from customers in future rates. At December 31, 2011, substantially all of the successful bidders under all of the solicitations had an investment grade credit rating from S&P, and were not required to post collateral under the Agreement. There is no instance under the Agreement in which PPL Electric is required to post collateral to its suppliers.
See "Overview" in this Item 7 and Notes 15, 16, 18 and 19 to the Financial Statements for additional information on the competitive solicitations, the Agreement, credit concentration and credit risk.
Related Party Transactions
PPL Electric is not aware of any material ownership interests or operating responsibility by senior management of PPL Electric in outside partnerships, including leasing transactions with variable interest entities, or other entities doing business with PPL Electric. See Note 16 to the Financial Statements for additional information on related party transactions.
Environmental Matters
Protection of the environment is a priority for PPL Electric and a significant element of its business activities. See "Item 1. Business - Environmental Matters" and Note 15 to the Financial Statements for a discussion of environmental matters.
Competition
See "Item 1. Business - Segment Information - Pennsylvania Regulated Segment - Competition" for a discussion of competitive factors affecting PPL Electric.
New Accounting Guidance
See Notes 1 and 24 to the Financial Statements for a discussion of new accounting guidance adopted and pending adoption.
Application of Critical Accounting Policies
Financial condition and results of operations are impacted by the methods, assumptions and estimates used in the application of critical accounting policies. The following accounting policies are particularly important to the financial condition or results of operations, and require estimates or other judgments of matters inherently uncertain. Changes in the estimates or other judgments included within these accounting policies could result in a significant change to the information presented in the Financial Statements (these accounting policies are also discussed in Note 1 to the Financial Statements). PPL's senior management has reviewed these critical accounting policies, the following disclosures regarding their application and the estimates and assumptions regarding them, with PPL's Audit Committee.
1) Defined Benefits
PPL Electric participates in a qualified funded defined benefit pension plan, an unfunded non-qualified defined benefit plan and a funded defined benefit other postretirement benefit plan, sponsored by other PPL subsidiaries and administered through PPL Services. PPL Electric is allocated a significant portion of the liability and net periodic defined benefit pension and other postretirement costs of the plans sponsored by other PPL subsidiaries based on participation in those plans. PPL Electric records an asset or liability to recognize the funded status of all defined benefit plans with an offsetting entry to regulatory assets. Consequently, the funded status of all defined benefit plans is fully recognized on the Balance Sheets. See Note 13 to the Financial Statements for additional information about the plans and the accounting for defined benefits.
PPL Services makes certain assumptions regarding the valuation of benefit obligations and the performance of plan assets. When accounting for defined benefits, delayed recognition in earnings of differences between actual results and expected or estimated results is a guiding principle. Annual net periodic defined benefit costs are recorded in current earnings based on estimated results. Any differences between actual and estimated results are recorded in regulatory assets. The amount in
regulatory assets is amortized to income over future periods. The delayed recognition allows for a smoothed recognition of costs over the working lives of the employees who benefit under the plans. The primary assumptions are:
·
Discount Rate - The discount rate is used in calculating the present value of benefits, which is based on projections of benefit payments to be made in the future. The objective in selecting the discount rate is to measure the single amount that, if invested at the measurement date in a portfolio of high-quality debt instruments, would provide the necessary future cash flows to pay the accumulated benefits when due.
·
Expected Return on Plan Assets - Management projects the long-term rates of return on plan assets based on historical performance, future expectations and periodic portfolio rebalancing among the diversified asset classes. These projected returns reduce the net benefit costs PPL records currently.
·
Rate of Compensation Increase - Management projects employees' annual pay increases, which are used to project employees' pension benefits at retirement.
·
Health Care Cost Trend Rate - Management projects the expected increases in the cost of health care.
In selecting a discount rate for its defined benefit plans, PPL Services starts with a cash flow analysis of the expected benefit payment stream for its plans. For 2010, these plan-specific cash flows were matched against a spot-rate yield curve to determine the assumed discount rate. To develop the spot-rate yield curve, the full universe of Aa-rated non-callable (or callable with make-whole provisions) bonds, served as the base from which those with the lowest and highest yields were eliminated to develop an appropriate subset of bonds from which the ultimate yield curve would be built. At that time, Management believed this plan-specific cash flow matching model represented the best available tool for estimating the discount rate. Beginning in 2011, PPL Services utilized a new tool that enhanced this plan-specific cash flow matching methodology by primarily matching the plan-specific cash flows against the coupons and expected maturity values of individually selected bonds. This bond matching process begins with the same subset of the universe of Aa-rated corporate bonds from which those with the lowest and highest yields were eliminated, similar to the yield curve approach. Individual bonds were then selected based on the timing of each plan's cash flows and parameters were established as to the percentage of each individual bond issue that could be hypothetically purchased and the surplus reinvestment rates to be assumed. This process more accurately approximated the process of settlement of the obligations, which better aligns with the objective of selecting the discount rate. At December 31, 2011, PPL Services decreased the discount rate for its U.S. pension plans from 5.41% to 5.07% and decreased the discount rate for its other postretirement benefit plans from 5.16% to 4.81%.
The expected long-term rates of return for PPL Services' U.S. defined benefit pension and other postretirement benefits have been developed using a best-estimate of expected returns, volatilities and correlations for each asset class. PPL management corroborates these rates with expected long-term rates of return calculated by its independent actuary, who uses a building block approach that begins with a risk-free rate of return with factors being added such as inflation, duration, credit spreads and equity risk. Each plan's specific asset allocation is also considered in developing a reasonable return assumption. Based on PPL's change to a liability-driven investment strategy, PPL's U.S. defined benefit pension assets have shifted into a greater proportion of fixed-income investments. Based on this change in investment strategy, at December 31, 2011, PPL Services' expected return on plan assets decreased from 7.25% to 7.00% for its U.S. pension plan and decreased from 6.45% to 5.70% for its other postretirement benefit plan.
In selecting a rate of compensation increase, PPL Services considers past experience in light of movements in inflation rates. At December 31, 2011, PPL Services' rate of compensation increase decreased from 4.75% to 4.00% for its U.S. plan.
In selecting health care cost trend rates for PPL Services' other postretirement benefit plans, PPL Services considers past performance and forecasts of health care costs. At December 31, 2011, PPL Services' health care cost trend rates were 8.50% for 2012, gradually declining to 5.50% for 2019.
A variance in the assumptions listed above could have a significant impact on the accrued defined benefit liabilities or assets, reported annual net periodic defined benefit costs and the regulatory assets allocated to PPL Electric. While the charts below reflect either an increase or decrease in each assumption, the inverse of this change would impact the accrued defined benefit liabilities or assets, reported annual net periodic defined benefit costs and regulatory assets by a similar amount in the opposite direction. The sensitivities below reflect an evaluation of the change based solely on a change in that assumption and does not include income tax effects.
At December 31, 2011, the defined benefit plans were recorded as follows.
The following chart reflects the sensitivities in the December 31, 2011 Balance Sheet associated with a change in certain assumptions based on PPL Services' primary defined benefit plans.
(a)
Only impacts other postretirement benefits.
In 2011, PPL Electric was allocated net periodic defined benefit costs charged to operating expense of $17 million. This amount represents a $3 million decrease compared with the charge recognized during 2010.
The following chart reflects the sensitivities in the 2011 Statement of Income (excluding income tax effects) associated with a change in certain assumptions based on PPL Services' primary defined benefit plans.
2) Loss Accruals
Losses are accrued for the estimated impacts of various conditions, situations or circumstances involving uncertain or contingent future outcomes. For loss contingencies, the loss must be accrued if (1) information is available that indicates it is probable that a loss has been incurred, given the likelihood of the uncertain future events, and (2) the amount of the loss can be reasonably estimated. Accounting guidance defines "probable" as cases in which "the future event or events are likely to occur." The accrual of contingencies that might result in gains is not recorded unless recovery is assured. Potential loss contingencies for environmental remediation, litigation claims, regulatory penalties and other events are continuously assessed.
The accounting aspects of estimated loss accruals include (1) the initial identification and recording of the loss, (2) the determination of triggering events for reducing a recorded loss accrual, and (3) the ongoing assessment as to whether a recorded loss accrual is sufficient. All three of these aspects require significant judgment by management. Internal expertise and outside experts (such as lawyers and engineers) are used, as necessary, to help estimate the probability that a loss has been incurred and the amount (or range) of the loss.
No new significant loss accruals were recorded in 2011.
Certain other events have been identified that could give rise to a loss, but that do not meet the conditions for accrual. Such events are disclosed, but not recorded, when it is "reasonably possible" that a loss has been incurred. See Note 15 to the Financial Statements for disclosure of other potential loss contingencies that have not met the criteria for accrual.
When an estimated loss is accrued, the triggering events for subsequently reducing the loss accrual are identified, where applicable. The triggering events generally occur when the contingency has been resolved and the actual loss is paid or written off, or when the risk of loss has diminished or been eliminated. The following are some of the triggering events that provide for the reduction of certain recorded loss accruals:
·
Allowances for uncollectible accounts are reduced when accounts are written off after prescribed collection procedures have been exhausted, a better estimate of the allowance is determined or underlying amounts are ultimately collected.
·
Environmental and other litigation contingencies are reduced when the contingency is resolved and actual payments are made, a better estimate of the loss is determined or the loss is no longer considered probable.
Loss accruals are reviewed on a regular basis to assure that the recorded potential loss exposures are appropriate. This involves ongoing communication and analyses with internal and external legal counsel, engineers, operation management and other parties.
3) Income Taxes
Significant management judgment is required in developing the provision for income taxes, primarily due to the uncertainty related to tax positions taken or expected to be taken in tax returns and the determination of deferred tax assets, liabilities and valuation allowances.
Significant management judgment is required to determine the amount of benefit recognized related to an uncertain tax position. Tax positions are evaluated following a two-step process. The first step requires an entity to determine whether, based on the technical merits supporting a particular tax position, it is more likely than not (greater than a 50% chance) that the tax position will be sustained. This determination assumes that the relevant taxing authority will examine the tax position and is aware of all the relevant facts surrounding the tax position. The second step requires an entity to recognize in the financial statements the benefit of a tax position that meets the more-likely-than-not recognition criterion. The benefit recognized is measured at the largest amount of benefit that has a likelihood of realization, upon settlement, that exceeds 50%. Management considers a number of factors in assessing the benefit to be recognized, including negotiation of a settlement.
On a quarterly basis, uncertain tax positions are reassessed by considering information known at the reporting date. Based on management's assessment of new information, a tax benefit may subsequently be recognized for a previously unrecognized tax position, a previously recognized tax position may be de-recognized, or the benefit of a previously recognized tax position may be remeasured. The amounts ultimately paid upon resolution of issues raised by taxing authorities may differ materially from the amounts accrued and may materially impact the financial statements in the future.
At December 31, 2011, it was reasonably possible that during the next 12 months the total amount of unrecognized tax benefits could increase by as much as $48 million or decrease by up to $63 million. This change could result from the timing and/or valuation of certain deductions, intercompany transactions and unitary filing groups. The events that could cause these changes are direct settlements with taxing authorities, litigation, legal or administrative guidance by relevant taxing authorities and the lapse of an applicable statute of limitation.
The balance sheet classification of unrecognized tax benefits and the need for valuation allowances to reduce deferred tax assets also require significant management judgment. Unrecognized tax benefits are classified as current to the extent management expects to settle an uncertain tax position by payment or receipt of cash within one year of the reporting date. Valuation allowances are initially recorded and reevaluated each reporting period by assessing the likelihood of the ultimate realization of a deferred tax asset. Management considers a number of factors in assessing the realization of a deferred tax asset, including the reversal of temporary differences, future taxable income and ongoing prudent and feasible tax planning strategies. Any tax planning strategy utilized in this assessment must meet the recognition and measurement criteria utilized to account for an uncertain tax position. See Note 5 to the Financial Statements for income tax disclosures.
4) Regulatory Assets and Liabilities
PPL Electric's electricity delivery business is subject to cost-based rate regulation. As a result, the effects of regulatory actions are required to be reflected in the financial statements. Assets and liabilities are recorded that result from the regulated ratemaking process that may not be recorded under GAAP for non-regulated entities. Regulatory assets generally represent incurred costs that have been deferred because such costs are probable of future recovery in regulated customer rates. Regulatory liabilities are recognized for amounts expected to be returned through future regulated customer rates. In certain cases, regulatory liabilities are recorded based on an understanding or agreement with the regulator that rates have been set to recover costs that are expected to be incurred in the future, and the regulated entity is accountable for any amounts charged pursuant to such rates and not yet expended for the intended purpose.
Management continually assesses whether the regulatory assets are probable of future recovery by considering factors such as changes in the applicable regulatory and political environments, the ability to recover costs through regulated rates, recent rate orders to other regulated entities, and the status of any pending or potential deregulation legislation. Based on this continual assessment, management believes the existing regulatory assets are probable of recovery. This assessment reflects the current political and regulatory climate at the state and federal levels, and is subject to change in the future. If future recovery of costs ceases to be probable, then asset write-offs would be required to be recognized in operating income. Additionally, the regulatory agencies can provide flexibility in the manner and timing of depreciation of PP&E and amortization of regulatory assets.
At December 31, 2011 and 2010, PPL Electric had regulatory assets of $729 million and $655 million. All regulatory assets are either currently being recovered under specific rate orders, represent amounts that are expected to be recovered in future rates or benefit future periods based upon established regulatory practices. At December 31, 2011 and 2010, PPL Electric had regulatory liabilities of $60 million and $32 million.
In March 2012, PPL Electric plans to file a request with the FERC seeking recovery, over a 34-year period beginning in June 2012, of its unrecovered regulatory asset related to the deferred state tax liability that existed at the time of the transition from the flow-through treatment of state income taxes to full normalization. This change in tax treatment occurred in 2008 as a result of prior FERC initiatives that transferred regulatory jurisdiction of certain transmission assets from the PUC to the FERC. A regulatory asset of $51 million related to this transition, classified as taxes recoverable through future rates, is included in "Other Noncurrent Assets - Regulatory assets" on the Balance Sheet. PPL Electric believes recoverability of this regulatory asset is probable based on FERC precedent in similar cases; however, it is reasonably possible that the FERC may limit the recovery of all or part of the claimed asset.
See Note 6 to the Financial Statements for additional information on regulatory assets and liabilities.
5) Revenue Recognition - Unbilled Revenue
Revenues related to the sale of energy are recorded when energy is delivered to customers. Because customers are billed on cycles which vary based on the timing of the actual meter reads taken throughout the month, PPL Electric records estimates for unbilled revenues at the end of each reporting period. Such unbilled revenue amounts reflect estimates of the amount of energy delivered to customers since the date of the last reading of their meters. The unbilled estimate is based on daily load models, the meter read schedule, and actual weather data. The unbilled accrual is based on estimated usage for each customer class, and the current rate schedule pricing. At December 31, 2011 and 2010, PPL Electric had unbilled revenue of $98 million and $134 million.
Other Information
PPL's Audit Committee has approved the independent auditor to provide audit and audit-related services, tax services and other services permitted by Sarbanes-Oxley and SEC rules. The audit and audit-related services include services in connection with statutory and regulatory filings, reviews of offering documents and registration statements, and internal control reviews. See "Item 14. Principal Accounting Fees and Services" for more information.
LG&E AND KU ENERGY LLC AND SUBSIDIARIES
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
The information provided in this Item 7 should be read in conjunction with LKE's Financial Statements and the accompanying Notes. Capitalized terms and abbreviations are explained in the glossary. Dollars are in millions, unless otherwise noted.
"Management's Discussion and Analysis of Financial Condition and Results of Operations" includes the following information:
·
"Overview" provides a description of LKE and its business strategy. "Financial and Operational Developments" includes a review of Net Income and discusses certain events that are important to understanding LKE's results of operations and financial condition.
·
"Results of Operations" provides a summary of LKE's earnings and a description of key factors expected to impact future earnings. This section ends with "Statement of Income Analysis," which includes explanations of significant changes in principal items on LKE's Statements of Income, comparing 2011, 2010 and 2009.
·
"Financial Condition - Liquidity and Capital Resources" provides an analysis of LKE's liquidity position and credit profile. This section also includes a discussion of rating agency decisions and capital expenditure projections.
·
"Financial Condition - Risk Management" provides an explanation of LKE's risk management programs relating to market and credit risk.
·
"Application of Critical Accounting Policies" provides an overview of the accounting policies that are particularly important to the results of operations and financial condition of LKE and that require its management to make significant estimates, assumptions and other judgments of matters inherently uncertain.
Overview
Introduction
LKE, headquartered in Louisville, Kentucky, is a limited liability company. LKE became a wholly owned subsidiary of PPL when PPL acquired all of LKE's interests from E.ON US Investments Corp. on November 1, 2010. LKE has regulated utility operations through its subsidiaries, LG&E and KU, which constitute substantially all of LKE's assets. LG&E and KU are engaged in the generation, transmission, distribution and sale of electric energy. LG&E also engages in the distribution and sale of natural gas. LG&E and KU maintain their separate identities and serve customers in Kentucky under their respective names. KU also serves customers in Virginia under the Old Dominion Power name and it serves customers in Tennessee under the KU name. Refer to "Item 1. Business - Background" for a description of LKE's business.
Business Strategy
LKE's overall strategy is to provide reliable, safe and competitively priced energy to its customers.
A key objective for LKE is to maintain a strong credit profile through managing financing costs and access to credit markets. LKE continually focuses on maintaining an appropriate capital structure and liquidity position.
Successor and Predecessor Financial Presentation
LKE's Financial Statements and related financial and operating data include the periods before and after PPL's acquisition of LKE on November 1, 2010, and have been segregated to present pre-acquisition activity as the Predecessor and post-acquisition activity as the Successor. Predecessor activity covers the time period prior to November 1, 2010. Successor activity covers the time period after October 31, 2010. Certain accounting and presentation methods were changed to acceptable alternatives to conform to PPL's accounting policies, which are discussed in Note 1 to the Financial Statements. The cost bases of certain assets and liabilities were changed as of November 1, 2010, as a result of the application of push-down basis of accounting, which was used to record the fair value adjustments of assets and liabilities at the acquisition date. Consequently, the financial position, results of operations and cash flows for the Successor periods are not comparable to the Predecessor periods; however, the core operations of LKE have not changed as a result of the acquisition.
Financial and Operational Developments
Net Income
The operating results for 2011 and 2010 include the effect of LG&E's and KU's base rate increases, which became effective August 1, 2010, partially offset by net cost increases, which have not yet been reflected in the rates charged by LG&E and KU. The operating results for the ten months ended October 31, 2010 also include $19 million of other income associated with the establishment of regulatory assets for previously recorded losses on interest rate swaps. The operating results for 2009 include a loss on impairment of goodwill of $1,493 million, which LKE recorded based on bids received from parties interested in purchasing LKE, including PPL. In addition, net income for 2009 includes $220 million of losses from discontinued operations primarily related to the disposition of a 25-year lease and operating agreements of WKE, for the generating facilities of BREC.
See "Results of Operations" below for further discussion and analysis of the results of operations.
TC2
LKE constructed a 732 MW summer capacity coal-fired unit, TC2, which is jointly owned by LG&E and KU (combined 75%), together with the Illinois Municipal Electric Agency and the Indiana Municipal Power Agency (combined 25%). With limited exceptions LKE took care, custody and control of TC2 in January 2011. LG&E and KU and the construction contractor further amended the construction agreement to provide that the contractor will complete certain actions to identify and complete any necessary modifications to allow operation of TC2 on all fuels in accordance with initial specifications prior to certain dates, and amending the provisions relating to liquidated damages. A number of remaining issues regarding these matters are still under discussion with the contractor. See Notes 8 and 15 to the Financial Statements for additional information.
Registered Debt Exchange Offer by LKE, LG&E and KU
In April 2011, LKE, LG&E and KU each filed a Registration Statement with the SEC, related to an offer to exchange certain senior notes and first mortgage bonds issued in November 2010, in transactions not subject to registration under the Securities Act of 1933, with similar but registered securities. The 2011 Registration Statements became effective in June 2011, and the exchanges were completed in July 2011, with substantially all of the senior notes and first mortgage bonds being exchanged. See Note 7 to the Financial Statements and the 2011 Registration Statements for additional information.
CSAPR
In July 2011, the EPA signed the CSAPR, which finalizes and renames the Clean Air Transport Rule (Transport Rule) proposed in August 2010, and made revisions to the rule on February 7, 2012. This rule applies to the Kentucky coal plants. The CSAPR is meant to facilitate attainment of ambient air quality standards for ozone and fine particulates by requiring reductions in sulfur dioxide and nitrogen oxide emissions.
In December 2011, the U.S. Court of Appeals for the District of Columbia (Court) stayed implementation of the CSAPR and left CAIR in effect pending a final resolution on the merits of the validity of the rule. Oral argument on the various challenges to the CSAPR is scheduled for April 2012, and a final decision on the validity of the rule could be issued as early as May 2012.
With respect to LKE's Kentucky coal-fired generating plants, the stay of the CSAPR will initially only impact the unit dispatch order. With the return of the CAIR and LG&E's and KU's significant number of sulfur dioxide allowances, those units will be dispatched with lower operating cost, but slightly higher sulfur dioxide and nitrogen oxide emissions. However, a key component of the Court's final decision, even if the CSAPR is upheld, will be whether the ruling delays the implementation of the CSAPR by one year for both Phases I and II, or instead still requires the significant sulfur dioxide and nitrogen oxide reductions associated with Phase II to begin in 2014. LG&E's and KU's CSAPR compliance strategy is based on over-compliance during Phase I to generate allowances sufficient to cover the expected shortage during the first two years
of Phase II (2014 and 2015) when additional pollution control equipment will be installed. Should Phase I of the CSAPR be shortened to one year, it will be more difficult and costly to provide enough excess allowances in one year to meet the shortage projected for 2014 and 2015.
See Note 15 to the Financial Statements for additional information on the CSAPR.
Pending Bluegrass CTs Acquisition and NGCC Construction
In September 2011, LG&E and KU filed a CPCN with the KPSC requesting approval to build a 640 MW NGCC at the existing Cane Run plant site. In conjunction with this request and to meet new, stricter EPA regulations, LG&E and KU anticipate retiring six older coal-fired electric generating units. These units are located at the Cane Run, Green River and Tyrone plants, which have a combined summer rating of 797 MW. LG&E and KU also requested approval to purchase the Bluegrass CTs, which are expected to provide up to 495 MW of peak generation supply.
LG&E and KU anticipate that the NGCC construction and the acquisition of the Bluegrass CTs could require up to $800 million (comprised of up to $300 million for LG&E and up to $500 million for KU) in capital costs including related transmission projects. Formal requests for recovery of the costs associated with the NGCC construction and the acquisition of the Bluegrass CTs were not included in the CPCN filing with the KPSC but are expected to be included in future rate proceedings. The KPSC issued an Order on the procedural schedule in the CPCN filing that has discovery, scheduled through early February 2012. A KPSC order on the CPCN filing is anticipated in the second quarter of 2012. See Note 8 to the Financial Statements for additional information.
ECR Filing - Environmental Upgrades
In June 2011, in order to achieve compliance with new and pending mandated federal EPA regulations, LG&E and KU filed ECR plans with the KPSC requesting approval to install environmental upgrades for certain of their coal-fired plants along with the recovery of their expected $1.4 billion for LG&E and $1.1 billion for KU in associated capital costs, as well as operating expenses incurred. The ECR plans detailed upgrades that will be made to certain of LG&E's and KU's coal-fired generating plants to continue to be compliant with EPA regulations.
In November 2011, LG&E and KU filed a unanimous settlement agreement, stipulation and recommendation with the KPSC. In December 2011, LG&E and KU received KPSC approval in their proceedings relating to the ECR plans. The KPSC Order approved the terms of the November 2011 settlement agreement entered into between LG&E and KU and the parties to the ECR proceedings. The KPSC Order authorized the installation of environmental upgrades at certain plants during 2012-2016 representing approximate capital costs of $1.4 billion at LG&E and $900 million at KU. In connection with the approved projects, the KPSC Order allows recovery through the ECR rate mechanism of the capital costs and operating expenses of the projects and granted CPCNs for their construction. The KPSC Order also confirmed an existing 10.63% authorized return on equity for projects remaining from earlier ECR plans and provided for an authorized return on equity of 10.10% for the approved projects in the 2011 ECR proceedings. The KPSC Order noted KU's consent to defer the requested approval for certain environmental upgrades at its E.W. Brown generating plant, which represented approximately $200 million in capital costs. KU retained the right to operate and dispatch the E.W. Brown generating plant in accordance with applicable environmental standards and the right to request approval of the deferred projects and related costs in future regulatory proceedings See Note 6 to the Financial Statements for additional information.
Storm Recovery
In August 2011, a strong storm hit LG&E's service area causing significant damage and widespread outages for approximately 139,000 customers. LG&E filed an application with the KPSC in September 2011 requesting approval of a regulatory asset recorded to defer, for future recovery, $8 million in incremental operation and maintenance expenses related to the storm restoration. An Order was received in December 2011 granting regulatory accounting treatment, while recovery of the regulatory asset will be determined within the next base rate case.
In December 2009, a major snowstorm hit KU's Virginia service area causing approximately 30,000 customer outages. During the normal 2009 Virginia Annual Information Filing (AIF), KU requested that the VSCC establish a regulatory asset and defer for future recovery $6 million in incremental operation and maintenance expenses related to the storm restoration. In March 2011, the VSCC Staff issued its report on KU's 2009 AIF stating that it considered this storm damage to be extraordinary, non-recurring and material to KU. The Staff Report also recommended establishing a regulatory asset for these costs, with recovery over a five-year period upon approval in the next base rate case. In March 2011, a regulatory asset of $6 million was established for actual costs incurred. In June 2011, the VSCC issued an Order approving the recommendations contained in the Staff Report. KU received approval in its 2011 base rate case to recover this regulatory asset over a five-year period ending October 2016.
In September 2009, the KPSC approved the deferral of a total of $101 million ($44 million and $57 million for LG&E and KU) of costs associated with a severe ice storm that occurred in January 2009 and a wind storm that occurred in February 2009. Additionally, in December 2008, the KPSC approved the deferral of a total of $26 million ($24 million and $2 million for LG&E and KU) of costs associated with high winds from the remnants of Hurricane Ike in September 2008. LG&E and KU received approval in their 2010 base rate cases to recover these regulatory assets over a ten-year period beginning August 2010.
Virginia Rate Case
In April 2011, KU filed an application with the VSCC requesting an annual increase in electric base rates for its Virginia jurisdictional customers of $9 million, or 14%. In September 2011, a settlement stipulation was reached between KU and the VSCC Staff and filed with the VSCC for consideration. In October 2011, the VSCC approved the stipulation with two modifications that were accepted by KU. The VSCC issued an Order closing the proceeding in October 2011. The approved revenue increase was $7 million annually, based on a return on equity of 10.3%, with new base rates effective November 1, 2011.
Results of Operations
As previously noted, LKE's results for the time periods after October 31, 2010 are on a basis of accounting different from its results for time periods prior to November 1, 2010. When discussing LKE's results of operations material differences resulting from the different basis of accounting will be isolated for purposes of comparability. See "Overview - Successor and Predecessor Financial Presentation" for further information.
The utility business is affected by seasonal weather. As a result, operating revenues (and associated operating expenses) are not generated evenly throughout the year. Revenue and earnings are generally higher during the first and third quarters and lower during the second quarter due to weather.
The following table summarizes the significant components of net income for 2011, 2010, and 2009 and the changes therein:
Earnings
The changes in the components of Net Income between these periods were due to the following factors. The results are adjusted for certain items that management considers special. See additional detail of these special items in the table below.
·
See "Statement of Income Analysis - Margin - Changes in Non-GAAP Financial Measures" for an explanation of margin.
·
Other operation and maintenance increased in 2010 compared with 2009, primarily due to higher administrative and general costs of $38 million and higher steam costs of $13 million. Administrative and general costs increased in part due to acquisition-related costs of $17 million and higher bad debt costs of $6 million, partially offset by lower pension costs of $6 million.
·
Depreciation expense was $32 million higher in 2011 compared with 2010, due to TC2 commencing dispatch in January 2011.
·
Taxes, other than income increased in 2011 compared with 2010, primarily due to a $9 million clean coal incentive tax credit that LKE was able to apply to property tax in 2010.
·
Other Income (Expense) - net decreased in 2011 compared with 2010, primarily due to $19 million of other income from the establishment of a regulatory asset for previously recorded losses on interest rate swaps in 2010.
·
Interest expense decreased in 2011 compared with 2010, due to lower interest rates and lower long-term debt balances. Lower interest rates contributed $17 million of the decrease in interest expense, as the interest rates on the first mortgage bonds were lower than the rates on the loans from Fidelia Corporation and other E.ON AG affiliates, which were replaced. Lower long-term debt principal balances contributed $15 million of the decrease, as LKE's long-term debt principal balances were lower for most of 2011, compared with its long-term debt principal balances as of December 31, 2010, this was partially offset; as LKE's long-term debt principal balances increased in 2011. LKE long-term debt principal balances were $248 million higher as of December 31, 2011 compared with December 31, 2010.
·
Income taxes increased in 2011 compared with 2010, primarily due to the $19 million impact of higher pre-tax income.
Income taxes increased in 2010 compared with 2009, primarily due to the $43 million impact of higher pre-tax income.
The following after-tax amounts, which management considers special items, also impacted earnings:
(a)
Represents net unrealized gains (losses) on contracts that economically hedge anticipated cash flows.
(b)
Represents costs associated with a terminated lease of WKE for the generating facilities of BREC. See Note 9 to the Financial Statements for additional information.
(c)
Represents an impairment loss for LKE's interest in two gas distribution companies in Argentina, which it sold in 2010. See Note 9 to the Financial Statements for additional information.
2012 Outlook
Excluding special items, LKE projects lower earnings in 2012 compared with 2011, as revenue increases are not expected to offset expense increases, which will include increases in depreciation expense, due to more plant in service and in interest expense, due to higher average debt balances as a result of capital expenditures. Actual results will be dependent on the effects of the economy and the impact of weather on retail sales among other variables. As a result of the stay out provision established in the settlement of the PPL-LKE acquisition, LKE is generally unable to implement an increase in base rates for its two regulated utilities in Kentucky before January 1, 2013.
Earnings in 2012 are subject to various risks and uncertainties. See "Forward-Looking Information," the rest of this Item 7, Notes 6 and 15 to the Financial Statements and "Business," and "Risk Factors" in this Form 10-K for a discussion of the risks, uncertainties and factors that may impact future earnings.
Statement of Income Analysis --
Margin
Non-GAAP Financial Measure
The following discussion includes financial information prepared in accordance with GAAP, as well as a non-GAAP financial measure, "Margin." Margin is not intended to replace "Operating Income," which is determined in accordance with GAAP as an indicator of overall operating performance. Other companies may use different measures to analyze and to report on the results of their operations. Margin is a single financial performance measure of LKE's operations. In calculating this measure, utility revenues and expenses associated with approved cost recovery tracking mechanisms are offset. These mechanisms allow for recovery of certain expenses, returns on capital investments associated with environmental regulations and performance incentives. Certain costs associated with these mechanisms, primarily ECR and DSM, are recorded as "Other operation and maintenance" expenses and the depreciation associated with ECR equipment is recorded as "Depreciation" expense. As a result, this measure represents the net revenues from LKE's operations. This performance measure is used, in conjunction with other information, internally by senior management to manage LKE's operations and analyze actual results compared with budget.
Reconciliation of Non-GAAP Financial Measures
The following tables reconcile "Operating Income" to "Margin" as defined by LKE for 2011, 2010 and 2009.
(a)
Represents amounts excluded from Margin.
(b)
As reported on the Statements of Income.
Changes in Non-GAAP Financial Measures
Margins were higher by $92 million for 2011 compared with 2010. New KPSC rates went into effect on August 1, 2010, contributing to an additional $112 million in operating revenue over the prior year. Partially offsetting the rate increase were lower retail volumes resulting from weather and economic conditions.
(a)
Fuel handling costs are included in fuel for electric generation on the Statements of Income for the Successor's periods and are in other operation and maintenance expense on the Statements of Income for the Predecessor's periods.
(b)
Steam operation costs increased in 2011 compared with 2010, primarily due to higher variable costs, the result of TC2 commencing dispatch in 2011.
(c)
Distribution maintenance costs increased in 2011 compared with 2010, primarily due to amortization of storm restoration-related costs along with a hazardous tree removal project initiated in August 2010, and an increase in pipeline integrity work. This increase was partially offset by $6 million of 2009 winter storm restoration expenses being reclassified to a regulatory asset in 2011.
(d)
Steam maintenance costs increased in 2010 compared with 2009, primarily due to increased generation and boiler and electric maintenance costs related to outage work.
(e)
Transmission operation costs increased in 2010 compared with 2009, primarily due to a settlement agreement with a third party resulting in the establishment of a regulatory asset in 2009.
(f)
Administrative and general costs increased in 2010 compared with 2009, primarily due to acquisition-related costs of $17 million incurred in 2010, higher bad debt costs of $6 million and PPL support charges of $3 million incurred for two post-acquisition months in 2010, partially offset by lower pension costs of $6 million. Bad debt costs increased in 2010 compared with 2009, due to higher billed revenues and a higher net charge-off percentage partially offset by increased late payment charges. Pension costs decreased in 2010 compared with 2009, due to favorable asset performance in 2009.
(g)
Other generation maintenance costs increased in 2010 compared with 2009, primarily due to the overhaul of Paddy's Run Unit 13.
Depreciation
Changes in depreciation were due to the following:
Taxes, Other Than Income
Taxes, other than income increased by $14 million in 2011 compared with 2010 primarily due to a $9 million state coal tax credit that was applied to 2010 property taxes. The remaining increase was due to higher assessments, primarily from significant property additions. Taxes, other than income decreased by $8 million in 2010 compared with 2009 primarily due to a $5 million increase in the amount of state coal tax credits applied to property tax.
Loss on Impairment
LKE did not experience impairment losses in 2011 or in 2010. In 2009, the loss on impairment of goodwill was $1,493 million. LKE recorded goodwill impairment in 2009 based on bids received from parties interested in purchasing LKE, including PPL.
Other Income (Expense) - net
Changes in other income (expense) - net were due to the following:
(a)
Net derivative gains and losses includes the unrealized gains and losses on interest rate swaps not designated as hedging instruments and the ineffective portion of interest rate swaps designated and qualifying as a cash flow hedge.
(b)
Other income in 2010 resulted from the establishment of a regulatory asset for previously recorded losses on interest rate swaps, which is included in "Net derivative gains and losses" within Note 17 to the Financial Statements.
Interest Expense
The changes in interest expense were due to:
(a)
Interest rates on senior notes and first mortgage bonds issued in November 2010 were lower than the rates on the loans from Fidelia Corporation and other E.ON AG affiliates in place through October 2010.
(b)
LKE's long-term debt principal balance was $923 million lower as of December 31, 2010 compared with December 31, 2009 primarily due to an equity contribution from PPL of $1.6 billion at the time of acquisition. LKE's long-term debt principal balance was $248 million higher as of December 31, 2011 compared with December 31, 2010.
(a)
In 2009, LKE completed the disposition of WKE's 25-year lease and operating agreements for the generating facilities owned or operated by BREC.
(b)
In 2009, LKE recorded an impairment loss for two gas distribution companies located in Argentina, which it sold in 2010.
Financial Condition
Liquidity and Capital Resources
LKE expects to continue to have adequate liquidity available through operating cash flows, cash and cash equivalents and its credit facilities.
LKE's cash flows from operations and access to cost-effective bank and capital markets are subject to risks and uncertainties including, but not limited to:
·
changes in market prices for electricity;
·
changes in commodity prices that may increase the cost of producing power or decrease the amount LKE receives from selling power;
·
operational and credit risks associated with selling and marketing products in the wholesale power markets;
·
unusual or extreme weather that may damage LKE's transmission and distribution facilities or affect energy sales to customers;
·
reliance on transmission and distribution facilities that LKE does not own or control to deliver its electricity and natural gas;
·
unavailability of generating units (due to unscheduled or longer-than-anticipated generation outages, weather and natural disasters) and the resulting loss of revenues and additional costs of replacement electricity;
·
the ability to recover and the timeliness and adequacy of recovery of costs associated with regulated utility businesses;
·
costs of compliance with existing and new environmental laws;
·
any adverse outcome of legal proceedings and investigations with respect to LKE's current and past business activities;
·
deterioration in the financial markets that could make obtaining new sources of bank and capital markets funding more difficult and more costly; and
·
a downgrade in LKE's or its rated subsidiaries' credit ratings that could adversely affect their ability to access capital and increase the cost of credit facilities and any new debt.
See "Item 1A. Risk Factors" for further discussion of risks and uncertainties affecting LKE's cash flows.
At December 31, LKE had the following:
(a)
Represents tax-exempt bonds issued by Louisville/Jefferson County, Kentucky, on behalf of LG&E that were purchased from the remarketing agent in 2008. Such bonds were remarketed to unaffiliated investors in January 2011. See Note 7 to the Financial Statements for additional information.
(b)
Represents borrowings under LG&E's $400 million syndicated credit facility. See Note 7 to the Financial Statements for additional information.
The changes in LKE's cash and cash equivalents position resulted from:
Auction Rate Securities
At December 31, 2011, LG&E's and KU's tax-exempt revenue bonds that are in the form of auction rate securities and total $231 million continue to experience failed auctions. Therefore, the interest rate continues to be set by a formula pursuant to the relevant indentures. For the periods ended December 31, 2011, the weighted-average rate on LG&E's and KU's auction rate bonds in total was 0.25%.
See Note 7 to the Financial Statements for additional information about long-term debt securities.
Operating Activities
Net cash provided by operating activities increased by 50%, or $255 million, in 2011 compared with 2010, primarily as a result of:
·
an increase in net income adjusted for non-cash effects of $177 million (deferred income taxes and investment tax credits of $101 million, depreciation of $50 million, amortization of regulatory assets of $15 million and other noncash items of $11 million, partially offset by unrealized (gains) losses on derivatives of $14 million, defined benefit plans - expense of $13 million and loss from discontinued operations - net of tax of $1 million);
·
an increase in cash inflows related to income tax receivable of $79 million primarily due to net operating losses of $40 million recorded in 2010 and the payment of $40 million received by LKE for tax benefits in 2011;
·
a net decrease in working capital related to unbilled revenues of $53 million due to colder weather in December 2010 as compared with December 2009 and milder weather in December 2011 as compared with December 2010; and
·
a decrease in cash outflows of $29 million due to lower inventory levels in 2011 as compared with 2010 driven by $32 million for fuel inventory purchased in 2010 for TC2 that was not used until 2011 when TC2 began dispatch, $21 million due to lower coal burn as a result of unplanned outages at LG&E's Mill Creek plant and $6 million for decreases in gas storage volumes, partially offset by $22 million for KU's E.W. Brown and Ghent plants due primarily to increases in coal prices and $7 million for increases in coal in-transit; partially offset by
·
an increase in discretionary defined benefit plan contributions of $105 million made in order to achieve LKE's long-term funding requirements.
Net cash provided by operating activities increased by 352%, or $718 million, in 2010 compared with 2009, primarily as a result of:
·
the absence of payments made in July 2009 of $580 million for the WKE lease and operating agreement termination;
·
an increase in net income adjusted for non-cash effects of $155 million (deferred income taxes and investment tax credits of $74 million, unrealized (gains) losses on derivatives of $47 million, depreciation of $13 million and amortization of regulatory assets of $3 million, partially offset by loss on impairment of goodwill of $1,493 million, loss from discontinued operations of $224 million, defined benefit plans - expense of $19 million and other noncash items of $20 million);
·
lower storm expenses of $104 million; and
·
the timing of ECR collections of $53 million; partially offset by
·
a net increase in working capital from accounts receivable and unbilled revenues of $107 million due to the timing of cash receipts, an increase in base rates effective August 2010, colder weather in December 2009 as compared with December 2008 and colder weather in December 2010 as compared with December 2009;
·
an increase in cash refunded to customers of $55 million due to prior period over-recoveries related to the gas supply clause filings;
·
an increase in cash outflows related to inventory of $44 million, primarily due to a nominal decrease in the market price of natural gas in 2010 and a significant decrease in the market price of natural gas in 2009;
·
an increase in backstop energy and aluminum production credit payments of $39 million under the smelter contract;
·
higher interest payments of $33 million due to an accelerated settlement with E.ON AG; and
·
an increase in discretionary defined benefit plan contributions of $14 million made in order to achieve LKE's long-term funding requirements.
Investing Activities
The primary use of cash in investing activities in 2011, 2010 and 2009 was capital expenditures. See "Forecasted Uses of Cash" for detail regarding projected capital expenditures for the years 2012 through 2016.
Net cash used in investing activities decreased by 58%, or $372 million, in 2011 compared with 2010, as a result of:
·
proceeds from the sale of other investments of $163 million in 2011;
·
a decrease in capital expenditures of $134 million, primarily due to the completion of KU's scrubber program in 2010 and TC2 being dispatched in 2011; and
·
an increase of notes receivable from affiliates of $107 million; partially offset by
·
proceeds from sales of discontinued operations of $21 million in 2010 and
·
a decrease in restricted cash of $11 million.
Net cash used in investing activities decreased by 10%, or $69 million, in 2010 compared with 2009, as a result of:
·
a decrease in capital expenditures of $127 million, primarily due to lower expenditures related to the construction of TC2 and major storm events that occurred in 2009, and
·
proceeds from sales of discontinued operations of $21 million in 2010; partially offset by
·
a decrease of notes receivable from affiliates of $61 million;
·
a decrease in restricted cash of $8 million;
·
proceeds on the settlement of derivatives of $7 million in 2009; and
·
proceeds from the sale of assets of $3 million in 2009.
Financing Activities
Net cash used in financing activities was $456 million in 2011 compared with net cash provided by financing activities of $127 million in 2010, primarily as a result of increased distributions to PPL and reduced contributions from PPL.
In 2011, cash used in financing activities consisted of:
·
distributions to PPL of $533 million, which includes $248 million using the proceeds of the long-term debt issuance noted below;
·
a repayment on a revolving line of credit of $163 million;
·
the payment of debt issuance and credit facility costs of $8 million; and
·
the repayment of debt of $2 million; partially offset by
·
the issuance of senior notes of $250 million.
Net cash provided by financing activities was $127 million in 2010 compared with $902 million in 2009. In spite of significant new debt issuances associated with the repayments to E.ON AG affiliates in connection with PPL's acquisition of LKE, the cash provided by financing in 2010 is lower as a result of new debt issuances exceeding repayments by a smaller amount and by higher distributions paid in 2010.
In the two months of 2010 following PPL's acquisition of LKE, cash provided by financing activities of the Successor consisted of:
·
the issuance of senior unsecured notes and first mortgage bonds of $2,890 million after discounts;
·
the issuance of debt of $2,784 million to a PPL affiliate to repay debt due to E.ON AG affiliates upon the closing of PPL's acquisition of LKE;
·
an equity contribution from PPL of $1,565 million; and
·
a draw on a revolving line of credit of $163 million; partially offset by
·
the repayment of debt to E.ON AG affiliates of $4,319 million upon the closing of PPL's acquisition of LKE;
·
the repayment of debt to a PPL affiliate of $2,784 million upon the issuance of senior unsecured notes and first mortgage bonds;
·
distributions to PPL of $100 million; and
·
the payment of debt issuance and credit facility costs of $32 million.
In the ten months of 2010 preceding PPL's acquisition of LKE, cash used in financing activities by the Predecessor consisted of:
·
the repayment of debt to an E.ON AG affiliate of $900 million;
·
distributions to E.ON US Investments Corp. of $87 million; and
·
a net decrease in notes payable with affiliates of $3 million; partially offset by
·
the issuance of debt of $950 million to an E.ON AG affiliate.
In 2009, cash provided by financing activities by the Predecessor consisted of:
·
the issuance of debt of $1,230 million to an E.ON AG affiliate, partially offset by
·
the repayment of debt to an E.ON AG affiliate of $255 million;
·
distributions to E.ON US Investments Corp. of $49 million;
·
a net decrease in notes payable with affiliates of $22 million; and
·
distributions to noncontrolling interests of $2 million for discontinued operations in 2009.
See "Forecasted Sources of Cash" for a discussion of LKE's plans to issue debt securities, as well as a discussion of credit facility capacity available to LKE. Also see "Forecasted Uses of Cash" for a discussion of plans to pay dividends on common securities in the future, as well as maturities of long-term debt.
LKE's long-term debt securities activity through December 31, 2011 was:
(a)
Notes were retired upon maturity.
(b)
In April 2011, LKE, LG&E and KU each filed a 2011 Registration Statement with the SEC related to offers to exchange securities issued in November 2010 in transactions not registered under the Securities Act of 1933 with similar but registered securities. The registration became effective in June 2011, and the exchanges were completed in July 2011 with substantially all securities being exchanged.
See Note 7 to the Financial Statements for additional information about long-term debt securities.
Forecasted Sources of Cash
LKE expects to continue to have sufficient sources of cash available in the near term, including various credit facilities and operating cash flow. LG&E expects to remarket $194 million of tax-exempt bonds that will be put back to LG&E in 2012. In February 2012, LG&E and KU each established a commercial paper program for up to $250 million to provide an additional financing source to fund each of their short-term liquidity needs. Commercial paper issuances will be supported by the respective Syndicated Credit Facility.
Credit Facilities
At December 31, 2011, LKE's total committed borrowing capacity under its credit facilities and the use of this borrowing capacity were:
(a)
In June 2011, LG&E and KU each amended its respective Syndicated Credit Facility such that the fees and the spread to benchmark interest rates for borrowings depend upon the respective company's senior secured long-term debt rating rather than the senior unsecured debt rating.
(b)
In April 2011, KU entered into a new $198 million letter of credit facility that has been used to issue letters of credit to support outstanding tax exempt bonds. KU pays customary commitment and letter of credit fees under the new facility. The facility matures in April 2014. In August 2011, KU amended its letter of credit facility such that the fees depend upon KU's senior secured long-term debt rating rather than the senior unsecured debt rating.
(c)
Total borrowings outstanding under LKE's credit facilities decreased on a net basis by $163 million since December 31, 2010.
(d)
In October 2011, LG&E and KU each amended its respective syndicated credit facilities. The amendments included extending the expiration dates from December 2014 to October 2016. Under these facilities, LG&E and KU each continue to have the ability to make cash borrowings and to request the lenders to issue letters of credit.
The commitments under LG&E's and KU's credit facilities are provided by a diverse bank group, with no one bank and its affiliates providing an aggregate commitment of more than 9% of the total committed capacity; however, the PPL affiliate provides a commitment of approximately 23% of LKE's total facilities listed above.
See Note 7 to the Financial Statements for further discussion of LKE's credit facilities.
Operating Leases
LKE and its subsidiaries also have available funding sources that are provided through operating leases. LKE's subsidiaries lease office space, gas storage and certain equipment. These leasing structures provide LKE additional operating and financing flexibility. The operating leases contain covenants that are typical for these agreements, such as maintaining insurance, maintaining corporate existence and timely payment of rent and other fees.
See Note 11 to the Financial Statements for further discussion of the operating leases.
Forecasted Uses of Cash
In addition to expenditures required for normal operating activities, such as purchased power, payroll, fuel and taxes, LKE currently expects to incur future cash outflows for capital expenditures, various contractual obligations, payment of dividends on its common securities and possibly the purchase or redemption of a portion of debt securities.
Capital Expenditures
The table below shows LKE's current capital expenditure projections for the years 2012 through 2016.
(a)
Construction expenditures include AFUDC, which is not expected to be significant for the years 2012 through 2016.
(b)
Includes approximately $700 million of currently estimable costs related to replacement generation units due to EPA regulations not recoverable through the ECR mechanism. LKE expects to recover these costs over a period equivalent to the related depreciable lives of the assets through future rate proceedings.
(c)
Includes approximately $100 million of currently estimable transmission costs related to replacement generation units. LKE expects to recover these costs over a period equivalent to the related depreciable lives of the assets through future rate proceedings.
LKE's capital expenditure projections for the years 2012 through 2016 total approximately $6.3 billion. Capital expenditure plans are revised periodically to reflect changes in operational, market and regulatory conditions. This table includes current estimates for LKE's environmental projects related to new and anticipated EPA compliance standards. Actual costs may be significantly lower or higher depending on the final requirements and market conditions. Certain environmental compliance costs incurred by LG&E and KU in serving KPSC jurisdictional customers are generally eligible for recovery through the ECR mechanism.
LKE plans to fund its capital expenditures in 2012 with cash on hand, cash from operations and short-term debt.
Contractual Obligations
LKE has assumed various financial obligations and commitments in the ordinary course of conducting its business. At December 31, 2011, the estimated contractual cash obligations of LKE were:
(a)
Reflects principal maturities only based on stated maturity dates. See Note 7 to the Financial Statements for a discussion of variable-rate remarketable bonds issued on behalf of LG&E and KU. LKE does not have any significant capital lease obligations.
(b)
Assumes interest payments through stated maturity. The payments herein are subject to change, as payments for debt that is or becomes variable-rate debt have been estimated.
(c)
See Note 11 to the Financial Statements for additional information.
(d)
Represents contracts to purchase coal, natural gas and natural gas transportation. See Note 15 to the Financial Statements for additional information.
(e)
Represents future minimum payments under OVEC power purchase agreements through June 2040. See Note 15 to the Financial Statements for additional information.
(f)
Represents construction commitments, including commitments for the Ghent landfill, Ohio Falls refurbishment and the Brown SCR construction including associated material transport systems for coal combustion residuals, which are also reflected in the Capital Expenditures table presented above.
(g)
Based on the current funded status of LKE's qualified pension plans, no cash contributions are required. See Note 13 to the Financial Statements for a discussion of expected contributions.
(h)
Represents other contractual obligations. Purchase orders made in the ordinary course of business are excluded from the amounts presented.
Dividends
From time to time, as determined by its Board of Directors, LKE pays dividends to the sole member, PPL.
As discussed in Note 7 to the Financial Statements, LG&E's and KU's ability to pay dividends is limited under a covenant in each of their $400 million revolving line of credit facilities. This covenant restricts their debt to total capital ratio to not more than 70%.
See Note 7 to the Financial Statements for other restrictions related to distributions on capital interests for LKE subsidiaries.
Purchase or Redemption of Debt Securities
LKE will continue to evaluate purchasing or redeeming outstanding debt securities and may decide to take action depending upon prevailing market conditions and available cash.
Rating Agency Decisions
Moody's, S&P and Fitch periodically review the credit ratings on the debt securities of LKE and its subsidiaries. Based on their respective independent reviews, the rating agencies may make certain ratings revisions or ratings affirmations.
A credit rating reflects an assessment by the rating agency of the creditworthiness associated with an issuer and particular securities that it issues. The credit ratings of LKE and its subsidiaries are based on information provided by LKE and other sources. The ratings of Moody's, S&P and Fitch are not a recommendation to buy, sell or hold any securities of LKE or its subsidiaries. Such ratings may be subject to revisions or withdrawal by the agencies at any time and should be evaluated independently of each other and any other rating that may be assigned to the securities. A downgrade in LKE's or its subsidiaries' credit ratings could result in higher borrowing costs and reduced access to capital markets.
In LKE's 2011 Registration Statement, LKE described its then-current credit ratings in connection with, and to facilitate, an understanding of its liquidity position. As a result of the passage of the Dodd-Frank Act and the attendant uncertainties relating to the extent to which issuers of non-asset backed securities may disclose credit ratings without being required to obtain rating agency consent to the inclusion of such disclosure, or incorporation by reference of such disclosure, in a registrant's registration statement or section 10(a) prospectus, LKE is limiting its credit rating disclosure to a description of the actions taken by the rating agencies with respect to LKE's ratings, but without stating what ratings have been assigned to LKE or its subsidiaries, or their securities. The ratings assigned by the rating agencies to LKE and its subsidiaries and their respective securities may be found, without charge, on each of the respective ratings agencies' websites, which ratings together with all other information contained on such rating agency websites is, hereby, explicitly not incorporated by reference in this report.
Following the announcement of PPL's then-pending acquisition of WPD Midlands in March 2011, the rating agencies took the following actions.
·
Moody's affirmed all of the ratings for LKE and all of its rated subsidiaries;
·
S&P revised the outlook for LKE, LG&E and KU and lowered the issuer and senior unsecured ratings of LKE and the issuer, senior secured and short-term ratings of LG&E and KU; and
·
Fitch affirmed all of the ratings for LKE and all of its rated subsidiaries.
In April 2011, S&P took the following actions following the completion of PPL's acquisition of WPD Midlands:
· revised the outlook for LKE and all of its rated subsidiaries;
· raised the short-term ratings of LG&E and KU; and
· affirmed all of the long-term ratings for LKE and its rated subsidiaries.
In May 2011, S&P downgraded the long-term rating of four series of pollution control bonds issued on behalf of KU by one notch in connection with the substitution of the letters of credit enhancing these four bonds.
In September 2011, Moody's affirmed the issuer ratings for LG&E and KU and all of the ratings for LKE.
In November 2011, Moody's and S&P affirmed all of their ratings for LKE and all of its rated subsidiaries.
In December 2011, Fitch affirmed all of the ratings for LKE and all of its rated subsidiaries.
Ratings Triggers
LKE and its subsidiaries have various derivative and non-derivative contracts, including contracts for the sale and purchase of electricity, fuel, commodity transportation and storage and interest rate instruments, which contain provisions requiring LKE and its subsidiaries to post additional collateral, or permitting the counterparty to terminate the contract, if LKE's or the subsidiaries' credit rating were to fall below investment grade. See Note 19 to the Financial Statements for a discussion of "Credit Risk-Related Contingent Features," including a discussion of the potential additional collateral that would have been required for derivative contracts in a net liability position at December 31, 2011. At December 31, 2011, if LKE's or its subsidiaries' credit ratings had been below investment grade, the maximum amount that LKE would have been required to post as additional collateral to counterparties was $84 million for both derivative and non-derivative commodity and commodity-related contracts used in its generation and marketing operations, gas supply and interest rate contracts.
Off-Balance Sheet Arrangements
LKE has entered into certain agreements that may contingently require payment to a guaranteed or indemnified party. See Note 15 to the Financial Statements for a discussion of these agreements.
Risk Management
Market Risk
LKE is exposed to market risk from equity instruments, interest rate instruments and commodity instruments, as discussed below. However, regulatory cost recovery mechanisms significantly mitigate those risks. See Notes 1, 18 and 19 to the Financial Statements for information about LKE's risk management objectives, valuation techniques and accounting designations.
The forward-looking information presented below provides estimates of what may occur in the future, assuming certain adverse market conditions and model assumptions. Actual future results may differ materially from those presented. These disclosures are not precise indicators of expected future losses, but only indicators of possible losses under normal market conditions at a given confidence level.
Commodity Price Risk (Non-trading)
LG&E's and KU's rates are set by regulatory commissions and the fuel costs incurred are directly recoverable from customers. As a result, LG&E and KU are subject to commodity price risk for only a small portion of on-going business operations. LKE conducts energy trading and risk management activities to maximize the value of the physical assets at times when the assets are not required to serve LG&E's and KU's customers. LKE managed its energy commodity risk using derivative instruments, including swaps and forward contracts. See Note 19 to the Financial Statements for additional disclosures.
The balance and change in net fair value of LKE's commodity derivative contracts for the periods ended December 31, 2011, 2010, and 2009 are shown in the table below.
(a) Represents the change in value of outstanding transactions and the value of transactions entered into and settled during the period.
Interest Rate Risk
LKE and its subsidiaries have issued debt to finance their operations, which exposes them to interest rate risk. LKE utilizes various financial derivative instruments to adjust the mix of fixed and floating interest rates in its debt portfolio when appropriate. Risk limits under LKE's risk management program are designed to balance risk, exposure to volatility in interest expense and changes in the fair value of LKE's debt portfolio due to changes in the absolute level of interest rates.
At December 31, 2011 and 2010, LKE's potential annual exposure to increased interest expense, based on a 10% increase in interest rates, was not significant.
LKE is also exposed to changes in the fair value of its debt portfolio. LKE estimated that a 10% decrease in interest rates at December 31, 2011, would increase the fair value of its debt portfolio by $125 million compared with $123 million at December 31, 2010.
(a)
Includes accrued interest.
(b)
LKE utilizes various risk management instruments to reduce its exposure to the expected future cash flow variability of its debt instruments. These risks include exposure to adverse interest rate movements for outstanding variable rate debt and for future anticipated financing. While LKE is exposed to changes in the fair value of these instruments, any realized changes in the fair value of such economic hedges are recoverable through regulated rates and any subsequent changes in fair value of these derivatives are included in regulatory assets or liabilities. Sensitivities represent a 10% adverse movement in interest rates. The positions outstanding at December 31, 2011 mature through 2033.
Credit Risk
LKE is exposed to potential losses as a result of nonperformance by counterparties of their contractual obligations. LKE maintains credit policies and procedures to limit counterparty credit risk including evaluating credit ratings and financial information along with having certain counterparties post margin if the credit exposure exceeds certain thresholds. LKE is exposed to potential losses as a result of nonpayment by customers. LKE maintains an allowance for doubtful accounts based on a historical charge-off percentage for retail customers. Allowances for doubtful accounts from wholesale and municipal customers and for miscellaneous receivables are based on specific identification by management. Retail, wholesale and municipal customer accounts are written-off after four months of no payment activity. Miscellaneous receivables are written-off as management determines them to be uncollectible.
Certain of LKE's derivative instruments contain provisions that require it to provide immediate and on-going collateralization of derivative instruments in net liability positions based upon LKE's credit ratings from each of the major credit rating agencies. See Notes 18 and 19 to the Financial Statements for information regarding exposure and the risk management activities.
Related Party Transactions
LKE is not aware of any material ownership interest or operating responsibility by senior management of LKE, LG&E or KU in outside partnerships, including leasing transactions with variable interest entities or other entities doing business with LKE. See Note 16 to the Financial Statements for additional information on related party transactions between LKE and affiliates.
Environmental Matters
Protection of the environment is a major priority for LKE and a significant element of its business activities. Extensive federal, state and local environmental laws and regulations are applicable to LKE's air emissions, water discharges and the management of hazardous and solid waste, among other areas, and the costs of compliance or alleged non-compliance cannot be predicted with certainty but could be material. In addition, costs may increase significantly if the requirements or scope of environmental laws or regulations, or similar rules, are expanded or changed from prior versions by the relevant agencies. Costs may take the form of increased capital or operating and maintenance expenses; monetary fines, penalties or forfeitures or other restrictions. Many of these environmental law considerations are also applicable to the operations of key suppliers, or customers, such as coal producers, industrial power users, etc.; and may impact the costs for their products or their demand for LKE's services. See "Item 1. Business - Environmental Matters" and Note 15 to the Financial Statements for a discussion of environmental matters.
New Accounting Guidance
See Note 24 to the Financial Statements for a discussion of new accounting guidance pending adoption.
Application of Critical Accounting Policies
Financial condition and results of operations are impacted by the methods, assumptions and estimates used in the application of critical accounting policies. The following accounting policies are particularly important to the financial condition or results of operations, and require estimates or other judgments of matters inherently uncertain. Changes in the estimates or other judgments included within these accounting policies could result in a significant change to the information presented in the Financial Statements (these accounting policies are also discussed in Note 1 to the Financial Statements). LKE's senior management has reviewed these critical accounting policies, the following disclosures regarding their application and the estimates and assumptions regarding them, with PPL's Audit Committee.
1)
Revenue Recognition - Unbilled Revenue
Revenues related to the sale of energy are recorded when service is rendered or when energy is delivered to customers. Because customers of LG&E's and KU's retail operations are billed on cycles which vary based on the timing of the actual reading of their electric and gas meters, LKE records estimates for unbilled revenues at the end of each reporting period. Such unbilled revenue amounts reflect estimates of the amount of energy delivered to customers since the date of the last reading of their meters. These unbilled revenues reflect consideration of estimated usage by customer class, the effect of different rate schedules, changes in weather, and where applicable, the impact of weather normalization or other regulatory provisions of rate structures. In addition to the unbilled revenue accrual resulting from cycle billing, LKE makes additional accruals resulting from the timing of customer bills. The accrual of unbilled revenues in this manner properly matches revenues and related costs. At December 31, 2011 and 2010 LKE had unbilled revenue balances of $146 million and $170 million.
2)
Price Risk Management
See "Financial Condition - Risk Management" above.
3)
Defined Benefits
LKE and certain of its subsidiaries sponsor and participate in qualified funded and non-qualified unfunded defined benefit pension plans. LKE also sponsors a funded other postretirement benefit plan. These plans are applicable to the majority of the employees of LKE and its subsidiaries. LKE records an asset or liability to recognize the funded status of all defined benefit plans with an offsetting entry to OCI or regulatory assets or liabilities. Consequently, the funded status of all defined benefit plans is fully recognized on the Balance Sheets. See Note 13 to the Financial Statements for additional information about the plans and the accounting for defined benefits.
Certain assumptions are made by LKE and certain of its subsidiaries regarding the valuation of benefit obligations and the performance of plan assets. When accounting for defined benefits, delayed recognition in earnings of differences between actual results and expected or estimated results is a guiding principle. Annual net periodic defined benefit costs are recorded in current earnings based on estimated results. Any differences between actual and estimated results are recorded in OCI or regulatory assets and liabilities for amounts that are expected to be recovered through regulated customer rates. These amounts in regulatory assets and liabilities are amortized to income over future periods. The delayed recognition allows for a smoothed recognition of costs over the working lives of the employees who benefit under the plans. The primary assumptions are:
·
Discount Rate - The discount rate is used in calculating the present value of benefits, which is based on projections of benefit payments to be made in the future. The objective in selecting the discount rate is to measure the single amount that, if invested at the measurement date in a portfolio of high-quality debt instruments, would provide the necessary future cash flows to pay the accumulated benefits when due.
·
Expected Long-term Return on Plan Assets - Management projects the long-term rates of return on plan assets based on historical performance, future expectations and periodic portfolio rebalancing among the diversified asset classes. These projected returns reduce the net benefit costs LKE records currently.
·
Rate of Compensation Increase - Management projects employees' annual pay increases, which are used to project employees' pension benefits at retirement.
·
Health Care Cost Trend Rate - Management projects the expected increases in the cost of health care.
In selecting a discount rate for its defined benefit plans LKE starts with a cash flow analysis of the expected benefit payment stream for its plans. In 2010, these plan-specific cash flows were matched against a spot-rate yield curve to determine the assumed discount rate. To develop the spot-rate yield curve, the full universe of Aa-rated non-callable (or callable with make-whole provisions) bonds, served as the base from which those with the lowest and highest yields were eliminated to develop an appropriate subset of bonds from which the ultimate yield curve would be built. At that time, management believed this plan-specific cash flow matching model represented the best available tool for estimating the discount rate. Beginning in 2011, LKE utilized a new tool that enhanced this plan-specific cash flow matching methodology by primarily matching the plan-specific cash flows against the coupons and expected maturity values of individually selected bonds. This bond matching process begins with the same universe of Aa-rated corporate bonds from which those with the lowest and highest yields were eliminated, similar to the yield curve approach. Individual bonds are then selected based on the timing of each plan's cash flows and parameters are established as to the percentage of each individual bond issue that could be hypothetically purchased and the surplus reinvestment rates to be assumed. This process more accurately approximated the process of settlement of the obligations which better aligned with the objective of selecting the discount rate. At December 31, 2011 LKE decreased the discount rate for its pension plans from 5.49% to 5.08% and decreased the discount rate for its other postretirement benefit plan from 5.12% to 4.78%.
The expected long-term rates of return for LKE's defined benefit pension plans and defined other postretirement benefit plan have been developed using a best-estimate of expected returns, volatilities and correlations for each asset class. LKE management corroborates these rates with expected long-term rates of return calculated by its independent actuary, who uses a building block approach that begins with a risk-free rate of return with factors being added such as inflation, duration, credit spreads and equity risk. Each plan's specific asset allocation is also considered in developing a reasonable return assumption. At December 31, 2011, LKE's expected return on plan assets was 7.25%.
In selecting a rate of compensation increase, LKE considers past experience in light of movements in inflation rates. At December 31, 2011, LKE's rate of compensation increase changed from 5.25% to 4.00%.
In selecting health care cost trend rates LKE considers past performance and forecasts of health care costs. At December 31, 2011, LKE's health care cost trend rates were 8.50% for 2012, gradually declining to 5.50% for 2019.
A variance in the assumptions listed above could have a significant impact on accrued defined benefit liabilities or assets, reported annual net periodic defined benefit costs and OCI or regulatory assets and liabilities for LKE. While the charts below reflect either an increase or decrease in each assumption, the inverse of the change would impact the accrued defined benefit liabilities or assets, reported annual net periodic defined benefit costs and OCI or regulatory assets and liabilities for LKE by a similar amount in the opposite direction. The sensitivities below reflect an evaluation of the change based solely on a change in that assumption and does not include income tax effects.
At December 31, 2011, the defined benefit plans were recorded as follows:
(a)
Amount includes current and noncurrent portions.
The following chart reflects the sensitivities in the December 31, 2011 Balance Sheet associated with a change in certain assumptions based on LKE's primary defined benefit plans.
(a)
Only impacts other postretirement benefits.
In 2011, LKE recognized net periodic defined benefit costs charged to operating expense of $51 million. This amount represents a $6 million decrease from 2010. This decrease in expense was primarily attributable to the increase in the expected return on plan assets resulting from the $150 million pension contribution in January 2011.
The following chart reflects the sensitivities in the 2011 Statement of Income (excluding income tax effects) associated with a change in certain assumptions based on LKE's primary defined benefit plans.
(a)
Only impacts other postretirement benefits.
4)
Asset Impairment
Impairment analyses are performed for long-lived assets that are subject to depreciation or amortization whenever events or changes in circumstances indicate that a long-lived asset's carrying value may not be recoverable. For these long-lived assets classified as held and used, such events or changes in circumstances are:
·
a significant decrease in the market price of an asset;
·
a significant adverse change in the extent or manner in which an asset is being used or in its physical condition;
·
a significant adverse change in legal factors or in the business climate;
·
an accumulation of costs significantly in excess of the amount originally expected for the acquisition or construction of an asset;
·
a current-period operating or cash flow loss combined with a history of losses or a forecast that demonstrates continuing losses; or
·
a current expectation that, more likely than not, an asset will be sold or otherwise disposed of significantly before the end of its previously estimated useful life.
For a long-lived asset classified as held and used, impairment is recognized when the carrying amount of the asset is not recoverable and exceeds its fair value. The carrying amount is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. If the asset is impaired, an impairment loss is recorded to adjust the asset's carrying value to its estimated fair value. Management must make significant judgments to estimate future cash flows including the useful lives of long-lived assets, the fair value of the assets and management's intent to use the assets. Alternate courses of action are considered to recover the carrying value of a long-lived asset, and estimated cash flows from the "most likely" alternative are used to assess impairment whenever one alternative is clearly the most likely outcome. If no alternative is clearly the most likely, then a probability-weighted approach is used taking into consideration estimated cash flows from the alternatives. For assets tested for impairment as of the balance sheet date, the estimates of future cash flows used in that test consider the likelihood of possible outcomes that existed at the balance sheet date, including the assessment of the likelihood of a future sale of the assets. That assessment is not revised based on events
that occur after the balance sheet date. Changes in assumptions and estimates could result in significantly different results than those identified and recorded in the financial statements.
For a long-lived asset classified as held for sale, impairment exists when the carrying amount of the asset (disposal group) exceeds its fair value less cost to sell. If the asset (disposal group) is impaired, an impairment loss is recorded to adjust the carrying amount to its fair value less cost to sell. A gain is recognized for any subsequent increase in fair value less cost to sell, but not in excess of the cumulative impairment previously recognized.
For determining fair value, quoted market prices in active markets are the best evidence. However, when market prices are unavailable, LKE considers all valuation techniques appropriate under the circumstances and for which market participant inputs can be obtained. Generally discounted cash flows are used to estimate fair value, which incorporates market participant inputs when available. Discounted cash flows are calculated by estimating future cash flow streams and applying appropriate discount rates to determine the present value of the cash flow streams.
In 2011, LKE did not recognize an impairment of any long-lived assets.
Goodwill is tested for impairment at the reporting unit level. LKE's reporting unit has been determined to be at the operating segment level. A goodwill impairment test is performed annually or more frequently if events or changes in circumstances indicate that the carrying value of the reporting unit may be greater than the unit's fair value. Additionally, goodwill is tested for impairment after a portion of goodwill has been allocated to a business to be disposed of. Goodwill is tested for impairment using a two-step approach. In step 1, LKE identifies a potential impairment by comparing the estimated fair value of LKE (the goodwill reporting unit) to its carrying value, including goodwill, on the measurement date. If the estimated fair value exceeds its carrying amount, goodwill is not considered impaired. If the carrying amount exceeds the estimated fair value, the second step is performed to measure the amount of impairment loss, if any.
The second step requires a calculation of the implied fair value of goodwill which is determined in the same manner as the amount of goodwill in a business combination. That is, the estimated fair value is allocated to all of LKE's assets and liabilities as if LKE had been acquired in a business combination and the estimated fair value of LKE was the price paid. The excess of the estimated fair value of LKE over the amounts assigned to its assets and liabilities is the implied fair value of goodwill. The implied fair value of goodwill is then compared with the carrying amount of that goodwill. If the carrying amount exceeds the implied fair value, an impairment loss is recognized in an amount equal to that excess. The loss recognized cannot exceed the carrying amount of the reporting unit's goodwill.
LKE tested goodwill for impairment in the fourth quarter of 2011 and no impairment was recognized. Management used both discounted cash flows and market multiples to estimate the fair value of LKE, which involved the use of significant estimates and assumptions. Applying an appropriate weighting to both the discounted cash flow and market multiple valuations, a decrease in the forecasted cash flows of 10%, an increase in the discount rate by 25 basis points, or a 10% decrease in the multiples would not have resulted in an impairment of goodwill.
5)
Loss Accruals
Losses are accrued for the estimated impacts of various conditions, situations or circumstances involving uncertain or contingent future outcomes. For loss contingencies, the loss must be accrued if (1) information is available that indicates it is probable that a loss has been incurred, given the likelihood of the uncertain future events and (2) the amount of the loss can be reasonably estimated. Accounting guidance defines "probable" as cases in which "the future event or events are likely to occur." The accrual of contingencies that might result in gains is not recorded unless recovery is assured. Potential loss contingencies for environmental remediation, litigation claims, regulatory penalties and other events are continuously assessed.
The accounting aspects of estimated loss accruals include (1) the initial identification and recording of the loss, (2) the determination of triggering events for reducing a recorded loss accrual and (3) the ongoing assessment as to whether a recorded loss accrual is sufficient. All three of these aspects require significant judgment by management. Internal expertise and outside experts (such as lawyers and engineers) are used, as necessary to help estimate the probability that a loss has been incurred and the amount (or range) of the loss.
In 2011, no significant adjustments were made to LKE's existing contingencies. See Note 15 to the Financial Statements for commitment and contingency disclosures.
Certain other events have been identified that could give rise to a loss, but that do not meet the conditions for accrual. Such events are disclosed, but not recorded, when it is reasonably possible that a loss has been incurred. Accounting guidance defines "reasonably possible" as cases in which "the future event or events occurring is more than remote, but less than likely to occur." See Note 15 to the Financial Statements, for disclosure of other potential loss contingencies that have not met the criteria for accrual.
When an estimated loss is accrued, the triggering events for subsequently adjusting the loss accrual are identified, where applicable. The triggering events generally occur when the contingency has been resolved and the actual loss is paid or written off, or when the risk of loss has diminished or been eliminated. The following are some of the triggering events that provide for the adjustment of certain recorded loss accruals:
·
Allowances for uncollectible accounts are reduced when accounts are written off after prescribed collection procedures have been exhausted, a better estimate of the allowance is determined or underlying amounts are ultimately collected.
·
Environmental and other litigation contingencies are reduced when the contingency is resolved, LKE makes actual payments, a better estimate of the loss is determined or the loss is no longer considered probable.
Loss accruals are reviewed on a regular basis to assure that the recorded potential loss exposures are appropriate. This involves ongoing communication and analyses with internal and external legal counsel, engineers, operation management and other parties.
6)
Asset Retirement Obligations
LKE is required to recognize a liability for legal obligations associated with the retirement of long-lived assets. The initial obligation is measured at its estimated fair value. An equivalent amount is recorded as an increase in the value of the capitalized asset and allocated to expense over the useful life of the asset. Until the obligation is settled, the liability is increased, through the recognition of accretion expense in the Consolidated Statements of Income, for changes in the obligation due to the passage of time. The accretion and depreciation are offset with a regulatory credit on the income statement, such that there is no earnings impact. The regulatory asset created by the regulatory credit is relieved when the ARO has been settled. An ARO must be recognized when incurred if the fair value of the ARO can be reasonably estimated. See Note 21 to the Financial Statements for related disclosures.
In determining AROs, management must make significant judgments and estimates to calculate fair value. Fair value is developed using an expected present value technique based on assumptions of market participants that considers estimated retirement costs in current period dollars that are inflated to the anticipated retirement date and then discounted back to the date the ARO was incurred. Changes in assumptions and estimates included within the calculations of the fair value of AROs could result in significantly different results than those identified and recorded in the financial statements. Estimated ARO costs and settlement dates, which affect the carrying value of various AROs and the related assets, are reviewed periodically to ensure that any material changes are incorporated into the estimate of the obligations. Any change to the capitalized asset is amortized over the remaining life of the associated long-lived asset.
At December 31, 2011, LKE had AROs comprised of current and noncurrent amounts, totaling $118 million recorded on the Balance Sheet. Of the total amount, $74 million, or 63%, relates to LKE's ash ponds, landfills and natural gas mains. The most significant assumptions surrounding AROs are the forecasted retirement costs, the discount rates and the inflation rates. A variance in the forecasted retirement costs, the discount rates or the inflation rates could have a significant impact on the ARO liabilities.
The following chart reflects the sensitivities related to LKE's ARO liabilities for ash ponds, landfills and natural gas mains at December 31, 2011:
7)
Income Taxes
Significant management judgment is required in developing LKE's provision for income taxes primarily due to the uncertainty related to tax positions taken or expected to be taken in tax returns and the determination of deferred tax assets, liabilities and valuation allowances.
Significant management judgment is required to determine the amount of benefit recognized related to an uncertain tax position. LKE evaluates its tax positions following a two-step process. The first step requires an entity to determine whether, based on the technical merits supporting a particular tax position, it is more likely than not (greater than a 50% chance) that the tax position will be sustained. This determination assumes that the relevant taxing authority will examine the tax position and is aware of all the relevant facts surrounding the tax position. The second step requires an entity to recognize in the financial statements the benefit of a tax position that meets the more-likely-than-not recognition criterion. The benefit recognized is measured at the largest amount of benefit that has a likelihood of realization upon settlement that exceeds 50%. LKE's management considers a number of factors in assessing the benefit to be recognized, including negotiation of a settlement.
On a quarterly basis, LKE's uncertain tax positions are reassessed by considering information known at the reporting date. Based on management's assessment of new information, a tax benefit may subsequently be recognized for a previously unrecognized tax position, a previously recognized tax position maybe de-recognized, or the benefit of a previously recognized tax position may be remeasured. The amounts ultimately paid upon resolution of issues raised by taxing authorities may differ materially from the amounts accrued and may materially impact the financial statements in the future.
At December 31, 2011, LKE's existing reserve exposure to either increases or decreases in unrecognized tax benefits during the next 12 months is less than $1 million. This change could result from subsequent recognition, de-recognition and/or changes in the measurement of uncertain tax positions. The events that could cause these changes are direct settlements with taxing authorities, litigation, legal or administrative guidance by relevant taxing authorities and the lapse of an applicable statute of limitation.
The balance sheet classification of unrecognized tax benefits and the need for valuation allowances to reduce deferred tax assets also require significant management judgment. Unrecognized tax benefits are classified as current to the extent management expects to settle an uncertain tax position by payment or receipt of cash within one year of the reporting date. Valuation allowances are initially recorded and reevaluated each reporting period by assessing the likelihood of the ultimate realization of a deferred tax asset. Management considers a number of factors in assessing the realization of a deferred tax asset, including the reversal of temporary differences, future taxable income and ongoing prudent and feasible tax planning strategies. Any tax planning strategy utilized in this assessment must meet the recognition and measurement criteria utilized to account for an uncertain tax position. See Note 5 to the Financial Statements for related disclosures.
8)
Regulatory Assets and Liabilities
LKE's subsidiaries, LG&E and KU, are cost-based rate-regulated utilities. As a result, the effects of regulatory actions are required to be reflected in the financial statements. Assets and liabilities are recorded that result from the regulated ratemaking process that may not be recorded under GAAP for non-regulated entities. Regulatory assets generally represent incurred costs that have been deferred because such costs are probable of future recovery in regulated customer rates. Regulatory liabilities are recognized for amounts expected to be returned through future regulated customer rates. In certain cases, regulatory liabilities are recorded based on an understanding with the regulator that rates have been set to recover costs that are expected to be incurred in the future, and the regulated entity is accountable for any amounts charged pursuant to such rates and not yet expended for the intended purpose. The accounting for regulatory assets and liabilities is based on specific ratemaking decisions or precedent for each transaction or event as prescribed by the FERC, the KPSC, the VSCC and the TRA. See Note 6 to the Financial Statements for related disclosures.
Management continually assesses whether the regulatory assets are probable of future recovery by considering factors such as changes in the applicable regulatory and political environments, the ability to recover costs through regulated rates, recent rate orders to other regulated entities and the status of any pending or potential deregulation legislation. Based on this continual assessment, management believes the existing regulatory assets are probable of recovery. This assessment reflects the current political and regulatory climate at the state and federal levels, and is subject to change in the future. If future recovery of costs ceases to be probable, then asset write-off would be required to be recognized in operating income. Additionally, the regulatory agencies can provide flexibility in the manner and timing of the depreciation of PP&E and amortization of regulatory assets.
At December 31, 2011 and 2010, LKE had regulatory assets of $629 million and $610 million. All regulatory assets are either currently being recovered under specific rate orders, represent amounts that are expected to be recovered in future rates or benefit future periods based upon established regulatory practices. At December 31, 2011 and 2010, LKE had regulatory liabilities of $1,023 million and $1,108 million.
Other Information
PPL's Audit Committee has approved the independent auditor to provide audit, tax and other services permitted by Sarbanes-Oxley and SEC rules. The audit services include services in connection with statutory and regulatory filings, reviews of offering documents and registration statements, and internal control reviews. See "Item 14. Principal Accounting Fees and Services" for more information.
LOUISVILLE GAS AND ELECTRIC COMPANY
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
The information provided in this Item 7 should be read in conjunction with LG&E's Financial Statements and the accompanying Notes. Capitalized terms and abbreviations are explained in the glossary. Dollars are in millions, unless otherwise noted.
"Management's Discussion and Analysis of Financial Condition and Results of Operations" includes the following information:
·
"Overview" provides a description of LG&E and its business strategy. "Financial and Operational Developments" includes a review of Net Income and discusses certain events that are important to understanding LG&E's results of operations and financial condition.
·
"Results of Operations" provides a summary of LG&E's earnings and a description of key factors expected to impact future earnings. This section ends with "Statement of Income Analysis," which includes explanations of significant changes in principal items on LG&E's Statements of Income, comparing 2011, 2010 and 2009.
·
"Financial Condition - Liquidity and Capital Resources" provides an analysis of LG&E's liquidity position and credit profile. This section also includes a discussion of rating agency decisions and capital expenditure projections.
·
"Financial Condition - Risk Management" provides an explanation of LG&E's risk management programs relating to market and credit risk.
·
"Application of Critical Accounting Policies" provides an overview of the accounting policies that are particularly important to the results of operations and financial condition of LG&E and that require its management to make significant estimates, assumptions and other judgments of matters inherently uncertain.
Overview
Introduction
LG&E, headquartered in Louisville, Kentucky, is a regulated utility engaged in the generation, transmission, distribution and sale of electric energy and distribution and sale of natural gas in Kentucky. LG&E and its affiliate, KU, are wholly owned subsidiaries of LKE. LKE, a limited liability company, became a wholly owned subsidiary of PPL when PPL acquired all of LKE's interests from E.ON US Investments Corp. on November 1, 2010. Following the acquisition, both LG&E and KU continue operating as subsidiaries of LKE, which is now an intermediary holding company in PPL's group of companies. Refer to "Item 1. Business - Background" for a description of LG&E's business.
Business Strategy
LG&E's overall strategy is to provide reliable, safe and competitively priced energy to its customers.
A key objective for LG&E is to maintain a strong credit profile through managing financing costs and access to credit markets. LG&E continually focuses on maintaining an appropriate capital structure and liquidity position.
