ITEM 1. BUSINESS
BACKGROUND
PPL Corporation, headquartered in Allentown, Pennsylvania, is an energy and utility holding company that was incorporated in 1994. Through 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 delivers natural gas to customers in Kentucky.
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 in its energy supply business while mitigating volatility in both cash flows and earnings.
In pursuing this strategy, in 2011 and 2010, PPL completed two significant acquisitions that 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:
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On April 1, 2011, PPL, through an 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. WPD Midlands operates two regulated distribution networks that serve five million end-users in the Midlands area of England.
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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.
See Note 10 to the Financial Statements for additional information on both acquisitions.
Each rate-regulated business plans to make material capital investments over the next several years to improve infrastructure and customer reliability. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Financial Condition - Liquidity and Capital Resources" for information on each Registrant's capital expenditure projections.
A key objective of PPL's business strategy is to maintain a strong credit profile. PPL's recent growth in rate-regulated businesses has provided the organization with an enhanced corporate level financing alternative, through PPL Capital Funding, that further enables PPL to support targeted credit profiles cost effectively across all of PPL's rated companies. As a result, PPL plans to further utilize PPL Capital Funding in addition to continued direct financing by the operating companies, as appropriate.
At December 31, 2012, PPL had:
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$12.3 billion in operating revenues for the year (56% from regulated businesses),
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10.5 million end-users of its utility services,
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approximately 19,000 MW of generation (44% within regulated businesses), and
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approximately 18,000 full-time employees.
PPL's principal subsidiaries at December 31, 2012 are shown below (* denotes an SEC registrant).
In addition to PPL Corporation, the other SEC registrants included in this filing are:
LG&E and KU Energy LLC, headquartered in Louisville, Kentucky, is a holding company with regulated utility operations through subsidiaries, LG&E and KU, and is a 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, 2012, LG&E owned 3,354 MW of electric power generation capacity and is implementing capital projects at an existing generation facility to provide 141 MW of additional generating capacity by the end of 2015. LG&E also anticipates retiring 563 MW of coal-fired 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, 2012, KU owned 4,833 MW of electric power generation capacity and is implementing capital projects at an existing generation facility owned by LG&E to provide 499 MW of additional generating capacity by the end of 2015. KU retired the remaining 71 MW unit at the Tyrone plant in February 2013. KU also anticipates retiring 163 MW of coal-fired 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 Electric Utilities Corporation, headquartered in Allentown, Pennsylvania, is a direct subsidiary of PPL incorporated in Pennsylvania 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.
PPL Energy Supply, LLC, headquartered in Allentown, Pennsylvania, is an indirect 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. In January 2011, PPL Energy Supply distributed its entire 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 these 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. The 2010 operating results of PPL Global, which represented the U.K. Regulated segment (formerly International Regulated), are classified as discontinued operations. At December 31, 2012, PPL Energy Supply owned or controlled 10,591 MW of electric power generation capacity and is implementing capital projects at certain of its existing generation facilities in Pennsylvania and Montana to provide 153 MW of additional generating capacity by the end of 2013.
PPL's utility subsidiaries, and to a lesser extent, certain competitive supply subsidiaries, are subject to extensive regulation by the FERC related to wholesale power sales and related transactions, electricity 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. 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)
PPL is organized into four reportable segments: Kentucky Regulated, U.K. Regulated (name changed in 2012 from International Regulated), Pennsylvania Regulated and Supply. There were no changes to reportable segments in 2012 other than the name change noted above.
(a)
Business activities include the generation, transmission, distribution and sale of electricity and the distribution and sale of natural gas.
(b)
Business activities include the distribution of electricity.
(c)
Business activities include the transmission and distribution of electricity.
(d)
Represents RAV for U.K. Regulated, capitalization for KY Regulated and rate base for PA Regulated.
(PPL Energy Supply)
PPL Energy Supply has operated in a single reportable segment since 2011. Prior to 2011, PPL Energy Supply's segments consisted of Supply and U.K. Regulated (formerly 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. The distribution separated the U.S.-based competitive energy marketing and supply business from the U.K.-based regulated electricity distribution business. The 2010 operating results of PPL Global, which represented the U.K. Regulated segment, are classified as discontinued operations for PPL Energy Supply.
(PPL Electric, LKE, LG&E and KU)
PPL Electric, LKE, LG&E and KU each operate within a single reportable segment.
(PPL)
See Note 2 to the Financial Statements for financial information about the segments.
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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 393,000 customers in Louisville and adjacent areas in Kentucky, covering approximately 700 square miles in 9 counties. LG&E provides natural gas service to approximately 318,000 customers in its electric service area and 7 additional counties in Kentucky. KU provides electric service to approximately 510,000 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. Under the terms of the settlement, LG&E and KU retained the right to seek approval for the deferral of "extraordinary and uncontrollable costs." Interim rate adjustments continued to be permissible during that period through existing fuel, environmental and demand side management recovery mechanisms. In October 2010, both the VSCC and the TRA approved the transfer of control of LKE to PPL. The orders and the settlement agreement approved by the KPSC contained certain other commitments by LG&E and KU 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 included 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 costs from retail customers and agreements to coordinate with intervenors in certain pending matters.
See Note 10 to the Financial Statements for additional information on regulatory matters related to the acquisition.
Franchises and Licenses
LG&E and KU provide electricity delivery service, and LG&E provides natural gas distribution service, in their respective 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. From time to time, bills are introduced into the Kentucky General Assembly which seek to authorize, promote or mandate increased distributed generation, customer choice or other developments. 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 that 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.
Operating Revenues
Details of operating revenues by customer class are shown below.
(a)
The LKE Successor information also represents PPL's Kentucky Regulated segment.
(b)
Includes wholesale and transmission revenues.
(c)
Includes intercompany power sales and transmission revenues, which are eliminated upon consolidation at LKE.
Power Supply
At December 31, 2012, LKE owned, controlled or had an ownership interest in generating capacity (summer rating) of 8,187 MW, of which 3,354 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 2012, LKE's Kentucky power plants generated the following amounts of electricity.
(a)
Includes 990 MWh of power generated by and purchased from OVEC for LKE, 685 MWh for LG&E and 305 MWh for KU.
(b)
This generation represents a 4% decrease for LKE, a 4% decrease for LG&E and a 3% decrease for KU from 2011 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 development of Cane Run Unit 7. KU retired the remaining 71 MW unit at the Tyrone plant in February 2013. LG&E and KU also anticipate retiring 563 MW and 163 MW of coal-fired 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. However, natural gas will play a more significant role starting in 2015 when Cane Run Unit 7 is expected to be placed into operation. This unit is expected to be used for baseload generation. Natural gas and oil will continue to be 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. To enhance the reliability of natural gas supply, LG&E and KU have secured long-term pipeline capacity on the interstate pipeline serving the new combined cycle unit and six simple cycle combustion turbine units.
LG&E and KU have entered into coal supply agreements with various suppliers for coal deliveries through 2017 and normally augment their coal supply agreements with spot market purchases, as needed.
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 increased during 2012 due to the installation of scrubbers and the sulfuric acid mist mitigation system at KU's E.W. Brown plant. In 2013 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, 2012, LG&E had a 12 Bcf inventory balance of natural gas stored underground with a carrying value of $42 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 2015 and 2018. Total winter capacity under these contracts is 194,900 MMBtu/day and summer capacity is 88,000 MMBtu/day. LG&E has a contract with another pipeline that expires in October 2014. Total winter and summer capacity under this contract is 20,000 MMBtu/day during both seasons.
(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. LG&E and KU contracted with Southwest Power Pool, Inc. (SPP), to function as their independent transmission operator, pursuant to FERC requirements under a contract that expired on August 31, 2012. After receiving FERC approval, LG&E and KU transferred from SPP to TranServ International, Inc. as their independent transmission operator beginning September 1, 2012.
In February 2013, LG&E and KU submitted a compliance filing to the FERC reflecting their participation with other utilities in the Southeastern Regional Transmission Planning relating to certain FERC Order 1000 requirements. FERC Order 1000, issued in July 2011, establishes certain procedural and substantive requirements relating to participation, cost allocation and non-incumbent developer aspects of regional and inter-regional electric transmission planning activities.
LG&E's and KU's Kentucky base rates are calculated based on a return on capitalization (common equity, long-term debt and short-term debt) including certain adjustments to exclude non-regulated investments and costs recovered separately through other rate mechanisms. As such, LG&E and KU earn a return on the net cash invested in regulatory assets and regulatory liabilities.
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.
2012 Kentucky Rate Case
In June 2012, LG&E and KU filed requests with the KPSC for increases in annual base electric rates of approximately $62 million at LG&E and approximately $82 million at KU and an increase in annual base gas rates of approximately $17 million at LG&E. In November 2012, LG&E and KU along with all of the parties filed a unanimous settlement agreement. Among other things, the settlement provided for increases in annual base electric rates of $34 million at LG&E and $51 million at KU and an increase in annual base gas rates of $15 million at LG&E. The settlement agreement also included revised depreciation rates that result in reduced annual electric depreciation expense of approximately $9 million for LG&E and approximately $10 million for KU. The settlement agreement included an authorized return on equity at LG&E and KU of 10.25%. On December 20, 2012, the KPSC issued orders approving the provisions in the settlement agreement. The new rates became effective on January 1, 2013. In addition to the increased base rates, the KPSC approved a gas line tracker mechanism for LG&E to provide for recovery of costs associated with LG&E's gas main replacement program, gas service lines and risers.
FERC Wholesale Rates
In May 2012, KU submitted to the FERC the annual adjustments to the formula rate which incorporated certain proposed increases. These rates became effective as of July 1, 2012.
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U.K. Regulated Segment (PPL)
Includes WPD, a regulated electricity distribution business in the U.K.
WPD, through indirect wholly owned subsidiaries, operates four of the 15 regulated distribution networks providing electricity service in the U.K. With the April 2011 acquisition of WPD Midlands, the number of end-users served has more than doubled totaling 7.8 million across 21,400 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 above years are not comparable 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 regulated revenue it can earn 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 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. Under recoveries are recovered in the next regulatory year, however, PPL does not record a receivable for under recoveries in the current period. Over recoveries are reflected in the current period as a liability and are not included in revenue.
In addition to providing a base regulated 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 a benchmark of data from the last four years of the prior price control period.
Effective April 1, 2012, an additional customer satisfaction incentive mechanism was implemented that includes a customer satisfaction survey, a complaints metric and a measure of stakeholder engagement. This incentive replaced the customer response telephone performance incentive that was effective April 1, 2010.
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Line Loss Incentive - This incentive existed in the prior price control review, DPCR4, and was 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. In November 2012, Ofgem issued a decision not to activate the DPCR5 line loss incentive. See Note 6 to the Financial Statements for information on Ofgem's review of line loss calculations.
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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. Since the beginning of DPCR5, WPD earned additional incentive revenue, primarily from IIS of $83 million and $30 million for the regulatory years ended March 31, 2012 and 2011, which will be included in revenue for the 2013-14 and 2012-13 regulatory years.
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. The next electricity distribution price control review is referred to as RIIO-ED1. In September 2012, Ofgem published a strategy consultation document providing an overview of its approach for RIIO-ED1 and is expected to publish a policy decision document in February 2013. Key components of the RIIO-ED1 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. Management is in the process of creating the "well-justified business plans" required by Ofgem for WPD's four DNOs. These plans are expected to be submitted to Ofgem in July 2013 as part of the RIIO-ED1 review process. Once the business plans are complete, management will be in a better position to determine the effect of RIIO-ED1 on future 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, and has significantly impacted our earnings since the second half of 2008. The breadth and depth of these negative economic conditions had a wide-ranging impact on the U.S. and U.K. business environment, including our businesses. As a result of the economic downturn, demand for energy commodities declined significantly. This reduced demand continues 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 increased supply of natural gas 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, 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 and Basel III in Europe 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 either or both directly decrease revenues and 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 summer or decreased winter overall electricity consumption 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.
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 to fund our significant capital expenditures, debt service 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, inflation rates, 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 2012, 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 1, 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, among other things, to 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 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 and decrease our revenues and 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 and lead to increased costs, expenses or losses. Operation of our delivery systems below our expectations may result in lost revenue and 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, employment-related and other 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 period from 2014 through 2018, 23.5% of PPL's total 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 skilled 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.
(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 or based on future projected costs, the rates we are allowed to charge may or may not match our costs at any given time. Our regulated utility businesses are subject to substantial capital expenditure requirements over the next several years, which will likely require rate increase requests to the regulators. If our costs are not adequately recovered through rates, it could have an adverse effect on our business, results of operations, cash flows and 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 electricity 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 expenditures 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 and demand for our services.
Ongoing 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 and 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.
PPL Electric is subject to Act 129 which contains requirements for energy efficiency and conservation programs and for the use of smart metering technology, imposes new PLR electricity supply procurement rules, provides remedies for market misconduct, and made changes to the existing AEPS. 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 for Phase 1 and by 2016 for Phase 2). 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.
(PPL)
Risks Related to U.K. 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, reducing regulatory rate uncertainty in the U.K. Regulated segment until the next rate review which will be effective April 1, 2015. The regulated income of the U.K. Regulated segment and also the RAV are to some extent linked to movements in the Retail Price Index (RPI), a measure of inflation. Reductions in the RPI would adversely impact revenues and the debt-to-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:
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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.
The WPD Midlands acquisition exposes us to additional risks and uncertainties with respect to the acquired businesses and their operations.
Although the WPD Midlands acquisition increased our relative investment in regulated operations, which we believe should help mitigate our exposure to downturns in the wholesale power markets, it will increase our dependence on rate-of-return regulation.
The WPD businesses generally are subject to risks similar to those to which we were subject 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 or repayments of intercompany loans. 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 electricity generating 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 capacity prices and 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, competitive subsidiaries of regulated utilities and financial institutions.
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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demand for electricity;
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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. However, 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, including bankruptcy, 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 and 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.
Unforeseen changes in the price of coal and natural gas could cause us to incur excess coal inventories and contract termination costs.
Extraordinarily low natural gas prices during 2012 caused natural gas to be the more cost competitive fuel compared to coal for generating electricity. Because we enter into guaranteed supply contracts to provide for the amount of coal needed to operate our base load coal-fired generating facilities, we may experience periods where we hold excess amounts of coal if fuel pricing results in our reducing or idling coal-fired generating facilities in favor of operating available alternative natural gas-fired generating facilities. In addition, we may incur costs to terminate supply contracts for coal in excess of our generating requirements.
Our risk management policy and programs relating to electricity and fuel prices, interest rates 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 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, 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 previously proposed federal and state environmental laws and regulations primarily governing air emissions from coal-fired plants, since 2005 PPL has spent more than $1.6 billion 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) in its competitive generation fleet. Many states and environmental groups have challenged certain federal laws and regulations relating to air emissions as not being sufficiently strict. As a result, state and federal regulations have been adopted that would impose more stringent restrictions than are currently in effect, which could require us significantly to 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 electricity 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, contract for, 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" and "Maryland Capacity Order" 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 31% of our 2012 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 and 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, 2012 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)
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.
(e)
This unit was retired in February 2013. See Note 8 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, 2012, 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 917 circuit miles of lines. LG&E's distribution system included 97 substations (32 of which are shared with the transmission system) with a total capacity of 5 million kVA, 3,908 miles of overhead lines and 2,390 miles of underground wires. KU's transmission system included 134 substations (55 of which are shared with the distribution system) with a total capacity of 13 million kVA and 4,079 circuit miles of lines. KU's distribution system included 480 substations (55 of which are shared with the transmission system) with transformer capacity of 7 million kVA, 14,134 miles of overhead lines and 2,299 miles of underground conduit.
LG&E's natural gas transmission system includes 4,272 miles of gas distribution mains and 388 miles of gas transmission mains, consisting of 255 miles of gas transmission pipeline, 124 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, 2012, 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)
LG&E and KU anticipate retiring these units by the end of 2015. See Notes 8 and 15 to the Financial Statements for additional information.
(c)
KU retired this unit in February 2013. See Note 8 to the Financial Statements for additional information.
(d)
In May 2012, LG&E and KU received approval to build this unit at the existing Cane Run site. See Note 8 to the Financial Statements for additional information.
(PPL)
U.K. Regulated Segment
For a description of WPD's service territory, see "Item 1. Business - Background." At December 31, 2012, 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 1,592 substations with a total capacity of 68 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, 2012, 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 includes 61 substations with a total capacity of 18 million kVA and 3,973 pole miles in service. PPL Electric's distribution system includes 339 substations with a total capacity of 12 million kVA, 37,031 circuit miles of overhead lines and 8,098 cable miles of underground conductors in service. 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 Regional Transmission Line Expansion Plan.
(PPL and PPL Energy Supply)
Supply Segment
PPL Energy Supply's electric generating capacity (summer rating) at December 31, 2012 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)
Represents the leasehold interest held by PPL Montana. See Note 11 to the Financial Statements for additional information.
(c)
This unit is jointly owned. Each owner is entitled to its proportionate share of the unit's total output and funds its proportionate share of fuel and other operating costs. See Note 14 to the Financial Statements for additional information.
(d)
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 from time to time 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. See Note 15 to the Financial Statements for information on PPL Energy Supply's intention, beginning in April 2015, to place its Corette plant in long-term reserve status. At December 31, 2012, 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 involves construction of a new powerhouse and retirement of the exiting 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, 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, 2013, there were 66,130 common stock shareowners of record.
(1)
Represents shares of common stock withheld by PPL at the request of its executive officers to pay income taxes upon the vesting of the officers' restricted stock awards, as permitted under the terms of PPL's ICP and ICPKE.
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 $787 million in 2012 and $316 million in 2011. 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 $95 million in 2012 and $92 million in 2011.
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 $155 million in 2012 and $533 million in 2011 (including $248 million from the proceeds of a note issuance).
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 $75 million in 2012 and $83 million in 2011.
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 $100 million in 2012 and $124 million in 2011.
(a)
The earnings each year were affected by several items that management considers special. See "Results of Operations - Segment Results" in "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" for a description of special items in 2012, 2011 and 2010. The earnings were also affected by the sales of various businesses. See Note 9 to the Financial Statements for a discussion of discontinued operations in 2012, 2011 and 2010.
(b)
See "Item 1A. Risk Factors" and Notes 6 and 15 to the Financial Statements for a discussion of uncertainties that could affect PPL's future financial condition.
(c)
Includes WPD Midlands activity since its April 1, 2011 acquisition date. Includes LKE activity since its November 1, 2010 acquisition date.
(d)
As of each respective year-end.
(e)
Computed using earnings and fixed charges of PPL and its subsidiaries. Fixed charges consist of interest on short- and long-term debt, amortization of debt discount, expense and premium - net, other interest charges, the estimated interest component of operating rentals and preferred securities distributions of subsidiaries. See Exhibit 12(a) for additional information.
(f)
Based on diluted EPS.
(g)
Based on year-end market prices.
(h)
The electric energy supplied changes in 2010 reflect the expiration of the PLR contract between PPL EnergyPlus and PPL Electric as of December 31, 2009.
(i)
GWh are included until the transaction closing for facilities that were sold.
(j)
(k)
Prior period volumes were restated to include unbilled volumes.
Year 2011 includes eight months of deliveries associated with the acquisition of WPD Midlands as volumes are reported on a one-month lag.
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.
PPL CORPORATION AND SUBSIDIARIES
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 defined in the glossary. Dollars are in millions, except per share data, 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, a summary of Net Income Attributable to PPL Shareowners and a discussion of certain events related to 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 explanations of significant changes in principal items on PPL's Statements of Income, comparing 2012 with 2011 and 2011 with 2010.
·
"Financial Condition - Liquidity and Capital Resources" provides an analysis of PPL's liquidity position and credit profile. This section also includes a discussion of forecasted sources and uses of cash and rating agency actions.
·
"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.
PPL's principal subsidiaries are shown below (* denotes an SEC registrant):
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 in its energy supply business 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. Each of the rate-regulated businesses plans to make material capital investments over the next several years to improve infrastructure and customer reliability. As a result of these acquisitions, approximately 71% of PPL's assets were in its regulated businesses at December 31, 2012 and approximately 73% of "Net Income Attributable to PPL Shareowners" was from regulated businesses for the year ended December 31, 2012.
The increase in regulated assets is expected to provide earnings stability through regulated returns on equity 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.
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 acquisition of WPD Midlands, PPL has a higher proportion of overall earnings subject to foreign currency translation risk. 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 energy supply business is to optimize the value from its competitive 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 and strong liquidity position. In addition, PPL 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 Shareowners
Net Income Attributable to PPL Shareowners for the years ended December 31 by segment and in total was:
(a)
LKE was acquired on November 1, 2010. Therefore, 2012 and 2011 include a full year of LKE results, while 2010 includes two months of LKE results.
(b)
WPD Midlands was acquired on April 1, 2011 and its results are recorded on a one-month lag. Therefore, 2012 includes a full year of WPD Midlands' results, while 2011 includes eight months of WPD Midlands' results. 2011 was also impacted by certain acquisition related costs. These costs are considered special items by management and are discussed in further detail in "Results of Operations - Earnings - U.K. Regulated Segment." See Notes 7 and 10 to the Financial Statements for additional information on the acquisition and related financing.
(c)
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. 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.
Earnings in 2012 increased 2% over 2011 and earnings in 2011 increased 59% over 2010. The changes in Net Income Attributable to PPL Shareowners from year to year were, in part, attributable to the acquisition of LKE and WPD Midlands and certain items that management considers special. See "Results of Operations" for further discussion of PPL's business segments, details of special items and analysis of the consolidated results of operations.
Economic and Market Conditions
Unregulated Gross Energy Margins associated with PPL Energy Supply's competitive generation and marketing business are impacted by changes in market prices and demand for electricity and natural gas, power plant availability, competition in the markets for retail customers, fuel costs and availability, fuel transportation costs and other costs. Current depressed wholesale market prices for electricity and natural gas have resulted from general weak economic conditions and other factors, including the impact of expanded domestic shale gas development and production. As a result of these factors, PPL Energy Supply has experienced a shift in the dispatching of its competitive generation from coal-fired to combined-cycle gas-fired generation as illustrated in the following table:
(a)
All periods reflect the year ended December 31.
This reduction in coal-fired generation output had resulted in a surplus of coal inventory at certain of PPL Energy Supply's Pennsylvania coal plants. To mitigate the risk of exceeding available coal storage, PPL Energy Supply incurred pre-tax charges of $29 million in 2012 to reduce its 2012 and 2013 contracted coal deliveries. PPL Energy Supply will continue to manage its coal inventory to mitigate the financial impact and physical implications of an oversupply; however, no additional coal contract modifications are expected at this time.
In addition, current economic and commodity market conditions indicate a lower value of unhedged future energy margins (primarily in 2014 and forward years) compared to the energy margins in 2012. As has been PPL Energy Supply's practice in periods of changing business conditions, PPL Energy Supply continues to review its future business and operational plans, including capital and operation and maintenance expenditures, as well as its hedging strategies, to help counter the financial effects of low commodity prices.
PPL's businesses are subject to extensive federal, state and local environmental laws, rules and regulations. Although PPL Energy Supply's competitive generation assets are well positioned to meet these requirements, certain regulated generation assets at LG&E and KU will require substantial capital investment. LG&E and KU project $2.3 billion of capital investment over the next five years to satisfy certain of these requirements. See Note 15 to the Financial Statements for additional information on these requirements. These requirements have resulted in LKE's anticipated retirement of five coal-fired units with a combined summer capacity rating of 726 MW by 2015. KU retired the 71 MW unit at the Tyrone plant in February 2013. See Note 8 to the Financial Statements for additional information regarding the anticipated retirement of these units as well as plans to build a combined-cycle natural gas facility in Kentucky. Also, in 2012 KU recorded a $25 million pre-tax impairment of its EEI investment as a result of environmental regulations and low energy prices. Finally, in September 2012 PPL announced its intention, beginning in April 2015, to place its Corette plant in long-term reserve status, suspending the plant's operation due to expected market conditions and the costs to comply with MATS. The Corette plant asset group's carrying amount at December 31, 2012 was approximately $68 million. Although the Corette plant asset group was not determined to be impaired at December 31, 2012, it is reasonably possible that an impairment could occur in future periods, as higher priced sales contracts settle, adversely impacting projected cash flows.