Successor and Predecessor Financial Presentation
LG&E's Financial Statements and related financial and operating data include the periods before and after PPL's acquisition of LKE on November 1, 2010, and have been segregated to present pre-acquisition activity as the Predecessor and post-acquisition activity as the Successor. Predecessor activity covers the time period prior to November 1, 2010. Successor activity covers the time period after October 31, 2010. Certain accounting and presentation methods were changed to acceptable alternatives to conform to PPL's accounting policies, which are discussed in Note 1 to the Financial Statements. The cost bases of certain assets and liabilities were changed as of November 1, 2010, as a result of the application of push-down basis of accounting, which was used to record the fair value adjustments of assets and liabilities at the acquisition date. Consequently, the financial position, results of operations and cash flows for the Successor periods are not comparable to the Predecessor periods; however, the core operations of LG&E have not changed as a result of the acquisition.
Financial and Operational Developments
Net Income
The operating results for 2011 and 2010 include the effect of LG&E's base rate increases, which became effective August 1, 2010, partially offset by net cost increases, which have not yet been reflected in the rates charged by LG&E. The operating results for the ten months ended October 31, 2010 also include $19 million of other income associated with the establishment of regulatory assets for previously recorded losses on interest rate swaps. The operating results for 2009 were impacted by $18 million of derivative gains.
See "Results of Operations" below for further discussion and analysis of the results of operations.
TC2
LG&E and KU constructed a 732 MW summer capacity coal-fired unit, TC2, which is jointly owned by LG&E (14.25%) and KU (60.75%), together with the Illinois Municipal Electric Agency and the Indiana Municipal Power Agency (combined 25%). With limited exceptions, LG&E and KU took care, custody and control of TC2 in January 2011. LG&E and KU and the construction contractor further amended the construction agreement to provide that the contractor will complete certain actions to identify and complete any necessary modifications to allow operation of TC2 on all fuels in accordance with initial specifications prior to certain dates, and amending the provisions relating to liquidated damages. A number of remaining issues regarding these matters are still under discussion with the contractor. See Notes 8 and 15 to the Financial Statements for additional information.
Registered Debt Exchange Offer by LG&E
In April 2011, LG&E filed a Registration Statement with the SEC, related to an offer to exchange certain first mortgage bonds issued in November 2010, in transactions not subject to registration under the Securities Act of 1933, with similar but registered securities. The 2011 Registration Statement became effective in June 2011, and the exchange was completed in July 2011 with all of the first mortgage bonds being exchanged. See Note 7 to the Financial Statements and LG&E's 2011 Registration Statement for additional information.
CSAPR
In July 2011, the EPA signed the CSAPR, which finalizes and renames the Clean Air Transport Rule (Transport Rule) proposed in August 2010, and made revisions to the rule on February 7, 2012. This rule applies to the Kentucky coal plants. The CSAPR is meant to facilitate attainment of ambient air quality standards for ozone and fine particulates by requiring reductions in sulfur dioxide and nitrogen oxide emissions.
In December 2011, the U.S. Court of Appeals for the District of Columbia (Court) stayed implementation of the CSAPR and left CAIR in effect pending a final resolution on the merits of the validity of the rule. Oral argument on the various challenges to the CSAPR is scheduled for April 2012, and a final decision on the validity of the rule could be issued as early as May 2012.
With respect to LG&E's coal-fired generating plants, the stay of the CSAPR will initially only impact the unit dispatch order. With the return of the CAIR and LG&E's significant number of sulfur dioxide allowances, those units will be dispatched with lower operating cost, but slightly higher sulfur dioxide and nitrogen oxide emissions. However, a key component of the Court's final decision, even if the CSAPR is upheld, will be whether the ruling delays the implementation of the CSAPR by one year for both Phases I and II, or instead still requires the significant sulfur dioxide and nitrogen oxide reductions associated with Phase II to begin in 2014. LG&E's CSAPR compliance strategy is based on over-compliance during Phase I to generate allowances sufficient to cover the expected shortage during the first two years of Phase II (2014 and 2015) when additional pollution control equipment will be installed. Should Phase I of the CSAPR be shortened to one year, it will be more difficult and costly to provide enough excess allowances in one year to meet the shortage projected for 2014 and 2015.
See Note 15 to the Financial Statements for additional information on the CSAPR.
Pending Bluegrass CTs Acquisition and NGCC Construction
In September 2011, LG&E and KU filed a CPCN with the KPSC requesting approval to build a 640 MW NGCC at the existing Cane Run plant site. In conjunction with this request and to meet new, stricter EPA regulations, LG&E anticipates retiring three older coal-fired electric generating units, located at the Cane Run plant, which have a combined summer rating of 563 MW. LG&E and KU also requested approval to purchase the Bluegrass CTs, which are expected to provide up to 495 MW of peak generation supply.
LG&E anticipates that its share of the NGCC construction and the acquisition of the Bluegrass CTs could require up to $300 million in capital costs including related transmission projects. Formal requests for recovery of the costs associated with the NGCC construction and the acquisition of the Bluegrass CTs were not included in the CPCN filing with the KPSC but are expected to be included in future rate proceedings. The KPSC issued an Order on the procedural schedule in the CPCN filing that has discovery, scheduled through early February 2012. A KPSC order on the CPCN filing is anticipated in the second quarter of 2012. See Note 8 to the Financial Statements for additional information.
ECR Filing - Environmental Upgrades
In June 2011, in order to achieve compliance with new and pending mandated federal EPA regulations, LG&E filed an ECR plan with the KPSC requesting approval to install environmental upgrades for certain of its coal-fired plants along with the recovery of the expected $1.4 billion in associated capital costs, as well as operating expenses incurred. The ECR plan detailed upgrades that will be made to certain of LG&E's coal-fired generating plants to continue to be compliant with EPA regulations.
In November 2011, LG&E filed a unanimous settlement agreement, stipulation and recommendation with the KPSC. In December 2011, LG&E received KPSC approval in its proceedings relating to the ECR plan. The KPSC Order approved the terms of the November 2011 settlement agreement entered into between LG&E and the parties to the ECR proceedings. The KPSC Order authorized the installation of environmental upgrades at certain plants during 2012-2016 representing approximate capital costs of $1.4 billion at LG&E. In connection with the approved projects, the KPSC Order allows recovery through the ECR rate mechanism of the capital costs and operating expenses of the projects and granted CPCN for their construction. The KPSC Order also confirmed an existing 10.63% authorized return on equity for projects remaining from earlier ECR plans and provided for an authorized return on equity of 10.10% for the approved projects in the 2011 ECR proceedings. See Note 6 to the Financial Statements for additional information.
Storm Recovery
In August 2011, a strong storm hit LG&E's service area causing significant damage and widespread outages for approximately 139,000 customers. LG&E filed an application with the KPSC in September 2011 requesting approval of a regulatory asset recorded to defer, for future recovery, $8 million in incremental operation and maintenance expenses related to the storm restoration. An Order was received in December 2011 granting regulatory accounting treatment, while recovery of the regulatory asset will be determined within the next base rate case.
In September 2009, the KPSC approved the deferral of $44 million of costs associated with a severe ice storm that occurred in January 2009 and a wind storm that occurred in February 2009. Additionally, in December 2008, the KPSC approved the deferral of $24 million of costs associated with high winds from the remnants of Hurricane Ike in September 2008. LG&E received approval in its 2010 base rate case to recover these regulatory assets over a ten-year period beginning August 2010.
Results of Operations
As previously noted, LG&E's results for the time periods after October 31, 2010 are on a basis of accounting different from its results for time periods prior to November 1, 2010. When discussing LG&E's results of operations material differences resulting from the different basis of accounting will be isolated for purposes of comparability. See "Overview - Successor and Predecessor Financial Presentation" for further information.
The utility business is affected by seasonal weather. As a result, operating revenues (and associated operating expenses) are not generated evenly throughout the year. Revenue and earnings are generally higher during the first and third quarters and lower during the second quarter due to weather.
The following table summarizes the significant components of net income for 2011, 2010, and 2009 and the changes therein:
Earnings
The changes in the components of Net Income between these periods were due to the following factors. The results are adjusted for certain items that management considers special. See additional detail of this special item below.
The net unrealized gains (losses) on contracts that economically hedge anticipated cash flows are considered special items by management. The after-tax amounts for 2011 and for 2010 were insignificant.
·
See "Statement of Income Analysis - Margin - Changes in Non-GAAP Financial Measures" for an explanation of margin.
·
Other operation and maintenance increased in 2011 compared with 2010, primarily due to higher distribution maintenance costs of $8 million and higher administrative and general costs of $4 million. Distribution maintenance costs increased due to amortization of storm restoration related costs, together with a hazardous tree removal project initiated in August 2010.
Other operation and maintenance increased in 2010 compared with 2009, primarily due to higher steam maintenance costs of $9 million, administrative and general costs of $4 million, other generation maintenance costs of $3 million, and transmission operation costs of $2 million. Steam maintenance costs increased due to higher boiler and electric maintenance costs related to outage work.
·
Depreciation expense was $7 million higher in 2011 compared with 2010, due to TC2 commencing dispatch in January 2011.
·
Other Income (Expense) - net decreased in 2011 compared with 2010, primarily due to $19 million of other income from the establishment of a regulatory asset for previously recorded losses on interest rate swaps in 2010.
·
Income taxes increased in 2010 compared with 2009, primarily due to the $21 million impact of higher pre-tax income.
2012 Outlook
LG&E projects lower earnings in 2012 compared with 2011, as revenue increases are not expected to offset operating expense increases, including depreciation, due to more plant in service. Actual results will be dependent on the effects of the economy and the impact of weather on retail sales among other variables. As a result of the stay out provision established in the settlement of the PPL-LKE acquisition, LG&E is generally unable to implement an increase in its base rates before January 1, 2013.
Earnings in 2012 are subject to various risks and uncertainties. See "Forward-Looking Information," the rest of this Item 7, Notes 6 and 15 to the Financial Statements and "Business," and "Risk Factors" in this Form 10-K for a discussion of the risks, uncertainties and factors that may impact future earnings.
Statement of Income Analysis --
Margin
Non-GAAP Financial Measure
The following discussion includes financial information prepared in accordance with GAAP, as well as a non-GAAP financial measure, "Margin." Margin is not intended to replace "Operating Income," which is determined in accordance with GAAP as an indicator of overall operating performance. Other companies may use different measures to analyze and to report on the results of their operations. Margin is a single financial performance measure of LG&E's operations. In calculating this measure, utility revenues and expenses associated with approved cost recovery tracking mechanisms are offset. These mechanisms allow for recovery of certain expenses, returns on capital investments associated with environmental regulations and performance incentives. Certain costs associated with these mechanisms, primarily ECR and DSM, are recorded as "Other operation and maintenance" expenses and the depreciation associated with ECR equipment is recorded as "Depreciation" expense. As a result, this measure represents the net revenues from LG&E's operations. This performance measure is used, in conjunction with other information, internally by senior management to manage operations and analyze actual results compared with budget.
Reconciliation of Non-GAAP Financial Measures
The following tables reconcile "Operating Income" to "Margin" as defined by LG&E for 2011, 2010 and 2009.
(a)
Represents amounts excluded from Margin.
(b)
As reported on the Statements of Income.
Changes in Non-GAAP Financial Measures
Margins were higher by $39 million for 2011 compared with 2010. New KPSC rates went into effect on August 1, 2010, contributing an additional $48 million in operating revenue over the prior year. Partially offsetting the rate increase were lower retail volumes resulting from weather and economic conditions.
(a)
Fuel handling costs are included in fuel for electric generation on the Statements of Income for the Successor's periods and are in other operation and maintenance expense on the Statements of Income for the Predecessor's periods.
(b)
Distribution maintenance costs increased in 2011 compared with 2010, primarily due to amortization of storm restoration-related costs along with a hazardous tree removal project initiated in August 2010 and an increase in pipeline integrity work.
(c)
Steam maintenance costs decreased in 2011 compared with 2010, primarily due to the timing of scheduled maintenance outages and non-outage boiler maintenance.
Steam maintenance costs increased in 2010 compared with 2009, primarily due to higher boiler and electric maintenance costs related to outage work.
Depreciation
Changes in depreciation were due to the following:
Taxes, Other Than Income
Taxes, other than income increased by $5 million in 2011 compared with 2010 primarily due to a $4 million state coal tax credit that was applied to 2010 property taxes. The remaining increase was due to higher assessments, primarily from significant property additions.
Other Income (Expense) - net
Changes in other income (expense) - net were due to the following:
(a)
Net derivative gains and losses includes the unrealized gains and losses on interest rate swaps not designated as hedging instruments and the ineffective portion of interest rate swaps designated and qualifying as a cash flow hedge.
(b)
Other income in 2010 resulted from the establishment of a regulatory asset for previously recorded losses on interest rate swaps, which is included in "Net derivative gains and losses" within Note 17 to the Financial Statements.
Interest Expense
The changes in interest expense were due to:
(a)
Interest rates on the first mortgage bonds issued in November 2010 were lower than the rates on the loans from Fidelia Corporation in place through October 2010.
(b)
LG&E's long-term debt principal balance was $213 million higher as of December 31, 2010 compared with December 31, 2009 and did not change as of December 31, 2010 compared with December 31, 2011. The higher interest expense in 2011 was the result of lower long-term debt balances for the first ten months of 2010.
Financial Condition
Liquidity and Capital Resources
LG&E expects to continue to have adequate liquidity available through operating cash flows, cash and cash equivalents and its credit facilities.
LG&E's cash flows from operations and access to cost-effective bank and capital markets are subject to risks and uncertainties including, but not limited to:
·
changes in market prices for electricity;
·
changes in commodity prices that may increase the cost of producing power or decrease the amount LG&E receives from selling power;
·
operational and credit risks associated with selling and marketing products in the wholesale power markets;
·
unusual or extreme weather that may damage LG&E's transmission and distribution facilities or affect energy sales to customers;
·
reliance on transmission and distribution facilities that LG&E does not own or control to deliver its electricity and natural gas;
·
unavailability of generating units (due to unscheduled or longer-than-anticipated generation outages, weather and natural disasters) and the resulting loss of revenues and additional costs of replacement electricity;
·
the ability to recover and the timeliness and adequacy of recovery of costs associated with regulated utility businesses;
·
costs of compliance with existing and new environmental laws;
·
any adverse outcome of legal proceedings and investigations with respect to LG&E's current and past business activities;
·
deterioration in the financial markets that could make obtaining new sources of bank and capital markets funding more difficult and more costly; and
·
a downgrade in LG&E's credit ratings that could adversely affect its ability to access capital and increase the cost of credit facilities and any new debt.
See "Item 1A. Risk Factors" for further discussion of risks and uncertainties affecting LG&E's cash flows.
At December 31, LG&E had the following:
(a)
Represents tax-exempt bonds issued by Louisville/Jefferson County, Kentucky, on behalf of LG&E that were purchased from the remarketing agent in 2008. Such bonds were remarketed to unaffiliated investors in January 2011. See Note 7 to the Financial Statements for additional information.
(b)
Represents borrowings under LG&E's $400 million syndicated credit facility. See Note 7 to the Financial Statements for additional information.
The changes in LG&E's cash and cash equivalents position resulted from:
Auction Rate Securities
At December 31, 2011, LG&E's tax-exempt revenue bonds that are in the form of auction rate securities and total $135 million continue to experience failed auctions. Therefore, the interest rate continues to be set by a formula pursuant to the relevant indentures. For the period ended December 31, 2011, the weighted-average rate on LG&E's auction rate bonds in total was 0.24%.
See Note 7 to the Financial Statements for additional information about long-term debt securities.
Operating Activities
Net cash provided by operating activities increased by 77%, or $140 million, in 2011 compared with 2010, primarily as a result of:
·
a decrease in working capital related to accounts receivable and unbilled revenues of $87 million primarily due to the timing of cash receipts and colder weather in December 2010 as compared with December 2009 and milder weather in December 2011 as compared with December 2010;
·
an increase in net income adjusted for non-cash effects of $33 million (the recording of a regulatory asset for previously recorded losses on interest rate swaps of $22 million, deferred income taxes and investment tax credits of $17 million, depreciation of $9 million and other noncash items of $6 million, partially offset by unrealized (gains) losses on derivatives of $14 million and defined benefit plans - expense of $3 million);
·
a decrease in cash outflows of $32 million due to lower inventory levels in 2011 as compared with 2010 driven by $21 million due to lower coal burn as a result of unplanned outages at the Mill Creek plant, $8 million for fuel inventory purchased in 2010 for TC2 that was not used until 2011 when TC2 began dispatch and $6 million for decreases in gas storage volumes;
·
a decrease in cash refunded to customers of $25 million due to prior period over-recoveries related to the gas supply clause filings in 2009; and
·
a decrease in cash outflows related to accrued taxes of $22 million due to the timing of payments of accrued tax liabilities in 2011 and 2010; partially offset by
·
an increase in discretionary defined benefit plan contributions of $44 million made in order to achieve LG&E's long-term funding requirements; and
·
an increase in working capital related to accounts payable of $41 million, which was driven primarily by the timing of cash payments and a decrease in natural gas purchases of $18 million in 2011 as compared with 2010 due to a decrease in combustion turbine generation as a result of the dispatch of TC2 beginning in January 2011.
Net cash provided by operating activities decreased by 41%, or $128 million, in 2010 compared with 2009, primarily as a result of:
·
an increase in working capital related to accounts receivable and unbilled revenues of $101 million primarily due to the timing of cash receipts and colder weather in December 2009 as compared with December 2008 and colder weather in December 2010 as compared with December 2009;
·
an increase in cash outflows related to inventory of $57 million, primarily due to a nominal decrease in the market price of natural gas in 2010 and a significant decrease in the market price of natural gas in 2009;
·
an increase in cash refunded to customers of $55 million due to prior period over-recoveries related to the gas supply clause filings;
·
higher interest payments of $14 million due to an accelerated settlement with E.ON AG; and
·
an increase in discretionary defined benefit plan contributions of $11 million made in order to achieve LG&E's long-term funding requirements; partially offset by
·
an increase in net income adjusted for non-cash effects of $80 million (unrealized (gains) losses on derivatives of $47 million, deferred income taxes and investment tax credits of $19 million, depreciation of $2 million and other noncash items of $10 million, partially offset by the recording of a regulatory asset for previously recorded losses on interest rate swaps of $22 million and defined benefit plans - expense of $9 million);
·
lower storm expenses of $45 million; and
·
a decrease in cash outflows related to accrued taxes of $26 million due to the timing of payments of accrued tax liabilities in 2010 and 2009.
Investing Activities
The primary use of cash in investing activities in 2011, 2010 and 2009 was capital expenditures. See "Forecasted Uses of Cash" for detail regarding projected capital expenditures for the years 2012 through 2016.
Net cash used in investing activities decreased by 78%, or $132 million, in 2011 compared with 2010, as a result of:
·
proceeds from the sale of other investments of $163 million in 2011 and
·
a decrease in capital expenditures of $28 million due primarily to TC2 being dispatched in 2011, partially offset by
·
proceeds from the sale of assets of $48 million in 2010 and
·
a decrease in restricted cash of $11 million.
Net cash used in investing activities decreased by 3%, or $6 million, in 2010 compared with 2009, as a result of:
·
an increase in proceeds from the sale of assets of $45 million and
·
an increase in restricted cash of $2 million in 2010, partially offset by
·
an increase in capital expenditures of $34 million, primarily due to higher expenditures related to large-scale main replacements and the Ohio Falls redevelopment, partially offset by lower expenditures related to the construction of TC2 and major storm events that occurred in 2009, and
·
proceeds on the settlement of derivatives of $7 million in 2009.
Financing Activities
Net cash used in financing activities was $260 million, in 2011 compared with $14 million in 2010, primarily as a result of changes in short-term debt.
In 2011, cash used in financing activities consisted of:
·
a repayment on a revolving line of credit of $163 million;
·
the payment of common stock dividends to LKE of $83 million;
·
a net decrease in notes payable with affiliates of $12 million; and
·
the payment of debt issuance and credit facility costs of $2 million.
Net cash used in financing activities was $14 million in 2010 compared with $132 million in 2009, primarily as a result of new long-term debt issued in excess of retirements, lower dividend payments and less repayment of notes payable with affiliates.
In the two months of 2010 following PPL's acquisition of LKE, cash provided by financing activities of the Successor consisted of:
·
the issuance of first mortgage bonds of $531 million after discounts;
·
the issuance of debt of $485 million to a PPL affiliate to repay debt due to an E.ON AG affiliate upon the closing of PPL's acquisition of LKE; and
·
a draw on a revolving line of credit of $163 million; partially offset by
·
the repayment of debt to an E.ON AG affiliate of $485 million upon the closing of PPL's acquisition of LKE;
·
the repayment of debt to a PPL affiliate of $485 million upon the issuance of first mortgage bonds;
·
a net decrease in notes payable with affiliates of $130 million; and
·
the payment of debt issuance and credit facility costs of $10 million.
In the ten months of 2010 preceding PPL's acquisition of LKE, cash used in financing activities by the Predecessor consisted of:
·
the payment of common stock dividends to LKE of $55 million and
·
a net decrease in notes payable with affiliates of $28 million.
In 2009, cash used in financing activities by the Predecessor consisted of:
·
the payment of common stock dividends to LKE of $80 million and
·
a net decrease in notes payable with affiliates of $52 million.
See "Forecasted Sources of Cash" for a discussion of LG&E's plans to issue debt securities, as well as a discussion of credit facility capacity available to LG&E. Also see "Forecasted Uses of Cash" for a discussion of plans to pay dividends on common securities in the future, as well as maturities of long-term debt.
LG&E's long-term debt securities activity through December 31, 2011 was:
(a)
Issuances are net of pricing discounts, where applicable and exclude the impact of debt issuance costs.
(b)
In April 2011, LG&E filed a 2011 Registration Statement with the SEC related to offers to exchange securities issued in November 2010 in transactions not registered under the Securities Act of 1933 with similar but registered securities. The registration became effective in June 2011, and the exchanges were completed in July 2011 with all securities being exchanged.
See Note 7 to the Financial Statements for additional information about long-term debt securities.
Forecasted Sources of Cash
LG&E expects to continue to have sufficient sources of cash available in the near term, including various credit facilities and operating cash flow. LG&E expects to remarket $194 million of tax-exempt bonds that will be put back to LG&E in 2012. In February 2012, LG&E established a commercial paper program for up to $250 million to provide an additional financing source to fund its short-term liquidity needs. Commercial paper issuances will be supported by LG&E's Syndicated Credit Facility.
Credit Facilities
At December 31, 2011, LG&E's total committed borrowing capacity under its Syndicated Credit Facility and the use of this borrowing capacity were:
(a)
In June 2011, LG&E amended its Syndicated Credit Facility such that the fees and the spread to benchmark interest rates for borrowings depend upon LG&E's senior secured long-term debt rating rather than the senior unsecured debt rating. Total borrowings outstanding under this facility decreased on a net basis by $163 million since December 31, 2010.
(b)
In October 2011, LG&E amended its Syndicated Credit Facility. The amendment included extending the expiration date from December 2014 to October 2016. Under this facility LG&E continues to have the ability to make cash borrowings and to request the lenders to issue letters of credit.
The commitments under LG&E's Syndicated Credit Facility are provided by a diverse bank group, with no one bank and its affiliates providing an aggregate commitment of more than 5% of the total committed capacity available to LG&E.
LG&E participates in an intercompany money pool agreement whereby LKE and/or KU make available to LG&E funds up to $500 million at an interest rate based on a market index of commercial paper issues. At December 31, 2011, there was no balance outstanding. At December 31, 2010, $12 million was outstanding. The interest rate for the period ended December 31, 2010 was 0.25%.
See Note 7 to the Financial Statements for further discussion of LG&E's credit facilities.
Operating Leases
LG&E also has available funding sources that are provided through operating leases. LG&E leases office space, gas storage and certain equipment. These leasing structures provide LG&E additional operating and financing flexibility. The operating leases contain covenants that are typical for these agreements, such as maintaining insurance, maintaining corporate existence and timely payment of rent and other fees.
See Note 11 to the Financial Statements for further discussion of the operating leases.
Forecasted Uses of Cash
In addition to expenditures required for normal operating activities, such as purchased power, payroll, fuel and taxes, LG&E currently expects to incur future cash outflows for capital expenditures, various contractual obligations, payment of dividends on its common securities and possibly the purchase or redemption of a portion of debt securities.
Capital Expenditures
The table below shows LG&E's current capital expenditure projections for the years 2012 through 2016.
(a)
Includes approximately $200 million of currently estimable costs related to replacement generation units due to EPA regulations not recoverable through the ECR mechanism. LG&E expects to recover these costs over a period equivalent to the related depreciable lives of the assets through future rate proceedings.
(b)
Includes approximately $70 million of currently estimable transmission costs related to replacement generation units. LG&E expects to recover these costs over a period equivalent to the related depreciable lives of the assets through future rate proceedings.
LG&E's capital expenditure projections for the years 2012 through 2016 total approximately $3.2 billion. Capital expenditure plans are revised periodically to reflect changes in operational, market and regulatory conditions. This table includes current estimates for LG&E's environmental projects related to new and anticipated EPA compliance standards. Actual costs may be significantly lower or higher depending on the final requirements and market conditions. Certain environmental compliance costs incurred by LG&E in serving KPSC jurisdictional customers are generally eligible for recovery through the ECR mechanism.
LG&E plans to fund its capital expenditures in 2012 with cash on hand, cash from operations and short-term debt.
Contractual Obligations
LG&E has assumed various financial obligations and commitments in the ordinary course of conducting its business. At December 31, 2011, the estimated contractual cash obligations of LG&E were:
(a)
Reflects principal maturities only based on stated maturity dates. See Note 7 to the Financial Statements for a discussion of variable-rate remarketable bonds issued on behalf of LG&E. LG&E does not have any significant capital lease obligations.
(b)
Assumes interest payments through stated maturity. The payments herein are subject to change, as payments for debt that is or becomes variable-rate debt have been estimated.
(c)
See Note 11 to the Financial Statements for additional information.
(d)
Represents contracts to purchase coal, natural gas and natural gas transportation. See Note 15 to the Financial Statements for additional information.
(e)
Represents future minimum payments under OVEC power purchase agreements through June 2040. See Note 15 to the Financial Statements for additional information.
(f)
Represents construction commitments, including commitments for the Ohio Falls refurbishment construction including associated material transport systems for coal combustion residuals, which are also reflected in the Capital Expenditures table presented above.
(g)
Based on the current funded status of LKE's qualified pension plan, which covers LG&E employees, no cash contributions are required. See Note 13 to the Financial Statements for a discussion of expected contributions.
(h)
Represents other contractual obligations. Purchase orders made in the ordinary course of business are excluded from the amounts presented.
Dividends
From time to time, as determined by its Board of Directors, LG&E pays dividends to its sole shareholder, LKE.
As discussed in Note 7 to the Financial Statements, LG&E's ability to pay dividends is limited under a covenant in its $400 million revolving line of credit facility. This covenant restricts the debt to total capital ratio to not more than 70%.
Purchase or Redemption of Debt Securities
LG&E will continue to evaluate purchasing or redeeming outstanding debt securities and may decide to take action depending upon prevailing market conditions and available cash.
Rating Agency Decisions
Moody's, S&P and Fitch periodically review the credit ratings on the debt securities of LG&E. Based on their respective independent reviews, the rating agencies may make certain ratings revisions or ratings affirmations.
A credit rating reflects an assessment by the rating agency of the creditworthiness associated with an issuer and particular securities that it issues. The credit ratings of LG&E are based on information provided by LG&E and other sources. The ratings of Moody's, S&P and Fitch are not a recommendation to buy, sell or hold any securities of LG&E. Such ratings may be subject to revisions or withdrawal by the agencies at any time and should be evaluated independently of each other and any other rating that may be assigned to the securities. A downgrade in LG&E's credit ratings could result in higher borrowing costs and reduced access to capital markets.
In LG&E's 2011 Registration Statement, LG&E described its then-current credit ratings in connection with, and to facilitate, an understanding of its liquidity position. As a result of the passage of the Dodd-Frank Act and the attendant uncertainties relating to the extent to which issuers of non-asset backed securities may disclose credit ratings without being required to obtain rating agency consent to the inclusion of such disclosure, or incorporation by reference of such disclosure, in a registrant's registration statement or section 10(a) prospectus, LG&E is limiting its credit rating disclosure to a description of the actions taken by the rating agencies with respect to LG&E's ratings, but without stating what ratings have been assigned to LG&E's securities. The ratings assigned by the rating agencies to LG&E and its securities may be found, without charge, on each of the respective ratings agencies' websites, which ratings together with all other information contained on such rating agency websites is, hereby, explicitly not incorporated by reference in this report.
Following the announcement of PPL's then-pending acquisition of WPD Midlands in March 2011, the rating agencies took the following actions:
· Moody's affirmed its ratings for LG&E;
· S&P revised the outlook and lowered the issuer, senior secured and short-term ratings of LG&E; and
· Fitch affirmed its ratings for LG&E.
In April 2011, S&P took the following actions following the completion of PPL's acquisition of WPD Midlands:
· revised the outlook for LG&E;
· raised its short-term ratings of LG&E; and
· affirmed its long-term ratings for LG&E.
In September 2011, Moody's affirmed its issuer rating for LG&E.
In November 2011, Moody's and S&P affirmed their ratings for LG&E.
In December 2011, Fitch affirmed its ratings for LG&E.
Ratings Triggers
LG&E has various derivative and non-derivative contracts, including contracts for the sale and purchase of electricity, fuel, commodity transportation and storage and interest rate instruments, which contain provisions requiring LG&E to post additional collateral, or permitting the counterparty to terminate the contract, if LG&E's credit rating were to fall below investment grade. See Note 19 to the Financial Statements for a discussion of "Credit Risk-Related Contingent Features," including a discussion of the potential additional collateral that would have been required for derivative contracts in a net liability position at December 31, 2011. At December 31, 2011, if LG&E's credit ratings had been below investment grade, the maximum amount that LG&E would have been required to post as additional collateral to counterparties was $64 million for both derivative and non-derivative commodity and commodity-related contracts used in its generation and marketing operations, gas supply and interest rate contracts.
Off-Balance Sheet Arrangements
LG&E has entered into certain agreements that may contingently require payment to a guaranteed or indemnified party. See Note 15 to the Financial Statements for a discussion of these agreements.
Risk Management
Market Risk
LG&E is exposed to market risk from equity instruments, interest rate instruments and commodity instruments, as discussed below. However, regulatory cost recovery mechanisms significantly mitigate those risks. See Notes 1, 18 and 19 to the Financial Statements for information about LG&E's risk management objectives, valuation techniques and accounting designations.
The forward-looking information presented below provides estimates of what may occur in the future, assuming certain adverse market conditions and model assumptions. Actual future results may differ materially from those presented. These disclosures are not precise indicators of expected future losses, but only indicators of possible losses under normal market conditions at a given confidence level.
Commodity Price Risk (Non-trading)
LG&E's rates are set by regulatory commissions and the fuel costs incurred are directly recoverable from customers. As a result, LG&E is subject to commodity price risk for only a small portion of on-going business operations. LG&E conducts energy trading and risk management activities to maximize the value of the physical assets at times when the assets are not required to serve LG&E's or KU's customers. LG&E managed its energy commodity risk using derivative instruments, including swaps and forward contracts. See Note 19 to the Financial Statements for additional disclosures.
The balance and change in net fair value of LG&E's commodity derivative contracts for the periods ended December 31, 2011, 2010, and 2009 are shown in the table below.
(a)
Represents the change in value of outstanding transactions and the value of transactions entered into and settled during the period.
Interest Rate Risk
LG&E has issued debt to finance its operations, which exposes it to interest rate risk. LG&E utilizes various financial derivative instruments to adjust the mix of fixed and floating interest rates in its debt portfolio when appropriate. Risk limits under LG&E's risk management program are designed to balance risk, exposure to volatility in interest expense and changes in the fair value of LG&E's debt portfolio due to changes in the absolute level of interest rates.
At December 31, 2011 and 2010, LG&E's potential annual exposure to increased interest expense, based on a 10% increase in interest rates, was not significant.
LG&E is also exposed to changes in the fair value of its debt portfolio. LG&E estimated that a 10% decrease in interest rates at December 31, 2011, would increase the fair value of its debt portfolio by $27 million. This estimate is unchanged from December 31, 2010.
(a)
Includes accrued interest.
(b)
LG&E utilizes various risk management instruments to reduce its exposure to the expected future cash flow variability of its debt instruments. These risks include exposure to adverse interest rate movements for outstanding variable rate debt and for future anticipated financing. While LG&E is exposed to changes in the fair value of these instruments, any realized changes in the fair value of such economic hedges are recoverable through regulated rates and any subsequent changes in fair value of these derivatives are included in regulatory assets or liabilities. Sensitivities represent a 10% adverse movement in interest rates. The positions outstanding at December 31, 2011 mature through 2033.
Credit Risk
LG&E is exposed to potential losses as a result of nonperformance by counterparties of their contractual obligations. LG&E maintains credit policies and procedures to limit counterparty credit risk including evaluating credit ratings and financial information along with having certain counterparties post margin if the credit exposure exceeds certain thresholds. LG&E is exposed to potential losses as a result of nonpayment by customers. LG&E maintains an allowance for doubtful accounts based on a historical charge-off percentage for retail customers. Allowances for doubtful accounts from wholesale customers and miscellaneous receivables are based on specific identification by management. Retail and wholesale customer accounts are written-off after four months of no payment activity. Miscellaneous receivables are written-off as management determines them to be uncollectible.
Certain of LG&E's derivative instruments contain provisions that require it to provide immediate and on-going collateralization of derivative instruments in net liability positions based upon LG&E's credit ratings from each of the major credit rating agencies. See Notes 18 and 19 to the Financial Statements for information regarding exposure and the risk management activities.
Related Party Transactions
LG&E is not aware of any material ownership interest or operating responsibility by senior management in outside partnerships, including leasing transactions with variable interest entities or other entities doing business with LG&E. See Note 16 to the Financial Statements for additional information on related party transactions between LG&E and affiliates.
Environmental Matters
Protection of the environment is a major priority for LG&E and a significant element of its business activities. Extensive federal, state and local environmental laws and regulations are applicable to LG&E's air emissions, water discharges and the management of hazardous and solid waste, among other areas, and the costs of compliance or alleged non-compliance cannot be predicted with certainty but could be material. In addition, costs may increase significantly if the requirements or scope of environmental laws or regulations, or similar rules, are expanded or changed from prior versions by the relevant agencies. Costs may take the form of increased capital or operating and maintenance expenses; monetary fines, penalties or forfeitures or other restrictions. Many of these environmental law considerations are also applicable to the operations of key suppliers, or customers, such as coal producers, industrial power users, etc.; and may impact the costs for their products or their demand for LG&E's services. See "Item 1. Business - Environmental Matters" and Note 15 to the Financial Statements for a discussion of environmental matters.
New Accounting Guidance
See Note 24 to the Financial Statements for a discussion of new accounting guidance pending adoption.
Application of Critical Accounting Policies
Financial condition and results of operations are impacted by the methods, assumptions and estimates used in the application of critical accounting policies. The following accounting policies are particularly important to the financial condition or results of operations, and require estimates or other judgments of matters inherently uncertain. Changes in the estimates or other judgments included within these accounting policies could result in a significant change to the information presented in the Financial Statements (these accounting policies are also discussed in Note 1 to the Financial Statements). LG&E's senior management has reviewed these critical accounting policies, the following disclosures regarding their application and the estimates and assumptions regarding them, with PPL's Audit Committee.
1)
Revenue Recognition - Unbilled Revenue
Revenues related to the sale of energy are recorded when service is rendered or when energy is delivered to customers. Because customers of LG&E's retail operations are billed on cycles which vary based on the timing of the actual reading of their electric and gas meters, LG&E records estimates for unbilled revenues at the end of each reporting period. Such unbilled revenue amounts reflect estimates of the amount of energy delivered to customers since the date of the last reading of their meters. Such unbilled revenues reflect consideration of estimated usage by customer class, the effect of different rate schedules, changes in weather and where applicable, the impact of weather normalization or other regulatory provisions of rate structures. In addition to the unbilled revenue accrual resulting from cycle billing, LG&E makes additional accruals resulting from the timing of customer bills. The accrual of unbilled revenues in this manner properly matches revenues and related costs. At December 31, 2011 and 2010 LG&E had unbilled revenue balances of $65 million and $81 million.
2)
Price Risk Management
See "Financial Condition - Risk Management" above.
3)
Defined Benefits
LG&E sponsors and participates in qualified funded defined benefit pension plans and participates in a funded other postretirement benefit plan. These plans are applicable to the majority of the employees of LG&E. The plans LG&E participates in are sponsored by LKE. LKE allocates a portion of the liability and net periodic defined benefit pension and other postretirement costs of certain plans to LG&E based on its participation. LG&E records an asset or liability to recognize the funded status of all defined benefit plans with an offsetting entry to regulatory assets or liabilities. Consequently, the funded status of all defined benefit plans is fully recognized on the Balance Sheets. See Note 13 to the Financial Statements for additional information about the plans and the accounting for defined benefits.
Certain assumptions are made by LKE and LG&E regarding the valuation of benefit obligations and the performance of plan assets. When accounting for defined benefits, delayed recognition in earnings of differences between actual results and
expected or estimated results is a guiding principle. Annual net periodic defined benefit costs are recorded in current earnings based on estimated results. Any differences between actual and estimated results are recorded in regulatory assets and liabilities for amounts that are expected to be recovered through regulated customer rates. These amounts in regulatory assets and liabilities are amortized to income over future periods. The delayed recognition allows for a smoothed recognition of costs over the working lives of the employees who benefit under the plans. The primary assumptions are:
·
Discount Rate - The discount rate is used in calculating the present value of benefits, which is based on projections of benefit payments to be made in the future. The objective in selecting the discount rate is to measure the single amount that, if invested at the measurement date in a portfolio of high-quality debt instruments, would provide the necessary future cash flows to pay the accumulated benefits when due.
·
Expected Long-term Return on Plan Assets - Management projects the long-term rates of return on plan assets based on historical performance, future expectations and periodic portfolio rebalancing among the diversified asset classes. These projected returns reduce the net benefit costs LG&E records currently.
·
Rate of Compensation Increase - Management projects employees' annual pay increases, which are used to project employees' pension benefits at retirement.
·
Health Care Cost Trend Rate - Management projects the expected increases in the cost of health care.
In selecting a discount rate for their defined benefit plans LKE and LG&E start with a cash flow analysis of the expected benefit payment stream for their plans. In 2010, these plan-specific cash flows were matched against a spot-rate yield curve to determine the assumed discount rate. To develop the spot-rate yield curve, the full universe of Aa-rated non-callable (or callable with make-whole provisions) bonds, served as the base from which those with the lowest and highest yields were eliminated to develop an appropriate subset of bonds from which the ultimate yield curve would be built. At that time, management believed this plan-specific cash flow matching model represented the best available tool for estimating the discount rate. Beginning in 2011, LKE and LG&E utilized a new tool that enhanced this plan-specific cash flow matching methodology by primarily matching the plan-specific cash flows against the coupons and expected maturity values of individually selected bonds. This bond matching process begins with the same universe of Aa-rated corporate bonds from which those with the lowest and highest yields were eliminated, similar to the yield curve approach. Individual bonds are then selected based on the timing of each plan's cash flows and parameters are established as to the percentage of each individual bond issue that could be hypothetically purchased and the surplus reinvestment rates to be assumed. This process more accurately approximated the process of settlement of the obligations which better aligned with the objective of selecting the discount rate. At December 31, 2011, LKE decreased the discount rate for its pension plan from 5.52% to 5.12%. LG&E decreased the discount rate for its pension plan from 5.45% to 5.05%. LKE decreased the discount rate for its other postretirement benefit plan from 5.12% to 4.78%.
The expected long-term rates of return for LKE's and LG&E's defined benefit pension plans and LKE's defined other postretirement benefit plan have been developed using a best-estimate of expected returns, volatilities and correlations for each asset class. LKE and LG&E management corroborates these rates with expected long-term rates of return calculated by its independent actuary, who uses a building block approach that begins with a risk-free rate of return with factors being added such as inflation, duration, credit spreads, and equity risk. Each plan's specific asset allocation is also considered in developing a reasonable return assumption. At December 31, 2011, LKE's and LG&E's expected return on plan assets was 7.25%.
In selecting a rate of compensation increase, LKE and LG&E consider past experience in light of movements in inflation rates. At December 31, 2011, LKE's and LG&E's rate of compensation increase changed from 5.25% to 4.00%.
In selecting health care cost trend rates, LKE considers past performance and forecasts of health care costs. At December 31, 2011, LKE's health care cost trend rates were 8.50% for 2012, gradually declining to 5.50% for 2019.
A variance in the assumptions listed above could have a significant impact on accrued defined benefit liabilities or assets, reported annual net periodic defined benefit costs and regulatory assets and liabilities for LG&E. While the charts below reflect either an increase or decrease in each assumption, the inverse of the change would impact the accrued defined benefit liabilities or assets, reported annual net periodic defined benefit costs and regulatory assets and liabilities for LG&E by a similar amount in the opposite direction. The sensitivities below reflect an evaluation of the change based solely on a change in that assumption and does not include income tax effects.
At December 31, 2011, the defined benefit plans were recorded as follows:
The following chart reflects the sensitivities in the December 31, 2011 Balance Sheet associated with a change in certain assumptions based on LG&E's primary defined benefit plans.
(a)
Only impacts other postretirement benefits.
In 2011, LG&E recognized net periodic defined benefit costs charged to operating expense of $21 million. This amount represents a $1 million increase from 2010. This increase in expense was primarily attributable to amortization of actuarial losses.
The following chart reflects the sensitivities in the 2011 Statement of Income (excluding income tax effects) associated with a change in certain assumptions based on LG&E's primary defined benefit plans.
(a)
Only impacts other postretirement benefits.
4) Asset Impairment
Impairment analyses are performed for long-lived assets that are subject to depreciation or amortization whenever events or changes in circumstances indicate that a long-lived asset's carrying value may not be recoverable. For these long-lived assets classified as held and used, such events or changes in circumstances are:
·
a significant decrease in the market price of an asset;
·
a significant adverse change in the extent or manner in which an asset is being used or in its physical condition;
·
a significant adverse change in legal factors or in the business climate;
·
an accumulation of costs significantly in excess of the amount originally expected for the acquisition or construction of an asset;
·
a current-period operating or cash flow loss combined with a history of losses or a forecast that demonstrates continuing losses; or
·
a current expectation that, more likely than not, an asset will be sold or otherwise disposed of significantly before the end of its previously estimated useful life.
For a long-lived asset classified as held and used, impairment is recognized when the carrying amount of the asset is not recoverable and exceeds its fair value. The carrying amount is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. If the asset is impaired, an impairment loss is recorded to adjust the asset's carrying value to its estimated fair value. Management must make significant judgments to estimate future cash flows including the useful lives of long-lived assets, the fair value of the assets and management's intent to use the assets. Alternate courses of action are considered to recover the carrying value of a long-lived asset, and estimated cash flows from the "most likely" alternative are used to assess impairment whenever one alternative is clearly the most likely outcome. If no alternative is clearly the most likely, then a probability-weighted approach is used taking into consideration estimated cash flows from the alternatives. For assets tested for impairment as of the balance sheet date, the estimates of future cash flows used in that test consider the likelihood of possible outcomes that existed at the balance sheet date, including the assessment of the likelihood of a future sale of the assets. That assessment is not revised based on events that occur after the balance sheet date. Changes in assumptions and estimates could result in significantly different results than those identified and recorded in the financial statements.
For a long-lived asset classified as held for sale, impairment exists when the carrying amount of the asset (disposal group) exceeds its fair value less cost to sell. If the asset (disposal group) is impaired, an impairment loss is recorded to adjust the carrying amount to its fair value less cost to sell. A gain is recognized for any subsequent increase in fair value less cost to sell, but not in excess of the cumulative impairment previously recognized.
For determining fair value, quoted market prices in active markets are the best evidence. However, when market prices are unavailable, LG&E considers all valuation techniques appropriate under the circumstances and for which market participant inputs can be obtained. Generally discounted cash flows are used to estimate fair value, which incorporates market participant inputs when available. Discounted cash flows are calculated by estimating future cash flow streams and applying appropriate discount rates to determine the present value of the cash flow streams.
In 2011, LG&E did not recognize an impairment of any long-lived assets.
Goodwill is tested for impairment at the reporting unit level. LG&E's reporting unit has been determined to be at the operating segment level. A goodwill impairment test is performed annually or more frequently if events or changes in circumstances indicate that the carrying value of the reporting unit may be greater than the unit's fair value. Additionally, goodwill is tested for impairment after a portion of goodwill has been allocated to a business to be disposed of. Goodwill is tested for impairment using a two-step approach. In step 1, LG&E identifies a potential impairment by comparing the estimated fair value of LG&E (the goodwill reporting unit) to its carrying value, including goodwill, on the measurement date. If the estimated fair value exceeds its carrying amount, goodwill is not considered impaired. If the carrying amount exceeds the estimated fair value, the second step is performed to measure the amount of impairment loss, if any.
The second step requires a calculation of the implied fair value of goodwill, which is determined in the same manner as the amount of goodwill in a business combination. That is, the estimated fair value is allocated to all of LG&E's assets and liabilities as if LG&E had been acquired in a business combination and the estimated fair value of LG&E was the price paid. The excess of the estimated fair value of LG&E over the amounts assigned to its assets and liabilities is the implied fair value of goodwill. The implied fair value of goodwill is then compared with the carrying amount of that goodwill. If the carrying amount exceeds the implied fair value, an impairment loss is recognized in an amount equal to that excess. The loss recognized cannot exceed the carrying amount of the reporting unit's goodwill.
LG&E tested goodwill for impairment in the fourth quarter of 2011 and no impairment was recognized. Management used both discounted cash flows and market multiples to estimate the fair value of LKE, which involved the use of significant estimates and assumptions. Applying an appropriate weighting to both the discounted cash flow and market multiple valuations, a decrease in the forecasted cash flows of 10%, an increase in the discount rate by 25 basis points, or a 10% decrease in the multiples would not have resulted in an impairment of goodwill.
5)
Loss Accruals
Losses are accrued for the estimated impacts of various conditions, situations or circumstances involving uncertain or contingent future outcomes. For loss contingencies, the loss must be accrued if (1) information is available that indicates it is probable that a loss has been incurred, given the likelihood of the uncertain future events and (2) the amount of the loss can be reasonably estimated. Accounting guidance defines "probable" as cases in which "the future event or events are likely to occur." The accrual of contingencies that might result in gains is not recorded unless recovery is assured. Potential loss contingencies for environmental remediation, litigation claims, regulatory penalties and other events are continuously assessed.
The accounting aspects of estimated loss accruals include (1) the initial identification and recording of the loss, (2) the determination of triggering events for reducing a recorded loss accrual and (3) the ongoing assessment as to whether a recorded loss accrual is sufficient. All three of these aspects require significant judgment by management. Internal expertise and outside experts (such as lawyers and engineers) are used, as necessary to help estimate the probability that a loss has been incurred and the amount (or range) of the loss.
In 2011, no significant adjustments were made to LG&E's existing contingencies. See Note 15 to the Financial Statements for commitment and contingency disclosures.
Certain other events have been identified that could give rise to a loss, but that do not meet the conditions for accrual. Such events are disclosed, but not recorded, when it is reasonably possible that a loss has been incurred. Accounting guidance defines "reasonably possible" as cases in which "the future event or events occurring is more than remote, but less than likely to occur." See Note 15 to the Financial Statements for disclosure of other potential loss contingencies that have not met the criteria for accrual.
When an estimated loss is accrued, the triggering events for subsequently adjusting the loss accrual are identified, where applicable. The triggering events generally occur when the contingency has been resolved and the actual loss is paid or written off, or when the risk of loss has diminished or been eliminated. The following are some of the triggering events that provide for the adjustment of certain recorded loss accruals:
·
Allowances for uncollectible accounts are reduced when accounts are written off after prescribed collection procedures have been exhausted, a better estimate of the allowance is determined or underlying amounts are ultimately collected.
·
Environmental and other litigation contingencies are reduced when the contingency is resolved, LG&E makes actual payments, a better estimate of the loss is determined or the loss is no longer considered probable.
Loss accruals are reviewed on a regular basis to assure that the recorded potential loss exposures are appropriate. This involves ongoing communication and analyses with internal and external legal counsel, engineers, operation management and other parties.
6)
Asset Retirement Obligations
LG&E is required to recognize a liability for legal obligations associated with the retirement of long-lived assets. The initial obligation is measured at its estimated fair value. An equivalent amount is recorded as an increase in the value of the capitalized asset and allocated to expense over the useful life of the asset. Until the obligation is settled, the liability is increased, through the recognition of accretion expense in the Statements of Income, for changes in the obligation due to the passage of time. The accretion and depreciation are offset with a regulatory credit on the income statement, such that there is no earnings impact. The regulatory asset created by the regulatory credit is relieved when the ARO has been settled. An ARO must be recognized when incurred if the fair value of the ARO can be reasonably estimated. See Note 21 to the Financial Statements for related disclosures.
In determining AROs, management must make significant judgments and estimates to calculate fair value. Fair value is developed using an expected present value technique based on assumptions of market participants that considers estimated retirement costs in current period dollars that are inflated to the anticipated retirement date and then discounted back to the date the ARO was incurred. Changes in assumptions and estimates included within the calculations of the fair value of AROs could result in significantly different results than those identified and recorded in the financial statements. Estimated ARO costs and settlement dates, which affect the carrying value of various AROs and the related assets, are reviewed periodically to ensure that any material changes are incorporated into the estimate of the obligations. Any change to the capitalized asset is amortized over the remaining life of the associated long-lived asset.
At December 31, 2011, LG&E had AROs comprised of current and noncurrent amounts, totaling $57 million recorded on the Balance Sheet. Of the total amount, $34 million, or 59%, relates to LG&E's ash ponds, landfills and natural gas mains. The most significant assumptions surrounding AROs are the forecasted retirement costs, the discount rates and the inflation rates. A variance in the forecasted retirement costs, the discount rates or the inflation rates could have a significant impact on the ARO liabilities.
The following chart reflects the sensitivities related to LG&E's ARO liabilities for ash ponds, landfills and natural gas mains at December 31, 2011:
7)
Income Taxes
Significant management judgment is required in developing LG&E's provision for income taxes primarily due to the uncertainty related to tax positions taken or expected to be taken in tax returns and the determination of deferred tax assets, liabilities and valuation allowances.
Significant management judgment is required to determine the amount of benefit recognized related to an uncertain tax position. LG&E evaluates its tax positions following a two-step process. The first step requires an entity to determine whether, based on the technical merits supporting a particular tax position, it is more likely than not (greater than a 50% chance) that the tax position will be sustained. This determination assumes that the relevant taxing authority will examine the tax position and is aware of all the relevant facts surrounding the tax position. The second step requires an entity to
recognize in the financial statements the benefit of a tax position that meets the more-likely-than-not recognition criterion. The benefit recognized is measured at the largest amount of benefit that has a likelihood of realization upon settlement that exceeds 50%. LG&E's management considers a number of factors in assessing the benefit to be recognized, including negotiation of a settlement.
On a quarterly basis, LG&E's uncertain tax positions are reassessed by considering information known at the reporting date. Based on management's assessment of new information, a tax benefit may subsequently be recognized for a previously unrecognized tax position, a previously recognized tax position maybe de-recognized, or the benefit of a previously recognized tax position may be remeasured. The amounts ultimately paid upon resolution of issues raised by taxing authorities may differ materially from the amounts accrued and may materially impact the financial statements in the future.
At December 31, 2011, LG&E had no existing reserve for unrecognized tax benefits.
The balance sheet classification of unrecognized tax benefits and the need for valuation allowances to reduce deferred tax assets also require significant management judgment. Unrecognized tax benefits are classified as current to the extent management expects to settle an uncertain tax position by payment or receipt of cash within one year of the reporting date. Valuation allowances are initially recorded and reevaluated each reporting period by assessing the likelihood of the ultimate realization of a deferred tax asset. Management considers a number of factors in assessing the realization of a deferred tax asset, including the reversal of temporary differences, future taxable income and ongoing prudent and feasible tax planning strategies. Any tax planning strategy utilized in this assessment must meet the recognition and measurement criteria utilized to account for an uncertain tax position. See Note 5 to the Financial Statements for related disclosures.
Regulatory Assets and Liabilities
LG&E is a cost-based rate-regulated utility. As a result, the effects of regulatory actions are required to be reflected in the financial statements. Assets and liabilities are recorded that result from the regulated ratemaking process that may not be recorded under GAAP for non-regulated entities. Regulatory assets generally represent incurred costs that have been deferred because such costs are probable of future recovery in regulated customer rates. Regulatory liabilities are recognized for amounts expected to be returned through future regulated customer rates. In certain cases, regulatory liabilities are recorded based on an understanding with the regulator that rates have been set to recover costs that are expected to be incurred in the future, and the regulated entity is accountable for any amounts charged pursuant to such rates and not yet expended for the intended purpose. The accounting for regulatory assets and liabilities is based on specific ratemaking decisions or precedent for each transaction or event as prescribed by the FERC and the KPSC. See Note 6 to the Financial Statements for related disclosures.
Management continually assesses whether the regulatory assets are probable of future recovery by considering factors such as changes in the applicable regulatory and political environments, the ability to recover costs through regulated rates, recent rate orders to other regulated entities and the status of any pending or potential deregulation legislation. Based on this continual assessment, management believes the existing regulatory assets are probable of recovery. This assessment reflects the current political and regulatory climate at the state and federal levels, and is subject to change in the future. If future recovery of costs ceases to be probable, then asset write-off would be required to be recognized in operating income. Additionally, the regulatory agencies can provide flexibility in the manner and timing of the depreciation of PP&E and amortization of regulatory assets.
At December 31, 2011 and 2010, LG&E had regulatory assets of $412 million and $380 million. All regulatory assets are either currently being recovered under specific rate orders, represent amounts that are expected to be recovered in future rates or benefit future periods based upon established regulatory practices. At December 31, 2011 and 2010, LG&E had regulatory liabilities of $488 million and $534 million.
Other Information
PPL's Audit Committee has approved the independent auditor to provide audit and other services permitted by Sarbanes-Oxley and SEC rules. The audit services include services in connection with statutory and regulatory filings, reviews of offering documents and registration statements, and internal control reviews. See "Item 14. Principal Accounting Fees and Services" for more information.
KENTUCKY UTILITIES COMPANY
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
The information provided in this Item 7 should be read in conjunction with KU's Financial Statements and the accompanying Notes. Capitalized terms and abbreviations are explained in the glossary. Dollars are in millions, unless otherwise noted.
"Management's Discussion and Analysis of Financial Condition and Results of Operations" includes the following information:
·
"Overview" provides a description of KU and its business strategy. "Financial and Operational Developments" includes a review of Net Income and discusses certain events that are important to understanding KU's results of operations and financial condition.
·
"Results of Operations" provides a summary of KU's earnings and a description of key factors expected to impact future earnings. This section ends with "Statement of Income Analysis," which includes explanations of significant changes in principal items on KU's Statements of Income, comparing 2011, 2010 and 2009.
·
"Financial Condition - Liquidity and Capital Resources" provides an analysis of KU's liquidity position and credit profile. This section also includes a discussion of rating agency decisions and capital expenditure projections.
·
"Financial Condition - Risk Management" provides an explanation of KU's risk management programs relating to market and credit risk.
·
"Application of Critical Accounting Policies" provides an overview of the accounting policies that are particularly important to the results of operations and financial condition of KU and that require its management to make significant estimates, assumptions and other judgments of matters inherently uncertain.
Overview
Introduction
KU, headquartered in Lexington, Kentucky, is a regulated utility engaged in the generation, transmission, distribution and sale of electric energy, in Kentucky, Virginia and Tennessee. KU and its affiliate, LG&E, are wholly owned subsidiaries of LKE. LKE, a limited liability company, became a wholly owned subsidiary of PPL when PPL acquired all of LKE's interests from E.ON US Investments Corp. on November 1, 2010. Following the acquisition, both KU and LG&E continue operating as subsidiaries of LKE, which is now an intermediary holding company in PPL's group of companies. Refer to "Item 1. Business - Background" for a description of KU's business.
Business Strategy
KU's overall strategy is to provide reliable, safe and competitively priced energy to its customers.
A key objective for KU is to maintain a strong credit profile through managing financing costs and access to credit markets. KU continually focuses on maintaining an appropriate capital structure and liquidity position.
Successor and Predecessor Financial Presentation
KU's Financial Statements and related financial and operating data include the periods before and after PPL's acquisition of LKE on November 1, 2010, and have been segregated to present pre-acquisition activity as the Predecessor and post-acquisition activity as the Successor. Predecessor activity covers the time period prior to November 1, 2010. Successor activity covers the time period after October 31, 2010. Certain accounting and presentation methods were changed to acceptable alternatives to conform to PPL's accounting policies, which are discussed in Note 1 to the Financial Statements. The cost bases of certain assets and liabilities were changed as of November 1, 2010, as a result of the application of push-down basis of accounting, which was used to record the fair value adjustments of assets and liabilities at the acquisition date. Consequently, the financial position, results of operations and cash flows for the Successor periods are not comparable to the Predecessor periods; however, the core operations of KU have not changed as a result of the acquisition.
Financial and Operational Developments
Net Income
The operating results for 2011 and 2010 include the effect of KU's base rate increases, which became effective August 1, 2010, partially offset by net cost increases, which have not yet been reflected in the rates charged by KU. Retail sales volumes increased during 2010 compared with 2009 as a result of increased consumption primarily due to increased heating degree days during the first and third quarters of 2010 and increased cooling degree days during the second and third quarters of 2010.
See "Results of Operations" below for further discussion and analysis of the results of operations.
TC2
KU and LG&E constructed a 732 MW summer capacity coal-fired unit, TC2, which is jointly owned by KU (60.75%) and LG&E (14.25%), together with the Illinois Municipal Electric Agency and the Indiana Municipal Power Agency (combined 25%). With limited exceptions, KU and LG&E took care, custody and control of TC2 in January 2011. KU and LG&E and the construction contractor further amended the construction agreement to provide that the contractor will complete certain actions to identify and complete any necessary modifications to allow operation of TC2 on all fuels in accordance with initial specifications prior to certain dates, and amending the provisions relating to liquidated damages. A number of remaining issues regarding these matters are still under discussion with the contractor. See Notes 8 and 15 to the Financial Statements for additional information.
Registered Debt Exchange Offer by KU
In April 2011, KU filed a Registration Statement with the SEC, related to an offer to exchange certain first mortgage bonds issued in November 2010, in transactions not subject to registration under the Securities Act of 1933, with similar but registered securities. The 2011 Registration Statement became effective in June 2011, and the exchange was completed in July 2011 with substantially all of the first mortgage bonds being exchanged. See Note 7 to the Financial Statements and KU's 2011 Registration Statement for additional information.
CSAPR
In July 2011, the EPA signed the CSAPR, which finalizes and renames the Clean Air Transport Rule (Transport Rule) proposed in August 2010, and made revisions to the rule on February 7, 2012. This rule applies to the Kentucky coal plants. The CSAPR is meant to facilitate attainment of ambient air quality standards for ozone and fine particulates by requiring reductions in sulfur dioxide and nitrogen oxide emissions.
In December 2011, the U.S. Court of Appeals for the District of Columbia (Court) stayed implementation of the CSAPR and left CAIR in effect pending a final resolution on the merits of the validity of the rule. Oral argument on the various challenges to the CSAPR is scheduled for April 2012, and a final decision on the validity of the rule could be issued as early as May 2012.
With respect to KU's Kentucky coal-fired generating plants, the stay of the CSAPR will initially only impact the unit dispatch order. With the return of the CAIR and KU's significant number of sulfur dioxide allowances, those units will be dispatched with lower operating cost, but slightly higher sulfur dioxide and nitrogen oxide emissions. However, a key component of the Court's final decision, even if the CSAPR is upheld, will be whether the ruling delays the implementation of the CSAPR by one year for both Phases I and II, or instead still requires the significant sulfur dioxide and nitrogen oxide reductions associated with Phase II to begin in 2014. KU's CSAPR compliance strategy is based on over-compliance during Phase I to generate allowances sufficient to cover the expected shortage during the first two years of Phase II (2014 and 2015) when additional pollution control equipment will be installed. Should Phase I of the CSAPR be shortened to one year, it will be more difficult and costly to provide enough excess allowances in one year to meet the shortage projected for 2014 and 2015.
See Note 15 to the Financial Statements for additional information on the CSAPR.
Pending Bluegrass CTs Acquisition and NGCC Construction
In September 2011, KU and LG&E filed a CPCN with the KPSC requesting approval to build a 640 MW NGCC at the existing Cane Run plant site. In conjunction with this request and to meet new, stricter EPA regulations, KU anticipates retiring three older coal-fired electric generating units. These units are located at the Green River and Tyrone plants, which have a combined summer rating of 234 MW. KU and LG&E also requested approval to purchase the Bluegrass CTs, which are expected to provide up to 495 MW of peak generation supply.
KU anticipates that its share of the NGCC construction and the acquisition of the Bluegrass CTs could require up to $500 million in capital costs including related transmission projects. Formal requests for recovery of the costs associated with the NGCC construction and the acquisition of the Bluegrass CTs were not included in the CPCN filing with the KPSC but are expected to be included in future rate proceedings. The KPSC issued an Order on the procedural schedule in the CPCN filing that has discovery, scheduled through early February 2012. A KPSC order on the CPCN filing is anticipated in the second quarter of 2012. See Note 8 to the Financial Statements for additional information.
ECR Filing - Environmental Upgrades
In June 2011, in order to achieve compliance with new and pending mandated federal EPA regulations, KU filed an ECR plan with the KPSC requesting approval to install environmental upgrades for certain of its coal-fired plants along with the recovery of the expected $1.1 billion in associated capital costs, as well as operating expenses incurred. The ECR plan detailed upgrades that will be made to certain of KU's coal-fired generating plants to continue to be compliant with EPA regulations.
In November 2011, KU filed a unanimous settlement agreement, stipulation and recommendation with the KPSC. In December 2011, KU received KPSC approval in its proceedings relating to the ECR plan. The KPSC Order approved the terms of the November 2011 settlement agreement entered into between KU and the parties to the ECR proceedings. The KPSC Order authorized the installation of environmental upgrades at certain plants during 2012-2016 representing approximate capital costs of $900 million at KU. In connection with the approved projects, the KPSC Order allows recovery through the ECR rate mechanism of the capital costs and operating expenses of the projects and granted CPCN for their construction. The KPSC Order also confirmed an existing 10.63% authorized return on equity for projects remaining from earlier ECR plans and provided for an authorized return on equity of 10.10% for the approved projects in the 2011 ECR proceedings. The KPSC Order noted KU's consent to defer the requested approval for certain environmental upgrades at its E.W. Brown generating plant, which represented approximately $200 million in capital costs. KU retained the right to operate and dispatch the E.W. Brown generating plant in accordance with applicable environmental standards and the right to request approval of the deferred projects and related costs in future regulatory proceedings. See Note 6 to the Financial Statements for additional information.
Storm Recovery
In December 2009, a major snowstorm hit KU's Virginia service area causing approximately 30,000 customer outages. During the normal 2009 Virginia Annual Information Filing (AIF), KU requested that the VSCC establish a regulatory asset and defer for future recovery $6 million in incremental operation and maintenance expenses related to the storm restoration. In March 2011, the VSCC Staff issued its report on KU's 2009 AIF stating that it considered this storm damage to be extraordinary, non-recurring and material to KU. The Staff Report also recommended establishing a regulatory asset for these costs, with recovery over a five-year period upon approval in the next base rate case. In March 2011, a regulatory asset of $6 million was established for actual costs incurred. In June 2011, the VSCC issued an Order approving the recommendations contained in the Staff Report. KU received approval in its 2011 base rate case to recover this regulatory asset over a five-year period ending October 2016.
In September 2009, the KPSC approved the deferral of $57 million of costs associated with a severe ice storm that occurred in January 2009 and a wind storm that occurred in February 2009. Additionally, in December 2008, the KPSC approved the deferral of $2 million of costs associated with high winds from the remnants of Hurricane Ike in September 2008. KU received approval in its 2010 base rate case to recover these regulatory assets over a ten-year period beginning August 2010.
Virginia Rate Case
In April 2011, KU filed an application with the VSCC requesting an annual increase in electric base rates for its Virginia jurisdictional customers of $9 million, or 14%. In September 2011, a settlement stipulation was reached between KU and the VSCC Staff and filed with the VSCC for consideration. In October 2011, the VSCC approved the stipulation with two modifications that were accepted by KU. The VSCC issued an Order closing the proceeding in October 2011. The approved
revenue increase was $7 million annually, based on a return on equity of 10.3%, with new base rates effective November 1, 2011.
Results of Operations
As previously noted, KU's results for the time periods after October 31, 2010 are on a basis of accounting different from its results for time periods prior to November 1, 2010. When discussing KU's results of operations material differences resulting from the different basis of accounting will be isolated for purposes of comparability. See "Overview - Successor and Predecessor Financial Presentation" for further information.
The utility business is affected by seasonal weather. As a result, operating revenues (and associated operating expenses) are not generated evenly throughout the year. Revenue and earnings are generally higher during the first and third quarters and lower during the second quarter due to weather.
The following table summarizes the significant components of net income for 2011, 2010, and 2009 and the changes therein:
The changes in the components of Net Income between these periods were due to the following factors.
·
See "Statement of Income Analysis - Margin - Changes in Non-GAAP Financial Measures" for an explanation of margin.
·
Other operation and maintenance increased in 2011 compared with 2010, primarily due to $19 million of higher steam costs, the result of increase scope of scheduled outages including those at Ghent and Green River plants, along with higher variable costs from increased generation.
Other operation and maintenance increased in 2010 compared with 2009, primarily due to higher administrative and general costs of $13 million, higher steam costs of $6 million and higher transmission operation costs of $5 million. Administrative and general costs increased due to higher bad debt costs, higher labor costs and higher property and public liability insurance costs.
·
Depreciation expense was $25 million higher in 2011 compared with 2010, due to TC2 commencing dispatch in January 2011.
·
Taxes, other than income increased in 2011 compared with 2010, primarily due to a $5 million clean coal incentive tax credit that KU was able to apply to property tax in 2010.
·
Income taxes increased in 2010 compared with 2009, primarily due to the $28 million impact of higher pre-tax income, primarily due to margin.
2012 Outlook
KU projects lower earnings in 2012 compared with 2011, as revenue increases are not expected to offset operating expense increases, including depreciation, due to more plant in service. Actual results will be dependent on the effects of the economy and the impact of weather on retail sales among other variables. As a result of the stay out provision established in the settlement of the PPL-LKE acquisition, KU is generally unable to implement an increase in base rates in Kentucky before January 1, 2013.
Earnings in 2012 are subject to various risks and uncertainties. See "Forward-Looking Information," the rest of this Item 7, Notes 6 and 15 to the Financial Statements and "Business," and "Risk Factors" in this Form 10-K for a discussion of the risks, uncertainties and factors that may impact future earnings.
Statement of Income Analysis --
Margin
Non-GAAP Financial Measure
The following discussion includes financial information prepared in accordance with GAAP, as well as a non-GAAP financial measure, "Margin." Margin is not intended to replace "Operating Income," which is determined in accordance with GAAP as an indicator of overall operating performance. Other companies may use different measures to analyze and to report on the results of their operations. Margin is a single financial performance measure of KU's operations. In calculating this measure, utility revenues and expenses associated with approved cost recovery tracking mechanisms are offset. These mechanisms allow for recovery of certain expenses, returns on capital investments associated with environmental regulations and performance incentives. Certain costs associated with these mechanisms, primarily ECR and DSM, are recorded as "Other operation and maintenance" expenses and the depreciation associated with ECR equipment is recorded as "Depreciation" expense. As a result, this measure represents the net revenues from KU's operations. This performance measure is used, in conjunction with other information, internally by senior management to manage operations and analyze actual results compared with budget.
Reconciliation of Non-GAAP Financial Measures
The following tables reconcile "Operating Income" to "Margin" as defined by KU for 2011, 2010 and 2009.
(a)
Represents amounts excluded from Margin.
(b)
As reported on the Statements of Income.
Changes in Non-GAAP Financial Measures
Margins were higher by $52 million for 2011 compared with 2010. New KPSC rates went into effect on August 1, 2010, contributing an additional $64 million in operating revenues over the prior year. Partially offsetting the rate increase were lower retail volumes resulting from weather and economic conditions.
(a)
Fuel handling costs are included in fuel for electric generation on the Statements of Income for the Successor's periods and are in other operation and maintenance expense on the Statements of Income for the Predecessor's periods.
(b)
Steam operation costs increased in 2011 compared with 2010, due to increased generation, the result of TC2 commencing dispatch in 2011.
(c)
Steam maintenance costs increased in 2011 compared with 2010, due to an increase in the scope of scheduled outages including those at Ghent and Green River.
(d)
Transmission operation costs increased in 2010 compared with 2009, primarily due to a settlement agreement with a third party resulting in the establishment of a regulatory asset in 2009, net of twelve months of amortization expense recorded in 2010.
(e)
Administrative and general costs increased in 2011 compared with 2010, due to higher outside services costs of $2 million, higher labor costs of $1 million and higher pension costs of $1 million, partially offset by $2 million of lower bad debt costs.
Administrative and general costs increased in 2010 compared with 2009, due higher bad debt costs of to $4 million, higher labor costs of $1 million, and higher property and public liability insurance costs of $2 million. Bad debt costs increased in 2010 compared with 2009, due to higher billed revenues and a higher net charge-off percentage, partially offset by higher late payment charges.
Depreciation
Changes in depreciation were due to the following:
Taxes, Other Than Income
Taxes, other than income increased by $9 million in 2011 compared with 2010 primarily due to a $5 million state coal tax credit that was applied to 2010 property taxes. The remaining increase was due to higher assessments, primarily from significant property additions.
Interest Expense
The changes in interest expense were due to:
(a)
Interest rates on the first mortgage bonds issued in November 2010 were lower than the rates on the loans from the Fidelia Corporations in place through October 2010.
(b)
KU's long-term debt principal balance was $169 million higher as of December 31, 2010 compared with December 31, 2009 and did not change from December 31, 2010 to December 31, 2011. The higher interest expense in 2011 was the result of higher long-term debt balances for the last two months of 2010.
Financial Condition
Liquidity and Capital Resources
KU expects to continue to have adequate liquidity available through operating cash flows, cash and cash equivalents and its credit facilities. KU currently has no plans to access capital markets in 2012.
KU's cash flows from operations and access to cost-effective bank and capital markets are subject to risks and uncertainties including, but not limited to:
·
changes in market prices for electricity;
·
changes in commodity prices that may increase the cost of producing power or decrease the amount KU receives from selling power;
·
operational and credit risks associated with selling and marketing products in the wholesale power markets;
·
unusual or extreme weather that may damage KU's transmission and distribution facilities or affect energy sales to customers;
·
reliance on transmission and distribution facilities that KU does not own or control to deliver its electricity and natural gas;
·
unavailability of generating units (due to unscheduled or longer-than-anticipated generation outages, weather and natural disasters) and the resulting loss of revenues and additional costs of replacement electricity;
·
the ability to recover and the timeliness and adequacy of recovery of costs associated with regulated utility businesses;
·
costs of compliance with existing and new environmental laws;
·
any adverse outcome of legal proceedings and investigations with respect to KU's current and past business activities;
·
deterioration in the financial markets that could make obtaining new sources of bank and capital markets funding more difficult and more costly; and
·
a downgrade in KU's credit ratings that could adversely affect its ability to access capital and increase the cost of credit facilities and any new debt.
See "Item 1A. Risk Factors" for further discussion of risks and uncertainties affecting KU's cash flows.
At December 31, KU had the following:
The changes in KU's cash and cash equivalents position resulted from:
Auction Rate Securities
At December 31, 2011, KU's tax-exempt revenue bonds that are in the form of auction rate securities and total $96 million continue to experience failed auctions. Therefore, the interest rate continues to be set by a formula pursuant to the relevant indentures. For the period ended December 31, 2011, the weighted-average rate on KU's auction rate bonds in total was 0.27%.
See Note 7 to the Financial Statements for additional information about long-term debt securities.
Operating Activities
Net cash provided by operating activities increased by 17%, or $65 million, in 2011 compared with 2010, primarily as a result of:
·
an increase in net income adjusted for non-cash effects of $115 million (deferred income taxes and investment tax credits of $81 million and depreciation of $41 million, partially offset by defined benefit plans - expense of $2 million and other noncash items of $8 million);
·
a net decrease in working capital related to unbilled revenues of $21 million due to colder weather in December 2010 as compared with December 2009, and milder weather in December 2011 as compared with December 2010; partially offset by
·
an increase in discretionary defined benefit plan contributions of $30 million made in order to achieve KU's long-term funding requirements;
·
the timing of ECR collections of $28 million; and
·
an increase in cash outflows related to accrued taxes of $19 million due to an accrual in excess of payments made in 2010 for the 2010 tax year and the payment of the 2010 tax liability in 2011, along with payments made in 2011 over the accrual for the 2011 tax year.
Net cash provided by operating activities increased by 47%, or $120 million, in 2010 compared with 2009, primarily as a result of:
·
lower storm expenses of $59 million;
·
the timing of ECR collections of $48 million;
·
a decrease in cash outflows related to inventory of $27 million, primarily due to a nominal change in inventory levels in 2010 and lower consumption in 2009 due to lower generation; and
·
an increase in net income adjusted for non-cash effects of $8 million (depreciation of $12 million and other noncash items of $11 million, partially offset by deferred income taxes and investment tax credits of $47 million and defined benefit plans - expense of $10 million), partially offset by
·
higher interest payments of $14 million due to an accelerated settlement with E.ON AG.
Investing Activities
The primary use of cash in investing activities in 2011, 2010 and 2009 was capital expenditures. See "Forecasted Uses of Cash" for detail regarding projected capital expenditures for the years 2012 through 2016.
Net cash used in investing activities decreased by 36%, or $155 million, in 2011 compared with 2010, as a result of a decrease in capital expenditures of $155 million, primarily due to the completion of KU's scrubber program in 2010 and TC2 being dispatched in 2011.
Net cash used in investing activities decreased by 16%, or $79 million, in 2010 compared with 2009, as a result of a decrease in capital expenditures of $88 million, primarily due to lower expenditures related to the construction of TC2 and major storm events that occurred in 2009, partially offset by a decrease in restricted cash of $9 million.
Financing Activities
Net cash used in financing activities was $137 million in 2011 compared with net cash provided by financing activities of $56 million in 2010, primarily as a result of less long-term debt issuances and higher dividends to LKE.
In 2011, cash used in financing activities consisted of:
·
the payment of common stock dividends to LKE of $124 million;
·
a net decrease in notes payable with affiliates of $10 million; and
·
the payment of debt issuance and credit facility costs of $3 million.
Net cash provided by financing activities was $56 million in 2010 compared with $254 million in 2009. In spite of significant new debt issuances associated with the repayments to E.ON AG affiliates in connection with PPL's acquisition of LKE, cash provided by financing was less in 2010 due to lower increases in debt in 2010 and the payment of dividends in 2010; whereas, KU received equity contributions in 2009.
In the two months of 2010 following the acquisition, cash provided by financing activities of the Successor consisted of:
·
the issuance of first mortgage bonds of $1,489 million after discounts and
·
the issuance of debt of $1,331 million to a PPL affiliate to repay debt due to an E.ON AG affiliate upon the closing of PPL's acquisition of LKE, partially offset by
·
the repayment of debt to an E.ON AG affiliate of $1,331 million upon the closing of PPL's acquisition of LKE;
·
the repayment of debt to a PPL affiliate of $1,331 million upon the issuance of first mortgage bonds;
·
a net decrease in notes payable with affiliates of $83 million; and
·
the payment of debt issuance and credit facility costs of $17 million.
In the ten months of 2010 preceding PPL's acquisition of LKE, cash used in financing activities by the Predecessor consisted of:
·
the payment of common stock dividends to LKE of $50 million, partially offset by
·
a net increase in notes payable with affiliates of $48 million.
In 2009, cash provided by financing activities of the Predecessor consisted of:
·
the issuance of debt of $150 million to an E.ON AG affiliate;
·
the receipt of capital contributions of $75 million from LKE; and
·
a net increase in notes payable with affiliates of $29 million.
See "Forecasted Sources of Cash" for a discussion of KU's plans to issue debt securities, as well as a discussion of credit facility capacity available to KU. Also see "Forecasted Uses of Cash" for a discussion of plans to pay dividends on common securities in the future, as well as maturities of long-term debt.
KU's long-term debt securities activity through December 31, 2011 was:
(a)
Issuances are net of pricing discounts, where applicable and exclude the impact of debt issuance costs.
(b)
In April 2011, KU filed a 2011 Registration Statement with the SEC related to offers to exchange securities issued in November 2010 in transactions not registered under the Securities Act of 1933 with similar but registered securities. The registration became effective in June 2011, and the exchanges were completed in July 2011 with all securities being exchanged.
See Note 7 to the Financial Statements for additional information about long-term debt securities.
Forecasted Sources of Cash
KU expects to continue to have sufficient sources of cash available in the near term, including various credit facilities and operating cash flow. KU currently has no plans to access capital markets in 2012. In February 2012, KU established a commercial paper program for up to $250 million to provide an additional financing source to fund its short-term liquidity needs. Commercial paper issuances will be supported by KU's Syndicated Credit Facility.
Credit Facilities
At December 31, 2011, KU's total committed borrowing capacity under its credit facilities and the use of this borrowing capacity were:
(a)
In June 2011, KU amended its Syndicated Credit Facility such that the fees and the spread to benchmark interest rates for borrowings depend upon KU's senior secured long-term debt rating rather than the senior unsecured debt rating.
(b)
In April 2011, KU entered into a new $198 million letter of credit facility that has been used to issue letters of credit to support outstanding tax-exempt bonds. KU pays customary commitment and letter of credit fees under the new facility. The facility matures in April 2014. In August 2011, KU amended its letter of credit facility such that the fees depend upon KU's senior secured long-term debt rating rather than the senior unsecured debt rating.
(c)
In October 2011, KU amended its Syndicated Credit Facility. The amendment included extending the expiration date from December 2014 to October 2016. Under this facility KU continues to have the ability to make cash borrowings and to request the lenders to issue letters of credit.
The commitments under KU's credit facilities are provided by a diverse bank group, with no one bank and its affiliates providing an aggregate commitment of more than 19% of the total committed capacity available to KU.
KU participates in an intercompany money pool agreement whereby LKE and/or LG&E make available to KU funds up to $500 million at an interest rate based on a market index of commercial paper issues. At December 31, 2011, there was no balance outstanding. At December 31, 2010, $10 million was outstanding. The interest rate for the period ended December 31, 2010 was 0.25%.
See Note 7 to the Financial Statements for further discussion of KU's credit facilities.
Operating Leases
KU also has available funding sources that are provided through operating leases. KU leases office space and certain equipment. These leasing structures provide KU additional operating and financing flexibility. The operating leases contain covenants that are typical for these agreements, such as maintaining insurance, maintaining corporate existence and timely payment of rent and other fees.
See Note 11 to the Financial Statements for further discussion of the operating leases.
Forecasted Uses of Cash
In addition to expenditures required for normal operating activities, such as purchased power, payroll, fuel and taxes, KU currently expects to incur future cash outflows for capital expenditures, various contractual obligations, payment of dividends on its common securities and possibly the purchase or redemption of a portion of debt securities.
Capital Expenditures
The table below shows KU's current capital expenditure projections for the years 2012 through 2016.
(a)
Construction expenditures include AFUDC, which is not expected to be significant for the years 2012 through 2016.
(b)
Includes approximately $500 million of currently estimable costs related to replacement generation units due to EPA regulations not recoverable through the ECR mechanism. KU expects to recover these costs over a period equivalent to the related depreciable lives of the assets through future rate proceedings.
(c)
Includes approximately $30 million of currently estimable transmission costs related to replacement generation units. KU expects to recover these costs over a period equivalent to the related depreciable lives of the assets through future rate proceedings.
KU's capital expenditure projections for the years 2012 through 2016 total approximately $3.1 billion. Capital expenditure plans are revised periodically to reflect changes in operational, market and regulatory conditions. This table includes current estimates for KU's environmental projects related to new and anticipated EPA compliance standards. Actual costs may be significantly lower or higher depending on the final requirements and market conditions. Certain environmental compliance costs incurred by KU in serving KPSC jurisdictional customers are generally eligible for recovery through the ECR mechanism.
KU plans to fund its capital expenditures in 2012 with cash on hand, cash from operations and short-term debt.
Contractual Obligations
KU has assumed various financial obligations and commitments in the ordinary course of conducting its business. At December 31, 2011, the estimated contractual cash obligations of KU were:
(a)
Reflects principal maturities only based on stated maturity dates. See Note 7 to the Financial Statements for a discussion of variable-rate remarketable bonds issued on behalf of KU. KU does not have any significant capital lease obligations.
(b)
Assumes interest payments through stated maturity. The payments herein are subject to change, as payments for debt that is or becomes variable-rate debt have been estimated.
(c)
See Note 11 to the Financial Statements for additional information.
(d)
Represents contracts to purchase coal, natural gas and natural gas transportation. See Note 15 to the Financial Statements for additional information.
(e)
Represents future minimum payments under OVEC power purchase agreements through June 2040. See Note 15 to the Financial Statements for additional information.
(f)
Represents construction commitments, including commitments for the Ghent landfill and Brown SCR construction including associated material transport systems for coal combustion residuals, which are also reflected in the Capital Expenditures table presented above.
(g)
Based on the current funded status of LKE's qualified pension plan, which covers KU employees, no cash contributions are required. See Note 13 to the Financial Statements for a discussion of expected contributions.
(h)
Represents other contractual obligations. Purchase orders made in the ordinary course of business are excluded from the amounts presented.
Dividends
From time to time, as determined by its Board of Directors, KU pays dividends to its sole shareholder, LKE.
As discussed in Note 7 to the Financial Statements, KU's ability to pay dividends is limited under a covenant in its $400 million revolving line of credit facility. This covenant restricts the debt to total capital ratio to not more than 70%.
Purchase or Redemption of Debt Securities
KU will continue to evaluate purchasing or redeeming outstanding debt securities and may decide to take action depending upon prevailing market conditions and available cash.
Rating Agency Decisions
Moody's, S&P and Fitch periodically review the credit ratings on the debt securities of KU. Based on their respective independent reviews, the rating agencies may make certain ratings revisions or ratings affirmations.
A credit rating reflects an assessment by the rating agency of the creditworthiness associated with an issuer and particular securities that it issues. The credit ratings of KU are based on information provided by KU and other sources. The ratings of Moody's, S&P and Fitch are not a recommendation to buy, sell or hold any securities of KU. Such ratings may be subject to revisions or withdrawal by the agencies at any time and should be evaluated independently of each other and any other rating that may be assigned to the securities. A downgrade in KU's credit ratings could result in higher borrowing costs and reduced access to capital markets.
In KU's 2011 Registration Statement, KU described its then-current credit ratings in connection with, and to facilitate, an understanding of its liquidity position. As a result of the passage of the Dodd-Frank Act and the attendant uncertainties relating to the extent to which issuers of non-asset backed securities may disclose credit ratings without being required to obtain rating agency consent to the inclusion of such disclosure, or incorporation by reference of such disclosure, in a registrant's registration statement or section 10(a) prospectus, KU is limiting its credit rating disclosure to a description of the actions taken by the rating agencies with respect to KU's ratings, but without stating what ratings have been assigned to KU's securities. The ratings assigned by the rating agencies to KU and its securities may be found, without charge, on each of the respective ratings agencies' websites, which ratings together with all other information contained on such rating agency websites is, hereby, explicitly not incorporated by reference in this report.
Following the announcement of PPL's then-pending acquisition of WPD Midlands in March 2011, the rating agencies took the following actions:
· Moody's affirmed its ratings for KU;
· S&P revised the outlook and lowered the issuer, senior secured and short-term ratings of KU; and
· Fitch affirmed its ratings for KU.
In April 2011, S&P took the following actions following the completion of PPL's acquisition of WPD Midlands:
· revised the outlook for KU;
· raised its short-term ratings of KU; and
· affirmed its long-term ratings for KU.
In May 2011, S&P downgraded its long-term rating of four series of pollution control bonds issued on behalf of KU by one notch in connection with the substitution of the letters of credit enhancing these four bonds.
In September 2011, Moody's affirmed its issuer rating for KU.
In November 2011, Moody's and S&P affirmed their ratings for KU.
In December 2011, Fitch affirmed its ratings for KU.
Ratings Triggers
KU has various derivative and non-derivative contracts, including contracts for the sale and purchase of electricity, fuel, and commodity transportation and storage, which contain provisions requiring KU to post additional collateral, or permitting the counterparty to terminate the contract, if KU's credit rating were to fall below investment grade. See Note 19 to the Financial Statements for a discussion of "Credit Risk-Related Contingent Features," including a discussion of the potential additional collateral that would have been required for derivative contracts in a net liability position at December 31, 2011. At December 31, 2011, if KU's credit ratings had been below investment grade, the maximum amount that KU would have been
required to post as additional collateral to counterparties was $20 million for both derivative and non-derivative commodity and commodity-related contracts used in its generation and marketing operations.
Off-Balance Sheet Arrangements
KU has entered into certain agreements that may contingently require payment to a guaranteed or indemnified party. See Note 15 to the Financial Statements for a discussion of these agreements.
Risk Management
Market Risk
KU is exposed to market risk from equity instruments, interest rate instruments and commodity instruments, as discussed below. However, regulatory cost recovery mechanisms significantly mitigate those risks. See Notes 1, 18 and 19 to the Financial Statements for information about KU's risk management objectives, valuation techniques and accounting designations.
The forward-looking information presented below provides estimates of what may occur in the future, assuming certain adverse market conditions and model assumptions. Actual future results may differ materially from those presented. These disclosures are not precise indicators of expected future losses, but only indicators of possible losses under normal market conditions at a given confidence level.
Commodity Price Risk (Non-trading)
KU's rates are set by regulatory commissions and the fuel costs incurred are directly recoverable from customers. As a result, KU is subject to commodity price risk for only a small portion of on-going business operations. KU conducts energy trading and risk management activities to maximize the value of the physical assets at times when the assets are not required to serve KU's or LG&E's customers. KU managed its energy commodity risk using derivative instruments, including swaps and forward contracts. See Note 19 to the Financial Statements for additional disclosures.
The balance and change in net fair value of KU's commodity derivative contracts for the periods ended December 31, 2011, 2010, and 2009 were not significant.
Interest Rate Risk
KU has issued debt to finance its operations, which exposes it to interest rate risk. At December 31, 2011 and 2010, KU's potential annual exposure to increased interest expense, based on a 10% increase in interest rates, was not significant.
KU is also exposed to changes in the fair value of its debt portfolio. KU estimated that a 10% decrease in interest rates at December 31, 2011, would increase the fair value of its debt portfolio by $72 million compared with $73 million at December 31, 2010.
KU had no interest rate hedges outstanding at December 31, 2011 and December 31, 2010.
Credit Risk
KU is exposed to potential losses as a result of nonperformance by counterparties of their contractual obligations. KU maintains credit policies and procedures to limit counterparty credit risk including evaluating credit ratings and financial information along with having certain counterparties post margin if the credit exposure exceeds certain thresholds. KU is exposed to potential losses as a result of nonpayment by customers. KU maintains an allowance for doubtful accounts based on a historical charge-off percentage for retail customers. Allowances for doubtful accounts from wholesale and municipal customers and miscellaneous receivables are based on specific identification by management. Retail, wholesale and municipal customer accounts are written-off after four months of no payment activity. Miscellaneous receivables are written-off as management determines them to be uncollectible.
Certain of KU's derivative instruments contain provisions that require it to provide immediate and on-going collateralization of derivative instruments in net liability positions based upon KU's credit ratings from each of the major credit rating agencies. See Notes 18 and 19 to the Financial Statements for information regarding exposure and the risk management activities.
Related Party Transactions
KU is not aware of any material ownership interest or operating responsibility by senior management in outside partnerships, including leasing transactions with variable interest entities or other entities doing business with KU. See Note 16 to the Financial Statements for additional information on related party transactions between KU and affiliates.
Environmental Matters
Protection of the environment is a major priority for KU and a significant element of its business activities. Extensive federal, state and local environmental laws and regulations are applicable to KU's air emissions, water discharges and the management of hazardous and solid waste, among other areas, and the costs of compliance or alleged non-compliance cannot be predicted with certainty but could be material. In addition, costs may increase significantly if the requirements or scope of environmental laws or regulations, or similar rules, are expanded or changed from prior versions by the relevant agencies. Costs may take the form of increased capital or operating and maintenance expenses; monetary fines, penalties or forfeitures or other restrictions. Many of these environmental law considerations are also applicable to the operations of key suppliers, or customers, such as coal producers, industrial power users, etc.; and may impact the costs for their products or their demand for KU's services. See "Item 1. Business - Environmental Matters" and Note 15 to the Financial Statements for a discussion of environmental matters.
New Accounting Guidance
See Note 24 to the Financial Statements for a discussion of new accounting guidance pending adoption.
Application of Critical Accounting Policies
Financial condition and results of operations are impacted by the methods, assumptions and estimates used in the application of critical accounting policies. The following accounting policies are particularly important to the financial condition or results of operations, and require estimates or other judgments of matters inherently uncertain. Changes in the estimates or other judgments included within these accounting policies could result in a significant change to the information presented in the Financial Statements (these accounting policies are also discussed in Note 1 to the Financial Statements). KU's senior management has reviewed these critical accounting policies, the following disclosures regarding their application and the estimates and assumptions regarding them, with PPL's Audit Committee.
1)
Revenue Recognition - Unbilled Revenue
Revenues related to the sale of energy are recorded when service is rendered or when energy is delivered to customers. Because customers of KU's retail operations are billed on cycles which vary based on the timing of the actual reading of their electric meters, KU records estimates for unbilled revenues at the end of each reporting period. Such unbilled revenue amounts reflect estimates of the amount of energy delivered to customers since the date of the last reading of their meters. Such unbilled revenues reflect consideration of estimated usage by customer class, the effect of different rate schedules, changes in weather, and where applicable, the impact of weather normalization or other regulatory provisions of rate structures. In addition to the unbilled revenue accrual resulting from cycle billing, KU makes additional accruals resulting from the timing of customer bills. The accrual of unbilled revenues in this manner properly matches revenues and related costs. At December 31, 2011 and 2010 KU had unbilled revenue balances of $81 million and $89 million.
2)
Price Risk Management
See "Financial Condition - Risk Management" above.
3)
Defined Benefits
KU participates in a qualified funded defined benefit pension and a funded other postretirement benefits plan. These plans are applicable to the majority of the employees of KU and are sponsored by LKE. LKE allocates a portion of the liability and net periodic defined benefit pension and other postretirement costs of the plans to KU based on its participation. KU records an asset or liability to recognize the funded status of all defined benefit plans with an offsetting entry to regulatory assets or liabilities. Consequently, the funded status of all defined benefit plans is fully recognized on the Balance Sheets. See Note 13 to the Financial Statements for additional information about the plans and the accounting for defined benefits.
Certain assumptions are made by LKE regarding the valuation of benefit obligations and the performance of plan assets. When accounting for defined benefits, delayed recognition in earnings of differences between actual results and expected or estimated results is a guiding principle. Annual net periodic defined benefit costs are recorded in current earnings based on
estimated results. Any differences between actual and estimated results are recorded in regulatory assets and liabilities for amounts that are expected to be recovered through regulated customer rates. These amounts in regulatory assets and liabilities are amortized to income over future periods. The delayed recognition allows for a smoothed recognition of costs over the working lives of the employees who benefit under the plans. The primary assumptions are:
·
Discount Rate - The discount rate is used in calculating the present value of benefits, which is based on projections of benefit payments to be made in the future. The objective in selecting the discount rate is to measure the single amount that, if invested at the measurement date in a portfolio of high-quality debt instruments, would provide the necessary future cash flows to pay the accumulated benefits when due.
·
Expected Long-term Return on Plan Assets - Management projects the long-term rates of return on plan assets based on historical performance, future expectations and periodic portfolio rebalancing among the diversified asset classes. These projected returns reduce the net benefit costs KU records currently.
·
Rate of Compensation Increase - Management projects employees' annual pay increases, which are used to project employees' pension benefits at retirement.
·
Health Care Cost Trend Rate - Management projects the expected increases in the cost of health care.
In selecting a discount rate for its defined benefit plans, LKE starts with a cash flow analysis of the expected benefit payment stream for its plans. In 2010, these plan-specific cash flows were matched against a spot-rate yield curve to determine the assumed discount rate. To develop the spot-rate yield curve, the full universe of Aa-rated non-callable (or callable with make-whole provisions) bonds, served as the base from which those with the lowest and highest yields were eliminated to develop an appropriate subset of bonds from which the ultimate yield curve would be built. At that time, management believed this plan-specific cash flow matching model represented the best available tool for estimating the discount rate. Beginning in 2011, LKE utilized a new tool that enhanced this plan-specific cash flow matching methodology by primarily matching the plan-specific cash flows against the coupons and expected maturity values of individually selected bonds. This bond matching process begins with the same universe of Aa-rated corporate bonds from which those with the lowest and highest yields were eliminated, similar to the yield curve approach. Individual bonds are then selected based on the timing of each plan's cash flows and parameters are established as to the percentage of each individual bond issue that could be hypothetically purchased and the surplus reinvestment rates to be assumed. This process more accurately approximated the process of settlement of the obligations which better aligned with the objective of selecting the discount rate. At December 31, 2011 LKE decreased the discount rate for its pension plan from 5.52% to 5.12% and decreased the discount rate for its other postretirement benefit plan from 5.12% to 4.78%.
The expected long-term rates of return for LKE's defined benefit pension and other postretirement benefit plans have been developed using a best-estimate of expected returns, volatilities and correlations for each asset class. LKE management corroborates these rates with expected long-term rates of return calculated by its independent actuary, who uses a building block approach that begins with a risk-free rate of return with factors being added such as inflation, duration, credit spreads and equity risk. Each plan's specific asset allocation is also considered in developing a reasonable return assumption. At December 31, 2011, LKE's expected return on plan assets was 7.25%.
In selecting a rate of compensation increase, LKE considers past experience in light of movements in inflation rates. At December 31, 2011, LKE's rate of compensation increase changed from 5.25% to 4.00%.
In selecting health care cost trend rates LKE considers past performance and forecasts of health care costs. At December 31, 2011, LKE's health care cost trend rates were 8.50% for 2012, gradually declining to 5.50% for 2019.
A variance in the assumptions listed above could have a significant impact on accrued defined benefit liabilities or assets, reported annual net periodic defined benefit costs and regulatory assets and liabilities allocated to KU. While the charts below reflect either an increase or decrease in each assumption, the inverse of the change would impact the accrued defined benefit liabilities or assets, reported annual net periodic defined benefit costs and regulatory assets and liabilities for KU by a similar amount in the opposite direction. The sensitivities below reflect an evaluation of the change based solely on a change in that assumption and does not include income tax effects.
At December 31, 2011, the defined benefit plans were recorded as follows:
The following chart reflects the sensitivities in the December 31, 2011 Balance Sheet associated with a change in certain assumptions based on KU's primary defined benefit plans.
(a)
Only impacts other postretirement benefits.
In 2011 and 2010, KU recognized net periodic defined benefit costs charged to operating expense of $14 million.
The following chart reflects the sensitivities in the 2011 Statement of Income (excluding income tax effects) associated with a change in certain assumptions based on KU's primary defined benefit plans.
(a)
Only impacts other postretirement benefits.
4) Asset Impairment
Impairment analyses are performed for long-lived assets that are subject to depreciation or amortization whenever events or changes in circumstances indicate that a long-lived asset's carrying value may not be recoverable. For these long-lived assets classified as held and used, such events or changes in circumstances are:
·
a significant decrease in the market price of an asset;
·
a significant adverse change in the extent or manner in which an asset is being used or in its physical condition;
·
a significant adverse change in legal factors or in the business climate;
·
an accumulation of costs significantly in excess of the amount originally expected for the acquisition or construction of an asset;
·
a current-period operating or cash flow loss combined with a history of losses or a forecast that demonstrates continuing losses; or
·
a current expectation that, more likely than not, an asset will be sold or otherwise disposed of significantly before the end of its previously estimated useful life.
For a long-lived asset classified as held and used, impairment is recognized when the carrying amount of the asset is not recoverable and exceeds its fair value. The carrying amount is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. If the asset is impaired, an impairment loss is recorded to adjust the asset's carrying value to its estimated fair value. Management must make significant judgments to estimate future cash flows including the useful lives of long-lived assets, the fair value of the assets and management's intent to use the assets. Alternate courses of action are considered to recover the carrying value of a long-lived asset, and estimated cash flows from the "most likely" alternative are used to assess impairment whenever one alternative is clearly the most likely outcome. If no alternative is clearly the most likely, then a probability-weighted approach is used taking into consideration estimated cash flows from the alternatives. For assets tested for impairment as of the balance sheet date, the estimates of future cash flows used in that test consider the likelihood of possible outcomes that existed at the balance sheet date, including the assessment of the likelihood of a future sale of the assets. That assessment is not revised based on events that occur after the balance sheet date. Changes in assumptions and estimates could result in significantly different results than those identified and recorded in the financial statements.
For a long-lived asset classified as held for sale, impairment exists when the carrying amount of the asset (disposal group) exceeds its fair value less cost to sell. If the asset (disposal group) is impaired, an impairment loss is recorded to adjust the carrying amount to its fair value less cost to sell. A gain is recognized for any subsequent increase in fair value less cost to sell, but not in excess of the cumulative impairment recognized.
For determining fair value, quoted market prices in active markets are the best evidence. However, when market prices are unavailable, KU considers all valuation techniques appropriate under the circumstances and for which market participant inputs can be obtained. Generally discounted cash flows are used to estimate fair value, which incorporates market participant inputs when available. Discounted cash flows are calculated by estimating future cash flow streams and applying appropriate discount rates to determine the present value of the cash flow streams.
In 2011, KU did not recognize an impairment of any long-lived assets.
Goodwill is tested for impairment at the reporting unit level. KU's reporting unit has been determined to be at the operating segment level. A goodwill impairment test is performed annually or more frequently if events or changes in circumstances indicate that the carrying value of the reporting unit may be greater than the unit's fair value. Additionally, goodwill is tested for impairment after a portion of goodwill has been allocated to a business to be disposed of. Goodwill is tested for impairment using a two-step approach. In step 1, KU identifies a potential impairment by comparing the estimated fair value of KU (the goodwill reporting unit) to its carrying value, including goodwill, on the measurement date. If the estimated fair value exceeds its carrying amount, goodwill is not considered impaired. If the carrying amount exceeds the estimated fair value, the second step is performed to measure the amount of impairment loss, if any.
The second step requires a calculation of the implied fair value of goodwill, which is determined in the same manner as the amount of goodwill in a business combination. That is, the estimated fair value is allocated to all of KU's assets and liabilities as if KU had been acquired in a business combination and the estimated fair value of KU was the price paid. The excess of the estimated fair value of KU over the amounts assigned to its assets and liabilities is the implied fair value of goodwill. The implied fair value of goodwill is then compared with the carrying amount of that goodwill. If the carrying amount exceeds the implied fair value, an impairment loss is recognized in an amount equal to that excess. The loss recognized cannot exceed the carrying amount of the reporting unit's goodwill.
KU tested goodwill for impairment in the fourth quarter of 2011 and no impairment was recognized. Management used both discounted cash flows and market multiples to estimate the fair value of LKE, which involved the use of significant estimates and assumptions. Applying an appropriate weighting to both the discounted cash flow and market multiple valuations, a decrease in the forecasted cash flows of 10%, an increase in the discount rate by 25 basis points, or a 10% decrease in the multiples would not have resulted in an impairment of goodwill.
5)
Loss Accruals
Losses are accrued for the estimated impacts of various conditions, situations or circumstances involving uncertain or contingent future outcomes. For loss contingencies, the loss must be accrued if (1) information is available that indicates it is probable that a loss has been incurred, given the likelihood of the uncertain future events and (2) the amount of the loss can be reasonably estimated. Accounting guidance defines "probable" as cases in which "the future event or events are likely to occur." The accrual of contingencies that might result in gains is not recorded unless recovery is assured. Potential loss contingencies for environmental remediation, litigation claims, regulatory penalties and other events are continuously assessed.
The accounting aspects of estimated loss accruals include (1) the initial identification and recording of the loss, (2) the determination of triggering events for reducing a recorded loss accrual and (3) the ongoing assessment as to whether a recorded loss accrual is sufficient. All three of these aspects require significant judgment by management. Internal expertise and outside experts (such as lawyers and engineers) are used, as necessary to help estimate the probability that a loss has been incurred and the amount (or range) of the loss.
In 2011, no significant adjustments were made to KU's existing contingencies. See Note 15 to the Financial Statements for commitment and contingency disclosures.
Certain other events have been identified that could give rise to a loss, but that do not meet the conditions for accrual. Such events are disclosed, but not recorded, when it is reasonably possible that a loss has been incurred. Accounting guidance defines "reasonably possible" as cases in which "the future event or events occurring is more than remote, but less than likely to occur." See Note 15 to the Financial Statements for disclosure of other potential loss contingencies that have not met the criteria for accrual.
When an estimated loss is accrued, the triggering events for subsequently adjusting the loss accrual are identified, where applicable. The triggering events generally occur when the contingency has been resolved and the actual loss is paid or written off, or when the risk of loss has diminished or been eliminated. The following are some of the triggering events that provide for the adjustment of certain recorded loss accruals:
·
Allowances for uncollectible accounts are reduced when accounts are written off after prescribed collection procedures have been exhausted, a better estimate of the allowance is determined or underlying amounts are ultimately collected.
·
Environmental and other litigation contingencies are reduced when the contingency is resolved, KU makes actual payments, a better estimate of the loss is determined or the loss is no longer considered probable.
Loss accruals are reviewed on a regular basis to assure that the recorded potential loss exposures are appropriate. This involves ongoing communication and analyses with internal and external legal counsel, engineers, operation management and other parties.
6)
Asset Retirement Obligations
KU is required to recognize a liability for legal obligations associated with the retirement of long-lived assets. The initial obligation is measured at its estimated fair value. An equivalent amount is recorded as an increase in the value of the capitalized asset and allocated to expense over the useful life of the asset. Until the obligation is settled, the liability is increased, through the recognition of accretion expense in the Statements of Income, for changes in the obligation due to the passage of time. The accretion and depreciation are offset with a regulatory credit on the income statement, such that there is no earnings impact. The regulatory asset created by the regulatory credit is relieved when the ARO has been settled. An ARO must be recognized when incurred if the fair value of the ARO can be reasonably estimated. See Note 21 to the Financial Statements for related disclosures.
In determining AROs, management must make significant judgments and estimates to calculate fair value. Fair value is developed using an expected present value technique based on assumptions of market participants that considers estimated retirement costs in current period dollars that are inflated to the anticipated retirement date and then discounted back to the date the ARO was incurred. Changes in assumptions and estimates included within the calculations of the fair value of AROs could result in significantly different results than those identified and recorded in the financial statements. Estimated ARO costs and settlement dates, which affect the carrying value of various AROs and the related assets, are reviewed periodically to ensure that any material changes are incorporated into the estimate of the obligations. Any change to the capitalized asset is amortized over the remaining life of the associated long-lived asset.
At December 31, 2011, KU had AROs totaling $61 million recorded on the Balance Sheet. Of the total amount, $40 million, or 66%, relates to KU's ash ponds. The most significant assumptions surrounding AROs are the forecasted retirement costs, the discount rates and the inflation rates. A variance in the forecasted retirement costs, the discount rates or the inflation rates could have a significant impact on the ARO liabilities.
The following chart reflects the sensitivities related to KU's ARO liabilities for ash ponds at December 31, 2011:
7)
Income Taxes
Significant management judgment is required in developing KU's provision for income taxes primarily due to the uncertainty related to tax positions taken or expected to be taken in tax returns and the determination of deferred tax assets, liabilities and valuation allowances.
Significant management judgment is required to determine the amount of benefit recognized related to an uncertain tax position. KU evaluates its tax positions following a two-step process. The first step requires an entity to determine whether, based on the technical merits supporting a particular tax position, it is more likely than not (greater than a 50% chance) that the tax position will be sustained. This determination assumes that the relevant taxing authority will examine the tax position and is aware of all the relevant facts surrounding the tax position. The second step requires an entity to recognize in the financial statements the benefit of a tax position that meets the more-likely-than-not recognition criterion. The benefit recognized is measured at the largest amount of benefit that has a likelihood of realization upon settlement that exceeds 50%. KU's management considers a number of factors in assessing the benefit to be recognized, including negotiation of a settlement.
On a quarterly basis, KU's uncertain tax positions are reassessed by considering information known at the reporting date. Based on management's assessment of new information, a tax benefit may subsequently be recognized for a previously unrecognized tax position, a previously recognized tax position maybe de-recognized, or the benefit of a previously
recognized tax position may be remeasured. The amounts ultimately paid upon resolution of issues raised by taxing authorities may differ materially from the amounts accrued and may materially impact the financial statements in the future.
At December 31, 2011, KU's existing reserve exposure to either increases or decreases in unrecognized tax benefits during the next 12 months is less than $1 million. This change could result from subsequent recognition, de-recognition and/or changes in the measurement of uncertain tax positions. The events that could cause these changes are direct settlements with taxing authorities, litigation, legal or administrative guidance by relevant taxing authorities and the lapse of an applicable statute of limitation.
The balance sheet classification of unrecognized tax benefits and the need for valuation allowances to reduce deferred tax assets also require significant management judgment. Unrecognized tax benefits are classified as current to the extent management expects to settle an uncertain tax position by payment or receipt of cash within one year of the reporting date. Valuation allowances are initially recorded and reevaluated each reporting period by assessing the likelihood of the ultimate realization of a deferred tax asset. Management considers a number of factors in assessing the realization of a deferred tax asset, including the reversal of temporary differences, future taxable income and ongoing prudent and feasible tax planning strategies. Any tax planning strategy utilized in this assessment must meet the recognition and measurement criteria utilized to account for an uncertain tax position. See Note 5 to the Financial Statements for related disclosures.
8)
Regulatory Assets and Liabilities
KU is a cost-based rate-regulated utility. As a result, the effects of regulatory actions are required to be reflected in the financial statements. Assets and liabilities are recorded that result from the regulated ratemaking process that may not be recorded under GAAP for non-regulated entities. Regulatory assets generally represent incurred costs that have been deferred because such costs are probable of future recovery in regulated customer rates. Regulatory liabilities are recognized for amounts expected to be returned through future regulated customer rates. In certain cases, regulatory liabilities are recorded based on an understanding with the regulator that rates have been set to recover costs that are expected to be incurred in the future, and the regulated entity is accountable for any amounts charged pursuant to such rates and not yet expended for the intended purpose. The accounting for regulatory assets and liabilities is based on specific ratemaking decisions or precedent for each transaction or event as prescribed by the FERC, the KPSC, the VSCC or the TRA. See Note 6 to the Financial Statements for related disclosures.
Management continually assesses whether the regulatory assets are probable of future recovery by considering factors such as changes in the applicable regulatory and political environments, the ability to recover costs through regulated rates, recent rate orders to other regulated entities and the status of any pending or potential deregulation legislation. Based on this continual assessment, management believes the existing regulatory assets are probable of recovery. This assessment reflects the current political and regulatory climate at the state and federal levels, and is subject to change in the future. If future recovery of costs ceases to be probable, then asset write-off would be required to be recognized in operating income. Additionally, the regulatory agencies can provide flexibility in the manner and timing of the depreciation of PP&E and amortization of regulatory assets.
At December 31, 2011 and 2010, KU had regulatory assets of $217 million and $230 million. All regulatory assets are either currently being recovered under specific rate orders, represent amounts that are expected to be recovered in future rates or benefit future periods based upon established regulatory practices. At December 31, 2011 and 2010, KU had regulatory liabilities of $535 million and $574 million.
Other Information
PPL's Audit Committee has approved the independent auditor to provide audit, tax and other services permitted by Sarbanes-Oxley and SEC rules. The audit services include services in connection with statutory and regulatory filings, reviews of offering documents and registration statements, and internal control reviews. See "Item 14. Principal Accounting Fees and Services" for more information.
ITEM 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
PPL Corporation, PPL Energy Supply, LLC, PPL Electric Utilities Corporation, LG&E and KU Energy LLC, Louisville Gas and Electric Company and Kentucky Utilities Company
Reference is made to "Risk Management - Energy Marketing & Trading and Other" for PPL and PPL Energy Supply and "Risk Management" for PPL Electric, LKE, LG&E and KU in "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations."
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareowners of PPL Corporation
We have audited the accompanying consolidated balance sheets of PPL Corporation and subsidiaries as of December 31, 2011 and 2010, and the related consolidated statements of income, comprehensive income, equity, and cash flows for each of the three years in the period ended December 31, 2011. Our audits also included the financial statement schedule listed in the index at Item 15(a). These financial statements and schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits. We did not audit the 2010 financial statements of LG&E and KU Energy LLC (LKE), a wholly owned subsidiary, which statements reflect total assets of $10,719 million as of December 31, 2010, and total revenues of $493 million for the period November 1, 2010 (date of acquisition) to December 31, 2010. Those statements were audited by other auditors whose report has been furnished to us, and our opinion, insofar as it relates to the amounts included for LKE, is based solely on the report of the other auditors.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits and the report of other auditors provide a reasonable basis for our opinion.
In our opinion, based on our audits and, for 2010, the report of other auditors, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of PPL Corporation and subsidiaries at December 31, 2011 and 2010, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2011, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), PPL Corporation's internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 28, 2012 expressed an unqualified opinion thereon.
/s/ Ernst & Young LLP
Philadelphia, Pennsylvania
February 28, 2012
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareowners of PPL Corporation
We have audited PPL Corporation's internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). PPL Corporation's management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in Management's Report on Internal Control over Financial Reporting at Item 9A. Our responsibility is to express an opinion on the company's internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with U.S. generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
As set forth in Item 9A, Management's Report on Internal Control over Financial Reporting, management's assessment of and conclusion on the effectiveness of internal control over financial reporting did not include the internal controls of WPD Midlands, which is included in the 2011 consolidated financial statements of PPL Corporation and subsidiaries and constituted 19% and 27% of total assets and net assets, respectively, as of December 31, 2011 and 6% and 9% of revenues and net income, respectively, for the year then ended. Our audit of internal control over financial reporting of PPL Corporation and subsidiaries also did not include an evaluation of the internal control over financial reporting of WPD Midlands.
In our opinion, PPL Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2011, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of PPL Corporation and subsidiaries as of December 31, 2011 and 2010, and the related consolidated statements of income, comprehensive income, equity, and cash flows for each of the three years in the period ended December 31, 2011 and our report dated February 28, 2012 expressed an unqualified opinion thereon.
/s/ Ernst & Young LLP
Philadelphia, Pennsylvania
February 28, 2012
Report of Independent Registered Public Accounting Firm
To the Board of Managers and Sole Member of PPL Energy Supply, LLC
We have audited the accompanying consolidated balance sheets of PPL Energy Supply, LLC and subsidiaries as of December 31, 2011 and 2010, and the related consolidated statements of income, comprehensive income, equity, and cash flows for each of the three years in the period ended December 31, 2011. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company's internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of PPL Energy Supply, LLC and subsidiaries at December 31, 2011 and 2010, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2011, in conformity with U.S. generally accepted accounting principles.
/s/ Ernst & Young LLP
Philadelphia, Pennsylvania
February 28, 2012
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareowners of PPL Electric Utilities Corporation
We have audited the accompanying consolidated balance sheets of PPL Electric Utilities Corporation and subsidiaries as of December 31, 2011 and 2010, and the related consolidated statements of income, shareowners' equity, and cash flows for each of the three years in the period ended December 31, 2011. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company's internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of PPL Electric Utilities Corporation and subsidiaries at December 31, 2011 and 2010, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2011, in conformity with U.S. generally accepted accounting principles.
/s/ Ernst & Young LLP
Philadelphia, Pennsylvania
February 28, 2012
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Sole Member of LG&E and KU Energy LLC
We have audited the accompanying consolidated balance sheet of LG&E and KU Energy LLC and subsidiaries as of December 31, 2011, and the related consolidated statements of income, comprehensive income, cash flows, and equity for the year then ended. Our audit also included the financial statement schedule listed in the index at Item 15(a). These financial statements and schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and schedule based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company's internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of LG&E and KU Energy LLC and subsidiaries at December 31, 2011 and the consolidated results of their operations and their cash flows for the year then ended, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.
/s/ Ernst & Young LLP
Louisville, Kentucky
February 28, 2012
Report of Independent Registered Public Accounting Firm
To the Member of LG&E and KU Energy LLC
In our opinion, the accompanying consolidated balance sheet and the related consolidated statements of income, retained earnings, comprehensive income, cash flows, and capitalization present fairly, in all material respects, the financial position of LG&E and KU Energy LLC and its subsidiaries (Successor Company) at December 31, 2010 and the results of their operations and their cash flows for the period from November 1, 2010 to December 31, 2010 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audit. We conducted our audit of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
As discussed in Note 10 to the consolidated financial statements, on November 1, 2010, PPL Corporation completed its acquisition of LG&E and KU Energy LLC and its subsidiaries. The push-down basis of accounting was used at the acquisition date.
/s/ PricewaterhouseCoopers LLP
Louisville, Kentucky
February 25, 2011
Report of Independent Registered Public Accounting Firm
To the Member of LG&E and KU Energy LLC
In our opinion, the accompanying consolidated statements of income, retained earnings (deficit), comprehensive income (loss), cash flows, and capitalization present fairly, in all material respects, the results of operations and cash flows of LG&E and KU Energy LLC and its subsidiaries (formerly E.ON U.S. LLC, Predecessor Company) for the period from January 1, 2010 to October 31, 2010 and for the year ended December 31, 2009 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
As discussed in Note 10 to the consolidated financial statements, on November 1, 2010, PPL Corporation completed its acquisition of LG&E and KU Energy LLC and its subsidiaries. The push-down basis of accounting was used at the acquisition date.
/s/ PricewaterhouseCoopers LLP
Louisville, Kentucky
February 25, 2011
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Sole Stockholder of Louisville Gas and Electric Company
We have audited the accompanying balance sheet of Louisville Gas and Electric Company as of December 31, 2011, and the related statements of income, comprehensive income, cash flows, and equity for the year then ended. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company's internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Louisville Gas and Electric Company at December 31, 2011 and the results of its operations and its cash flows for the year then ended, in conformity with U.S. generally accepted accounting principles.
/s/ Ernst & Young LLP
Louisville, Kentucky
February 28, 2012
Report of Independent Registered Public Accounting Firm
To the Stockholder of Louisville Gas and Electric Company
In our opinion, the accompanying balance sheet and the related statements of income, retained earnings, comprehensive income, cash flows, and capitalization present fairly, in all material respects, the financial position of Louisville Gas and Electric Company (Successor Company) at December 31, 2010 and the results of its operations and its cash flows for the period from November 1, 2010 to December 31, 2010 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
As discussed in Note 10 to the financial statements, on November 1, 2010, PPL Corporation completed its acquisition of LG&E and KU Energy LLC and its subsidiaries. The push-down basis of accounting was used at the acquisition date.
/s/ PricewaterhouseCoopers LLP
Louisville, Kentucky
February 25, 2011
Report of Independent Registered Public Accounting Firm
To the Stockholder of Louisville Gas and Electric Company
In our opinion, the accompanying statements of income, retained earnings, comprehensive income, cash flows, and capitalization present fairly, in all material respects, the results of operations and cash flows of Louisville Gas and Electric Company (Predecessor Company) for the period from January 1, 2010 to October 31, 2010 and for the year ended December 31, 2009 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
As discussed in Note 10 to the financial statements, on November 1, 2010, PPL Corporation completed its acquisition of LG&E and KU Energy LLC and its subsidiaries. The push-down basis of accounting was used at the acquisition date.
/s/ PricewaterhouseCoopers LLP
Louisville, Kentucky
February 25, 2011
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Sole Stockholder of Kentucky Utilities Company
We have audited the accompanying balance sheet of Kentucky Utilities Company as of December 31, 2011, and the related statements of income, comprehensive income, cash flows, and equity for the year then ended. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company's internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Kentucky Utilities Company at December 31, 2011 and the results of its operations and its cash flows for the year then ended, in conformity with U.S. generally accepted accounting principles.
/s/ Ernst & Young LLP
Louisville, Kentucky
February 28, 2012
Report of Independent Registered Public Accounting Firm
To the Stockholder of Kentucky Utilities Company
In our opinion, the accompanying balance sheet and the related statements of income, retained earnings, comprehensive income, cash flows, and capitalization present fairly, in all material respects, the financial position of Kentucky Utilities Company (Successor Company) at December 31, 2010 and the results of its operations and its cash flows for the period from November 1, 2010 to December 31, 2010 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
As discussed in Note 10 to the financial statements, on November 1, 2010, PPL Corporation completed its acquisition of LG&E and KU Energy LLC and its subsidiaries. The push-down basis of accounting was used at the acquisition date.
/s/ PricewaterhouseCoopers LLP
Louisville, Kentucky
February 25, 2011
Report of Independent Registered Public Accounting Firm
To the Stockholder of Kentucky Utilities Company
In our opinion, the accompanying statements of income, retained earnings, comprehensive income, cash flows, and capitalization present fairly, in all material respects, the results of operations and cash flows of Kentucky Utilities Company (Predecessor Company) for the period from January 1, 2010 to October 31, 2010 and for the year ended December 31, 2009 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
As discussed in Note 10 to the financial statements, on November 1, 2010, PPL Corporation completed its acquisition of LG&E and KU Energy LLC and its subsidiaries. The push-down basis of accounting was used at the acquisition date.
/s/ PricewaterhouseCoopers LLP
Louisville, Kentucky
February 25, 2011
(a)
At December 31, 2011 and December 31, 2010, includes $416 million and $424 million of PP&E, consisting primarily of "Generation," including leasehold improvements, and $11 million of "Other intangibles" from the consolidation of a VIE that is the owner/lessor of the Lower Mt. Bethel plant. See Note 22 for additional information.
The accompanying Notes to Financial Statements are an integral part of the financial statements.
(a)
780,000 shares authorized; 578,405 and 483,391 shares issued and outstanding at December 31, 2011 and December 31, 2010.
The accompanying Notes to Financial Statements are an integral part of the financial statements.
(a)
Shares in thousands. Each share entitles the holder to one vote on any question presented to any shareowners' meeting.
(b)
See "General - Comprehensive Income" in Note 1 for disclosure of balances of each component of AOCI.
(c)
2011 includes the April issuance of 92 million shares of common stock. See Note 7 for additional information. 2010 includes the June issuance of 103.5 million shares of common stock. Each year includes shares of common stock issued through various stock and incentive compensation plans.
(d)
"Earnings reinvested" includes dividends and dividend equivalents on PPL Corporation common stock and restricted stock units. "Noncontrolling interests" includes dividends, redemptions and distributions to noncontrolling interests. 2010 includes $54 million paid to redeem PPL Electric's preferred stock, including an insignificant premium.
(e)
Recorded in connection with the adoption of accounting guidance related to the recognition and presentation of other-than-temporary impairments.
(f)
2011 includes $123 million for the 2011 Purchase Contracts and $20 million of related fees and expenses, net of tax. See Note 7 for additional information. 2010 includes $157 million for the 2010 Purchase Contracts and $19 million of related fees and expenses, net of tax.
The accompanying Notes to Financial Statements are an integral part of the financial statements.
(a)
At December 31, 2011 and December 31, 2010, includes $416 million and $424 million of PP&E, consisting primarily of "Generation," including leasehold improvements, and $11 million of "Other intangibles" from the consolidation of a VIE that is the owner/lessor of the Lower Mt. Bethel plant. See Note 22 for additional information.
The accompanying Notes to Financial Statements are an integral part of the financial statements.
(a)
See "General - Comprehensive Income" in Note 1 for disclosure of balances of each component of AOCI.
(b)
See Note 9 for additional information.
The accompanying Notes to Financial Statements are an integral part of the financial statements.
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(a)
170,000 shares authorized; 66,368 shares issued and outstanding at December 31, 2011 and December 31, 2010.
The accompanying Notes to Financial Statements are an integral part of the financial statements.
(a)
Shares in thousands. All common shares of PPL Electric stock are owned by PPL.
(b)
In April 2010, PPL Electric redeemed all of its outstanding preferred stock. See Note 3 for additional information.
The accompanying Notes to Financial Statements are an integral part of the financial statements.
(a) See "General - Comprehensive Income" in Note 1 for disclosure of balances of each component of AOCI.
The accompanying Notes to Financial Statements are an integral part of the financial statements.
(a)
75,000 shares authorized; 21,294 shares issued and outstanding at December 31, 2011 and December 31, 2010.
The accompanying Notes to Financial Statements are an integral part of the financial statements.
(a) Shares in thousands. All common shares of LG&E stock are owned by LKE.
(b) See "General - Comprehensive Income" in Note 1 for disclosure of balances of each component of AOCI.
The accompanying Notes to Financial Statements are an integral part of the financial statements.
(a) 80,000 shares authorized; 37,818 shares issued and outstanding at December 31, 2011 and December 31, 2010.
The accompanying Notes to Financial Statements are an integral part of the financial statements.
(a) Shares in thousands. All common shares of KU stock are owned by LKE.
(b) See "General - Comprehensive Income" in Note 1 for disclosure of balances of each component of AOCI.
The accompanying Notes to Financial Statements are an integral part of the financial statements.
COMBINED NOTES TO FINANCIAL STATEMENTS
1. Summary of Significant Accounting Policies
(PPL, PPL Energy Supply, PPL Electric, LKE, LG&E and KU)
General
Capitalized terms and abbreviations are explained in the glossary. Dollars are in millions, except per share data, unless otherwise noted.
Business and Consolidation
(PPL)
PPL is an energy and utility holding company that, through its subsidiaries, is primarily engaged in: 1) the regulated generation, transmission, distribution and sale of electricity and the regulated distribution and sale of natural gas, primarily in Kentucky; 2) the regulated distribution of electricity in the U.K.; 3) the regulated transmission, distribution and sale of electricity in Pennsylvania; and 4) the competitive generation and marketing of electricity in portions of the northeastern and northwestern U.S. Headquartered in Allentown, PA, PPL's principal subsidiaries are LKE (including its principal subsidiaries, LG&E and KU), PPL Global, PPL Electric and PPL Energy Supply (including its principal subsidiaries, PPL EnergyPlus and PPL Generation).
On April 1, 2011, PPL, through its indirect, wholly owned subsidiary PPL WEM, completed its acquisition of all of the outstanding ordinary share capital of Central Networks East plc and Central Networks Limited, the sole owner of Central Networks West plc, together with certain other related assets and liabilities (collectively referred to as Central Networks and subsequently referred to as WPD Midlands), from subsidiaries of E.ON AG. As PPL is consolidating WPD Midlands on a one-month lag, eight months of WPD Midlands' operating results are included in PPL's results of operations for 2011 with no comparable amounts for 2010.
On November 1, 2010, PPL acquired all of the limited liability company interests of E.ON U.S. LLC from a wholly owned subsidiary of E.ON AG. Upon completion of the acquisition, E.ON U.S. LLC was renamed LG&E and KU Energy LLC. LKE's operating results are included in PPL's results of operations for the full year of 2011, while 2010 includes LKE's operating results for the two months ended December 31, 2010.
See Note 10 for additional information regarding the acquisitions of WPD Midlands and LKE.
(PPL, LKE, LG&E and KU)
LKE is a holding company with cost-based rate-regulated utility operations through its subsidiaries, LG&E and KU, and is subject to PUHCA. LG&E and KU are engaged in the regulated generation, transmission, distribution and sale of electricity. LG&E also engages in the regulated distribution and sale of natural gas. LG&E and KU maintain their separate identities and serve customers in Kentucky under their respective names. KU also serves customers in Virginia under the Old Dominion Power name and it serves customers in Tennessee under the KU name.
(LKE, LG&E and KU)
The financial statements and accompanying footnotes of LKE, LG&E and KU have been segregated to present pre-acquisition activity as the "Predecessor" and post-acquisition activity as the "Successor." Predecessor activity covers the time period prior to November 1, 2010. Successor activity covers the time period after October 31, 2010. Certain accounting and presentation methods were changed to acceptable alternatives in the Successor financial statements to conform to PPL's accounting policies. The cost basis of certain assets and liabilities were changed as of November 1, 2010 as a result of the application of push-down accounting. Consequently, the financial position, results of operations and cash flows for the Successor period are not comparable to the Predecessor period. "Earnings reinvested" on the Balance Sheets of LG&E and KU were reset to $0 as of November 1, 2010 and only reflect earnings and dividend activity since that date. See Note 7 for information about an application filed with the FERC regarding future dividend payments related to this push-down accounting impact.
(PPL and PPL Energy Supply)
PPL Generation owns and operates a portfolio of competitive domestic power generating assets. These power plants are located in Pennsylvania and Montana and use well-diversified fuel sources including coal, uranium, natural gas, oil and water. PPL EnergyPlus sells electricity produced by PPL Generation subsidiaries, participates in wholesale market load-following auctions, and markets various energy products and commodities such as: capacity, transmission, FTRs, coal,
natural gas, oil, uranium, emission allowances, RECs and other commodities in competitive wholesale and competitive retail markets, primarily in the northeastern and northwestern U.S.
(PPL Energy Supply)
In January 2011, PPL Energy Supply distributed its membership interest in PPL Global, representing 100% of the outstanding membership interest of PPL Global, to PPL Energy Supply's parent, PPL Energy Funding. The distribution was made based on the book value of the assets and liabilities of PPL Global with financial effect as of January 1, 2011. See Note 9 for additional information.
(PPL, PPL Energy Supply and LKE)
"Income (Loss) from Discontinued Operations (net of income taxes)" on the Statements of Income includes the activities of various businesses that were sold or distributed. See Note 9 for additional information. The Statements of Cash Flows do not separately report the cash flows of the Discontinued Operations, except for the LKE Predecessor period, which separately discloses these cash flows within operating, investing and financing activities, consistent with LKE's pre-acquisition accounting policy.
(PPL and PPL Electric)
PPL Electric is a cost-based rate-regulated subsidiary of PPL. PPL Electric's principal business is the regulated transmission and distribution of electricity to serve retail customers in its franchised territory in eastern and central Pennsylvania and the regulated supply of electricity to retail customers in that territory as a PLR.
(PPL, PPL Energy Supply, PPL Electric, LKE, LG&E and KU)
The financial statements of the Registrants include each company's own accounts as well as the accounts of all entities in which the company has a controlling financial interest. Entities for which a controlling financial interest is not demonstrated through voting interests are evaluated based on accounting guidance for VIEs. The Registrants consolidate a VIE when they are determined to have a controlling interest in the VIE, and thus are the primary beneficiary of the entity. For PPL and PPL Energy Supply, see Note 22 for information regarding a consolidated VIE. Investments in entities in which a company has the ability to exercise significant influence but does not have a controlling financial interest are accounted for under the equity method. All other investments are carried at cost or fair value. All significant intercompany transactions have been eliminated. Any noncontrolling interests are reflected in the financial statements.
The financial statements of PPL, PPL Energy Supply, LKE, LG&E and KU include their share of any undivided interests in jointly owned facilities, as well as their share of the related operating costs of those facilities. See Note 14 for additional information.
(PPL)
PPL consolidates WPD, including WPD Midlands, on a one-month lag. Material intervening events, such as debt issuances that occur in the lag period, are recognized in the current period financial statements. Events that are significant but not material are disclosed.
Regulation
(PPL, PPL Electric, LKE, LG&E and KU)
PPL Electric, LG&E and KU are cost-based rate-regulated utilities for which rates are set by regulators to enable PPL Electric, LG&E and KU to recover the costs of providing electric or gas service, as applicable, and to provide a reasonable return to shareholders. Rates are generally established based on a historical test period adjusted to exclude unusual or nonrecurring items. As a result, the financial statements are subject to the accounting for certain types of regulation as prescribed by GAAP and reflect the effects of regulatory actions. Regulatory assets are recognized for the effect of transactions or events where future recovery of underlying costs is probable in regulated customer rates. The effect of such accounting is to defer certain or qualifying costs that would otherwise currently be charged to expense. Regulatory liabilities are recognized for amounts expected to be returned through future regulated customer rates. In certain cases, regulatory liabilities are recorded based on an understanding or agreement with the regulator that rates have been set to recover costs that are expected to be incurred in the future, and the regulated entity is accountable for any amounts charged pursuant to such rates and not yet expended for the intended purpose. The accounting for regulatory assets and liabilities is based on
specific ratemaking decisions or precedent for each transaction or event as prescribed by the FERC or the applicable state regulatory commissions. See Note 6 for additional details regarding regulatory matters.
(PPL)
WPD is not subject to accounting for the effects of certain types of regulation as prescribed by GAAP. WPD operates in an incentive-based regulatory structure under distribution licenses granted by Ofgem. Electricity distribution revenues are set every five years through price controls that are not directly based on cost recovery. The price control formula that governs WPD's allowed revenue is designed to provide economic incentives to minimize operating, capital and financing costs. Ofgem completed a review in December 2009 and set distribution revenues that became effective April 1, 2010 and will continue through March 31, 2015.
Accounting Records (PPL, PPL Electric, LKE, LG&E and KU)
The system of accounts is maintained in accordance with the Uniform System of Accounts prescribed by the FERC and adopted by the applicable state regulatory commissions.
(PPL, PPL Energy Supply, PPL Electric, LKE, LG&E and KU)
Use of Estimates
The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Loss Accruals
Potential losses are accrued when (1) information is available that indicates it is "probable" that a loss has been incurred, given the likelihood of the uncertain future events and (2) the amount of the loss can be reasonably estimated. Accounting guidance defines "probable" as cases in which "the future event or events are likely to occur." The Registrants continuously assess potential loss contingencies for environmental remediation, litigation claims, regulatory penalties and other events. Loss accruals for environmental remediation are discounted when appropriate.
The accrual of contingencies that might result in gains is not recorded, unless recovery is assured.
Changes in Classification
The classification of certain amounts in the 2010 and 2009 financial statements have been changed to conform to the current presentation. The changes in classification did not affect the Registrants' net income or equity.
Comprehensive Income (PPL, PPL Energy Supply, LKE, LG&E and KU)
Comprehensive income, which includes net income and OCI, consists of changes in equity from transactions not related to shareowners. Comprehensive income is shown on the Statements of Comprehensive Income.
AOCI, which is presented on the Balance Sheets of PPL and included in Member's Equity on the Balance Sheets of PPL Energy Supply and LKE, consisted of the following after-tax gains (losses).
(a)
Recorded in connection with the adoption of accounting guidance related to the recognition and presentation of other-than-temporary impairments.
(b)
See Note 9 for additional information.
LG&E had AOCI balances of $(14) million and $(10) million at December 31, 2008 and 2009 (Predecessor periods). Changes between periods were due to $4 million of after-tax gains on qualifying derivatives. During the ten months ended October 31, 2010 (a Predecessor period), LG&E had $10 million of after-tax gains on qualifying derivatives. There were no AOCI balances at December 31, 2010 and 2011 (Successor periods).
KU had no AOCI balances at December 31, 2008 or 2009 (Predecessor periods), or at December 31, 2010 or 2011 (Successor periods). KU had $2 million of after-tax losses related to equity investees' AOCI during the ten months ended October 31, 2010 (a Predecessor period) which were eliminated with the effect of the PPL acquisition.
Earnings Per Share (PPL)
EPS is computed using the two-class method, which is an earnings allocation method for computing EPS that treats a participating security as having rights to earnings that would otherwise have been available to common shareowners. Share-
based payment awards that provide recipients a non-forfeitable right to dividends or dividend equivalents are considered participating securities.
Price Risk Management
(PPL, PPL Energy Supply, LKE, LG&E and KU)
Energy and energy-related contracts are used to hedge the variability of expected cash flows associated with the generating units and marketing activities, as well as for trading purposes. Interest rate contracts are used to hedge exposures to changes in the fair value of debt instruments and to hedge exposures to variability in expected cash flows associated with existing debt instruments or forecasted issuances of debt. Foreign currency exchange contracts are used to hedge foreign currency exposures related to firm commitments, recognized assets or liabilities, forecasted transactions, net investments and foreign earnings translation. Similar derivatives may receive different accounting treatment, depending on management's intended use and documentation.
Certain energy and energy-related contracts meet the definition of a derivative, while others do not meet the definition of a derivative because they lack a notional amount or a net settlement provision. In cases where there is no net settlement provision, contracts are periodically reviewed to assess whether a market mechanism has evolved which could facilitate net settlement. Certain derivative energy contracts have been excluded from the requirements of derivative accounting treatment because they meet the definition of NPNS. These contracts are accounted for using accrual accounting. All other contracts that have been classified as derivative contracts are reflected on the balance sheet at their fair value. These contracts are recorded as "Price risk management assets" and "Price risk management liabilities" on the Balance Sheets. Derivative positions that deliver within a year are included in "Current Assets" and "Current Liabilities," while derivative positions that deliver beyond a year are recorded in "Other Noncurrent Assets" and "Deferred Credits and Other Noncurrent Liabilities."
Energy and energy-related trades are assigned a strategy and accounting classification. Processes exist that allow for subsequent review and validation of the trade information. These strategies are discussed in more detail in Note 19. The accounting department provides the traders and the risk management department with guidelines on appropriate accounting classifications for various trade types and strategies. Some examples of these guidelines include, but are not limited to:
·
Physical coal, limestone, lime, uranium, electric transmission, gas transportation, gas storage and renewable energy credit contracts are not derivatives due to the lack of net settlement provisions.
·
Only contracts where physical delivery is deemed probable throughout the entire term of the contract can qualify for the NPNS exception.
·
Physical transactions that permit cash settlement and financial transactions do not qualify for NPNS because physical delivery cannot be asserted; however, these transactions can receive cash flow hedge treatment if they lock in the future cash flows for energy-related commodities.
·
Certain purchased option contracts or net purchased option collars may receive hedge accounting treatment. Those that are not eligible are marked to fair value through earnings.
·
Derivative transactions that do not qualify for NPNS or hedge accounting treatment are marked to fair value through earnings.
A similar process is also followed by the treasury department as it relates to interest rate and foreign currency derivatives. Examples of accounting guidelines provided to the treasury department staff include, but are not limited to:
·
Transactions to lock in an interest rate prior to a debt issuance can be designated as cash flow hedges.
·
Cross-currency transactions to hedge interest and principal repayments can be designated as cash flow hedges.
·
Transactions entered into to hedge fluctuations in the fair value of existing debt can be designated as fair value hedges.
·
Transactions entered into to hedge the value of a net investment of foreign operations can be designated as net investment hedges.
·
Derivative transactions that do not qualify for hedge accounting treatment are marked to fair value through earnings. These transactions generally include hedges of earnings translation risk associated with subsidiaries that report their financial statements in a currency other than the U.S. dollar. As such, these transactions reduce earnings volatility due solely to changes in foreign currency exchange rates.
·
Derivative transactions may be marked to fair value through regulatory assets/liabilities if approved by the appropriate regulatory body. These transactions generally include the effect of interest rate swaps that are included in customer rates.
Changes in the fair value of derivatives are recorded in either OCI or in current-period earnings.
Cash inflows and outflows related to derivative instruments are included as a component of operating, investing or financing activities on the Statements of Cash Flows, depending on the underlying nature of the hedged items.
PPL and its subsidiaries have elected not to offset net derivative positions against the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a payable) under master netting arrangements.
PPL Energy Supply reflects its net realized and unrealized gains and losses associated with all derivatives that are held for trading purposes in "Net energy trading margins" on the Statements of Income.
See Notes 18 and 19 for additional information on derivatives.
(PPL and PPL Electric)
To meet its obligation as a PLR to its customers, PPL Electric has entered into certain contracts that meet the definition of a derivative. However, these contracts qualify for NPNS. See Notes 18 and 19 for additional information.
Revenue
Utility Revenue (PPL)
The Statements of Income "Utility" line item contains rate-regulated revenue from the following:
(a)
Represents revenue from regulated generation, transmission and/or distribution in Pennsylvania, Kentucky, Virginia and Tennessee, including regulated wholesale revenue.
(b)
Represents electric revenue from the operation of WPD's distribution networks. 2011 includes eight months of revenue for WPD Midlands, which are recorded on a one-month lag.
Revenue Recognition
(PPL, PPL Energy Supply, PPL Electric, LKE, LG&E and KU)
Operating revenues, except for "Energy-related businesses," are recorded based on energy deliveries through the end of the calendar month. Unbilled retail revenues result because customers' meters are read and bills are rendered throughout the month, rather than all being read at the end of the month. Unbilled revenues for a month are calculated by multiplying an estimate of unbilled kWh by the estimated average cents per kWh. Unbilled wholesale energy revenues are recorded at month-end to reflect estimated amounts until actual dollars and MWhs are confirmed and invoiced. At that time, unbilled revenue is reversed and actual revenue is recorded.
Certain PPL subsidiaries participate primarily in the PJM RTO, as well as in other RTOs and ISOs. In PJM, PPL EnergyPlus is a marketer, a load-serving entity to its customers who have selected it as a supplier and a seller for PPL Energy Supply's generation subsidiaries. A function of interchange accounting is to match participants' MWh entitlements (generation plus scheduled bilateral purchases) against their MWh obligations (load plus scheduled bilateral sales) during every hour of every day. If the net result during any given hour is an entitlement, the participant is credited with a spot-market sale to the RTO at the respective market price for that hour; if the net result is an obligation, the participant is charged with a spot-market purchase at the respective market price for that hour. RTO purchases and sales are not allocated to individual customers. PPL Energy Supply records the hourly net sales in its Statements of Income as "Wholesale energy marketing" if in a net sales position and "Energy purchases" if in a net purchase position.
(PPL)
WPD's revenue is primarily from charges to suppliers to use its distribution system to deliver electricity to the end-user. WPD's allowed revenue is not dependent on volume delivered over the five-year price control period. However, in any fiscal period, WPD's revenue could be negatively affected if its tariffs and the volume delivered do not fully recover the allowed revenue for a given period. Any under recovery would be recovered in the next regulatory year, but would not be recorded as
a receivable in the current period. Any over recovery would be reflected in the current period as a liability and would not be included in revenue.
(PPL and PPL Energy Supply)
PPL Energy Supply records energy marketing activity in the period when the energy is delivered. Generally, sales that qualify as derivative instruments held for non-trading purposes are reported gross on the Statements of Income within "Wholesale energy marketing" and "Unregulated retail electric and gas." However, non-trading physical sales and purchases of electricity at major market delivery points (which is any delivery point with liquid pricing available, such as the pricing hub for PJM West), are netted and reported in the Statements of Income within "Wholesale energy marketing" or "Energy Purchases," depending on the original intent. Additionally, the bilateral sales and purchases that are designated as speculative trading activities and qualify as derivative instruments for accounting purposes are reported net on the Statements of Income within "Net energy trading margins." Spot market activity that balances PPL Energy Supply's physical trading positions is included on the Statements of Income in "Net energy trading margins."
"Energy-related businesses" revenue primarily includes revenue from the mechanical contracting and engineering subsidiaries. The mechanical contracting and engineering subsidiaries record revenue from construction contracts on the percentage-of-completion method of accounting, measured by the actual cost incurred to date as a percentage of the estimated total cost for each contract. Accordingly, costs and estimated earnings in excess of billings on uncompleted contracts are recorded within "Unbilled revenues" on the Balance Sheets, and billings in excess of costs and estimated earnings on uncompleted contracts are recorded within "Other current liabilities" on the Balance Sheets. The amount of costs and estimated earnings in excess of billings was $15 million and $9 million at December 31, 2011 and 2010, and the amount of billings in excess of costs and estimated earnings was $67 million and $70 million at December 31, 2011 and 2010.
Accounts Receivable
(PPL, PPL Energy Supply, PPL Electric, LKE, LG&E and KU)
Accounts receivable are reported on the Balance Sheets at the gross outstanding amount adjusted for an allowance for doubtful accounts. Accounts receivable that are acquired are initially recorded at fair value on the date of acquisition. See Note 10 for information related to the acquisitions of WPD Midlands and LKE.
(PPL, PPL Energy Supply and PPL Electric)
PPL Electric's customers may choose an alternative supplier for their generation supply. In accordance with a PUC-approved purchase of accounts receivable program, beginning in the first quarter of 2010, PPL Electric has purchased certain accounts receivable from alternative suppliers at a nominal discount, which reflects a provision for uncollectible accounts. The alternative suppliers (including PPL EnergyPlus) have no continuing involvement or interest in the purchased accounts receivable. The purchased accounts receivable are initially recorded at fair value using a market approach based on the purchase price paid and are classified as Level 2 in the fair value hierarchy. PPL Electric receives a nominal fee for administering its program. During 2011 and 2010, PPL Electric purchased $872 million and $617 million of accounts receivable from unaffiliated third parties. During 2011 and 2010, PPL Electric purchased $267 million and $215 million of accounts receivable from its affiliate, PPL EnergyPlus.
Allowance for Doubtful Accounts (PPL, PPL Energy Supply, PPL Electric, LKE, LG&E and KU)
Accounts receivable collectability is evaluated using a combination of factors, including past due status based on contractual terms, trends in write-offs, the age of the receivable, counterparty creditworthiness and economic conditions. Specific events, such as bankruptcies, are also considered. Adjustments to the allowance for doubtful accounts are made when necessary based on the results of analysis, the aging of receivables, and historical and industry trends.
Accounts receivable are written off in the period in which the receivable is deemed uncollectible. Recoveries of accounts receivable previously written off are recorded when it is known they will be received.
The changes in the allowance for doubtful accounts were:
(a)
Primarily related to uncollectible accounts written off.
(b)
Includes amounts associated with LKE activity since the November 1, 2010 acquisition date. See Note 10 for additional information related to the acquisition of LKE.
(c)
Includes amounts related to the SMGT bankruptcy. See Note 15 for additional information.
(d)
Includes amounts related to the June 2011, FERC approved settlement agreement between PPL and California ISO related to the sales made to the California ISO during the period October 2000 through June 2001 that were not paid to PPL subsidiaries. Therefore, the receivable and the related allowance for doubtful accounts were reversed and the settlement recorded.
(e)
Primarily related to capital projects, thus the provision was recorded as an adjustment to construction work in progress.
Cash (PPL, PPL Energy Supply, PPL Electric, LKE, LG&E, and KU)
Cash Equivalents
All highly liquid debt instruments purchased with original maturities of three months or less are considered to be cash equivalents.
Restricted Cash and Cash Equivalents
Bank deposits and other cash equivalents that are restricted by agreement or that have been clearly designated for a specific purpose are classified as restricted cash and cash equivalents. The change in restricted cash and cash equivalents is reported as an investing activity on the Statements of Cash Flows. On the Balance Sheets, the current portion of restricted cash and cash equivalents is shown as "Restricted cash and cash equivalents" for PPL and PPL Energy Supply and included in "Other current assets" for PPL Electric, LKE, LG&E and KU while the noncurrent portion is included in "Other noncurrent assets" for all Registrants. At December 31, the balances of restricted cash and cash equivalents included the following.
(a)
Deposits posted to counterparties associated with trading activities.
(b)
Cash collateral posted to counterparties related to interest rate swap contracts.
(c)
Funds received by WPD, which are to be spent on approved initiatives to support a low carbon environment.
(d)
Funds required by law to be held by WPD's captive insurance company to meet claims.
(e)
Funds deposited with a trustee to defease PPL Electric's 1945 First Mortgage Bonds. See Note 7 for additional information.
Fair Value Measurements (PPL, PPL Energy Supply, PPL Electric, LKE, LG&E and KU)
The Registrants value certain financial and nonfinancial assets and liabilities at fair value. Generally, the most significant fair value measurements relate to price risk management assets and liabilities, investments in securities including investments in the NDT funds and defined benefit plans, and cash and cash equivalents. PPL and its subsidiaries use, as appropriate, a market approach (generally, data from market transactions), an income approach (generally, present value techniques and option-pricing models) and/or a cost approach (generally, replacement cost) to measure the fair value of an asset or liability. These valuation approaches incorporate inputs such as observable, independent market data and/or unobservable data that management believes are predicated on the assumptions market participants would use to price an asset or liability. These inputs may incorporate, as applicable, certain risks such as nonperformance risk, which includes credit risk.
The Registrants classify fair value measurements within one of three levels in the fair value hierarchy. The level assigned to a fair value measurement is based on the lowest level input that is significant to the fair value measurement in its entirety. The three levels of the fair value hierarchy are as follows:
·
Level 1 - quoted prices (unadjusted) in active markets for identical assets or liabilities that are accessible at the measurement date. Active markets are those in which transactions for the asset or liability occur with sufficient frequency and volume to provide pricing information on an ongoing basis.
·
Level 2 - inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for substantially the full term of the asset or liability.
·
Level 3 - unobservable inputs that management believes are predicated on the assumptions market participants would use to measure the asset or liability at fair value.
Assessing the significance of a particular input requires judgment that considers factors specific to the asset or liability. As such, the Registrants' assessment of the significance of a particular input may affect how the assets and liabilities are classified within the fair value hierarchy.
Investments
(PPL, PPL Energy Supply, PPL Electric, LKE, LG&E and KU)
Generally, the original maturity date of an investment and management's intent and ability to sell an investment prior to its original maturity determine the classification of investments as either short-term or long-term. Investments that would otherwise be classified as short-term, but are restricted as to withdrawal or use for other than current operations or are clearly designated for expenditure in the acquisition or construction of noncurrent assets or for the liquidation of long-term debts, are classified as long-term.
Short-term Investments
Short-term investments generally include certain deposits as well as securities that are considered highly liquid or provide for periodic reset of interest rates. Investments with original maturities greater than three months and less than a year, as well as investments with original maturities of greater than a year that management has the ability and intent to sell within a year, are included in "Short-term investments" ("Other current assets" if not material) on the Balance Sheets.
Investments in Debt and Equity Securities
Investments in debt securities are classified as held-to-maturity and measured at amortized cost when there is an intent and ability to hold the securities to maturity. Debt and equity securities held principally to capitalize on fluctuations in their value with the intention of selling them in the near-term are classified as trading. All other investments in debt and equity securities are classified as available-for-sale. Both trading and available-for-sale securities are carried at fair value. The specific identification method is used to calculate realized gains and losses on debt and equity securities. Any unrealized gains and losses on trading securities are included in earnings. Through March 31, 2009, unrealized gains and losses on all available-for-sale securities were reported, net of tax, in OCI or recognized in earnings when the decline in fair value below amortized cost was determined to be an other-than-temporary impairment.
Accounting guidance effective April 1, 2009 modified the criteria for determining whether a decline in fair value of a debt security is other than temporary and whether the other-than-temporary impairment is recognized in earnings or reported in OCI. Beginning April 1, 2009, when a debt security is in an unrealized loss position and:
·
there is an intent or a requirement to sell the security before recovery, the other-than-temporary impairment is recognized currently in earnings; or
·
there is no intent or requirement to sell the security before recovery, the portion of the other-than-temporary impairment that is considered a credit loss is recognized currently in earnings and the remainder of the other-than-temporary impairment is reported in OCI, net of tax; or
·
there is no intent or requirement to sell the security before recovery and there is no credit loss, the unrealized loss is reported in OCI, net of tax.
Equity securities were not impacted by this accounting guidance; therefore, unrealized gains and losses on available-for-sale equity securities continue to be reported, net of tax, in OCI. Earnings continue to be charged when an equity security's decline in fair value below amortized cost is determined to be an other-than-temporary impairment. See Notes 18 and 23 for additional information on investments in debt and equity securities.
Equity Method Investment (LKE and KU)
KU's investment in EEI is included in "Investments" on the Balance Sheets. KU owns 20% of the common stock of EEI. Through a power marketer affiliated with its majority owner, EEI sells its output to third parties. KU's investment in EEI is accounted for under the equity method of accounting and amounted to $30 million at December 31, 2011 and 2010. As part of PPL's acquisition of LKE and its subsidiaries, the purchase accounting adjustment to reflect the EEI investment at fair value was calculated using the discounted cash flow valuation method. The fair value of the investment in EEI was calculated to be $30 million. The fair value adjustment to the investment is being amortized over the expected remaining useful life of the plant and equipment at EEI, which is estimated to be over 20 years. KU's direct exposure to loss as a result of its involvement with EEI is generally limited to the value of its investment.
Cost Method Investment (LKE, LG&E and KU)
LG&E and KU each have an investment in OVEC, which is accounted for using the cost method. The investment is recorded in "Investments" on the LKE and KU Balance Sheets, in "Other noncurrent assets" on the LG&E Balance Sheets and in "Other investments" on the PPL Balance Sheets. LG&E and KU and ten other electric utilities are equity owners of OVEC, located in Piketon, Ohio. OVEC owns and operates two coal-fired plants, Kyger Creek Plant in Ohio and Clifty Creek Plant in Indiana, with combined nameplate generating capacities of 2,390 MW. OVEC's power is currently supplied to LG&E and KU and 11 other companies affiliated with the various owners. LG&E and KU own 5.63% and 2.5% of OVEC's common stock. Pursuant to a power purchase agreement, LG&E and KU are contractually entitled to their ownership percentage of OVEC's output, which is 134 MW for LG&E and 60 MW for KU.
LG&E and KU's combined investment in OVEC is not significant. The direct exposure to loss as a result of LG&E's and KU's involvement with OVEC is generally limited to the value of its investment; however, LG&E and KU may be conditionally responsible for a pro-rata share of certain OVEC obligations. As part of PPL's acquisition of LKE, the value of the power purchase contract was recorded as an intangible asset with the offset to a regulatory liability which are both being amortized using the units-of-production method until March 2026, the expiration date of the agreement at the date of the acquisition. See Notes 15 and 20 for additional discussion on the power purchase agreement.
Long-Lived and Intangible Assets
Property, Plant and Equipment
(PPL, PPL Energy Supply, PPL Electric, LKE, LG&E and KU)
PP&E is recorded at original cost, unless impaired. If impaired, the asset is written down to fair value at that time, which becomes the new cost basis of the asset. Original cost includes material, labor, contractor costs, certain overheads and financing costs, where applicable. The cost of repairs and minor replacements are charged to expense as incurred. The Registrants record costs associated with planned major maintenance projects in the period in which the costs are incurred. No costs are accrued in advance of the period in which the work is performed for PPL Energy Supply or PPL Electric. LG&E and KU accrue costs of removal net of estimated salvage value through depreciation, which is included in the calculation of customer rates over the assets' depreciable lives in accordance with regulatory practices. Cost of removal amounts accrued through depreciation rates are accumulated as a regulatory liability until the removal costs are incurred. See Note 6 for additional information.
(PPL)
The original cost for the PP&E acquired in the WPD Midlands acquisition is its fair value on April 1, 2011, which approximated RAV as of the acquisition date. See Note 10 for additional information on the acquisition.
(PPL, PPL Electric, LKE and KU)
AFUDC is capitalized as part of the construction costs for cost-based rate-regulated projects for which a return on such costs is recovered after the project is placed in service. The debt component of AFUDC is credited to "Interest Expense" and the equity component is credited to "Other Income (Expense) - net" on the Statements of Income. KU has not recorded significant AFUDC as a return has been provided during the construction period for most projects.
(PPL and PPL Energy Supply)
Nuclear fuel-related costs, including fuel, conversion, enrichment, fabrication and assemblies, are capitalized as PP&E. Such costs are amortized as the fuel is spent using the units-of-production method and included in "Fuel" on the Statements of Income.
PPL Energy Supply capitalizes interest costs as part of construction costs. The following capitalized interest was excluded from "Interest Expense" on the Statements of Income.
(PPL, PPL Energy Supply, PPL Electric, LKE, LG&E and KU)
Included in PP&E on the Balance Sheets are capitalized costs of software projects that were developed or obtained for internal use. These capitalized costs are amortized ratably over the expected lives of the projects when they become operational, generally not to exceed five years. Following are capitalized software costs and the accumulated amortization.
Amortization expense of capitalized software costs was as follows:
The amortization of capitalized software is included in "Depreciation" on the Statements of Income.
(PPL, PPL Energy Supply, PPL Electric, LKE, LG&E and KU)
Depreciation
Depreciation is recorded over the estimated useful lives of property using various methods including the straight-line, composite and group methods. When a component of PP&E that was depreciated under the composite or group method is retired, the original cost is charged to accumulated depreciation. When all or a significant portion of an operating unit that was depreciated under the composite or group method is retired or sold, the property and the related accumulated depreciation account is reduced and any gain or loss is included in income, unless otherwise required by regulators.
Following are the weighted-average rates of depreciation at December 31.
(a)
For PPL, LKE, LG&E and KU, as a result of the acquisition of LKE, the original cost for PP&E is its fair value on November 1, 2010, which approximated net book value. This fair value adjustment resulted in lowering the original cost basis of LKE's, LG&E's and KU's PP&E, thus impacting the calculation of the weighted-average depreciation rate.
(b)
As a result of PPL Energy Supply's distribution of its membership interest in PPL Global in January 2011, PPL Energy Supply no longer has any regulated utility plant.
Goodwill and Other Intangible Assets
Goodwill represents the excess of the purchase price paid over the fair value of the identifiable net assets acquired in a business combination.
Other acquired intangible assets are initially measured based on their fair value. Intangibles that have finite useful lives are amortized over their useful lives based upon the pattern in which the economic benefits of the intangible assets are consumed or otherwise used. Costs incurred to renew or extend terms of licenses are capitalized as intangible assets.
When determining the useful life of an intangible asset, including intangible assets that are renewed or extended, PPL and its subsidiaries consider the expected use of the asset; the expected useful life of other assets to which the useful life of the intangible asset may relate; legal, regulatory, or contractual provisions that may limit the useful life; the company's historical experience as evidence of its ability to support renewal or extension; the effects of obsolescence, demand, competition, and other economic factors; and the level of maintenance expenditures required to obtain the expected future cash flows from the asset.
PPL and PPL Energy Supply account for RECs as intangible assets. PPL and PPL Energy Supply buy and/or sell RECs and also create RECs through owned renewable energy generation facilities. In any period, PPL and PPL Energy Supply can be a net purchaser or seller of RECs depending on their contractual obligations to purchase or deliver RECs and the production of RECs from their renewable energy generation facilities. The carrying value of RECs created from their renewable energy generation facilities is initially recorded at zero value and purchased RECs are initially recorded based on their purchase price. When RECs are consumed to satisfy an obligation to deliver RECs to meet a state's Renewable Portfolio Standard Obligation or when RECs are sold to third parties, they are removed from the Balance Sheet at their weighted-average carrying value. Since the economic benefits of RECs are not diminished until they are consumed, RECs are not amortized; rather, they are expensed when consumed or a gain or loss is recognized when sold. Such expense is included in "Energy purchases" on the Statements of Income. Gains and losses on the sale of RECs are included in "Other operation and maintenance" on the Statements of Income.
PPL, PPL Energy Supply, LKE, LG&E and KU account for emission allowances as intangible assets. PPL, PPL Energy Supply, LKE, LG&E and KU are allocated emission allowances by states based on their generation facilities' historical emissions experience, and have purchased emission allowances generally when it is expected that additional allowances will be needed. The carrying value of allocated emission allowances is initially recorded at zero value and purchased allowances are initially recorded based on their purchase price. LKE, LG&E, and KU emission allowances acquired in the LKE acquisition were recorded at fair value on the date of acquisition. See Note 10 for additional information on the acquisition. When consumed or sold, emission allowances are removed from the Balance Sheet at their weighted-average carrying value. Since the economic benefits of emission allowances are not diminished until they are consumed, emission allowances are not amortized; rather, they are expensed when consumed or a gain or loss is recognized when sold. Such expense is included in "Fuel" on the Statements of Income. Gains and losses on the sale of emission allowances are included in "Other operation and maintenance" on the Statements of Income.
Asset Impairment
The Registrants review long-lived assets that are subject to depreciation or amortization, including finite-lived intangibles, for impairment when events or circumstances indicate carrying amounts may not be recoverable. For example, certain emission allowances are expected to be sold rather than consumed. These emission allowances are tested for impairment when events or changes in circumstances, such as a decline in market prices, indicate that their carrying value may not be recoverable.
A long-lived asset classified as held and used is impaired when the carrying amount of the asset exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. If impaired, the asset's carrying value is written down to its fair value.
A long-lived asset classified as held for sale is impaired when the carrying amount of the asset (disposal group) exceeds its fair value less cost to sell. If impaired, the asset's (disposal group's) carrying value is written down to its fair value less cost to sell. See Notes 9 and 18 for a discussion of impairment charges recorded associated with long-lived assets classified as held for sale.
Goodwill is reviewed for impairment at the reporting unit level annually or more frequently when events or circumstances indicate that the carrying amount of a reporting unit may be greater than the unit's fair value. Additionally, goodwill must be tested for impairment after a portion of goodwill has been allocated to a business to be disposed of. PPL's reporting units are at or one level below its operating segments and represent significant businesses with discrete financial information that is regularly reviewed by segment management. If the carrying amount of the reporting unit, including goodwill, exceeds its fair value, the implied fair value of goodwill must be calculated in the same manner as goodwill in a business combination. The fair value of a reporting unit is allocated to all assets and liabilities of that unit as if the reporting unit had been acquired in a business combination. The excess of the fair value of the reporting unit over the amounts assigned to its assets and liabilities is the implied fair value of goodwill. If the implied fair value of goodwill is less than the carrying amount, goodwill is written down to its implied fair value.
The goodwill recognized upon the acquisition of LKE, although entirely recorded at LG&E and KU, was assigned for impairment testing by PPL to its reporting units expected to benefit from the acquisition, which were the Kentucky Regulated segment and the Supply segment. The goodwill recognized upon the acquisition of WPD Midlands was assigned for impairment testing by PPL to its International Regulated segment. See Note 10 for additional information regarding the acquisitions.
Asset Retirement Obligations
PPL and its subsidiaries record liabilities to reflect various legal obligations associated with the retirement of long-lived assets. Initially, this obligation is measured at fair value and offset with an increase in the value of the capitalized asset, which is depreciated over the asset's useful life. Until the obligation is settled, the liability is increased to reflect changes in the obligation due to the passage of time through the recognition of accretion expense classified within "Other operation and maintenance" on the Statements of Income. The accretion and depreciation related to LG&E's and KU's AROs are offset with a regulatory credit on the income statement, such that there is no earnings impact. The regulatory asset created by the regulatory credit is relieved when the ARO is settled.
Estimated ARO costs and settlement dates, which affect the carrying value of the ARO and the related capitalized asset, are reviewed periodically to ensure that any material changes are incorporated into the latest estimate of the ARO. Any change to the capitalized asset, positive or negative, is amortized over the remaining life of the associated long-lived asset. See Note 21 for additional information on AROs.
Compensation and Benefits
Defined Benefits (PPL, PPL Energy Supply, PPL Electric, LKE, LG&E and KU)
Certain PPL subsidiaries sponsor various defined benefit pension and other postretirement plans. An asset or liability is recorded to recognize the funded status of all defined benefit plans with an offsetting entry to OCI or, for LG&E, KU and PPL Electric, to regulatory assets or liabilities. Consequently, the funded status of all defined benefit plans is fully recognized on the Balance Sheets.
The expected return on plan assets is determined based on a market-related value of plan assets, which is calculated by rolling forward the prior year market-related value with contributions, disbursements and long-term expected return on investments. One-fifth of the difference between the actual value and the expected value is added (or subtracted if negative) to the expected value to determine the new market-related value.
PPL uses an accelerated amortization method for the recognition of gains and losses for its defined benefit pension plans. Under the accelerated method, actuarial gains and losses in excess of 30% of the plan's projected benefit obligation are amortized on a straight-line basis over one-half of the expected average remaining service of active plan participants. Actuarial gains and losses in excess of 10% of the greater of the plan's projected benefit obligation or the market-related value of plan assets and less than 30% of the plan's projected benefit obligation are amortized on a straight-line basis over the expected average remaining service period of active plan participants.
See Note 13 for a discussion of defined benefits.
Stock-Based Compensation
(PPL, PPL Energy Supply, PPL Electric and LKE)
PPL has several stock-based compensation plans for purposes of granting stock options, restricted stock, restricted stock units and performance units to certain employees as well as stock units and restricted stock units to directors. PPL grants most stock-based awards in the first quarter of each year. PPL and its subsidiaries recognize compensation expense for stock-based awards based on the fair value method. Stock options that vest in installments are valued as a single award. PPL grants stock options with an exercise price that is not less than the fair value of PPL's common stock on the date of grant. See Note 11 for a discussion of stock-based compensation. All awards are recorded as equity or a liability on the Balance Sheets. Stock-based compensation is primarily included in "Other operation and maintenance" on the Statements of Income. Stock-based compensation expense for PPL Energy Supply, PPL Electric and LKE includes an allocation of PPL Services' expense.
Other
Debt Issuance Costs (PPL, PPL Energy Supply, PPL Electric, LKE, LG&E and KU)
Debt issuance costs are deferred and amortized over the appropriate term for the related debt using the interest method or another method, generally straight-line, if the results obtained are not materially different than those that would result from the interest method.