In light of these economic and market conditions, as well as current and projected environmental regulatory requirements, PPL considered whether certain of its other generating assets were impaired, and determined that no impairment charges were required at December 31, 2012. PPL is unable to predict whether future environmental requirements or market conditions will result in impairment charges for other generating assets or other retirements.
PPL and its subsidiaries may also be impacted in future periods by the uncertainty in the worldwide financial and credit markets. In addition, PPL may be impacted by reductions in the credit ratings of financial institutions and evolving regulations in the financial sector. Collectively, these factors could reduce availability or restrict PPL and its subsidiaries' ability to maintain sufficient levels of liquidity, reduce capital market activities, change collateral posting requirements and increase the associated costs to PPL and its subsidiaries.
PPL cannot predict the future impact that these economic and market conditions and regulatory requirements may have on its financial condition or results of operations.
Susquehanna Turbine Blade Inspection
During 2012, PPL Energy Supply performed inspections of the Unit 1 and Unit 2 turbine blades at the PPL Susquehanna nuclear power plant in order to further address the issue of turbine blade cracking that was first identified in 2011. The after-tax earnings impact of these 2012 inspections, including reduced energy-sales margins and repair expenses, was approximately $53 million. The after-tax earnings impact of turbine blade related outages in 2011 was approximately $63 million.
Ironwood Acquisition
In April 2012, an indirect, wholly owned subsidiary of PPL Energy Supply completed the acquisition of the equity interests in the owner and operator of the Ironwood Facility. The Ironwood Facility began operation in 2001 and, since 2008, PPL EnergyPlus has supplied natural gas for the facility and received the facility's full electricity output and capacity value pursuant to a tolling agreement that expires in 2021. The acquisition provides PPL Energy Supply, through its subsidiaries, operational control of additional combined-cycle gas generation in PJM. See Note 10 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 for the District of Montana. At the time of the bankruptcy filing, SMGT was PPL EnergyPlus' largest unsecured credit exposure. This contract was accounted for as NPNS by PPL EnergyPlus.
The SMGT Contract provided for fixed volume purchases on a monthly basis at established prices. Pursuant to a court order and subsequent stipulations entered into between the SMGT bankruptcy trustee 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 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 March 2012, the U.S. Bankruptcy Court for the District of Montana issued an order approving the request of the SMGT bankruptcy trustee and PPL EnergyPlus to terminate the SMGT Contract. As a result, the SMGT Contract was terminated effective April 1, 2012, allowing PPL EnergyPlus to resell to other customers the electricity previously contracted to SMGT under the SMGT Contract.
PPL EnergyPlus' receivable under the SMGT Contract totaled approximately $21 million at December 31, 2012, which has been fully reserved.
In July 2012, PPL EnergyPlus filed its proof of claim in the SMGT bankruptcy proceeding. The total claim is approximately $375 million, including the above receivable, predominantly an unsecured claim representing the value for energy sales that will not occur as a result of the termination of the SMGT Contract. No assurance can be given as to the collectability of the claim, thus no amounts have been recorded in the 2012 financial statements.
PPL Energy Supply cannot predict any amounts that it may recover in connection with the SMGT bankruptcy or the prices and other terms on which it will be able to market to third parties the power that SMGT will not purchase from PPL EnergyPlus due to the termination of the SMGT Contract.
Tax Litigation
In 1997, the U.K. imposed a Windfall Profits Tax (WPT) on privatized utilities, including WPD. PPL filed its federal 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 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, 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. In February 2012, PPL filed its petition for rehearing of the Third Circuit's opinion. In March 2012, the Third Circuit denied PPL's petition. In June 2012, the U.S. Court of Appeals for the Fifth Circuit issued a contrary opinion in an identical case involving another company. In July 2012, PPL filed a petition for a writ of certiorari seeking U.S. Supreme Court review of the Third Circuit's opinion. The Supreme Court granted PPL's petition on October 29, 2012, and oral argument was held on February 20, 2013. PPL expects the case to be decided before the end of the Supreme Court's current term in June 2013 and cannot predict the outcome of this matter.
Terminated 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, pending receipt of applicable regulatory approvals. In May 2012, the KPSC issued an order approving the request to purchase the Bluegrass CTs. In November 2011, LG&E and KU filed an application with the FERC under the Federal Power Act requesting approval to purchase the Bluegrass CTs. In May 2012, the FERC issued an order conditionally authorizing the acquisition of the Bluegrass CTs, subject to approval by the FERC of satisfactory mitigation measures to address market-power concerns. After a review of potentially available mitigation options, LG&E and KU determined that the options were not commercially justifiable. In June 2012, LG&E and KU terminated the asset purchase agreement for the Bluegrass CTs in accordance with its terms and made applicable filings with the KPSC and FERC.
Cane Run Unit 7 Construction
In September 2011, LG&E and KU filed a CPCN with the KPSC requesting approval to build Cane Run Unit 7. In May 2012, the KPSC issued an order approving the request. A formal request for recovery of the costs associated with the construction was not included in the CPCN filing with the KPSC but is expected to be included in future rate case proceedings. LG&E and KU commenced preliminary construction activities in the third quarter of 2012 and project construction is expected to be completed by May 2015. The project, which includes building a natural gas supply pipeline and related transmission projects, has an estimated cost of approximately $600 million.
Future Capacity Needs
In addition to the construction of a combined cycle gas unit at the Cane Run station, LG&E and KU continue to assess future capacity needs. As a part of the assessment, LG&E and KU issued an RFP in September 2012 for up to 700 MW of capacity beginning as early as 2015.
Storm Costs
During 2012, PPL Electric experienced several PUC-reportable storms, including Hurricane Sandy, resulting in total restoration costs of $81 million, of which $61 million were initially recorded in "Other operation and maintenance" on the Statement of Income. In particular, in late October 2012, PPL Electric experienced widespread significant damage to its distribution network from Hurricane Sandy resulting in total restoration costs of $66 million, of which $50 million were initially 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. PPL Electric recorded a regulatory asset of $28 million in December 2012 (offset to "Other operation and maintenance" on the Statement of Income). In February 2013, PPL Electric received an order from the PUC granting permission to defer qualifying storm costs in excess of insurance recoveries associated with Hurricane Sandy.
See "Regulatory Matters - Pennsylvania Activities - Storm Costs" in Note 6 to the Financial Statements for information on $84 million of storm costs incurred in 2011.
Rate Case Proceedings
Pennsylvania
In March 2012, PPL Electric filed a request with the PUC to increase distribution rates by approximately $105 million, effective January 1, 2013. In its December 28, 2012 final order, the PUC approved a 10.4% return on equity and a total distribution revenue increase of about $71 million. The approved rates became effective January 1, 2013.
Also, in its December 28, 2012 final order, the PUC ordered PPL Electric to file a proposed Storm Damage Expense Rider within 90 days following the order. PPL Electric plans to file a proposed Storm Damage Expense Rider with the PUC and, as part of that filing, request recovery of the $28 million of qualifying storm costs incurred as a result of the October 2012 landfall of Hurricane Sandy.
Kentucky
In June 2012, LG&E and KU filed requests with the KPSC for increases in annual base electric rates of approximately $62 million at LG&E and approximately $82 million at KU and an increase in annual base gas rates of approximately $17 million at LG&E. In November 2012, LG&E and KU along with all of the parties filed a unanimous settlement agreement. Among other things, the settlement provided for increases in annual base electric rates of $34 million at LG&E and $51 million at KU and an increase in annual base gas rates of $15 million at LG&E. The settlement agreement also included revised depreciation rates that result in reduced annual electric depreciation expense of approximately $9 million for LG&E and approximately $10 million for KU. The settlement agreement included an authorized return on equity at LG&E and KU of 10.25%. On December 20, 2012, the KPSC issued orders approving the provisions in the settlement agreement. The new rates became effective on January 1, 2013. In addition to the increased base rates, the KPSC approved a gas line tracker mechanism for LG&E to provide for recovery of costs associated with LG&E's gas main replacement program, gas service lines and risers.
Regional Transmission Line Expansion Plan
Susquehanna-Roseland
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 was needed to prevent potential overloads that could occur on several existing transmission lines in the interconnected PJM system. PJM directed PPL Electric to construct the portion of the Susquehanna-Roseland line in Pennsylvania and Public Service Electric & Gas Company to construct the portion of the line in New Jersey.
On October 1, 2012, the National Park Service (NPS) issued its Record of Decision (ROD) on the proposed Susquehanna-Roseland transmission line affirming the route chosen by PPL Electric and Public Service Electric & Gas Company as the preferred alternative under the NPS's National Environmental Policy Act review. On October 15, 2012, a complaint was filed in the United States District Court for the District of Columbia by various environmental groups, including the Sierra Club, challenging the ROD and seeking to prohibit its implementation; and on December 6, 2012, the groups filed a petition for injunctive relief seeking to prohibit all construction activities until the court issues a final decision on the complaint. PPL Electric has intervened in the lawsuit. The chosen route had previously been approved by the PUC and New Jersey Board of Public Utilities.
On December 13, 2012, PPL Electric received federal construction and right of way permits to build on National Park Service lands.
Construction activities have begun on portions of the 101-mile route in Pennsylvania. The line is expected to be completed before the peak summer demand period of 2015. At December 31, 2012, PPL Electric's estimated share of the project cost was $560 million.
PPL and PPL Electric cannot predict the ultimate outcome or timing of any legal challenges to the project or what additional actions, if any, PJM might take in the event of a further delay to its scheduled in-service date for the new line.
Northeast/Pocono
In October 2012, the FERC issued an order in response to PPL Electric's December 2011 request for ratemaking incentives for the Northeast/Pocono Reliability project (a new 58-mile 230 kV transmission line, three new substations and upgrades to adjacent facilities). The incentives were specifically tailored to address the risks and challenges PPL Electric will face in building the project. The FERC granted the incentive for inclusion of all prudently incurred construction work in progress (CWIP) costs in rate base and denied the request for a 100 basis point adder to the return on equity incentive. The order required a follow-up compliance filing from PPL Electric to ensure proper accounting treatment of AFUDC and CWIP for the project, which PPL Electric will submit to the FERC in March 2013. PPL Electric expects the project to be completed in 2017. At December 31, 2012, PPL Electric estimates the total project costs to be approximately $200 million with approximately $190 million qualifying for the CWIP incentive.
Legislation - Regulatory Procedures and Mechanisms
Act 11 authorizes the PUC to approve two specific ratemaking mechanisms - the use of a fully projected future test year in base rate proceedings and, subject to certain conditions, the use of a DSIC. Such alternative ratemaking procedures and mechanisms provide opportunity for accelerated cost-recovery and, therefore, are important to PPL Electric as it begins a period of significant capital investment to maintain and enhance the reliability of its delivery system, including the replacement of aging distribution assets. In August 2012, the PUC issued a final implementation order adopting procedures, guidelines and a model tariff for the implementation of Act 11. Act 11 requires utilities to file an LTIIP as a prerequisite to filing for recovery through the DSIC. The LTIIP is mandated to be a five- to ten-year plan describing projects eligible for inclusion in the DSIC. In September 2012, PPL Electric filed its LTIIP describing projects eligible for inclusion in the DSIC. The PUC approved the LTIIP on January 10, 2013 and PPL Electric filed a petition requesting permission to establish a DSIC on January 15, 2013, with rates proposed to be effective beginning May 1, 2013.
FERC Formula Rates
In March 2012, PPL Electric filed a request with the FERC seeking recovery of its 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. At December 31, 2012 and December 31, 2011, $52 million and $53 million respectively, are classified as taxes recoverable through future rates and included on the Balance Sheets in "Other Noncurrent Assets - Regulatory assets." In May 2012, the FERC issued an order approving PPL Electric's request to recover the deferred tax regulatory asset over a 34 year period beginning June 1, 2012.
U.K. Tax Rate Change
In July 2012, the U.K.'s Finance Act of 2012 (the Act) became effective. The Act reduced the U.K. statutory income tax rate from 25% to 24%, retroactive to April 1, 2012 and from 24% to 23%, effective April 1, 2013. As a result of these changes, PPL recognized a deferred tax benefit of $75 million in 2012.