Income Taxes
(PPL, PPL Energy Supply, PPL Electric, LKE, LG&E and KU)
PPL and its domestic subsidiaries file a consolidated U.S. federal income tax return. Prior to PPL's acquisition of LKE, LKE and its subsidiaries were included in E.ON US Investments Corp.'s consolidated U.S. federal income tax return.
Significant management judgment is required in developing the Registrants' provision for income taxes, primarily due to the uncertainty related to tax positions taken or expected to be taken in tax returns and the determination of deferred tax assets, liabilities and valuation allowances.
Significant management judgment is also required to determine the amount of benefit to be recognized in relation to an uncertain tax position. The Registrants use a two-step process to evaluate tax positions. The first step requires an entity to determine whether, based on the technical merits supporting a particular tax position, it is more likely than not (greater than a 50% chance) that the tax position will be sustained. This determination assumes that the relevant taxing authority will examine the tax position and is aware of all the relevant facts surrounding the tax position. The second step requires an entity to recognize in the financial statements the benefit of a tax position that meets the more-likely-than-not recognition criterion. The benefit recognized is measured at the largest amount of benefit that has a likelihood of realization, upon settlement, that exceeds 50%. The amounts ultimately paid upon resolution of issues raised by taxing authorities may differ materially from the amounts accrued and may materially impact the financial statements of the Registrants in the future.
Deferred income taxes reflect the net future tax effects of temporary differences between the carrying amounts of assets and liabilities for accounting purposes and their basis for income tax purposes, as well as the tax effects of net operating losses and tax credit carryforwards.
The Registrants record valuation allowances to reduce deferred tax assets to the amounts that are more likely than not to be realized. The Registrants consider the reversal of temporary differences, future taxable income and ongoing prudent and feasible tax planning strategies in initially recording and subsequently reevaluating the need for valuation allowances. If the Registrants determine that they are able to realize deferred tax assets in the future in excess of recorded net deferred tax assets, adjustments to the valuation allowances increase income by reducing tax expense in the period that such determination is made. Likewise, if the Registrants determine that they are not able to realize all or part of net deferred tax assets in the future, adjustments to the valuation allowances would decrease income by increasing tax expense in the period that such determination is made.
The Registrants defer investment tax credits when the credits are utilized and amortize the deferred amounts over the average lives of the related assets.
The Registrants recognize interest and penalties in "Income Taxes" on their Statements of Income.
See Note 5 for additional discussion regarding income taxes.
(PPL Energy Supply, PPL Electric, LKE, LG&E and KU)
The income tax provision for PPL Energy Supply, PPL Electric, LKE, LG&E and KU is calculated in accordance with an intercompany tax sharing agreement which provides that taxable income be calculated as if PPL Energy Supply, PPL Electric, LKE, LG&E, KU and any domestic subsidiaries each filed a separate return. Tax benefits are not shared between companies. A tax benefit inures only to the entity that gave rise to said benefit. The effect of PPL filing a consolidated tax return is taken into account in the settlement of current taxes and the recognition of deferred taxes. PPL Energy Supply's intercompany tax payable was $50 million and $26 million at December 31, 2011 and 2010. PPL Electric's intercompany tax receivable was $22 million and $74 million at December 31, 2011 and 2010. LKE's intercompany tax receivable was $3 million and $40 million at December 31, 2011 and 2010. LG&E's intercompany tax receivable was $4 million and $4 million at December 31, 2011 and 2010. KU's intercompany tax receivable was $5 million at December 31, 2011 and the intercompany tax payable was $15 million at December 31, 2010.
(PPL, PPL Electric, LKE, LG&E and KU)
The provision for PPL, PPL Electric, LKE, LG&E and KU's deferred income taxes for regulated assets is based upon the ratemaking principles reflected in rates established by the regulators. The difference in the provision for deferred income taxes for regulated assets and the amount that otherwise would be recorded under GAAP is deferred and included on the Balance Sheet in noncurrent "Regulatory assets" or "Regulatory liabilities."
Taxes, Other Than Income (PPL, PPL Energy Supply, PPL Electric, LKE, LG&E and KU)
The Registrants present sales taxes in "Accounts Payable" and value-added taxes in "Taxes" on their Balance Sheets. These taxes are not reflected on the Statements of Income. See Note 5 for details on taxes included in "Taxes, other than income" on the Statements of Income.
Leases
(PPL, PPL Energy Supply, PPL Electric, LKE, LG&E and KU)
PPL and its subsidiaries evaluate whether arrangements entered into contain leases for accounting purposes. See Note 11 for a discussion of arrangements under which PPL Energy Supply, LG&E and KU are lessees for accounting purposes.
(PPL and PPL Energy Supply)
PPL EnergyPlus entered into several tolling agreements whereby PPL EnergyPlus was considered the lessor for accounting purposes. See Note 9 for additional information regarding the 2010 sale of the Long Island generation business and the tolling agreements that were transferred to the purchaser upon completion of the sale.
Fuel, Materials and Supplies
(PPL, PPL Energy Supply, PPL Electric, LKE, LG&E and KU)
Fuel, natural gas stored underground and materials and supplies are valued at the lower of cost or market using the average cost method. Fuel costs for electric generation are charged to expense as used. For LG&E, natural gas supply costs are charged to expense as delivered to the distribution system. See Note 6 for further discussion of the fuel adjustment clause and gas supply clause.
(PPL, PPL Energy Supply, LKE, LG&E and KU)
"Fuel, materials and supplies" on the Balance Sheets consisted of the following at December 31.
(a)
The majority of LKE's and LG&E's natural gas stored underground is held to serve native load. The majority of PPL Energy Supply's natural gas stored underground is available for resale.
Guarantees (PPL, PPL Energy Supply, PPL Electric, LKE, LG&E and KU)
Generally, the initial measurement of a guarantee liability is the fair value of the guarantee at its inception. However, there are certain guarantees excluded from the scope of accounting guidance and other guarantees that are not subject to the initial recognition and measurement provisions of accounting guidance that only require disclosure. See Note 15 for further discussion of recorded and unrecorded guarantees.
Treasury Stock (PPL and PPL Electric)
PPL and PPL Electric restore all shares of common stock acquired to authorized but unissued shares of common stock upon acquisition.
Foreign Currency Translation and Transactions (PPL)
The GBP, which is the local currency, is the functional currency of WPD. As such, assets and liabilities are translated at the exchange rates on the date of consolidation and related revenues and expenses are translated at average exchange rates prevailing during the period included in PPL's results of operations. Adjustments resulting from translation are recorded in AOCI. The effect of translation is removed from AOCI upon the sale or substantial liquidation of the international subsidiary that gave rise to the translation adjustment.
Gains or losses relating to foreign currency transactions are recognized in "Other Income (Expense) - net" on the Statements of Income. Net transaction losses were $15 million in 2011 and insignificant in 2010 and 2009.
New Accounting Guidance Adopted (PPL, PPL Energy Supply, PPL Electric, LKE, LG&E and KU)
Disclosures about an Employer's Participation in a Multiemployer Plan
Effective December 31, 2011, the Registrants retrospectively adopted accounting guidance issued to improve the transparency about an employer's participation in a multiemployer plan. The disclosures required by this guidance include the significant multiemployer plans in which an employer participates, the level of the employer's participation in these plans, the financial health of these plans and the nature of employer commitments to these plans. For plans for which users are unable to obtain additional publicly available information outside the employer's financial statements, additional disclosures are required.
The adoption of this standard resulted in additional footnote disclosure for PPL and PPL Energy Supply but did not have a significant impact on any of the Registrants. See Note 13 for disclosures related to PPL Energy Supply's participation in multiemployer plans.
Presentation of Comprehensive Income
Effective December 31, 2011, the Registrants retrospectively adopted accounting guidance that was issued to improve the comparability, consistency and transparency of financial reporting and to increase the prominence of items that are recorded in OCI. This guidance requires that all non-owner changes in stockholders' equity be presented either in a single continuous statement of comprehensive income or in two separate but consecutive statements where the first statement includes the components of net income and the second statement includes the components of OCI.
Regardless of whether an entity chooses to present comprehensive income in a single continuous statement or in two separate but consecutive statements, the guidance also would have required an entity to present on the face of the financial statements reclassification adjustments for items that are reclassified from other comprehensive income to net income in the statement(s) where the components of net income and the components of other comprehensive income are presented. However, subsequent to the issuance of this new accounting guidance, this requirement that companies present reclassification adjustments for each component of OCI in both net income and OCI on the face of the financial statements was deferred for further evaluation. The deferral did not change the requirement to present items of net income, items of other comprehensive income and total comprehensive income in either one continuous statement or two separate consecutive statements.
The Registrants required to present comprehensive income have elected to present two separate consecutive statements. The adoption of this standard resulted in a change in presentation and additional footnote disclosure that did not have a significant impact on the Registrants.
2. Segment and Related Information
(PPL and PPL Energy Supply)
Since the acquisition of LKE on November 1, 2010, PPL is organized into four segments: Kentucky Regulated, International Regulated, Pennsylvania Regulated and Supply. PPL's segments are split between its regulated and competitive businesses with its regulated businesses further segmented by geographic location.
The Kentucky Regulated segment consists primarily of LKE's regulated electric generation, transmission and distribution operations, primarily in Kentucky. This segment also includes LKE's regulated distribution and sale of natural gas in Kentucky. In addition, the Kentucky Regulated segment includes certain financing activities associated with the acquisition of LKE. See Note 10 for additional information regarding the acquisition.
The International Regulated segment primarily consists of the regulated electric distribution operations in the U.K. This includes the operating results and assets of WPD Midlands since the April 1, 2011 acquisition date recorded on a one-month lag. The International Regulated segment also includes certain acquisition-related costs and financing activities associated with the acquisition of WPD Midlands. See Note 10 for additional information regarding the acquisition.
The Pennsylvania Regulated segment includes the regulated electric transmission and distribution operations of PPL Electric.
The Supply segment primarily consists of the domestic energy marketing and trading activities, as well as the competitive generation operations of PPL Energy Supply. In 2011, 2010 and 2009, PPL Energy Supply sold certain Supply segment generation facilities and businesses. See Note 9 for additional information.
"Unallocated Costs" represent one-time LKE acquisition-related costs including advisory, accounting and legal fees, certain internal costs and 2010 Bridge Facility costs.
The results of several facilities and businesses have been classified as Discontinued Operations on the Statements of Income. See Note 9 for additional information on these discontinued operations. Therefore, with the exception of "Net Income Attributable to PPL/PPL Energy Supply," the operating results from these facilities and businesses have been excluded from the income statement data tables below.
In January 2011, PPL Energy Supply distributed its membership interest in PPL Global to its parent, PPL Energy Funding. Following the distribution, PPL Energy Supply operates in a single reportable segment, the Supply segment. PPL Energy Supply's 2010 and 2009 segment information was revised to reflect PPL Global as a Discontinued Operation. See Note 9 for additional information. The Supply segment information reported by PPL Energy Supply does not equal the Supply segment information reported by PPL because additional Supply segment functions exist at PPL. Further, certain income items, including PLR revenue and certain interest income with affiliates, exist at PPL Energy Supply but are eliminated in consolidation by PPL. Finally, certain expense items are fully allocated to the segments by PPL only.
Segment costs include direct charges, as well as an allocation of indirect corporate service costs, from PPL Services. These service costs include functions such as financial, legal, human resources and information services. See Note 16 for additional information.
Financial data for the segments are:
(a)
Includes unrealized gains and losses from economic activity. See Note 19 for additional information.
(b)
See Note 1 for additional information on Utility Revenue.
(c)
See "PLR Contracts/Purchase of Accounts Receivable" and "NUG Purchases" in Note 16 for a discussion of the basis of accounting between reportable segments.
(d)
Represents non-cash expense items that include amortization of nuclear fuel, regulatory assets, debt discounts and premiums, debt issuance costs, emission allowances and RECs.
(e)
Includes interest income from affiliate(s).
(f)
Includes interest expense with affiliate(s).
(g)
Represents both current and deferred income taxes, including investment tax credits.
(h)
Represents a non-cash expense item that is also included in "Income Taxes."
(i)
For PPL Energy Supply, 2010 and 2009 were reported as Discontinued Operations. See Note 9 for additional information, including the $24 million of income tax expense recognized in 2009 by the International Regulated segment related to a correction of income tax bases for the Latin American businesses sold in 2007.
(j)
In April 2011, during the PPL Susquehanna Unit 2 refueling and generation uprate outages, a planned inspection of the Unit 2 turbine revealed cracks in certain of its low pressure turbine blades. As a precaution, PPL Susquehanna also took Unit 1 out of service in mid-May to inspect that unit's turbine blades. This inspection revealed cracked blades similar to those found in Unit 2. Replacement of these blades was completed, significantly extending these outages. The after-tax earnings impact, including reduced energy sales margins and repair expense for both units was $63 million in 2011.
(k)
A portion of the goodwill related to the 2010 LKE acquisition has been attributed to PPL's Supply segment.
(PPL Electric, LKE, LG&E and KU)
PPL Electric, LKE, LG&E and KU each operate within a single reportable segment.
3. Preferred Securities
Preferred Stock
(PPL)
PPL is authorized to issue up to 10 million shares of preferred stock. No PPL preferred stock was issued or outstanding in 2011, 2010, or 2009.
PPL classifies preferred securities of a subsidiary as "Noncontrolling interests" on the Balance Sheets. Dividend requirements of $16 million for 2011, $17 million for 2010 and $18 million for 2009 were included in "Net Income Attributable to Noncontrolling Interests" on the Statements of Income.
(PPL Electric)
PPL Electric is authorized to issue up to 629,936 shares of 4-1/2% Preferred Stock and 10 million shares of series preferred stock. There were 247,524 shares of 4-1/2% Preferred Stock (amounting to $25 million) and an aggregate of 257,665 shares of four series of preferred stock (amounting to $26 million) issued and outstanding at December 31, 2009.
In April 2010, PPL Electric redeemed all of its outstanding preferred stock, with a par value in the aggregate of $51 million, for $54 million including accumulated dividends. The redeemed shares are no longer outstanding and represent only the right to receive the applicable redemption price, to the extent the shares have not yet been presented for payment. The premium of $3 million is included in "Distributions on Preferred Securities" on the Statement of Income.
(LG&E)
LG&E is authorized to issue up to 1,720,000 shares of preferred stock at a $25 par value and 6,750,000 shares of preferred stock without par value. LG&E had no preferred stock issued or outstanding in 2011, 2010 or 2009.
(KU)
KU is authorized to issue up to 5,300,000 shares of preferred stock without par value. KU had no preferred stock issued or outstanding in 2011, 2010 or 2009.
Preference Stock
(PPL Electric)
Of the 10 million shares of Preference Stock authorized, PPL Electric had 2.5 million shares of 6.25% Series Preference Stock (Preference Shares) issued and outstanding in 2011, 2010 and 2009. The Preference Shares are held by a bank that acts as depositary for 10 million depositary shares, each of which represents a one-quarter interest in a Preference Share. Holders of the depositary shares are entitled to all proportional rights and preferences of the Preference Shares, including dividend, voting, redemption and liquidation rights, exercised through the bank acting as a depositary. The Preference Shares rank senior to PPL Electric's common stock but have no voting rights, except as provided by law, and they have a liquidation preference of $100 per share (equivalent to $25 per depositary share). The Preference Shares, which have no stated maturity date and no sinking fund requirements, have been redeemable by PPL Electric since April 6, 2011 for $100 per share (equivalent to $25 per depositary share).
Dividends on the Preference Shares are not cumulative and will be paid when, as and if declared by the Board of Directors at a fixed annual rate of 6.25%, or $1.5625 per depositary share per year. PPL Electric may not pay dividends on, or redeem, purchase or make a liquidation payment with respect to any of its common stock, except in certain circumstances, unless full dividends on the Preference Shares have been paid for the then-current dividend period.
(KU)
KU is authorized to issue up to 2,000,000 shares of preference stock without par value. KU had no preference stock issued or outstanding in 2011, 2010 or 2009.
4. Earnings Per Share
(PPL)
Basic EPS is computed by dividing income available to PPL common shareowners by the weighted-average number of common shares outstanding during the period. Diluted EPS is computed by dividing income available to PPL common shareowners by the weighted-average number of shares outstanding that are increased for additional shares that would be outstanding if potentially dilutive non-participating securities were converted to common shares as calculated using the treasury stock method. In 2011, 2010 and 2009, these securities included stock options and performance units granted under incentive compensation plans. Additionally, the 2011 and 2010 Purchase Contracts associated with the 2011 and 2010 Equity Units will be dilutive under the treasury stock method if the average VWAP of PPL's common stock for a certain period exceeds approximately $30.99 and $28.80. The 2011 Purchase Contracts were excluded from the diluted EPS calculations because they did not meet this criteria during 2011. The 2010 Purchase Contracts were included in the diluted EPS calculation for 2011 as they met this criteria for a portion of that year, but were excluded from the diluted EPS calculations for 2010 because they did not meet this criteria for that year. Subject to antidilution adjustments at December 31, 2011, the maximum number of shares issuable to settle the Purchase Contracts was 101,552,245 shares, including
86,552,565 shares that could be issued under standard provisions of the Purchase Contracts and 14,999,680 shares that could be issued under make-whole provisions in the event of early settlement upon a Fundamental Change. See Note 7 for additional information on both the 2011 and 2010 Equity Units.
Reconciliations of the amounts of income and shares of PPL common stock (in thousands) for the periods ended December 31 used in the EPS calculation are:
During 2011, PPL issued 443,865 shares of common stock related to the exercise of stock options, vesting of restricted stock and restricted stock units and conversion of stock units granted to directors under its stock-based compensation plans. In addition, PPL issued 301,319 and 2,269,388 shares of common stock related to its ESOP and DRIP during 2011. See Note 12 for a discussion of PPL's stock-based compensation plans.
See Note 7 for information on the issuance of common stock and 2011 and 2010 Equity Units.
The following stock options to purchase PPL common stock and performance units were excluded from the computations of diluted EPS because the effect would have been antidilutive.
5. Income and Other Taxes
(PPL)
"Income from Continuing Operations Before Income Taxes" included the following components:
Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for accounting purposes and their basis for income tax purposes and the tax effects of net operating loss and tax
credit carryforwards. The provision for PPL's deferred income taxes for regulated assets is based upon the ratemaking principles of the applicable jurisdiction. See Notes 1 and 6 for additional information.
Net deferred tax assets have been recognized based on management's estimates of future taxable income for the U.S. and certain foreign jurisdictions in which PPL's operations have historically been profitable.
Significant components of PPL's deferred income tax assets and liabilities were as follows:
PPL had the following loss and tax credit carryforwards.
(a)
2010 loss and credit carryforwards associated with the acquisition of LKE. LKE's federal capital loss carryforwards were fully utilized in 2011.
(b)
2010 state net operating loss and state capital loss carryforwards associated with the acquisition of LKE are $1.0 billion and $163 million.
(c)
2011 includes $456 million of foreign capital losses associated with WPD Midlands.
Valuation allowances have been established for the amount that, more likely than not, will not be realized. The changes in deferred tax valuation allowances were:
(a)
Primarily related to a $101 million valuation allowance that was recorded against certain deferred tax assets as a result of the 2011 acquisition of WPD Midlands. See Note 10 for additional information on the acquisition.
(b)
The reduction of the U.K. statutory income tax rate resulted in a $35 million reduction in the valuation allowance. See "Reconciliation of Income Tax Expense" below for more information on the impact of the U.K. Finance Act of 2011.
(c)
A valuation allowance was recorded against certain deferred tax assets as a result of the 2010 acquisition of LKE. See Note 10 for additional information on the acquisition.
(d)
Resulting from the projected revenue increase in connection with the expiration of the Pennsylvania generation rate caps in 2010, the valuation allowance related to state net operating loss carryforwards over the remaining carryforward period was reduced by $72 million (or $0.17 per share, basic and diluted).
(e)
Related to the change in foreign net operating loss carryforwards, including the change in foreign currency exchange rates.
(f)
Primarily from the projected revenue increase in connection with the expiration of the Pennsylvania generation rate caps in 2010, the valuation allowance related to a portion of state net operating loss carryforwards was reduced by $13 million.
PPL Global does not pay or record U.S. income taxes on the undistributed earnings of WPD, as management has determined that the earnings are indefinitely reinvested. Historically, dividends paid by WPD have been distributions from current year's earnings. WPD's long-term working capital forecasts and capital expenditure projections for the foreseeable future require reinvestment of WPD's undistributed earnings, and WPD would have to issue debt or access credit facilities to fund any distributions in excess of current earnings. Additionally, U.S. long-term working capital forecasts and capital expenditure projections for the foreseeable future do not require or contemplate distributions from WPD in excess of some portion of future WPD earnings. The cumulative undistributed earnings are included in "Earnings Reinvested" on the Balance Sheets. The amounts considered permanently reinvested at December 31, 2011 and 2010 were $1.2 billion and $837 million. If the WPD earnings were remitted as dividends, PPL Global could be subject to additional U.S. taxes, net of allowable foreign tax credits. It is not practicable to estimate the amount of additional taxes that could be payable on these foreign earnings.
Details of the components of income tax expense, a reconciliation of federal income taxes derived from statutory tax rates applied to "Income from Continuing Operations Before Income Taxes" to income taxes for reporting purposes, and details of "Taxes, other than income" were:
(a)
Excludes current and deferred federal, state and foreign tax expense (benefit) recorded to Discontinued Operations of $2 million in 2011, $(6) million in 2010 and $46 million in 2009. Excludes realized tax expense (benefits) related to stock-based compensation, recorded as a decrease (increase) to additional paid-in capital of $3 million in 2011 and insignificant amounts in 2010 and 2009. Excludes tax benefits related to the issuance costs of the Purchase Contracts, recorded as an increase to additional paid-in capital in the amount of $5 million in 2011 and $10 million in 2010, offset by an insignificant amount of related valuation allowances for state deferred taxes in 2011. Also excludes federal, state, and foreign tax expense (benefit) recorded to OCI of $(137) million in 2011, $83 million in 2010 and $358 million in 2009, and related valuation allowances for state deferred taxes in the amount of $3 million for 2011.
(a)
During 2011, the Pennsylvania Department of Revenue issued interpretive guidance on the treatment of bonus depreciation for Pennsylvania income tax purposes. In accordance with Corporation Tax Bulletin 2011-01, Pennsylvania allows 100% bonus depreciation for qualifying assets in the same year bonus depreciation is allowed for Federal income tax purposes. Due to the decrease in taxable income related to bonus depreciation and a decrease in projected future taxable income, PPL recorded $43 million in state deferred income tax expense related to deferred tax valuation allowances.
Additionally, the 100% Pennsylvania bonus depreciation deduction created a current state income tax benefit for the flow-through impact of Pennsylvania regulated state tax depreciation.
Pennsylvania H.B. 1531, enacted in October 2009, increased the net operating loss limitation to 20% of taxable income for tax years beginning in 2010. During 2009, based on the projected revenue increase due to the expiration of the Pennsylvania generation rate caps in 2010, PPL recorded a $13 million state deferred income tax benefit related to the reversal of deferred tax valuation allowances for a portion of its Pennsylvania net operating losses. During 2010, PPL recorded an additional $72 million state deferred income tax benefit related to the reversal of deferred tax valuation allowances related to the future projections of taxable income over the remaining carryforward period of the net operating losses.
(b)
During 2011, PPL recorded a $28 million federal income tax benefit related to U.K. pension contributions.
During 2010, PPL recorded additional U.S. income tax expense resulting from increased taxable dividends and certain restructuring of U.K. entities.
(c)
In 1997, the U.K. imposed a Windfall Profits Tax (WPT) on privatized utilities, including WPD. PPL filed its tax returns for years subsequent to its 1997 and 1998 claims for refund on the basis that the U.K. WPT was creditable. In September 2010, the U.S. Tax Court (Tax Court) ruled in PPL's favor in a dispute with the IRS, concluding that the U.K. WPT is a creditable tax for U.S. tax purposes. As a result and with the finalization of other issues, PPL recorded a $42 million tax benefit in 2010. In January 2011, the IRS appealed the Tax Court's decision to the U.S. Court of Appeals for the Third Circuit (Third Circuit). In December 2011, the Third Circuit issued its opinion reversing the Tax Court's decision and holding that the U.K. WPT is not a creditable tax. As a result of the Third Circuit's adverse determination, PPL recorded a $39 million expense in 2011. On February 27, 2012, PPL filed with the Third Circuit a petition for rehearing of its opinion on this matter.
In July 2010, the U.S. Tax Court ruled in PPL's favor in a dispute with the IRS, concluding that street lighting assets are depreciable for tax purposes over seven years. As a result, PPL recorded a $7 million tax benefit to federal and state income tax reserves and related deferred income taxes. The IRS did not appeal this decision.
During 2011, 2010 and 2009, PPL recorded a $6 million, $7 million and $6 million tax benefit to federal and state income tax reserves related to stranded cost securitization.
(d)
During 2011, WPD reached an agreement with the HM Revenue & Customs, the U.K. tax authority, related to the amount of the capital losses that resulted from prior years' restructuring in the U.K. and recorded a $147 million foreign tax benefit for the reversal of tax reserves related to the capital losses. Additionally, WPD recorded a $147 million valuation allowance for the amount of capital losses that, more likely than not, will not be utilized.
During 2010, PPL recorded a $261 million foreign tax benefit in conjunction with losses resulting from restructuring in the U.K. A portion of these losses offset tax on a deferred gain from a prior year sale of WPD's supply business. WPD recorded a $215 million valuation allowance for the amount of capital losses that, more likely than not, will not be realized.
During 2009, PPL recorded a $46 million foreign tax benefit and a related $46 million tax reserve related to losses resulting from restructuring in the U.K. Additionally, PPL recorded a $29 million foreign tax benefit related to the resolution of a tax dispute and foreign currency exchange losses.
(e)
During 2011, PPL recorded $17 million in federal and state tax benefits related to the filing of the 2010 federal and state income tax returns. Of this amount, $7 million in tax benefits relate to an additional domestic manufacturing deduction resulting from revised bonus depreciation amounts and $3 million in tax benefits relate to the flow-through impact of Pennsylvania regulated state tax depreciation.
During 2009, PPL received consent from the IRS to change its method of accounting for certain expenditures for tax purposes. PPL deducted the resulting IRC Sec. 481 adjustment on its 2008 federal income tax return and recorded a $24 million adjustment to federal and state income tax expense resulting from the reduction in federal income tax benefits related to the domestic manufacturing deduction and certain state tax benefits related to state net operating losses and regulated depreciation.
(f)
During 2010, PPL recorded an increase in tax benefits related to domestic manufacturing deductions due to an increase in domestic taxable income resulting from the expiration of generation rate caps in 2010. In December 2010, Congress enacted legislation allowing for 100% bonus depreciation on qualified property. The increased tax depreciation deduction related to bonus depreciation significantly reduced the tax benefits related to domestic manufacturing deductions during 2010 and eliminated the tax benefit in 2011.
(g)
Beginning in 2013, provisions within Health Care Reform eliminated the tax deductibility of retiree health care costs to the extent of federal subsidies received by plan sponsors that provide retiree prescription drug benefits equivalent to Medicare Part D Coverage. As a result, PPL recorded deferred income tax expense during 2010. See Note 13 for additional information.
(h)
The U.K.'s Finance Act of 2011, enacted in July 2011, included reductions in the U.K. statutory income tax rate. The statutory income tax rate was reduced from 27% to 26% retroactive to April 1, 2011 and will be reduced from 26% to 25 % effective April 1, 2012. As a result, PPL reduced its net deferred tax liabilities and recognized a deferred tax benefit during 2011 related to both tax rate decreases.
The U.K.'s Finance Act of 2010, enacted in July 2010, included a reduction in the U.K. statutory income tax rate. Effective April 1, 2011, the statutory income tax rate was reduced from 28% to 27%. As a result, PPL reduced its net deferred tax liabilities and recognized a deferred tax benefit.
(i)
During 2011 and 2010, PPL recorded a deferred tax benefit related to investment tax credits on progress expenditures related to hydroelectric plant expansions. See Note 8 for additional information.
(j)
During 2011, PPL completed the sale of certain non-core generation facilities. See Note 9 for additional information. Due to changes in state apportionment resulting in the reduction in the future estimated state tax rate, PPL recorded a deferred tax benefit related to its December 31, 2011 state deferred tax liabilities.
See Note 6 for information on a settlement related to PURTA tax that was returned to PPL Electric customers.
(PPL Energy Supply)
Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for accounting purposes and their basis for income tax purposes and the tax effects of net operating loss and tax credit carryforwards.
Net deferred tax assets have been recognized based on management's estimates of future taxable income for the U.S. and certain foreign jurisdictions in which PPL Energy Supply's operations have historically been profitable.
Significant components of PPL Energy Supply's deferred income tax assets and liabilities were as follows:
(a)
During 2011, PPL Energy Supply distributed its membership interest in PPL Global to PPL Energy Funding. See Note 9 for additional information.
Valuation allowances have been established for the amount that, more likely than not, will not be realized. The changes in deferred tax valuation allowances were:
(a)
During 2011, PPL Energy Supply distributed its membership interest in PPL Global to PPL Energy Funding. See Note 9 for additional information.
(b)
Resulting from the projected revenue increase in connection with the expiration of the Pennsylvania generation rate caps in 2010, the valuation allowance related to state net operating loss carryforwards over the remaining carryforward period was reduced by $52 million.
(c)
Pennsylvania state legislation, enacted in 2007 and 2009, increased the net operating loss limitation. As a result, the deferred tax asset (and related valuation allowance) associated with certain of its Pennsylvania net operating loss carryforwards for all periods presented were increased to reflect the higher limitation. There was no impact on the net deferred tax asset position as a result of the legislation and related adjustments.
(d)
Primarily related to the change in foreign net operating loss carryforwards including the change in currency exchange rates.
Details of the components of income tax expense, a reconciliation of federal income taxes derived from statutory tax rates applied to "Income (Loss) from Continuing Operations Before Income Taxes" to income taxes for reporting purposes, and details of "Taxes, other than income" were:
(a)
Excludes current and deferred federal, state and foreign tax expense (benefit) recorded to Discontinued Operations of $3 million in 2011, $(5) million in 2010 and $66 million in 2009. Also, excludes federal, state and foreign tax expense (benefit) recorded to OCI of $(83) million in 2011, $132 million in 2010 and $338 million in 2009. The deferred tax benefit of operating loss carryforwards was insignificant for 2011, 2010 and 2009.
(a)
During 2011, the Pennsylvania Department of Revenue issued interpretive guidance on the treatment of bonus depreciation for Pennsylvania income tax purposes. In accordance with Corporation Tax Bulletin 2011-01, Pennsylvania allows 100% bonus depreciation for qualifying assets in the same year bonus depreciation is allowed for Federal income tax purposes. Due to the decrease in taxable income related to bonus depreciation and a decrease in projected future taxable income, PPL Energy Supply recorded $22 million state deferred income tax expense related to deferred tax valuation allowances.
Pennsylvania H.B. 1531, enacted in October 2009, increased the net operating loss limitation to 20% of taxable income for tax years beginning in 2010. Based on the projected revenue increase related to the expiration of the generation rate caps, PPL Energy Supply recorded a $52 million state deferred income tax benefit related to the reversal of deferred tax valuation allowances over the remaining carry forward period of the net operating losses.
(b)
During 2011, PPL Energy Supply completed the sale of certain non-core generation facilities. See Note 9 for additional information. Due to changes in state apportionment resulting in the reduction in the future estimated state tax rate, PPL Energy Supply recorded a deferred tax benefit related to its December 31, 2011 state deferred tax liabilities.
(c)
During 2010, PPL Energy Supply recorded an increase in tax benefits related to domestic manufacturing deductions due to an increase in domestic taxable income resulting from the expiration of Pennsylvania generation rate caps in 2010. In December 2010, Congress enacted legislation allowing for 100% bonus depreciation on qualified property. The increased tax depreciation deduction related to bonus depreciation significantly reduced the tax benefits related to domestic manufacturing deductions during 2010 and eliminated the tax benefit in 2011.
(d)
During 2011, PPL recorded $22 million in federal and state tax benefits related to the filing of the 2010 federal and state income tax returns. $7 million in tax benefits relate to an additional domestic manufacturing deduction resulting from revised bonus depreciation amounts.
During 2009, PPL Energy Supply received consent from the IRS to change its method of accounting for certain expenditures for tax purposes. PPL Energy Supply deducted the resulting IRC Sec. 481 adjustment on its 2008 federal income tax return and recorded a $21 million adjustment to federal and state income tax expense resulting from the reduction in federal income tax benefits related to the domestic manufacturing deduction and certain state tax benefits related to state net operating losses.
(e)
Beginning in 2013, provisions within Health Care Reform eliminated the tax deductibility of retiree health care costs to the extent of federal subsidies received by plan sponsors that provide retiree prescription drug benefits equivalent to Medicare Part D Coverage. As a result, PPL Energy Supply recorded deferred income tax expense during 2010. See Note 13 for additional information.
(f)
During 2011 and 2010, PPL Energy Supply recorded a deferred tax benefit related to investment tax credits on progress expenditures related to hydroelectric plant expansions. See Note 8 for additional information.
(PPL Electric)
The provision for PPL Electric's deferred income taxes for regulated assets is based upon the ratemaking principles reflected in rates established by the PUC and the FERC. The difference in the provision for deferred income taxes for regulated assets and the amount that otherwise would be recorded under GAAP is deferred and included in "Regulatory assets" on the Balance Sheets.
Significant components of PPL Electric's deferred income tax assets and liabilities were as follows:
Details of the components of income tax expense, a reconciliation of federal income taxes derived from statutory tax rates applied to "Income Before Income Taxes" to income taxes for reporting purposes, and details of "Taxes, other than income" were:
(a)
In July 2010, the U.S. Tax Court ruled in PPL Electric's favor in a dispute with the IRS, concluding that street lighting assets are depreciable for tax purposes over seven years. As a result, PPL Electric recorded a $7 million tax benefit to federal and state income tax reserves and related deferred income taxes. The IRS did not appeal this decision.
During 2011, 2010 and 2009 PPL Electric recorded a $6 million, $7 million and $6 million tax benefit to federal and state income tax reserves related to stranded cost securitization.
(b)
During 2009, PPL Electric received consent from the IRS to change its method of accounting for certain expenditures for tax purposes. PPL Electric deducted the resulting IRC Sec. 481 amount on its 2008 federal income tax return and recorded a $3 million adjustment to federal and state income tax expense resulting from the reversal of prior years' state income tax benefits related to regulated depreciation.
(c)
In February 2011, the Pennsylvania Department of Revenue issued interpretive guidance on the treatment of bonus depreciation for Pennsylvania income tax purposes. In accordance with Corporation Tax Bulletin 2011-01, Pennsylvania allows 100% bonus depreciation for qualifying assets in the same year bonus depreciation is allowed for Federal income tax purposes. The 100% Pennsylvania bonus depreciation deduction created a current state income tax benefit for the flow-through impact of Pennsylvania regulated state tax depreciation.
See Note 6 for information on a settlement related to PURTA tax that was returned to PPL Electric customers.
(LKE)
The provision for LKE's deferred income taxes for regulated assets is based upon the ratemaking principles reflected in rates established by the KPSC, VSCC, TRA and the FERC. The difference in the provision for deferred income taxes for regulated assets and the amount that otherwise would be recorded under GAAP is deferred and included in "Regulatory liabilities" on the Balance Sheets.
Significant components of LKE's deferred income tax assets and liabilities were as follows:
(a)
Changes in balance primarily relate to investment tax credits for TC2, which began dispatching electricity in January 2011. See discussion on TC2 below.
LKE expects to have adequate levels of taxable income to realize its recorded deferred income tax assets.
LKE had the following loss and tax credit carryforwards.
(a)
Fully utilized against capital gains generated during 2011.
Changes in deferred tax valuation allowances were:
(a)
A valuation allowance was recorded against deferred tax assets for federal capital loss carryforwards.
(b)
A valuation allowance was recorded against deferred tax assets for state capital loss carryforwards.
(c)
Primarily related to the expiration of state capital loss carryforwards.
(d)
Related to release of a valuation allowance associated with federal capital loss carryforwards due to the LKE acquisition by PPL.
Details of the components of income tax expense, a reconciliation of federal income taxes derived from statutory tax rates applied to "Income Before Income Taxes" to income taxes for reporting purposes, and details of "Taxes, other than income" were:
(a)
Excludes current and deferred federal and state tax expense (benefit) recorded to Discontinued Operations of $(1) million in 2011, $1 million for the two month period ended December 31, 2010, $(1) million for the ten month period ended October 31, 2010 and $(116) million in 2009. Excludes deferred federal and state tax expense (benefit) recorded to OCI of $(1) million in 2011, $3 million for the two month period ended December 31, 2010, $(7) million for the ten month period ended October 31, 2010 and $12 million in 2009. Also excludes deferred federal and state tax expense recorded to Regulatory assets of $1 million in 2011, $2 million for the two month period ended December 31, 2010, $8 million for the ten month period ended October 31, 2010 and $11 million in 2009.
(LG&E)
The provision for LG&E's deferred income taxes for regulated assets is based upon the ratemaking principles reflected in rates established by the KPSC and the FERC. The difference in the provision for deferred income taxes for regulated assets and the amount that otherwise would be recorded under GAAP is deferred and included in "Regulatory liabilities" on the Balance Sheets.
Significant components of LG&E's deferred income tax assets and liabilities were as follows:
(a)
Changes in balance primarily relate to investment tax credits for TC2, which began dispatching electricity in January 2011. See discussion on TC2 below.
LG&E expects to have adequate levels of taxable income to realize its recorded deferred income tax assets.
Details of the components of income tax expense, a reconciliation of federal income taxes derived from statutory tax rates applied to "Income Before Income Taxes" to income taxes for reporting purposes, and details of "Taxes, other than income" were:
(a)
Excludes deferred federal and state tax expense recorded to OCI of $7 million for the ten month period ended October 31, 2010 and $2 million in 2009. Also excludes deferred federal and state tax expense recorded to Regulatory assets of $2 million in 2011, $1 million for the two month period ended December 31, 2010, $6 million for the ten month period ended October 31, 2010 and $5 million in 2009.
(KU)
The provision for KU's deferred income taxes for regulated assets is based upon the ratemaking principles reflected in rates established by the KPSC, VSCC, TRA and the FERC. The difference in the provision for deferred income taxes for regulated assets and the amount that otherwise would be recorded under GAAP is deferred and included in "Regulatory liabilities" on the Balance Sheets.
Significant components of KU's deferred income tax assets and liabilities were as follows:
(a)
Changes in balance primarily relate to investment tax credits for TC2, which began dispatching electricity in January 2011. See discussion on TC2 below.
KU expects to have adequate levels of taxable income to realize its recorded deferred income tax assets.
Details of the components of income tax expense, a reconciliation of federal income taxes derived from statutory tax rates applied to "Income Before Income Taxes" to income taxes for reporting purposes, and details of "Taxes, other than income" were:
(a)
Excludes deferred federal and state tax (benefit) recorded to OCI of $(1) million for the ten month period ended October 31, 2010. Also excludes deferred federal and state tax expense (benefit) recorded to Regulatory assets of $(1) million in 2011, $1 million for the two month period ended December 31, 2010, $2 million for the ten month period ended October 31, 2010 and $7 million in 2009.
(LKE, LG&E and KU)
In June 2006, LG&E and KU filed a joint application with the DOE requesting certification to be eligible for $125 million in investment tax credits ($24 million to LG&E and $101 million to KU) applicable to the construction of TC2. All necessary DOE and IRS approvals were subsequently received. In September 2007, LG&E and KU received an Order from the KPSC approving the accounting of the investment tax credits, which includes full depreciation basis adjustment for the amount of the credits. The income tax impacts from recording the depreciation basis adjustment and from amortizing these credits over the life of the related property began in January 2011, when LKE began dispatching electricity from TC2 to meet customer demand. In 2011, $2 million of net tax benefits were recognized for LG&E and KU.
Unrecognized Tax Benefits (PPL, PPL Energy Supply, PPL Electric, LKE, LG&E and KU)
Changes to unrecognized tax benefits were as follows:
(a)
Represents unrecognized tax benefits derecognized as a result of PPL Energy Supply's distribution of its membership interest in PPL Global to PPL Energy Supply's parent, PPL Energy Funding. See Note 9 for additional information on the distribution.
LKE's, LG&E's and KU's unrecognized tax benefits and changes in those unrecognized tax benefits are insignificant at December 31, 2011 and December 31, 2010.
At December 31, 2011, it was reasonably possible that during the next 12 months the total amount of unrecognized tax benefits could increase or decrease by the following amounts. For LKE, LG&E and KU, no significant changes in unrecognized tax benefits are projected over the next 12 months.
These potential changes could result from subsequent recognition, derecognition and/or changes in the measurement of uncertain tax positions related to the creditability of foreign taxes, the timing and utilization of foreign tax credits and the related impact on alternative minimum tax and other credits, the timing and/or valuation of certain deductions, intercompany transactions and unitary filing groups. The events that could cause these changes are direct settlements with taxing authorities, litigation, legal or administrative guidance by relevant taxing authorities and the lapse of an applicable statute of limitation.
At December 31, the total unrecognized tax benefits and related indirect effects that, if recognized, would decrease the effective tax rate were as follows. The amounts for LKE, LG&E and KU were insignificant.
At December 31, 2011 and 2010, the following receivable (payable) balances were recorded for interest related to tax positions. The amounts for LKE, LG&E and KU were insignificant.
The following interest expense (benefit) was recognized in income taxes. The amounts for LKE, LG&E and KU were insignificant.
PPL or its subsidiaries file tax returns in five major tax jurisdictions. The income tax provisions for PPL Energy Supply, PPL Electric, LKE, LG&E and KU are calculated in accordance with an intercompany tax sharing policy which provides that taxable income be calculated as if each domestic subsidiary filed a separate consolidated return. Based on this tax sharing agreement, PPL Energy Supply or its subsidiaries indirectly or directly file tax returns in three major tax jurisdictions, PPL Electric or its subsidiaries indirectly or directly file tax returns in two major tax jurisdictions, and LKE, LG&E and KU or their subsidiaries indirectly or directly file tax returns in two major tax jurisdictions. With few exceptions, at December 31, 2011, these jurisdictions, as well as the tax years that are no longer subject to examination, were as follows:
(a)
For LKE, LG&E and KU 2008 and 2009, as well as the ten month period ending October 31, 2010, remain open under the standard three year statute of limitations; however, the IRS has completed its audit of these periods under the Compliance Assurance Process, effectively closing them to audit adjustments. No issues remain outstanding.
(b)
Through an indirect wholly owned subsidiary, PPL acquired WPD Midlands on April 1, 2011. PPL is obligated for the acquired companies' tax liability commencing with tax year 2011. The acquired companies are no longer subject to audit for 2007 and prior years.
Other (PPL, PPL Energy Supply and PPL Electric)
PPL changed its method of accounting for repair expenditures for tax purposes effective for its 2008 tax year for the Pennsylvania generation, transmission and distribution operations. The same change was made for the Montana generation operations for 2009.
In August 2011, the IRS issued Rev. Procs. 2011-42 and 2011-43. Rev. Proc. 2011-42 provides guidance regarding the use and evaluation of statistical samples and sampling estimates. Rev. Proc. 2011-43 provides a safe harbor method of determining whether the repair expenditures for electric transmission and distribution property can be currently deducted for tax purposes. If PPL adopts the safe harbor method of Rev. Proc. 2011-43, the amount of deductible versus capitalizable expenditures will likely be different from PPL's current method. PPL does not believe any resulting adjustment to unrecognized tax benefits or income tax liabilities will have a significant impact on net income.
The IRS has not issued guidance to provide a safe harbor method for repair expenditures for generation property. The IRS may assert and ultimately conclude that PPL's deduction for generation-related expenditures should be disallowed in whole or in part. PPL believes that it has provided adequate reserves for this issue.
6. Utility Rate Regulation
(PPL, PPL Electric, LKE, LG&E and KU)
As discussed in Note 1 and summarized below, PPL, PPL Electric, LKE, LG&E and KU reflect the effects of regulatory actions in the financial statements for their cost-based rate-regulated utility operations. Regulatory assets and liabilities are classified as current if, upon initial recognition, the entire amount related to that item will be recovered or refunded within a year of the balance sheet date. As such, the primary items classified as current are related to rate mechanisms that periodically adjust to account for over- or under-collections.
(PPL, LKE, LG&E and KU)
LG&E is subject to the jurisdiction of the KPSC and FERC, and KU is subject to the jurisdiction of the KPSC, FERC, VSCC and TRA.
LG&E's and KU's Kentucky base rates are calculated based on a return on capitalization (common equity, long-term debt and notes payable) including certain adjustments to exclude non-regulated investments and environmental compliance costs recovered separately through the ECR mechanism. As such, regulatory assets generally earn a return.
As a result of purchase accounting requirements, certain fair value amounts related to contracts that had favorable or unfavorable terms relative to market were recorded on the Balance Sheets with an offsetting regulatory asset or liability. LG&E and KU recover in customer rates the cost of coal contracts, power purchases and emission allowances. As a result, management believes the regulatory assets and liabilities created to offset the fair value amounts at the acquisition date meet the recognition criteria established by existing accounting guidance and eliminate any rate making impact of the fair value adjustments. LG&E's and KU's customer rates will continue to reflect the original contracted prices for these contracts.
(PPL, LKE and KU)
KU's Virginia base rates are calculated based on a return on rate base (net utility plant plus working capital less deferred taxes and miscellaneous deductions). All regulatory assets and liabilities, except the levelized fuel factor, are excluded from the return on rate base utilized in the calculation of Virginia base rates; therefore, no return is earned on the related assets.
KU's rates to municipal customers for wholesale requirements are calculated based on annual updates to a rate formula that utilizes a return on rate base (net utility plant plus working capital less deferred taxes and miscellaneous deductions). All regulatory assets and liabilities are excluded from the return on rate base utilized in the development of municipal rates; therefore, no return is earned on the related assets.
(PPL and PPL Electric)
PPL Electric's distribution base rates are calculated based on a return on rate base (net utility plant plus a cash working capital allowance less plant-related deferred taxes and other miscellaneous additions and deductions). PPL Electric's transmission revenues are billed in accordance with a FERC tariff that allows for recovery of transmission costs incurred, a return on transmission-related plant and an automatic annual update. See "Transmission Formula Rate" below for additional information on this tariff. All regulatory assets and liabilities are excluded from distribution and transmission return on investment calculations; therefore, generally no return is earned on PPL Electric's regulatory assets.
(PPL, PPL Electric, LKE, LG&E and KU)
The following tables provide information about the regulatory assets and liabilities of cost-based rate-regulated utility operations.
(a)
PPL Electric's generation supply charge recovery mechanism moved from an undercollected status at December 31, 2010 to an overcollected status at December 31, 2011, reflecting the impacts of changes in customer billing cycles, the timing of rate reconciliation filings, the levels of customers choosing alternative energy suppliers and other factors. Because customer rates are designed to collect the costs of PPL Electric's energy purchases to meet its PLR requirements, there is minimal impact on earnings.
(b)
The December 31, 2010 balance of accumulated cost of removal of utility plant was reclassified from "Accumulated depreciation - regulated utility plant" to noncurrent "Regulatory assets" on the Balance Sheets. These costs will continue to be included in future rate proceedings.
(c)
These regulatory assets and liabilities were recorded as offsets to certain intangible assets and liabilities that were recorded at fair value upon the acquisition of LKE.
Regulatory Assets and Liabilities
Following is an overview of selected regulatory assets and liabilities detailed in the preceding tables. Specific developments with respect to certain of these regulatory assets and liabilities are discussed in "Regulatory Matters."
(PPL and PPL Electric)
Generation Supply Charge
The generation supply charge is a cost recovery mechanism that permits PPL Electric to recover costs incurred to provide generation supply to PLR customers who receive basic generation supply service. The recovery includes charges for generation supply (energy and capacity and ancillary services), as well as administration of the acquisition process. In addition, the generation supply charge contains a reconciliation mechanism whereby any over- or under-recovery from prior quarters is refunded to, or recovered from, customers through the adjustment factor determined for the subsequent quarter.
Universal Service Rider (USR)
PPL Electric's distribution rates permit recovery of applicable costs associated with the universal service programs provided to PPL Electric's residential customers. Universal service programs include low-income programs, such as OnTrack and Winter Relief Assistance Program (WRAP). OnTrack is a special payment program for low-income households within the federal poverty level who have difficulty paying their electric bills. This program is funded by residential customers and administered by community-based organizations. Customers who participate in OnTrack receive assistance in the form of reduced payment arrangements, protection against termination of electric service and referrals to other community programs and services. The WRAP program reduces electric bills and improves living comfort for low-income customers by providing services such as weatherization measures and energy education services. The USR is applied to distribution charges for each customer who receives distribution service under PPL Electric's residential service rate schedules. The USR contains a reconciliation mechanism whereby any over- or under-recovery from the current year is refunded to or recovered from residential customers through the adjustment factor determined for the subsequent year.
Taxes Recoverable through Future Rates
Taxes recoverable through future rates represent the portion of future income taxes that will be recovered through future rates based upon established regulatory practices. Accordingly, this regulatory asset is recognized when the offsetting deferred tax liability is recognized. For general-purpose financial reporting, this regulatory asset and the deferred tax liability are not offset; rather, each is displayed separately. This regulatory asset is expected to be recovered over the period that the underlying book-tax timing differences reverse and the actual cash taxes are incurred.
PURTA Tax
In December 2009, PPL Electric reached a settlement with the Pennsylvania Department of Revenue related to the appeal of its 1997 PURTA tax assessments that resulted in a reduction in PURTA tax. Substantially all of the regulatory liability was refunded to customers in 2011 pursuant to PUC regulations.
Act 129 Compliance Rider
In compliance with Pennsylvania's Act 129 of 2008 and implementing regulations, PPL Electric filed its energy efficiency and conservation plan in July 2009. The plan was approved by PUC Order in October 2009. The Order allows PPL Electric to recover the maximum $250 million cost of the program ratably over the life of the plan, from January 1, 2010 through May 31, 2013. The plan includes programs intended to reduce electricity consumption. The recoverable costs include direct and indirect charges, including design and development costs, general and administrative costs and applicable state evaluator costs. The rates are applied to customers who receive distribution service through the Act 129 Compliance Rider. The actual program costs are reconcilable, and any over- or under-recovery from customers will be refunded or collected at the end of the program. See below under "Regulatory Matters - Pennsylvania Activities" for additional information on Act 129.
Transmission Service Charge (TSC)
PPL Electric is charged by PJM for transmission service-related costs applicable to its PLR customers. PPL Electric passes these costs on to customers, who receive basic generation supply service through the PUC-approved TSC cost recovery mechanism. The TSC contains a reconciliation mechanism whereby any over- or under-recovery from customers is either refunded to, or recovered from, customers through the adjustment factor determined for the subsequent year.
(PPL, PPL Electric, LKE, LG&E and KU)
Defined Benefit Plans
Recoverable costs of defined benefit plans represent the portion of unrecognized transition obligation, prior service cost and net actuarial losses that will be recovered in defined benefit plans expense through future base rates based upon established regulatory practices. These regulatory assets and liabilities are adjusted at least annually or whenever the funded status of defined benefit plans is re-measured. Of the regulatory asset and liability balances recorded, the following costs of $44 million for PPL, $13 million for PPL Electric, $31 million for LKE, $21 million for LG&E and $10 million for KU are expected to be amortized into net periodic defined benefit costs in 2012. All costs will be amortized over the average service lives of plan participants.
Storm Costs
PPL Electric, LG&E and KU have the ability to request from the PUC, KPSC and VSCC the authority to treat expenses related to specific extraordinary storms as a regulatory asset and defer and amortize such costs for regulatory accounting and reporting purposes. Once such authority is granted, PPL Electric, LG&E and KU can request recovery of those expenses in a base rate case.
Unamortized Loss on Debt
Unamortized loss on reacquired debt represents losses on long-term debt reacquired or redeemed that have been deferred and will be amortized and recovered over either the original life of the extinguished debt or the life of the replacement debt (in the case of refinancing). Such costs are being amortized through 2029 for PPL Electric. Such costs are being amortized through 2035 for LG&E and 2036 for PPL, LKE and KU.
As further discussed in Note 7, in July 2011 PPL Electric redeemed Senior Secured Bonds for $458 million, plus accrued interest. The redemption premium and the unamortized financing costs of $59 million were recorded as a regulatory asset and will be amortized over the life of the replacement debt.
Accumulated Cost of Removal
LG&E and KU accrue for costs of removal through depreciation expense with an offsetting credit to a regulatory liability. The regulatory liability is relieved as costs are incurred. See Note 1 for additional information.
PPL Electric does not accrue for costs of removal. When costs of removal are incurred, PPL Electric records the deferral of costs as a regulatory asset. Such deferral is included in rates and amortized over the subsequent five-year period.
(PPL, LKE, LG&E and KU)
ECR
Kentucky law permits LG&E and KU to recover the costs, including a return of operating expenses and a return of and on capital invested, of complying with the Federal Clean Air Act and those federal, state or local environmental requirements which apply to coal combustion wastes and by-products from coal-fired electric generating facilities. The KPSC requires reviews of the past operations of the environmental surcharge for six-month and two-year billing periods to evaluate the related charges, credits and rates of return, as well as to provide for the roll-in of ECR amounts to base rates each two-year period. The ECR regulatory asset or liability represents the amount that has been under- or over-recovered due to timing or adjustments to the mechanism and is recovered within 12 months. LG&E and KU are authorized to receive a 10.63% return on equity for the 2005, 2006 and 2009 compliance plans and a 10.10% return on projects associated with the 2011 compliance plan.
Coal Contracts
As a result of purchase accounting associated with PPL's acquisition of LKE, LG&E's and KU's coal contracts were recorded at fair value on the Balance Sheets with offsets to regulatory assets for those contracts with unfavorable terms relative to current market prices and offsets to regulatory liabilities for those contracts with favorable terms relative to current market prices. These regulatory assets and liabilities are being amortized over the same terms as the related contracts, which expire at various times through 2016.
Gas Supply Clause
LG&E's natural gas rates contain a gas supply clause, whereby the expected cost of natural gas supply and variances between actual and expected costs from prior periods are adjusted quarterly in LG&E's rates, subject to approval by the KPSC. The gas supply clause includes a separate natural gas procurement incentive mechanism, a performance-based rate, which allows LG&E's rates to be adjusted annually to share variances between actual costs and market indices between the shareholders and the customers during each performance-based rate year (12 months ending October 31). The regulatory assets or liabilities represent the total amounts that have been under- or over-recovered due to timing or adjustments to the mechanisms and are recovered within 18 months.
Fuel Adjustments
LG&E's and KU's retail electric rates contain a fuel adjustment clause, whereby variances in the cost of fuel for electric generation, including transportation costs, from the costs embedded in base rates are adjusted in LG&E's and KU's rates. The KPSC requires public hearings at six-month intervals to examine past fuel adjustments and at two-year intervals to review past operations of the fuel clause and, to the extent appropriate, reestablish the fuel charge included in base rates.
KU also employs a levelized fuel factor mechanism for Virginia customers using an average fuel cost factor based primarily on projected fuel costs. The Virginia levelized fuel factor allows fuel recovery based on projected fuel costs for the coming year plus an adjustment for any under- or over-recovery of fuel expenses from the prior year. The regulatory assets or liabilities represent the amounts that have been under- or over-recovered due to timing or adjustments to the mechanism and are recovered within 12 months.
Interest Rate Swaps
(PPL, LKE and LG&E)
Because realized amounts associated with LG&E's interest rate swaps, including a terminated swap contract, are recoverable through rates based on an Order from the KPSC, LG&E's unrealized gains and losses are recorded as a regulatory asset or liability until they are realized as interest expense. Interest expense from existing swaps is realized and recovered over the
terms of the associated debt, which matures through 2033. Amortization of the gain/loss related to the terminated swap contract is recovered through 2035 as approved by the KPSC.
(LKE and LG&E)
In the third quarter of 2010, LG&E recorded a pre-tax gain to reverse previously recorded losses of $21 million and $9 million to reflect the reclassification of its ineffective swaps and terminated swap to regulatory assets based on an Order from the KPSC in the 2010 rate case whereby the cost of LG&E's terminated swap was allowed to be recovered in base rates. Previously, gains and losses on interest rate swaps designated as effective cash flow hedges were recorded within other comprehensive income and common equity. The gains and losses on the ineffective portion of interest rate swaps designated as cash flow hedges were recorded to earnings monthly, as was the entire change in the market value of the ineffective swaps.
(PPL, LKE, LG&E and KU)
AROs
As noted in Note 1, the accretion and depreciation related to LG&E's and KU's AROs are offset with a regulatory credit on the income statement, such that there is no earnings impact. When an asset with an ARO is retired, the related ARO regulatory asset created by the regulatory credit is offset against the associated regulatory liability, PP&E and ARO liability.
DSM
DSM consists of energy efficiency programs which are intended to reduce peak demand and delay the investment in additional power plant construction, provide customers with tools and information to become better managers of their energy usage and prepare for potential future legislation governing energy efficiency. LG&E's and KU's rates contain a DSM rate mechanism that provides for concurrent recovery of DSM costs and also provides an incentive for implementing DSM programs. The provision also allows LG&E and KU to recover revenues from lost sales associated with the DSM programs up to the earlier of three years or implementation of new base rates which reflect that load reduction. In addition, with the KPSC Order issued in November 2011, the DSM mechanism now includes a provision to earn a return of and on capital investment for DSM programs. The regulatory assets or liabilities represent the total amounts that have been under- or over-recovered due to timing or adjustments to the mechanism.
Power Purchase Agreement - OVEC
As a result of purchase accounting associated with PPL's acquisition of LKE, LG&E's and KU's fair values of the OVEC power purchase agreement were recorded on the balance sheets with offsets to regulatory liabilities. The regulatory liabilities are being amortized using the units-of-production method until March 2026, the expiration date of the agreement at the date of the acquisition, and have no impact on rate making.
Regulatory Liability associated with Net Deferred Tax Assets
LG&E's and KU's regulatory liabilities associated with net deferred tax assets represent the future revenue impact from the reversal of deferred income taxes required primarily for unamortized investment tax credits. These regulatory liabilities are recognized when the offsetting deferred tax assets are recognized. For general-purpose financial reporting, these regulatory liabilities and the deferred tax assets are not offset; rather, each is displayed separately.
Regulatory Matters
Kentucky Activities (PPL, LKE, LG&E and KU)
Environmental Upgrades
In order to achieve compliance with new and pending federal EPA regulations including the CSAPR, National Ambient Air Quality Standards and MATS, in June 2011, LG&E and KU filed ECR plans with the KPSC requesting approval to install environmental upgrades for certain of their coal-fired plants and for recovery of the expected $2.5 billion in associated capital costs, as well as operating expenses incurred. The ECR plans detailed upgrades that will be made to certain of their coal-fired generating plants to continue to be compliant with EPA regulations. LG&E requested $1.4 billion to modernize the sulfur dioxide scrubbers at the Mill Creek generating plant as well as install fabric-filter baghouse systems for increased particulate and mercury control on all units at the Mill Creek generating plant and on Unit 1 at the Trimble County generating plant. KU requested $1.1 billion to upgrade fabric-filter baghouse systems for increased particulate and mercury control on
all units at the E.W. Brown and Ghent generating plants and to convert a wet storage facility to a dry landfill at the E.W. Brown generating plant.
In November 2011, LG&E and KU filed a unanimous settlement agreement, stipulation and recommendation with the KPSC. In December 2011, LG&E and KU received KPSC approval in their proceedings relating to the ECR plans. The KPSC Order approved the terms of the November 2011 settlement agreement entered into between LG&E and KU and the parties to the ECR proceedings. The KPSC Order authorized the installation of environmental upgrades at certain plants during 2012-2016 representing approximate capital costs of $1.4 billion at LG&E and $900 million at KU. In connection with the approved projects, the KPSC Order allowed recovery through the ECR rate mechanism of the capital costs and operating expenses of the projects and granted CPCNs for their construction. The KPSC Order also confirmed an existing 10.63% authorized return on equity for projects remaining from earlier ECR plans and provided for an authorized return on equity of 10.10% for the approved projects in the 2011 ECR proceedings. The KPSC Order noted KU's consent to defer the requested approval for certain environmental upgrades at its E.W. Brown generating plant, which represented approximately $200 million in capital costs. KU retained the right to operate and dispatch the E.W. Brown generating plant in accordance with applicable environmental standards and the right to request approval of the deferred projects and related costs in future regulatory proceedings. See Note 15 for additional information.
IRP
IRP regulations in Kentucky require major utilities to make triennial IRP filings with the KPSC. In April 2011, LG&E and KU filed their 2011 joint IRP with the KPSC. The IRP provides historical and projected demand, resource and financial data, and other operating performance and system information. In May 2011, the KPSC issued a procedural schedule and data discovery concluded during the fourth quarter. The IRP assumes approximately 500 MW of peak demand reductions by 2017 through existing or expanded DSM or energy efficiency programs. Implementation of the major findings of the IRP is subject to further analysis and decision-making and further regulatory approvals. LG&E and KU are awaiting the KPSC Staff report, which will close this proceeding.
CPCN Filing
In September 2011, LG&E and KU filed a CPCN with the KPSC requesting approval to build a 640 MW NGCC at the existing Cane Run plant site. LG&E will own a 22% undivided interest, and KU will own a 78% undivided interest in the new NGCC. In addition, LG&E and KU also requested approval to purchase the Bluegrass CTs which are expected to provide up to 495 MW of peak generation supply. LG&E will own a 69% undivided interest, and KU will own a 31% undivided interest in the purchased assets. In conjunction with these developments, at the end of 2015, LG&E and KU anticipate retiring three coal-fired generating units at LG&E's Cane Run plant and also one coal-fired generating unit at KU's Tyrone plant and two at KU's Green River plant. These generating units represent 797 MW of combined summer capacity.
LG&E and KU anticipate that the NGCC construction and the acquisition of the Bluegrass CTs could require up to $800 million (comprised of up to $300 million for LG&E and up to $500 million for KU) in capital costs including related transmission projects. Formal requests for recovery of the costs associated with the NGCC construction and the acquisition of the Bluegrass CTs were not included in the CPCN filing with the KPSC but are expected to be included in future rate proceedings. The KPSC issued an Order on the procedural schedule in the CPCN filing that has discovery scheduled through early February 2012. A KPSC order on the CPCN filing is anticipated in the second quarter of 2012.
PPL's Acquisition of LKE
In September 2010, the KPSC approved a settlement agreement among PPL and all of the intervening parties to PPL's joint application to the KPSC for approval of its acquisition of ownership and control of LKE, LG&E and KU. In the settlement agreement, the parties agreed that LG&E and KU would commit that no base rate increases would take effect before January 1, 2013. Under the terms of the settlement, LG&E and KU retain the right to seek KPSC approval for the deferral of "extraordinary and uncontrollable costs," such as significant storm restoration costs, if incurred. Additionally, interim rate adjustments will continue to be permissible during that period for existing recovery mechanisms such as the ECR and DSM.
In connection with the approval of PPL's acquisition of LKE, LG&E and KU agreed to implement the Acquisition Savings Sharing Deferral (ASSD) methodology whereby LG&E's and KU's adjusted jurisdictional revenues, expenses, and net operating income are calculated each year. If LG&E's or KU's actual earned rate of return on common equity is in excess of 10.75%, fifty percent of the excess amount will be deferred as a regulatory liability and ultimately returned to customers. The first ASSD filing will be made by April 1, 2012 based on the 2011 calendar year. Based upon 2011 earnings and their current estimates of the outcome of an ASSD filing in 2012, LG&E and KU have not recognized any impact of the ASSD in the financial statements as of December 31, 2011. The ASSD methodology for each of LG&E's and KU's utility operations
will terminate on the earlier of the end of 2015 or the first day of the calendar year during which new base rates go into effect.
Independent Transmission Operators
LG&E and KU operate under a FERC-approved open access transmission tariff. LG&E and KU contract with the Tennessee Valley Authority, to act as their transmission reliability coordinator, and Southwest Power Pool, Inc. (SPP), to function as their independent transmission operator, pursuant to FERC requirements. The contract with SPP expires on August 31, 2012. LG&E and KU have received FERC approval to transfer from SPP to TranServ International, Inc. as their independent transmission operator beginning September 1, 2012. Approval from the KPSC is required, and an application requesting approval was filed in January 2012.
Storm Costs
In August 2011, a strong storm hit LG&E's service area causing significant damage and widespread outages for approximately 139,000 customers. LG&E filed an application with the KPSC in September 2011 requesting approval of a regulatory asset recorded to defer, for future recovery, $8 million in incremental operation and maintenance expenses related to the storm restoration. An Order was received in December 2011 granting regulatory accounting treatment, while recovery of the regulatory asset will be determined within the next base rate case.
In September 2009, the KPSC approved the deferral of $44 million and $57 million for LG&E and KU of costs associated with a severe ice storm that occurred in January 2009 and a wind storm that occurred in February 2009. Additionally, in December 2008, the KPSC approved the deferral of $24 million and $2 million for LG&E and KU of costs associated with high winds from the remnants of Hurricane Ike in September 2008. LG&E and KU received approval in their 2010 base rate cases to recover these regulatory assets over a ten-year amortization period ending July 2020.
DSM/Energy Efficiency
In April 2011, LG&E and KU filed a DSM application to expand existing energy efficiency programs and implement new energy efficiency programs. Discovery and evidentiary phases concluded in September 2011. In November 2011, the KPSC approved the application as filed. The new rates were effective December 30, 2011.
Virginia Activities (PPL, LKE and KU)
IRP
Pursuant to a December 2008 Order, KU filed the 2011 joint IRP with the VSCC in September 2011, with certain supplemental information as required by this Order. The IRP provides historical and projected demand, resource and financial data, and other operating performance and system information and assumes approximately 500 MW of peak demand reductions by 2017 through existing or expanded DSM or energy efficiency programs. Implementation of the major findings of the IRP is subject to further analysis and decision-making and further regulatory approvals.
Virginia Fuel Factor
In February 2011, KU filed an application with the VSCC seeking approval of an increase in its fuel cost factor beginning with service rendered in April 2011. In March 2011, a hearing was held on KU's requested fuel factor, and an Order was issued approving a revised fuel factor to be in effect beginning with service rendered on and after April 1, 2011, with recovery of the regulatory asset for prior period under-recoveries over a three-year amortization period.
Storm Costs
In December 2009, a major snowstorm hit KU's Virginia service area causing approximately 30,000 customer outages. During the normal 2009 Virginia Annual Information Filing (AIF), KU requested that the VSCC establish a regulatory asset and defer for future recovery $6 million in incremental operation and maintenance expenses related to the storm restoration. In March 2011, the VSCC Staff issued its report on KU's 2009 AIF stating that it considered this storm damage to be extraordinary, non-recurring and material to KU. The Staff report also recommended establishing a regulatory asset for these costs, with recovery over a five-year period upon approval in the next base rate case. In March 2011, a regulatory asset of $6 million was established for actual costs incurred. In June 2011, the VSCC issued an Order approving the recommendations contained in the Staff report, and KU began recovering these costs over a five-year amortization period ending October 2016.
Pennsylvania Activities (PPL and PPL Electric)
Act 129
Act 129 requires Pennsylvania Electric Distribution Companies (EDCs) to meet specified goals for reduction in customer electricity usage and peak demand by specified dates. EDCs not meeting the requirements of Act 129 are exposed to significant penalties.
Under Act 129, EDCs must file an energy efficiency and conservation plan (EE&C Plan) with the PUC and contract with conservation service providers to implement all or a portion of the EE&C Plan. Act 129 requires EDCs to cause reduced overall electricity consumption of 1.0% by May 2011 and 3.0% by May 2013 and reduced peak demand of 4.5% for the 100 hours of highest demand by May 2013 (which will be measured during the June 2012 through September 2012 period). To date, PPL Electric has met the 2011 requirement, subject to the PUC's verification. EDCs will be able to recover the costs (capped at 2% of the EDC's 2006 revenue) of implementing their EE&C Plans. In October 2009, the PUC approved PPL Electric's EE&C Plan. The plan includes 14 programs, all of which are voluntary for customers. The plan includes a proposed rate mechanism for recovery of all costs incurred (up to a maximum of $250 million) by PPL Electric to implement the plan. Such costs include direct and indirect charges, including design, general and administrative costs and applicable state evaluator costs, and are being recovered over the period from January 1, 2010 through May 31, 2013. The costs are recovered through the Act 129 Compliance Rider from all customers who receive distribution service. The program contains a reconciliation mechanism whereby any over- or under-recovery from customers will be refunded or collected at the end of the program. In September 2010, PPL Electric filed its Program Year 1 Annual Report and Process Evaluation Report. PPL Electric also filed a petition requesting permission to modify two components of its EE&C Plan. The PUC issued its Final Order in January 2011, approving the changes proposed by PPL Electric and directing PPL Electric to re-file its plan to reflect all changes made since its initial approval. In February 2011, PPL Electric filed the changes to its plan and in May 2011, the PUC approved those changes. PPL Electric filed its Program Year 2 Annual Report and Process Evaluation Report in November 2011. In February 2012, PPL Electric filed a petition with the PUC requesting permission to implement additional changes to its EE&C Plan. Other parties have 30 days to file comments to this petition; PPL Electric has 20 days to file reply comments.
Act 129 also requires the Default Service Provider (DSP) to provide electric generation supply service to customers pursuant to a PUC-approved competitive procurement plan through auctions, requests for proposal and bilateral contracts at the sole discretion of the DSP. Act 129 requires a mix of spot market purchases, short-term contracts and long-term contracts (4 to 20 years), with long-term contracts limited to 25% of the load unless otherwise approved by the PUC. The DSP will be able to recover the costs associated with a competitive procurement plan.
Under Act 129, the DSP competitive procurement plan must ensure adequate and reliable service "at least cost to customers" over time. Act 129 grants the PUC authority to extend long-term power contracts up to 20 years, if necessary, to achieve the "least cost" standard. The PUC has approved PPL Electric's procurement plan for the period January 1, 2011 through May 31, 2013, and PPL Electric continues to procure power for its PLR obligations under that plan. In December 2010, the PUC approved PPL Electric's rate rider to recover the costs of providing default service.
Smart Meter Rider
Act 129 also requires installation of smart meters for new construction, upon the request of consumers and at their cost, or on a depreciation schedule not exceeding 15 years. Under Act 129, EDCs will be able to recover the costs of providing smart metering technology. In August 2009, PPL Electric filed its proposed smart meter technology procurement and installation plan with the PUC. All of PPL Electric's metered customers currently have smart meters installed at their service locations. PPL Electric's current advanced metering technology generally satisfies the requirements of Act 129 and does not need to be replaced. In June 2010, the PUC entered its order approving PPL Electric's smart meter plan with several modifications. In compliance with the Order, in the third quarter of 2010, PPL Electric submitted a revised plan with a cost estimate of $38 million to be incurred over a five-year period, beginning in 2009, and filed its Section 1307(e) cost recovery mechanism, the Smart Meter Rider (SMR) to recover these costs beginning January 1, 2011. In December 2010, the PUC approved PPL Electric's SMR which reflects the costs of its smart meter program plus a return on its Smart Meter investments. The SMR, which became effective January 1, 2011, contains a reconciliation mechanism whereby any over- or under-recovery from customers is either refunded to or collected from customers in the subsequent year. In August 2011, PPL Electric filed with the PUC an annual report describing the actions it is taking under its Smart Meter plan in 2011 and its planned actions for 2012. PPL Electric also submitted revised SMR charges which became effective January 1, 2012.
PUC Investigation of Retail Market
In April 2011, the PUC opened an investigation of Pennsylvania's retail electricity market to be conducted in two phases. Phase one addressed the status of the current retail market and explored potential changes. Questions promulgated by the PUC for this phase of the investigation focused primarily on default service issues. In June 2011, interested parties filed comments and the PUC held a hearing in this phase of the investigation. In July 2011, the PUC entered an order initiating phase two of the investigation to study how best to address issues identified by the PUC as being most relevant to improving the current retail electricity market. The PUC issued a tentative order in October 2011 addressing issues associated with the timing and various other details of EDCs' default service procurement plans. Parties filed comments to that tentative order. The PUC also held a hearing in this phase of the investigation in November 2011. In December 2011, the PUC issued a final order providing guidance to EDCs on the design of their next default service procurement plan filings. In December 2011, the PUC also issued a tentative order proposing an intermediate work plan to address issues raised in the investigation. Parties filed comments to that tentative order. PPL Electric cannot predict the outcome of the investigation.
Legislation - Regulatory Procedures and Mechanisms
In June 2011, the Pennsylvania House Consumer Affairs Committee approved legislation that would authorize the PUC to approve regulatory procedures and mechanisms to provide for more timely recovery of a utility's costs. Such alternative ratemaking procedures and mechanisms are important to PPL Electric as it begins a period of significant increasing capital investment related to the asset optimization program focused on the replacement of aging distribution assets. Those procedures and mechanisms include, but are not limited to, the use of a fully projected future test year and an automatic adjustment clause to recover certain capital costs and related operating expenses. In October 2011, the legislation was passed by the Pennsylvania House of Representatives. In January 2012, the Senate Consumer Affairs Committee adopted significant amendments to the legislation. The amended legislation authorizes the PUC to approve only two specific ratemaking mechanisms -- a fully projected future test year and a distribution system improvements charge. In addition, the amendments impose a number of conditions on the use of such a charge. In January 2012, the Pennsylvania Senate passed the amended legislation and in February 2012, the Pennsylvania House agreed to those amendments. The Governor signed the bill (Act 11 of 2012), which will become effective April 14, 2012. Utilities cannot file a petition with the PUC before January 1, 2013 requesting permission to establish the charge.
Storm Recovery
PPL Electric experienced several PUC-reportable storms during 2011 resulting in total restoration costs of $84 million, of which $54 million were recorded in "Other operation and maintenance" on the Statement of Income. Although PPL Electric has storm insurance with a PPL affiliate, the costs associated with the unusually high number of PUC-reportable storms has exceeded policy limits. Probable insurance recoveries recorded during 2011 were $26.5 million, of which $16 million were included in "Other operation and maintenance" on the Statement of Income. In December 2011, PPL Electric received orders from the PUC granting permission to defer qualifying storm costs in excess of insurance recoveries associated with Hurricane Irene and a late October snowstorm. Based on the PUC orders, PPL Electric recorded a regulatory asset of $25 million in December 2011. PPL Electric will seek recovery of these costs in its next general base rate proceeding.
In 2007, based on PUC approval, a regulatory asset of $12 million was established for actual costs incurred associated with severe ice storms that occurred in January 2005. Recovery began in January 2008 and will continue through August 2015.
Federal Matters
FERC Formula Rates (PPL and PPL Electric)
Transmission rates are regulated by the FERC. PPL Electric's transmission revenues are billed in accordance with a FERC-approved PJM open access transmission tariff that utilizes a formula-based rate recovery mechanism. The tariff allows for recovery of actual transmission costs incurred, a return on transmission plant placed in service and an incentive return, including a return on construction work in progress, on the Susquehanna-Roseland transmission line project. The tariff utilizes actual costs from the most recent FERC Form No. 1 to set the rate for the current year billing to customers, including a true-up to adjust for actual costs in the subsequent year's FERC Form No. 1. The annual update of the rate is implemented automatically without requiring specific approval by the FERC before going into effect. PPL Electric accrues or defers revenues applicable to any estimated true-up of this formula-based rate.
In May 2010, PPL Electric initiated the 2010 Annual Update of its formula rate. In November 2010, a group of municipal customers taking transmission service in PPL Electric's transmission zone filed a preliminary challenge to the update and, in December 2010, filed a formal challenge. In August 2011, the FERC issued an order substantially rejecting the formal
challenge and accepting PPL Electric's 2010 Annual Update. The group of municipal customers filed a request for rehearing of that order.
In June 2011, PPL Electric initiated the 2011 Annual Update of its formula rate. In October 2011, the group of municipal customers filed a preliminary challenge to the update. PPL Electric was not able to resolve the issues that were raised in this preliminary challenge and the group of municipal customers filed a formal challenge. PPL Electric filed a response to that formal challenge and the group of municipal customers filed an answer to that response. PPL Electric cannot predict the outcome of these two proceedings, which remain pending before the FERC.
In March 2012, PPL Electric plans to file a request with the FERC seeking recovery, over a 34-year period beginning in June 2012, of its unrecovered regulatory asset related to the deferred state tax liability that existed at the time of the transition from the flow-through treatment of state income taxes to full normalization. This change in tax treatment occurred in 2008 as a result of prior FERC initiatives that transferred regulatory jurisdiction of certain transmission assets from the PUC to FERC. A regulatory asset of $51 million related to this transition, classified as taxes recoverable through future rates, is included in "Other Noncurrent Assets - Regulatory assets" on the balance sheet. PPL Electric believes recoverability of this regulatory asset is probable based on FERC precedent in similar cases; however, it is reasonably possible that the FERC may limit the recovery of all or part of the claimed asset.
International Activities (PPL)
U.K. Overhead Electricity Networks
In 2002, for safety reasons, the U.K. Government issued guidance that low voltage overhead electricity networks within three meters horizontal clearance of a building should either be insulated or relocated. This imposed a retroactive requirement on existing assets that were built with lower clearances. In 2008, the U.K. Government determined that the U.K. electricity network should comply with the issued guidance. WPD estimates that the cost of compliance will be approximately $120 million. The projected expenditures in the current regulatory period, April 1, 2010 through March 31, 2015, have been included in allowed revenues, and it is expected that expenditures beyond this five-year period (including WPD Midlands expenditures) will also be included in allowed revenues. The U.K. Government has determined that WPD (South Wales) and WPD Midlands should comply by 2015 and WPD (South West) should comply by 2018.
To improve network reliability, the U.K. Government amended a regulation relating to safety and continuity of supply by adding an obligation which broadly requires, beginning January 31, 2009, network operators to implement a risk-based program to clear trees away from overhead lines. WPD estimates that the cost of compliance will be approximately $198 million over a 25-year period. The projected expenditures in the current regulatory period have been included in allowed revenues under the current price control review, and it is expected that expenditures beyond this five-year period will also be included in allowed revenues.
In addition to the above, WPD Midlands was not in compliance with earlier regulations pertaining to overhead line clearances as of the acquisition date. WPD Midlands expects to incur costs through 2015 to comply with these requirements that are not included in allowed revenues under the current price control review. In 2011, WPD Midlands recorded a liability of $68 million associated with meeting these requirements as an opening balance sheet adjustment in accordance with accounting guidance for business combinations. The balance at December 31, 2011 was $57 million.
Ofgem Review of Line Loss Calculation
WPD has a $170 million liability recorded at December 31, 2011, calculated in accordance with an accepted methodology, related to the close-out of line losses for the prior price control period, DPCR4. Ofgem is currently consulting on the methodology used to calculate the final line loss incentive/penalty for the DPCR4. In October 2011, Ofgem issued a consultation paper citing two potential changes to the methodology, both of which would result in a reduction of the liability; however, it is uncertain at this time whether any changes will be made. Ofgem is expected to make a decision before the end of 2012.
New U.K. Pricing Model
The electricity distribution subsidiaries of WPD operate under distribution licenses and price controls granted and set by Ofgem for each of the distribution subsidiaries. The price control formula that governs allowed revenue is designed to provide economic incentives to minimize operating, capital and financing costs. The price control formula is normally determined every five years. Ofgem completed its review in December 2009 that became effective April 1, 2010 and will continue through March 31, 2015.
In October 2010, Ofgem announced a pricing model that will be effective for the U.K. electricity distribution sector beginning April 2015. The model, known as RIIO (Revenues = Incentives + Innovation + Outputs), is intended to encourage investment in regulated infrastructure. Key components of the model are: an extension of the price review period from five to eight years, increased emphasis on outputs and incentives, enhanced stakeholder engagement including network customers, a stronger incentive framework to encourage more efficient investment and innovation, expansion of the current Low Carbon Network Fund to stimulate innovation and continued use of a single weighted average cost of capital. At this time, management does not expect the impact of this pricing model to be significant to WPD's operating results.
7. Financing Activities
Credit Arrangements and Short-term Debt
(PPL, PPL Energy Supply, PPL Electric, LKE, LG&E and KU)
Credit facilities are maintained to enhance liquidity and provide credit support, and as a backstop to commercial paper programs, when necessary. The following credit facilities were in place at:
(a)
Amounts borrowed are recorded as "Short-term debt" on the Balance Sheets.
(b)
Under this facility, PPL WW has the ability to make cash borrowings but cannot request the lenders to issue letters of credit. PPL WW pays customary commitment fees under this facility, and borrowings bear interest at LIBOR-based rates plus a spread, depending on the company's long-term credit rating. The cash borrowing outstanding at December 31, 2011 was a USD-denominated borrowing of $178 million, which equated to £111 million at the time of borrowing and bears interest at approximately 1.05%. The interest rates at December 31, 2010 were approximately 0.94% on a USD-denominated borrowing of $181 million, which equated to £115 million at the time of borrowing.
This credit facility contains financial covenants that require PPL WW to maintain an interest coverage ratio of not less than 3.0 times consolidated earnings before income taxes, depreciation and amortization and a RAV that exceeds total net debt by the higher of an amount equal to 15% of total net debt or £150 million, in each case as calculated in accordance with the credit facility.
(c)
Under this facility, WPD (South West) has the ability to make cash borrowings but cannot request the lenders to issue letters of credit. WPD (South West) pays customary commitment fees under this facility, and borrowings bear interest at LIBOR-based rates plus a margin.
The facility contains financial covenants that require WPD (South West) to maintain an interest coverage ratio of not less than 3.0 times consolidated earnings before income taxes, depreciation and amortization and total net debt not in excess of 85% of its RAV, in each case calculated in accordance with the credit facility.
In January 2012, WPD (South West) entered into a new £245 million syndicated credit facility to replace its existing £210 million syndicated credit facility. Under the new facility, WPD (South West) has the ability to make cash borrowings but cannot request the lenders to issue letters of credit. WPD (South West) pays customary commitment fees under this facility, and borrowings bear interest at LIBOR-based rates plus a margin. The facility contains financial covenants that require WPD (South West) to maintain an interest coverage ratio of not less than 3.0 times consolidated earnings before income taxes, depreciation and amortization and total net debt not in excess of 85% of its RAV, in each case calculated in accordance with the credit facility.
(d)
In April 2011, following the completion of the acquisition of WPD Midlands, WPD (East Midlands) and WPD (West Midlands) each entered into a £300 million 5-year syndicated credit facility. Under the facilities, WPD (East Midlands) and WPD (West Midlands) each have the ability to make cash borrowings and to request the lenders to issue up to £80 million of letters of credit in lieu of borrowing. Each company pays customary commitment and utilization fees under its respective facility and borrowings generally bear interest at LIBOR-based rates plus a spread, depending upon the respective company's senior unsecured long-term debt rating. Each credit facility contains financial covenants that require the respective company to maintain an interest coverage ratio of not less than 3.0 times consolidated earnings before interest, income taxes, depreciation and amortization and total net debt not in excess of 85% of its RAV, in each case calculated in accordance with the credit facilities. An aggregate of $7 million in fees were incurred in connection with establishing these facilities.
(e)
The total amount borrowed under WPD's credit facilities equated to $178 million and approximately $181 million at December 31, 2011 and 2010. At December 31, 2011, the unused capacity of WPD's credit facilities was approximately $1.2 billion.
As a result of PPL Energy Supply's January 2011 distribution of its membership interest in PPL Global to its parent, PPL Energy Funding, the assets and liabilities of PPL Global, including the total amount borrowed under WPD's credit facilities at December 31, 2010 were removed from PPL Energy Supply's balance sheet in 2011. See Note 9 for additional information.
(f)
All credit facilities at PPL Energy Supply, PPL Electric, LG&E and KU also apply to PPL on a consolidated basis for financial reporting purposes.
(g)
Under this facility, PPL Energy Supply has the ability to make cash borrowings and to request the lenders to issue letters of credit. Borrowings generally bear interest at LIBOR-based rates plus a spread, depending upon the company's senior unsecured long-term debt rating. PPL Energy Supply also pays customary commitment and letter of credit issuance fees under this facility. The credit facility contains a financial covenant requiring PPL Energy Supply's debt to total capitalization not to exceed 65%, as calculated in accordance with the facility, and other customary covenants. Additionally, subject to certain conditions, PPL Energy Supply may request that the facility's capacity be increased by up to $500 million.
In October 2010, PPL Energy Supply borrowed $3.2 billion under this facility in order to enable a subsidiary to make loans to certain affiliates to provide interim financing of amounts required by PPL to partially fund PPL's acquisition of LKE. Such borrowing bore interest at 2.26% and was refinanced primarily through the issuance of long-term debt by LKE, LG&E, and KU and the use of internal funds. This borrowing and related payments were included in "Net increase (decrease) in short-term debt" on the Statement of Cash Flows.
PPL Energy Supply incurred an aggregate of $41 million of fees in 2010 in connection with establishing this facility. Such fees were initially deferred and amortized through December 2014. In connection with the reduction in the capacity from $4 billion to $3 billion in December 2010, PPL Energy Supply wrote off $10 million, $6 million after tax, of deferred fees, which was reflected in "Interest Expense" in the Statement of Income.
The borrowings outstanding at December 31, 2010 bore interest at a weighted-average rate of 2.27%.
(h)
In October 2011, PPL Energy Supply, PPL Electric, LG&E and KU each amended its respective credit facility. The amendments include extending the expiration dates from December 2014 to October 2016. Under these credit facilities, PPL Energy Supply, PPL Electric, LG&E and KU each continue to have the ability to make cash borrowings and request the lenders to issue letters of credit.
(i)
In March 2011, PPL Energy Supply's $300 million Structured Credit Facility expired. PPL Energy Supply's obligations under this facility were supported by a $300 million letter of credit issued on PPL Energy Supply's behalf under a separate but related $300 million 5-year credit agreement, which also expired in March 2011.
(j)
Under this facility, PPL Electric has the ability to make cash borrowings and to request the lenders to issue letters of credit. Borrowings generally bear interest at LIBOR-based rates plus a spread, depending upon the company's senior secured long-term debt rating. The credit facility contains a financial covenant requiring PPL Electric's debt to total capitalization not to exceed 70%, as calculated in accordance with the credit facility, and other customary covenants. PPL Electric also pays customary commitment and letter of credit issuance fees under this facility. Additionally, subject to certain conditions, PPL Electric may request that the facility's capacity be increased by up to $100 million. An aggregate of $2 million of fees were incurred in 2010 in connection with establishing this facility. Such fees were initially deferred and amortized through December 2014.
(k)
PPL Electric participates in an asset-backed commercial paper program through which PPL Electric obtains financing by selling and contributing its eligible accounts receivable and unbilled revenue to a special purpose, wholly owned subsidiary on an ongoing basis. The subsidiary has pledged these assets to secure loans from a commercial paper conduit sponsored by a financial institution.
At December 31, 2011 and December 31, 2010, $251 million and $248 million of accounts receivable and $98 million and $133 million of unbilled revenue were pledged by the subsidiary under the credit agreement related to PPL Electric's and the subsidiary's participation in the asset-backed commercial paper program. Based on the accounts receivable and unbilled revenue pledged at December 31, 2011, the amount available for borrowing under the facility was limited to $103 million. PPL Electric's sale to its subsidiary of the accounts receivable and unbilled revenue is an absolute sale of assets, and PPL Electric does not retain an interest in these assets. However, for financial reporting purposes, the subsidiary's financial results are consolidated in PPL Electric's financial statements. PPL Electric performs certain record-keeping and cash collection functions with respect to the assets in return for a servicing fee from the subsidiary.
In July 2011, PPL Electric and the subsidiary extended the expiration date of the credit agreement to July 2012.
(l)
All credit facilities at LG&E and KU also apply to LKE on a consolidated basis for financial reporting purposes.
(m)
In June 2011, these facilities were amended such that the fees and the spreads to benchmark interest rates for borrowings depend upon the respective company's senior secured long-term debt rating rather than the senior unsecured long-term debt rating. The facilities each contain a financial covenant requiring LG&E's and KU's debt to total capitalization not to exceed 70%, as calculated in accordance with the facilities, and other customary covenants. Additionally, subject to certain conditions, LG&E and KU may request that each respective facility's capacity be increased by up to $100 million.
(n)
The borrowing outstanding at December 31, 2010 bore interest at 2.27%. Such borrowing was repaid in January 2011 with proceeds received from the remarketing of certain tax-exempt bonds that were held by LG&E at December 31, 2010.
(o)
In April 2011, KU entered into a letter of credit facility that has been used to issue letters of credit to support outstanding tax-exempt bonds. The facility contains a financial covenant requiring KU's debt to total capitalization not to exceed 70%, as calculated in accordance with the credit facility. KU pays customary commitment and letter of credit fees under the new facility. In August 2011, KU amended its letter of credit facility such that the fees depend upon KU's senior secured long-term debt rating rather than its senior unsecured long-term debt rating.
(PPL and PPL Energy Supply)
PPL Energy Supply maintains a $500 million Facility Agreement expiring June 2017, whereby PPL Energy Supply has the ability to request up to $500 million of committed letter of credit capacity at fees to be agreed upon at the time of each request, based on certain market conditions. At December 31, 2011, PPL Energy Supply has not requested any capacity for the issuance of letters of credit under this arrangement.
PPL Energy Supply, PPL EnergyPlus, PPL Montour and PPL Brunner Island maintain an $800 million secured energy marketing and trading facility, whereby PPL EnergyPlus will receive credit to be applied to satisfy collateral posting obligations related to its energy marketing and trading activities with counterparties participating in the facility. The credit amount is guaranteed by PPL Energy Supply, PPL Montour and PPL Brunner Island. PPL Montour and PPL Brunner Island have granted liens on their respective generating facilities to secure any amount they may owe under their guarantees, which had an aggregate carrying value of $2.7 billion at December 31, 2011. The facility expires in November 2015, but is subject to automatic one-year renewals under certain conditions. There were no secured obligations outstanding under this facility at December 31, 2011.
In October 2011, PPL Energy Supply re-activated its $500 million commercial paper program to provide an additional financing source to fund its short-term liquidity needs, if and when necessary. Commercial paper issuances are supported by PPL Energy Supply's Syndicated Credit Facility. At December 31, 2011, PPL Energy Supply had $400 million of commercial paper outstanding, included in "Short-term debt" on the Balance Sheet, at a weighted-average interest rate of approximately 0.53%, which was used to partially fund the repayment of PPL Energy Supply's 6.40% Senior Notes upon maturity discussed below.
(PPL and PPL Electric)
PPL Electric maintains a commercial paper program for up to $200 million to provide an additional financing source to fund its short-term liquidity needs, if and when necessary. Commercial paper issuances are supported by PPL Electric's Syndicated Credit Facility. PPL Electric had no commercial paper outstanding at December 31, 2011.
(PPL, LKE, LG&E and KU)
In February 2012, LG&E and KU each established a commercial paper program for up to $250 million to provide an additional financing source to fund their short-term liquidity needs. Commercial paper issuances will be supported by LG&E and KU's Syndicated Credit Facilities.
(PPL Energy Supply, PPL Electric, LKE, LG&E and KU)
See Note 16 for discussion of intercompany borrowings.
2011 Bridge Facility (PPL)
In March 2011, concurrently and in connection with entering into the agreement to acquire WPD Midlands, PPL Capital Funding and PPL WEM, as borrowers, and PPL, as guarantor, entered into a 364-day unsecured £3.6 billion bridge facility to (i) fund the acquisition and (ii) pay certain fees and expenses in connection with the acquisition. During 2011, PPL incurred $44 million of fees in connection with establishing the 2011 Bridge Facility, which is reflected in "Interest Expense" on the Statement of Income. On April 1, 2011, concurrent with the closing of the WPD Midlands acquisition, PPL Capital Funding borrowed an aggregate of £1.75 billion and PPL WEM borrowed £1.85 billion under the 2011 Bridge Facility. Borrowings bore interest at approximately 2.62%, determined by one-month LIBOR rates plus a spread, based on PPL Capital Funding's
senior unsecured debt rating and the length of time from the date of the acquisition closing that borrowings were outstanding. See Note 10 for additional information on the acquisition.
In accordance with the terms of the 2011 Bridge Facility, PPL Capital Funding's borrowings of £1.75 billion were repaid with approximately $2.8 billion of proceeds received from PPL's issuance of common stock and 2011 Equity Units in April 2011, as discussed in "Long-term Debt" below. In April 2011, PPL WEM repaid £650 million of its 2011 Bridge Facility borrowing. Such repayment was funded primarily with proceeds received from PPL WEM's issuance of senior notes, which is also discussed below. In May 2011, PPL WEM repaid the remaining £1.2 billion of borrowings then-outstanding under the 2011 Bridge Facility, primarily with the proceeds from senior notes issued by WPD (East Midlands) and WPD (West Midlands), as described below.
In anticipation of the repayment of a portion of the borrowings under the 2011 Bridge Facility with U.S. dollar proceeds received from PPL's issuance of common stock and 2011 Equity Units and PPL WEM's issuance of U.S. dollar-denominated senior notes, PPL entered into forward contracts to purchase GBP in order to economically hedge the foreign currency exchange rate risk related to the repayment. See Note 19 for additional information.
Long-term Debt (PPL, PPL Energy Supply, PPL Electric, LKE, LG&E and KU)
(a)
Aggregate maturities of long-term debt are:
PPL - 2012, $0; 2013, $737; 2014, $310; 2015, $1,300; 2016, $810; and $14,825 thereafter.
PPL Energy Supply - 2012, $0; 2013, $737; 2014, $300; 2015, $300; 2016, $350; and $1,336 thereafter.
PPL Electric - 2012, $0; 2013, $0; 2014, $10; 2015, $100; 2016, $0; and $1,614 thereafter.
LKE - 2012, $0; 2013, $0; 2014, $0; 2015, $900; 2016, $0; and $3,185 thereafter.
LG&E - 2012, $0; 2013, $0; 2014, $0; 2015, $250; 2016, $0; and $859 thereafter.
KU - 2012, $0; 2013, $0; 2014, $0; 2015, $250; 2016, $0; and $1,601 thereafter.
None of the debt securities outstanding have sinking fund requirements.
(b)
At December 31, 2011:
PPL - interest rates range from 2.125% to 6.85%, and maturities range from 2013 to 2047.
PPL Energy Supply - interest rates range from 4.60% to 6.50%, and maturities range from 2013 to 2036.
LKE - interest rates range from 2.125% to 4.375%, and maturities range from 2015 to 2021.
At December 31, 2010:
PPL - interest rates range from 2.125% to 7.00%, and maturities range from 2011 to 2047.
PPL Energy Supply - interest rates range from 5.40% to 7.00%, and maturities range from 2011 to 2046.
LKE - interest rates range from 2.125% to 3.75%, and maturities range from 2015 to 2020.
(c)
Includes $99 million of notes that may be redeemed at par beginning in July 2012.
(d)
Includes $300 million of 5.70% REset Put Securities due 2035 (REPSSM). The REPS bear interest at a rate of 5.70% per annum to, but excluding, October 15, 2015 (Remarketing Date). The REPS are required to be put by existing holders on the Remarketing Date either for (a) purchase and remarketing by a designated remarketing dealer or (b) repurchase by PPL Energy Supply. Therefore, the REPS are reflected as a 2015 maturity for PPL and PPL Energy Supply in (a) above. If the remarketing dealer elects to purchase the REPS for remarketing, it will purchase the REPS at 100% of the principal amount, and the REPS will bear interest on and after the Remarketing Date at a new fixed rate per annum determined in the remarketing. PPL Energy Supply has the right to terminate the remarketing process. If the remarketing is terminated at the option of PPL Energy Supply or under certain other circumstances, including the occurrence of an event of default by PPL Energy Supply under the related indenture or a failed remarketing for certain specified reasons, PPL Energy Supply will be required to pay the remarketing dealer a settlement amount as calculated in accordance with the related remarketing agreement.
In July 2011, PPL Energy Supply redeemed at par the entire $250 million aggregate principal amount of its 7.00% Senior Notes due 2046. PPL Energy Supply recorded a loss of $7 million, which is reflected in "Interest Expense" on the Statements of Income for 2011, as a result of accelerating the amortization of deferred financing fees in connection with the redemption.
In November 2011, PPL Energy Supply repaid the entire $500 million principal amount of its 6.40% Senior Notes upon maturity.
In December 2011, PPL Energy Supply issued $500 million of 4.60% Senior Notes due 2021. The bonds may be redeemed at PPL Energy Supply's option at make-whole redemption prices until the date three months prior to maturity and at par thereafter. PPL Energy Supply received proceeds of $497 million, net of discounts and underwriting fees. The net proceeds were used to repay a portion of short-term debt incurred to repay at maturity PPL Energy Supply's $500 million aggregate principal amount of 6.40% Senior Notes due November 1, 2011. The balance of the net proceeds will be used for general corporate purposes.
(e)
Includes $875 million of Senior Notes issued by LKE in 2010 in private offerings to qualified institutional buyers and other transactions not subject to registration requirements under the Securities Act of 1933. In April 2011, LKE filed 2011 Registration Statements with the SEC related to offers to exchange securities issued in November 2010 in transactions not registered under the Securities Act of 1933 with similar but registered securities. The 2011 Registration Statements became effective in June 2011 and the exchanges were completed in July 2011, with substantially all securities being exchanged.
In September 2011, LKE issued $250 million of 4.375% Senior Notes due 2021. The notes were issued in a private offering to qualified institutional buyers and other transactions not subject to registration requirements under the Securities Act of 1933. In connection with the issuance, LKE entered into a registration rights agreement with representatives of the initial purchasers of the notes, pursuant to which LKE agreed to file, by late April
2012, a registration statement to exchange such notes for securities containing substantially identical terms (except for certain transfer restrictions), or in certain cases to file, by late April 2012, a registration statement covering resale of the notes. LKE also agreed, under its registration rights agreement, to (i) use its commercially reasonable efforts to cause the registration statement to be declared effective under the Securities Act by late July 2012 and (ii) upon effectiveness of the registration statement, take certain actions to promptly exchange the notes or, in the case of a registration statement covering resale of the notes, keep the registration statement effective until no later than late September 2012. Pursuant to the registration rights agreement, LKE may be required to pay liquidated damages if it does not meet certain requirements under its registration rights agreement. Liquidated damages will generally accrue with respect to the principal amount of the notes at a rate of 0.25% per annum for the first 90 days from and including the date on which a default specified under the registration rights agreement occurs, and increase by an additional 0.25% per annum thereafter, provided that the liquidated damages rate shall not at any time exceed 0.50% per annum.
Liquidated damages will cease to accrue when all registration defaults under the registration rights agreement have been cured, or if earlier, upon the redemption by the issuer or maturity of the notes.
The notes may be redeemed at LKE's option at make-whole redemption prices until the date three months prior to maturity and at par thereafter. LKE received proceeds of $248 million, net of discounts and underwriting fees. The net proceeds have been used to make a return of capital to PPL.
(f)
2011 includes $480 million of Junior Subordinated Notes that bear interest at 6.70% into March 2017, at which time the notes will bear interest at three-month LIBOR plus 2.665%, reset quarterly, until maturity. Interest payments may be deferred, from time to time, on one or more occasions for up to ten consecutive years. The notes may be redeemed at par beginning in March 2017.
2011 also includes $978 million of 4.32% Junior Subordinated Notes due 2019 that were issued in connection with PPL's issuance of the 2011 Equity Units in April 2011 and $1.15 billion of 4.625% Junior Subordinated Notes due 2018 that were issued in connection with PPL's issuance of the 2010 Equity Units in June 2010. See discussion of the Equity Units below for further information on such notes.
2010 includes $480 million of Junior Subordinated Notes that bear interest at 6.70% into March 2017, at which time the notes will bear interest at three-month LIBOR plus 2.665%, reset quarterly, until maturity. Interest payments may be deferred, from time to time, on one or more occasions for up to ten consecutive years. The notes may be redeemed at par beginning in March 2017.
2010 also includes $1.15 billion of 4.625% Junior Subordinated Notes due 2018 that were issued in connection with PPL's issuance of the 2010 Equity Units in June 2010.
(g)
Represents lease financing consolidated through a VIE. See Note 22 for additional information.
(h)
The 1945 First Mortgage Bonds were issued under, and secured by, the lien of the 1945 First Mortgage Bond Indenture. In December 2008, PPL Electric completed an in-substance defeasance of the 1945 First Mortgage Bonds by depositing sufficient funds with the trustee solely to satisfy the principal and remaining interest obligations on the bonds when due. The amount of funds on deposit with the trustee was $12 million at December 31, 2011 and $13 million at December 31, 2010, and is recorded as restricted cash, primarily in "Other noncurrent assets" on the Balance Sheets.
Also in December 2008, PPL Electric discharged the lien under the 1945 First Mortgage Bond Indenture, which covered substantially all electric distribution plant and certain transmission plant owned by PPL Electric.
(i)
At December 31, 2011:
PPL - interest rates range from 1.625% to 6.45%, and maturities range from 2015 to 2041.
PPL Electric - interest rates range from 3.00% to 6.45%, and maturities range from 2015 to 2041.
LG&E - interest rates range from 1.625% to 5.125%, and maturities range from 2015 to 2040.
KU - interest rates range from 1.625% to 5.125%, and maturities range from 2015 to 2040.
At December 31, 2010:
PPL - interest rates range from 1.625% to 7.125%, and maturities range from 2013 to 2040.
PPL Electric - interest rates range from 4.95% to 7.125%, and maturities range from 2013 to 2039.
LG&E - interest rates range from 1.625% to 5.125%, and maturities range from 2015 to 2040.
KU - interest rates range from 1.625% to 5.125%, and maturities range from 2015 to 2040.
In July 2011, PPL Electric issued $250 million of 5.20% First Mortgage Bonds due 2041. The bonds may be redeemed at PPL Electric's option at make-whole redemption prices until the date six months prior to maturity and at par thereafter. PPL Electric received proceeds of $246 million, net of discounts and underwriting fees. The net proceeds have been or will be used for capital expenditures and other general corporate purposes.
Also in July 2011, PPL Electric redeemed the entire $400 million aggregate principal amount of its 7.125% Senior Secured Bonds due 2013 for $458 million, plus accrued interest. PPL Electric recorded a regulatory asset for the redemption premium and unamortized financing costs associated with this debt. See Note 6 for additional information.
In August 2011, PPL Electric issued $400 million of 3.00% First Mortgage Bonds due 2021. The bonds may be redeemed at PPL Electric's option at make-whole redemption prices until the date three months prior to maturity and at par thereafter. PPL Electric received proceeds of $394 million, net of discounts and underwriting fees. The net proceeds were used to repay $250 million of short-term debt and to replenish cash used to redeem the 7.125% Senior Secured Bonds due 2013 in July 2011, as discussed above.
The senior secured and first mortgage bonds issued by PPL Electric are secured by the lien of the PPL Electric 2001 Mortgage Indenture, which covers substantially all electric distribution plant and certain transmission plant owned by PPL Electric. The carrying value of PPL Electric's property, plant and equipment was approximately $3.9 billion and $3.6 billion at December 31, 2011 and 2010.
LG&E's first mortgage bonds are secured by the lien of the LG&E 2010 Mortgage Indenture, which creates a lien, subject to certain exceptions and exclusions, on substantially all of LG&E's real and tangible personal property located in Kentucky and used or to be used in connection with the generation, transmission and distribution of electricity and the storage and distribution of natural gas. The aggregate carrying value of the property subject to the lien was $2.6 billion and $2.5 billion at December 31, 2011 and December 31, 2010.
KU's first mortgage bonds are secured by the lien of the KU 2010 Mortgage Indenture, which creates a lien, subject to certain exceptions and exclusions, on substantially all of KU's real and tangible personal property located in Kentucky and used or to be used in connection with the generation, transmission and distribution of electricity. The aggregate carrying value of the property subject to the lien was $4.1 billion and $4.0 billion at December 31, 2011 and December 31, 2010.
The LG&E and KU first mortgage bonds were issued in 2010 in private offerings to qualified institutional buyers and other transactions not subject to registration requirements under the Securities Act of 1933. In April 2011, LG&E and KU each filed 2011 Registration Statements with the SEC related to offers to exchange the first mortgage bonds with similar but registered securities. The 2011 Registration Statements became effective in June 2011 and the exchanges were completed in July 2011, with substantially all securities being exchanged.
(j)
PPL Electric issued a series of its senior secured bonds to secure its obligations to make payments with respect to each series of Pollution Control Bonds that were issued by the LCIDA and the PEDFA on behalf of PPL Electric. These senior secured bonds were issued in the same principal amount, contain payment and redemption provisions that correspond to and bear the same interest rate as such Pollution Control Bonds. These senior secured bonds were issued under PPL Electric's 2001 Mortgage Indenture and are secured as noted in (i) above. $224 million of such bonds may be redeemed at par beginning in 2015. $90 million of such bonds may be redeemed, in whole or in part, at par beginning in October 2020 and are subject to mandatory redemption upon determination that the interest rate on the bonds would be included in the holders' gross income for federal tax purposes.
(k)
In October 2010, LG&E and KU each issued a series of first mortgage bonds to the respective trustees of tax-exempt revenue bonds to secure its respective obligations to make payments with respect to each series of bonds. The first mortgage bonds were issued in the same principal amount, contain payment and redemption provisions that correspond to and bear the same interest rate as such tax-exempt revenue bonds. These first mortgage bonds were issued under the LG&E 2010 Mortgage Indenture and the KU 2010 Mortgage Indenture and are secured as noted in (i) above. The related tax-exempt revenue bonds were issued by various governmental entities, principally counties in Kentucky, on behalf of LG&E and KU. The related revenue bond documents allow LG&E and KU to convert the interest rate mode on the bonds from time to time to a commercial paper rate, daily rate, weekly rate, term rate of at least one year or, in some cases, an auction rate or a LIBOR index rate.
At December 31, 2011, the aggregate tax-exempt revenue bonds issued on behalf of LG&E and KU that were in a term rate mode totaled $321 million, $294 million and $27 million for LKE, LG&E and KU. The weighted average rates on these bonds were 3.57%, 3.37% and 5.83% for LKE, LG&E and KU. At December 31, 2010, the amounts that were in a term rate mode totaled $183 million, $156 million and $27 million for LKE, LG&E and KU. The weighted average rates on these bonds were 5.31%, 5.22% and 5.83% for LKE, LG&E and KU.
At December 31, 2011, the aggregate tax-exempt revenue bonds issued on behalf of LG&E and KU that were in a variable rate mode totaled $604 million, $280 million and $324 million for LKE, LG&E and KU. The weighted average rates on these bonds were 0.23%, 0.33% and 0.15% for LKE, LG&E and KU. At December 31, 2010, the amounts that were in a variable rate mode totaled $742 million, $418 million and $324 million for LKE, LG&E and KU. The weighted average rates on these bonds were 0.45%, 0.55% and 0.38% for LKE, LG&E and KU.
Several series of the tax-exempt revenue bonds are insured by monoline bond insurers whose ratings were reduced due to exposures relating to insurance of sub-prime mortgages. Of the bonds outstanding, $231 million are in the form of insured auction rate securities, wherein interest rates are reset either weekly or every 35 days via an auction process. Beginning in late 2007, the interest rates on these insured bonds began to increase due to investor concerns about the creditworthiness of the bond insurers. During 2008, interest rates increased, and LG&E and KU experienced failed auctions when there were insufficient bids for the bonds. When a failed auction occurs, the interest rate is set pursuant to a formula stipulated in the indenture. As noted above, the instruments governing these auction rate bonds permit LG&E and KU to convert the bonds to other interest rate modes.
Certain variable rate tax-exempt revenue bonds totaling $348 million at December 31, 2011, are subject to tender for purchase by LG&E and KU at the option of the holder and to mandatory tender for purchase by LG&E and KU upon the occurrence of certain events. At December 31, 2010, LG&E held $163 million of such bonds, which were issued on its behalf by Louisville/Jefferson County, Kentucky and are reflected as "Short-term investments" on the Balance Sheet. In January 2011, the entire $163 million of bonds were remarketed to unaffiliated investors in a term rate mode, bearing interest at 1.90% into 2012. The proceeds from the remarketing were used to repay the borrowing under LG&E's syndicated credit facility, which is discussed above in "Credit Arrangements and Short-term Debt."
(l)
The interest rate mode on all three series of bonds was converted from a commercial paper rate to a term rate of 3.00% for five years, effective in September 2010.
(m)
At December 31, 2011:
PPL and PPL Energy Supply - 6.00% notes due 2020.
At December 31, 2010:
PPL - 6.00%- 7.471% notes due 2011-2020.
PPL Energy Supply - 6.00% notes due 2020.
LKE - 7.471% notes due 2011.
(n)
Includes £225 million ($354 million at December 31, 2011 and $350 million at December 31, 2010) of notes that may be redeemed, in total but not in part, on December 21, 2026, at the greater of the principal value or a value determined by reference to the gross redemption yield on a nominated U.K. Government bond.
Also includes £3.7 billion ($5.8 billion) at December 31, 2011 and £1.0 billion ($1.6 billion) at December 31, 2010 of notes that may be put by the holders back to the issuer for redemption if the long-term credit ratings assigned to the Notes by Moody's, S&P or Fitch are withdrawn by any of the rating agencies or reduced to a non-investment grade rating of Ba1 or BB+ in connection with a restructuring event. A restructuring event includes the loss of, or a material adverse change to, the distribution licenses under which WPD's network companies operate.
In connection with the closing of the acquisition of WPD Midlands in April 2011, PPL assumed, through consolidation, £250 million of Senior Notes due 2040 (2040 Notes) previously issued by WPD (East Midlands), and £250 million of Senior Notes due 2025 (2025 Notes) previously issued by WPD (West Midlands), equating to an aggregate principal amount of approximately $800 million at the time of closing. The interest rates on the notes are subject to adjustment into June 2012 in the event of a rating change on the notes. The 2040 Notes currently bear interest at 5.75% and the 2025 Notes currently bear interest at 6.00%.
The maximum rate of interest allowable under the adjustment provisions is 6.50% for the 2040 Notes and 6.25% for the 2025 Notes. The 2025 Notes and 2040 Notes may be put by the holders back to the respective issuer for redemption if the long-term credit ratings assigned to the notes by Moody's or S&P are withdrawn by either of the rating agencies or reduced to a non-investment grade rating of Ba1 or BB+ in connection with a restructuring event. A restructuring event includes the loss of, or material adverse change to, the distribution license under which WPD (West Midlands) and WPD (East Midlands) operate.
In April 2011, PPL WEM issued $460 million of 3.90% Senior Notes due 2016 (2016 Notes) and $500 million of 5.375% Senior Notes due 2021 (2021 Notes). The 2016 Notes may be redeemed any time prior to maturity at PPL WEM's option at make-whole redemption prices. The 2021 Notes may be redeemed at PPL WEM's option at make-whole redemption prices until the date three months prior to maturity and at par thereafter. PPL WEM received proceeds of $953 million, net of discounts and underwriting fees, from the combined issuance of the notes. The net proceeds were used to repay a portion of PPL WEM's borrowing under the 2011 Bridge Facility as discussed above. In connection with the issuance of the senior notes, PPL WEM, through PPL, entered into cross currency interest rate swaps for the entire aggregate principal amount of each series of notes in order to hedge PPL WEM's risk of variability in the GBP functional currency equivalent cash flows related to its U.S. dollar interest and principal payments on the notes.
In May 2011, WPD (West Midlands) issued £800 million of 5.75% Senior Notes due 2032 (2032 Notes) and WPD (East Midlands) issued £600 million of 5.25% Senior Notes due 2023 (2023 Notes). WPD (West Midlands) and WPD (East Midlands) collectively received proceeds of £1.4 billion, which equated to $2.2 billion at the time of issuance, net of discounts and underwriting fees, from the combined debt issuances. A portion of the net proceeds were dividended to PPL WEM and used to repay the remaining balance of PPL WEM's borrowing under the 2011 Bridge Facility in May 2011 as discussed above. The balance of the net proceeds have been or will be used to pre-fund certain capital expenditures and for other general corporate purposes.
The 2032 Notes and the 2023 Notes may be put by the holders back to the respective issuer for redemption if the long-term credit ratings assigned to the notes by Moody's or S&P are withdrawn by either of the rating agencies or reduced to a non-investment grade rating of Ba1 or BB+ in connection with a restructuring event. A restructuring event includes the loss of, or material adverse change to, the distribution license under which WPD (West Midlands) and WPD (East Midlands) operate.
The change from 2010 to 2011 includes an increase of $16 million resulting from movements in foreign currency exchange rates related to the amounts that were outstanding at both December 31, 2010 and December 31, 2011.
(o)
The principal amount of the notes issued by WPD (South West) is adjusted on a semi-annual basis based on changes in a specified index, as detailed in the terms of the related indentures. The adjustment to the principal amount from 2010 to 2011 was an increase of approximately £14 million ($22 million) resulting from inflation and a $4 million increase resulting from movements in foreign currency exchange rates.
These notes may be redeemed, in total by series, on December 1, 2026, at the greater of the adjusted principal value and a make-whole value determined by reference to the gross real yield on a nominated U.K. government bond. Additionally, these notes may be put by the holders back to the issuer for redemption if the long-term credit ratings assigned to the notes by Moody's, S&P or Fitch are withdrawn by any of the rating agencies or reduced to a non-investment grade rating of Ba1 or BB+ in connection with a restructuring event. A restructuring event includes the loss of, or a material adverse change to, the distribution license under which the issuer operates.
In June 2011, WPD (East Midlands) issued £100 million of Index-Linked Notes due 2043 (2043 Notes). The principal amount of the 2043 Notes is adjusted based on changes in a specified index, as detailed in the terms of the notes. WPD (East Midlands) received proceeds of £99 million, which equated to $163 million at the time of issuance, net of discounts and underwriting fees, from the issuance of the 2043 Notes. The majority of the net proceeds were used to repay short-term debt. Since issuance, the principal amount on the 2043 Notes has increased by approximately £2 million ($4 million) as a result of inflation.
The 2043 Notes may be put by the holders back to WPD (East Midlands) for redemption if the long-term credit ratings assigned to the notes by Moody's or S&P are withdrawn by either of the rating agencies or reduced to a non-investment grade rating of Ba1 or BB+ in connection with a restructuring event. A restructuring event includes the loss of, or material adverse change to, the distribution license under which WPD (East Midlands) operates.
(p)
As a result of PPL Energy Supply's January 2011 distribution of its membership interest in PPL Global to its parent, PPL Energy Funding, assets and liabilities of PPL Global at December 31, 2010, including total long-term debt of $2.3 billion, were removed from PPL Energy Supply's Balance Sheet in 2011. See Note 9 for additional information.
(q)
Reflects adjustments made to record WPD's long-term debt at fair value at the time of acquisition of the controlling interest in WPD in 2002 and the acquisition of WPD Midlands in 2011.
(r)
Reflects adjustments made to record LG&E's and KU's long-term debt at fair value at the time of acquisition of LKE in 2010.
2011 Equity Units (PPL)
In April 2011, in connection with the acquisition of WPD Midlands, PPL issued 92 million shares of its common stock at a public offering price of $25.30 per share, for a total of $2.328 billion. Proceeds from the issuance were $2.258 billion, net of the $70 million underwriting discount. PPL also issued 19.55 million 2011 Equity Units at a stated amount per unit of $50.00 for a total of $978 million. Proceeds from the issuance were $948 million, net of the $30 million underwriting discount. PPL
used the net proceeds to repay PPL Capital Funding's borrowings under the 2011 Bridge Facility, as discussed above, to pay certain acquisition-related fees and expenses and for general corporate purposes.
Each 2011 Equity Unit consists of a 2011 Purchase Contract and, initially, a 5.0% undivided beneficial ownership interest in $1,000 principal amount of PPL Capital Funding 4.32% Junior Subordinated Notes due 2019 (2019 Notes).
Each 2011 Purchase Contract obligates the holder to purchase, and PPL to sell, for $50.00 a number of shares of PPL common stock to be determined by the average VWAP of PPL's common stock for the 20-trading day period ending on the third trading day prior to May 1, 2014, subject to antidilution adjustments and an early settlement upon a Fundamental Change as follows:
·
if the average VWAP equals or exceeds approximately $30.99, then 1.6133 shares (a minimum of 31,540,015 shares);
·
if the average VWAP is less than approximately $30.99 but greater than $25.30, a number of shares of common stock having a value, based on the average VWAP, equal to $50.00; and
·
if the average VWAP is less than or equal to $25.30, then 1.9763 shares (a maximum of 38,636,665 shares).
If holders elect to settle the 2011 Purchase Contract prior to May 1, 2014, they will receive 1.6133 shares of PPL common stock, subject to antidilution adjustments and an early settlement upon a Fundamental Change.
A holder's ownership interest in the 2019 Notes is pledged to PPL to secure the holder's obligation under the related 2011 Purchase Contract. If a holder of a 2011 Purchase Contract chooses at any time no longer to be a holder of the 2019 Notes, such holder's obligation under the 2011 Purchase Contract must be secured by a U.S. Treasury security.
Each 2011 Purchase Contract also requires PPL to make quarterly contract adjustment payments at a rate of 4.43% per year on the $50.00 stated amount of the 2011 Equity Unit. PPL has the option to defer these contract adjustment payments until the 2011 Purchase Contract settlement date. Deferred contract adjustment payments will accrue additional contract adjustment payments at the rate of 8.75% per year until paid. Until any deferred contract adjustment payments have been paid, PPL may not declare or pay any dividends or distributions on, or redeem, purchase or acquire or make a liquidation payment with respect to, any of its capital stock, subject to certain exceptions.
The 2019 Notes are fully and unconditionally guaranteed by PPL as to payment of principal and interest. The 2019 Notes initially bear interest at 4.32% and are not subject to redemption prior to May 2016. Beginning May 2016, PPL Capital Funding may, at its option, redeem the 2019 Notes, in whole but not in part, at any time, at par plus accrued and unpaid interest. The 2019 Notes are expected to be remarketed in 2014 into two tranches, such that neither tranche will have an aggregate principal amount of less than the lesser of $250 million and 50% of the aggregate principal amount of the 2019 Notes to be remarketed. One tranche will mature on or about the third anniversary of the settlement of the remarketing, and the other tranche will mature on or about the fifth anniversary of such settlement. Upon a successful remarketing, the interest rate on the 2019 Notes may be reset and the maturity of the tranches may be modified as necessary. In connection with a remarketing, PPL Capital Funding may elect with respect to each tranche, to extend or eliminate the early redemption date and/or calculate interest on the notes of a tranche on a fixed or floating rate basis. If the remarketing fails, holders of the 2019 Notes will have the right to put their notes to PPL Capital Funding on May 1, 2014 for an amount equal to the principal amount plus accrued interest.
Prior to May 2016, PPL Capital Funding may elect at one or more times to defer interest payments on the 2019 Notes for one or more consecutive interest periods until the earlier of the third anniversary of the interest payment due date and May 2016. Deferred interest payments will accrue additional interest at a rate equal to the interest rate then applicable to the 2019 Notes. Until any deferred interest payments have been paid, PPL may not, subject to certain exceptions, (i) declare or pay any dividends or distributions on, or redeem, purchase or acquire or make a liquidation payment with respect to, any of its capital stock, (ii) make any payment of principal of, or interest or premium, if any, on, or repay, purchase or redeem any of its debt securities that upon its liquidation ranks equal with, or junior in interest to, the subordinated guarantee of the 2019 Notes by PPL as of the date of issuance and (iii) make any payments regarding any guarantee by PPL of securities of any of its subsidiaries (other than PPL Capital Funding) if the guarantee ranks equal with, or junior in interest to, the 2019 Notes as of the date of their issuance.
In the financial statements, the proceeds from the sale of the 2011 Equity Units were allocated to the 2019 Notes and the 2011 Purchase Contracts, including the obligation to make contract adjustment payments, based on the underlying fair value of each instrument at the time of issuance. As a result, the 2019 Notes were recorded at $978 million, which approximated fair value, as long-term debt. At the time of issuance, the present value of the contract adjustment payments of $123 million was recorded to other liabilities representing the obligation to make contract adjustment payments, with an offsetting reduction to additional paid-in capital for the issuance of the 2011 Purchase Contracts, which approximated the fair value of each. The liability is being accreted through interest expense over the three-year term of the 2011 Purchase Contracts. The
initial valuation of the contract adjustment payments is considered a non-cash transaction that is excluded from the Statement of Cash Flows in 2011. Costs to issue the 2011 Equity Units were primarily allocated on a relative cost basis, resulting in $25 million being recorded to "Additional paid-in capital" and $6 million being recorded to "Other noncurrent assets" on the Balance Sheet. See Note 4 for EPS considerations related to the 2011 Purchase Contracts.
2010 Equity Units (PPL)
In June 2010, in connection with the acquisition of LKE, PPL issued 103.5 million shares of its common stock at a public offering price of $24.00 per share, for a total of $2.484 billion. Proceeds from the issuance were $2.409 billion, net of the $75 million underwriting discount. PPL also issued 23 million 2010 Equity Units at a stated amount per unit of $50.00 for a total of $1.150 billion. Proceeds from the issuance were $1.116 billion, net of the $34 million underwriting discount.
Each 2010 Equity Unit consists of a Purchase Contract and, initially, a 5.0% undivided beneficial ownership interest in $1,000 principal amount of PPL Capital Funding 4.625% Junior Subordinated Notes due 2018 (2018 Notes).
Each 2010 Purchase Contract obligates the holder to purchase, and PPL to sell, for $50.00 a variable number of shares of PPL common stock determined by the average VWAP of PPL's common stock for the 20-trading day period ending on the third trading day prior to July 1, 2013, subject to antidilution adjustments and an early settlement upon a Fundamental Change as follows:
·
if the average VWAP equals or exceeds $28.80, then 1.7361 shares (a minimum of 39,930,300 shares);
·
if the average VWAP is less than $28.80 but greater than $24.00, a number of shares of common stock having a value, based on the average VWAP, equal to $50.00; and
·
if the average VWAP is less than or equal to $24.00, then 2.0833 shares (a maximum of 47,915,900 shares).
If holders elect to settle the 2010 Purchase Contract prior to July 1, 2013, they will receive 1.7361 shares of PPL common stock, subject to antidilution adjustments and an early settlement upon a Fundamental Change.
A holder's ownership interest in the 2018 Notes is pledged to PPL to secure the holder's obligation under the related 2010 Purchase Contract. If a holder of a 2010 Purchase Contract chooses at any time to no longer be a holder of the 2018 Notes, such holder's obligation under the 2010 Purchase Contract must be secured by a U.S. Treasury security.
Each 2010 Purchase Contract also requires PPL to make quarterly contract adjustment payments at a rate of 4.875% per year on the $50.00 stated amount of the 2010 Equity Unit. PPL has the option to defer these contract adjustment payments until the 2010 Purchase Contract settlement date. Deferred contract adjustment payments will accrue additional contract adjustment payments at the rate of 9.5% per year until paid. Until any deferred contract adjustment payments have been paid, PPL may not declare or pay any dividends or distributions on, or redeem, purchase or acquire or make a liquidation payment with respect to, any of its capital stock, subject to certain exceptions.
The 2018 Notes are fully and unconditionally guaranteed by PPL as to payment of principal and interest. The 2018 Notes initially bear interest at 4.625% and are not subject to redemption prior to July 2015. Beginning July 2015, PPL Capital Funding may, at its option, redeem the 2018 Notes, in whole but not in part, at any time, at par plus accrued and unpaid interest. The 2018 Notes are expected to be remarketed in 2013 in two tranches, such that neither tranche will have an aggregate principal amount of less than the lesser of $300 million and 50% of the aggregate principal amount of the 2018 Notes to be remarketed. One tranche will mature on or about the third anniversary of the settlement of the remarketing, and the other tranche will mature on or about the fifth anniversary of such settlement. The 2018 Notes will be remarketed as subordinated, unsecured obligations of PPL Capital Funding, as PPL Capital Funding notified the trustee in September 2010 of its irrevocable election to maintain the subordination provisions of the notes and related guarantees in a remarketing. Upon a successful remarketing, the interest rate on the 2018 Notes may be reset and the maturity of the tranches may be modified as necessary. In connection with a remarketing, PPL Capital Funding may elect, with respect to each tranche, to extend or eliminate the early redemption date and/or calculate interest on the notes of a tranche on a fixed or floating rate basis. If the remarketing fails, holders of the 2018 Notes will have the right to put their notes to PPL Capital Funding on July 1, 2013 for an amount equal to the principal amount plus accrued interest.
Prior to July 2013, PPL Capital Funding may elect at one or more times to defer interest payments on the 2018 Notes for one or more consecutive interest periods until the earlier of the third anniversary of the interest payment due date and July 2015. Deferred interest payments will accrue additional interest at a rate equal to the interest rate then applicable to the 2018 Notes. Until any deferred interest payments have been paid, PPL may not, subject to certain exceptions, (i) declare or pay any dividends or distributions on, or redeem, purchase or acquire or make a liquidation payment with respect to, any of its capital stock, (ii) make any payment of principal of, or interest or premium, if any, on, or repay, purchase or redeem any of its debt securities that upon its liquidation ranks equal with, or junior in interest to, the subordinated guarantee of the 2018 Notes by
PPL as of the date of issuance and (iii) make any payments regarding any guarantee by PPL of securities of any of its subsidiaries (other than PPL Capital Funding) if the guarantee ranks equal with, or junior in interest to, the 2018 Notes as of the date of their issuance.
In the financial statements, the proceeds from the sale of the 2010 Equity Units were allocated to the 2018 Notes and the 2010 Purchase Contracts, including the obligation to make contract adjustment payments, based on the underlying fair value of each instrument at the time of issuance. As a result, the 2018 Notes were recorded at $1.150 billion, which approximated fair value, as long-term debt. At the time of issuance, the present value of the contract adjustment payments of $157 million was recorded to other liabilities, representing the obligation to make contract adjustment payments, with an offsetting reduction to additional paid-in capital value for the issuance of the 2010 Purchase Contracts, which approximated the fair value of each. The liability is being accreted through interest expense over the three-year term of the 2010 Purchase Contracts. The initial valuation of the contract adjustment payments is considered a non-cash transaction that was excluded from the Statement of Cash Flows in 2010. Costs to issue the 2010 Equity Units were primarily allocated on a relative cost basis, resulting in $29 million being recorded to "Additional paid-in capital" and $7 million being recorded to "Other noncurrent assets" on the Balance Sheet. See Note 4 for EPS considerations related to the 2010 Purchase Contracts.
Legal Separateness (PPL, PPL Energy Supply, PPL Electric and LKE)
In 2001, PPL Electric completed a strategic initiative to confirm its legal separation from PPL and PPL's other affiliated companies. This initiative was designed to enable PPL Electric to substantially reduce its exposure to volatility in energy prices and supply risks through 2009 and to reduce its business and financial risk profile by, among other things, limiting its business activities to the transmission and distribution of electricity and businesses related to or arising out of the electric transmission and distribution businesses. In connection with this initiative, PPL Electric:
·
obtained long-term electric supply contracts to meet its PLR obligations (with its affiliate PPL EnergyPlus) through 2009, as further described in Note 16 under "PLR Contracts/Purchase of Accounts Receivable" (also see Note 15 under "Energy Purchase Commitments" for information on current PLR supply procurement procedures);
·
agreed to limit its businesses to electric transmission and distribution and related activities;
·
adopted amendments to its Articles of Incorporation and Bylaws containing corporate governance and operating provisions designed to clarify and reinforce its legal and corporate separateness from PPL and its other affiliated companies; and
·
appointed an independent director to its Board of Directors and required the unanimous approval of the Board of Directors, including the consent of the independent director, to amendments to these corporate governance and operating provisions or to the commencement of any insolvency proceedings, including any filing of a voluntary petition in bankruptcy or other similar actions.
In addition, in connection with the issuance of certain series of bonds, PPL Electric entered into a compliance administration agreement with an independent compliance administrator to review, on a semi-annual basis, its compliance with the corporate governance and operating requirements contained in its Articles of Incorporation and Bylaws. Such series of bonds are no longer outstanding and the compliance administration agreement has terminated, but PPL Electric continues to comply with the corporate separateness provisions in its Articles of Incorporation and Bylaws.
The enhancements to PPL Electric's legal separation from its affiliates are intended to minimize the risk that a court would order PPL Electric's assets and liabilities to be substantively consolidated with those of PPL or another affiliate of PPL in the event that PPL or another PPL affiliate were to become a debtor in a bankruptcy case. Based on these various measures, PPL Electric was able to issue and maintain a higher level of debt and use it to replace higher cost equity, thereby maintaining a lower total cost of capital. Nevertheless, if PPL or another PPL affiliate were to become a debtor in a bankruptcy case, there can be no assurance that a court would not order PPL Electric's assets and liabilities to be consolidated with those of PPL or such other PPL affiliate.
The subsidiaries of PPL are separate legal entities. PPL's subsidiaries are not liable for the debts of PPL. Accordingly, creditors of PPL may not satisfy their debts from the assets of PPL's subsidiaries absent a specific contractual undertaking by a subsidiary to pay PPL's creditors or as required by applicable law or regulation. Similarly, absent a specific contractual undertaking or as required by applicable law or regulation, PPL is not liable for the debts of its subsidiaries, nor are its subsidiaries liable for the debts of one another. Accordingly, creditors of PPL's subsidiaries may not satisfy their debts from the assets of PPL or its other subsidiaries absent a specific contractual undertaking by PPL or its other subsidiaries to pay the creditors or as required by applicable law or regulation.
Similarly, the subsidiaries of PPL Energy Supply, PPL Electric and LKE are each separate legal entities. These subsidiaries are not liable for the debts of PPL Energy Supply, PPL Electric and LKE. Accordingly, creditors of PPL Energy Supply, PPL Electric and LKE may not satisfy their debts from the assets of their subsidiaries absent a specific contractual
undertaking by a subsidiary to pay the creditors or as required by applicable law or regulation. Similarly, absent a specific contractual undertaking or as required by applicable law or regulation, PPL Energy Supply, PPL Electric and LKE are not liable for the debts of their subsidiaries, nor are their subsidiaries liable for the debts of one another. Accordingly, creditors of these subsidiaries may not satisfy their debts from the assets of PPL Energy Supply, PPL Electric and LKE (or their other subsidiaries) absent a specific contractual undertaking by that parent or other subsidiary to pay such creditors or as required by applicable law or regulation.
Distributions, Capital Contributions and Related Restrictions
(PPL)
In November 2011, PPL declared its quarterly common stock dividend, payable January 3, 2012, at 35.0 cents per share (equivalent to $1.40 per annum). In February 2012, PPL declared its quarterly common stock dividend, payable April 2, 2012, at 36.0 cents per share (equivalent to $1.44 per annum). Future dividends, declared at the discretion of the Board of Directors, will be dependent upon future earnings, cash flows, financial and legal requirements and other factors.
Neither PPL Capital Funding nor PPL may declare or pay any cash dividend or distribution on its capital stock during any period in which PPL Capital Funding defers interest payments on its 2007 Series A Junior Subordinated Notes due 2067. Subject to certain exceptions, PPL may not declare or pay any dividend or distribution on its capital stock until any deferred interest payments on its 4.625% Junior Subordinated Notes due 2018 and its 4.32% Junior Subordinated Notes due 2019 have been paid and deferred contract adjustment payments on PPL's Purchase Contracts have been paid. At December 31, 2011, no payments were deferred on either series of junior subordinated notes or the Purchase Contracts.
(PPL, PPL Electric, LKE, LG&E and KU)
PPL relies on dividends or loans from its subsidiaries to fund PPL's dividends to its common shareholders. The net assets of certain PPL subsidiaries are subject to legal restrictions. LKE primarily relies on dividends from its subsidiaries to fund its dividends to PPL. LG&E, KU and PPL Electric are subject to Section 305(a) of the Federal Power Act, which makes it unlawful for a public utility to make or pay a dividend from any funds "properly included in capital account." The meaning of this limitation has never been clarified under the Federal Power Act. LG&E, KU and PPL Electric believe, however, that this statutory restriction, as applied to their circumstances, would not be construed or applied by the FERC to prohibit the payment from retained earnings of dividends that are not excessive and are for lawful and legitimate business purposes. Also, under Virginia law, KU is prohibited from making loans to affiliates without the prior approval of the VSCC. There are no comparable statutes under Kentucky law applicable to LG&E and KU, or under Pennsylvania law applicable to PPL Electric. However, Orders from the KPSC require LG&E or KU to obtain prior regulatory consent or approval before loaning funds to PPL. At December 31, 2011, the net restricted assets of LG&E and KU were approximately $4.4 billion.
(a)
In addition to the cash distributions paid, in January 2011, PPL Energy Supply distributed its membership interest in PPL Global to its parent company, PPL Energy Funding. See Note 9 for additional information.
(b) Includes $248 million return of capital made to PPL in September 2011 from proceeds of senior unsecured note issuance.
(PPL Energy Supply)
In January 2012, PPL Energy Supply distributed $200 million to its parent.
(PPL and PPL Energy Supply)
The PPL Montana Colstrip lease places certain restrictions on PPL Montana's ability to declare dividends. At this time, PPL believes that these covenants will not limit PPL's or PPL Energy Supply's ability to operate as desired and will not affect their ability to meet any of their cash obligations. WPD subsidiaries also have financing arrangements that limit their ability to pay dividends. However, PPL does not, at this time, expect that any of such limitations would significantly impact PPL's ability to meet its cash obligations.
(PPL and PPL Electric)
As discussed in Note 3, PPL Electric may not pay dividends on its common stock, except in certain circumstances, unless full dividends have been paid on the Preference Shares for the then-current dividend period. The quarterly dividend rate for PPL Electric's Preference Shares is $1.5625 per depositary share. PPL Electric has declared and paid dividends on its outstanding Preference Shares since issuance. Dividends on the Preference Shares are not cumulative and future dividends, declared at the discretion of PPL Electric's Board of Directors, will be dependent upon future earnings, cash flows, financial and legal requirements and other factors.
(LG&E and KU)
In February 2012, LG&E and KU filed an application with FERC seeking authorization to pay dividends in the future based on retained earnings balances, which would be calculated ignoring the impact of the accounting for the acquisition by PPL. If approved, as of December 31, 2011, this would increase the balance available for dividends from LG&E by $809 million and KU by $1.4 billion. LG&E and KU do not anticipate changing their dividend practices.
8. Acquisitions, Development and Divestitures
(PPL, PPL Energy Supply, PPL Electric, LKE, LG&E and KU)
The Registrants continuously evaluate opportunities for potential acquisitions, divestitures and development projects. Development projects are continuously reexamined based on market conditions and other factors to determine whether to proceed with the projects, sell, cancel or expand them, execute tolling agreements or pursue other options. Any resulting transactions may impact future financial results. See Note 9 for information on PPL Energy Supply's distribution of its membership interest in PPL Global to its parent, PPL Energy Funding, which was presented as discontinued operations by PPL Energy Supply, and the sales of businesses that were presented as discontinued operations by PPL, PPL Energy Supply and LKE. See Note 10 for information on PPL's acquisitions of WPD Midlands and LKE.
(PPL, LKE, LG&E and KU)
Acquisition
Pending Bluegrass CTs Acquisition
In September 2011, LG&E and KU entered into an Asset Purchase Agreement with Bluegrass Generation for the purchase of the Bluegrass CTs, aggregating approximately 495 MW, plus limited associated contractual arrangements required for operation of the units, for a purchase price of $110 million. Pursuant to the Asset Purchase Agreement, LG&E and KU will jointly acquire the Bluegrass CTs as tenants in common, with LG&E as owner of a 69% undivided interest, and KU as owner of a 31% undivided interest, in the purchased assets. The purchase is subject to receipt of approvals from the KPSC, the FERC, certain permit assignments or local approvals, and other conditions. Either party can terminate the Asset Purchase Agreement should the purchase transaction fail to occur by June 30, 2012.
Development
NGCC Construction
In September 2011, LG&E and KU requested KPSC approval to build a 640 MW NGCC at the existing Cane Run plant site in Kentucky. This project is also subject to certain regulatory approvals. Once all approvals are received, construction is expected to begin in 2012 and be complete by 2016. The project, which includes building a natural gas supply pipeline, has an expected cost of approximately $580 million. See Note 6 for additional information.
In conjunction with this request and to meet new, stricter federal EPA regulations, LG&E and KU anticipate retiring six older coal-fired electric generating units at the Cane Run, Green River and Tyrone plants, which have a combined summer rating of 797 MW. The Cane Run and Green River coal units will need to remain operational until the replacement generation and associated transmission projects are completed.
TC2
In January 2011, LKE began dispatching electricity from TC2 to meet customer demand. See Note 15 for additional information regarding the construction of TC2.
(PPL and PPL Energy Supply)
Hydroelectric Expansion Projects
In 2009, in light of the availability of tax incentives and potential federal loan guarantees for renewable projects contained in the Economic Stimulus Package, PPL Energy Supply filed an application with the FERC to expand capacity at its Holtwood hydroelectric plant, which the FERC approved. The project's expected cost is $438 million. Construction continues on the project, with commercial operations scheduled to begin in 2013. At December 31, 2011, expected remaining expenditures are $196 million.
In 2009, PPL Montana received FERC approval for its request to redevelop the Rainbow hydroelectric facility at Great Falls, Montana to increase capacity by 28 MW. The project's expected cost is $207 million. Construction continues on the project, with commercial operations scheduled to begin in 2012. At December 31, 2011, expected remaining expenditures are $29 million.
PPL Energy Supply believes that it is qualified for either investment tax credits or Treasury grants for the projects at the Holtwood and Rainbow facilities. PPL Energy Supply has recognized investment tax credits and continues to evaluate whether to seek Treasury grants in lieu of the credits. During 2010, PPL Energy Supply recorded deferred investment tax credits of $52 million related to 2010 and 2009. During 2011, PPL Energy Supply recorded deferred investment tax credits of $52 million related to 2011. PPL Energy Supply anticipates recognizing an additional $54 million in tax credits for tax years 2012 and 2013. These credits reduce PPL Energy Supply's tax liability and will be amortized over the life of the related assets.
Susquehanna Uprate Project
In 2008, PPL Susquehanna received NRC approval for its request to increase the generation capacity of the Susquehanna nuclear plant. The project was completed in phases over several years. The final phase of the project, a 50 MW Unit 2 uprate, was completed in 2011. PPL Susquehanna's share of the total capacity increase was approximately 195 MW.
Bell Bend COLA
In 2008, a PPL Energy Supply subsidiary, PPL Bell Bend, LLC (PPL Bell Bend) submitted a COLA to the NRC for the proposed Bell Bend nuclear generating unit (Bell Bend) to be built adjacent to the Susquehanna plant. Also in 2008, the COLA was formally docketed and accepted for review by the NRC. PPL Bell Bend continues to respond to questions from the NRC regarding technical and site specific information provided in the initial COLA and subsequent amendments. PPL Bell Bend does not expect to complete the COLA review process with the NRC prior to 2014.
In 2008, PPL Bell Bend submitted Parts I and II of an application for a federal loan guarantee for Bell Bend to the DOE. The DOE is expected in the first half of 2012 to finalize the first nuclear loan guarantee for a project in Georgia. Eight of the ten applicants that submitted Part II applications remain active in the DOE program; however, the DOE has stated that the $18.5 billion currently appropriated to support new nuclear projects would not likely be enough for more than three projects. PPL Bell Bend submits quarterly application updates for Bell Bend to the DOE to remain active in the loan guarantee application process.
PPL Bell Bend has made no decision to proceed with construction of Bell Bend and expects that such decision will not be made for several years given the anticipated lengthy NRC license approval process. Additionally, PPL Bell Bend has announced that it does not expect to proceed with construction absent favorable economics, a joint arrangement with other interested parties and a federal loan guarantee or other acceptable financing. PPL Bell Bend is currently authorized to spend up to $162 million through 2012 on the COLA and other permitting costs (including land costs) necessary for construction. At December 31, 2011 and 2010, $131 million and $109 million of costs associated with the licensing application were capitalized and are included on the Balance Sheets in noncurrent "Other intangibles." PPL Bell Bend believes it is probable that these costs are ultimately recoverable following NRC approval of the COLA either through construction of the new nuclear unit, transfer of the COLA rights to a joint venture, or sale of the COLA rights to another party.
Susquehanna-Roseland Transmission Line (PPL and PPL Electric)
In 2007, PJM directed the construction of a new 150-mile, 500-kilovolt transmission line between the Susquehanna substation in Pennsylvania and the Roseland substation in New Jersey that it identified as essential to long-term reliability of the Mid-Atlantic electricity grid. PJM determined that the line is needed to prevent potential overloads that could occur on several existing transmission lines in the interconnected PJM system. PJM has directed PPL Electric to construct the portion of the Susquehanna-Roseland line in Pennsylvania and has directed Public Service Electric & Gas Company to construct the
portion of the line in New Jersey, in each case by June 1, 2012. PPL Electric's estimated share of the project costs is approximately $500 million.
This project is pending certain regulatory approvals. PPL Electric has identified the approximately 100-mile route for the Pennsylvania portion of the line. In February 2010, the PUC and the New Jersey Board of Public Utilities approved the project. Several parties appealed the PUC decision to the Commonwealth Court of Pennsylvania. In July 2011, the Commonwealth Court affirmed the PUC's order approving the project, and no further appeals were filed.
In addition, both companies are working with the National Park Service to obtain any approvals that may be required to route the line through the Delaware Water Gap National Recreation Area. The National Park Service record of decision for the project is scheduled to be issued on October 1, 2012. In October 2011, the project was placed on the initial list of projects for the Rapid Response Team for Transmission (RRTT), an initiative of the White House to facilitate coordination among federal agencies to improve the overall quality and timeliness of electric transmission infrastructure permitting, review and consultation. The RRTT has reaffirmed the issuance date of the National Park Service record of decision for the project. The National Park Service has stated that it will announce the preferred route for the transmission line in March 2012 with an expected Record of Decision in October 2012. PPL Electric cannot predict the ultimate outcome or timing of the National Park Service approval.
PPL Electric anticipates the delays in the approval process will postpone the in-service date to 2015. In 2011, PJM issued an updated assessment of the new line within its 2010 Regional Transmission Expansion Plan, which confirms that the line is needed to prevent overloads on other power lines in the region. PJM has developed a strategy to manage potential reliability problems until the line is built. PPL Electric cannot predict what action, if any, PJM might take in the event of a further delay to its scheduled in-service date for the new line.
9. Discontinued Operations
(PPL and PPL Energy Supply)
Sale of Certain Non-core Generation Facilities
In March 2011, PPL Energy Supply subsidiaries completed the sale of their ownership interests in certain non-core generation facilities, which were included in the Supply segment, for $381 million. The transaction included the natural gas-fired facilities in Wallingford, Connecticut and University Park, Illinois and an equity interest in Safe Harbor Water Power Corporation, which owns a hydroelectric facility in Conestoga, Pennsylvania.
These non-core generation facilities met the held for sale criteria in the third quarter of 2010. As a result, assets with a carrying amount of $473 million were written down to their estimated fair value (less cost to sell) of $377 million at September 30, 2010, resulting in a pre-tax impairment charge of $96 million ($58 million after tax). In addition, $5 million ($4 million after tax) of allocated goodwill was written off in the third quarter of 2010. During the fourth quarter of 2010 and in connection with the completion of the sale, in 2011, PPL Energy Supply recorded insignificant losses. These charges are included in "Income (Loss) from Discontinued Operations (net of income taxes)" on the Statements of Income.
Following are the components of Discontinued Operations in the Statements of Income.
(a)
2010 includes the impairments to the carrying value of the non-core generation facilities and the write-off of allocated goodwill.
(b)
Represents allocated interest expense based upon debt attributable to the generation facilities sold.
Upon completion of the sale, assets primarily consisting of $357 million of PP&E and a $14 million equity method investment, which were classified as held for sale at December 31, 2010, were removed from the Balance Sheet.
Sale of Long Island Generation Business
In February 2010, PPL Energy Supply subsidiaries completed the sale of the Long Island generation business, which was included in the Supply segment. The definitive sales agreement included provisions that reduced the $135 million purchase price monthly, commencing September 1, 2009. After adjusting for these price-reduction provisions, proceeds from the sale approximated $124 million.
In the second quarter of 2009, the Long Island generation business met the held for sale criteria. As a result, at June 30, 2009, net assets held for sale were written down to their estimated fair value less cost to sell, resulting in a pre-tax impairment charge of $52 million ($34 million after tax). At both September 30 and December 31, 2009, the estimated fair value (less cost to sell) was remeasured and additional impairments totaling $10 million ($3 million after tax) were recorded. In 2010 PPL Energy Supply recorded an insignificant loss due to the price-reduction provisions. The losses recognized in the third and fourth quarters of 2009 and in 2010 did not significantly impact earnings, as such amounts were substantially offset by tolling revenues from the Long Island generation assets during the same periods. In addition, an insignificant amount of goodwill allocated to this business was written off in 2009. These amounts are included in "Income (Loss) from Discontinued Operations (net of income taxes)" on the Statements of Income. There was no significant impact on earnings in 2010 from the operation of this business or as a result of this sale.
The tolling agreements related to these plants were transferred to the new owner upon completion of the sale.
Following are the components of Discontinued Operations in the Statements of Income.
(a)
Includes impairment charges.
(b)
Represents allocated interest expense based upon debt attributable to the Long Island generation business sold.
Sale of Maine Hydroelectric Generation Business
Sale of the Remaining Maine Hydroelectric Generation Facilities
In December 2010, a PPL Energy Supply subsidiary completed the sale of its remaining three hydroelectric facilities in Maine, which were included in the Supply segment, for $24 million. As a result of the sale, PPL Energy Supply recorded a gain of $11 million ($7 million after tax), reflected in "Income (Loss) from Discontinued Operations (net of income taxes)" on the 2010 Statement of Income.
Sale of the Majority of Maine Hydroelectric Generation Business
In 2009, a PPL Energy Supply subsidiary completed the sale of the majority of its Maine hydroelectric generation business, which was included in the Supply segment, for $81 million in cash, adjusted for working capital. The assets sold in this transaction included five hydroelectric facilities and a 50% equity interest in a sixth hydroelectric facility, which had been accounted for as an equity investment, together with rights to increase energy output at these facilities upon completion of the sale of the PPL Energy Supply subsidiary's three other hydroelectric facilities in Maine (see "Sale of the Remaining Maine Hydroelectric Generation Business" above). As a result of the sale of the majority of the Maine hydroelectric generation business, PPL Energy Supply recorded a gain of $38 million ($22 million after tax), reflected in "Income (Loss) from Discontinued Operations (net of income taxes)" on the 2009 Statement of Income. Additionally, in December 2010, the PPL Energy Supply subsidiary received $14 million in contingent consideration, which was tied to its completion of the sale of the three other hydroelectric facilities noted above. PPL Energy Supply accordingly recorded a gain of $14 million ($8 million after tax), reflected in "Income (Loss) from Discontinued Operations (net of income taxes)" on the 2010 Statement of Income.
Following are the components of Discontinued Operations in the Statements of Income.
(a)
Includes the gains recorded on the sales.
(b)
Represents allocated interest expense based upon debt attributable to the Maine hydroelectric generation business sold.
Sale of Latin American Businesses
In 2007, PPL Energy Supply completed the sale of its regulated electricity delivery businesses in Chile, El Salvador and Bolivia, which were included in the International Regulated segment. In 2009, PPL Energy Supply identified a correction to the previously computed tax bases of the Latin American businesses. The most significant adjustment related to the sale of the El Salvadoran business and was largely due to returns of capital in certain prior years that had not been reflected in the calculated tax basis. As a result, PPL Energy Supply recorded $24 million of additional income tax expense in 2009, which is reflected in "Income (Loss) from Discontinued Operations (net of income taxes)" on the 2009 Statement of Income. The additional expense is not considered by management to be material to the 2009 financial statements.
Distribution of Membership Interest in PPL Global to Parent (PPL Energy Supply)
In January 2011, PPL Energy Supply distributed its 100% membership interest in PPL Global, which represented the entire International Regulated segment, to PPL Energy Supply's parent, PPL Energy Funding. The distribution was made based on the book value of the assets and liabilities of PPL Global with financial effect as of January 1, 2011, and no gains or losses were recognized on the distribution. The purpose of the distribution was to better align PPL's organizational structure with the manner in which it manages these businesses, separating the U.S.-based competitive energy marketing and supply business from the U.K.-based regulated electricity distribution business. Following the distribution, PPL Energy Supply operates in a single reportable segment, and through its subsidiaries is primarily engaged in the generation and marketing of power, primarily in the northeastern and northwestern U.S.
Following are the components of Discontinued Operations in the Statements of Income.
(a)
No interest was allocated, as PPL Global was sufficiently capitalized.
(b)
2009 includes the impact of the Latin American adjustments discussed above.
In connection with the distribution, the following assets and liabilities were removed from PPL Energy Supply's Balance Sheet in the first quarter of 2011. Except for "Cash and cash equivalents," which has been reflected as a financing activity, the remaining distribution represents a non-cash transaction excluded from PPL Energy Supply's 2011 Statement of Cash Flows.
WKE
(PPL and LKE)
WKE had a 25-year lease for and operated nine generating facilities of BREC, and a coal-fired generating facility owned by the City of Henderson, Kentucky.
In 2007, WKE entered into an agreement to terminate the lease, which closed in 2009, prior to PPL acquiring LKE. As part of the lease termination, LKE was obligated to pay a former customer, an aluminum smelter, an aluminum production payment in lieu of a lump-sum cash consent payment, as well as the difference between the electricity prices charged by WKE under the previous long-term sales contract and the electricity prices charged by the aluminum smelter's current electricity supplier. This obligation was partially mitigated by the opportunity to make off-system sales, when economic, for the contractual demand not used by the aluminum smelter. In addition, the total amount of the obligation to this smelter was limited to $82 million; any amount paid by LKE over the limit has been recorded as an interest-bearing receivable and is required to be repaid (plus interest) only if certain conditions occur by 2028. Such exposure expired in January 2011. In addition, because the former customer posted a letter of credit supporting payment to its current electricity supplier, LKE reversed a portion of the accrual associated with its guarantee of payment by the former customer. Also, WKE had a contingent obligation to another aluminum smelter, also a former customer, to make an escrow payment of approximately $4 million, which became payable and was included in the liability at December 31, 2010, and paid in January 2011. The income statement impacts are included in the Kentucky Regulated segment for PPL and are reflected in "Income (Loss) from Discontinued Operations (net of income taxes)" on the Statements of Income. See Note 15 for additional information related to the termination of the lease. The results of operations for the 2011 and 2010 Successor periods were insignificant.
(LKE)
Following are the components of Discontinued Operations in LKE's Statements of Income.
Argentine Gas Distribution
At December 31, 2009, LKE owned interests in two gas distribution companies in Argentina: 45.9% of Distribuidora de Gas Del Centro S.A. (Centro) and 14.4% of Distribuidora de Gas Cuyana S.A. (Cuyana). These two entities served a combined customer base of approximately one million customers. The Centro investment was consolidated due to LKE's majority ownership in the holding company of Centro. The Cuyana investment was accounted for using the equity method due to the ownership influence LKE exerted on the businesses.
In November 2009, subsidiaries of LKE entered into agreements to sell their direct and indirect interests in Centro and Cuyana to E.ON Spain and a subsidiary, both affiliates of E.ON. On January 1, 2010, the parties completed the transfer of the interests for a sale price of $35 million. In December 2009, LKE recorded an impairment loss of $12 million. The impairment loss represented the difference between the carrying values of LKE's interests in Centro and Cuyana and the sales price. LKE classified the results of operations of the Argentine gas distribution companies, including the impairment loss, as discontinued operations for all periods presented effective December 31, 2009. In connection with the reorganization transaction, E.ON Spain assumed rights and obligations relating to claims and liabilities associated with the former Argentine businesses or indemnified LKE with respect to such matters.
Following are the components of Discontinued Operations in LKE's Statement of Income.
10. Business Acquisitions
Acquisition of WPD Midlands (PPL)
On April 1, 2011, PPL, through its indirect, wholly owned subsidiary PPL WEM, completed its acquisition of all of the outstanding ordinary share capital of Central Networks East plc and Central Networks Limited, the sole owner of Central Networks West plc, together with certain other related assets and liabilities (collectively referred to as Central Networks and subsequently renamed WPD Midlands), from subsidiaries of E.ON AG. The consideration for the acquisition consisted of cash of $5.8 billion, including the repayment of $1.7 billion of affiliate indebtedness owed to subsidiaries of E.ON AG, and approximately $800 million of long-term debt assumed through consolidation. WPD Midlands operates two regulated distribution networks that serve five million end-users in the Midlands area of England. The acquisition increases the regulated portion of PPL's business and enhances rate-regulated growth opportunities as the regulated businesses make investments to improve infrastructure and customer reliability. Further, since the service territories of WPD (South Wales), WPD (South West) and WPD Midlands are contiguous, cost savings, efficiencies and other benefits are expected from the combined operations of these entities.
The fair value of the consideration paid for Central Networks was as follows (in billions).
The total cash consideration paid was primarily funded by borrowings under the 2011 Bridge Facility on the date of acquisition. Subsequently, PPL repaid those borrowings in 2011 using proceeds from the permanent financing, including issuances of common stock and 2011 Equity Units, as well as proceeds from the issuance of debt by PPL WEM, WPD (East Midlands) and WPD (West Midlands). See Note 7 for additional information on the 2011 Bridge Facility and permanent financing.
Purchase Price Allocation
The following table summarizes (in billions) the allocation of the purchase price of WPD Midlands to the fair value of the major classes of assets acquired and liabilities assumed.
(a)
Includes gross contractual amount of the accounts receivable acquired of $122 million, which approximates fair value.
(b)
Represents non-cash activity excluded from the 2011 Statement of Cash Flows.
The purchase price allocation resulted in goodwill of $2.4 billion that was assigned to the International Regulated segment. The goodwill is attributable to the expected continued growth of a rate-regulated business with a defined service area operating under a constructive regulatory framework, expected cost savings, efficiencies and other benefits resulting from a contiguous service area with WPD (South West) and WPD (South Wales), as well as the ability to leverage WPD (South West)'s and WPD (South Wales)'s existing management team's high level of performance in capital cost efficiency, system reliability and customer service. The goodwill is not deductible for U.K. income tax purposes.
Separation Benefits - International Regulated Segment
In connection with the acquisition, PPL completed a reorganization designed to transition WPD Midlands from a functional structure to a regional structure that will require a smaller combined support structure, reduce duplication and implement more efficient procedures. Approximately 740 employees of WPD Midlands have or will receive separation benefits from the companies as a result of the reorganization through the end of 2012.
The separation benefits, before income taxes, associated with the reorganization are as follows.
In connection with the reorganization, WPD Midlands recorded $93 million of the total expected separation benefits in 2011, of which $48 million relates to severance compensation and $45 million relates to ERDC. Based on the expected timing of when employees will separate from the companies, WPD Midlands expects to record the remaining portion of severance compensation in 2012. The separation benefits recorded in 2011 are included in "Other operation and maintenance" on the Statement of Income. The accrued severance compensation is reflected in "Other current liabilities" and the ERDC reduced "Other noncurrent assets" on the Balance Sheet at December 31, 2011.
The carrying amount of accrued severance was as follows.
(a) Payments to approximately 350 employees separated.
In addition to the reorganization costs noted above, an additional $9 million was recorded in 2011 for ERDC payable under applicable pension plans and severance compensation for certain employees who separated from the WPD Midlands companies, but were not part of the reorganization. These separation benefits are also included in "Other operation and maintenance" on the Statement of Income.
Pro forma Information
WPD Midlands' operating revenues, net income and net income excluding nonrecurring acquisition-related adjustments (which are recorded on a one-month lag) included in PPL's 2011 Statement of Income and included in the International Regulated segment, are as follows.
The pro forma operating revenues and net income attributable to PPL, which include LKE as if the acquisition had occurred January 1, 2009 and WPD Midlands as if the acquisition had occurred January 1, 2010, are as follows.
The pro forma financial information presented above has been derived from the historical consolidated financial statements of PPL and LKE, which was acquired on November 1, 2010, and from the historical combined financial statements of WPD Midlands. Income (loss) from discontinued operations (net of income taxes), which was not significant for 2011 and was $(18) million for 2010, were excluded from the pro forma amounts above.
The pro forma adjustments include adjustments to depreciation, net periodic pension costs, interest expense, nonrecurring adjustments and the related income tax effects. Nonrecurring adjustments include the following pre-tax credits (expenses).
(a)
Primarily includes advisory, accounting and legal fees recorded in "Other Income (Expense) - net" and contract termination costs, rebranding costs and relocation costs recorded in "Other operation and maintenance."
Acquisition of LKE
(PPL)
On November 1, 2010, PPL completed the acquisition of all of the limited liability company interests of E.ON U.S. LLC from a wholly owned subsidiary of E.ON AG. Upon completion of the acquisition, E.ON U.S. LLC was renamed LG&E and KU Energy LLC (LKE). LKE is a holding company with regulated utility operations conducted through its subsidiaries, LG&E and KU. The acquisition reapportioned the mix of PPL's regulated and competitive businesses by increasing the regulated portion of its business, strengthens PPL's credit profile and enhances rate-regulated growth opportunities as the regulated businesses make investments to improve infrastructure and customer reliability.
The fair value of the consideration paid for E.ON U.S. LLC was as follows (in billions).
The total cash consideration paid, including repayment of affiliate indebtedness, was funded by PPL's June 2010 issuance of $3.6 billion of common stock and 2010 Equity Units that provided proceeds totaling $3.5 billion, net of underwriting discounts, $3.2 billion of borrowings under an existing credit facility in October 2010, $249 million of proceeds from the
monetization of certain full-requirement sales contracts in July 2010 and cash on hand. See Note 7 for additional information on the issuance of common stock and 2010 Equity Units and the October 2010 borrowing under PPL Energy Supply's syndicated credit facility that provided interim financing to partially fund the acquisition. See Note 19 for additional information on the monetization of certain full-requirement sales contracts.
Purchase Price Allocation
The following table summarizes (in billions) the allocation of the purchase price of LKE to the fair value of the major classes of assets acquired and liabilities assumed.
(a)
Includes gross contractual amount of the accounts receivable acquired of $186 million. PPL expected $11 million to be uncollectible; however, credit risk is mitigated since uncollectible accounts are a component of customer rates.
(b)
Represents non-cash activity excluded from the 2010 Statement of Cash Flows.
(c)
Includes $1.6 billion designated as a capital contribution to LKE.
For purposes of goodwill impairment testing, the $996 million of goodwill was assigned to the PPL reportable segments expected to benefit from the acquisition. Both the Kentucky Regulated and the Supply segments are expected to benefit and the assignment of goodwill was $662 million to the Kentucky Regulated segment and $334 million to the Supply segment. The goodwill at the Kentucky Regulated segment reflects the value paid for the expected continued growth of a rate-regulated business located in a defined service area with a constructive regulatory environment, the ability of LKE to leverage its assembled workforce to take advantage of those growth opportunities and the attractiveness of stable, growing cash flows. Although no other assets or liabilities from the acquisition were assigned to the Supply segment, the Supply segment obtained a synergistic benefit attributed to the overall de-risking of the PPL portfolio, which enhanced PPL Energy Supply's credit profile, thereby increasing the value of the Supply segment. This increase in value resulted in the assignment of goodwill to the Supply segment. None of the goodwill recognized is expected to be included in regulated customer rates or deductible for income tax purposes. As such, no deferred taxes were recorded related to goodwill.
See Note 9 and the "Guarantees and Other Assurances" section of Note 15 for additional information on certain indemnifications provided by LKE, the most significant of which relates to the discontinued operations of WKE.
The actual LKE operating revenues and net income attributable to PPL included in PPL's 2010 Statement of Income are as follows.
(PPL, PPL Energy Supply, LKE, LG&E and KU)
In November 2010, LKE, LG&E and KU issued debt totaling $2.9 billion, of which $100 million was used to return capital to PPL. The majority of these proceeds, together with a borrowing by LG&E under its available credit facilities were applied to repay borrowings from a PPL Energy Supply subsidiary. Such borrowings were incurred to permit LKE to repay certain indebtedness owed to affiliates of E.ON AG upon the closing of the acquisition. In November 2010, PPL Energy Supply used the above-referenced amounts received from LKE, together with other cash on hand, to repay approximately $3.0 billion of its October 2010 borrowing under existing credit facilities. See Note 7 for additional information.
(PPL and PPL Energy Supply)
To ensure adequate funds were available for the acquisition, in July 2010, PPL Energy Supply monetized certain full-requirement sales contracts that resulted in cash proceeds of $249 million. See "Commodity Price Risk (Non-trading) -
Monetization of Certain Full-Requirement Sales Contracts" in Note 19 for additional information. Additionally, PPL Energy Supply received proceeds in 2011 from the sale of certain non-core generation facilities, which were used to repay the short-term borrowings drawn on existing credit facilities. See "Sale of Certain Non-core Generation Facilities" in Note 9 for additional information.
As a result of the monetization of these full-requirement sales contracts, coupled with the expected net proceeds from the then-anticipated sale of these non-core generation facilities, debt that had been planned to be issued by PPL Energy Supply in late 2010 was no longer needed. Therefore, hedge accounting associated with interest rate swaps entered into by PPL in anticipation of a debt issuance by PPL Energy Supply was discontinued. Net losses of $(29) million, or $(19) million after tax, were reclassified from AOCI to "Other Income (Expense) - net" on PPL's 2010 Statement of Income.