Ofgem Review of Line Loss Calculation
WPD had a $94 million liability recorded at December 31, 2012, compared with $170 million at December 31, 2011, related to the close-out of line losses for the prior price control period, DPCR4. Ofgem is currently consulting on the methodology to be used by all network operators 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. In March 2012, Ofgem issued a decision regarding the preferred methodology. In July 2012, Ofgem issued a consultation paper regarding certain aspects of the preferred methodology as it relates to the DPCR4 line loss incentive/penalty and a proposal to delay the target date for making a final decision until April 2013. In October 2012, a license modification was issued to allow Ofgem to publish the final decisions on these matters by April 2013. In November 2012, Ofgem issued an additional consultation on the final DPCR4 line loss close-out that published values for each DNO and further indicated the preferred methodology that would replace the methodology under WPD's licenses. Based on applying the preferred methodology for DPCR4, the liability was reduced by $79 million, with a credit recorded in "Utility" on the Statement of Income, to reflect what WPD expects to be the final close-out settlement under Ofgem's preferred methodology. This consultation also confirmed the final decisions will be published by April 2013. In February 2013, Ofgem issued additional consultation proposing to delay the April 2013 decision date. PPL cannot predict when this matter will be resolved.
Ofgem also stated in the November 2012 consultation that the line loss incentive implemented at the last rate review will be withdrawn and no incentive will apply for the DPCR5 period. That decision resulted in the elimination of the DPCR5 liability of $11 million, with a credit recorded in "Utility" on the Statement of Income.
Equity Forward Contract
In April 2012, PPL made a registered underwritten public offering of 9.9 million shares of its common stock. In conjunction with that offering, the underwriters exercised an option to purchase 591 thousand additional shares of PPL common stock solely to cover over-allotments.
In connection with the registered public offering, PPL entered into forward sale agreements with two counterparties covering the 9.9 million shares of PPL's common stock. Settlement of these initial forward sale agreements will occur no later than April 2013. As a result of the underwriters' exercise of the overallotment option, PPL entered into additional forward sale agreements covering the additional 591 thousand shares of PPL common stock. Settlement of the subsequent forward sale agreements will occur no later than July 2013.
PPL will not receive any proceeds or issue any shares of common stock until settlement of the forward sale agreements. PPL intends to use any net proceeds that it receives upon settlement to repay short-term debt obligations and for other general corporate purposes.
The forward sale agreements are classified as equity transactions. As a result, no amounts will be recorded in the consolidated financial statements until the settlement of the forward sale agreements. Prior to those settlements, the only impact to the financial statements will be the inclusion of incremental shares within the calculation of diluted EPS using the treasury stock method. See Note 7 to the Financial Statements for additional information.
2010 Equity Units
During 2013, two events will occur related to the components of the 2010 Equity Units. PPL will receive proceeds of $1.150 billion through the issuance of PPL common stock to settle the 2010 Purchase Contracts and PPL Capital Funding expects to remarket the 4.625% Junior Subordinated Notes due 2018. See Note 7 to the Financial Statements for additional information.
Redemption of PPL Electric Preference Stock
In June 2012, PPL Electric redeemed all 2.5 million shares of its 6.25% Series Preference Stock, par value $100 per share. The price paid for the redemption was the par value, without premium ($250 million in the aggregate). At December 31, 2011, the preference stock was reflected in "Noncontrolling Interests" on PPL's Balance Sheet.
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 and Unregulated Gross Energy Margins.
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, a full year of WPD Midlands' results of operations are included in PPL's results for 2012, and 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 2012 compared with 2011 and 2011 compared with 2010, the results of WPD Midlands are isolated for purposes of comparability. WPD Midlands' results are included within "Segment Results - U.K. Regulated Segment (formerly the International Regulated Segment, renamed in 2012)." 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 2012 and 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, 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.
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 Shareowners includes the following results:
(a)
Represents the results of operations for the two-month period from November 1, 2010 through December 31, 2010.
(b)
Includes allocated interest expense of $68 million in 2012, $70 million in 2011 and $31 million in 2010 related to the 2010 Equity Units and interest rate swaps.
The changes in the components of the Kentucky Regulated segment's results between 2012 and 2011 were due to the following factors, which reflect reclassifications for items included in Kentucky Gross Margins and certain items that management considers special. See additional detail of these special items in the table below. The 2011 and 2010 comparison has not been included as the periods are not comparable (2010 includes two months of activity as LKE was acquired on November 1, 2010).
·
See "Statement of Income Analysis - Margins - Changes in Non-GAAP Financial Measures" for an explanation of Kentucky Gross Margins.
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Higher other operation and maintenance in 2012 compared with 2011 primarily due to $11 million of expenses related to an increased scope of scheduled outages and a $6 million credit to establish a regulatory asset recorded when approved in 2011 related to 2009 storm costs.
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Higher depreciation in 2012 compared with 2011 due to PP&E additions.
·
Lower other income (expense) - net in 2012 compared with 2011 primarily due to losses from the EEI investment.
·
Lower income taxes in 2012 compared with 2011 primarily due to lower pre-tax income.
The following after-tax gains (losses), which management considers special items, also impacted the Kentucky Regulated segment's results.
(a)
KU recorded an impairment of its equity method investment in EEI. See Note 18 to the Financial Statements for additional information.
(b)
2012 includes an adjustment to an indemnification liability.
2013 Outlook
Excluding special items, PPL projects higher segment earnings in 2013 compared with 2012, primarily driven by electric and gas base rate increases effective January 1, 2013, returns on additional environmental capital investments and retail load growth, partially offset by higher operation and maintenance.
Earnings in future periods 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.
U.K. Regulated Segment
The U.K. Regulated segment consists primarily of the regulated electric distribution operations in the U.K. As a result of the WPD Midlands acquisition on April 1, 2011, the U.K. 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 Shareowners includes the following results (includes PPL WW and WPD Midlands on a consolidated basis, except for 2012 and 2011 acquisition-related adjustments, which are shown separately):
(a)
Includes $1,423 million in 2012 and $790 million in 2011 for WPD Midlands.
(b)
Includes allocated interest expense of $47 million and $38 million for 2012 and 2011 related primarily to the 2011 Equity Units.
(c)
Includes $570 million in 2012 and $137 million in 2011 for WPD Midlands, net of acquisition-related adjustments.
The changes in the components of the U.K. Regulated segment's results between these periods were due to the following factors, which reflect reclassifications for certain items that management considers special and with WPD Midlands isolated for comparability purposes. See additional detail of special items in the table below. The amounts for PPL WW and WPD Midlands 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
·
The increase in utility revenues in 2012 compared with 2011 was due to the impact of the April 2012 and 2011 price increases which resulted in $78 million of higher utility revenues, partially offset by $13 million of lower volumes due primarily to a downturn in the economy and weather.
The increase in utility revenues in 2011 compared with 2010 was due to the impact of the April 2011 and 2010 price increases that resulted in $76 million of additional revenue.
·
The increases in other operation and maintenance in 2012 compared with 2011 and 2011 compared with 2010 were due to higher pension expense resulting from an increase in amortization of actuarial losses.
·
The decrease in interest expense in 2012 compared with 2011 was due to lower interest expense on index-linked notes.
The increase in interest expense in 2011 compared with 2010 was due to $11 million of higher interest expense arising from a March 2010 debt issuance.
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The increase in depreciation expense in 2012 compared with 2011 was due to $10 million of depreciation related to PP&E additions.
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The decrease in income taxes in 2012 compared with 2011 was due to the tax deductibility of interest on acquisition financing of $12 million and $9 million from a benefit relating to customer contributions for capital expenditures.
The increase in income taxes in 2011 compared with 2010 was 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 2011 pre-tax income.
WPD Midlands
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Earnings in 2012 compared with 2011 were affected by an additional four months of results in 2012 totaling $171 million, after-tax.
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The comparable eight month period was affected by higher utility revenue of $125 million resulting from the April 1, 2012 price increase and $26 million of lower pension expense, partially offset by $26 million of higher taxes due to higher pre-tax income, $25 million of additional interest expense on debt issuances in 2011 and 2012 and $25 million of higher taxes due to a U.K./U.S. intercompany tax transaction.
U.S.
·
The increase in interest expense and other in 2012 compared with 2011 was due to $9 million of higher interest expense primarily associated with the 2011 Equity Units issued to finance the WPD Midlands acquisition.
The increase in interest expense and other in 2011 compared with 2010 was due to $38 million of higher interest expense primarily associated with the 2011 Equity Units issued to finance the WPD Midlands acquisition.
·
The increase in income taxes in 2012 compared with 2011 was due to $28 million of tax benefits recorded in 2011 as a result of U.K. pension plan contributions and a $20 million adjustment primarily related to the recalculation of 2010 U.K. earnings and profits, partially offset by $25 million from the U.K./U.S. intercompany tax transaction.
The decrease in income taxes in 2011 compared with 2010 was 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 2011 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.
Foreign Currency Exchange Rates
·
Changes in foreign currency exchange rates negatively affected the segment's earnings for 2012 compared with 2011 and positively affected 2011 compared with 2010. The weighted-average exchange rates for the British pound sterling, including the effects of currency hedges, were approximately $1.58 in 2012, $1.61 in 2011, and $1.57 in 2010.
The following after-tax gains (losses), which management considers special items, also impacted the U.K. 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.
(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)
2012 represents severance compensation and early retirement deficiency costs. 2011 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). 2011 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)
2011 primarily includes $34 million, pre-tax, of advisory, accounting and legal fees which are recorded in "Other Income (Expense) - net" on the Statement of Income; $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 Statement 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 Statement of Income.
(h)
The U.K. Finance Act of 2012, enacted in July 2012, reduced the U.K. statutory income tax rate from 25% to 24% retroactive to April 1, 2012 and from 24% to 23% effective April 1, 2013. The U.K. 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 reduced the rate from 26% to 25% effective April 1, 2012. The U.K. 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 deferred tax benefits in 2012, 2011 and 2010. WPD Midlands' portion of the deferred tax benefit was $43 million and $35 million for 2012 and 2011.
(i)
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 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 WPT is not a creditable tax. As a result of the Third Circuit's adverse determination, PPL recorded a $39 million expense in 2011. See Note 5 to the Financial Statements for information on 2012 activities related to this case, including the U.S. Supreme Court's decision to grant PPL's petition for a writ of certiorari to review the Third Circuit's opinion.
(j)
In November 2012, Ofgem issued additional consultation on the final DPCR4 line loss close-out that published values for each DNO and further indicated the preferred methodology that would replace the methodology under WPD's licenses. Based on applying the preferred methodology for DPCR4, WPD Midlands reduced its line loss liability by $86 million, pre-tax. Ofgem also indicated that the line loss incentive implemented at the last rate review will be withdrawn and no incentive will apply for the DPCR5 period. As a result, WPD Midlands reduced their line loss accrual by $11 million, pre-tax. This represents WPD Midlands' portion of the adjustment as the original liability was primarily established through purchase accounting.
2013 Outlook
Excluding special items, PPL projects higher segment earnings in 2013 compared with 2012, primarily driven by higher electricity delivery revenue and lower income taxes, partially offset by higher operation and maintenance, higher depreciation and higher interest expense.
Earnings in future periods 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 Shareowners 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, which reflect reclassifications for items included in Pennsylvania Gross Delivery Margins.
·
See "Statement of Income Analysis - Margins - Changes in Non-GAAP Financial Measures" for an explanation of Pennsylvania Gross Delivery Margins.
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Higher other operation and maintenance for 2012 compared with 2011, primarily due to $17 million in higher payroll-related costs due to less project costs being capitalized in 2012, higher support group costs of $11 million and $10 million for increased vegetation management.
·
Higher depreciation for 2012 compared with 2011 and 2011 compared with 2010 primarily due to PP&E additions.
·
Higher taxes, other than income for 2012 primarily due to a $10 million tax provision related to gross receipts tax.
·
Income taxes were flat in 2012 compared with 2011 primarily due to the $22 million impact of lower 2012 pre-tax income primarily offset by $9 million of depreciation not normalized and $9 million of income tax return adjustments, largely related to changes in flow-through regulated tax depreciation.