(LKE, LG&E and KU)
On November 1, 2010, PPL completed its acquisition of LKE and its subsidiaries. The push-down basis of accounting was used to record the fair value adjustments of assets and liabilities on LKE at the acquisition date. PPL paid cash consideration for the equity interests in LKE and its subsidiaries of $2,493 million and provided a capital contribution on November 1, 2010, of $1,565 million; included within this was the consideration paid of $1,702 million for LG&E and $2,656 million for KU. The allocation of the purchase price was based on the fair value of assets acquired and liabilities assumed.
The push-down accounting for the fair value of assets acquired and liabilities assumed was as follows (in millions).
Goodwill represents value paid for the rate regulated businesses of LG&E and KU, which are located in a defined service area with a constructive regulatory environment, which provides for future investment, earnings and cash flow growth, as well as the talented and experienced workforce. LG&E's and KU's franchise values are being attributed to the going concern value of the business, and thus were recorded as goodwill rather than a separately identifiable intangible asset. None of the goodwill recognized is deductible for income tax purposes or included in customer rates.
Adjustments to LKE's, LG&E's and KU's assets and liabilities that contributed to goodwill are as follows:
The fair value adjustment on the EEI investment was calculated using the discounted cash flow valuation method. The result was an increase in KU's value of the investment in EEI; the fair value of EEI was calculated to be $30 million and a fair value adjustment of $18 million was recorded on KU. The fair value adjustment to EEI is amortized over the expected remaining useful life of plant and equipment at EEI, which is estimated to be over 20 years.
The pollution control bonds, excluding the reacquired bonds, had a fair value adjustment of $7 million for LG&E and $1 million for KU. All variable bonds were valued at par while the fixed rate bonds were valued with a yield curve based on average credit spreads for similar bonds.
As a result of the purchase accounting associated with the acquisition, the following items had a fair value adjustment but no effect on goodwill as the offset was either a regulatory asset or liability. The regulatory asset or liability has been recorded to eliminate any ratemaking impact of the fair value adjustments:
·
The value of OVEC was determined to be $126 million based upon an announced transaction by another owner. LG&E and KU's combined investment in OVEC was not significant and the power purchase agreement was valued at $87 million for LG&E and $39 million for KU. An intangible asset was recorded with the offset to regulatory liability and is amortized using the units of production method until March 2026, the expiration date of the agreement at the date of the acquisition.
·
LG&E and KU each recorded an emission allowance intangible asset and a regulatory liability as the result of adjusting the fair value of the emission allowances at LG&E and KU. The emission allowance intangible of $8 million at LG&E and $9 million at KU represents allocated and purchased sulfur dioxide and nitrogen oxide emission allowances that were unused as of the valuation date or allocated for use in future years. LG&E and KU had previously recorded emission allowances as other materials and supplies. To conform to PPL's accounting policy all emission allowances are now recorded as intangible assets. The emission allowance intangible asset is amortized as the emission allowances are consumed, which is expected to occur through 2040.
·
Coal contract intangible assets were recorded at LG&E for $124 million and at KU for $145 million as well as a non-current liability of $11 million for LG&E and $22 million for KU on the Balance Sheets. An offsetting regulatory asset was recorded for those contracts with unfavorable terms relative to market. An offsetting regulatory liability was recorded for those contracts that had favorable terms relative to market. All coal contracts held by LG&E and KU, wherein it had entered into arrangements to buy amounts of coal at fixed prices from counterparties at a future date, were fair valued. The intangible assets and other liabilities, as well as the regulatory assets and liabilities, are being amortized over the same terms as the related contracts, which expire through 2016.
·
Adjustments on November 1, 2010 were made to record LKE pension assets at fair value, remeasure its pension and postretirement benefit obligations at current discount rates and eliminate accumulated other comprehensive income (loss). An increase of $4 million in the liability balances of LG&E and KU was recorded, due to the lowering of the discount rate; this was credited to their respective pension and postretirement liability balances with offsetting adjustments made to the related regulatory assets and liabilities.
The fair value of intangible assets and liabilities (e.g. contracts that have favorable or unfavorable terms relative to market), including coal contracts and power purchase agreements, as well as emission allowances, have been reflected on the Balance Sheets with offsetting regulatory assets or liabilities. Prior to the acquisition, LG&E and KU recovered the cost of the coal contracts, power purchases and emission allowances and this rate treatment will continue after the acquisition. As a result, management believes the regulatory assets and liabilities created to offset the fair value adjustments meet the recognition criteria established by existing accounting guidance and eliminate any ratemaking impact of the fair value adjustments. LG&E's and KU's customer rates will continue to reflect these items (e.g. coal, purchased power, emission allowances) at their original contracted prices.
LG&E and KU also considered whether a separate fair value should be assigned to LG&E's and KU's rights to operate within its various electric and natural gas distribution service areas but concluded that these rights only provided the opportunity to earn a regulated return and barriers to market entry, which in management's judgment is not considered a separately identifiable intangible asset under applicable accounting guidance; rather, it is considered going-concern value, or goodwill.
11. Leases
Lessee Transactions
(PPL, LKE, LG&E and KU)
E.W. Brown Combustion Turbines
LG&E and KU are participants in a sale-leaseback transaction involving two combustion turbines at the E.W. Brown generating plant. In December 1999, after selling their interests in the combustion turbines, LG&E and KU entered into an 18-year lease of the turbines. LG&E and KU provided funds to fully defease the lease and have the right to exercise an early purchase option contained in the lease after 15.5 years, which will occur in 2015. The financial statement treatment of this transaction is the same as if LG&E and KU had retained their ownership interest. Since the lease was defeased, there are no remaining minimum lease payments and all related PP&E is reflected on the Balance Sheets. See Note 14 for the balances included on the Balance Sheets related to this transaction. Depreciation expense was insignificant for all periods presented.
Upon a default under the lease, LG&E and KU are obligated to pay to the lessor their share of certain amounts. Primary events of default include loss or destruction of the combustion turbines, failure to insure or maintain the combustion turbines and unwinding of the transaction due to governmental actions. No events of default currently exist with respect to the lease. Upon any termination of the lease, whether by default or expiration of its term, title to the combustion turbines reverts to LG&E and KU. The maximum aggregate amount at December 31, 2011 that could be required to be paid by PPL and LKE is $6 million, by LG&E is $2 million and by KU is $4 million. LKE has guaranteed the payment of these potential default payments of LG&E and KU.
(PPL and PPL Energy Supply)
Tolling Agreement
In 2008, PPL EnergyPlus acquired the rights to an existing long-term tolling agreement for the capacity and energy of Ironwood. Under the agreement, PPL EnergyPlus has control over the plant's dispatch into the electricity grid and will supply the natural gas necessary to operate the plant. The tolling agreement extends through 2021 and is considered to be an operating lease for accounting purposes. The fixed payments under the tolling agreement are subject to adjustment based upon changes to the facility capacity rating, which may occur up to twice per year. Certain costs within the tolling agreement, primarily non-lease costs, are subject to escalation.
Colstrip Generating Plant
In July 2000, PPL Montana sold its interest in the Colstrip generating plants to owner lessors who lease back to PPL Montana, under four 36-year non-cancelable leases, a 50% interest in Colstrip Units 1 and 2 and a 30% interest in Unit 3. This transaction is accounted for as a sale-leaseback and classified as an operating lease. PPL Montana is responsible for its share of the operating expenses associated with its leasehold interests. See Note 14 for information on the sharing agreement for Colstrip Units 3 and 4. PPL Montana currently amortizes material leasehold improvements over no more than the remaining life of the original leases; however, the leases provide two renewal options based on the economic useful life of the generation assets. The leases place certain restrictions on PPL Montana's ability to incur additional debt, sell assets and declare dividends and require PPL Montana to maintain certain financial ratios related to cash flow and net worth. There are no residual value guarantees in these leases. However, upon an event of default or an event of loss, PPL Montana could be required to pay a termination value of amounts sufficient to allow the lessor to repay amounts owing on the lessor notes and make the lessor whole for its equity investment and anticipated return on investment. The events of default include payment defaults, breaches of representations or covenants, acceleration of other indebtedness of PPL Montana, change in control of PPL Montana and certain bankruptcy events. The termination value was estimated to be $327 million at December 31, 2011.
Kerr Dam
At December 31, 2011, PPL Montana continued to participate in a lease arrangement with the Confederated Salish and Kootenai Tribes of the Flathead Nation. Under a joint operating license issued by the FERC, PPL Montana is responsible to make payments to the tribes for the use of their property. This agreement, subject to escalation based upon inflation, extends until the end of the license term in 2035. Between 2015 and 2025, the tribes have the option to purchase, hold and operate the project, which would result in the termination of this leasing arrangement.
(PPL, PPL Energy Supply, LKE, LG&E and KU)
Other Leases
PPL and its subsidiaries have entered into various agreements for the lease of office space, vehicles, land gas storage and other equipment.
Rent - Operating Leases
Rent expense for operating leases was as follows:
Total future minimum rental payments for all operating leases are estimated to be:
12. Stock-Based Compensation
(PPL, PPL Energy Supply, PPL Electric and LKE)
Under the PPL Incentive Compensation Plan (ICP) and the Incentive Compensation Plan for Key Employees (ICPKE) (together, the Plans), restricted shares of PPL common stock, restricted stock units, performance units and stock options may be granted to officers and other key employees of PPL, PPL Energy Supply, PPL Electric, LKE and other affiliated companies. Awards under the Plans are made by the Compensation, Governance and Nominating Committee (CGNC) of the PPL Board of Directors, in the case of the ICP, and by the PPL Corporate Leadership Council (CLC), in the case of the ICPKE.
The ICP limits the total number of awards that may be granted under it after April 23, 1999 to 15,769,431. The ICPKE limits the total number of awards that may be granted under it after April 25, 2003 to 14,199,796. In addition, each Plan limits the number of shares available for awards in any calendar year to 2% of the outstanding common stock of PPL on the first day of such calendar year. The maximum number of options that can be awarded under each Plan to any single eligible employee in any calendar year is three million shares. Any portion of these options that has not been granted may be carried over and used in any subsequent year. If any award lapses, is forfeited or the rights of the participant terminate, the shares of PPL common stock underlying such an award are again available for grant. Shares delivered under the Plans may be in the form of authorized and unissued PPL common stock, common stock held in treasury by PPL or PPL common stock purchased on the open market (including private purchases) in accordance with applicable securities laws.
Restricted Stock and Restricted Stock Units
Restricted shares of PPL common stock are outstanding shares with full voting and dividend rights. Restricted stock awards are granted as a retention award for select key executives and vest when the recipient reaches a certain age or meets service or other criteria set forth in the executive's restricted stock award agreement. The shares are subject to forfeiture or accelerated payout under Plan provisions for termination, retirement, disability and death of employees. Restricted shares vest fully if control of PPL changes, as defined by the Plans.
The Plans allow for the grant of restricted stock units. Restricted stock units are awards based on the fair value of PPL common stock on the date of grant. Actual PPL common shares will be issued upon completion of a vesting period, generally three years. The fair value of restricted stock units granted is recognized on a straight-line basis over the service period or through the date at which the employee reaches retirement eligibility. The fair value of restricted stock units granted to retirement-eligible employees is recognized immediately upon the date of grant. Recipients of restricted stock units may also be granted the right to receive dividend equivalents through the end of the restriction period or until the award is forfeited. Restricted stock units are subject to forfeiture or accelerated payout under the Plan provisions for termination, retirement, disability and death of employees. Restricted stock units vest fully if control of PPL changes, as defined by the Plans.
The weighted-average grant date fair value of restricted stock and restricted stock units granted was:
Restricted stock and restricted stock unit activity for 2011 was:
Substantially all restricted stock and restricted stock unit awards are expected to vest.
The total fair value of restricted stock/units vesting for the years ended December 31 was:
Performance Units
Performance units are intended to encourage and award future performance. Performance units represent a target number of shares (Target Award) of PPL's common stock that the recipient would receive upon PPL's attainment of the applicable performance goal. Performance is determined based on total shareowner return during a three-year performance period. At the end of the period, payout is determined by comparing PPL's performance to the total shareowner return of the companies included in an index group, in this case the S&P Electric Utilities Index. Awards granted in 2010 and 2009 were payable on a graduated basis within the following ranges: if PPL's performance is at or above the 85th percentile of the index group, the award is paid at 200% of the Target Award; at the 50th percentile of the index group, the award is paid at 100% of the Target Award; at the 40th percentile of the index group, the award is paid at 50% of the Target Award; and below the 40th percentile, no award is payable. Awards granted in 2011 provide for payment at 25% of the Target Award if performance falls below the 40th percentile of the index group. Dividends payable during the performance cycle accumulate and are converted into additional performance units and are payable in shares of PPL common stock upon completion of the performance period based on the determination of the CGNC of whether the performance goals have been achieved. Under the Plan provisions, performance units are subject to forfeiture upon termination of employment except for retirement, disability or death of an employee, in which case the total performance units remain outstanding and are eligible for vesting through the conclusion of the performance period. The fair value of performance units granted is recognized on a straight-line basis over the three-year performance period. Performance units vest on a pro rata basis if control of PPL changes, as defined by the Plan.
The fair value of each performance unit granted was estimated using a Monte Carlo pricing model that considers stock beta, a risk-free interest rate, expected stock volatility and expected life. The stock beta was calculated comparing the risk of the individual securities to the average risk of the companies in the index group. The risk-free interest rate reflects the yield on a U.S. Treasury bond commensurate with the expected life of the performance unit. Volatility over the expected term of the
performance unit is calculated using daily stock price observations for PPL and all companies in the index group and is evaluated with consideration given to prior periods that may need to be excluded based on events not likely to recur that had impacted PPL and companies in the index group. PPL had used historical volatility to value its performance units in 2010 and 2009. Beginning in 2011, PPL began using a mix of historic and implied volatility in response to the significant changes in its business model, moving from a primarily unregulated to a primarily regulated business model, as a result of the acquisitions of LKE and WPD Midlands.
The weighted-average assumptions used in the model were:
The weighted-average grant date fair value of performance units granted was:
Performance unit activity for 2011 was:
Stock Options
Under the Plans, stock options may be granted with an option exercise price per share not less than the fair value of PPL's common stock on the date of grant. Options outstanding at December 31, 2011, become exercisable in equal installments over a three-year service period beginning one year after the date of grant, assuming the individual is still employed by PPL or a subsidiary. The CGNC and CLC have discretion to accelerate the exercisability of the options, except that the exercisability of an option issued under the ICP may not be accelerated unless the individual remains employed by PPL or a subsidiary for one year from the date of grant. All options expire no later than ten years from the grant date. The options become exercisable immediately if control of PPL changes, as defined by the Plans. The fair value of options granted is recognized on a straight-line basis over the service period or through the date at which the employee reaches retirement eligibility. The fair value of options granted to retirement-eligible employees is recognized immediately upon the date of grant.
The fair value of each option granted is estimated using a Black-Scholes option-pricing model. PPL uses a risk-free interest rate, expected option life, historical volatility and dividend yield to value its stock options. The risk-free interest rate reflects the yield for a U.S. Treasury Strip available on the date of grant with constant rate maturity approximating the option's expected life. Expected life is calculated based on historical exercise behavior. Volatility over the expected term of the options is evaluated with consideration given to prior periods that may need to be excluded based on events not likely to recur that had impacted PPL's volatility in those prior periods. Management's expectations for future volatility, considering potential changes to PPL's business model and other economic conditions, are also reviewed in addition to the historical data to determine the final volatility assumption. PPL had used historical volatility to value its stock options granted in 2010 and 2009. Beginning in 2011, PPL began using a mix of historic and implied volatility in response to the significant changes in its business model, moving from a primarily unregulated to a primarily regulated business model, as a result of the acquisitions of LKE and WPD Midlands. The dividend yield is based on several factors, including PPL's most recent dividend payment, as of the grant date and the forecasted stock price through 2012. The assumptions used in the model were:
The weighted-average grant date fair value of options granted was:
Stock option activity for 2011 was:
PPL received $1 million in cash from stock options exercised in 2011. The related tax savings were not significant for 2011. Substantially all stock option awards are expected to vest.
The total intrinsic value of stock options exercised for the years ended December 31 2011, 2010, and 2009 was not significant.
Compensation Expense
Compensation expense for restricted stock, restricted stock units, performance units and stock options accounted for as equity awards was as follows:
(a)
Income tax benefits of $15 million, $11 million and $9 million.
(b)
Income tax benefits of $6 million, $8 million and $7 million.
(c)
Income tax benefits of $3 million, $3 million and $2 million.
(d)
Income tax benefits of $2 million.
The income tax benefit PPL realized from stock-based awards vested or exercised for 2011 was not significant.
At December 31, 2011, unrecognized compensation expense related to nonvested restricted stock, restricted stock units, performance units and stock option awards was:
13. Retirement and Postemployment Benefits
(PPL, PPL Energy Supply, PPL Electric, LKE, LG&E, and KU)
Defined Benefits
Until January 1, 2012, the majority of PPL's subsidiaries domestic employees were eligible for pension benefits under non-contributory defined benefit pension plans with benefits based on length of service and final average pay, as defined by the plans. Effective January 1, 2012, PPL's domestic qualified pension plans were closed to newly hired salaried employees. Newly hired bargaining unit employees will continue to be eligible under the plans based on their collective bargaining agreements. Salaried employees hired on or after January 1, 2012 will be eligible to participate in the new PPL Retirement Savings Plan, a 401(k) savings plan with enhanced employer matching. PPL does not expect a significant near-term cost impact as a result of the change.
Certain employees may also be eligible for pension enhancements in the form of special termination benefits under PPL's separation plan. See "Separation Benefits" below for additional information regarding PPL's separation plan.
The defined benefit pension plans of LKE and its subsidiaries were closed to new salaried and bargaining unit employees hired after December 31, 2005. Employees hired after December 31, 2005 receive additional company contributions above the standard matching contributions to their savings plans.
Until January 1, 2012, employees of PPL Montana were eligible for pension benefits under a cash balance pension plan. Effective January 1, 2012, that plan was closed to newly hired salaried employees. Newly hired bargaining unit employees will continue to be eligible under the plan based on their collective bargaining agreements. Salaried employees hired on or after January 1, 2012 will be eligible to participate in the new PPL Retirement Savings Plan, a 401(k) savings plan with enhanced employer matching. PPL Montana does not expect a significant near-term cost impact as a result of the change.
Employees of certain of PPL Energy Supply's mechanical contracting companies are eligible for benefits under multiemployer plans sponsored by various unions.
Effective April 1, 2010, PPL WW's principal pension plan was closed to most new employees, except for those meeting specific grandfathered participation rights. New employees not eligible to participate in the plan are offered benefits under a defined contribution plan. WPD Midlands was acquired by PPL WEM on April, 1, 2011. WPD Midlands' defined benefit plan had been closed to new members, except for those meeting specific grandfathered participation rights, prior to acquisition.
PPL and certain of its subsidiaries also provide supplemental retirement benefits to executives and other key management employees through unfunded nonqualified retirement plans.
The majority of employees of PPL's domestic subsidiaries will become eligible for certain health care and life insurance benefits upon retirement through contributory plans. Postretirement health benefits are paid from 401(h) accounts established within the PPL Services Corporation Master Trust, LG&E and KU Energy LLC Pension Plan Trusts, funded VEBA trusts and company funds. Postretirement benefits under the PPL Montana Retiree Health Plan are paid from company assets. WPD does not sponsor any postretirement benefit plans other than pensions.
As a result of PPL Energy Supply's January 2011 distribution of its membership interest in PPL Global to its parent, PPL Energy Funding, the U.K. pension plans were removed from PPL Energy Supply's balance sheet in the first quarter of 2011. No future contributions to the plans are expected to be made by PPL Energy Supply beginning in 2011. See Note 9 for additional information.
The following disclosures distinguish between the domestic (U.S.) and WPD (U.K.) pension plans.
(a)
Includes the settlement of the pension plan of PPL's former mining subsidiary, PA Mines, LLC in 2009.
(b)
Related to the 2011 WPD Midlands separations in the U.K. and a 2009 U.S. cost reduction initiative.
(c)
For PPL's U.S. pension benefits, the amounts recognized in OCI for 2011, 2010 and 2009 were $47 million, $84 million and $51 million. The amounts recognized in regulatory assets/liabilities for 2011, 2010 and 2009 were $24 million, $364 million and $33 million. In total, the amounts recognized in either OCI or regulatory assets/liabilities for 2011, 2010 and 2009 were $71 million, $448 million and $84 million.
For other postretirement benefits, the amounts recognized in OCI for 2011, 2010 and 2009 were $(6) million, $(40) million and $6 million. The amounts recognized in regulatory assets/liabilities for 2011, 2010 and 2009 were $(1) million, $(18) million and $3 million. In total, the amounts recognized in either OCI or regulatory assets/liabilities for 2011, 2010 and 2009 were $(7) million, $(58) million and $9 million.
(d)
WPD is not subject to accounting for the effects of certain types of regulation as prescribed by GAAP. As a result, WPD does not record regulatory assets/liabilities.
The estimated amounts to be amortized from AOCI and regulatory assets/liabilities into net periodic benefit costs in 2012 are as follows:
(a)
In January 2011, PPL Energy Supply distributed its membership interest in PPL Global to PPL Energy Supply's parent. See Note 9 for additional information.
(b)
Includes the settlement of the pension plan of PPL Energy Supply's former mining subsidiary, PA Mines, LLC in 2009.
Actuarial loss of $2 million related to PPL Energy Supply's U.S. pension plan is expected to be amortized from AOCI into net periodic benefit costs in 2012.
The following table provides the components of net periodic benefit cost for LKE's pension and other postretirement benefit plans for January 1, 2011 through December 31, 2011, and November 1, 2010 through December 31, 2010, for the Successor, and January 1, 2010 through October 31, 2010, and January 1, 2009 through December 31, 2009, for the Predecessor.
(a)
For LKE's pension and other postretirement benefits, the amounts recognized in OCI and regulatory assets/liabilities are as follows at December 31, 2011 and 2010, for the Successor, and at October 31, 2010, and December 31, 2009, for the Predecessor.
The estimated amounts to be amortized from AOCI and regulatory assets/liabilities into net periodic benefit costs for LKE in 2012 are as follows.
The following table provides the components of net periodic benefit cost for LG&E's pension benefit plan for January 1, 2011 through December 31, 2011, and November 1, 2010 through December 31, 2010, for the Successor, and January 1, 2010 through October 31, 2010, and January 1, 2009 through December 31, 2009, for the Predecessor.
The estimated amounts to be amortized from regulatory assets into net periodic benefit costs for LG&E in 2012 are as follows.
Net periodic defined benefit costs (credits) charged to operating expense, excluding amounts charged to construction and other non-expense accounts were:
(a)
As a result of PPL Energy Supply's January 2011 distribution of its membership interest in PPL Global to its parent, PPL Energy Funding, these amounts are included in "Income (Loss) from Discontinued Operations (net of income taxes)" on PPL Energy Supply's Statements of Income. See Note 6 for additional information.
(b)
Includes costs for the specific plans it sponsors and the following allocated costs of defined benefit plans sponsored by PPL Services, based on PPL Energy Supply's participation in those plans, which management believes are reasonable.
(c)
PPL Electric does not directly sponsor any defined benefit plans. PPL Electric was allocated these costs of defined benefit plans sponsored by PPL Services, based on its participation in those plans, which management believes are reasonable.
The following table provides net periodic benefit costs charged to operating expense for January 1, 2011 through December 31, 2011, and November 1, 2010 through December 31, 2010, for the Successor, and January 1, 2010 through October 31, 2010, and January 1, 2009 through December 31, 2009, for the Predecessor.
(d)
Includes costs for the specific plans it sponsors and the following allocated costs of defined benefit plans sponsored by LKE, based on its participation in those plans, which management believes are reasonable.
(e)
KU does not directly sponsor any defined benefit plans. KU was allocated these costs of defined benefit plans sponsored by LKE, based on its participation in those plans, which management believes are reasonable.
The following weighted-average assumptions were used in the valuation of the benefit obligations at December 31.
The following table provides the weighted-average assumptions used in the valuation of the benefit obligations at December 31, 2011 and 2010, for the Successor, and at October 31, 2010 and December 31, 2009, for the Predecessor.
The following weighted-average assumptions were used to determine the net periodic benefit costs for the year ended December 31.
The following table provides the weighted-average assumptions used to determine the net periodic benefit costs for January 1, 2011 through December 31, 2011, and November 1, 2010 through December 31, 2010, for the Successor, and January 1, 2010 through October 31, 2010, and January 1, 2009 through December 31, 2009, for the Predecessor.
(a)
The expected long-term rates of return for PPL, PPL Energy Supply, LKE and LG&E's U.S. pension and other postretirement benefits have been developed using a best-estimate of expected returns, volatilities and correlations for each asset class. The best estimates are based on historical performance, future expectations and periodic portfolio rebalancing among the diversified asset classes. PPL management corroborates these rates with expected long-term rates of return calculated by its independent actuary, who uses a building block approach that begins with a risk-free rate of return with factors being added such as inflation, duration, credit spreads and equity risk. Each plan's specific asset allocation is also considered in developing a reasonable return assumption.
The expected long-term rates of return for PPL's U.K. pension plans have been developed by PPL management with assistance from an independent actuary using a best estimate of expected returns, volatilities and correlations for each asset class. The best estimates are based on historical performance, future expectations and periodic portfolio rebalancing among the diversified asset classes.
The following table provides the assumed health care cost trend rates for the year ended December 31.
The following table provides the assumed health care cost trend rates for January 1, 2011 through December 31, 2011, and November 1, 2010 through December 31, 2010, for the Successor, and January 1, 2010 through October 31, 2010, and January 1, 2009 through December 31, 2009, for the Predecessor.
A one percentage point change in the assumed health care costs trend rate assumption would have had the following effects on the other postretirement benefit plans in 2011.
The effects on PPL Energy Supply's other postretirement benefit plans would not have been significant.
(PPL)
The funded status of the PPL plans was as follows.
(a)
Includes the pension and other postretirement medical plans of LKE, which were acquired in 2010, and the pension plan of WPD Midlands, which was acquired in 2011. See Note 10 for additional information.
(b)
For PPL's U.S. pension benefits, the amounts recognized in AOCI for 2011 and 2010 were $481 million, $431 million. The amounts recognized in regulatory assets/liabilities for 2011 and 2010 were $556 million and $536 million. In total, the amounts recognized in either OCI or regulatory assets/liabilities for 2011 and 2010 were $1,037 million and $967 million.
For other postretirement benefits, the amounts recognized in AOCI for 2011 and 2010 were $56 million and $53 million. The amounts recognized in regulatory assets/liabilities for 2011 and 2010 were $38 million and $47 million. In total, the amounts recognized in either OCI or regulatory assets/liabilities for 2011 and 2010 were $94 million and $100 million.
(c)
WPD is not subject to accounting for the effects of certain types of regulation as prescribed by GAAP. As a result, WPD does not record regulatory assets/liabilities.
All of PPL's U.S. pension plans had projected and accumulated benefit obligations in excess of plan assets at December 31, 2011 and 2010. All of PPL's other postretirement benefit plans had accumulated postretirement benefit obligations in excess of plan assets at December 31, 2011 and 2010. For the U.K. pension plans of PPL WEM, the fair value of plan assets of $3.7 billion exceeded both the projected benefit obligations of $3.6 billion and the accumulated benefit obligations of $3.3 billion at December 31, 2011. For the pension plans of PPL WW, both the projected benefit obligations of $3.0 billion and accumulated benefit obligations of $2.8 billion exceeded the plan assets of $2.6 billion at December 31, 2011. For the pension plans of PPL WW, both the projected benefit obligations of $2.8 billion and accumulated benefit obligations of $2.6 billion exceeded the plan assets of $2.5 billion at 2010.
(PPL Energy Supply)
The funded status of the PPL Energy Supply plans was as follows.
(a)
As a result of PPL Energy Supply's January 2011 distribution of its membership interest in PPL Global to its parent, PPL Energy Funding, the funded status and AOCI were removed from the balance sheet in January 2011. See Note 9 for additional information.
All of PPL Energy Supply's pension plans had projected and accumulated benefit obligations in excess of plan assets at December 31, 2011 and 2010. All of PPL Energy Supply's other postretirement benefit plans had accumulated postretirement benefit obligations in excess of plan assets at December 31, 2011 and 2010.
In addition to the plans it sponsors, PPL Energy Supply and its subsidiaries are allocated a portion of the funded status and costs of the defined benefit plans sponsored by PPL Services based on their participation in those plans, which management believes are reasonable. The actuarially determined obligations of current active employees are used as a basis to allocate total plan activity, including active and retiree costs and obligations. PPL Energy Supply's allocated share of the funded status of the pension plans resulted in a liability of $204 million and $287 million at December 31, 2011 and 2010. PPL
Energy Supply's allocated share of other postretirement benefits was a liability of $51 million and $55 million at December 31, 2011 and 2010.
(LKE)
The funded status of the LKE plans was as follows for January 1, 2011 through December 31, 2011, and November 1, 2010 through December 31, 2010, for the Successor, and January 1, 2010 through October 31, 2010, for the Predecessor.
(a)
For LKE's pension and other post-retirement benefits, the amounts recognized in AOCI and regulatory assets/liabilities are as follows at December 31, 2011 and 2010, for the Successor, and at October 31, 2010, for the Predecessor.
LKE's pension plans had projected and accumulated benefit obligations in excess of plan assets at December 31, 2011 and 2010. LKE's postretirement benefit plan had accumulated postretirement benefit obligations in excess of plan assets at December 31, 2011 and 2010.
(LG&E)
The funded status of the LG&E plan was as follows for January 1, 2011 through December 31, 2011, and November 1, 2010 through December 31, 2010, for the Successor, and January 1, 2010 through October 31, 2010, for the Predecessor.
LG&E's pension plan had projected and accumulated benefit obligations in excess of plan assets at December 31, 2011 and 2010.
In addition to the plan it sponsors, LG&E is allocated a portion of the funded status and costs of certain defined benefit plans sponsored by LKE based on its participation in those plans, which management believes are reasonable. The actuarially determined obligations of current active employees and retired employees are used as a basis to allocate total plan activity, including active and retiree costs and obligations. LG&E's allocated share of the funded status of the pension plans resulted in a liability of $53 million and $69 million at December 31, 2011 and 2010. LG&E's allocated share of other postretirement benefits was a liability of $87 million and $85 million at December 31, 2011 and 2010.
(PPL and PPL Energy Supply)
PPL Energy Supply's mechanical contracting subsidiaries make contributions to over 70 multiemployer pension plans, based on the bargaining units from which labor is procured. The risks of participating in these multiemployer plans are different from single-employer plans in the following aspects:
·
Assets contributed to the multiemployer plan by one employer may be used to provide benefits to employees of other participating employers.
·
If a participating employer stops contributing to the plan, the unfunded obligations of the plan may be borne by the remaining participating employers.
·
If PPL Energy Supply's mechanical contracting subsidiaries choose to stop participating in some of their multiemployer plans, they may be required to pay those plans an amount based on the unfunded status of the plan, referred to as a withdrawal liability.
PPL Energy Supply identified the Steamfitters Local Union No. 420 Pension Plan, EIN/Plan Number 23-2004424/001 as the only significant plan to which contributions are made. Contributions to this plan by PPL Energy Supply's mechanical contracting companies were $5 million for 2011, $4 million for 2010 and $5 million for 2009. At the date the financial statements were issued, the Form 5500 was not available for the plan year ending in 2011. Therefore, the following disclosures specific to this plan are being made based on the Form 5500s filed for the plan years ended December 31, 2010 and 2009. PPL Energy Supply's mechanical contracting subsidiaries were not identified individually as greater than 5%
contributors on the Form 5500s. However, the combined contributions of the three subsidiaries contributing to the plan had exceeded 5%. The plan had a Pension Protection Act zone status of red, without utilizing an extended amortization period, as of December 31, 2010 and 2009. In addition, the plan is subject to a rehabilitation plan and surcharges have been applied to participating employer contributions. The expiration date of the collective-bargaining agreement related to those employees participating in this plan is April 30, 2014. There were no other plans deemed individually significant based on a multifaceted assessment of each plan. This assessment included review of the funded/zone status of each plan and PPL Energy Supply's potential obligations under the plan and the number of participating employers contributing to the plan.
PPL Energy Supply's mechanical contracting subsidiaries also participate in multiemployer other postretirement plans that provide for retiree life insurance and health benefits.
The table below details total contributions to all multiemployer pension and other postretirement plans, including the plan identified as significant above. The contribution amounts fluctuate each year based on the volume of work and type of projects undertaken from year to year.
PPL Energy Supply maintains a liability for the cost of health care of retired miners of former subsidiaries that had been engaged in coal mining, as required by the Coal Industry Retiree Health Benefit Act of 1992. At December 31, 2011, the liability was $6 million. The liability is the net of $67 million of estimated future benefit payments offset by $31 million of assets in a retired miners VEBA trust and an additional $30 million of excess assets available in a Black Lung Trust that can be used to fund the health care benefits of retired miners.
(PPL Electric)
Although PPL Electric does not directly sponsor any defined benefit plans, it is allocated a portion of the funded status and costs of plans sponsored by PPL Services based on its participation in those plans, which management believes are reasonable. The actuarially determined obligations of current active employees are used as a basis to allocate total plan activity, including active and retiree costs and obligations. PPL Electric's allocated share of the funded status of the pension plans resulted in a liability of $186 million and $259 million at December 31, 2011 and 2010. PPL Electric's allocated share of other postretirement benefits was a liability of $53 million and $57 million at December 31, 2011 and 2010.
(KU)
Although KU does not directly sponsor any defined benefit plans, it is allocated a portion of the funded status and costs of plans sponsored by LKE based on its participation in those plans, which management believes are reasonable. The actuarially determined obligations of current active employees and retired employees of KU are used as a basis to allocate total plan activity, including active and retiree costs and obligations. KU's allocated share of the funded status of the pension plans resulted in a liability of $83 million and $113 million at December 31, 2011 and 2010. KU's allocated share of other postretirement benefits was a liability of $62 million at December 31, 2011 and 2010.
Plan Assets - U.S. Pension Plans
(PPL, PPL Energy Supply, LKE and LG&E)
PPL's primary legacy pension plan and the pension plan in which employees of PPL Montana participate are invested in the PPL Services Corporation Master Trust that also includes a 401(h) account that is restricted for certain other postretirement benefit obligations. Through December 31, 2011, the plans sponsored by LKE were invested in Pension Trusts that also included a 401(h) account that is restricted for certain other postretirement benefit obligations. Effective January 1, 2012, the assets in the LKE Pension Trusts were transferred into the PPL Services Corporation Master Trust. The investment strategy for the master trust is to achieve a risk-adjusted return on a mix of assets that, in combination with PPL's funding policy, will ensure that sufficient assets are available to provide long-term growth and liquidity for benefit payments. The master trust benefits from a wide diversification of asset types, investment fund strategies and external investment fund managers, and therefore have no significant concentration of risk.
The investment policies of the PPL Services Corporation Master Trust and LG&E and KU Energy LLC Pension Trusts outline allowable investments and define the responsibilities of the EBPB and the external investment managers. The only prohibited investments are investments in debt or equity securities issued by PPL and its subsidiaries or PPL's pension plan
consultant. Derivative instruments may be utilized as a cost-effective means to mitigate risk and match the duration of investments to projected obligations. The investment policies are reviewed annually by PPL's Board of Directors.
The EBPB created a risk management framework around the trust assets and pension liabilities. This framework considers the trust assets as being composed of three sub-portfolios: the growth, immunizing and liquidity portfolios. The growth portfolio is comprised of investments that generate a return at a reasonable risk, including equity securities, certain debt securities and alternative investments. The immunizing portfolio consists of debt securities and derivative positions that will typically have long durations. The immunizing portfolio is designed to offset a portion of the change in the pension liabilities due to changes in interest rates. The liquidity portfolio consists primarily of cash and cash equivalents.
Target allocation ranges have been developed for each portfolio based on input from external consultants with a goal of limiting funded status volatility. The EBPB monitors the investments in each portfolio, and seeks to obtain a target portfolio that emphasizes reduction of risk of loss from market volatility. In pursuing that goal, the EBPB establishes revised guidelines from time to time. Revised EBPB investment guidelines as of the end of 2011 are presented below.
The asset allocation for the trusts and the target allocation by portfolio, at December 31 are as follows.
PPL Services Corporation Master Trust
(a) Includes commingled debt funds, which PPL treats as debt securities for asset allocation purposes.
(a)
Includes commingled debt funds, which LKE treats as debt securities for asset allocation purposes.
(b)
The asset allocation for this portfolio is not within the established target range due to the transition of assets at the end of 2011 in anticipation of transfer into the PPL Services Corporation Master Trust in January 2012.
Prior to the fourth quarter of 2011, the LKE trusts were managed using a different investment policy. As of December 31, 2010, the asset allocation was as follows.
(a) Includes commingled debt funds.
(PPL and PPL Energy Supply)
PPL Montana, a subsidiary of PPL Energy Supply, has a pension plan whose assets are solely invested in the PPL Services Corporation Master Trust, which is fully disclosed by PPL (below). The fair value of this plan's assets of $133 million at December 31, 2011 represents a 5% undivided interest in the assets and liabilities of this master trust, including each asset whose fair value measurement was determined using significant unobservable inputs (Level 3).
The fair value of net assets in the U.S. pension plan trusts by asset class and level within the fair value hierarchy was:
A reconciliation of U.S. pension trust assets classified as Level 3 at December 31, 2011 is as follows.
A reconciliation of U.S. pension trust assets classified as Level 3 at December 31, 2010 is as follows.
(PPL, PPL Energy Supply, LKE and LG&E)
The fair value measurements of cash and cash equivalents are based on the amounts on deposit.
The market approach is used to measure fair value of equity securities. The fair value measurements of equity securities (excluding commingled funds), which are generally classified as Level 1, are based on quoted prices in active markets. These securities represent actively and passively managed investments that are managed against various equity indices.
Investments in commingled funds are classified as Level 2 and categorized as equity securities. The fair value measurements are based on firm quotes of net asset values per share, which are not considered obtained from a quoted price in an active market. For the PPL Services Corporation Master Trust for 2011 and 2010 and the LG&E and KU Energy LLC Pension Trusts for 2011, these securities represent investments that are measured against the Russell 1000 Growth Index, the Russell 3000 Index and the MSCI EAFE Index. For the LG&E and KU Energy LLC Pension Trusts during 2010, these securities represent passively and actively managed investments in equity funds managed against the S&P 500 Index, the Russell 2500 Growth & Value Indexes and the MSCI EAFE Index.
The fair value measurements of debt securities are generally based on evaluated prices that reflect observable market information, such as actual trade information for identical securities or for similar securities, adjusted for observable differences. Debt securities are generally measured using a market approach, including the use of matrix pricing. Common inputs include reported trades; broker/dealer bid/ask prices, benchmark securities and credit valuation adjustments. When necessary, the fair value of debt securities is measured using the income approach, which incorporates similar observable inputs as well as benchmark yields, credit valuation adjustments, reference data from market research publications, monthly payment data, collateral performance and new issue data. For the PPL Services Corporation Master Trust, these securities represent investments in securities issued by U.S. Treasury and U.S. government sponsored agencies; investments securitized by residential mortgages, auto loans, credit cards and other pooled loans; investments in investment grade and non-investment grade bonds issued by U.S. companies across several industries; and investments in debt securities issued by foreign governments and corporations as well as commingled fund investments that are measured against the JP Morgan EMBI Global Diversified Index and the Barclays Long A or Better Index. During 2010 and the first ten months of 2011 for the LG&E and KU pension trusts, debt securities within commingled trusts were managed against the Barclays Aggregated Bond Index and the Barclays U.S. Government/Credit Long Index. During the last two months of 2011, the debt securities for the LG&E and KU pension trusts were transitioned to debt securities similar to those within the PPL Services Corporation Master Trust. The debt securities, excluding those in commingled funds, held by the PPL Services Corporation Master Trust at December 31, 2011 have a weighted-average coupon of 3.96% and a weighted-average maturity of 25 years.
Investments in real estate represent an investment in a partnership whose purpose is to manage investments in core U.S. real estate properties diversified geographically and across major property types (e.g., office, industrial, retail, etc.). The manager
is focused on properties with high occupancy rates with quality tenants. This results in a focus on high income and stable cash flows with appreciation being a secondary factor. Core real estate generally has a lower degree of leverage when compared with more speculative real estate investing strategies. The partnership has limitations on the amounts that may be redeemed based on available cash to fund redemptions. Additionally, the general partner may decline to accept redemptions when necessary to avoid adverse consequences for the partnership, including legal and tax implications, among others. The fair value of the investment is based upon a partnership unit value.
Investments in private equity represent interests in partnerships in multiple early-stage venture capital funds and private equity fund of funds that use a number of diverse investment strategies. Four of the partnerships have limited lives of ten years, while the fifth has a life of 15 years, after which liquidating distributions will be received. Prior to the end of each partnership's life, the investment cannot be redeemed with the partnership; however, the interest may be sold to other parties, subject to the general partner's approval. The PPL Services Corporation Master Trust has unfunded commitments of $83 million that may be required during the lives of the partnerships. Fair value is based on an ownership interest in partners' capital to which a proportionate share of net assets is attributed.
Investments in hedge fund of funds represent investments in two hedge fund of funds each with a different investment objective. Hedge funds seek a return utilizing a number of diverse investment strategies. The strategies, when combined aim to reduce volatility and risk while attempting to deliver positive returns under all market conditions. Major investment strategies for both hedge fund of funds include long/short equity, market neutral, distressed debt, and relative value. Generally, shares may be redeemed on 90 days prior written notice. Both funds are subject to short term lockups and have limitations on the amount that may be withdrawn based on a percentage of the total net asset value of the fund, among other restrictions. All withdrawals are subject to the general partner's approval. One fund's fair value has been estimated using the net asset value per share and the other fund's fair value is based on an ownership interest in partners' capital to which a proportionate share of net assets is attributed.
The fair value measurements of derivative instruments utilize various inputs that include quoted prices for similar contracts or market-corroborated inputs. In certain instances, these instruments may be valued using models, including standard option valuation models and standard industry models. These securities represent investments in To-be-announced debt securities and interest rate swaps. To-be-announced debt securities are commitments to purchase debt securities and are used as a cost effective means of managing the duration of assets in the trust. These commitments are valued by reviewing the issuing agency, program and coupon. Interest rate swaps are valued based on the swap details such as: swap curves, notional amount, index and term of index, reset frequency and payer/receiver credit ratings.
Receivables/payables classified as Level 1 represent investments sold/purchased but not yet settled. Receivables/payables classified as Level 2 represent interest and dividends earned but not yet received and costs incurred but not yet paid.
Insurance contracts, classified as Level 3, are held by the LG&E and KU Energy LLC Pension Trusts and represent an investment in an immediate participation guaranteed group annuity contract. The fair value is based on contract value, which represents cost plus interest income less distributions for benefit payments and administrative expenses.
Plan Assets - U.S. Other Postretirement Benefit Plans (PPL and LKE)
PPL's investment strategy with respect to its other postretirement benefit obligations is to fund VEBA trusts and 401(h) accounts with voluntary contributions and to invest in a tax efficient manner. Excluding the 401(h) accounts included in the PPL Services Corporation Master Trust and LG&E and KU Energy LLC Pension Trusts, discussed in Plan Assets - U.S. Pension Plans above, PPL's other postretirement benefit plans are invested in a mix of assets for long-term growth with an objective of earning returns that provide liquidity as required for benefit payments. These plans benefit from diversification of asset types, investment fund strategies and investment fund managers, and therefore, have no significant concentration of risk. The only prohibited investments are investments in debt or equity securities issued by PPL and its subsidiaries. Equity securities include investments in domestic large-cap commingled funds. Securities issued by commingled funds that invest entirely in debt securities are traded as equity units, but treated by PPL as debt securities for asset allocation and target allocation purposes. Securities issued by commingled money market funds that invest entirely in money market securities are traded as equity units, but treated by PPL as cash and cash equivalents for asset allocation and target allocation purposes. The asset allocation for the VEBA trusts and the target allocation, by asset class, at December 31, are detailed below.
(a)
Includes commingled debt funds and debt securities.
(b)
Includes commingled money market fund.
The fair value of assets in the U.S. other postretirement benefit plans by asset class and level within the fair value hierarchy was:
LKE's other postretirement benefit plans are invested primarily in a 401(h) account as disclosed in the LG&E and KU Energy LLC Pension Trusts Table.
Investments in large-cap equity securities represent investments in a passively managed equity index fund that invests in securities and a combination of other collective funds that together track the performance of the S&P 500 Index. Redemptions can be made daily on this fund.
Investments in commingled debt securities represent investments in a fund that invests in a diversified portfolio of investment grade money market instruments including, but not limited to, commercial paper, notes, repurchase agreements and other evidences of indebtedness with a maturity date not exceeding 13 months from date of purchase. Redemptions can be made weekly on this fund.
Investments in commingled money market funds represent investments in a fund that invests in securities and a combination of other collective funds that together are designed to track the performance of the Barclays Capital Long-term Treasury Index, as well as a fund that invests primarily in a diversified portfolio of investment grade money market instruments, including, but not limited to, commercial paper, notes, repurchase agreements and other evidences of indebtedness with a maturity not exceeding 13 months from the date of purchase. The primary objective of the fund is a high level of current income consistent with stability of principal and liquidity. Redemptions can be made daily on each of these funds.
Investments in municipalities represent investments in a diverse mix of tax-exempt municipal securities.
Receivables represent interest and dividends earned but not received as well as investments sold but not yet settled.
Plan Assets - U.K. Pension Plans (PPL)
The overall investment strategy of WPD's pension plans is developed by each plan's independent trustees in its Statement of Investment Principles in compliance with the U.K. Pensions Act of 1995 and other U.K. legislation. The trustees' primary focus is to ensure that assets are sufficient to meet members' benefits as they fall due with a longer term objective to reduce investment risk. The investment strategy is intended to maximize investment returns while not incurring excessive volatility in the funding position. WPD's plans are invested in a wide diversification of asset types, fund strategies and fund managers and therefore have no significant concentration of risk. Commingled funds that consist entirely of debt securities are traded as equity units, but treated by WPD as debt securities for asset allocation and target allocation purposes. These include investments in U.K. corporate bonds and U.K. gilts.
The asset allocation and target allocation at December 31 of WPD's pension plans are detailed below.
(a)
Includes commingled debt funds.
The fair value of assets in the U.K. pension plans by asset class and level within the fair value hierarchy was:
Except for investments in real estate, the fair value measurements of WPD's pension plan assets are based on the same inputs and measurement techniques used to measure the U.S. pension plan assets described above.
Investments in U.K. equity securities represent passively managed equity index funds that are measured against the FTSE All Share Index. Investments in European equity securities represent passively managed equity index funds that are measured against the FTSE Europe ex U.K. Index. Investments in Asian-Pacific equity securities represent passively managed equity index funds that aim to outperform 50% FTSE Asia Pacific ex-Japan Index and 50% FTSE Japan Index. Investments in North American equity securities represent passively managed index funds that are measured against the FTSE North America Index. Investments in emerging market equity securities represent passively managed equity index funds that are measured against the MSCI Emerging Markets Index. Investments in currency equity securities represent investments in unitized passive and actively traded currency funds. The Global Tactical Asset Allocation strategy attempts to benefit from short-term market inefficiencies by taking positions in worldwide markets with the objective to profit from relative movements across those markets.
Debt securities include investment grade corporate bonds of companies from diversified U.K. industries.
Investments in real estate represent holdings in a U.K. unitized fund that owns and manages U.K. industrial and commercial real estate with a strategy of earning current rental income and achieving capital growth. The fair value measurement of the fund is based upon a net asset value per share, which is based on the value of underlying properties that are independently appraised in accordance with Royal Institution of Chartered Surveyors valuation standards at least annually with quarterly valuation updates based on recent sales of similar properties, leasing levels, property operations and/or market conditions. The fund may be subject to redemption restrictions in the unlikely event of a large forced sale in order to ensure other unit holders are not disadvantaged.
Expected Cash Flows - U.S. Defined Benefit Plans (PPL)
PPL's U.S. defined benefit plans have the option to utilize available prior year credit balances to meet current and future contribution requirements. However, PPL contributed $207 million to its U.S. pension plans in January 2012 to meet minimum funding requirements.
PPL sponsors various non-qualified supplemental pension plans for which no assets are segregated from corporate assets. PPL expects to make approximately $28 million of benefit payments under these plans in 2012.
PPL is not required to make contributions to its other postretirement benefit plans but has historically funded these plans in amounts equal to the postretirement benefit costs recognized. Continuation of this past practice would cause PPL to contribute $28 million to its other postretirement benefit plans in 2012.
The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid and the following federal subsidy payments are expected to be received by the separate plan trusts.
(PPL Energy Supply)
The PPL Montana pension plan has the option to utilize available prior year credit balances to meet current and future contribution requirements. However, PPL Montana contributed $4 million to the plan in January 2012 to meet minimum funding requirements.
The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid by the separate plan trusts.
(LKE)
LKE's defined benefit plans have the option to utilize available prior year credit balances to meet current and future contribution requirements. However, LKE contributed $53 million to its pension plans in January 2012.
LKE sponsors various non-qualified supplemental pension plans for which no assets are segregated from corporate assets. LKE expects to make $2 million of benefit payments under these plans in 2012.
LKE is not required to make contributions to its other postretirement benefit plan but has historically funded this plan in amounts equal to the postretirement benefit costs recognized. Continuation of this past practice would cause LKE to contribute $13 million to its other postretirement benefit plan in 2012.
The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid and the following federal subsidy payments are expected to be received by the separate plan trusts.
(LG&E)
LG&E's defined benefit plan has the option to utilize available prior year credit balances to meet current and future contribution requirements. However, LG&E contributed $13 million to its pension plan in January 2012.
The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid by the separate plan trust.
Expected Cash Flows - U.K. Pension Plans (PPL)
The pension plans of WPD are subject to formal actuarial valuations every three years, which are used to determine funding requirements. Future contributions for PPL WW were evaluated in accordance with the latest valuation performed as of March 31, 2010, in respect of PPL WW's principal pension scheme, to determine contribution requirements for 2012 and forward. Future contributions for PPL WEM are based on the assumption that a valuation had occurred as of March 31, 2010, and the deficit repair plan was settled on a similar basis. WPD expects to make contributions of approximately $161 million in 2012. PPL WW and PPL WEM are currently permitted to recover in rates approximately 75% of their deficit funding requirements for their primary pension plans.
The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid by the separate plan trusts.
(PPL, PPL Energy Supply, PPL Electric and LKE)
Savings Plans
Substantially all employees of PPL's domestic subsidiaries are eligible to participate in deferred savings plans (401(k)s). Employer contributions to the plans were as follows.
The increase for PPL in 2011 and 2010 is primarily the result of PPL's acquisition of LKE and the employer contributions related to the employees of that company and its subsidiaries under their existing plans.
(PPL, PPL Energy Supply and PPL Electric)
Employee Stock Ownership Plan
Certain PPL subsidiaries sponsor a non-leveraged ESOP in which substantially all domestic employees, excluding those of PPL Montana, LKE and the mechanical contractors, are enrolled on the first day of the month following eligible employee status. Dividends paid on ESOP shares are treated as ordinary dividends by PPL. Under existing income tax laws, PPL is permitted to deduct the amount of those dividends for income tax purposes and to contribute the resulting tax savings (dividend-based contribution) to the ESOP.
The dividend-based contribution is used to buy shares of PPL's common stock and is expressly conditioned upon the deductibility of the contribution for federal income tax purposes. Contributions to the ESOP are allocated to eligible participants' accounts as of the end of each year, based 75% on shares held in existing participants' accounts and 25% on the eligible participants' compensation.
Compensation expense for ESOP contributions was $8 million in 2011, 2010 and 2009. These amounts were offset by the dividend-based contribution tax savings and had no impact on PPL's earnings.
PPL shares within the ESOP outstanding at December 31, 2011 were 7,867,977 or 1% of total common shares outstanding, and are included in all EPS calculations.
Separation Benefits
Certain PPL subsidiaries provide separation benefits to eligible employees. These benefits may be provided in the case of separations due to performance issues, loss of job related qualifications or organizational changes. Certain employees separated are eligible for cash severance payments, outplacement services, accelerated stock award vesting, continuation of group health and welfare coverage, and enhanced pension and postretirement medical benefits. The type and amount of benefits provided is based upon age, years of service and the nature of the separation. Separation benefits are recorded when such amounts are probable and estimable.
In February 2009, PPL announced workforce reductions that resulted in the elimination of approximately 200 management and staff positions across PPL's domestic operations, or approximately 6% of PPL's non-union, domestic workforce. The charges noted below consisted primarily of enhanced pension and severance benefits under PPL's Pension Plan and Separation Policy and were recorded primarily to "Other operation and maintenance" on the Statement of Income.
As a result of the workforce reductions, PPL recorded a charge of $22 million ($13 million after tax) in 2009.
PPL Energy Supply eliminated approximately 50 management and staff positions and recorded a charge of $13 million ($8 million after tax) in 2009. Included in this charge was $8 million ($4 million after tax) of allocated costs associated with the elimination of employees of PPL Services.
PPL Electric eliminated approximately 50 management and staff positions and recorded a charge of $9 million ($5 million after tax) in 2009. Included in this charge was $3 million ($1 million after tax) of allocated costs associated with the elimination of employees of PPL Services.
Separation benefits were not significant in 2010.
See Note 10 for separation benefits recorded in 2011 in connection with a reorganization following the acquisition of WPD Midlands.
(PPL, PPL Energy Supply, PPL Electric and LKE)
Health Care Reform
In March 2010, Health Care Reform was signed into law. Many provisions of Health Care Reform do not take effect for an extended period of time, and most will require the publication of implementing regulations and/or issuance of program guidelines.
Beginning in 2013, provisions within Health Care Reform eliminate the tax deductibility of retiree health care costs to the extent of federal subsidies received by plan sponsors that provide retiree prescription drug benefits equivalent to Medicare Part D Coverage. As a result, in 2010:
·
PPL decreased deferred tax assets by $13 million, increased regulatory assets by $9 million, increased deferred tax liabilities by $4 million and recorded income tax expense of $8 million;
·
PPL Energy Supply decreased deferred tax assets by $5 million and recorded income tax expense of $5 million; and
·
PPL Electric decreased deferred tax assets by $5 million, increased regulatory assets by $9 million and increased deferred tax liabilities by $4 million.
Other provisions within Health Care Reform that apply to PPL and its subsidiaries include:
·
an excise tax, beginning in 2018, imposed on high-cost plans providing health coverage that exceeds certain thresholds;
·
a requirement to extend dependent coverage up to age 26; and
·
broadening the eligibility requirements under the Federal Black Lung Act.
PPL and its subsidiaries have evaluated the provisions of Health Care Reform and have included the applicable provision in the valuation of those benefit plans that are impacted. The inclusion of the various provision of Health Care Reform did not have a material impact on the financial statements. PPL and its subsidiaries will continue to monitor the potential impact of any changes to the existing provisions and implementation guidance related to Health Care Reform on their benefit programs.
14. Jointly Owned Facilities
(PPL, PPL Energy Supply, LKE, LG&E and KU)
At December 31, 2011 and 2010, the Balance Sheets reflect the owned interests in the facilities listed below.
(a) These jointly owned facilities at LG&E and KU are entirely owned by LKE and thus are not jointly owned at the LKE or PPL level.
In addition to the interests mentioned above, PPL Montana has a 50% leasehold interest in Colstrip Units 1 and 2 and a 30% leasehold interest in Colstrip Unit 3 under operating leases. See Note 11 for additional information. At December 31, 2011 and 2010, NorthWestern owned a 30% leasehold interest in Colstrip Unit 4. PPL Montana and NorthWestern have a sharing agreement to govern each party's responsibilities regarding the operation of Colstrip Units 3 and 4, and each party is responsible for 15% of the respective operating and construction costs, regardless of whether a particular cost is specified to Colstrip Unit 3 or 4.
Each subsidiary owning these interests provides its own funding for its share of the facility. Each receives a portion of the total output of the generating plants equal to its percentage ownership. The share of fuel and other operating costs associated with the plants is included in the corresponding operating expenses on the Statements of Income.
15. Commitments and Contingencies
Energy Purchases, Energy Sales and Other Commitments
Energy Purchase Commitments
(PPL and PPL Energy Supply)
PPL Energy Supply enters into long-term purchase contracts to supply the fuel requirements and other costs of production for generation facilities. These contracts include commitments to purchase coal, emission allowances, limestone, natural gas, oil and nuclear fuel. These long-term contracts extend through 2023, with the exception of a limestone contract that extends through 2030. PPL Energy Supply also enters into long-term contracts for the storage and transportation of natural gas. The long-term natural gas storage contracts extend through 2015, and the long-term natural gas transportation contracts extend through 2032. PPL Energy Supply has entered into long-term contracts to purchase power that extend through 2017, with the exception of long-term power purchase agreements for the full output of two wind farms that extend through 2027. Additionally, PPL Energy Supply has entered into REC contracts that extend through 2038.
In 2008, PPL EnergyPlus acquired the rights to an existing long-term tolling agreement associated with the capacity and energy of Ironwood. Under the agreement, PPL EnergyPlus has control over the plant's dispatch into the electricity grid and supplies the natural gas necessary to operate the plant. The tolling agreement extends through 2021. See Note 11 for additional information.
(PPL, LKE, LG&E and KU)
LG&E and KU have a power purchase agreement with OVEC, extended in February 2011 to June 2040. FERC approval of the extension was received in May 2011, followed by KPSC and VSCC approvals in August 2011. Pursuant to the OVEC power purchase contract, LG&E and KU are responsible for their pro-rata share of certain obligations of OVEC under defined circumstances. These potential liabilities include unpaid OVEC indebtedness as well as shortfall amounts in certain excess decommissioning costs and other post-employment and post-retirement benefit costs other than pension. LKE's proportionate share of OVEC's outstanding debt was $117 million at December 31, 2011, consisting of LG&E's share of $81 million and KU's share of $36 million. Future obligations for power purchases from OVEC are unconditional demand payments, comprised of annual minimum debt service payments, as well as contractually required reimbursement of plant operating, maintenance and other expenses as follows:
In addition, LG&E and KU had total energy purchases under the OVEC power purchase agreement for the periods ended as follows:
LG&E and KU enter into purchase contracts to supply the coal and natural gas requirements for generation facilities and LG&E's gas supply operations. The coal contracts extend through 2016 and the natural gas contracts extend through 2013. LG&E and KU also enter into contracts for other coal related consumables, coal transportation and fleeting services, which
expire at different time periods through 2018. LG&E and KU also have transportation contracts for natural gas that extend through 2018.
(PPL and PPL Electric)
In 2009, the PUC approved PPL Electric's PLR energy procurement plan for the period January 2011 through May 2013. To date, PPL Electric has conducted ten of its 14 planned competitive solicitations. The solicitations include a mix of long-term and short-term purchases ranging from five months to ten years to fulfill PPL Electric's obligation to provide for customer supply as a PLR.
(PPL Energy Supply and PPL Electric)
See Note 16 for information on the power supply agreements between PPL EnergyPlus and PPL Electric.
Energy Sales Commitments
(PPL and PPL Energy Supply)
In connection with its marketing activities or hedging strategy for its power plants, PPL Energy Supply has entered into long-term power sales contracts that extend through 2024, excluding long-term retail sales agreements for the full output from solar generators that extend through 2036.
(PPL Energy Supply and PPL Electric)
See Note 16 for information on the power supply agreements between PPL EnergyPlus and PPL Electric.
PPL Montana Hydroelectric License Commitments (PPL and PPL Energy Supply)
PPL Montana owns and operates 11 hydroelectric facilities and one storage reservoir licensed by the FERC under long-term licenses pursuant to the Federal Power Act. Pursuant to Section 8(e) of the Federal Power Act, the FERC approved the transfer from Montana Power to PPL Montana of all pertinent licenses in connection with the Montana Asset Purchase Agreement.
The Kerr Dam Project license (50-year term) was jointly issued by the FERC to Montana Power and the Confederated Salish and Kootenai Tribes of the Flathead Nation in 1985, and requires PPL Montana (as successor licensee to Montana Power) to hold and operate the project for at least 30 years (to 2015). Between 2015 and 2025, the tribes have the option to purchase, hold and operate the project for the remainder of the license term, which expires in 2035. PPL Montana cannot predict if and when this option will be exercised. The license also requires PPL Montana to continue to implement a plan to mitigate the impact of the Kerr Dam on fish, wildlife and their habitats. Under this arrangement, PPL Montana has a remaining commitment to spend $8 million between 2012 and 2015, in addition to the annual rent it pays to the tribes.
PPL Montana entered into two Memoranda of Understanding (MOUs) with state, federal and private entities related to the issuance in 2000 of the FERC renewal license for the nine dams comprising the Missouri-Madison project. The MOUs are periodically updated and renewed and require PPL Montana to implement plans to mitigate the impact of its projects on fish, wildlife and their habitats, and to increase recreational opportunities. The MOUs were created to maximize collaboration between the parties and enhance the possibility to receive matching funds from relevant federal agencies. Under these arrangements, PPL Montana has a remaining commitment to spend $32 million between 2012 and 2040.
Legal Matters
(PPL, PPL Energy Supply, PPL Electric, LKE, LG&E and KU)
PPL and its subsidiaries are involved in legal proceedings, claims and litigation in the ordinary course of business. PPL and its subsidiaries cannot predict the outcome of such matters, or whether such matters may result in material liabilities, unless otherwise noted.
TC2 Construction (PPL, LKE, LG&E and KU)
In June 2006, LG&E and KU, as well as the Indiana Municipal Power Agency and Illinois Municipal Electric Agency (collectively, TC2 Owners), entered into a construction contract regarding the TC2 project. The contract is generally in the form of a turnkey agreement for the design, engineering, procurement, construction, commissioning, testing and delivery of
the project, according to designated specifications, terms and conditions. The contract price and its components are subject to a number of potential adjustments which may serve to increase or decrease the ultimate construction price. During 2009 and 2010, the TC2 Owners received several contractual notices from the TC2 construction contractor asserting historical force majeure and excusable event claims for a number of adjustments to the contract price, construction schedule, commercial operations date, liquidated damages or other relevant provisions. In September 2010, the TC2 Owners and the construction contractor agreed to a settlement to resolve the force majeure and excusable event claims occurring through July 2010, under the TC2 construction contract, which settlement provided for a limited, negotiated extension of the contractual commercial operations date and/or relief from liquidated damage calculations. With limited exceptions, the TC2 Owners took care, custody and control of TC2 in January 2011. Pursuant to certain amendments to the construction agreement, the contractor will complete modifications to the combustion system prior to certain dates to allow operation of TC2 on all specified fuels categories. The provisions of the construction agreement relating to liquidated damages were also amended. In September 2011, the TC2 Owners and the construction contractor entered into a further amendment to the construction agreement settling, among other matters, certain historical change order, labor rate and prior liquidated damages amounts. The remaining issues are still under discussion with the contractor. PPL, LKE, LG&E and KU cannot currently predict the outcome of this matter or the potential impact on the capital costs of this project.
(PPL and PPL Energy Supply)
Spent Nuclear Fuel Litigation
Federal law requires the U.S. government to provide for the permanent disposal of commercial spent nuclear fuel, but there is no definitive date by which a repository will be operational. As a result, it was necessary to expand Susquehanna's on-site spent fuel storage capacity. To support this expansion, PPL Susquehanna contracted for the design and construction of a spent fuel storage facility employing dry cask fuel storage technology. The facility is modular, so that additional storage capacity can be added as needed. The facility began receiving spent nuclear fuel in 1999. PPL Susquehanna estimates that there is sufficient storage capacity in the spent nuclear fuel pools and the on-site dry cask storage facility at Susquehanna to accommodate spent fuel discharged through approximately 2017 under current operating conditions. If necessary, on-site dry cask storage capability can be expanded, assuming appropriate regulatory approvals are obtained, such that, together, the spent fuel pools and the expanded dry fuel storage facilities will accommodate all of the spent fuel expected to be discharged through the current licensed life of each unit, 2042 for Unit 1 and 2044 for Unit 2.
In 1996, the U.S. Court of Appeals for the District of Columbia Circuit (D.C. Circuit Court) ruled that the Nuclear Waste Policy Act imposed on the DOE an unconditional obligation to begin accepting spent nuclear fuel on or before January 31, 1998. In 1997, the D.C. Circuit Court ruled that the contracts between the utilities and the DOE provide a potentially adequate remedy if the DOE failed to begin accepting spent nuclear fuel by January 31, 1998. The DOE did not, in fact, begin to accept spent nuclear fuel by that date. The DOE continues to contest claims that its breach of contract resulted in recoverable damages. In January 2004, PPL Susquehanna filed suit in the U.S. Court of Federal Claims for unspecified damages suffered as a result of the DOE's breach of its contract to accept and dispose of spent nuclear fuel. In May 2011, the parties entered into a settlement agreement which resolved all claims of PPL Susquehanna through December 2013. Under the settlement agreement, PPL Susquehanna received $50 million for its share of claims to recover costs to store spent nuclear fuel at the Susquehanna plant through September 30, 2009, and recognized a credit to "Fuel" expense in the second quarter of 2011. PPL Susquehanna also will be eligible to receive payment of annual claims for allowed costs, as set forth in the settlement agreement, that are incurred thereafter through the December 31, 2013 termination date of the settlement agreement. In exchange, PPL Susquehanna has waived any claims against the United States government for costs paid or injuries sustained related to storing spent nuclear fuel at the Susquehanna plant through December 31, 2013.
Montana Hydroelectric Litigation
In November 2004, PPL Montana, Avista Corporation (Avista) and PacifiCorp commenced an action for declaratory judgment in Montana First Judicial District Court seeking a determination that no lease payments or other compensation for their hydroelectric facilities' use and occupancy of certain riverbeds in Montana can be collected by the State of Montana. This lawsuit followed dismissal on jurisdictional grounds of an earlier federal lawsuit seeking such compensation in the U.S. District Court of Montana. The federal lawsuit alleged that the beds of Montana's navigable rivers became state-owned trust property upon Montana's admission to statehood, and that the use of them should, under a 1931 regulatory scheme enacted after all but one of the hydroelectric facilities in question were constructed, trigger lease payments for use of land beneath. In July 2006, the Montana state court approved a stipulation by the State of Montana that it was not seeking compensation for the period prior to PPL Montana's December 1999 acquisition of the hydroelectric facilities.
Following a number of adverse trial court rulings, in 2007 Pacificorp and Avista each entered into settlement agreements with the State of Montana providing, in pertinent part, that each company would make prospective lease payments for use of
the State's navigable riverbeds (subject to certain future adjustments), resolving the State's claims for past and future compensation.
Following an October 2007 trial of this matter on damages, in June 2008, the Montana District Court awarded the State retroactive compensation of approximately $35 million for the 2000-2006 period and approximately $6 million for 2007 compensation. Those unpaid amounts continued to accrue interest at 10% per year. The Montana District Court also deferred determination of compensation for 2008 and future years to the Montana State Land Board. In October 2008, PPL Montana appealed the decision to the Montana Supreme Court, requesting a stay of judgment and a stay of the Land Board's authority to assess compensation for 2008 and future periods.
In 2009, PPL Montana adjusted its previously recorded accrual by $8 million, $5 million after tax. Of this total, $5 million, $3 million after tax, related to prior periods. In March 2010, the Montana Supreme Court substantially affirmed the June 2008 Montana District Court decision. As a result, in the first quarter of 2010, PPL Montana recorded a charge of $56 million ($34 million after tax or $0.08 per share, basic and diluted, for PPL), representing estimated rental compensation for the first quarter of 2010 and prior years, including interest. Rental compensation was estimated for periods subsequent to 2007. The portion of the pre-tax charge that related to prior years totaled $54 million ($32 million after tax). The charge recorded on the Statement of Income was $49 million in "Other operation and maintenance" and $7 million in "Interest Expense." PPL Montana continued to accrue interest expense for the prior years and rent expense for the subsequent years.
In August 2010, PPL Montana filed a petition for a writ of certiorari with the U.S. Supreme Court requesting review of this matter. In June 2011, the U.S. Supreme Court granted PPL Montana's petition. Oral argument was held in December 2011 and on February 22, 2012, the U.S. Supreme Court issued a decision overturning the Montana Supreme Court decision and remanded the case to the Montana Supreme Court for further proceedings consistent with the U.S. Supreme Court's opinion. As a result, PPL Montana reversed its total loss accrual of $89 million ($53 million after-tax or $0.09 per share, basic and diluted for PPL), which had been recorded prior to the U.S. Supreme Court decision. The amount reversed was recorded on the Statements of Income as a $75 million credit to "Other operation and maintenance" and a $14 million credit to "Interest Expense." PPL Montana believes the U.S. Supreme Court decision resolves certain questions of liability in this case in favor of PPL Montana and leaves open for reconsideration by Montana courts, consistent with the findings of the U.S. Supreme Court, certain other questions. The State of Montana has 30 days from February 22, 2012 to petition the U.S. Supreme Court for a rehearing. PPL Montana has concluded it is no longer probable, but it remains reasonably possible, that a loss has been incurred. While unable to estimate a range of loss, PPL Montana believes that any such amount would not be material.
Bankruptcy of Southern Montana Electric Generation and Transmission Cooperative, Inc.
On October 21, 2011, SMGT, a Montana cooperative and purchaser of electricity under a long-term supply contract with PPL EnergyPlus expiring in June 2019 (SMGT Contract), filed for protection under Chapter 11 of the U.S. Bankruptcy Code in the U.S. Bankruptcy Court in Montana. At the time of the bankruptcy filing, SMGT was PPL EnergyPlus' largest customer.
The SMGT Contract provides for fixed volume purchases on a monthly basis at established prices. A trustee has been appointed for SMGT's estate in the bankruptcy proceeding, and PPL EnergyPlus has been involved in preliminary discussions with the trustee concerning possible modifications to the SMGT Contract as part of the bankruptcy reorganization. Pursuant to a court order and subsequent stipulations entered into by SMGT and PPL EnergyPlus, since the date of its Chapter 11 filing through January 2012, SMGT continued to purchase electricity from PPL EnergyPlus at the price specified in the SMGT Contract, and has made timely payments for such purchases, but at lower volumes than as prescribed in the SMGT Contract. During January 2012, the trustee notified PPL EnergyPlus that SMGT would not purchase electricity under the SMGT Contract for the month of February. In addition, the trustee requested PPL EnergyPlus to leave the SMGT Contract in place to permit SMGT to purchase electricity in the event its requirements were not met by third-party providers from whom the trustee intends to purchase power on behalf of SMGT, at prices more favorable than under the SMGT Contract, for future periods. PPL EnergyPlus is evaluating the trustee's request.
PPL EnergyPlus' damage claim under the SMGT Contract totaled approximately $11 million at December 31, 2011, all of which has been fully reserved. No assurance can be given as to the collectability of these damages.
At the present time, PPL cannot predict whether SMGT will be successful in its attempts to reorganize its business under Chapter 11 of the U.S. Bankruptcy Code or the extent to which the SMGT Contract may be modified as part of a successful Chapter 11 reorganization and, in either case, PPL cannot presently predict the extent to which it will be able to market to third parties any amount of power that SMGT ultimately does not continue to purchase from PPL EnergyPlus.
Regulatory Issues
(PPL, PPL Electric, LKE, LG&E and KU)
See Note 6 for information on regulatory matters related to utility rate regulation.
Enactment of Financial Reform Legislation (PPL, PPL Energy Supply, PPL Electric, LKE, LG&E and KU)
In July 2010, the Dodd-Frank Act was signed into law. The Dodd-Frank Act includes provisions that impose derivative transaction reporting requirements and require most over-the-counter derivative transactions to be executed through an exchange and to be centrally cleared. The Dodd-Frank Act also provides that the CFTC may impose collateral and margin requirements for over-the-counter derivative transactions, as well as capital requirements for certain entity classifications. Final rules on major provisions in the Dodd-Frank Act are being established through rulemakings, and the CFTC generally has postponed implementation until the later of July 16, 2012 or when required key final rules are issued (e.g. definitional rules for "swap" and "swap dealer"). In order to comply with implementing regulations of the Dodd-Frank Act, the Registrants likely will be faced with significant new recordkeeping and reporting requirements. Also, the Registrants could face significantly higher operating costs or may be required to post additional collateral if they are subject to margin requirements as ultimately adopted in the implementing regulations of the Dodd-Frank Act. The Registrants will continue to evaluate the provisions of the Dodd-Frank Act. At this time, the Registrants cannot predict the impact that the law or its implementing regulations will have on their businesses or operations, or the markets in which they transact business, but could incur material costs related to compliance with the Dodd-Frank Act.
New Jersey Capacity Legislation (PPL, PPL Energy Supply and PPL Electric)
In January 2011, New Jersey enacted a law that intervenes in the wholesale capacity market exclusively regulated by the FERC: S. No. 2381, 214th Leg. (N.J. 2011) (the Act). To create incentives for the development of new, in-state electric generation facilities, the Act implements a "long-term capacity agreement pilot program (LCAPP)." The Act requires New Jersey utilities to pay a guaranteed fixed price for wholesale capacity, imposed by the New Jersey Board of Public Utilities (BPU), to certain new generators participating in PJM, with the ultimate costs of that guarantee to be borne by New Jersey ratepayers. PPL believes the intent and effect of the LCAPP is to encourage the construction of new generation in New Jersey even when, under the FERC-approved PJM economic model, such new generation would not be economic. The Act could depress capacity prices in PJM in the short term, impacting PPL Energy Supply's revenues, and harm the long-term ability of the PJM capacity market to incent necessary generation investment throughout PJM. In February 2011, the PJM Power Providers Group (P3), an organization in which PPL is a member, filed a complaint before the FERC seeking changes in PJM's capacity market rules designed to ensure that subsidized generation, such as may result from the implementation of the LCAPP, will not be able to set capacity prices artificially low as a result of their exercise of buyer market power. In April 2011, the FERC issued an order granting in part and denying in part P3's complaint and ordering changes in PJM's capacity rules consistent with a significant portion of P3's requested changes. PPL, PPL Energy Supply and PPL Electric cannot predict the outcome of this proceeding or the economic impact on their businesses or operations, or the markets in which they transact business.
In addition, in February 2011, PPL, and several other generating companies and utilities filed a complaint in U.S. District Court in New Jersey challenging the Act on the grounds that it violates well-established principles under the Supremacy Clause and the Commerce Clause of the U.S. Constitution. In this action, the plaintiffs request declaratory and injunctive relief barring implementation of the Act by the Commissioners of the BPU. In October 2011, the court denied the BPU's motion to dismiss the proceeding and the litigation is moving forward. PPL, PPL Energy Supply and PPL Electric cannot predict the outcome of this proceeding or the economic impact on their businesses or operations, or the markets in which they transact business.
Pacific Northwest Markets (PPL and PPL Energy Supply)
Through its subsidiaries, PPL Energy Supply made spot market bilateral sales of power in the Pacific Northwest during the period from December 2000 through June 2001. Several parties subsequently claimed refunds at FERC as a result of these sales. In June 2003, the FERC terminated proceedings to consider whether to order refunds for spot market bilateral sales made in the Pacific Northwest, including sales made by PPL Montana, during the period December 2000 through June 2001. In August 2007, the U.S. Court of Appeals for the Ninth Circuit reversed the FERC's decision and ordered the FERC to consider additional evidence. In October 2011, FERC initiated proceedings to consider additional evidence.
Although PPL and its subsidiaries believe that they have not engaged in any improper trading or marketing practices affecting the Pacific Northwest markets, PPL and PPL Energy Supply cannot predict the outcome of the above-described proceedings or whether any subsidiaries will be the subject of any additional governmental investigations or named in other lawsuits or refund proceedings. Consequently, PPL and PPL Energy Supply cannot estimate a range of reasonably possible losses, if any, related to this matter.
(PPL, PPL Energy Supply, PPL Electric, LKE, LG&E and KU)
FERC Market-Based Rate Authority
In November 1998, the FERC authorized LG&E and KU and, in December 1998, authorized PPL EnergyPlus to make wholesale sales of electric power and related products at market-based rates. In those orders, the FERC directed LG&E and KU and PPL EnergyPlus, respectively, to file an updated market analysis within three years after the order, and every three years thereafter. Since then, periodic market-based rate filings with the FERC have been made by LG&E, KU, PPL EnergyPlus, PPL Electric, PPL Montana and most of PPL Generation's subsidiaries. These filings consisted of a Northwest market-based rate filing for PPL Montana and a Northeast market-based rate filing for most of the other PPL subsidiaries in PJM's region. In June 2011, FERC approved PPL's market-based rate update for the Eastern region and PPL's market-based rate update for the Western region. Also, in June 2011, PPL filed its market-based rate update for the Southeast region, including LG&E and KU in addition to PPL EnergyPlus. In June 2011, the FERC issued an order approving LG&E's and KU's request for a determination that they no longer be deemed to have market power in the Big Rivers Electric Corporation balancing area and removing restrictions on their market-based rate authority in such region.
Currently, a seller granted FERC market-based rate authority may enter into power contracts during an authorized time period. If the FERC determines that the market is not workably competitive or that the seller possesses market power or is not charging "just and reasonable" rates, it may institute prospective action, but any contracts entered into pursuant to the FERC's market-based rate authority remain in effect and are generally subject to a high standard of review before the FERC can order changes. Recent court decisions by the U.S. Court of Appeals for the Ninth Circuit have raised issues that may make it more difficult for the FERC to continue its program of promoting wholesale electricity competition through market-based rate authority. These court decisions permit retroactive refunds and a lower standard of review by the FERC for changing power contracts, and could have the effect of requiring the FERC in advance to review most, if not all, power contracts. In June 2008, the U.S. Supreme Court reversed one of the decisions of the U.S. Court of Appeals for the Ninth Circuit, thereby upholding the higher standard of review for modifying contracts. At this time, PPL, PPL Energy Supply, LKE, LG&E and KU cannot predict the impact of these court decisions on the FERC's future market-based rate authority program or on their businesses.
Energy Policy Act of 2005 - Reliability Standards
The NERC is responsible for establishing and enforcing mandatory reliability standards (Reliability Standards) regarding the bulk power system. The FERC oversees this process and independently enforces the Reliability Standards.
The Reliability Standards have the force and effect of law and apply to certain users of the bulk power electricity system, including electric utility companies, generators and marketers. The FERC has indicated it intends to vigorously enforce the Reliability Standards using, among other means, civil penalty authority. Under the Federal Power Act, the FERC may assess civil penalties of up to $1 million per day, per violation, for certain violations. The first group of Reliability Standards approved by the FERC became effective in June 2007.
LG&E, KU, PPL Electric and certain subsidiaries of PPL Energy Supply monitor their compliance with the Reliability Standards and continue to self-report potential violations of certain applicable reliability requirements and submit accompanying mitigation plans, as required. The resolution of a number of potential violations is pending. Any regional reliability entity determination concerning the resolution of violations of the Reliability Standards remains subject to the approval of the NERC and the FERC. The Registrants cannot predict the outcome of these matters, and cannot estimate a range of reasonably possible losses, if any, other than the amounts currently recorded.
In the course of implementing its program to ensure compliance with the Reliability Standards by those PPL affiliates subject to the standards, certain other instances of potential non-compliance may be identified from time to time.
Environmental Matters - Domestic
(PPL, PPL Energy Supply, PPL Electric, LKE, LG&E and KU)
Due to the environmental issues discussed below or other environmental matters, PPL subsidiaries may be required to modify, curtail, replace or cease operating certain facilities or operations to comply with statutes, regulations and other requirements of regulatory bodies or courts.
(PPL, PPL Energy Supply, LKE, LG&E and KU)
Air
The Clean Air Act addresses, among other things, emissions causing acid deposition, installation of best available control technologies for new or substantially modified sources, attainment of national ambient air quality standards, toxic air emissions and visibility standards in the U.S. Amendments to the Clean Air Act requiring additional emission reductions have been proposed but are unlikely to be introduced or passed in this Congress. The Clean Air Act allows states to develop more stringent regulations and in some instances, as discussed below, Kentucky, Pennsylvania and Montana have done so.
To comply with air-related requirements and other environmental requirements as described below, PPL's forecast for capital expenditures reflects a best estimate projection of expenditures that may be required within the next five years. Such projections are a combined $3.1 billion for LG&E and KU. These projections include $100 million for LG&E and $400 million for KU associated with currently approved ECR plans through 2013 to achieve emissions reductions and manage coal combustion residuals. The projections also include $1.4 billion for LG&E and $900 million for KU associated with the recently approved 2011 ECR Plans for additional expenditures to comply with new clean air rules and manage coal combustion residuals and an additional $300 million for other environmental expenditures. Such projections for PPL Energy Supply are $130 million. Actual costs (including capital, allowance purchases and operational modifications) may be significantly lower or higher depending on the final requirements and market conditions. Certain environmental compliance costs incurred by LG&E and KU in serving KPSC jurisdictional customers are subject to recovery through the ECR. See Note 6 for additional information on LG&E and KU's ECR plan.
CSAPR (formerly Clean Air Transport Rule)
In July 2011, the EPA signed the CSAPR, which finalizes and renames the Clean Air Transport Rule (Transport Rule) proposed in August 2010, and made revisions to the rule on February 7, 2012. The CSAPR replaces the EPA's previous Clean Air Interstate Rule (CAIR) which was struck down by the U.S. Court of Appeals for the District of Columbia Circuit (the Court) in July 2008. CAIR subsequently was effectively reinstated by the Court in December 2008, pending finalization of the Transport Rule. Like CAIR and the proposed Transport Rule, the CSAPR only applies to PPL's coal generation facilities located in Kentucky and Pennsylvania.
The CSAPR is meant to facilitate attainment of ambient air quality standards for ozone and fine particulates by requiring reductions in sulfur dioxide and nitrogen oxides. The CSAPR established new sulfur dioxide emission allowance cap and trade programs that are completely independent of, and more stringent than, the current Acid Rain Program. The CSAPR also established new nitrogen oxides emission allowance cap and trade programs to replace the current programs. All trading is more restrictive than previously under CAIR. The CSAPR provides for two-phased programs of sulfur dioxide and nitrogen oxide emissions reductions, with initial reductions in 2012 and more stringent reductions in 2014.
In December 2011, the Court stayed implementation of the CSAPR and left CAIR in effect pending a final resolution on the merits of the validity of the rule. Oral argument on the various challenges to the CSAPR is scheduled for April 2012, and a final decision on the validity of the rule could be released as early as May 2012.
With respect to the Kentucky coal-fired generating plants, the stay of the CSAPR will initially only impact the unit dispatch order. With the return of the CAIR and the Kentucky companies' significant number of sulfur dioxide allowances, those units will be dispatched with lower operating cost, but slightly higher sulfur dioxide and nitrogen oxide emissions. However, a key component of the Court's final decision, even if the CSAPR is upheld, will be whether the ruling delays the implementation of the CSAPR by one year for both Phases I and II, or instead still requires the significant sulfur dioxide and nitrogen oxide reductions associated with Phase II to begin in 2014. LG&E's and KU's CSAPR compliance strategy is based on over-compliance during Phase I to generate allowances sufficient to cover the expected shortage during the first two years of Phase II (2014 and 2015) when additional pollution control equipment will be installed. Should Phase I of the CSAPR be shortened to one year, it will be more difficult and costly to provide enough excess allowances in one year to meet the shortage projected for 2014 and 2015.
PPL Energy Supply's coal fired power plants can meet both the CAIR and the proposed CSAPR sulfur dioxide emission requirements with the existing scrubbers that went in-service in 2008 and 2009. For nitrogen oxide, under both the CAIR and the proposed CSAPR, PPL Energy Supply would need to buy allowances or make operational changes, the cost of which is not anticipated to be significant.
National Ambient Air Quality Standards
In addition to the reductions in sulfur dioxide and nitrogen oxide emissions required under the CSAPR for the Pennsylvania and Kentucky plants, PPL's coal plants, including those in Montana, may face further reductions in sulfur dioxide and
nitrogen oxide emissions as a result of more stringent national ambient air quality standards for ozone, nitrogen oxide, sulfur dioxide and/or fine particulates. The EPA has recently finalized a new one-hour standard for sulfur dioxide, and states are required to identify areas that meet those standards and areas that are in non-attainment. For non-attainment areas, states are required to develop plans by 2014 to achieve attainment by 2017. For areas in attainment or that are unclassifiable, states are required to develop maintenance plans by mid-2013 that demonstrate continued attainment. PPL, PPL Energy Supply, LKE, LG&E and KU anticipate that some of the measures required for compliance with the CSAPR such as upgraded or new sulfur dioxide scrubbers at some of their plants or, in the case of LG&E and KU, upgraded or new sulfur dioxide scrubbers at the Mill Creek plant and retirement of the Cane Run, Green River, and Tyrone plants, will also be necessary to achieve compliance with the new one-hour sulfur dioxide standard. If additional reductions were to be required, the economic impact could be significant.
Mercury and Other Hazardous Air Pollutants
In May 2011, the EPA published a proposed regulation providing for stringent reductions of mercury and other hazardous air pollutants. On February 16, 2012, the EPA published the final rule, known as the Mercury and Air Toxics Standards (MATS), with an effective date of April 16, 2012. The rule provides for a three-year compliance deadline with the potential for a one-year extension as provided under the statute. Based on their assessment of the need to install pollution control equipment to meet the provisions of the proposed rule, LG&E and KU filed requests with the KPSC for environmental cost recovery to facilitate moving forward with plans to install environmental controls including sorbent injection and fabric-filter baghouses to remove certain hazardous air pollutants. Recovery of the cost of certain controls was granted by KPSC order issued in December 2011. The cost for these controls is reflected in the combined costs of $3.1 billion for LG&E and KU noted under "Air" above. LG&E and KU have also announced the anticipated retirement of coal-fired generating units at the Cane Run, Green River, and Tyrone plants and have filed requests with the KPSC for replacement of those units with natural gas-fired generating units to be constructed or purchased. With the publication of the final MATS rule, LG&E and KU are currently assessing whether changes in the final rule warrant revision of their approved compliance plans. With respect to PPL Energy Supply's Pennsylvania plants, PPL believes that these plants are reasonably well controlled and require installation of chemical additive systems, the cost of which is not expected to be material. With respect to PPL Montana plants, modifications to the current air pollution controls installed on Colstrip may be required, the cost of which also is not expected to be material. For the Corette plant, additional controls are being evaluated, the cost of which could be significant. PPL Energy Supply, LG&E and KU are continuing to conduct in-depth reviews of the MATS.
Regional Haze and Visibility
In January 2012, the EPA proposed limited approval of the Pennsylvania Regional Haze State Implementation Plan. That proposed action would essentially approve PPL's analysis that further particulate controls at PPL Energy Supply's Pennsylvania plants are not warranted. The limited approval does not address deficiencies of the state plan arising from the remand of the CAIR rule. Previously, the EPA had determined that implementation of the CAIR requirements would meet regional haze BART (Best Available Retrofit Technology) requirements for sulfur dioxide and nitrogen oxides. In December 2011, the EPA proposed that implementation of the CSAPR would also meet the BART. This is expected to address that deficiency.
In Montana, the EPA Region 8 is developing the regional haze plan as the Montana Department of Environmental Quality declined to develop a BART state implementation plan at this time. PPL submitted to the EPA its analyses of the visibility impacts of sulfur dioxide, nitrogen oxides and particulate matter emissions for Colstrip Units 1 and 2 and Corette. PPL's analyses concluded that further reductions are not warranted. The EPA responded to PPL's reports for Colstrip and Corette and requested further information and analysis. PPL completed further analysis and submitted addendums to its initial reports for Colstrip and Corette. In February 2009, PPL received an information request for data related to the non-BART-affected emission sources of Colstrip Units 3 and 4. PPL responded to this request in March 2009.
In November 2010, PPL Montana received a request from the EPA Region 8, under the EPA's Reasonable Further Progress goals of the Regional Haze Rules, to provide further analysis with respect to Colstrip Units 3 and 4. PPL completed a high-level analysis of various control options to reduce emissions of sulfur dioxide and particulate matter for these units, and submitted that analysis to the EPA in January 2011. The analysis shows that any incremental reductions would not be cost effective and that further analysis is not warranted. PPL also concluded that further analysis for nitrogen oxides was not justifiable as these units installed controls under a Consent Decree in which the EPA had previously agreed that, when implemented, would satisfy the requirements for installing the BART for nitrogen oxides. The EPA is expected to issue a proposed Federal Implementation Plan for Montana in March 2012. Discussions with the EPA are ongoing with respect to this issue.
PPL and PPL Energy Supply cannot predict whether any additional reductions in emissions will be required in Pennsylvania or Montana. If additional reductions are required, the economic impact could be significant depending on what is required.
LG&E and KU also submitted analyses of the visibility impacts of their Kentucky BART-eligible sources to the Kentucky Division for Air Quality (KDAQ). Only LG&E's Mill Creek plant was determined to have a significant regional haze impact. The KDAQ has submitted a regional haze state implementation plan (SIP) to the EPA which requires the Mill Creek plant to reduce its sulfuric acid mist emissions from Units 3 and 4. After approval of the Kentucky SIP by the EPA and revision of the Mill Creek plant's Title V air permit, LG&E intends to install sorbent injection controls at the plant to reduce sulfuric acid mist emissions. In the event that the EPA determines that compliance with the CSAPR would be insufficient to meet the BART requirements, it would be necessary for LG&E and KU to reassess their planned compliance measures.
New Source Review (NSR)
The NSR regulations require major new or modified sources of regulated pollutants to receive pre-construction and operating permits with limits that prevent the significant deterioration of air quality in areas that are in attainment of the ambient air quality standards for certain pollutants.
The EPA has continued its NSR enforcement efforts targeting coal-fired generating plants. The EPA has asserted that modification of these plants has increased their emissions and, consequently, that they are subject to stringent NSR requirements under the Clean Air Act. In April 2009, PPL received EPA information requests for its Montour and Brunner Island plants. The requests are similar to those that PPL received several years ago for its Colstrip, Corette and Martins Creek plants. PPL and the EPA have exchanged certain information regarding this matter. In January 2009, PPL and other companies that own or operate the Keystone plant in Pennsylvania received a notice of violation from the EPA alleging that certain projects were undertaken without proper NSR compliance. PPL and PPL Energy Supply cannot predict the outcome of these matters, and cannot estimate a range of reasonably possible losses, if any.
In addition, in August 2007, LG&E and KU received information requests for their Mill Creek, Trimble County, and Ghent plants, but have received no further communications from the EPA since providing their responses. PPL, LKE, LG&E and KU cannot predict the outcome of these matters, and cannot estimate a range of reasonably possible losses, if any.
In March 2009, KU received a notice alleging that KU violated certain provisions of the Clean Air Act's rules governing NSR and prevention of significant deterioration by installing sulfur dioxide scrubbers and SCR controls at its Ghent generating plant without assessing potential increased sulfuric acid mist emissions. KU contends that the work in question, as pollution control projects, was exempt from the requirements cited by the EPA. In December 2009, the EPA issued an information request on this matter. KU has exchanged settlement proposals and other information with the EPA regarding imposition of additional permit limits and emission controls and anticipates continued settlement negotiations. In addition, any settlement or future litigation could potentially encompass a September 2007 notice of violation alleging opacity violations at the plant. Depending on the provisions of a final settlement or the results of litigation, if any, resolution of this matter could involve significant increased operating and capital expenditures. PPL, LKE and KU cannot predict the final outcome of this matter, but currently do not expect such outcome to result in material losses above the respective amounts accrued by KU.
If PPL subsidiaries are found to have violated NSR regulations, PPL would, among other things, be required to meet permit limits reflecting Best Available Control Technology (BACT) for the emissions of any pollutant found to have significantly increased due to a major plant modification. The costs to meet such limits, including installation of technology at certain units, could be significant.
States and environmental groups also have initiated enforcement actions and litigation alleging violations of the NSR regulations by coal-fired plants, and PPL is unable to predict whether such actions will be brought against any of PPL's plants.
TC2 Air Permit (PPL, LKE, LG&E and KU)
The Sierra Club and other environmental groups petitioned the Kentucky Environmental and Public Protection Cabinet to overturn the air permit issued for the TC2 baseload generating unit, but the agency upheld the permit in an Order issued in September 2007. In response to subsequent petitions by environmental groups, the EPA ordered certain non-material changes to the permit which were incorporated into a final revised permit issued by the KDAQ in January 2010. In March 2010, the environmental groups petitioned the EPA to object to the revised state permit. Until the EPA issues a final ruling on the pending petition and all available appeals are exhausted, PPL, LKE, LG&E and KU cannot currently predict the outcome of this matter or the potential impact on the capital costs of this project, if any.
(PPL, PPL Energy Supply, LKE, LG&E and KU)
Global Climate Change
There is concern nationally and internationally about global climate change and the possible contribution of GHG emissions including, most significantly, carbon dioxide, from the combustion of fossil fuels. This has resulted in increased demands for carbon dioxide emission reductions from investors, environmental organizations, government agencies and the international community. These demands and concerns have led to federal legislative proposals, actions at regional, state and local levels, litigation relating to GHG emissions and the EPA regulations on GHGs.
Greenhouse Gas Legislation
While climate change legislation was considered during the 111th Congress, the outcome of the 2010 elections has halted the debate on such legislation in the current 112th Congress. The timing and elements of any future legislation addressing GHG emission reductions are uncertain at this time. In the current Congress, legislation barring the EPA from regulating GHG emissions under the existing authority of the Clean Air Act has been passed by the U.S. House of Representatives. Various bills providing for barring or delaying the EPA from regulating GHG emissions have been introduced in the U.S. Senate, but the prospects for passage of such legislation remain uncertain. At the state level, the 2010 elections in Pennsylvania have also reduced the likelihood of GHG legislation in the near term, and there are currently no prospects for such legislation in Kentucky or Montana.
Greenhouse Gas Regulations and Tort Litigation
As a result of the April 2007 U.S. Supreme Court decision that the EPA has the authority to regulate GHG emissions from new motor vehicles under the Clean Air Act, in April 2010, the EPA and the U.S. Department of Transportation issued new light-duty vehicle emissions standards that apply to 2012 model year vehicles. The EPA has also clarified that this standard triggers regulation of GHG emissions from stationary sources under the NSR and Title V operating permit provisions of the Clean Air Act starting in 2011. This means that any new sources or major modifications to existing sources causing a net significant emissions increase requires the BACT permit limits for GHGs. The EPA recently proposed guidance for conducting a BACT analysis for projects that trigger such a review. In addition, New Source Performance Standards for new and existing power plants were expected to be proposed in September 2011 and finalized in May 2012, but this has been delayed. The EPA is expected to announce a new schedule for this rulemaking in the future.
At the regional level, ten northeastern states signed a Memorandum of Understanding (MOU) agreeing to establish a GHG emission cap-and-trade program, called the Regional Greenhouse Gas Initiative (RGGI). The program commenced in January 2009 and calls for stabilizing carbon dioxide emissions, at base levels established in 2005, from electric power plants with capacity greater than 3 MW. The MOU also provides for a 10% reduction in carbon dioxide emissions from base levels by 2019.
Pennsylvania has not stated an intention to join the RGGI, but has enacted the Pennsylvania Climate Change Act of 2008 (PCCA). The PCCA established a Climate Change Advisory Committee to advise the PADEP on the development of a Climate Change Action Plan. In December 2009, the Advisory Committee finalized its Climate Change Action Report which identifies specific actions that could result in reducing GHG emissions by 30% by 2020. Some of the proposed actions, such as a mandatory 5% efficiency improvement at power plants, could be technically unachievable. To date, there have been no regulatory or legislative actions taken to implement the recommendations of the report. In addition, legislation has been introduced that would, if enacted, accelerate the solar supply requirements and restrict eligible solar projects to those located in Pennsylvania. PPL cannot predict at this time whether this legislation will be enacted.
Eleven Western states, including Montana and certain Canadian provinces, are members of the Western Climate Initiative (WCI). The WCI has established a goal of reducing carbon dioxide emissions 15% below 2005 levels by 2020 and is currently developing GHG emission allocations, offsets, and reporting recommendations.
In November 2008, the Governor of Kentucky issued a comprehensive energy plan including non-binding targets aimed at promoting improved energy efficiency, development of alternative energy, development of carbon capture and sequestration projects, and other actions to reduce GHG emissions. In December 2009, the Kentucky Climate Action Plan Council was established to develop an action plan addressing potential GHG reductions and related measures. To date the state has yet to issue a final plan. The impact of any such plan is not now determinable, but the costs to comply with the plan could be significant.
A number of lawsuits have been filed asserting common law claims including nuisance, trespass and negligence against various companies with GHG emitting facilities, and the law remains unsettled on these claims. In September 2009, the U.S.
Court of Appeals for the Second Circuit in the case of AEP v. Connecticut reversed a federal district court's decision and ruled that several states and public interest groups, as well as the City of New York, could sue five electric utility companies under federal common law for allegedly causing a public nuisance as a result of their emissions of GHGs. In June 2011, the U.S. Supreme Court overturned the lower court and held that such federal common law claims were displaced by the Clean Air Act and regulatory actions of the EPA. In Comer v. Murphy Oil, the U.S. Court of Appeals for the Fifth Circuit declined to overturn a district court ruling that plaintiffs did not have standing to pursue state common law claims against companies that emit GHGs. The complaint in the Comer case named the previous indirect parent of LKE as a defendant based upon emissions from the Kentucky plants. In January 2011, the Supreme Court denied a petition to reverse the Court of Appeals' ruling. In May 2011, the plaintiffs in the Comer case filed a substantially similar complaint in federal district court in Mississippi against 87 companies, including KU and three other indirect subsidiaries of LKE, under a Mississippi statute that allows the re-filing of an action in certain circumstances. Additional litigation in federal and state courts over these issues is continuing. PPL, LKE and KU cannot predict the outcome of this litigation or estimate a range of reasonably possible losses, if any.
In 2011, PPL's power plants emitted approximately 74 million tons of carbon dioxide compared with 68 million tons in 2010. The totals reflect 36 million tons from PPL Generation and 38 million tons from LG&E's and KU's generating fleet. All tons are U.S. short tons (2,000 lbs/ton).
Renewable Energy Legislation (PPL and PPL Energy Supply)
There has been interest in renewable energy legislation at both the state and federal levels. At the federal level, House and Senate bills proposed in the 111th Congress would have imposed mandatory renewable energy supply and energy efficiency requirements in the 15% to 20% range by approximately 2020. Earlier in 2011, there were discussions regarding a Clean Energy Standard (CES) that addressed not only renewables but also encouraged clean energy requirements (as yet to be defined). At this time, neither the renewable energy debate nor the CES discussion is expected to gain momentum at the federal or state levels (beyond what is otherwise already required in Pennsylvania and Montana) in the near term.
PPL believes there are financial, regulatory and logistical uncertainties related to GHG reductions and the implementation of renewable energy mandates. These will need to be resolved before the impact of such requirements on PPL can be meaningfully estimated. Such uncertainties, among others, include the need to provide back-up supply to augment intermittent renewable generation, potential generation oversupply that could result from such renewable generation and back-up, impacts to PJM's capacity market and the need for substantial changes to transmission and distribution systems to accommodate renewable energy. These uncertainties are not directly addressed by proposed legislation. PPL and PPL Energy Supply cannot predict at this time the effect on their future competitive position, results of operation, cash flows and financial position of any GHG emissions, renewable energy mandate or other global climate change requirements that may be adopted, although the costs to implement and comply with any such requirements could be significant.
Water/Waste
Coal Combustion Residuals (CCRs) (PPL, PPL Energy Supply, LKE, LG&E and KU)
In June 2010, the EPA proposed two approaches to regulating the disposal and management of CCRs under the Resource Conservation and Recovery Act (RCRA). CCRs include fly ash, bottom ash and sulfur dioxide scrubber wastes. The first approach would regulate CCRs as a hazardous waste under Subtitle C of the RCRA. This approach would have very significant impacts on any coal-fired plant, and would require plants to retrofit their operations to comply with full hazardous waste requirements for the generation of CCRs and associated waste waters through transportation and disposal. This would also have a negative impact on the beneficial use of CCRs and could eliminate existing markets for CCRs. The second approach would regulate CCRs as a solid waste under Subtitle D of the RCRA. This approach would mainly affect disposal and most significantly affect any wet disposal operations. Under this approach, many of the current markets for beneficial uses would not be affected. Currently, PPL expects that several of its plants in Kentucky and Montana could be significantly impacted by the requirements of Subtitle D of the RCRA, as these plants are using surface impoundments for management and disposal of CCRs.
The EPA has issued information requests on CCR management practices at numerous plants throughout the power industry as it considers whether or not to regulate CCRs as hazardous waste. PPL has provided information on CCR management practices at most of its plants in response to the EPA's requests. In addition, the EPA has conducted follow-up inspections to evaluate the structural stability of CCR management facilities at several PPL plants and PPL has implemented certain actions in response to recommendations from these inspections.
The EPA is continuing to evaluate the unprecedented number of comments it received on its June 2010 proposed regulations. In October 2011, the EPA issued a Notice of Data Availability (NODA) that requests comments on selected documents that
the EPA received during the comment period for the proposed regulations. Comments were submitted on the NODA in November 2011. In addition, the U.S. House of Representatives in October 2011 approved a bill to modify Subtitle D of the RCRA to provide for the proper management and disposal of CCRs and that would preclude the EPA from regulating CCRs under Subtitle C of the RCRA. The bill has been introduced in the Senate and the prospect for passage of this legislation is uncertain. In January 2012, a coalition of environmental groups filed a 60-day notice of intent to sue the EPA for failure to perform nondiscretionary duties under RCRA, which could require a hard deadline for EPA to issue strict CCR regulations. In February 2012, a CCR recycling company also issued a 60-day notice of intent to sue the EPA over its timeliness in issuing CCR regulations, but that company requests that the EPA take a Subtitle D approach that would allow for continued recycling of CCRs.
PPL, PPL Energy Supply, LKE, LG&E and KU cannot predict at this time the final requirements of the EPA's CCR regulations or potential changes to the RCRA and what impact they would have on their facilities, but the economic impact could be significant.
Martins Creek Fly Ash Release (PPL and PPL Energy Supply)
In 2005, there was a release of approximately 100 million gallons of water containing fly ash from a disposal basin at the Martins Creek plant used in connection with the operation of the plant's two 150 MW coal-fired generating units. This resulted in ash being deposited onto adjacent roadways and fields, and into a nearby creek and the Delaware River. PPL determined that the release was caused by a failure in the disposal basin's discharge structure. PPL conducted extensive clean-up and completed studies, in conjunction with a group of natural resource trustees and the Delaware River Basin Commission, evaluating the effects of the release on the river's sediment, water quality and ecosystem.
The PADEP filed a complaint in Pennsylvania Commonwealth Court against PPL Martins Creek and PPL Generation, alleging violations of various state laws and regulations and seeking penalties and injunctive relief. PPL and the PADEP have settled this matter. The settlement also required PPL to submit a report on the completed studies of possible natural resource damages. PPL subsequently submitted the assessment report to the Pennsylvania and New Jersey regulatory agencies and has continued discussing potential natural resource damages and mitigation options with the agencies. Subsequently, in August 2011 the DEP submitted its National Resource Damage Assessment report to the court and to the intervenors. The intervenors have commented on the report and the PADEP and PPL recently filed separate responses with the court. The settlement agreement for the Natural Resources Damage Claim has not yet been submitted to the court or for public comments.
Through December 31, 2011, PPL Energy Supply has spent $28 million for remediation and related costs and an insignificant remediation liability remains on the balance sheet. PPL and PPL Energy Supply cannot be certain of the outcome of the natural resource damage assessment or the associated costs, the outcome of any lawsuit that may be brought by citizens or businesses or the exact nature of any other regulatory or other legal actions that may be initiated against PPL, PPL Energy Supply or their subsidiaries as a result of the disposal basin release. However, PPL and PPL Energy Supply currently do not expect such outcomes to result in material losses above the amounts currently recorded.
Seepages and Groundwater Infiltration - Pennsylvania, Montana and Kentucky
(PPL, PPL Energy Supply, LKE, LG&E and KU)
Seepages or groundwater infiltration have been detected at active and retired wastewater basins and landfills at various PPL plants. PPL has completed or is completing assessments of seepages or groundwater infiltration at various facilities and is working with agencies to implement abatement measures, where required. A range of reasonably possible losses cannot currently be estimated.
(PPL and PPL Energy Supply)
In 2007, six plaintiffs filed a lawsuit in the Montana Sixteenth Judicial District Court against the Colstrip plant owners asserting property damage claims from seepage from wastewater ponds at Colstrip. A settlement agreement was reached in July 2010 which would have resulted in a payment by PPL Montana, but certain of the plaintiffs later argued that the settlement was not final. The Colstrip plant owners filed a motion to enforce the settlement and in October 2011 the court granted the motion and ordered the settlement to be completed in 60 days. The plaintiffs have appealed the October order to the Montana Supreme Court, which is presently being briefed. The parties are in the process of submitting their briefs to the Montana Supreme Court. That court's decision is expected in the second half of 2012. The settlement ordered by the district court is, therefore, not final and PPL and PPL Energy Supply cannot predict the outcome of the appeal, although PPL Montana's share of any final settlement in excess of amounts recorded is not expected to be significant.
Conemaugh River Discharges (PPL and PPL Energy Supply)
In April 2007, PennEnvironment and the Sierra Club brought a Clean Water Act citizen suit in the U.S. District Court for the Western District of Pennsylvania (the Western District Court) against GenOn Northeast Management Company (then known as Reliant Energy Northeast Management Company) (GenOn), as operator of Conemaugh Generating Station (CGS), seeking civil penalties and injunctive relief for alleged violations of CGS's NPDES water discharge permit. A PPL Energy Supply subsidiary holds a 16.25% undivided, tenant-in-common ownership interest in CGS.
Throughout the relevant time period, the operators of CGS have worked closely with the PADEP to ensure that the facility is operated in a manner that does not cause any adverse environmental impacts to the Conemaugh River, a waterway already significantly impacted by discharges from abandoned coal mines and other historical industrial activity with respect to which neither PPL nor CGS had any involvement. Pursuant to a Consent Order and Agreement between the PADEP and GenOn (the CGS COA), a variety of studies have been conducted, a water treatment facility for cooling tower blowdown has been designed and built, and a second treatment facility for sulfur dioxide scrubber waste water has been designed (and is awaiting final PADEP approval for construction), all in order to comply with the stringent limits set out in CGS's NPDES permit.
In March 2011, the Western District Court entered a partial summary judgment in the plaintiffs' favor, declaring that discharges from CGS violated the NPDES permit. Subsequently, the parties agreed to settle the dispute and in August 2011 the court entered a Consent Decree and Order resolving the mater. PPL Energy Supply's share of the settlement is not significant.
In a separate matter, the PADEP plans to file a complaint in the Commonwealth Court of Pennsylvania alleging several violations of Clean Streams Law at the Conemaugh generating facility. The PADEP and GenOn Northeast Management Company, the operator, signed and lodged with the court a consent decree that when entered by the court will resolve the issues. It is expected that the court will enter the consent decree in March 2012 after a 30-day public comment period has lapsed. Under the terms of the consent decree, GenOn will be obligated to pay a civil penalty of $500,000. PPL Energy Supply is responsible for 16.25% of this amount.
Other Issues (PPL, PPL Energy Supply, LKE, LG&E and KU)
In 2006, the EPA significantly decreased to 10 parts per billion (ppb) the drinking water standards related to arsenic. In Pennsylvania, Montana and Kentucky, this arsenic standard has been incorporated into the states' water quality standards and could result in more stringent limits in NPDES permits for PPL's Pennsylvania, Montana and Kentucky plants. Subsequently, the EPA developed a draft risk assessment for arsenic that increases the cancer risk exposure by more than 20 times, which would lower the current standard from 10 ppb to 0.1 ppb. If the lower standard becomes effective, costly treatment would be required to attempt to meet the standard and, at this time, there is no assurance that it could be achieved. PPL, PPL Energy Supply, LKE, LG&E and KU cannot predict the outcome of the draft risk assessment and what impact, if any, it would have on their facilities, but the costs could be significant.
The EPA is reassessing its polychlorinated biphenyls (PCB) regulations under the Toxics Substance Control Act, which currently allow certain PCB articles to remain in use. In April 2010, the EPA issued an Advanced Notice of Proposed Rulemaking for changes to these regulations. This rulemaking could lead to a phase-out of all PCB-containing equipment. PPL, PPL Energy Supply, LKE, LG&E and KU cannot predict at this time the outcome of these proposed EPA regulations and what impact, if any, they would have on their facilities, but the costs could be significant.
The EPA finalized requirements in 2004 for new or modified cooling water intake structures. These requirements affect where generating facilities are built, establish intake design standards and could lead to requirements for cooling towers at new and modified power plants. Another rule, finalized in 2004, that addressed existing structures was withdrawn following a 2007 decision by the U.S. Court of Appeals for the Second Circuit. In 2009, however, the U.S. Supreme Court ruled that the EPA has discretion to use cost-benefit analysis in determining the best technology available for minimizing adverse environmental impact to aquatic organisms. The EPA published the proposed rule in April 2011. The industry and PPL reviewed the proposed rule and submitted comments. The EPA is evaluating comments and meeting with industry groups to discuss options. The final rule is to be issued by July 2012. The proposed rule contains two requirements to reduce impact to aquatic organisms. The first requires all existing facilities to meet standards for the reduction of mortality of aquatic organisms that become trapped against water intake screens regardless of the levels of mortality actually occurring or the cost of achieving the requirements. The second requirement is to determine and install best technology available to reduce mortality of aquatic organisms that are pulled through the plant's cooling water system. A form of cost-benefit analysis is allowed for this second requirement. This process involves a site-specific evaluation based on nine factors including impacts to energy delivery reliability and remaining useful life of the plant. PPL, PPL Energy Supply, LKE, LG&E and KU will be unable to determine the exact impact until a final rule is issued, the required studies have been completed, and each state in which they operate has decided how to implement the rule.
In October 2009, the EPA released its Final Detailed Study of the Steam Electric Power Generating effluent limitations guidelines and standards. Final regulations are expected to be effective in January 2014. PPL expects the revised guidelines and standards to be more stringent than the current standards especially for sulfur dioxide scrubber wastewater and ash basin discharges, which could result in more stringent discharge permit limits. In the interim, PPL is unable to predict whether the EPA and the states may impose more stringent limits on a case-by-case best professional judgment basis under existing authority as permits are renewed.
PPL has signed a Consent Order and Agreement (the Brunner COA) with the PADEP under which it agreed, under certain conditions, to take further actions to minimize the possibility of fish kills at its Brunner Island plant. Fish are attracted to warm water in the power plant discharge channel, especially during cold weather. Debris at intake pumps can result in a unit trip or reduction in load, causing a sudden change in water temperature. PPL is in the process of constructing a barrier to prevent debris from entering the river water intake area at a cost which is not expected to be material.
PPL has also investigated alternatives to exclude fish from the discharge channel and submitted three alternatives to the PADEP. According to the Brunner COA, once the cooling towers at Brunner Island became operational, PPL must implement one of these fish exclusion alternatives if a fish kill occurs in the discharge channel due to thermal impacts from the plant. Following start-up of the cooling towers in April 2010, several hundred dead fish were found in the cooling tower intake basket although there were no sudden changes in water temperature. In the third quarter of 2010, PPL discussed this matter with the PADEP and both parties agreed that this condition was not one anticipated by the Brunner COA, thereby concluding it did not trigger a need to implement a fish exclusion project. At this time, no fish exclusion project is planned.
In May 2010, the Kentucky Waterways Alliance and other environmental groups filed a petition with the Kentucky Energy and Environment Cabinet challenging the Kentucky Pollutant Discharge Elimination System permit issued in April 2010, which covers water discharges from the Trimble County plant. In November 2010, the Cabinet issued a final order upholding the permit. In December 2010, the environmental groups appealed the order to state court. PPL, LKE, LG&E, and KU are unable to predict the outcome of this matter or estimate a range of reasonably possible losses, if any.
The EPA and the Army Corps of Engineers are working on a guidance document that will expand the federal government's interpretation of what constitutes "waters of the United States" (WOUS) subject to regulation under the Clean Water Act. This change has the potential to affect generation and delivery operations, with the most significant effect being the potential elimination of the existing regulatory exemption for plant waste water treatment systems. The costs that may be imposed as a result of any eventual expansion of this interpretation cannot reliably be estimated at this time.
(PPL, PPL Energy Supply, PPL Electric, LKE, LG&E and KU)
Superfund and Other Remediation
PPL Electric is a potentially responsible party at several sites listed by the EPA under the federal Superfund program, including the Columbia Gas Plant site, the Metal Bank site and the Ward Transformer site. Clean-up actions have been or are being undertaken at all of these sites, the costs of which have not been significant to PPL Electric. However, should the EPA require different or additional measures in the future, or should PPL Electric's share of costs at multi-party sites increase significantly more than currently expected, the costs could be significant.
PPL Electric, LG&E and KU are remediating or have completed the remediation of several sites that were not addressed under a regulatory program such as Superfund, but for which PPL Electric, LG&E and KU may be liable for remediation. These include a number of former coal gas manufacturing facilities in Pennsylvania and Kentucky previously owned or operated or currently owned by predecessors or affiliates of PPL Electric, LG&E and KU. There are additional sites, formerly owned or operated by PPL Electric, LG&E and KU predecessors or affiliates, for which PPL Electric, LG&E and KU lack information on current site conditions and are therefore unable to predict what, if any, potential liability they may have.
In June 2011, Lepore-Moyers Partnership (LMP) filed a complaint in federal district court against PPL Electric, UGI Corporation and a neighboring property owner relating to contamination allegedly emanating from the former Mount Joy Manufactured Gas Plant (MGP) site located in Lancaster County, Pennsylvania. LMP owns property adjacent to the Mount Joy MGP site and claims that environmental testing done on its property indicates the presence of volatile organic compounds in the soil and/or groundwater. LMP claims that defendants are responsible for, among other things, the reimbursement of costs, future response costs, investigation and remediation of the contamination, and damages caused by the contamination. PPL Electric expects the costs related to this matter to be insignificant.
Depending on the outcome of investigations at sites where investigations have not begun or been completed or developments at sites for which PPL currently lacks information, the costs of remediation and other liabilities could be substantial. PPL and its subsidiaries also could incur other non-remediation costs at sites included in current consent orders or other contaminated sites which could be significant. PPL is unable to estimate a range of reasonably possible losses, if any, related to these matters.
The EPA is evaluating the risks associated with polycyclic aromatic hydrocarbons and naphthalene, chemical by-products of coal gas manufacturing. As a result of the EPA's evaluation, individual states may establish stricter standards for water quality and soil cleanup. This could require several PPL subsidiaries to take more extensive assessment and remedial actions at former coal gas manufacturing facilities. PPL cannot estimate a range of reasonably possible losses, if any, related to these matters.
Under the Pennsylvania Clean Streams Law, subsidiaries of PPL Generation are obligated to remediate acid mine drainage at former mine sites and may be required to take additional steps to prevent potential acid mine drainage at previously capped refuse piles. One PPL Generation subsidiary is pumping mine water at two mine sites and treating water at one of these sites. Another PPL Generation subsidiary has installed a passive wetlands treatment system at a third site. At December 31, 2011, PPL Energy Supply had accrued a discounted liability of $24 million to cover the costs of pumping and treating groundwater at the two mine sites for 50 years and for operating and maintaining passive wetlands treatment at the third site. PPL Energy Supply discounted this liability based on risk-free rates at the time of the mine closures. The weighted-average rate used was 8.15%. Expected undiscounted payments are estimated at $2 million for 2012, $1 million for each of the years from 2013 through 2016, and $133 million for work after 2016.
From time to time, PPL undertakes remedial action in response to spills or other releases at various on-site and off-site locations, negotiates with the EPA and state and local agencies regarding actions necessary for compliance with applicable requirements, negotiates with property owners and other third parties alleging impacts from PPL's operations, and undertakes similar actions necessary to resolve environmental matters which arise in the course of normal operations. Based on analyses to date, resolution of these general environmental matters is not expected to have a material adverse impact on PPL's operations.
Future cleanup or remediation work at sites currently under review, or at sites not currently identified, may result in material additional costs for the Registrants.
Electric and Magnetic Fields
Concerns have been expressed by some members of the public regarding potential health effects of power frequency EMFs, which are emitted by all devices carrying electricity, including electric transmission and distribution lines and substation equipment. Government officials in the U.S. and the U.K. have reviewed this issue. The U.S. National Institute of Environmental Health Sciences concluded in 2002 that, for most health outcomes, there is no evidence that EMFs cause adverse effects. The agency further noted that there is some epidemiological evidence of an association with childhood leukemia, but that the evidence is difficult to interpret without supporting laboratory evidence. The U.K. National Radiological Protection Board (part of the U.K. Health Protection Agency) concluded in 2004 that, while the research on EMFs does not provide a basis to find that EMFs cause any illness, there is a basis to consider precautionary measures beyond existing exposure guidelines. The Stakeholder Group on Extremely Low Frequency EMF, set up by the U.K. Government, has issued two reports, one in April 2007 and one in June 2010, describing options for reducing public exposure to EMF. The U.K. Government responded to the first report in 2009, agreeing to some of the proposals, including a proposed voluntary code to optimally phase 132 kilovolt overhead lines to reduce public exposure to EMF where it is cost effective to do so. In February 2011, the U.K. Government and the Energy Networks Association agreed to voluntary codes of practice under which new high voltage lines will be designed and operated using optimal phasing to reduce EMF unless doing so would be unreasonable, and defining the circumstances under which utilities will need to provide evidence of compliance with EMF exposure limits adopted by the U.K. Government. The U.K. Government is currently considering the second report which concentrates on EMF exposure from distribution systems. PPL and its subsidiaries believe research on EMF and health issues should continue and are taking steps to reduce EMFs, where practical, in the design of new transmission and distribution facilities. PPL and its subsidiaries are unable to predict what effect, if any, the EMF issue might have on their operations and facilities either in the U.S. or the U.K., and the associated cost, or what, if any, liabilities they might incur related to the EMF issue.
Environmental Matters - WPD (PPL)
WPD's distribution businesses are subject to environmental regulatory and statutory requirements. PPL believes that WPD has taken and continues to take measures to comply with the applicable laws and governmental regulations for the protection of the environment.
The U.K. Government has requested that utilities undertake projects to alleviate the impact of flooding on the U.K. utility infrastructure, including major electricity substations. WPD has agreed with the Ofgem to spend $44 million on flood prevention, which will be recovered through rates during the ten-year period commencing April 2010. WPD is currently liaising on site-specific proposals with local offices of a U.K. Government agency.
The U.K.'s 2008 Climate Change Act imposes a duty on certain companies, including WPD, to report on climate change adaptation. The first information request was received by WPD in March 2010 and submissions for all four distribution network operators were made in June 2011. In October 2011, the U.K. Government confirmed that the reports submitted by WPD fulfill the obligations imposed by Climate Change Act. WPD has worked with other U.K. electricity network operators to undertake research with the internationally recognized U.K. Met Office (the national weather service) and to report using common agreed methodology.
There are no other material legal or administrative proceedings pending against or related to WPD with respect to environmental matters. See "Electric and Magnetic Fields" above for a discussion of EMFs.
Other
Nuclear Insurance (PPL and PPL Energy Supply)
PPL Susquehanna is a member of certain insurance programs that provide coverage for property damage to members' nuclear generating plants. Facilities at the Susquehanna plant are insured against property damage losses up to $2.75 billion under these programs. PPL Susquehanna is also a member of an insurance program that provides insurance coverage for the cost of replacement power during prolonged outages of nuclear units caused by certain specified conditions.
Under the property and replacement power insurance programs, PPL Susquehanna could be assessed retroactive premiums in the event of the insurers' adverse loss experience. At December 31, 2011, this maximum assessment was $44 million.
In the event of a nuclear incident at the Susquehanna plant, PPL Susquehanna's public liability for claims resulting from such incident would be limited to $12.6 billion under provisions of The Price-Anderson Act Amendments under the Energy Policy Act of 2005. PPL Susquehanna is protected against this liability by a combination of commercial insurance and an industry assessment program.
In the event of a nuclear incident at any of the reactors covered by The Price-Anderson Act Amendments under the Energy Policy Act of 2005, PPL Susquehanna could be assessed up to $235 million per incident, payable at $35 million per year.
At December 31, 2011, the property, replacement power and nuclear incident insurers maintained an A.M. Best financial strength rating of A ("Excellent").
Guarantees and Other Assurances
(PPL, PPL Energy Supply, PPL Electric, LKE, LG&E and KU)
In the normal course of business, the Registrants enter into agreements that provide financial performance assurance to third parties on behalf of certain subsidiaries. Such agreements include, for example, guarantees, stand-by letters of credit issued by financial institutions and surety bonds issued by insurance companies. These agreements are entered into primarily to support or enhance the creditworthiness attributed to a subsidiary on a stand-alone basis or to facilitate the commercial activities in which these subsidiaries enter.
(PPL)
PPL fully and unconditionally guarantees all of the debt securities of PPL Capital Funding.
(PPL, PPL Energy Supply, PPL Electric, LKE, LG&E and KU)
The table below details guarantees provided as of December 31, 2011. The total recorded liability at December 31, 2011 and 2010 was $14 million for PPL and $11 million for LKE. Other than as noted in the descriptions for "WPD guarantee of pension and other obligations of unconsolidated entities," the probability of expected payment/performance under each of these guarantees is remote.
(a)
Represents the estimated maximum potential amount of future payments that could be required to be made under the guarantee.
(b)
PPL has provided indemnification to the purchaser of PPL Gas Utilities and Penn Fuel Propane, LLC for damages arising out of any breach of the representations, warranties and covenants under the related transaction agreement and for damages arising out of certain other matters, including certain pre-closing unknown environmental liabilities relating to former manufactured gas plant properties or off-site disposal sites, if any, outside of Pennsylvania. The indemnification provisions for most representations and warranties, including tax and environmental matters, are capped at $45 million, in the aggregate, and are triggered (i) only if the individual claim exceeds $50,000, and (ii) only if, and only to the extent that, in the aggregate, total claims exceed $4.5 million. The indemnification provisions for most representations and warranties expired on September 30, 2009 without any claims having been made. Certain representations and warranties, including those having to do with transaction authorization and title, survive indefinitely, are capped at the purchase price and are not subject to the above threshold or deductible. The indemnification provision for the tax matters representations survives for the duration of the applicable statute of limitation. The indemnification provision for the environmental matters representations expired on September 30, 2011 without any claims having been made. The indemnification for covenants survives until the applicable covenant is performed and is not subject to any cap.
(c)
WPD Midlands Holdings Limited (formerly Central Networks Limited) had agreed prior to the acquisition to indemnify certain former directors of a Turkish entity in which WPD Midlands Holdings Limited previously owned an interest for any liabilities that may arise as a result of an investigation by Turkish tax authorities, and PPL WEM has received a cross-indemnity from E.ON AG with respect to these indemnification obligations. Additionally, PPL subsidiaries agreed to provide indemnifications to subsidiaries of E.ON AG for certain liabilities relating to properties and assets owned by affiliates of E.ON AG that were transferred to WPD Midlands in connection with the acquisition. The maximum exposure and expiration of these indemnifications cannot be estimated because the maximum potential liability is not capped and there is no expiration date in the transaction documents.
(d)
In connection with the liquidation of wholly owned subsidiaries that have been deconsolidated upon turning the entities over to the liquidators, certain affiliates of PPL Global have agreed to indemnify the liquidators, directors and/or the entities themselves for any liabilities or expenses arising during the liquidation process, including liabilities and expenses of the entities placed into liquidation. In some cases, the indemnifications are limited to a maximum amount that is based on distributions made from the subsidiary to its parent either prior or subsequent to being placed into liquidation. In other cases, the maximum amount of the indemnifications is not explicitly stated in the agreements. The indemnifications generally expire two to seven years subsequent to the date of dissolution of the entities. The exposure noted only includes those cases in which the agreements provide for a specific limit on the amount of the indemnification, and the expiration date was based on an estimate of the dissolution date of the entities.
In connection with their sales of various businesses, WPD and its affiliates have provided the purchasers with indemnifications that are standard for such transactions, including indemnifications for certain pre-existing liabilities and environmental and tax matters. In addition, in connection with certain of these sales, WPD and its affiliates have agreed to continue their obligations under existing third-party guarantees, either for a set period of time following the transactions or upon the condition that the purchasers make reasonable efforts to terminate the guarantees. Finally, WPD and its affiliates remain secondarily responsible for lease payments under certain leases that they have assigned to third parties.
(e)
As a result of the privatization of the utility industry in the U.K., certain electric associations' roles and responsibilities were discontinued or modified. As a result, certain obligations, primarily pension-related, associated with these organizations have been guaranteed by the participating members. Costs are allocated to the members based on predetermined percentages as outlined in specific agreements. However, if a member becomes insolvent, costs can be reallocated to and are guaranteed by the remaining members. At December 31, 2011, WPD has recorded an estimated discounted liability based on its current allocated percentage of the total expected costs for which the expected payment/performance is probable. Neither the expiration date nor the maximum amount of potential payments for certain obligations is explicitly stated in the related agreements. Therefore, they have been estimated based on the types of obligations.
(f)
Two WPD unconsolidated affiliates were refinanced during 2005. Under the terms of the refinancing, WPD has indemnified the lender against certain tax and other liabilities.
(g)
Other than the letters of credit, all guarantees of PPL Energy Supply, on a consolidated basis, also apply to PPL on a consolidated basis for financial reporting purposes.
(h)
Standby letter of credit arrangements under PPL Energy Supply's credit facilities for the purposes of protecting various third parties against nonperformance by PPL. This is not a guarantee by PPL on a consolidated basis.
(i)
PPL Susquehanna is contingently obligated to pay this amount related to potential retrospective premiums that could be assessed under its nuclear insurance programs. See "Nuclear Insurance" above for additional information.
(j)
This is the maximum amount PPL Susquehanna could be assessed for each incident at any of the nuclear reactors covered by this Act. See "Nuclear Insurance" above for additional information.
(k)
PPL Energy Supply's maximum exposure with respect to certain indemnifications and the expiration of the indemnifications cannot be estimated because, in the case of certain indemnification provisions, the maximum potential liability is not capped by the transaction documents and the expiration date is based on the applicable statute of limitation. The exposure and expiration dates noted are only for those cases in which the agreements provide for specific limits.
A subsidiary of PPL Energy Supply has agreed to provide indemnification to the purchaser of the Long Island generation business for damages arising out of any breach of the representations, warranties and covenants under the related transaction agreement and for damages arising out of certain other matters, including liabilities relating to certain renewable energy facilities which were previously owned by one of the PPL subsidiaries sold in the transaction but which were unrelated to the Long Island generation business. The indemnification provisions are subject to certain customary limitations, including thresholds for allowable claims, caps on aggregate liability, and time limitations for claims arising out of breaches of most representations and warranties. The indemnification provisions for most representations and warranties expired in the third quarter of 2011.
A subsidiary of PPL Energy Supply has agreed to provide indemnification to the purchasers of the Maine hydroelectric facilities for damages arising out of any breach of the representations, warranties and covenants under the respective transaction agreements and for damages arising out of certain other matters, including liabilities of the PPL Energy Supply subsidiary relating to the pre-closing ownership or operation of those hydroelectric facilities. The indemnification obligations are subject to certain customary limitations, including thresholds for allowable claims, caps on aggregate liability, and time limitations for claims arising out of breaches of representations and warranties. The indemnification provisions for certain representations and warranties expired in the second quarter of 2011.
Subsidiaries of PPL Energy Supply have agreed to provide indemnification to the purchasers of certain non-core generation facilities sold in March 2011 (see Note 9 for additional information) for damages arising out of any breach of the representations, warranties and covenants under the related transaction agreements and for damages arising out of certain other matters relating to the facilities that were the subject of the transaction, including certain reduced capacity payments (if any) at one of the facilities in the event specified PJM rule changes are proposed and become effective. The indemnification provisions are subject to certain customary limitations, including thresholds for allowable claims, caps on aggregate liability, and time limitations for claims arising out of breaches of most representations and warranties.
(l)
In December 2007, a subsidiary of PPL Energy Supply executed revised owners agreements for two jointly owned facilities, the Keystone and Conemaugh generating plants. The agreements require that in the event of any default by an owner, the other owners fund contributions for the operation of the generating plants, based upon their ownership percentages. The maximum obligation among all owners, for each plant, is currently $20 million. The non-defaulting owners, who make up the defaulting owner's obligations, are entitled to the generation entitlement of the defaulting owner, based upon their ownership percentage. The agreements do not have an expiration date.
(m)
A PPL Energy Supply subsidiary owned a one-third equity interest in Safe Harbor Water Power Corporation (Safe Harbor) that was sold in March 2011. Beginning in 2008, PPL Energy Supply guaranteed one-third of any amounts payable with respect to certain senior notes issued by Safe Harbor. Under the terms of the sale agreement, PPL Energy Supply continues to guarantee the portion of Safe Harbor's debt, but received a cross-indemnity from the purchaser in the event PPL Energy Supply is required to make a payment under the guarantee. Exposure noted reflects principal only. See Note 9 for additional information on the sale of this interest.
(n)
All guarantees of PPL Electric and LKE, on a consolidated basis, also apply to PPL on a consolidated basis for financial reporting purposes.
(o)
PPL Electric entered into a contract with a third party logistics firm that provides inventory procurement and fulfillment services. Under the contract, the logistics firm has title to the inventory purchased for PPL Electric's use. Upon termination of the contract, PPL Electric has guaranteed to purchase any remaining inventory that has not been used or sold by the logistics firm at the weighted-average cost at which the logistics firm purchased the inventory, thus protecting the logistics firm from reductions in the fair value of the inventory.
(p)
LKE provides certain indemnifications, the most significant of which relate to the termination of the WKE lease in July 2009. These guarantees cover the due and punctual payment, performance and discharge by each party of its respective present and future obligations. The most comprehensive of these guarantees is the LKE guarantee covering operational, regulatory and environmental commitments and indemnifications made by WKE under the WKE Transaction Termination Agreement. This guarantee has a term of 12 years ending July 2021, and a cumulative maximum exposure of $200 million. Certain items such as non-excluded government fines and penalties fall outside the cumulative cap. Another guarantee with a maximum exposure of $100 million covering other indemnifications expires in 2023. Certain matters are currently under discussion among the parties, including one matter currently in arbitration and a further matter for which LKE is contesting the applicability of the indemnification requirement. The matter in arbitration may be ruled upon during early 2012, which ruling may result in increases or decreases to the liability estimate LKE has currently recorded. The ultimate outcome of both matters cannot be predicted at this time. Additionally, LKE has indemnified various third parties related to historical obligations for other divested subsidiaries and affiliates. The indemnifications vary by entity and the maximum amount limits range from being capped at the sale price to no specified maximum; however, LKE is not aware of formal claims under such indemnities made by any party at this time. LKE could be required to perform on these indemnifications in the event of covered losses or liabilities being claimed by an indemnified party. No additional material loss is anticipated by reason of such indemnification.
(q)
All guarantees of LG&E and KU also apply to LKE on a consolidated basis for financial reporting purposes.
(r)
As described in the "Energy Purchase Commitments" section of this footnote, pursuant to a power purchase agreement with OVEC, LG&E and KU are obligated to pay a demand charge which includes, among other charges, decommissioning costs, postretirement and post employment benefits. The demand charge is expected to cover LG&E's and KU's shares of the cost of these items over the term of the contract. However, in the event there is a shortfall in covering these costs, LG&E and KU are obligated to pay their share of the excess.
The Registrants provide other miscellaneous guarantees through contracts entered into in the normal course of business. These guarantees are primarily in the form of indemnification or warranties related to services or equipment and vary in duration. The amounts of these guarantees often are not explicitly stated, and the overall maximum amount of the obligation under such guarantees cannot be reasonably estimated. Historically, no significant payments have been made with respect to these types of guarantees and the probability of payment/performance under these guarantees is remote.
PPL, on behalf of itself and certain of its subsidiaries, maintains insurance that covers liability assumed under contract for bodily injury and property damage. The coverage requires a maximum $4 million deductible per occurrence and provides maximum aggregate coverage of $200 million. This insurance may be applicable to obligations under certain of these contractual arrangements.
16. Related Party Transactions
(PPL Energy Supply and PPL Electric)
PLR Contracts/Purchase of Accounts Receivable
In 2009, PPL EnergyPlus supplied PPL Electric's entire PLR load under power purchase contracts that expired on December 31, 2009. Under these contracts, PPL EnergyPlus provided electricity at the predetermined capped prices that PPL Electric was authorized to charge its PLR customers. These purchases totaled $1.8 billion in 2009 and included nuclear decommissioning recovery and amortization of an up-front contract payment. Additionally, beyond 2009, PPL EnergyPlus has been awarded a portion of the PLR generation supply through competitive solicitations. See Note 15 for additional information on PPL Electric's energy procurement plan for the period January 2011 through May 2013 and related competitive solicitations. PPL Electric's purchases from PPL EnergyPlus for 2011 and 2010 totaled $26 million and $320 million. The purchases are included in the Statements of Income as "Wholesale energy marketing to affiliate" by PPL Energy Supply and as "Energy purchases from affiliate" by PPL Electric.
Under the standard Supply Master Agreement for the solicitation process, PPL Electric requires all suppliers to post collateral once credit exposures exceed defined credit limits. PPL EnergyPlus is required to post collateral with PPL Electric: (a) when the market price of electricity to be delivered by PPL EnergyPlus exceeds the contract price for the forecasted quantity of electricity to be delivered and (b) this market price exposure exceeds a contractual credit limit. Based on the current credit rating of PPL Energy Supply, as guarantor, PPL EnergyPlus' credit limit was $35 million at December 31, 2011. In no instance is PPL Electric required to post collateral to suppliers under these supply contracts.
PPL Electric's customers may choose an alternative supplier for their generation supply. See Note 1 for additional information regarding PPL Electric's purchases of accounts receivable from alternative suppliers, including PPL EnergyPlus.
At December 31, 2011, PPL Energy Supply had a net credit exposure of $36 million to PPL Electric from its commitment as a PLR supplier and from the sale of its accounts receivable to PPL Electric.
NUG Purchases
PPL Electric has a reciprocal contract with PPL EnergyPlus to sell electricity purchased under contracts with NUGs. PPL Electric purchases electricity from the NUGs at contractual rates and then sells the electricity at the same price to PPL EnergyPlus. These purchases were insignificant in 2011 and 2010 and were $70 million in 2009. These amounts are included in the Statements of Income as "Electric revenue to affiliate" by PPL Electric, and as "Energy purchases from affiliate" by PPL Energy Supply. Most of the NUG contracts have expired, with the final NUG contract expiring in 2014.
Wholesale Sales and Purchases (LG&E and KU)
LG&E and KU jointly dispatch their generation units with the lowest cost generation used to serve their retail native load. When LG&E has excess generation capacity after serving its own retail native load and its generation cost is lower than that of KU, KU purchases electricity from LG&E. When KU has excess generation capacity after serving its own retail native load and its generation cost is lower than that of LG&E, LG&E purchases electricity from KU. These transactions are reflected in the Statements of Income as "Electric revenue from affiliate" and "Energy purchases from affiliate" and are recorded at a price equal to the seller's fuel cost. Savings realized from such intercompany transactions are shared equally between the two companies. The volume of energy each company has to sell to the other is dependent on its native load needs and its available generation.
Allocations of PPL Services Costs (PPL Energy Supply, PPL Electric and LKE)
PPL Services provides corporate functions such as financial, legal, human resources and information technology services. PPL Services charges the respective PPL subsidiaries for the cost of certain services when they can be specifically identified. The cost of services that is not directly charged to PPL subsidiaries is allocated to applicable subsidiaries based on an average of the subsidiaries' relative invested capital, operation and maintenance expenses and number of employees. PPL Services allocated the following amounts, which PPL management believes are reasonable, including amounts applied to accounts that are further distributed between capital and expense.
(a)
Excludes allocated costs associated with the February 2009 workforce reduction. See Note 13 for additional information.
(b)
Represents costs allocated during the two months ending December 31, 2010 as LKE was acquired November 1, 2010.
Intercompany Billings by LKS (LG&E and KU)
LKS provides LG&E and KU with a variety of centralized administrative, management and support services. The cost of these services is directly charged to the company or, for general costs that cannot be directly attributed, charged based on predetermined allocation factors, including the following measures: number of customers, total assets, revenues, number of employees and/or other statistical information. LKS charged the amounts in the table below, which LKE management believes are reasonable, including amounts that are further distributed between capital and expense.
In addition, LG&E and KU provide services to each other and to LKS. Billings between LG&E and KU relate to labor and overheads associated with union and hourly employees performing work for the other company, charges related to jointly-owned generating units and other miscellaneous charges. Tax settlements between LKE and LG&E and KU are reimbursed through LKS.
Intercompany Borrowings
(PPL Energy Supply)
A PPL Energy Supply subsidiary holds revolving lines of credit and demand notes from certain affiliates. A note with PPL Energy Funding had an outstanding balance at December 31, 2011 of $198 million, which is reflected in "Notes receivable from affiliates" on the Balance Sheet. The interest rate on this borrowing was equal to one-month LIBOR plus 3.50%. There were no balances outstanding at December 31, 2010. Interest earned on these revolving facilities is included in "Interest Income from Affiliates" on the Statements of Income. For 2011, interest earned on borrowings was $8 million, which was substantially attributable to borrowings by PPL Energy Funding as discussed above. For 2010, interest earned on borrowings, excluding the term notes discussed below, was $5 million. Interest rates were equal to one-month LIBOR plus 1% and one-month LIBOR plus 3.50%. For 2009, interest earned on borrowings was insignificant.
(PPL Energy Supply, LKE, LG&E and KU)
In November 2010, a PPL Energy Supply subsidiary held term notes with LG&E and KU. These notes were subsequently repaid and therefore no balances were outstanding at December 31, 2010. Interest on these notes was due monthly at interest rates between 4.24% and 7.04%. Interest on these notes is included in "Interest Income from Affiliates" for PPL Energy Supply and "Interest Expense with Affiliates" for LKE, LG&E and KU. When balances were outstanding, interest on these notes was $4 million for 2010.
(LKE)
LKE maintains a $300 million revolving line of credit with a PPL Energy Supply subsidiary whereby LKE can borrow funds on a short-term basis at market-based rates. The interest rates on borrowings are equal to one-month LIBOR plus a spread. There was no balance outstanding at December 31, 2011 or 2010. Interest on the revolving line of credit with the PPL Energy Supply subsidiary was not significant for 2011 or 2010.
After PPL's acquisition of LKE in November 2010, LKE held a note receivable from a PPL affiliate. At December 31, 2011, $15 million was outstanding compared with $61 million at December 31, 2010. The interest rate on the outstanding borrowing was 2.27% and 2.26% for 2011 and 2010. Interest income on this note was not significant in 2011 or 2010.
Prior to PPL's acquisition of LKE in November 2010, LKE had revolving credit facilities and several short-term and long-term loans with its former E.ON AG affiliates. During 2010 and 2009, LKE incurred interest expense on these debt arrangements of $131 million and $155 million, which is included in the Statements of Income as "Interest Expense with Affiliate." The consolidated debt had a weighted-average interest rate of 3.76% at December 31, 2009. Any such borrowings were repaid in 2010 prior to or at the time of the acquisition by PPL.
(LG&E)
LG&E participates in an intercompany money pool agreement whereby LKE and/or KU make available to LG&E funds up to $500 million at an interest rate based on a market index of commercial paper issues. At December 31, 2011 there was no balance outstanding. At December 31, 2010, $12 million was outstanding. The interest rate for the period ended December 31, 2010 was 0.25%. Interest expense incurred on the money pool agreement with LKE and/or KU was not significant for 2011, 2010 or 2009.
Prior to PPL's acquisition of LKE in November 2010, LG&E had long-term loans from its former E.ON AG affiliates. During 2010 and 2009, LG&E incurred interest expense related to these debt arrangements of $22 million and $27 million, which is included in the Statements of Income as "Interest Expense with Affiliate." The long-term intercompany debt had a weighted-average interest rate of 5.49% at December 31, 2009. Any such borrowings were repaid in 2010 prior to or at the time of the acquisition by PPL.
(KU)
KU participates in an intercompany money pool agreement whereby LKE and/or LG&E make available to KU funds up to $500 million at an interest rate based on a market index of commercial paper issues. At December 31, 2011, there was no balance outstanding. At December 31, 2010, $10 million was outstanding. The interest rate for the period ended December 31, 2010 was 0.25%. Interest expense incurred on the money pool agreement with LKE and/or LG&E was not significant for 2011, 2010 or 2009.
Prior to PPL's acquisition of LKE in November 2010, KU had long-term loans from its former E.ON AG affiliates. During 2010 and 2009, KU incurred interest expense on these debt arrangements of $62 million and $69 million, which are included in the Statements of Income as "Interest Expense with Affiliate." The long-term intercompany debt had a weighted-average interest rate of 5.50% at December 31, 2009. Any such borrowings were repaid in 2010 prior to or at the time of the acquisition by PPL.
(PPL Energy Supply)
Intercompany Derivatives
In 2010 and 2009, PPL Global, which was a subsidiary of PPL Energy Supply, entered into a combination of average rate forwards and average rate options with PPL to sell British pounds sterling. These hedging instruments had terms identical to average rate forwards and average rate options entered into by PPL with third parties to protect the translation of expected income denominated in British pounds sterling to U.S. dollars. As a result of PPL Energy Supply's January 2011 distribution of its membership interest in PPL Global to its parent, gains and losses, both realized and unrealized, on these types of hedging instruments are reflected in "Income (Loss) from Discontinued Operations (net of income taxes)" on the Statements of Income. PPL Energy Supply recorded an insignificant net gain in 2010 and a net loss of $9 million during 2009 related to average rate forwards and average rate options. Contracts outstanding at December 31, 2010 hedged a total exposure of £89 million related to the translation of expected income in 2011. The fair value of these positions was insignificant at December 31, 2010.
PPL Global was also a party to forward contracts with PPL to sell British pounds sterling to protect the value of a portion of its net investment in WPD. These hedging instruments had terms identical to forward sales contracts entered into by PPL with third parties. The total amount of the contracts outstanding at December 31, 2010 was £35 million ($62 million based on contracted rates). The fair value of these positions at December 31, 2010 was an asset of $7 million, which is included in "Current Assets - Price risk management assets" with an offsetting after-tax amount included in the foreign currency translation adjustment component of AOCI on the Balance Sheet.
As a result of PPL Energy Supply's distribution of its membership interest in PPL Global to its parent, these intercompany derivatives were removed from PPL Energy Supply's balance sheet in 2011. See Note 9 for additional information.
Trademark Royalties
A PPL subsidiary owns PPL trademarks and billed certain affiliates for their use. PPL Energy Supply was billed $40 million of license fees in 2011, 2010 and 2009. These fees are primarily included in "Other operation and maintenance" on the Statements of Income.
On December 31, 2011, this agreement was terminated.
Distribution of Interest in PPL Global to Parent
In January 2011, PPL Energy Supply distributed its membership interest in PPL Global to its parent, PPL Energy Funding. See Note 9 for additional information.
Intercompany Insurance (PPL Electric)
PPL Power Insurance Ltd. (PPL Power Insurance) is a subsidiary of PPL that provides insurance coverage to PPL and its subsidiaries for property damage, general/public liability and workers' compensation.
Due to damages resulting from several PUC-reportable storms that occurred in 2011, PPL Electric has exceeded its deductible for the 2011 policy year. Probable recoveries on insurance claims with PPL Power Insurance of $26.5 million were recorded during 2011, of which $16 million was included in "Other operation and maintenance" on the Statement of Income and the remainder was recorded in PP&E on the Balance Sheet.
Other (PPL Energy Supply, PPL Electric, LKE, LG&E and KU)
See Note 1 for discussions regarding the intercompany tax sharing agreement and Note 7 for a discussion regarding capital transactions by PPL Energy Supply, PPL Electric, LKE, LG&E and KU. For PPL Energy Supply, PPL Electric and LKE, refer to Note 1 for discussions regarding intercompany allocations of stock-based compensation expense. For PPL Energy Supply, PPL Electric, LG&E and KU, see Note 13 for discussions regarding intercompany allocations associated with defined benefits.
(a)
Represents PPL Energy Supply's $25 million gain on its tender offers to purchase up to $250 million aggregate principal amount of certain of its outstanding senior notes and PPL's additional net gain of $4 million as a result of reclassifying net gains on related cash flow hedges from AOCI into earnings.
(b)
Represents a gain on foreign currency contracts that hedged the repayment of the 2011 Bridge Facility borrowing.
(c)
As a result of PPL Electrics redemption of 7.125% Senior Secured Bonds due 2013, PPL recorded a gain on the accelerated amortization of the fair value adjustment to the debt recorded in connection with previously settled fair value hedges.
(d)
Represents losses reclassified from AOCI into earnings associated with discontinued hedges at PPL for debt that had been planned to be issued by PPL Energy Supply. As a result of the expected net proceeds from the sale of certain non-core generation facilities, coupled with the monetization of full-requirement sales contracts, the debt issuance was no longer needed.
(e)
Represents a foreign currency loss related to the repayment of the 2011 Bridge Facility borrowing.
18. Fair Value Measurements and Credit Concentration
(PPL, PPL Energy Supply, PPL Electric, LKE, LG&E and KU)
Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (an exit price). PPL and its subsidiaries use, as appropriate, a market approach (generally, data from market transactions), an income approach (generally, present value techniques and option-pricing models), and/or a cost approach (generally, replacement cost) to measure the fair value of an asset or liability. These valuation approaches incorporate inputs such as observable, independent market data and/or unobservable data that management believes are predicated on the assumptions market participants would use to price an asset or liability. These inputs may incorporate, as applicable, certain risks such as nonperformance risk, which includes credit risk.
Recurring Fair Value Measurements
The assets and liabilities measured at fair value were:
(a)
Current portion is included in "Restricted cash and cash equivalents" and long-term portion is included in "Other noncurrent assets" on the Balance Sheets.
(b)
Included in "Other investments" on the Balance Sheets.
(c)
Current portion is included in "Other current assets" on the Balance Sheets. Such amounts were insignificant at December 31, 2011 and December 31, 2010. The long-term portion is included in "Other noncurrent assets" on the Balance Sheets.
(d)
Included in "Other current liabilities" on the Balance Sheets.
(e)
Current portion is included in "Other current liabilities" on the Balance Sheets. The long-term portion is included in "Price risk management liabilities" on the Balance Sheets.
At December 31, 2011 and 2010, KU's price risk management assets and liabilities arising from energy commodities and interest rate swaps accounted for at fair value on a recurring basis were not significant.
(a)
"Energy Commodities" and "Cross-Currency Swaps" are included in "Qualifying derivatives" and "Auction Rate Securities" are included in "Available-for-sale securities" on the Statements of Comprehensive Income.
(b)
Accounting guidance effective January 1, 2011 requires purchase, sale, issuance and settlement transactions within Level 3 to be presented on a gross basis. The transactions in 2010 are reported on a net basis.
(a)
"Energy Commodities" are included in "Qualifying derivatives" and "Auction Rate Securities" are included in "Available-for-sale securities" on the Statements of Comprehensive Income.
(b)
Accounting guidance effective January 1, 2011 requires purchase, sale, issuance and settlement transactions within Level 3 to be presented on a gross basis. The transactions in 2010 are reported on a net basis.
Net gains and losses on assets and liabilities classified as Level 3 and included in earnings for the years ended were reported in the Statements of Income as follows:
PPL and its subsidiaries recognize transfers between levels at end-of-reporting-period values.
Price Risk Management Assets/Liabilities - Energy Commodities
Energy commodity contracts are generally valued using the income approach, except for exchange-traded derivative gas, oil and emission allowance contracts, which are valued using the market approach and are classified as Level 1. When observable inputs are used to measure all or most of the value of a contract, the contract is classified as Level 2. Over-the-counter (OTC) contracts are valued using quotes obtained from an exchange, binding and non-binding broker quotes, prices posted by ISOs or published tariff rates. Furthermore, PPL and its subsidiaries obtain independent quotes from the market to validate the forward price curves. OTC contracts include forwards, swaps, options and structured deals for electricity, gas, oil and/or emission allowances and may be offset with similar positions in exchange-traded markets. To the extent possible, fair value measurements utilize various inputs that include quoted prices for similar contracts or market-corroborated inputs. In certain instances, these instruments may be valued using models, including standard option valuation models and standard industry models. For example, the fair value of a structured deal that delivers power to an illiquid delivery point may be measured by valuing the nearest liquid trading point plus the value of the basis between the two points. The basis input may be from market quotes, FTR prices or historical prices.
When unobservable inputs are significant to the fair value measurement, a contract is classified as Level 3. Additionally, Level 2 and Level 3 fair value measurements include adjustments for credit risk based on PPL's own creditworthiness (for net liabilities) and its counterparties' creditworthiness (for net assets). PPL's credit department assesses all reasonably available market information and probabilities of default used to calculate the credit adjustment. PPL assumes that observable market prices include sufficient adjustments for liquidity and modeling risks, but for Level 3 fair value measurements, PPL also assesses the need for additional adjustments for liquidity or modeling risks. The contracts classified as Level 3 represent contracts for which delivery is at a location where pricing is unobservable or the delivery dates are beyond the dates for which independent prices are available. To measure the fair value of these contracts, PPL uses internally developed models that project forward prices. The models use proxy locations, historical settlement prices and extrapolation of observable forward curves.
In certain instances, energy commodity contracts are transferred between Level 2 and Level 3. The primary reasons for the transfers during 2011 and 2010 were changes in the availability of market information and changes in the significance of the unobservable portion of the contract. As the delivery period of a contract becomes closer, market information may become available. When this occurs, the model's unobservable inputs are replaced with observable market information.
Price Risk Management Assets/Liabilities - Interest Rate Swaps/Foreign Currency Exchange Contracts/Cross-Currency Swaps
To manage their interest rate risk, PPL and its subsidiaries generally use interest rate contracts such as forward-starting swaps, floating-to-fixed swaps and fixed-to-floating swaps. To manage their foreign currency exchange risk, PPL and its subsidiaries generally use foreign currency exchange contracts such as forwards and options, as well as cross-currency swaps that contain characteristics of both interest rate and foreign currency exchange contracts. PPL and its subsidiaries use an income approach to measure the fair value of these contracts, utilizing readily observable inputs, such as forward interest rates (e.g., LIBOR and government security rates) and forward foreign currency exchange rates (e.g., GBP and Euro), as well as inputs that may not be observable, such as credit valuation adjustments. In certain cases, PPL and its subsidiaries cannot practicably obtain market information to value credit risk and therefore rely on their own models. These models use projected probabilities of default based on historical observances. When the credit valuation adjustment is significant to the overall valuation, the contracts are classified as Level 3. Certain cross-currency contracts were executed in 2011 and upon remeasurement of their fair value were transferred to Level 3 due to the significance of the credit adjustment driven by the long dated nature of the contracts.
(PPL and PPL Energy Supply)
NDT Funds
PPL and PPL Energy Supply generally use the market approach to measure the fair value of equity securities held in the NDT funds.
·
The fair value measurements of equity securities classified as Level 1 are based on quoted prices in active markets and are comprised of securities that are representative of the Wilshire 5000 index, which is invested in approximately 70% large-cap stocks and 30% mid/small-cap stocks.
·
Investments in commingled equity funds are classified as Level 2 and represent securities that track the S&P 500 index and the Wilshire 4500 index. These fair value measurements are based on firm quotes of net asset values per share, which are not obtained from a quoted price in an active market.
Debt securities are generally measured using a market approach, including the use of matrix pricing. Common inputs include reported trades, broker/dealer bid/ask prices, benchmark securities and credit valuation adjustments. When necessary, the fair value of debt securities is measured using the income approach, which incorporates similar observable inputs, as well as benchmark yields, credit valuation adjustments, reference data from market research publications, monthly payment data, collateral performance and new issue data.
The debt securities held by the NDT funds at December 31, 2011 have a weighted-average coupon of 4.40% and a weighted-average maturity of 8.46 years.
Auction Rate Securities
PPL's and PPL Energy Supply's auction rate securities include Federal Family Education Loan Program guaranteed student loan revenue bonds, as well as various municipal bond issues. At December 31, 2011, contractual maturities for these auction rate securities were a weighted average of approximately 24 years. PPL and PPL Energy Supply do not have significant exposure to realize losses on these securities; however, auction rate securities are classified as Level 3 because failed auctions limit the amount of observable market data that is available for measuring the fair value of these securities.
The fair value of auction rate securities is estimated using an income approach with inputs for the underlying structure and credit quality of each security; the present value of future interest payments, estimated based on forward rates of the SIFMA Index, and principal payments discounted using interest rates for bonds with a credit rating and remaining term to maturity similar to the stated maturity of the auction rate securities; and the impact of auction failures or redemption at par.
Nonrecurring Fair Value Measurements
The following nonrecurring fair value measurements occurred during the reporting periods, resulting in asset impairments.
(a)
Represents carrying value before fair value measurement.
(b)
Losses on sulfur dioxide emission allowances and RECs were recorded in the Supply segment and included in "Other operation and maintenance" on the Statements of Income. Losses on certain non-core generation facilities and the Long Island generation business were recorded in the Supply segment and included in "Income (Loss) from Discontinued Operations (net of income taxes)" on the Statements of Income.
(c)
Current and long-term sulfur dioxide emission allowances and RECs are included in "Other intangibles" in their respective areas on the Balance Sheets.
Sulfur Dioxide Emission Allowances
Due to declines in market prices, PPL Energy Supply assessed the recoverability of sulfur dioxide emission allowances not expected to be consumed. When available, observable market prices were used to value the sulfur dioxide emission allowances. When observable market prices were not available, fair value was modeled using prices from observable transactions and appropriate discount rates. The modeled values were significant to the overall fair value measurement, resulting in the Level 3 classification.
RECs
Due to declines in forecasted full-requirement obligations in certain markets as well as declines in market prices, PPL Energy Supply assessed the recoverability of certain RECs not expected to be used. Observable market prices (Level 2) were used to value the RECs.
Certain Non-Core Generation Facilities
Certain non-core generation facilities met the held for sale criteria at September 30, 2010. As a result, net assets held for sale were written down to their estimated fair value less cost to sell. The fair value in the table above excludes $4 million of estimated costs to sell and was based on the negotiated sales price (achieved through an active auction process). See Note 9 for additional information on the completed sale.
Long Island Generation Business
The Long Island generation business met the held for sale criteria at June 30, 2009. As a result, net assets held for sale were written down to their estimated fair value less cost to sell. The fair value in the table above excludes $1 million of estimated costs to sell and was based on the negotiated sales price (achieved through an active auction process). See Note 9 for additional information on the completed sale.
Financial Instruments Not Recorded at Fair Value (PPL, PPL Energy Supply, PPL Electric, LKE, LG&E and KU)
The carrying amounts of contract adjustment payments related to the 2010 Purchase Contract component of the 2010 Equity Units, the 2011 Purchase Contract component of the 2011 Equity Units, and long-term debt on the Balance Sheets and their estimated fair values are set forth below. The fair values of these instruments were estimated using an income approach by discounting future cash flows at estimated current cost of funding rates. The effect of third-party credit enhancements is not included in the fair value measurement.
(a)
Included in "Other current liabilities" and "Other deferred credits and noncurrent liabilities" on the Balance Sheets.
The carrying value of short-term debt (including notes between affiliates), when outstanding, represents or approximates fair value due to the variable interest rates associated with the financial instruments. The carrying value of held-to-maturity, short-term investments approximates fair value due to the liquid nature and short-term duration of these instruments.
Credit Concentration Associated with Financial Instruments
(PPL, PPL Energy Supply, PPL Electric, LKE, LG&E and KU)
PPL and its subsidiaries enter into contracts with many entities for the purchase and sale of energy. Many of these contracts qualify for NPNS and as such, the fair value of these contracts is not reflected in the financial statements. However, the fair value of these contracts is considered when committing to new business from a credit perspective. See Note 19 for information on credit policies used by PPL and its subsidiaries to manage credit risk, including master netting arrangements and collateral requirements.
(PPL)
At December 31, 2011, PPL had credit exposure of $3.0 billion from energy trading partners, excluding the effects of netting arrangements and collateral. As a result of netting arrangements and collateral, PPL's credit exposure was reduced to $866 million. One of the counterparties accounted for 11% of the exposure, and the next highest counterparty accounted for 6% of the exposure. Ten counterparties accounted for $457 million, or 53%, of the net exposure. These counterparties had an investment grade credit rating from S&P or Moody's. The foregoing excludes a long-term supply contract with SMGT due to SMGT's filing for bankruptcy protection during the fourth quarter of 2011. The outstanding accounts receivable associated with SMGT at December 31, 2011 was $14 million, of which $11 million has been reserved. See Note 15 for more information.
(PPL Energy Supply)
At December 31, 2011, PPL Energy Supply had credit exposure of $3.0 billion from energy trading partners, excluding exposure from related parties and the effects of netting arrangements and collateral. As a result of netting arrangements and collateral, this credit exposure was reduced to $863 million. One of the counterparties accounted for 11% of the exposure, and the next highest counterparty accounted for 6% of the exposure. Ten counterparties accounted for $457 million, or 53%, of the net exposure. These counterparties had an investment grade credit rating from S&P or Moody's. The foregoing excludes a long-term supply contract with SMGT due to SMGT's filing for bankruptcy protection during the fourth quarter of 2011. The outstanding accounts receivable associated with SMGT at December 31, 2011 was $14 million, of which $11 million has been reserved. See Note 15 for more information.
(PPL Electric)
At December 31, 2011, PPL Electric had no credit exposure under energy supply contracts (including its supply contracts with PPL EnergyPlus).
(LKE, LG&E and KU)
At December 31, 2011, LKE's, LG&E's and KU's credit exposure was not significant.
19. Derivative Instruments and Hedging Activities
Risk Management Objectives
(PPL, PPL Energy Supply, PPL Electric, LKE, LG&E and KU)
PPL has a risk management policy approved by the Board of Directors to manage market risk and counterparty credit risk. The RMC, comprised of senior management and chaired by the Chief Risk Officer, oversees the risk management function. Key risk control activities designed to ensure compliance with the risk policy and detailed programs include, but are not limited to, credit review and approval, validation of transactions and market prices, verification of risk and transaction limits, VaR analyses, portfolio stress tests, gross margin at risk analyses, sensitivity analyses and daily portfolio reporting, including open positions, determinations of fair value and other risk management metrics. During the second quarter of 2011, the RMC formally approved the inclusion of the risk programs for LKE (acquired in November 2010) under the risk management policy. WPD Midlands (acquired in April 2011) adhered to the applicable risk management programs, including interest rate and foreign currency exchange programs, from the date of acquisition.
Market Risk
Market risk is the potential loss PPL and its subsidiaries may incur as a result of price changes associated with a particular financial or commodity instrument. PPL and its subsidiaries utilize forward contracts, futures contracts, options, swaps and structured deals, such as tolling agreements, as part of risk management strategies, to minimize unanticipated fluctuations in earnings caused by changes in commodity prices, volumes of full-requirement sales contracts, basis exposure, interest rates and/or foreign currency exchange rates. All derivatives are recognized on the Balance Sheets at their fair value, unless they qualify for NPNS.
PPL is exposed to market risk from foreign currency exchange risk primarily associated with its investments in U.K. affiliates, as well as additional market risk from certain subsidiaries, as discussed below. As described in Note 9, in January 2011, PPL Energy Supply distributed its membership interest in PPL Global to PPL Energy Supply's parent, PPL Energy Funding. Therefore, effective January 2011, PPL Energy Supply is no longer subject to interest rate and foreign currency exchange risk associated with investments in U.K. affiliates.
PPL Energy Supply is exposed to market risk from:
·
commodity price, basis and volumetric risks for energy and energy-related products associated with the sale of electricity from its generating assets and other electricity marketing activities (including full-requirement sales contracts) and the purchase of fuel and fuel-related commodities for generating assets, as well as for proprietary trading activities;
·
interest rate and price risk associated with debt used to finance operations, as well as debt and equity securities in NDT funds and defined benefit plans; and
·
foreign currency exchange rate risk associated with firm commitments in currencies other than the applicable functional currency.
PPL Electric is exposed to market and volumetric risks from PPL Electric's obligation as PLR. The PUC has approved a cost recovery mechanism that allows PPL Electric to pass through to customers the cost associated with fulfilling its PLR obligation. This cost recovery mechanism substantially eliminates PPL Electric's exposure to market risk. PPL Electric also mitigates its exposure to volumetric risk by entering into full-requirement supply agreements for its customers. These supply agreements transfer the volumetric risk associated with the PLR obligation to the energy suppliers.
By definition, the regulatory environments for PPL's other regulated entities, LKE (through its subsidiaries LG&E and KU) and WPD, significantly mitigate market risk. LG&E's and KU's rates are set to permit the recovery of prudently incurred costs, including certain mechanisms for fuel, gas supply and environmental expenses. These mechanisms generally provide for timely recovery of market price and volumetric fluctuations associated with these expenses. LG&E and KU primarily utilized forward financial transactions to manage price risk associated with expected economic generation capacity in excess of expected load requirements. WPD does not have supply risks as it is only in the distribution business.
LG&E also utilizes over-the-counter interest rate swaps to limit exposure to market fluctuations on interest expense. WPD utilizes over-the-counter cross currency swaps to limit exposure to market fluctuations on interest and principal payments from foreign currency exchange rates.