Income taxes were higher in 2011 compared with 2010, due to the $26 million impact of higher 2011 pre-tax income, partially offset by a $14 million tax benefit related to changes in flow-through regulated tax depreciation.
·
Lower noncontrolling interests in 2012 compared with 2011 due to PPL Electric's redemption of preference securities in June 2012.
2013 Outlook
PPL projects higher segment earnings in 2013 compared with 2012, due to higher distribution revenues from a distribution base rate increase effective January 1, 2013, and higher transmission margins, partially offset by higher depreciation.
Earnings in future periods 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 and 2010, 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 Shareowners 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, which reflect reclassifications for items included in Unregulated Gross Energy Margins and 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.
·
Higher other operation and maintenance in 2012 compared with 2011 due to higher costs at PPL Susquehanna of $27 million including refueling outage costs, payroll-related costs and project costs, $18 million due to the Ironwood Acquisition, $13 million due to eastern fossil and hydroelectric unit outages, $11 million of higher pension expense and $10 million of higher charges from support groups.
Higher other operation and maintenance 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-related costs, $23 million higher costs at eastern fossil and hydroelectric units largely due to outages, and $12 million higher net costs at western fossil and hydroelectric units, largely resulting from insurance recoveries received in 2010.
·
Higher depreciation in 2012 compared with 2011 primarily due to a $24 million impact from PP&E additions and $17 million due to the Ironwood Acquisition.
·
Lower taxes other than income in 2012 compared with 2011 primarily due to lower capital stock tax.
Higher taxes other than income in 2011 compared with 2010 primarily due to higher capital stock tax.
·
Lower other income (expense) - net in 2012 compared with 2011 and higher other income (expense) - net in 2011 compared with 2010 primarily due to a $22 million gain on the July 2011 redemption of Senior Secured Bonds.
·
Higher interest expense in 2012 compared with 2011 primarily due to hedging activity, which increased interest expense by $30 million and $12 million related to the debt assumed as a result of the Ironwood Acquisition, partially offset by $11 million of lower interest on short-term borrowings and $4 million of higher capitalized interest.
Higher interest expense in 2011 compared with 2010 of $13 million primarily due to hedging activity and $8 million due to short-term borrowings, partially offset by $15 million of higher capitalized interest.
·
Lower income taxes in 2012 compared with 2011 due to lower 2012 pre-tax income, which reduced income taxes by $151 million and $23 million related to lower adjustments to valuation allowances on Pennsylvania net operating losses, partially offset by $21 million related to the impact of prior period tax return adjustments.
Lower income taxes in 2011 compared with 2010 due to lower 2011 pre-tax income, which reduced taxes by $204 million and a $26 million reduction in deferred tax liabilities related to an updated blended state tax rate resulting from a change in state tax apportionment. These decreases were partially offset by $101 million related to adjustments to valuation allowances on Pennsylvania net operating losses, $16 million in favorable adjustments to uncertain tax benefits recorded in 2010 and an $11 million decrease in the domestic manufacturing deduction resulting from revised bonus depreciation estimates.
The following after-tax gains (losses), which management considers special items, also impacted the Supply segment's results.
(a)
See "Reconciliation of Economic Activity" below.
(b)
Gains recorded on the completion of the sale of the Maine hydroelectric generation business. See Note 9 to the Financial Statements for additional information.
(c)
Primarily represents impairment charges of sulfur dioxide emission allowances.
(d)
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 Statement of Income.
(e)
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.
(f)
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.
(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 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 Statement 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. See Note 15 to the Financial Statements for additional information.
(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)
In October 2011, a wholesale customer, SMGT, filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy code. In 2012, PPL EnergyPlus recorded an additional allowance for unpaid amounts under the long-term power contract. In March 2012, the U.S. Bankruptcy Court for the District of Montana approved the request to terminate the contract, effective April 1, 2012.
(l)
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.
(m)
As a result of lower electricity and natural gas prices, coal-fired generation output decreased during 2012. Contract modification payments were incurred to reduce 2012 and 2013 contracted coal deliveries.
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.
2013 Outlook
Excluding special items, PPL projects lower segment earnings in 2013 compared with 2012, primarily driven by lower energy prices, higher fuel costs, higher operation and maintenance, higher depreciation and higher financing costs, which are partially offset by higher capacity prices and higher nuclear generation output despite scheduled outages for both Susquehanna units to implement a long-term solution to turbine blade issues.
Earnings in future periods 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, fuel and energy purchases are deducted from revenues. In addition, utility revenues and expenses associated with approved cost recovery mechanisms are offset. These mechanisms allow for recovery of certain expenses, returns on capital investments primarily associated with environmental regulations and performance incentives. Certain costs associated with these mechanisms, primarily ECR and DSM, are recorded as "Other operation and maintenance" and "Depreciation." 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," which is primarily Act 129 costs, and "Taxes, other than income," which is primarily gross receipts tax. 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 fluctuations 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 "PLR intersegment utility revenue (expense)" in the table below. PPL excludes from "Unregulated Gross Energy Margins" the Supply segment's adjusted 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 adjusted 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 Statements 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 2012, "Wholesale energy marketing - Realized" and "Energy purchases - Realized" include a net pre-tax loss of $35 million related to the monetization of certain full-requirement sales contracts. 2011 includes a net pre-tax loss of $216 million related to the monetization of certain full-requirement sales contracts and a net pre-tax gain of $19 million related to the amortization of option premiums. 2010 includes a net pre-tax gain of $37 million related to the monetization of certain full-requirement sales contracts and a net pre-tax gain of $32 million related to the amortization of option premiums.
(g)
Represents energy-related economic activity, which is subject to fluctuations 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 as described in "Commodity Price Risk (Non-trading) - Economic Activity" within Note 19 to the Financial Statements. 2012 includes a net pre-tax loss of $29 million related to coal contract modification payments. 2011 includes pre-tax 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
Margins decreased in 2012 compared with 2011, primarily due to $6 million of lower wholesale margins, resulting from lower market prices. Retail margins were $2 million lower, as volumes were impacted by unseasonably mild weather during the first four months of 2012. Total heating degree days decreased 11% compared to 2011, partially offset by a 6% increase in cooling degree days.
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
Margins decreased in 2012 compared with 2011, primarily due to a $14 million unfavorable effect of mild weather early in 2012 and lower revenue applicable to certain energy-related costs of $3 million due to fewer PLR customers in 2012, partially offset by a $7 million charge recorded in 2011 to reduce a portion of the transmission service charge regulatory asset associated with a 2005 undercollection that was not included in any subsequent rate reconciliations filed with the PUC.
Margins increased in 2011 compared with 2010, largely due to the PPL Electric distribution rate case which increased rates by approximately 1.6% effective January 1, 2011, resulting in improved residential distribution margins of $68 million. Additionally, residential volume variances increased margins by an additional $4 million in 2011, compared with 2010, offset by unfavorable weather of $3 million for residential customers in 2011 compared with 2010. 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.
Transmission
Margins increased in 2012 compared with 2011, primarily due to increased investment in plant and the recovery of additional costs through the FERC formula-based rates.
(a)
Higher margins in 2011 compared with 2010 were driven by the monetization of loss contracts in 2010 and lower customer migration to alternative suppliers in 2011.
(b)
Volumes were lower in 2011 compared with 2010 as a result of unplanned outages and the sale of our interest in Safe Harbor Water Power Corporation.
(c)
Volumes were flat in 2012 compared to 2011 due to an uprate in the third quarter of 2011 offset by higher plant outage costs in 2012. Volumes were lower in 2011 compared with 2010 primarily as a result of the dual-unit turbine blade replacement outages beginning in May 2011.
(d)
See Note 10 to the Financial Statements for additional information.
Western U.S.
Non-trading margins were lower in 2012 compared with 2011 due to $34 million of lower wholesale volumes, including $31 million related to the bankruptcy of SMGT, $9 million of higher average fuel prices and $9 million of lower wholesale prices.
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 the coal unit output.
(a)
See "Pennsylvania Gross Delivery Margins" for further information.
(b)
See "Kentucky Gross Margins" for further information.
(c)
The increase in 2012 compared with 2011 was due to price increases effective April 1, 2012 and April 1, 2011. The increase in 2011 compared with 2010 was due to price increases effective April 1, 2011 and April 1, 2010.
(d)
The decreases in both periods were primarily due to the downturn in the economy and the unfavorable effect of weather.
(e)
The decrease in 2012 compared with 2011 was primarily due to a 2012 charge to income for the over-recovery of revenues from customers. The increase in 2011 compared with 2010 was primarily due to a revised estimate of network electricity line losses.
(f)
Amounts in each period were not comparable as 2011 includes eight months of WPD Midlands' results. The increase in 2012 compared with 2011 was primarily due to four additional months of utility revenue in 2012 of $446 million. The comparable eight month period was $125 million higher in 2012 compared to 2011 due to a price increase effective April 1, 2012.
(a)
2011 compared with 2010 is not comparable as 2010 includes two months of LKE's results.
(b)
2012 compared with 2011 was higher primarily due to $11 million of expense related to an increased scope of scheduled outages.
(c)
Relates to costs associated with PPL Electric's PUC-approved energy efficiency and conservation plan. These costs are recovered in customer rates. There were initially 15 Act 129 programs which began in 2010 and continued to ramp up in 2011. Some of the energy efficiency programs were reduced or closed in 2012 resulting in lower operation and maintenance expense.
(d)
PPL Electric incurred more expense in 2010 and 2012 compared to 2011 due to increased vegetation management activities related to transmission lines to comply with federal reliability requirements as well as increased vegetation management for the distribution system in 2012 in an effort to maintain and increase system reliability.
(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 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 decision. As a result in 2011, 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.
(f)
2012 compared with 2011 was higher primarily due to $11 million of higher payroll-related costs, $7 million of higher project costs and $7 million of higher costs from the refueling outage. 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.
(g)
2011 compared with 2010 was higher primarily due to $11 million of lower insurance proceeds.
(h)
2012 compared with 2011 was higher primarily due to plant outage costs of $13 million. 2011 compared with 2010 was higher primarily due to plant outage costs of $13 million.
(i)
There are no comparable amounts in 2011 as the Ironwood Acquisition occurred in April 2012.
(j)
2012 compared with 2011 was higher primarily due to higher payroll costs of $17 million in 2012 for PPL Electric due to less project costs being capitalized.
(k)
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.
(l)
Both periods were higher due to higher pension costs resulting from increased amortization of actuarial losses.
(m)
Amounts in each period were not comparable as 2011 includes eight months of WPD Midlands' results. The increase in 2012 compared with 2011 was partially due to four additional months of expense in 2012 of $86 million. The comparable eight month period was $171 million lower in 2012 compared to 2011 due to $86 million of lower 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), $34 million of lower other acquisition related costs, and $26 million of lower pension expense.
Depreciation
The increase (decrease) in depreciation was due to:
(a)
For 2011 compared with 2010, includes $32 million of depreciation expense related to TC2, which began to dispatch in January 2011.
(b)
2011 compared with 2010 is not comparable as 2010 includes two months of LKE's results.
(c)
Amounts in each period were not comparable as 2011 includes eight months of WPD Midlands' results. The increase in 2012 compared with 2011 is primarily due to four additional months of expense in 2012 of $49 million.
Taxes, Other Than Income
The increase (decrease) in taxes, other than income was due to:
(a)
The decrease in 2012 compared with 2011 was primarily due to a decrease in taxable electricity revenue. The decrease in 2011 compared with 2010 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 increase in 2012 compared with 2011 is primarily due to the fully amortized PURTA refund that was refunded to the customers in 2011 pursuant to PUC regulations. 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 decrease in 2012 compared to 2011 was due to changes in the statutory rate from the prior year. 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)
2011 compared with 2010 was not comparable as 2010 includes two months of LKE's results.
(e)
Amounts in each period were not comparable as 2011 includes eight months of WPD Midlands' results. The increase in 2012 compared with 2011 is primarily due to four additional months of expense in 2012 of $30 million.
(a)
Represents a gain on foreign currency contracts in 2011 that hedged the repayment of the 2011 Bridge Facility borrowing.
(b)
Represents a foreign currency loss in 2011 related to the repayment of the 2011 Bridge Facility borrowing.