Credit Risk
Credit risk is the potential loss PPL and its subsidiaries may incur due to a counterparty's non-performance, including defaults on payments and energy commodity deliveries.
PPL is exposed to credit risk from interest rate and foreign currency derivatives with financial institutions, as well as additional credit risk through certain of its subsidiaries, as discussed below.
PPL Energy Supply is exposed to credit risk from commodity derivatives with their energy trading partners, which include other energy companies, fuel suppliers and financial institutions.
PPL Electric is exposed to credit risk from PPL Electric's supply agreements for its PLR obligation.
LG&E is exposed to credit risk from interest rate derivatives with financial institutions.
The majority of PPL's and its subsidiaries' credit risk stems from PPL subsidiaries' commodity derivatives for multi-year contracts for energy sales and purchases. If PPL Energy Supply's counterparties fail to perform their obligations under such contracts and PPL Energy Supply could not replace the sales or purchases at the same prices as those under the defaulted contracts, PPL Energy Supply would incur financial losses. Those losses would be recognized immediately or through lower revenues or higher costs in future years, depending on the accounting treatment for the defaulted contracts. In the event a supplier of LKE (through its subsidiaries LG&E and KU) or PPL Electric defaults on its obligation, those entities would be required to seek replacement power or replacement fuel in the market. In general, incremental costs incurred by these entities would be recoverable from customers in future rates.
PPL and its subsidiaries have credit policies to manage their credit risk, including the use of an established credit approval process, daily monitoring of counterparty positions and the use of master netting agreements. These agreements generally include credit mitigation provisions, such as margin, prepayment or collateral requirements. PPL and its subsidiaries may request the additional credit assurance, in certain circumstances, in the event that the counterparties' credit ratings fall below investment grade or their exposures exceed an established credit limit. See Note 18 for credit concentration associated with financial instruments.
Master Netting Arrangements
PPL and its subsidiaries have elected not to offset net derivative positions against the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a payable) under master netting arrangements.
PPL's and PPL Energy Supply's obligation to return counterparty cash collateral under master netting arrangements was $147 million and $338 million at December 31, 2011 and December 31, 2010.
PPL Electric, LKE, LG&E and KU had no obligation to return cash collateral under master netting arrangements at December 31, 2011 and December 31, 2010.
PPL Energy Supply, PPL Electric and KU had not posted any cash collateral under master netting arrangements at December 31, 2011 and December 31, 2010.
PPL, LKE and LG&E had posted cash collateral under master netting arrangements of $29 million at December 31, 2011 and $19 million at December 31, 2010.
Commodity Price Risk (Non-trading)
(PPL and PPL Energy Supply)
Commodity price and basis risks are among PPL's and PPL Energy Supply's most significant risks due to the level of investment that PPL and PPL Energy Supply maintain in their competitive generation assets, as well as the extent of their marketing and proprietary trading activities. Several factors influence price levels and volatilities. These factors include, but are not limited to, seasonal changes in demand, weather conditions, available generating assets within regions, transportation/transmission availability and reliability within and between regions, market liquidity, and the nature and extent of current and potential federal and state regulations.
PPL and PPL Energy Supply enter into financial and physical derivative contracts, including forwards, futures, swaps and options, to hedge the price risk associated with electricity, gas, oil and other commodities. Certain contracts qualify for
NPNS or are non-derivatives and are therefore not reflected in the financial statements until delivery. PPL and PPL Energy Supply segregate their remaining non-trading activities into two categories: cash flow hedge activity and economic activity. In addition, the monetization of certain full-requirement sales contracts in 2010 impacted both the cash flow hedge and economic activity, as discussed below.
Monetization of Certain Full-Requirement Sales Contracts
In July 2010, in order to raise additional cash for the LKE acquisition, PPL Energy Supply monetized certain full-requirement sales contracts that resulted in cash proceeds of $249 million and triggered certain accounting:
·
A portion of these sales contracts had previously been accounted for as NPNS and received accrual accounting treatment. PPL Energy Supply could no longer assert that it was probable that any contracts with these counterparties would result in physical delivery. Therefore, the fair value of the NPNS contracts of $160 million was recorded on the Balance Sheet in "Price risk management assets," with a corresponding gain of $144 million recorded to "Wholesale energy marketing - Realized" on the Statement of Income, and $16 million recorded to "Wholesale energy marketing - Unrealized economic activity," related to full-requirement sales contracts that had not been monetized.
·
The related purchases to supply these sales contracts were accounted for as cash flow hedges, with the effective portion of the change in fair value being recorded in AOCI and the ineffective portion recorded in "Energy purchases - Unrealized economic activity." The corresponding cash flow hedges were dedesignated and all amounts previously recorded in AOCI were reclassified to earnings. This resulted in a pre-tax reclassification of $(173) million of losses from AOCI into "Energy purchases - Unrealized economic activity" on the Statement of Income. An additional charge of $(39) million was also recorded in "Wholesale energy marketing - Unrealized economic activity" on the Statement of Income to reflect the fair value of the sales contracts previously accounted for as economic activity.
·
The net result of these transactions, excluding the full-requirement sales contracts that have not been monetized, was a loss of $(68) million, or $(40) million, after tax.
The proceeds of $249 million from these monetizations are reflected in the Statement of Cash Flows as a component of "Net cash provided by operating activities."
Cash Flow Hedges
Many derivative contracts have qualified for hedge accounting so that the effective portion of a derivative's gain or loss is deferred in AOCI and reclassified into earnings when the forecasted transaction occurs. The cash flow hedges that existed at December 31, 2011 range in maturity through 2016. At December 31, 2011, the accumulated net unrecognized after-tax gains (losses) that are expected to be reclassified into earnings during the next 12 months were $394 million for PPL and PPL Energy Supply. Cash flow hedges are discontinued if it is no longer probable that the original forecasted transaction will occur by the end of the originally specified time periods and any amounts previously recorded in AOCI are reclassified into earnings once it is determined that the hedge transaction is probable of not occurring. For 2011, such reclassifications were insignificant. For 2010 and 2009, such reclassifications were after-tax gains (losses) of $(89) million and $9 million. The amounts recorded in 2010 were primarily due to the monetization of certain full-requirement sales contracts, for which the associated hedges are no longer required, as discussed above.
For 2011, 2010 and 2009, hedge ineffectiveness associated with energy derivatives was, after-tax, a loss of $(22) million, a loss of $(30) million and a gain of $41 million.
In addition, when cash flow hedge positions fail hedge effectiveness testing, hedge accounting is not permitted in the quarter in which this occurs and, accordingly, the entire change in fair value for the periods that failed is recorded to the Statement of Income. Certain power and gas cash flow hedge positions failed effectiveness testing during 2008 and the first quarter of 2009. However, these positions were not dedesignated as hedges, as prospective regression analysis demonstrated that these hedges were expected to be highly effective over their term. During 2009, fewer power and gas cash flow hedges failed hedge effectiveness testing; therefore, a portion of the previously recognized unrealized gains recorded in 2008 associated with these hedges were reversed. For 2009, after-tax gains (losses) of $(215) million were recognized in earnings as a result of these reversals. During the first quarter of 2010, after-tax gains (losses) of $(82) million were recognized in earnings as a result of these reversals continuing. Effective April 1, 2010, clarifying accounting guidance was issued that precludes the reversal of previously recognized gains/losses resulting from hedge failures. By the end of the first quarter of 2010, all previously recorded hedge ineffectiveness gains resulting from hedge failures were reversed; thus, the new accounting guidance did not have a significant impact at adoption on April 1, 2010.
Economic Activity
Certain derivative contracts economically hedge the price and volumetric risk associated with electricity, gas, oil and other commodities but do not receive hedge accounting treatment. These derivatives hedge a portion of the economic value of PPL and PPL Energy Supply's competitive generation assets and unregulated full-requirement and retail contracts, which are subject to changes in fair value due to market price volatility and volume expectations. Additionally, economic activity includes the ineffective portion of qualifying cash flow hedges (see "Cash Flow Hedges" above). The derivative contracts in this category that existed at December 31, 2011 range in maturity through 2019.
Examples of economic activity include certain purchase contracts used to supply full-requirement sales contracts; FTRs or basis swaps used to hedge basis risk associated with the sale of competitive generation or supplying unregulated full-requirement sales contracts; spark spreads (sale of electricity with the simultaneous purchase of fuel); retail electric and gas activities; and fuel oil swaps used to hedge price escalation clauses in coal transportation and other fuel-related contracts. PPL Energy Supply also uses options, which include the sale of call options and the purchase of put options tied to a particular generating unit. Since the physical generating capacity is owned, the price exposure is limited to the cost of the particular generating unit and does not expose PPL Energy Supply to uncovered market price risk.
Unrealized activity associated with monetizing certain full-requirement sales contracts was also included in economic activity during 2011.
The net fair value of economic positions at December 31, 2011 and December 31, 2010 was a net (asset) liability of $63 million and $389 million for PPL Energy Supply. The unrealized gains (losses) for economic activity are as follows.
The net gains (losses) recorded in "Wholesale energy marketing" resulted primarily from certain full-requirement sales contracts for which PPL Energy Supply did not elect NPNS, from hedge ineffectiveness, including hedges that failed effectiveness testing, as discussed in "Cash Flow Hedges" above, and from the July 2010 monetization of certain full-requirement sales contracts. The net gains (losses) recorded in "Energy purchases" resulted primarily from certain purchase contracts to supply the full-requirement sales contracts noted above for which PPL Energy Supply did not elect hedge treatment, from hedge ineffectiveness, including hedges that failed effectiveness testing, and from purchase contracts that no longer hedge the full-requirement sales contracts that were monetized as discussed above in "Monetization of Certain Full-Requirement Sales Contracts."
(PPL, LKE, LG&E and KU)
LG&E and KU primarily utilized forward financial transactions to manage price risk associated with expected economic generation capacity in excess of expected load requirements. Hedge accounting treatment was not elected for these transactions; therefore, realized and unrealized gains and losses are recorded in the Statements of Income.
The net fair value of economic positions for LKE, LG&E and KU at December 31, 2010 were not significant. There are no economic positions at December 31, 2011. Unrealized gains (losses) for economic activity for LKE, LG&E and KU in 2011, 2010 and 2009 were not significant.
(PPL and PPL Energy Supply)
Commodity Price Risk (Trading)
PPL Energy Supply also executes energy contracts to take advantage of market opportunities. As a result, PPL Energy Supply may at times create a net open position in its portfolio that could result in significant losses if prices do not move in the manner or direction anticipated. PPL Energy Supply's trading activity is shown in "Net energy trading margins" on the Statements of Income.
Commodity Volumetric Activity
PPL Energy Supply currently employs four primary strategies to maximize the value of its wholesale energy portfolio. As further discussed below, these strategies include the sales of baseload generation, optimization of intermediate and peaking generation, marketing activities, and proprietary trading activities. The tables within this section present the volumes of PPL Energy Supply's derivative activity, excluding those that qualify for NPNS, unless otherwise noted.
Sales of Baseload Generation
PPL Energy Supply has a formal hedging program for its competitive baseload generation fleet, which includes 7,252 MW of nuclear, coal and hydroelectric generating capacity. The objective of this program is to provide a reasonable level of near-term cash flow and earnings certainty while preserving upside potential of power price increases over the medium term. PPL Energy Supply sells its expected generation output on a forward basis using both derivative and non-derivative instruments. Both are included in the following tables.
The following table presents the expected sales, in GWh, from competitive baseload generation and tolling arrangements that are included in the baseload portfolio based on current forecasted assumptions for 2012-2014. These expected sales could be impacted by several factors, including plant availability.
The following table presents the percentage of expected baseload generation sales shown above that has been sold forward under fixed price contracts and the related percentage of fuel that has been purchased or committed at December 31, 2011.
(a)
Excludes non-derivative contracts and contracts that qualify for NPNS. Volumes for option contracts factor in the probability of an option being exercised and may be less than the notional amount of the option.
(b)
Amount represents derivative (including contracts that qualify for NPNS) and non-derivative contracts. Volumes for option contracts factor in the probability of an option being exercised and may be less than the notional amount of the option. Percentages are based on fixed-price contracts only.
(c)
Coal and nuclear contracts receive accrual accounting treatment, as they are not derivative contracts. Percentages are based on both fixed- and variable-priced contracts.
(d)
Volumes for derivative sales contracts that deliver in future periods total 1,541 GWh and 7.2 Bcf.
In addition to the fuel purchases above, PPL Energy Supply attempts to economically hedge the fuel price risk that is within its fuel-related and coal transportation contracts, which are tied to changes in crude oil or diesel prices. PPL Energy Supply has also entered into contracts to financially hedge the physical sale of oil. The following table presents the net volumes (in thousands of barrels) of derivative (sales)/purchase contracts used in support of these strategies at December 31, 2011.
Optimization of Intermediate and Peaking Generation
In addition to its competitive baseload generation activities, PPL Energy Supply attempts to optimize the overall value of its competitive intermediate and peaking fleet, which includes 3,256 MW of gas and oil-fired generation. The following table presents the net volumes of derivative (sales)/purchase contracts used in support of this strategy at December 31, 2011.
(a)
Volumes for derivative contracts used in support of these strategies that deliver in future periods are insignificant.
(b)
Included in these volumes are non-options and exercised option contracts that converted to non-option derivative contracts. Volumes associated with option contracts are not significant.
Marketing Activities
PPL Energy Supply's marketing portfolio is comprised of full-requirement sales contracts and their related supply contracts, retail gas and electricity sales contracts and other marketing activities. The full-requirement sales contracts and their related supply contracts make up a significant component of the marketing portfolio. The obligations under the full-requirement sales contracts include supplying a bundled product of energy, capacity, RECs, and other ancillary products. The full-requirement sales contracts PPL Energy Supply is awarded do not provide for specific levels of load, and actual load could vary significantly from forecasted amounts. PPL Energy Supply uses a variety of strategies to hedge its full-requirement sales contracts, including purchasing energy at a liquid trading hub or directly at the load delivery zone, purchasing capacity and RECs in the market and supplying the energy, capacity and RECs with its generation. The following table presents the volume of (sales)/purchase contracts, excluding FTRs, RECs, basis and capacity contracts, used in support of these activities at December 31, 2011.
(a)
Includes NPNS and contracts that are not derivatives, which receive accrual accounting.
(b)
PPL Energy Supply uses power and gas options, swaps and futures to hedge the volumetric risk associated with full-requirement sales contracts since the demand for power varies hourly. Volumes for option contracts factor in the probability of an option being exercised and may be less than the notional amount of the option.
Proprietary Trading Activity
At December 31, 2011, PPL Energy Supply's proprietary trading positions, excluding FTR, basis and capacity contract activity that is included in the tables below, were not significant.
Other Energy-Related Positions
FTRs and Other Basis Positions
PPL Energy Supply buys and sells FTRs and other basis positions to mitigate the basis risk between delivery points related to the sales of its generation, the supply of its full-requirement sales contracts and retail contracts, as well as for proprietary trading purposes. The following table presents the net volumes of derivative FTR and basis (sales)/purchase contracts at December 31, 2011.
(a)
Net volumes that deliver in future periods are (677) GWh and (5.1) Bcf.
Capacity Positions
PPL Energy Supply buys and sells capacity related to the sales of its generation and the supply of its full-requirement sales contracts. These contracts qualify for NPNS and receive accrual accounting. PPL Energy Supply also sells and purchases capacity for proprietary trading purposes. These contracts are marked to fair value through earnings. The following table presents the net volumes of derivative capacity (sales)/purchase contracts at December 31, 2011.
(a)
Volumes that deliver in future periods are 989 MW-months.
Interest Rate Risk
(PPL, PPL Energy Supply, LKE and LG&E)
PPL and its subsidiaries have issued debt to finance their operations, which exposes them to interest rate risk. PPL and its subsidiaries utilize various financial derivative instruments to adjust the mix of fixed and floating interest rates in their debt portfolio, adjust the duration of their debt portfolio and lock in benchmark interest rates in anticipation of future financing, when appropriate. Risk limits under the risk management program are designed to balance risk exposure to volatility in interest expense and changes in the fair value of PPL's and its subsidiaries' debt portfolio due to changes in benchmark interest rates.
Cash Flow Hedges (PPL and PPL Energy Supply)
Interest rate risks include exposure to adverse interest rate movements for outstanding variable rate debt and for future anticipated financings. PPL and PPL Energy Supply enter into financial interest rate swap contracts that qualify as cash flow hedges to hedge floating interest rate risk associated with both existing and anticipated debt issuances. For PPL, outstanding interest rate swap contracts ranged in maturity through 2022 and had a notional value of $150 million at December 31, 2011. No contracts were outstanding for PPL Energy Supply at December 31, 2011.
Through PPL, PPL WEM holds a notional position in cross-currency interest rate swaps totaling $960 million that mature through 2021 to hedge the interest payments and principal of the U.S. dollar-denominated senior notes issued by PPL WEM in April 2011. Additionally, PPL WW holds a notional position in cross-currency interest rate swaps totaling $302 million that mature through December 2028 to hedge the interest payments and principal of its U.S. dollar-denominated senior notes. In 2010, these PPL WW swaps were part of PPL Energy Supply's business. As a result of the distribution of PPL Energy Supply's membership interest in PPL Global to PPL Energy Funding effective January 2011, these swaps are no longer part of PPL Energy Supply's business.
For 2011, hedge ineffectiveness associated with interest rate derivatives resulted in a net after-tax gain (loss) of $(9) million for PPL, which included a gain (loss) of $(4) million attributable to certain interest rate swaps that failed hedge effectiveness testing during the second quarter of 2011. For 2010, hedge ineffectiveness associated with these derivatives resulted in a net after-tax gain (loss) of $(9) million for PPL and was insignificant for PPL Energy Supply. For 2009, hedge ineffectiveness associated with these derivatives was insignificant for PPL and PPL Energy Supply.
Cash flow hedges are discontinued if it is no longer probable that the original forecasted transaction will occur by the end of the originally specified time periods and any amounts previously recorded in AOCI are reclassified into earnings once it is determined that the hedged transaction is probable of not occurring. PPL had no such reclassifications for 2011. As a result of the expected net proceeds from the anticipated sale of certain non-core generation facilities, coupled with the monetization of certain full-requirement sales contracts, debt that had been planned to be issued by PPL Energy Supply in 2010 was no longer needed. As a result, hedge accounting associated with interest rate swaps entered into by PPL in anticipation of a debt issuance by PPL Energy Supply was discontinued. PPL reclassified into earnings a net after-tax gain (loss) of $(19) million in 2010 and an insignificant amount in 2009. PPL Energy Supply had no such reclassifications in 2011, 2010 and 2009.
At December 31, 2011, the accumulated net unrecognized after-tax gains (losses) on qualifying derivatives that are expected to be reclassified into earnings during the next 12 months were $(12) million for PPL and insignificant for PPL Energy Supply. Amounts are reclassified as the hedged interest payments are made.
Fair Value Hedges
(PPL and PPL Energy Supply)
PPL and PPL Energy Supply are exposed to changes in the fair value of their debt portfolios. To manage this risk, PPL and PPL Energy Supply may enter into financial contracts to hedge fluctuations in the fair value of existing debt issuances due to changes in benchmark interest rates. At December 31, 2011, PPL held contracts that range in maturity through 2047 and had a notional value of $99 million. PPL Energy Supply did not hold any such contracts at December 31, 2011. PPL and PPL Energy Supply did not recognize gains or losses resulting from the ineffective portion of fair value hedges or from a portion of the hedging instrument being excluded from the assessment of hedge effectiveness for 2011, 2010 and 2009.
(PPL)
In 2011, PPL Electric redeemed $400 million of 7.125% Senior Secured Bonds due 2013. As a result of this redemption, PPL recorded a gain (loss) of $22 million, or $14 million after tax, for 2011 in "Other Income (Expense) - net" on the
Statement of Income as a result of accelerated amortization of the fair value adjustments to the debt in connection with previously settled fair value hedges. Additionally, PPL recognized insignificant amounts from hedges of debt that no longer qualified as fair value hedges for 2010 and 2009.
(PPL Energy Supply)
PPL Energy Supply did not recognize any gains or losses resulting from hedges of debt issuances that no longer qualified as fair value hedges for 2011, 2010 and 2009.
Economic Activity (PPL, LKE and LG&E)
LG&E enters into interest rate swap contracts that economically hedge interest payments on variable rate debt. Because realized gains and losses from the swaps, including a terminated swap contract, are recoverable through regulated rates, any subsequent changes in fair value of these derivatives are included in regulatory assets or liabilities until they are realized as interest expense. Realized gains and losses are recognized in "Interest Expense" on the Statements of Income when the hedged transaction occurs. At December 31, 2011, LG&E held contracts with aggregate notional amounts of $179 million that range in maturity through 2033. The fair value of these contracts were recorded as liabilities of $60 million and $34 million at December 31, 2011 and 2010, with equal offsetting amounts recorded as regulatory assets.
Prior to the third quarter of 2010, LG&E Predecessor accounted for these contracts as cash flow hedges and reclassified amounts previously recorded in AOCI to earnings in the same period during which the forecasted transaction affected earnings.
Foreign Currency Risk
(PPL and PPL Energy Supply)
PPL is exposed to foreign currency risk, primarily through investments in U.K. affiliates. In addition, PPL and its subsidiaries are exposed to foreign currency risk associated with firm commitments in currencies other than the applicable functional currency.
PPL has adopted a foreign currency risk management program designed to hedge certain foreign currency exposures, including firm commitments, recognized assets or liabilities, anticipated transactions and net investments. In addition, PPL enters into financial instruments to protect against foreign currency translation risk of expected earnings.
Cash Flow Hedges
PPL may enter into foreign currency derivatives associated with foreign currency-denominated debt and the exchange rate associated with firm commitments (including those for the purchase of equipment) denominated in foreign currencies; however, at December 31, 2011, there were no existing contracts of this nature. Amounts previously settled and recorded in AOCI are reclassified as the hedged interest payments are made and as the related equipment is depreciated. Insignificant amounts are expected to be reclassified into earnings during the next 12 months.
During 2011, 2010 and 2009, no cash flow hedges were discontinued because it was probable that the original forecasted transaction would not occur by the end of the originally specified time periods.
Fair Value Hedges
PPL enters into foreign currency forward contracts to hedge the exchange rate risk associated with firm commitments denominated in foreign currencies; however, at December 31, 2011, there were no existing contracts of this nature and no gains or losses recorded for 2011, 2010 and 2009 related to hedge ineffectiveness, or from a portion of the hedging instrument being excluded from the assessment of hedge effectiveness, or from hedges of firm commitments that no longer qualified as fair value hedges.
Net Investment Hedges
PPL enters into foreign currency contracts on behalf of a subsidiary to protect the value of a portion of its net investment in WPD. In 2010 and 2009, these contracts were included in PPL Energy Supply's business. As a result of the distribution of PPL Energy Supply's membership interest in PPL Global to PPL Energy Funding, effective January 2011, these contracts are no longer included in PPL Energy Supply's business.
The contracts outstanding at December 31, 2011 had an aggregate notional amount of £92 million (approximately $150 million based on contracted rates). The settlement dates of these contracts range from January 2012 through September 2012. At December 31, 2011 and 2010, the fair value of these positions was a net asset of $7 million. For 2011, PPL recognized an insignificant amount of activity in the foreign currency translation adjustment component of AOCI. For 2010 and 2009, PPL and PPL Energy Supply recognized insignificant amounts in the foreign currency translation adjustment component of AOCI. At December 31, 2011, PPL had $19 million of accumulated net investment hedge after-tax gains (losses) that were included in the foreign currency translation adjustment component of AOCI. At December 31, 2010, PPL and PPL Energy Supply had $15 million of accumulated net investment hedge after-tax gains (losses) that were included in the foreign currency translation adjustment component of AOCI.
Economic Activity
(PPL)
In anticipation of the repayment of a portion of the GBP-denominated borrowings under the 2011 Bridge Facility with U.S. dollar proceeds received from PPL's issuance of common stock and 2011 Equity Units and PPL WEM's issuance of U.S. dollar-denominated senior notes, as discussed in Note 7, PPL entered into forward contracts to purchase GBP in order to economically hedge the foreign currency exchange rate risk related to the repayment. When these trades were settled in April 2011, PPL recorded $55 million of pre-tax, net gains (losses) in "Other Income (Expense) - net" on the Statements of Income.
(PPL and PPL Energy Supply)
PPL and PPL Energy Supply may enter into foreign currency contracts as an economic hedge of anticipated earnings denominated in British pounds sterling. In 2010 and 2009, these contracts were included in PPL Energy Supply's business. As a result of the distribution of PPL Energy Supply's membership interest in PPL Global to PPL Energy Funding, effective January 2011, these contracts are no longer included in PPL Energy Supply's business. At December 31, 2011, the total exposure hedged by PPL was £288 million and the fair value of these positions was a net asset of $11 million. These contracts had termination dates ranging from January 2012 to November 2012. For PPL and PPL Energy Supply, the net fair value of similar hedging instruments outstanding at December 31, 2010 was insignificant. PPL records gains (losses) on these contracts, both realized and unrealized, in "Other Income (Expense) - net" on the Statements of Income. PPL Energy Supply records gains (losses) on these contracts, both realized and unrealized, in "Income (Loss) from Discontinued Operations (net of income taxes)" on the Statements of Income. For 2011, PPL recorded gains (losses) of $10 million. For 2010, the amounts for PPL and PPL Energy Supply were insignificant. For 2009, PPL and PPL Energy Supply recorded gains (losses) of $(9) million.
Accounting and Reporting
(PPL, PPL Energy Supply, PPL Electric, LKE, LG&E and KU)
All derivative instruments are recorded at fair value on the Balance Sheet as an asset or liability unless they qualify for NPNS. NPNS contracts for PPL and PPL Energy Supply include full-requirement sales contracts, other physical sales contracts and certain retail energy and physical capacity contracts, and for PPL Electric include full-requirement purchase contracts and other physical purchase contracts. Changes in the derivatives' fair value are recognized currently in earnings unless specific hedge accounting criteria are met, except for the changes in fair value of LG&E's interest rate swaps, which beginning in the third quarter of 2010, have been recognized as regulatory assets. See Note 6 for amounts recorded in regulatory assets at December 31, 2011 and December 31, 2010.
See Note 1 for additional information on accounting policies related to derivative instruments.
(PPL)
The following tables present the fair value and location of derivative instruments recorded on the Balance Sheets.
(a)
$237 million and $326 million of net gains associated with derivatives that were no longer designated as hedging instruments are recorded in AOCI at December 31, 2011 and 2010.
(b)
Represents the location on the Balance Sheet.
The after-tax balances of accumulated net gains (losses) (excluding net investment hedges) in AOCI were $527 million, $695 million and $602 million at December 31, 2011, 2010 and 2009.
The following tables present the pre-tax effect of derivative instruments recognized in income, OCI or regulatory assets.
(a)
Differs from the Statement of Income due to intra-month transactions that PPL defines as spot activity, which is not accounted for as a derivative.
(PPL Energy Supply)
The following tables present the fair value and location of derivative instruments recorded on the Balance Sheets.
(a)
$237 million and $326 million of net gains associated with derivatives that were no longer designated as hedging instruments are recorded in AOCI at December 31, 2011 and 2010.
(b)
Represents the location on the Balance Sheet.
The after-tax balances of accumulated net gains (losses) (excluding net investment hedges) in AOCI were $605 million, $733 million and $573 million at December 31, 2011, 2010 and 2009. The December 31, 2011 AOCI balance reflects the effect of PPL Energy Supply's distribution of its membership interest in PPL Global to its parent, PPL Energy Funding. See Note 9 for additional information.
The following tables present the pre-tax effect of derivative instruments recognized in income or OCI.
(a)
Differs from the Statement of Income due to intra-month transactions that PPL Energy Supply defines as spot activity, which is not accounted for as a derivative.
(LKE and LG&E)
There were no derivatives designated as hedging instruments as of December 31, 2011 and December 31, 2010. The following table presents the fair value and location of derivative instruments not designated as hedging instruments recorded on the Balance Sheets:
(a)
Represents the location on the Balance Sheet.
The following tables present the pre-tax effect of derivative instruments recognized in income or regulatory assets for the periods ended December 31, 2011, 2010 and 2009, for the Successor and Predecessor.
(KU)
There were no derivatives designated as hedging instruments as of December 31, 2011 and December 31, 2010. There were no after-tax balances of accumulated net gains (losses) in AOCI at December 31, 2011 and 2010. The gains and losses recognized in income on derivatives associated with commodity contracts were not significant for the periods ended December 31, 2011, 2010, and 2009.
Credit Risk-Related Contingent Features (PPL, PPL Energy Supply, LKE and LG&E)
Certain of PPL's, PPL Energy Supply's, LKE's and LG&E's derivative contracts contain credit risk-related contingent provisions which, when in a net liability position, would permit the counterparties to require the transfer of additional collateral upon a decrease in the credit ratings of PPL, PPL Energy Supply, LKE, LG&E, or certain of their subsidiaries. Most of these provisions would require PPL, PPL Energy Supply, LKE or LG&E to transfer additional collateral or permit the counterparty to terminate the contract if the applicable credit rating were to fall below investment grade. Some of these provisions also would allow the counterparty to require additional collateral upon each decrease in the credit rating at levels that remain above investment grade. In either case, if the applicable credit rating were to fall below investment grade (i.e., below BBB- for S&P or Fitch, or Baa3 for Moody's), and assuming no assignment to an investment grade affiliate were allowed, most of these credit contingent provisions require either immediate payment of the net liability as a termination payment or immediate and ongoing full collateralization by PPL, PPL Energy Supply, LKE or LG&E on derivative instruments in net liability positions.
Additionally, certain of PPL's, PPL Energy Supply's, LKE's and LG&E's derivative contracts contain credit risk-related contingent provisions that require PPL, PPL Energy Supply, LKE or LG&E to provide "adequate assurance" of performance if the other party has reasonable grounds for insecurity regarding PPL's, PPL Energy Supply's, LKE's or LG&E's performance of its obligation under the contract. A counterparty demanding adequate assurance could require a transfer of additional collateral or other security, including letters of credit, cash and guarantees from a creditworthy entity. This would typically involve negotiations among the parties. However, amounts disclosed below represent assumed immediate payment or immediate and ongoing full collateralization for derivative instruments in net liability positions with "adequate assurance" provisions.
At December 31, 2011, the effect of a decrease in credit ratings below investment grade on derivative contracts that contain credit contingent features and were in a net liability position is summarized as follows:
(a)
Includes the effect of net receivables and payables already recorded on the Balance Sheet.
(a)
There were no accumulated impairment losses related to goodwill.
(b)
Activity in 2011 recognized as a result of the acquisition of WPD Midlands. Activity in 2010 recognized as a result of the acquisition of LKE. A portion of the goodwill related to the acquisition of LKE was allocated to the Supply segment. See Note 10 for additional information.
(c)
Represents goodwill allocated to certain non-core generation facilities that were held for sale in 2010 and sold in 2011.
(d)
Represents the amount of goodwill derecognized as a result of PPL Energy Supply's distribution of its membership interest in PPL Global to PPL Energy Supply's parent, PPL Energy Funding. See Note 9 for additional information on the distribution. Subsequent to the distribution, PPL Energy Supply operates in a single reportable segment and reporting unit.
(a)
The opening balances included $1.5 billion of impairment losses related to goodwill recorded in 2009. There were no accumulated impairment losses related to goodwill at December 31, 2010 or 2011.
(b)
Predecessor goodwill was eliminated in purchase accounting at November 1, 2010.
(c)
Recognized as a result of the November 1, 2010 acquisition by PPL. For LG&E and KU, the allocation of goodwill was based on the net asset values of the respective companies. See Note 10 for additional information.
(LKE)
For the 2009 annual impairment test, the estimated fair values of LG&E and KU were based on a combination of the income approach, which estimates the fair value of the reporting unit based on discounted future cash flows and the market approach, which estimates the fair value of the reporting unit based on market comparables. The discounted cash flows for LG&E and KU were based on discrete financial forecasts developed by management for planning purposes and consistent with those given to E.ON AG, LKE's former parent company. Cash flows beyond the discrete forecasts were estimated using a terminal-value calculation, which incorporated historical and forecasted financial trends for each of LG&E and KU and considered long-term earnings growth rates for publicly-traded peer companies. The level 3 income-approach valuations included a cash flow discount rate of 6.3% and a terminal-value growth rate of 1.1%. In addition, subsequent to 2009 but prior to the issuance of the 2009 financial statements, discussions were held with interested parties for the possible sale of LKE, including the regulated utilities. Data from this process was used for evaluating the carrying value of goodwill at December 31, 2009.
Based on information represented by bids received from interested parties, including PPL, LKE completed a goodwill impairment analysis at December 31, 2009. As a result of the impairment analysis described above, LKE recorded a goodwill impairment charge of $1.5 billion in 2009. The primary factors contributing to the goodwill impairment charge in 2009 were the significant economic downturn, which caused a decline in the volume of projected sales of electricity to
commercial customers and an increase in the implied discount rate due to higher risk premiums. In addition, a lower control premium was assumed, based on observable market data.
(a)
Gross carrying amount for 2010 includes $394 million, which represents the fair value of contracts with terms favorable to market recognized as a result of the 2010 acquisition of LKE. The weighted average amortization period of these contracts was five years at the acquisition date. An offsetting regulatory liability was recorded related to these contracts, which is being amortized over the same weighted-average period as the intangible assets, eliminating any income statement impact. See Note 6 for additional information.
(b)
Gross carrying amount for 2011 includes $10 million, which represents the fair value of customer contracts with terms favorable to market recognized as a result of the 2011 acquisition of WPD Midlands. The weighted-average amortization period of these contracts was ten years at the acquisition date. See Note 10 for additional information.
(c)
Gross carrying amount for 2010 includes $14 million, which represents the fair value of land and transmission rights recognized as a result of the 2010 acquisition of LKE. The weighted-average amortization period of these rights was 14 years at the acquisition date. An offsetting regulatory liability was recorded related to these rights, which is being amortized over the same weighted-average period as the intangible assets, eliminating any income statement impact. See Note 6 for additional information.
(d)
These emission allowances/RECs are expensed when consumed or sold. Consumption expense was $16 million, $45 million, and $32 million in 2011, 2010 and 2009. Consumption expense is expected to be insignificant in future periods.
(e)
Gross carrying amount for 2010 includes the fair value of emission allowances recognized as a result of the 2010 acquisition of LKE. An offsetting regulatory liability was recorded related to these emission allowances, which is being amortized as the emission allowances are consumed, eliminating any income statement impact. See Note 6 for additional information. The carrying amounts of these emission allowances were $5 million and $16 million as of December 31, 2011 and 2010. Consumption related to these emission allowances was $11 million and $2 million for 2011 and 2010.
(f)
During 2011 and 2010, PPL recorded $7 million and $17 million of impairment charges. See Note 18 for additional information.
(g)
"Other" includes costs for the development of licenses, the most significant of which is the COLA. Amortization of these costs begins when the related asset is placed in service. See Note 8 for additional information on the COLA.
(h)
Gross carrying amount for 2011 includes $88 million, which represents the fair value of easements recognized as a result of the 2011 acquisition of WPD Midlands. See Note 10 for additional information.
Current intangible assets are included in "Other current assets" and long-term intangible assets are included in "Other intangibles" in their respective areas on the Balance Sheets.
(a)
Removed from the Balance Sheets and expensed when consumed or sold. Consumption expense was $16 million, $46 million, and $32 million in 2011, 2010, and 2009. Consumption expense is expected to be insignificant in future periods.
(b)
During 2011 and 2010, PPL Energy Supply recorded $7 million and $16 million of impairment charges. See Note 18 for additional information.
(c)
"Other" includes costs for the development of licenses, the most significant of which is the COLA. Amortization of these costs begins when the related asset is placed in service. See Note 8 for additional information on the COLA.
(d)
Easements for 2010 pertain to WPD. As a result of PPL Energy Supply's January 2011 distribution of its membership interest in PPL Global to its parent, PPL Energy Funding, the assets and liabilities of PPL Global, including WPD's easements at December 31, 2010 were removed from PPL Energy Supply's balance sheet in 2011. See Note 9 for additional information.
Current intangible assets are included in "Other current assets" and long-term intangible assets are presented as "Other intangibles" in their respective areas on the Balance Sheets.
Intangible assets are shown as "Intangibles" on the Balance Sheets.
Amortization expense was insignificant in 2011, 2010 and 2009, and is expected to be insignificant in future years.
(a)
Gross carrying amount represents the fair value of contracts with terms favorable to market recognized as a result of the 2010 acquisition by PPL. An offsetting regulatory liability was recorded related to these contracts, which is being amortized over the same period as the intangible assets, eliminating any income statement impact. See Note 6 for additional information.
(b)
Gross carrying amount represents the fair value of land and transmission rights recognized as an intangible asset as a result of adopting PPL's accounting policies in the Successor period. Amortization expense is recovered through base rates and is expected to be insignificant for future periods.
(c)
Represents the fair value of emission allowances recognized as a result of the 2010 acquisition by PPL. An offsetting regulatory liability was recorded related to these emission allowances, which is being amortized as the emission allowances are consumed, eliminating any income statement impact. Consumption related to these emission allowances was $11 million and $2 million for 2011 and 2010.
(d)
Gross carrying amount represents the fair value of the OVEC power purchase contract recognized as a result of the 2010 acquisition by PPL. See Note 6 for additional information.
Current intangible assets and long-term intangible assets are presented as "Other intangibles" in their respective areas on the Balance Sheets.
(a)
Gross carrying amount represents the fair value of contracts with terms favorable to market recognized as a result of the 2010 acquisition by PPL. An offsetting regulatory liability was recorded related to these contracts, which is being amortized over the same period as the intangible assets, eliminating any income statement impact. See Note 6 for additional information.
(b)
Gross carrying amount represents the fair value of land and transmission rights recognized as an intangible asset as a result of adopting PPL's accounting policies in the Successor period. Amortization expense is recovered through base rates and is expected to be insignificant for future periods.
(c)
Represents the fair value of emission allowances recognized as a result of the 2010 acquisition by PPL. An offsetting regulatory liability was recorded related to these emission allowances, which is being amortized as the emission allowances are consumed, eliminating any income statement impact. Consumption related to these emission allowances was $5 million and $1 million for 2011 and 2010.
(d)
Gross carrying amount represents the fair value of the OVEC power purchase contract recognized as a result of the 2010 acquisition by PPL. See Note 6 for additional information.
Current intangible assets and long-term intangible assets are presented as "Other intangibles" in their respective areas on the Balance Sheets.
(a)
Gross carrying amount represents the fair value of contracts with terms favorable to market recognized as a result of the 2010 acquisition by PPL. An offsetting regulatory liability was recorded related to these contracts, which is being amortized over the same period as the intangible assets, eliminating any income statement impact. See Note 6 for additional information.
(b)
Gross carrying amount represents the fair value of land and transmission rights recognized as an intangible asset as a result of adopting PPL's accounting policies in the Successor period. Amortization expense is recovered through base rates and is expected to be insignificant for future periods.
(c)
Represents the fair value of emission allowances recognized as a result of the 2010 acquisition by PPL. An offsetting regulatory liability was recorded related to these emission allowances, which is being amortized as the emission allowances are consumed, eliminating any income statement impact. Consumption related to these emission allowances was $6 million and $1 million for 2011 and 2010.
(d)
Gross carrying amount represents the fair value of the OVEC power purchase contract recognized as a result of the 2010 acquisition by PPL. See Note 6 for additional information.
Current intangible assets and long-term intangible assets are presented as "Other intangibles" in their respective areas on the Balance Sheets.
21. Asset Retirement Obligations
(PPL)
WPD has recorded conditional AROs required by U.K. law related to treated wood poles, gas-filled switchgear and fluid-filled cables.
(PPL and PPL Energy Supply)
PPL Energy Supply has recorded liabilities in the financial statements to reflect various legal obligations associated with the retirement of long-lived assets, the most significant of which relates to the decommissioning of the Susquehanna plant. The accrued nuclear decommissioning obligation was $292 million and $270 million at December 31, 2011 and 2010, and is included in "Asset retirement obligations" on the Balance Sheets. The fair value of investments that are legally restricted for
the decommissioning of the Susquehanna nuclear plant was $640 million and $618 million at December 31, 2011 and 2010, and is included in "Nuclear plant decommissioning trust funds" on the Balance Sheets. See Notes 18 and 23 for additional information on the nuclear decommissioning trust funds. Other AROs recorded relate to various environmental requirements for coal piles, ash basins and other waste basin retirements.
PPL Energy Supply has recorded several conditional AROs, the most significant of which related to the removal and disposal of asbestos-containing material. In addition to the AROs that were recorded for asbestos-containing material, PPL Energy Supply identified other asbestos-related obligations, but were unable to reasonably estimate their fair values. PPL Energy Supply management was unable to reasonably estimate a settlement date or range of settlement dates for the remediation of all of the asbestos-containing material at certain of the generation plants. If economic events or other circumstances change that enable PPL Energy Supply to reasonably estimate the fair value of these retirement obligations, they will be recorded at that time.
PPL Energy Supply also identified legal retirement obligations associated with the retirement of a reservoir that could not be reasonably estimated due to an indeterminable settlement date.
(PPL and PPL Electric)
PPL Electric has identified legal retirement obligations for the retirement of certain transmission assets that could not be reasonably estimated due to indeterminable settlement dates. These assets are located on rights-of-way that allow the grantor to require PPL Electric to relocate or remove the assets. Since this option is at the discretion of the grantor of the right-of-way, PPL Electric is unable to determine when these events may occur.
(PPL, LKE, LG&E and KU)
LG&E's and KU's AROs are primarily related to the final retirement of assets associated with generating units. LG&E also has AROs related to natural gas mains and wells. LG&E's and KU's transmission and distribution lines largely operate under perpetual property easement agreements which do not generally require restoration upon removal of the property. Therefore, no material AROs are recorded for transmission and distribution assets. As described in Notes 1 and 6, the accretion and depreciation expense recorded by LG&E and KU is offset with a regulatory credit on the income statement, such that there is no earnings impact.
(PPL, PPL Energy Supply, LKE, LG&E and KU)
The changes in the carrying amounts of AROs were:
(a)
Obligations required under U.K. law related to treated wood poles, gas-filled switchgear and fluid-filled cables. See Note 10 for additional information on the acquisition.
(b)
Represents AROs derecognized as a result of PPL Energy Supply's distribution of its membership interest in PPL Global to PPL Energy Supply's parent, PPL Energy Funding. See Note 9 for additional information on the distribution.
In the third quarter of 2010, PPL Susquehanna completed a site-specific study to update the estimated cost to dismantle and decommission each Susquehanna nuclear unit immediately following final shutdown. This estimate included decommissioning the radiological portions of the station and the cost of removal of non-radiological structures and materials. Based on this study, which used a methodology consistent with the prior site-specific study done in 2002, the decommissioning ARO liability and the associated long-lived asset were reduced by $103 million. The primary factor for this decline was the lower estimated inflation rate assumption used in the 2010 ARO calculation.
(a)
Included in "Other current liabilities."
(b)
Included in "Asset retirement obligations."
22. Variable Interest Entities
(PPL and PPL Energy Supply)
In December 2001, a subsidiary of PPL Energy Supply entered into a $455 million operating lease arrangement, as lessee, for the development, construction and operation of a gas-fired combined-cycle generation facility located in Lower Mt. Bethel Township, Northampton County, Pennsylvania. The owner/lessor of this generation facility, LMB Funding, LP, was created to own/lease the facility and incur the related financing costs. The initial lease term commenced on the date of commercial operation, which occurred in May 2004, and ends in December 2013. Under a residual value guarantee, if the generation facility is sold at the end of the lease term and the cash proceeds from the sale are less than the original acquisition cost, the subsidiary of PPL Energy Supply is obligated to pay up to 70.52% of the original acquisition cost. This residual value guarantee protects the other variable interest holders from losses related to their investments. LMB Funding, LP cannot extend or cancel the lease or sell the facility without the prior consent of the PPL Energy Supply subsidiary. As a result, LMB Funding, LP was determined to be a VIE and the subsidiary of PPL Energy Supply was considered the primary beneficiary that consolidates this VIE.
The lease financing, which includes $437 million of "Long-term Debt" and $18 million of "Noncontrolling interests" at December 31, 2011 and December 31, 2010, is secured by, among other things, the generation facility, the carrying amount of which is disclosed on the Balance Sheets. The debt matures at the end of the initial lease term. As a result of the consolidation, PPL Energy Supply has recorded interest expense in lieu of rent expense. For 2011, 2010 and 2009, additional depreciation on the generation facility of $16 million, $16 million and $11 million was recorded.
23. Available-for-Sale Securities
(PPL, PPL Energy Supply, LKE and LG&E)
PPL and its subsidiaries classify certain short-term investments, securities held by the NDT funds and auction rate securities as available-for-sale. Available-for-sale securities are carried on the Balance Sheet at fair value. Unrealized gains and losses on these securities are reported, net of tax, in OCI or are recognized currently in earnings when a decline in fair value is determined to be other-than-temporary. The specific identification method is used to calculate realized gains and losses.
The following table shows the amortized cost, the gross unrealized gains and losses recorded in AOCI and the fair value of available-for-sale securities.
(a)
Represents tax-exempt bonds issued by Louisville/Jefferson County, Kentucky, on behalf of LG&E that were subsequently purchased by LG&E.
Such bonds were remarketed to unaffiliated investors in January 2011.
There were no securities with credit losses at December 31, 2011 and 2010.
The following table shows the scheduled maturity dates of debt securities held at December 31, 2011.
(a)
These proceeds are used to pay income taxes and fees related to managing the trust. Remaining proceeds are reinvested in the trust.
(b)
Excludes the impact of other-than-temporary impairment charges recognized in the Statements of Income.
Short-term Investments
(PPL, LKE and LG&E)
At December 31, 2010, LG&E held $163 million aggregate principal amount of tax-exempt revenue bonds issued by Louisville/Jefferson County, Kentucky on behalf of LG&E that were purchased from the remarketing agent in 2008. At December 31, 2010, these investments were reflected in "Short-term investments" on the Balance Sheet. In 2011, LG&E received $163 million for its investments in these bonds when they were remarketed to unaffiliated investors. No realized or unrealized gains (losses) were recorded on these securities, as the difference between carrying value and fair value was not significant.
(PPL and PPL Energy Supply)
In December 2008, the PEDFA issued $150 million aggregate principal amount of Exempt Facilities Revenue Bonds, Series 2008A and 2008B due 2038 (Series 2008 Bonds) on behalf of PPL Energy Supply. PPL Investment Corp. acted as the initial purchaser of the Series 2008 Bonds upon issuance. In April 2009, PPL Investment Corp. received $150 million for its investment in the Series 2008 Bonds when they were refunded by the PEDFA. No realized or unrealized gains (losses) were recorded on these securities, as the difference between carrying value and fair value was insignificant.
NDT Funds
Beginning in January 1999 and ending in December 2009, in accordance with the PUC Final Order, decommissioning costs were recovered from PPL Electric's customers through the CTC over the 11-year life of the CTC rather than the remaining life of the Susquehanna nuclear plant. The recovery included a return on unamortized decommissioning costs. Under the power supply agreements between PPL Electric and PPL EnergyPlus, these revenues were passed on to PPL EnergyPlus. Similarly, these revenues were passed on to PPL Susquehanna under a power supply agreement between PPL EnergyPlus and PPL Susquehanna.
Amounts collected from PPL Electric's customers for decommissioning, less applicable taxes, were deposited in external trust funds for investment and can only be used for future decommissioning costs. To the extent that the actual costs for decommissioning exceed the amounts in the nuclear decommissioning trust funds, PPL Susquehanna would be obligated to fund 90% of the shortfall.
When the fair value of a security is less than amortized cost, PPL and PPL Energy Supply must make certain assertions to avoid recording an other-than-temporary impairment that requires a current period charge to earnings. The NRC requires that nuclear decommissioning trusts be managed by independent investment managers, with discretion to buy and sell securities in the trusts. As a result, PPL and PPL Energy Supply have been unable to demonstrate the ability to hold an impaired security until it recovers its value; therefore, unrealized losses on debt securities through March 31, 2009 and unrealized losses on equity securities for all periods presented, represented other-than-temporary impairments that required a current period charge to earnings. PPL and PPL Energy Supply recorded impairments for certain securities invested in the NDT funds of $6 million, $3 million and $18 million for 2011, 2010 and 2009. These impairments are reflected on the Statements of Income in "Other-Than-Temporary Impairments."
Effective April 1, 2009, when PPL and PPL Energy Supply intend to sell a debt security or more likely than not will be required to sell a debt security before recovery, then the other-than-temporary impairment recognized in earnings will equal
the entire difference between the security's amortized cost basis and its fair value. However, if there is no intent to sell a debt security and it is not more likely than not that they will be required to sell the security before recovery, but the security has suffered a credit loss, the other-than-temporary impairment will be separated into the credit loss component, which is recognized in earnings, and the remainder of the other-than-temporary impairment, which is recorded in OCI. Temporary impairments of debt securities and unrealized gains on both debt and equity securities are recorded to OCI.
24. New Accounting Guidance Pending Adoption
(PPL, PPL Energy Supply, PPL Electric, LKE, LG&E and KU)
Fair Value Measurements
Effective January 1, 2012, the Registrants will prospectively adopt accounting guidance that was issued to clarify existing fair value measurement guidance as well as enhance fair value disclosures. The additional disclosures required by this guidance include quantitative information about significant unobservable inputs used for Level 3 measurements, qualitative information about the sensitivity of recurring Level 3 measurements, information about any transfers between Level 1 and 2 of the fair value hierarchy, information about when the current use of a non-financial asset is different from the highest and best use, and the hierarchy classification for assets and liabilities whose fair value is disclosed only in the notes to the financial statements.
Any fair value measurement differences resulting from the adoption of this guidance will be recognized in income in the period of adoption. The adoption of this guidance is not expected to have a significant impact on the Registrants.
Testing Goodwill for Impairment
Effective January 1, 2012, the Registrants will prospectively adopt accounting guidance which will allow an entity to elect the option to first make a qualitative evaluation about the likelihood of an impairment of goodwill. If, based on this assessment, the entity determines it is not more likely than not the fair value of a reporting unit is less than the carrying amount, the two-step goodwill impairment test is not necessary. However, the first step of the impairment test is required if an entity concludes it is more likely than not the fair value of a reporting unit is less than the carrying amount based on the qualitative assessment.
The adoption of this standard is not expected to have a significant impact on the Registrants.
Improving Disclosures about Offsetting Balance Sheet Items
Effective January 1, 2013, the Registrants will retrospectively adopt accounting guidance issued to enhance disclosures about financial instruments and derivative instruments that either (1) offset on the balance sheet or (2) are subject to an enforceable master netting arrangement or similar agreement, irrespective of whether they are offset on the balance sheet.
Upon adoption, the enhanced disclosure requirements are not expected to have a significant impact on the Registrants.
25. Subsequent Events
(PPL and PPL Energy Supply)
In February 2012 PPL announced that its indirect wholly owned subsidiary, PPL Generation, had entered into a definitive agreement (Acquisition Agreement) to acquire from AES Ironwood, Inc. , a subsidiary of The AES Corporation, all of the equity interests of AES Ironwood, L.L.C. and AES Prescott, L.L.C., which together own and operate the 705 MW (winter rating) AES Ironwood combined-cycle natural-gas-fired power plant (Ironwood Facility) located in Lebanon, Pennsylvania. The Ironwood Facility began operation in 2001 and, since July 1, 2008, PPL EnergyPlus has supplied natural gas for the operation of the Ironwood Facility in return for receiving its full electricity output pursuant to a tolling agreement that expires in 2021.
The Acquisition Agreement provides for the sale of 100% of the issued and outstanding membership interests (collectively, the "Interests") of each of AES Ironwood, L.L.C. and AES Prescott, L.L.C. (collectively, the "Acquired Companies") to PPL Generation. The consideration payable by PPL Generation in respect of the acquisition is $87 million in cash, which includes approximately $4.8 million of net working capital of the Acquired Companies expected to be received at closing, plus the assumption at closing, through consolidation as a result of acquiring the Interests, of approximately $217 million of net outstanding project indebtedness of AES Ironwood, L.L.C. The outstanding project indebtedness is represented by $308.5 million aggregate principal amount of AES Ironwood, L.L.C. 8.857% senior secured bonds due 2025, the net amount of
which expected to be outstanding at closing is approximately $226 million, plus $8 million of debt service reserve loans, less approximately $17 million of restricted cash reserves. The cash purchase price is subject to adjustment based on the amounts by which the actual closing date net working capital and net project indebtedness vary from expected balances.
AES Ironwood, Inc. and PPL Generation have each made customary representations, warranties and covenants in the Acquisition Agreement. The transaction is subject to customary closing conditions, including the expiration or termination of the applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, receipt of required regulatory approvals, including approval by the Federal Energy Regulatory Commission under section 203 of the Federal Power Act, and either a reaffirmation of the current ratings of Standard & Poor's Rating Group and Moody's Investors Services, Inc. on the outstanding project indebtedness or consent of the holders of two-thirds of the outstanding project indebtedness.
PPL Energy Supply has agreed to guarantee PPL Generation's obligations under the Acquisition Agreement until the cash purchase price has been paid in full, including any post-closing adjustments for net working capital and project indebtedness.
(a)
780,000 shares authorized; 578,405 and 483,391 shares issued and outstanding at December 31, 2011 and December 31, 2010.
The accompanying Notes to Condensed Unconsolidated Financial Statements are an integral part of the financial statements.
SCHEDULE I - PPL CORPORATION
NOTES TO CONDENSED UNCONSOLIDATED FINANCIAL STATEMENTS
1.
Basis of Presentation
PPL Corporation is a holding company and conducts substantially all of its business operations through its subsidiaries. Substantially all of its consolidated assets are held by such subsidiaries. Accordingly, its cash flow and its ability to meet its obligations are largely dependent upon the earnings of these subsidiaries and the distribution or other payment of such earnings to it in the form of dividends, loans or advances or repayment of loans and advances from it. These condensed financial statements and related footnotes have been prepared in accordance with Reg. §210.12-04 of Regulation S-X. These statements should be read in conjunction with the consolidated financial statements and notes thereto of PPL Corporation.
PPL Corporation indirectly or directly owns all of the ownership interests of its significant subsidiaries. PPL Corporation does not own the preferred securities of PPL Electric Utilities Corporation. PPL Corporation relies on dividends or loans from its subsidiaries to fund PPL Corporation's dividends to its common shareholders and to meet its other cash requirements.
2.
Commitments and Contingencies
See Note 15 to PPL Corporation's consolidated financial statements for commitments and contingencies of its subsidiaries.
Guarantees and Other Assurances
PPL Corporation's subsidiaries are separate and distinct legal entities and have no obligation to pay any amounts that may become due under PPL Corporation's guarantees or other assurances or to make any funds available for such payment.
PPL Corporation fully and unconditionally guarantees the payment of principal, premium and interest on all of the debt securities of PPL Capital Funding. The estimated maximum potential amount of future payments that could be required under the guarantees at December 31, 2011 was $5.2 billion. These guarantees will expire in 2067.
PPL Corporation has provided indemnification to the purchaser of PPL Gas Utilities and Penn Fuel Propane, LLC for damages arising out of any breach of the representations, warranties and covenants under the related transaction agreement and for damages arising out of certain other matters, including certain pre-closing unknown environmental liabilities relating to former manufactured gas plant properties or off-site disposal sites, if any, outside of Pennsylvania. The estimated maximum potential amount of future payments that could be required under the indemnifications at December 31, 2011 was $300 million. The indemnification provisions for most representations and warranties, including tax and environmental matters, are capped at $45 million, in the aggregate, and are triggered (i) only if the individual claim exceeds $50,000, and (ii) only if, and only to the extent that, in the aggregate, total claims exceed $4.5 million. The indemnification provisions for most representations and warranties expired on September 30, 2009 without any claims having been made. Certain representations and warranties, including those having to do with transaction authorization and title, survive indefinitely, are capped at the purchase price and are not subject to the above threshold or deductible. The indemnification provision for the tax matters representations survives for the duration of the applicable statute of limitation. The indemnification provision for the environmental matters representations expired on September 30, 2011 without any claims having been made. The indemnification for covenants survives until the applicable covenant is performed and is not subject to any cap.
The probability of expected payment under each of the guarantees is remote.
Schedule I - LG&E and KU Energy LLC
Notes to Condensed Unconsolidated Financial Statements
1.
Basis of Presentation
LG&E and KU Energy LLC (LKE) is a holding company and conducts substantially all of its business operations through its subsidiaries. Substantially all of its consolidated assets are held by such subsidiaries. Accordingly, its cash flow and its ability to meet its obligations are largely dependent upon the earnings of these subsidiaries and the distribution or other payment of such earnings to it in the form of dividends or repayment of loans and advances from the subsidiaries. These condensed financial statements and related footnotes have been prepared in accordance with Reg. §210.12-04 of Regulation S-X. These statements should be read in conjunction with the consolidated financial statements and notes thereto of LKE.
LKE indirectly or directly owns all of the ownership interests of its significant subsidiaries. LKE relies primarily on dividends from its subsidiaries to fund LKE's dividends to its member and to meet its other cash requirements.
2.
Commitments and Contingencies
See Note 15 to LKE's consolidated financial statements for commitments and contingencies of its subsidiaries.
Guarantees
In connection with various divestitures, LKE has indemnified/guaranteed respective parties against certain liabilities that may arise in connection with these transactions and business activities. The terms of these indemnifications/guarantees vary, as do the expiration terms. LKE has issued direct financial guarantees to parties involved in the WKE lease termination, which occurred in July 2009. These guarantees cover the due and punctual payment, performance and discharge by each party of its respective present and future obligations. The most comprehensive of these guarantees is a guarantee covering operational, regulatory and environmental commitments and indemnifications made by WKE under the WKE Transaction Termination Agreement. This guarantee has a term of 12 years beginning on July 16, 2009 and a cumulative maximum exposure of $200 million. Certain items, such as non-excluded government fines and penalties, fall outside the cumulative cap. Another guarantee with a maximum exposure of $100 million covering other indemnifications expires in 2023. Certain matters are currently under discussion among the parties, including one matter currently in arbitration and a further matter for which LKE is contesting the applicability of the indemnification requirement. The matter in arbitration may be ruled upon during early 2012, which ruling may result in increases or decreases to the liability estimate LKE has currently recorded. The ultimate outcome of both matters cannot be predicted at this time. See Note 9, Discontinued Operations, for further information. Additionally, LKE has indemnified various third parties related to historical obligations for divested subsidiaries and affiliates. The indemnifications vary by entity and the maximum amounts range from being capped at the sale price to no specified maximum; however, LKE is not aware of claims made by any party at this time. LKE could be required to perform on these indemnifications in the event of covered losses or liabilities being claimed by an indemnified party. No additional material loss is anticipated by reason of such indemnifications. A subsidiary of LKE has recorded liabilities for all guarantees totaling $11 million with respect to which LKE has certain guarantee obligations.
(a)
Quarterly results can vary depending on, among other things, weather and the forward pricing of power. In addition, earnings in 2011 and 2010 were affected by special items. Accordingly, comparisons among quarters of a year may not be indicative of overall trends and changes in operations.
(b)
The sum of the quarterly amounts may not equal annual earnings per share due to changes in the number of common shares outstanding during the year or rounding.
(c)
PPL has paid quarterly cash dividends on its common stock in every year since 1946. Future dividends, declared at the discretion of the Board of Directors, will be dependent upon future earnings, cash flows, financial requirements and other factors.
(a)
PPL Electric's business is seasonal in nature, with peak sales periods generally occurring in the winter and summer months. Accordingly, comparisons among quarters of a year may not be indicative of overall trends and changes in operations.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
ON ACCOUNTING AND FINANCIAL DISCLOSURE
PPL Corporation, PPL Energy Supply, LLC, PPL Electric Utilities Corporation, LG&E and KU Energy LLC, Louisville Gas and Electric Company and Kentucky Utilities Company
None.
ITEM 9A. CONTROLS AND PROCEDURES
(a)
Evaluation of disclosure controls and procedures.
PPL Corporation, PPL Energy Supply, LLC, PPL Electric Utilities Corporation, LG&E and KU Energy LLC, Louisville Gas and Electric Company and Kentucky Utilities Company
The registrants' principal executive officers and principal financial officers, based on their evaluation of the registrants' disclosure controls and procedures (as defined in Rules 13a-15(e) or 15d-15(e) of the Securities Exchange Act of 1934) have concluded that, as of December 31, 2011, the registrants' disclosure controls and procedures are effective to ensure that material information relating to the registrants and their consolidated subsidiaries is recorded, processed, summarized and reported within the time periods specified by the SEC's rules and forms, particularly during the period for which this annual report has been prepared. The aforementioned principal officers have concluded that the disclosure controls and procedures are also effective to ensure that information required to be disclosed in reports filed under the Exchange Act is accumulated and communicated to management, including the principal executive and principal financial officers, to allow for timely decisions regarding required disclosure.
PPL Corporation
PPL acquired WPD Midlands on April 1, 2011. These companies are included in PPL's 2011 financial statements as of the date of the acquisition, on a one-month lag. WPD Midlands accounted for approximately 9% of PPL's net income for the twelve months ended December 31, 2011. WPD Midlands represented 19% and 27% of PPL's total assets and net assets at December 31, 2011. The internal control over financial reporting of WPD Midlands was excluded from a formal evaluation of effectiveness of PPL's disclosure controls and procedures. This decision was based upon the significance of these companies to PPL, and the timing of integration efforts underway to transition WPD Midlands' processes, information technology systems and other components of internal control over financial reporting to the internal control structure of PPL. PPL has expanded its consolidation and disclosure controls and procedures to include the acquired companies, and PPL continues to assess the current internal control over financial reporting at WPD Midlands. Risks related to the increased account balances were partially mitigated by PPL's expanded controls and PPL's existing policy of consolidating foreign subsidiaries on a one-month lag, which provided management additional time for review and analysis of WPD Midlands' results and their incorporation into PPL's consolidated financial statements.
(b)
Changes in internal control over financial reporting.
PPL Corporation
PPL's principal executive officer and principal financial officer have concluded that a recent systems migration related to the WPD Midlands acquisition created a material change to its internal control over financial reporting. Specifically, on December 1, 2011 the use of legacy information technology systems at WPD Midlands was discontinued and the related data, processes and internal controls were migrated to the systems, processes and controls currently in place at PPL WW. Due to PPL's existing policy of consolidating foreign subsidiaries on a one-month lag, the system migration will primarily impact 2012 financial reporting for PPL and will likely have limited impact on PPL's 2011 financial reporting.
Risks related to the system migration were partially mitigated by PPL's expanded internal control over financial reporting that were implemented subsequent to the acquisition and PPL's existing policy of consolidating foreign subsidiaries on a one-month lag, which provided management additional time for review and analysis of WPD Midlands' results and their incorporation into PPL's consolidated financial statements. PPL continues to assess the internal control over financial reporting at WPD subsequent to the December 1, 2011 system migration.
The aforementioned principal executive officer and principal financial officer have concluded that there were no other changes in the registrant's internal control over financial reporting during the registrant's fourth fiscal quarter that have materially affected, or are reasonably likely to materially affect, the registrant's internal control over financial reporting.
PPL Energy Supply, LLC, PPL Electric Utilities Corporation, LG&E and KU Energy LLC, Louisville Gas and Electric Company and Kentucky Utilities Company
The registrants' principal executive officers and principal financial officers have concluded that there were no changes in the registrants' internal control over financial reporting during the registrants' fourth fiscal quarter that have materially affected, or are reasonably likely to materially affect, the registrants' internal control over financial reporting.
Management's Report on Internal Control over Financial Reporting
PPL Corporation
PPL's management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f) or 15d-15(f). PPL's internal control over financial reporting is a process designed to provide reasonable assurance to PPL's management and Board of Directors regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.
Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in "Internal Control - Integrated Framework" issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation under the framework in "Internal Control - Integrated Framework," our management concluded that our internal control over financial reporting was effective as of December 31, 2011. The effectiveness of our internal control over financial reporting has been audited by Ernst & Young LLP, an independent registered public accounting firm, as stated in their report contained on page 195.
In accordance with SEC rules, management excluded WPD Midlands from its evaluation of internal control over financial reporting due to the significance of these companies to PPL's financial results and the migration of WPD Midlands' legacy information technology systems, processes and controls to those at PPL WW. WPD Midlands accounted for 9% of PPL's net income for the year ended December 31, 2011. WPD Midlands represented 19% and 27% of PPL's consolidated total assets and net assets, respectively, at December 31, 2011. As discussed above, PPL Corporation is continuing to enhance and evaluate processes, information technology systems and other components of internal control over financial reporting as part of its ongoing integration activities.
PPL Energy Supply, LLC, PPL Electric Utilities Corporation, LG&E and KU Energy LLC, Louisville Gas and Electric Company and Kentucky Utilities Company
Management of PPL's non-accelerated filer companies, PPL Energy Supply, PPL Electric, LKE, LG&E and KU, are responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f) or 15d-15(f). PPL's internal control over financial reporting is a process designed to provide reasonable assurance to PPL's management and Board of Directors regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.
Under the supervision and with the participation of our management, including our principal executive officers and principal financial officers, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in "Internal Control - Integrated Framework" issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation under the framework in "Internal Control - Integrated Framework," our management concluded that our internal control over financial reporting was effective as of December 31, 2011. This annual report does not include an attestation report of Ernst & Young LLP, the companies' independent registered public accounting firm regarding internal control over financial reporting. Management's report was not subject to attestation by the companies' registered public accounting firm pursuant to rules of the Securities and Exchange Commission that permit the companies to provide only management's report in this annual report.
ITEM 9B. OTHER INFORMATION
PPL Corporation, PPL Energy Supply, LLC, PPL Electric Utilities Corporation, LG&E and KU Energy LLC, Louisville Gas and Electric Company and Kentucky Utilities Company
None.
PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
PPL Corporation
Additional information for this item will be set forth in the sections entitled "Nominees for Directors," "Board Committees - Audit Committee" and "Section 16(a) Beneficial Ownership Reporting Compliance" in PPL's 2012 Notice of Annual Meeting and Proxy Statement, which will be filed with the SEC not later than 120 days after December 31, 2011, and which information is incorporated herein by reference. There have been no changes to the procedures by which shareowners may recommend nominees to PPL's board of directors since the filing with the SEC of PPL's 2011 Notice of Annual Meeting and Proxy Statement. Information required by this item concerning the executive officers of PPL is set forth at the end of Part I of this report.
PPL has adopted a code of ethics entitled "Standards of Integrity" that applies to all directors, managers, trustees, officers (including the principal executive officers, principal financial officers and principal accounting officers (each, a "principal officer")), employees and agents of PPL and PPL's subsidiaries for which it has operating control (including PPL Energy Supply, PPL Electric, LKE, LG&E and KU). The "Standards of Integrity" are posted on PPL's Internet website: www.pplweb.com/about/corporate+governance. A description of any amendment to the "Standards of Integrity" (other than a technical, administrative or other non-substantive amendment) will be posted on PPL's Internet website within four business days following the date of the amendment. In addition, if a waiver constituting a material departure from a provision of the "Standards of Integrity" is granted to one of the principal officers, a description of the nature of the waiver, the name of the person to whom the waiver was granted and the date of the waiver will be posted on PPL's Internet website within four business days following the date of the waiver.
PPL also has adopted its "Guidelines for Corporate Governance," which address, among other things, director qualification standards and director and board committee responsibilities. These guidelines, and the charters of each of the committees of PPL's board of directors, are posted on PPL's Internet website: www.pplweb.com/about/corporate+governance.
PPL Energy Supply, LLC, PPL Electric Utilities Corporation, LG&E and KU Energy LLC, Louisville Gas and Electric Company and Kentucky Utilities Company
Item 10 is omitted as PPL Energy Supply, PPL Electric, LKE, LG&E and KU meet the conditions set forth in General Instruction (I)(1)(a) and (b) of Form 10-K.
EXECUTIVE OFFICERS OF THE REGISTRANTS
Officers of the Registrants are elected annually by their Boards of Directors (or Board of Managers for PPL Energy Supply) to serve at the pleasure of the respective Boards. There are no family relationships among any of the executive officers, nor is there any arrangement or understanding between any executive officer and any other person pursuant to which the officer was selected.
There have been no events under any bankruptcy act, no criminal proceedings and no judgments or injunctions material to the evaluation of the ability and integrity of any executive officer during the past five years.
Listed below are the executive officers at December 31, 2011.
PPL Corporation
Name
Age
Positions Held During the Past Five Years
Dates
James H. Miller (a)
Chairman
October 2006 - present
Chief Executive Officer
October 2006 - November 2011
President
August 2005 - July 2011
William H. Spence (b)
President and Chief Executive Officer
November 2011 - present
President-PPL Generation
June 2008 - present
President and Chief Operating Officer
July 2011 - November 2011
Executive Vice President and Chief Operating Officer
June 2006 - July 2011
Paul A. Farr
Executive Vice President and Chief Financial Officer
April 2007 - present
Senior Vice President-Financial
January 2006 - March 2007
Robert J. Grey
Senior Vice President, General Counsel and Secretary
March 1996 - present
David G. DeCampli (c)
President-PPL Electric
April 2007 - present
Senior Vice President-Transmission and Distribution Engineering and Operations-PPL Electric
December 2006 - April 2007
Robert D. Gabbard (c)
President-PPL EnergyPlus
June 2008 - present
Senior Vice President-Trading-PPL EnergyPlus
June 2008 - June 2008
Senior Vice President Merchant Trading Operations-Conectiv Energy
June 2005 - May 2008
Rick L. Klingensmith (c)
President-PPL Global
August 2004 - present
Victor A. Staffieri (c)
Chairman of the Board, President and Chief Executive
Officer-LKE
May 2001 - present
James E. Abel
Senior Vice President-Finance and Treasurer
August 2010 - present
Vice President-Finance and Treasurer
June 1999 - August 2010
J. Matt Simmons, Jr. (c)
Vice President-Risk Management and Chief Risk Officer
September 2009 - present
Vice President and Controller
January 2006 - March 2010
Vincent Sorgi
Vice President and Controller
March 2010 - present
Controller-Supply Accounting
June 2008 - March 2010
Controller-PPL EnergyPlus
April 2007 - June 2008
Financial Director-Supply-PPL Generation
April 2006 - April 2007
(a)
On July 22, 2011, James H. Miller resigned as President. On November 17, 2011, he also resigned as Chief Executive Officer. Mr. Miller has announced he will be retiring, effective April 1, 2012.
(b)
On July 22, 2011, William H. Spence resigned as Executive Vice President and was elected President and Chief Operating Officer. On November 17, 2011, he also resigned as Chief Operating Officer and was elected President and Chief Executive Officer.
(c)
Designated an executive officer of PPL by virtue of their respective positions at a PPL subsidiary.
ITEM 11. EXECUTIVE COMPENSATION
PPL Corporation
Information for this item will be set forth in the sections entitled "Compensation of Directors," "Compensation Committee Interlocks and Insider Participation" and "Executive Compensation" in PPL's 2012 Notice of Annual Meeting and Proxy Statement, which will be filed with the SEC not later than 120 days after December 31, 2011, and which information is incorporated herein by reference.
PPL Energy Supply, LLC, PPL Electric Utilities Corporation, LG&E and KU Energy LLC, Louisville Gas and Electric Company and Kentucky Utilities Company
Item 11 is omitted as PPL Energy Supply, PPL Electric, LKE, LG&E and KU meet the conditions set forth in General Instructions (I)(1)(a) and (b) of Form 10-K.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
AND RELATED STOCKHOLDER MATTERS
PPL Corporation
Information for this item will be set forth in the section entitled "Stock Ownership" in PPL's 2012 Notice of Annual Meeting and Proxy Statement, which will be filed with the SEC not later than 120 days after December 31, 2011, and which information is incorporated herein by reference. In addition, provided below in tabular format is information as of December 31, 2011, with respect to compensation plans (including individual compensation arrangements) under which equity securities of PPL are authorized for issuance.
(1)
Includes (a) the Amended and Restated Incentive Compensation Plan (ICP), under which stock options, restricted stock, restricted stock units, performance units, dividend equivalents and other stock-based awards may be awarded to executive officers of PPL; (b) the Amended and Restated Incentive Compensation Plan for Key Employees (ICPKE), under which stock options, restricted stock, restricted stock units, performance units, dividend equivalents and other stock-based awards may be awarded to non-executive key employees of PPL and its subsidiaries; and (c) the Directors Deferred Compensation Plan (DDCP), under which stock units may be awarded to directors of PPL. See Note 12 to the Financial Statements for additional information.
(2)
All of PPL's current compensation plans under which equity securities of PPL are authorized for issuance have been approved by PPL's shareowners.
(3)
Relates to common stock issuable upon the exercise of stock options awarded under the ICP and ICPKE as of December 31, 2011. In addition, as of December 31, 2011, the following other securities had been awarded and are outstanding under the ICP, ICPKE and DDCP: 45,400 shares of restricted stock, 549,805 restricted stock units and 236,714 performance units under the ICP; 24,600 shares of restricted stock, 1,420,230 restricted stock units and 161,894 performance units under the ICPKE; and 425,306 stock units under the DDCP.
(4)
Based upon the following aggregate award limitations under the ICP, ICPKE and DDCP: (a) under the ICP, 15,769,431 awards (i.e., 5% of the total PPL common stock outstanding as of April 23, 1999) granted after April 23, 1999; (b) under the ICPKE, 16,573,608 awards (i.e., 5% of the total PPL common stock outstanding as of January 1, 2003) granted after April 25, 2003, reduced by outstanding awards for which common stock was not yet issued as of such date of 2,373,812 resulting in a limit of 14,199,796; and (c) under the DDCP, 15,052,856 securities. In addition, each of the ICP and ICPKE includes an annual award limitation of 2% of total PPL common stock outstanding as of January 1 of each year.
PPL Energy Supply, LLC, PPL Electric Utilities Corporation, LG&E and KU Energy LLC, Louisville Gas and Electric Company and Kentucky Utilities Company
Item 12 is omitted as PPL Energy Supply, PPL Electric, LKE, LG&E and KU meet the conditions set forth in General Instructions (I)(1)(a) and (b) of Form 10-K.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
PPL Corporation
Information for this item will be set forth in the sections entitled "Transactions with Related Persons" and "Independence of Directors" in PPL's 2012 Notice of Annual Meeting and Proxy Statement, which will be filed with the SEC not later than 120 days after December 31, 2011, and is incorporated herein by reference.
PPL Energy Supply, LLC, PPL Electric Utilities Corporation, LG&E and KU Energy LLC, Louisville Gas and Electric Company and Kentucky Utilities Company
Item 13 is omitted as PPL Energy Supply, PPL Electric, LKE, LG&E and KU meet the conditions set forth in General Instructions (I)(1)(a) and (b) of Form 10-K.
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
PPL Corporation
Information for this item will be set forth in the section entitled "Fees to Independent Auditor for 2011 and 2010" in PPL's 2012 Notice of Annual Meeting and Proxy Statement, which will be filed with the SEC not later than 120 days after December 31, 2011, and which information is incorporated herein by reference.
PPL Energy Supply, LLC
The following table presents an allocation of fees billed, including expenses, by Ernst & Young LLP (EY) to PPL for the fiscal years ended December 31, 2011 and 2010, for professional services rendered for the audit of PPL Energy Supply's annual financial statements and for fees billed for other services rendered by EY.
(a)
Includes estimated fees for audit of annual financial statements and review of financial statements included in PPL Energy Supply's Quarterly Reports on Form 10-Q and for services in connection with statutory and regulatory filings or engagements, including comfort letters and consents for financings and filings made with the SEC.
(b)
Fees for performance of specific agreed-upon procedures.
(c)
Includes fees for tax advice in connection with a tax basis and earnings and profit study, a private letter ruling related to the sale of Safe Harbor, the funding of the Western Power Utilities Pension Scheme, review and consultation related to PPL's recognition of tax benefits resulting from U.S. Court decisions, consultation and analysis related to non-income tax process improvements initiated by PPL and review, consultation and analysis related to investment tax credits and related capital expenditures on certain hydro-electric plant upgrades.
(d)
Fees related to access to an EY online accounting research tool and an International Financial Reporting Standards diagnostic readiness assessment.
PPL Electric Utilities Corporation
The following table presents an allocation of fees billed, including expenses, by EY to PPL for the fiscal years ended December 31, 2011 and 2010, for professional services rendered for the audit of PPL Electric's annual financial statements and for fees billed for other services rendered by EY.
(a)
Includes estimated fees for audit of annual financial statements and review of financial statements included in PPL Electric's Quarterly Reports on Form 10-Q and for services in connection with statutory and regulatory filings or engagements, including comfort letters and consents for financings and filings made with the SEC.
(b)
Fees for consultation on a transmission and distribution study and performance of specific agreed-upon procedures.
(c)
Fees for consultation and analysis related to non-income tax process improvements initiated by PPL and review and consultation related to tax impacts resulting from U.S. Court decisions.
(d)
Fees related to access to an EY online accounting research tool and an International Financial Reporting Standards diagnostic readiness assessment.
LG&E and KU Energy LLC
For the fiscal year ended 2011, EY served as LKE's independent auditor. For the fiscal year ended 2010, PricewaterhouseCoopers LLP (PwC) served as LKE's independent auditor. The following table presents an allocation of fees billed, including expenses, by EY and PwC to LKE for the fiscal years ended December 31, 2011 and 2010, for professional services rendered for the audits of LKE's annual financial statements and for fees billed for other services rendered by EY and PwC.
(a)
Includes estimated fees for audit of annual financial statements and review of financial statements included in LKE's Quarterly Reports on Form 10-Q and for services in connection with statutory and regulatory filings or engagements, including comfort letters and consents for financings and filings made with the SEC.
Louisville Gas and Electric Company
For the fiscal year ended 2011, EY served as LG&E's independent auditor. For the fiscal year ended 2010, PwC served as LG&E's independent auditor. The following table presents an allocation of fees billed, including expenses, by EY and PwC to LG&E for the fiscal years ended December 31, 2011 and 2010, for professional services rendered for the audits of LG&E's annual financial statements and for fees billed for other services rendered by EY and PwC.
(a)
Includes estimated fees for audit of annual financial statements and review of financial statements included in LG&E's Quarterly Reports on Form 10-Q and for services in connection with statutory and regulatory filings or engagements, including comfort letters and consents for financings and filings made with the SEC.
Kentucky Utilities Company
For the fiscal year ended 2011, EY served as KU's independent auditor. For the fiscal year ended 2010, PwC served as KU's independent auditor. The following table presents an allocation of fees billed, including expenses, by EY and PwC to KU for the fiscal years ended December 31, 2011 and 2010, for professional services rendered for the audits of KU's annual financial statements and for fees billed for other services rendered by EY and PwC.
(a)
Includes estimated fees for audit of annual financial statements and review of financial statements included in KU's Quarterly Reports on Form 10-Q and for services in connection with statutory and regulatory filings or engagements, including comfort letters and consents for financings and filings made with the SEC.
PPL Corporation, PPL Energy Supply, LLC, PPL Electric Utilities Corporation, LG&E and KU Energy LLC, Louisville Gas and Electric Company and Kentucky Utilities Company
Approval of Fees The Audit Committee of PPL has procedures for pre-approving audit and non-audit services to be provided by the independent auditor. These procedures are designed to ensure the continued independence of the independent auditor. More specifically, the use of the independent auditor to perform either audit or non-audit services is prohibited unless specifically approved in advance by the Audit Committee of PPL. As a result of this approval process, the Audit Committee of PPL has pre-approved specific categories of services and authorization levels. All services outside of the specified categories and all amounts exceeding the authorization levels are approved by the Chair of the Audit Committee of PPL, who serves as the Committee designee to review and approve audit and non-audit related services during the year. A listing of the approved audit and non-audit services is reviewed with the full Audit Committee of PPL no later than its next meeting.
The Audit Committee of PPL approved 100% of the 2011 and 2010 services provided by EY.
The Audit Committee of PPL approved 100% of the 2010 services provided by PwC to LKE, LG&E and KU following their acquisition by PPL. Prior to the November 2010 acquisition of LKE by PPL, the Audit Committee of LKE, LG&E and KU maintained procedures for pre-approval of independent auditor services and fees substantially similar to those described above. The LKE, LG&E and KU Audit Committee approved 100% of the 2010 services provided by PwC prior to the PPL acquisition.
PART IV
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
PPL Corporation, PPL Energy Supply, LLC, PPL Electric Utilities Corporation, LG&E and KU Energy LLC, Louisville Gas and Electric Company and Kentucky Utilities Company
(a) The following documents are filed as part of this report:
1.
Financial Statements - Refer to the "Table of Contents" for an index of the financial statements included in this report.
2.
Supplementary Data and Supplemental Financial Statement Schedule - included in response to Item 8.