(c)
In July 2011, as a result of PPL Electric's 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 in 2010 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.
Other-Than-Temporary Impairments
Primarily due to a $25 million pre-tax impairment of the EEI investment, other-than-temporary impairments increased by $21 million in 2012 compared with 2011. See Notes 1 and 18 to the Financial Statements for additional information.
Interest Expense
The increase (decrease) in interest expense was due to:
(a)
Interest related to the issuance in June 2010 to support the LKE acquisition.
(b)
Interest related to the issuance in April 2011 to support the WPD Midlands acquisition.
(c)
2012 compared with 2011 was lower primarily due to lower interest rates on 2012 short-term borrowings coupled with lower fees on credit facilities. 2011 compared with 2010 was higher primarily due to increased borrowings in 2011 and an increase in commitment fees on credit facilities.
(d)
2011 compared with 2010 is not comparable as 2010 includes two months of LKE's results.
(e)
Amounts in each period are not comparable as 2011 includes eight months of WPD Midlands' results. The increase in 2012 compared with 2011 is primarily due to four additional months of expense in 2012 of $74 million.
(f)
Includes AFUDC.
(g)
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 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 2011 and 2010, PPL Montana, recorded $4 million and $10 million of 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, in the fourth quarter of 2011 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 increase (decrease) in income taxes was due to:
(a)
During 2011, the Pennsylvania Department of Revenue issued interpretive guidance on the treatment of bonus depreciation for Pennsylvania income tax purposes. The guidance 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 projected 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. The federal provision for 100% bonus depreciation generally applies to property placed into service before January 1, 2012. The placed in-service deadline is extended to January 1, 2013 for property that has a cost in excess of $1 million, has a production period longer than one year and has a tax life of at least ten years. PPL's tax deduction for 100% bonus regulated tax depreciation was significantly lower in 2012 than in 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 in 2010, PPL recorded a $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 during 2010.
(b)
Changes in state apportionment resulted in reductions to the future estimated state tax rate at December 31, 2012 and 2011. PPL recorded a $19 million deferred tax benefit in 2012 and a $26 million deferred tax benefit in 2011 related to its 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 tax benefit related to the domestic manufacturing deduction in 2012 and 2011.
(d)
In 1997, the U.K. imposed a Windfall Profits Tax (WPT) on privatized utilities, including WPD. PPL filed its federal income 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, 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. In February 2012, PPL filed a petition for rehearing of the Third Circuit's opinion. In March 2012, the Third Circuit denied PPL's petition. In June 2012, the U.S. Court of Appeals for the Fifth Circuit issued a contrary opinion in an identical case involving another company. In July 2012, PPL filed a petition for a writ of certiorari seeking U.S. Supreme Court review of the Third Circuit's opinion. The Supreme Court granted PPL's petition on October 29, 2012, and oral argument was held on February 20, 2013. PPL expects the case to be decided before the end of the Supreme Court's current term in June 2013 and cannot predict the outcome of this matter.
In 2010, the 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.
(e)
During 2012, PPL recorded $16 million in federal and state income tax expense related to the filing of the 2011 federal and state income tax returns. Of this amount, $5 million relates to the reversal of prior years' state income tax benefits related to regulated depreciation. PPL changed its method of accounting for repair expenditures for tax purposes effective for its 2008 tax year. In August 2011, the IRS issued guidance regarding the use and evaluation of statistical samples and sampling estimates for network assets. The IRS guidance provided a safe harbor method of determining whether the repair expenditures for electric transmission and distribution property can be currently deducted for tax purposes. PPL adopted the safe harbor method with the filing of its 2011 federal income tax return.
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 related to an additional domestic manufacturing deduction resulting from revised bonus depreciation amounts and $3 million in tax benefits related to the flow-through impact of Pennsylvania regulated state tax depreciation.
(f)
During 2012, PPL recorded a $23 million adjustment to federal income tax expense related to the recalculation of 2010 U.K. earnings and profits.
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 primarily resulting from increased taxable dividends.
(g)
The U.K.'s Finance Act of 2012, enacted in July 2012, reduced the U.K. statutory income tax rate from 25% to 24% retroactive to April 1, 2012 and from 24% to 23% effective April 1, 2013. As a result, PPL reduced its net deferred tax liabilities and recognized a $75 million deferred tax benefit in 2012 related to both rate decreases. WPD Midlands' portion of the deferred tax benefit is $43 million.
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 from 26% to 25% effective April 1, 2012. As a result, PPL reduced its net deferred tax liabilities and recognized a $69 million deferred tax benefit in 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, PPL reduced its net deferred tax liabilities and recognized an $18 million deferred tax benefit in 2010.
(h)
During 2012, PPL recorded a $5 million tax benefit following resolution of a U.K. tax issue related to interest expense.
During 2011, WPD reached an agreement with the HMRC 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 utilized.
(i)
2011 compared with 2010 was not comparable as 2010 includes two months of LKE's results.
(j)
Amounts in each period were not comparable as 2011 includes eight months of WPD Midlands' results. The increase in 2012 compared with 2011 was primarily due to higher pre-tax book income.
(k)
During 2012, PPL recorded adjustments to deferred taxes related to net operating loss carryforwards of LKE based on income tax return adjustments.
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 $8 million in 2012 compared with 2011 primarily due to an adjustment recorded in 2012 to a liability for indemnifications related to the termination of the WKE lease in 2009.
Income (Loss) from Discontinued Operations (net of income taxes) increased by $19 million in 2011 compared with 2010 primarily due to 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.
Noncontrolling Interests
"Net Income Attributable to Noncontrolling Interests" decreased by $12 million in 2012 compared with 2011. The decrease is primarily due to PPL Electric's June 2012 redemption of all 2.5 million shares of its preference stock.
Financial Condition
Liquidity and Capital Resources
PPL expects to continue to have adequate liquidity available through operating cash flows, cash and cash equivalents, credit facilities and commercial paper issuances. Additionally, subject to market conditions, PPL currently plans to access capital markets in 2013.
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 that could affect 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 23 to the Financial Statements for further discussion.
At December 31, 2012, $225 million of cash and cash equivalents 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 limited to 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 for the years ended December 31 resulted from:
Operating Activities
Net cash provided by operating activities increased by 10%, or $257 million, in 2012 compared with 2011. The increase was the net effect of:
·
an increase of $339 million in net income, when adjusted for non-cash components; and
·
a decrease of $60 million in defined benefit plan funding; partially offset by
·
changes in working capital of $178 million, primarily driven by changes in prepayments and net regulatory assets/liabilities offset by the changes in counterparty collateral.
Included in the above amounts is the impact of having an additional four months of WPD Midlands operations in 2012. WPD Midlands' cash from operating activities increased by $190 million in 2012 compared with 2011.
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).
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, 2012 positions, it would have been required to post additional collateral of approximately $438 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 2012 was for capital expenditures. In 2011, the primary uses of cash in investing activities were for the acquisition of WPD Midlands and capital expenditures. In 2010, the primary uses of cash in investing activities were for the acquisition of LKE and capital expenditures. See "Forecasted Uses of Cash" for detail regarding projected capital expenditures for the years 2013 through 2017.
Net cash used in investing activities was $3.1 billion in 2012 compared with $7.9 billion in 2011. Excluding the impact of cash used for the 2011 acquisition of WPD Midlands, net cash used in investing activities increased by $934 million in 2012 compared with 2011. This increase reflects $618 million of higher capital expenditures, $381 million less in asset sale proceeds (2011 sale of certain non-core generation facilities) and a $143 million reduction in proceeds from the sale of certain investments (other than securities in the nuclear plant decommissioning trust funds) partially offset by a $239 million net change in restricted cash and cash equivalents. See Note 9 to the Financial Statements for additional information on the sale of certain non-core generation facilities and Note 10 to the Financial Statements for additional information regarding the WPD Midlands acquisition.
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.
Financing Activities
Net cash provided by financing activities was $48 million in 2012 compared with $5.8 billion in 2011. The decrease of $5.7 billion was primarily the result of lower net long-term debt issuances of $3.4 billion and less proceeds from the issuance of common stock of $2.2 billion. Both of these decreases were primarily related to the 2011 acquisition of WPD Midlands. The decrease also included $250 million paid to redeem a subsidiary's preference stock and $87 million of higher common stock dividends. These decreases were partially offset by a $199 million net change in short-term debt.
Net cash provided by financing activities was $5.8 billion in 2011 compared with $6.3 billion in 2010, primarily as a result of issuance of long-term debt and equity related to the acquisition of WPD Midlands in 2011 and the acquisition of LKE in 2010. The decrease of $540 million was primarily the result of lower net long-term debt issuances of $87 million, lower proceeds from the issuance of common stock of $144 million, $180 million of higher common stock dividends and a $195 million decrease in net, short-term debt.
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 securities in the future, as well as maturities of long-term debt.
Long-term Debt and Equity Securities
The long-term debt and equity securities activity for the year ended December 31, 2012 was:
(a)
Issuances are net of pricing discounts, where applicable and exclude the impact of debt issuance costs.
(b)
Senior unsecured notes of $99 million were redeemed at par prior to their 2047 maturity date.
(c)
In June 2012, PPL Electric redeemed all 2.5 million shares of its 6.25% Series Preference Stock, par value $100 per share, which was included in "Noncontrolling Interests" on the 2011 Balance Sheet.
(d)
Includes $24 million of fair value adjustments resulting from the purchase price allocation. See Note 10 to the Financial Statements for additional information on the acquisition.
(e)
In June 2012, LKE completed an exchange of all its outstanding 4.375% Senior Notes due 2021 issued in September 2011 in a transaction not registered under the Securities Act of 1933, for similar securities that were issued in a transaction registered with the SEC.
In addition to the above, in April 2012, PPL made a registered underwritten public offering of 9.9 million shares of its common stock. In conjunction with that offering, the underwriters exercised an option to purchase 591 thousand additional shares of PPL common stock solely to cover over-allotments.
In connection with the registered public offering, PPL entered into forward sale agreements with two counterparties covering the 9.9 million shares of PPL common stock. Settlement of these initial forward sale agreements will occur no later than April 2013. As a result of the underwriters' exercise of the overallotment option, PPL entered into additional forward sale agreements covering the additional 591 thousand shares of PPL common stock. Settlement of the subsequent forward sale agreements will occur no later than July 2013. Upon any physical settlement of any forward sale agreement, PPL will issue and deliver to the forward counterparties shares of its common stock in exchange for cash proceeds per share equal to the forward sale price. The forward sale price will be calculated based on an initial forward price of $27.02 per share reduced during the period the contracts are outstanding as specified in the forward sale agreements. PPL may, in certain circumstances, elect cash settlement or net share settlement for all or a portion of its rights or obligations under the forward sale agreements.
PPL will not receive any proceeds or issue any shares of common stock until settlement of the forward sale agreements. PPL intends to use any net proceeds that it receives upon settlement to repay short-term debt obligations and for other general corporate purposes.
The forward sale agreements are classified as equity transactions. As a result, no amounts will be recorded in the consolidated financial statements until the settlement of the forward sale agreements. Prior to those settlements, the only impact to the financial statements will be the inclusion of incremental shares within the calculation of diluted EPS using the treasury stock method.
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 liquidity available in the near term, including cash flows from operations, various credit facilities, commercial paper issuances and operating leases. Additionally, subject to market conditions, PPL currently plans to access capital markets in 2013.
Credit Facilities
At December 31, 2012, PPL's total committed borrowing capacity under credit facilities and the use of this borrowing capacity were:
(a)
The syndicated credit facilities, as well as KU's letter of credit facility, each contain a financial covenant requiring debt to total capitalization not to exceed 65% for PPL Energy Supply and 70% for PPL Electric, LG&E and KU, as calculated in accordance with the facility, and other customary covenants. See Note 7 to the Financial Statements for additional information regarding these credit facilities.
(b)
Includes a $100 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 $100 million from a commercial paper conduit sponsored by a financial institution. At December 31, 2012, based on accounts receivable and unbilled revenue pledged, the amount available for borrowing under the facility was $100 million.
(c)
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.
(d)
In December 2012, the PPL WW credit facility was subsequently replaced with a credit facility expiring in December 2016 and the capacity was increased to £210 million.
(e)
The facilities contain financial covenants that require the company 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, calculated in accordance with the credit facility.
(f)
Each company pays customary fees under its respective syndicated credit facility, as does KU under its letter of credit facility, and borrowings generally bear interest at LIBOR-based rates plus an applicable margin.
(g)
Under the facilities, WPD (East Midlands) and WPD (West Midlands) each have the ability to request the lenders to issue up to £80 million of letters of credit in lieu of borrowing.
(h)
The total amount borrowed at December 31, 2012 was a USD-denominated borrowing of $171 million, which equated to £106 million at the time of borrowing and bore interest at 0.8452%. At December 31, 2012, the unused capacity of WPD's committed credit facilities was approximately $1.4 billion.
The commitments under WPD's credit facilities are provided by a diverse bank group with no one bank providing more than 16% 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, 2012, 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
PPL Energy Supply maintains a $750 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, 2012, PPL Energy Supply had $356 million of commercial paper outstanding at a weighted-average interest rate of 0.50%.
PPL Electric maintains a $300 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 currently supported by PPL Electric's Syndicated Credit Facility. PPL Electric had no commercial paper outstanding at December 31, 2012.
In February 2012, LG&E and KU each established a commercial paper program for up to $250 million to provide additional financing sources to fund its short-term liquidity needs, if and when necessary. Commercial paper issuances are supported by LG&E's and KU's Syndicated Credit Facilities. At December 31, 2012, LG&E and KU had $55 million and $70 million of commercial paper outstanding at a weighted average interest rate, for each, of 0.42%.
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. 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, approximately $2.0 billion of long-term indebtedness in 2013, the proceeds of which will be used to fund capital expenditures and for other general corporate purposes. In addition during 2013, two events will occur related to the components of the 2010 Equity Units. PPL will receive proceeds of $1.150 billion through the issuance of PPL common stock to settle the 2010 Purchase Contracts; and PPL Capital Funding expects to remarket the 4.625% Junior Subordinated Notes due 2018. See Note 7 to the Financial Statements for additional information.
In addition, PPL currently plans to issue new shares of common stock in 2013 in an aggregate amount up to $350 million under its forward contracts (see Note 7 to the Financial Statements for more information), 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 stock 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 2013 through 2017.
(a)
Construction expenditures include capitalized interest and AFUDC, which are expected to total approximately $160 million for the years 2013 through 2017.
(b)
Includes expenditures for certain intangible assets.
PPL's capital expenditure projections for the years 2013 through 2017 total approximately $18.5 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 793 MW of incremental capacity increases for both PPL Energy Supply and LKE, PPL Electric's asset optimization program to replace aging transmission and distribution assets and the PJM-approved regional transmission line expansion project. This table also includes LKE's environmental projects related to existing and proposed EPA compliance standards (actual costs may be significantly lower or higher depending on the final requirements; 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 2013 with 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, 2012, 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.
(e)
The amounts include WPD's contractual deficit pension funding requirements arising from actuarial valuations performed in March 2010 and June 2011. 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 2013 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, 2012, total unrecognized tax benefits of $92 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 2012, PPL's Board of Directors declared an increase to its quarterly dividend on its common stock to 36.0 cents per share (equivalent to $1.44 per share per annum). In February 2013, PPL's Board of Directors declared an increase to its quarterly dividend on its common stock to 36.75 cents per share (equivalent to $1.47 per share per annum). 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.
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 Actions
Moody's, S&P and Fitch periodically review the credit ratings on the debt 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. The credit ratings of PPL and its subsidiaries affect its liquidity, access to capital markets and cost of borrowing under its credit facilities.
The following table sets forth PPL's and its subsidiaries' security credit ratings as of December 31, 2012.
A downgrade in PPL's or its subsidiaries' credit ratings could result in higher borrowing costs and reduced access to capital markets. PPL and its subsidiaries have no credit rating triggers that would result in the reduction of access to capital markets or the acceleration of maturity dates of outstanding debt.
In addition to the credit ratings noted above, the rating agencies took the following actions related to PPL and its subsidiaries in 2012.
In January 2012, S&P affirmed its rating and revised its outlook, from positive to stable, for PPL Montana's Pass Through Certificates due 2020.
In February 2012, Fitch assigned ratings to the two newly established commercial paper programs for LG&E and KU.
In March 2012, Moody's affirmed the following ratings:
·
the long-term ratings of the First Mortgage Bonds for LG&E and KU;
·
the issuer ratings for LG&E and KU; and
·
the bank loan ratings for LG&E and KU.
Also in March 2012, Moody's and S&P each assigned short-term ratings to the two newly established commercial paper programs for LG&E and KU.
In March and May 2012, Moody's, S&P and Fitch affirmed the long-term ratings for LG&E's 2003 Series A and 2007 Series B pollution control bonds.
Following the announcement of the then-pending acquisition of AES Ironwood, L.L.C. in February 2012, the rating agencies took the following actions:
·
In March 2012, Moody's placed AES Ironwood, L.L.C.'s senior secured bonds under review for possible ratings upgrade.
·
In April 2012, S&P affirmed the rating of AES Ironwood, L.L.C.'s senior secured bonds.
In May 2012, Fitch downgraded its rating, from BBB to BBB- and revised its outlook, from negative to stable, for PPL Montana's Pass Through Certificates due 2020.
In June 2012, Fitch assigned a rating and outlook to PPL Capital Funding's $400 million of 4.20% Senior Notes.
In August 2012, Fitch assigned a rating and outlook to PPL Electric's $250 million First Mortgage Bonds.
In August 2012, S&P and Moody's assigned a rating to PPL Electric's $250 million First Mortgage Bonds.
In October 2012, Moody's, S&P and Fitch assigned a rating to PPL Capital Funding's $400 million of 3.50% Senior Notes.
In November 2012, Fitch affirmed the long-term issuer default rating and senior unsecured rating of PPL WW, WPD (South Wales) and WPD (South West).
In November 2012, S&P revised its outlook, from stable to negative, for PPL Montana's Pass Through Certificates due 2020.
In November 2012, Moody's and S&P affirmed the long-term ratings for LG&E's 2007 Series A pollution control bonds.
In December 2012, Fitch affirmed the issuer default ratings, individual security ratings and outlooks for PPL, PPL Capital Funding, PPL Electric, LKE, LG&E and KU.
In December 2012, Fitch affirmed the issuer default rating, individual security rating and revised the outlook, from stable to negative, for PPL Energy Supply.
In February 2013, Moody's upgraded its rating, from Ba1 to B2, and revised the outlook from under review to stable for PPL Ironwood.
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 are withdrawn by any of the rating agencies (Moody's, S&P, or Fitch) 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 (East Midlands), WPD (South West), WPD (South Wales) and WPD (West Midlands) operate and would be a trigger event in that company. These notes totaled £3.3 billion (approximately $5.3 billion) nominal value at December 31, 2012.
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 that require 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, 2012. At December 31, 2012, if PPL's and its subsidiaries' credit ratings had been below investment grade, PPL would have been required to prepay or post an additional $501 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 under normal market conditions 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, 2012 and 2011 was a net asset/(liability) of $346 million and $(63) million. See Note 19 to the Financial Statements for additional information.
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 range in maturity through 2019.
The following table sets forth the changes in the net fair value of non-trading commodity derivative contracts at December 31, 2012. 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.
The following table segregates the net fair value of non-trading commodity derivative contracts at December 31, 2012 based on the level of observability of the information used to determine the fair value.
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 (or their 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. In connection with its bankruptcy proceedings, a significant counterparty, SMGT, had been purchasing lower volumes of electricity than prescribed in the contract and effective April 1, 2012 the contract was terminated. PPL cannot predict the prices or other terms on which it will be able to market to third parties the power that SMGT will not purchase from PPL EnergyPlus due to the termination of this contract. See Note 15 to the Financial Statements for additional information.
Commodity Price Risk (Trading)
PPL's trading commodity derivative contracts range in maturity through 2017. The following table sets forth changes in the net fair value of trading commodity derivative contracts at December 31, 2012. 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.
The following table segregates the net fair value of trading commodity derivative contracts at December 31, 2012 based on the level of observability of the information used to determine the fair value.
VaR Models
A VaR model is utilized to measure commodity price risk in domestic 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. VaR is calculated using a Monte Carlo simulation technique based on a five-day holding period at a 95% confidence level. Given the company's disciplined hedging program, the non-trading VaR exposure is expected to be limited in the short-term. The VaR for portfolios using end-of-month results for the period was as follows.
The trading portfolio includes all proprietary trading positions, regardless of the delivery period. All positions not considered proprietary trading are considered non-trading. The non-trading portfolio includes the 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, 2012.
Interest Rate Risk
PPL and its subsidiaries issue 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, 2012 and 2011, 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, 2012 would increase the fair value of its debt portfolio by $611 million, compared with $635 million at December 31, 2011.
PPL had the following interest rate hedges outstanding at December 31.
(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 or as regulatory assets or liabilities, if recoverable through regulated rates. 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, 2012 mature through 2043.
(d)
PPL utilizes cross-currency swaps to hedge the interest payments and principal of WPD's U.S. dollar-denominated senior notes. 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. The positions outstanding at December 31, 2012 mature through 2028.
(e)
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, 2012 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 December 31:
(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. The positions outstanding at December 31, 2012 mature through 2013. Excludes the amount of an intercompany loan classified as a net investment hedge. See Note 19 to the Financial Statements for additional information.
(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, 2012 mature through 2015.
NDT Funds - Securities Price Risk
In connection with certain NRC requirements, PPL Susquehanna maintains trust funds to fund certain costs of decommissioning the PPL Susquehanna nuclear plant (Susquehanna). At December 31, 2012, 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 primarily 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, 2012, a hypothetical 10% increase in interest rates and a 10% decrease in equity prices would have resulted in an estimated $49 million reduction in the fair value of the trust assets, compared with $43 million at December 31, 2011. 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 in 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 all of its 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, 2012, most 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. A small portion of bidders were required to post collateral, which totaled less than $1 million, 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 2012, changes in this exchange rate resulted in a foreign currency translation gain of $99 million, which primarily reflected a $181 million increase to PP&E offset by an increase of $82 million to net liabilities. In 2011, changes in this exchange rate 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 this exchange rate 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. 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 from time to time evaluates opportunities for potential acquisitions, divestitures and development projects. Development projects are 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 2012, an indirect wholly owned subsidiary of PPL Energy Supply completed the Ironwood Acquisition. 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
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 by the relevant agencies. Costs may take the form of increased capital expenditures or operating and maintenance expenses, monetary fines, penalties or other restrictions. Many of these environmental law considerations are also applicable to the operations of key suppliers, or customers, such as coal producers and industrial power users, and may impact the cost for their products or their demand for PPL's services.
Physical effects associated with climate change could include the impact of changes in weather patterns, such as storm frequency and intensity, and the resultant potential damage to PPL's generation assets, electricity transmission and distribution systems, as well as impacts on customers. In addition, changed weather patterns could potentially reduce annual rainfall in areas where PPL has hydro generating facilities or where river water is used to cool its fossil and nuclear powered generators. PPL cannot currently predict whether its businesses will experience these potential climate change-related risks or estimate the potential cost of their related consequences.
The below provides a discussion of the more significant environmental matters.
Coal Combustion Residuals (CCRs)
In June 2010, the EPA proposed two approaches to regulating CCRs (as either hazardous or non-hazardous) under existing solid waste regulations. A final rulemaking is currently expected before the end of 2015. However, the timing of the final regulations could be accelerated by certain litigation that could require the EPA to issue its regulations sooner. Regulations could impact handling, disposal and/or beneficial use of CCRs. The economic impact could be material if CCRs are regulated as hazardous waste, and significant if regulated as non-hazardous, in accordance with the proposed rule.
Effluent Limitation Guidelines
The EPA is to issue guidelines for technology-based limits in discharge permits for scrubber wastewater and is expected to require dry ash handling. The EPA agreed, in recent settlement negotiations with environmentalists, to propose revisions to its effluent limitation guidelines (ELGs) by April 2013, with a final rule in late 2014. Limits could be so stringent that plants may consider extensive new or modified wastewater treatment facilities and possibly zero liquid discharge operations, the cost of which could be significant. Impacts should be better understood after the proposed rule is issued.
316(b) Cooling Water Intake Structure Rule
In April 2011, the EPA published a draft regulation under Section 316(b) of the Clean Water Act, which regulates cooling water intakes for power plants. The draft rule has two provisions: one requires installation of Best Technology Available (BTA) to reduce mortality of aquatic organisms that are pulled into the plant cooling water system (entrainment), and the second imposes standards for reduction of mortality of aquatic organisms trapped on water intake screens (impingement). A final rule is expected in June 2013. The proposed regulation would apply to nearly all PPL-owned steam electric plants in Pennsylvania, Kentucky, and Montana, potentially even including those equipped with closed-cycle cooling systems. PPL's compliance costs could be significant, especially if the final rule requires closed-cycle systems at plants that do not currently have them or conversions of once-through systems to closed-cycle.
GHG Regulations
In 2013, the EPA is expected to finalize limits on GHG emissions from new power plants and to begin working on a proposal for such emissions from existing power plants. The EPA's proposal on GHG emissions from new power plants would effectively preclude construction of any coal-fired plants and could even be difficult for new gas-fired plants to meet. With respect to existing power plants, the impact could be very significant, depending on the structure and stringency of the final rule. PPL, along with others in the industry, filed comments on the EPA's proposal related to GHG emissions from new plants. With respect to GHG limits for existing plants, PPL will advocate for reasonable, flexible requirements.
MATS
The EPA finalized MATS requiring fossil-fuel fired plants to reduce emissions of mercury and other hazardous air pollutants by April 16, 2015. The rule is being challenged by industry groups and states. The EPA has subsequently proposed changes to the rule with respect to new sources to address the concern that the rule effectively precludes new coal plants. PPL is generally well-positioned to comply with MATS, primarily due to recent investments in environmental controls and approved Environmental Cost Recovery (ECR) plans to install additional controls at some of our Kentucky plants. PPL is evaluating chemical additive systems for mercury control at Brunner Island, and modifications to existing controls at Colstrip for improved particulate matter reductions. In September 2012, PPL announced its intention to place its Corette plant in long-term reserve status beginning in April 2015 due to expected market conditions and costs to comply with MATS.
CSAPR and CAIR
In 2011, the EPA finalized its CSAPR regulating emissions of nitrous oxide and sulfur dioxide through new allowance trading programs which were to be implemented in two phases (2012 and 2014). Like its predecessor, the CAIR, CSAPR targeted sources in the eastern United States. In December 2011, the U.S. Court of Appeals for the District of Columbia Circuit (the Court) stayed implementation of CSAPR, leaving CAIR in place. Subsequently, in August 2012, the Court vacated and remanded CSAPR back to the EPA for further rulemaking, again leaving CAIR in place, pending further EPA action. PPL plants in Pennsylvania and Kentucky will continue to comply with CAIR through optimization of existing controls, balanced with emission allowance purchases. The Court's August decision leaves plants in CSAPR-affected states potentially exposed to more stringent emission reductions due to regional haze implementation (it was previously determined that CSAPR or CAIR participation satisfies regional haze requirements), and/or petitions to the EPA by downwind states under Section 126 of the Clean Air Act requesting the EPA to require plants that allegedly contribute to downwind non-attainment to take action to reduce emissions.
Regional Haze - Montana
The EPA signed its final Federal Implementation Plan (FIP) of the Regional Haze Rules for Montana in September 2012, with tighter emissions limits for Colstrip Units 1 & 2 based on the installation of new controls (no limits or additional controls were specified for Colstrip Units 3 & 4), and tighter emission limits for Corette (which are not based on additional controls). The cost of the potential additional controls for Colstrip Units 1 & 2, if required, could be significant. PPL expects to meet the tighter permit limits at Corette without any significant changes to operations, although other requirements have led to the planned suspension of operations at Corette beginning in April 2015 (see "MATS" discussion above).
See "Item 1. Business - Environmental Matters" and Note 15 to the Financial Statements for further 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). 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.
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.
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 benefit 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. The plan-specific cash flows are matched against the coupons and expected maturity values of individually selected bonds. This bond matching process begins with the full universe of Aa-rated non-callable (or callable with make-whole provisions) bonds, serving as the base from which those with the lowest and highest yields were eliminated to develop an appropriate subset of bonds. 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. At December 31, 2012, PPL decreased the discount rate for its U.S. pension plans from 5.06% to 4.22% and decreased the discount rate for its other postretirement benefit plans from 4.80% to 4.00%.
In selecting a discount rate for its U.K. defined benefit plans, PPL starts with a cash flow analysis of the expected benefit payment stream for its plans. These plan-specific cash flows were matched against a spot-rate yield curve to determine the assumed discount rate, which used an iBoxx British pounds sterling denominated corporate bond index as its base. An individual bond matching approach is not used for U.K. pension plans because the universe of bonds in the U.K. is not deep enough to adequately support such an approach. At December 31, 2012, the discount rate for the U.K. pension plans was decreased from 5.24% to 4.27% 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.
At December 31, 2012, PPL's expected return on plan assets decreased from 7.07% to 7.02% for its U.S. pension plans and increased from 5.93% to 5.97% 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 7.17% to 7.16% at December 31, 2012.
In selecting a rate of compensation increase, PPL considers past experience in light of movements in inflation rates. At December 31, 2012, PPL's rate of compensation increase decreased from 4.02% to 3.98% for its U.S. pension plans and 4.00% to 3.97% for its other postretirement benefit plans. For the U.K. plans, PPL's rate of compensation increase remained at 4.00% at December 31, 2012.
In selecting health care cost trend rates, PPL considers past performance and forecasts of health care costs. At December 31, 2012, PPL's health care cost trend rates were 8.00% for 2013, 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, 2012, the defined benefit plans were recorded as follows.
The following chart reflects the sensitivities in the December 31, 2012 Balance Sheet associated with a change in certain assumptions based on PPL's primary defined benefit plans.
(a)
Only impacts other postretirement benefits.
In 2012, PPL recognized net periodic defined benefit costs charged to operating expense of $166 million. This amount represents a $12 million increase from 2011, excluding $50 million of separation costs recorded in 2011. The increase was primarily attributable to increased amortization of losses and a non-qualified plan settlement charge recorded in 2012.
The following chart reflects the sensitivities in the 2012 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.
Asset Impairment (Excluding Investments)
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 amount 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 amount 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 amount 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.
In September 2012, PPL Energy Supply announced its intention, beginning in April 2015, to place the Corette coal-fired plant in Montana in long-term reserve status, suspending the plant's operation, due to expected market conditions and the costs to comply with MATS requirements. The Corette plant asset group's carrying amount at December 31, 2012 was approximately $68 million. An impairment analysis was performed for this asset group in the third and fourth quarters of 2012 and it was determined to not be impaired. It is reasonably possible that an impairment could occur in future periods, as higher priced sales contracts settle, adversely impacting projected cash flows.
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.
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 amount 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.
Beginning in 2012, PPL may elect either to initially make a qualitative evaluation about the likelihood of an impairment of goodwill or to bypass the qualitative evaluation and test goodwill for impairment using a two-step quantitative test. If the qualitative evaluation (referred to as "step zero") is elected and the assessment results in a determination that it is not more likely than not that the fair value of a reporting unit is less than the carrying amount, the two-step quantitative impairment test is not necessary. However, the quantitative impairment test is required if PPL concludes it is more likely than not the fair value of a reporting unit is less than the carrying amount based on the step zero assessment.
When the two-step quantitative impairment test is elected or required as a result of the step zero assessment, in step one, PPL identifies a potential impairment by comparing the estimated fair value of a reporting unit with its carrying amount, including goodwill, on the measurement date. If the estimated fair value of a reporting unit 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 of the quantitative test 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 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.
PPL elected to perform the two-step quantitative impairment test of goodwill for all of its reporting units in the fourth quarter of 2012 and no impairment was recognized. Management used both discounted cash flows and market multiples, which required significant assumptions, to estimate the fair value of the reporting units. For the U.K. Regulated reporting unit, management used only discounted cash flows to estimate the fair value of the reporting unit due to lack of industry comparable transactions. Applying an appropriate weighting to both the discounted cash flow and market multiple valuations (where applicable) 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.
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 2012.
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.
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 6 and 15 to the Financial Statements for disclosure of loss contingencies accrued and other potential loss contingencies that have not met the criteria for accrual. Note 6 to the Financial Statements includes a discussion of the Ofgem Review of Line Loss Calculation, including the $90 million reduction in the WPD liability.
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 statement of income, for changes in the obligation due to the passage of time.
In the case of LG&E and KU, since costs of removal are collected in rates, 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, 2012, AROs totaling $552 million were recorded on the Balance Sheet, of which $16 million is included in "Other current liabilities." Of the total amount, $316 million, or 57%, 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, 2012. 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.
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 derecognized, 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, 2012, it was reasonably possible that during the next 12 months the total amount of unrecognized tax benefits could increase by as much as $10 million or decrease by up to $90 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.
Regulatory Assets and Liabilities
PPL Electric, LG&E and KU, 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, 2012, PPL had regulatory assets of $1.5 billion and regulatory liabilities of $1.1 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.
See Note 6 to the Financial Statements for additional information on regulatory assets and liabilities.
WPD operates in an incentive-based regulatory structure under distribution licenses granted by Ofgem. WPD's electricity distribution revenues are set every five years through price controls that are not directly based on cost recovery; therefore, WPD is not subject to accounting for the effects of certain types of regulation as prescribed by GAAP and does not record regulatory assets and liabilities.
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 defined 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, a summary of Net Income Attributable to PPL Energy Supply Member and a discussion of certain events related to 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 explanations of significant changes in principal items on PPL Energy Supply's Statements of Income, comparing 2012 with 2011 and 2011 with 2010.
·
"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 forecasted sources and uses of cash and rating agency actions.
·
"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.
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 competitive generation and marketing portfolios. 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 strategy is to maintain a strong credit profile and strong 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 Member
Net Income Attributable to PPL Energy Supply Member for 2012, 2011 and 2010 was $474 million, $768 million and $861 million. Earnings in 2012 decreased 38% from 2011 and earnings in 2011 decreased 11% from 2010.
See "Results of Operations" below for further discussion and analysis of the consolidated results of operations.
Economic and Market Conditions
Unregulated Gross Energy Margins associated with PPL Energy Supply's competitive generation and marketing business are impacted by changes in market prices and demand for electricity and natural gas, power plant availability, competition in the markets for retail customers, fuel costs and availability, fuel transportation costs and other costs. Current depressed wholesale market prices for electricity and natural gas have resulted from general weak economic conditions and other factors, including the impact of expanded domestic shale gas development and production. As a result of these factors, PPL Energy Supply has experienced a shift in the dispatching of its competitive generation from coal-fired to combined-cycle gas-fired generation as illustrated in the following table:
(a)
All periods reflect the years ended December 31.
This reduction in coal-fired generation output had resulted in a surplus of coal inventory at certain of PPL Energy Supply's Pennsylvania coal plants. To mitigate the risk of exceeding available coal storage, PPL Energy Supply incurred pre-tax charges of $29 million in 2012 to reduce its 2012 and 2013 contracted coal deliveries. PPL Energy Supply will continue to manage its coal inventory to mitigate the financial impact and physical implications of an oversupply; however, no additional coal contract modifications are expected at this time.
In addition, current economic and commodity market conditions indicated a lower value of unhedged future energy margins (primarily in 2014 and forward years) compared to the energy margins in 2012. As has been PPL Energy Supply's practice in periods of changing business conditions, PPL Energy Supply continues to review its future business and operational plans, including capital and operation and maintenance expenditures, as well as its hedging strategies, to help counter the financial effects of low commodity prices.
PPL Energy Supply's businesses are subject to extensive federal, state and local environmental laws, rules and regulations. PPL Energy Supply's competitive generation assets are well positioned to meet these requirements. See Note 15 to the Financial Statements for additional information on these requirements. As a result of these requirements, PPL Energy Supply announced in September 2012 its intention, beginning in April 2015, to place its Corette plant in long-term reserve status, suspending the plant's operation due to expected market conditions and the costs to comply with MATS. The Corette plant asset group's carrying amount at December 31, 2012 was approximately $68 million. Although the Corette plant asset group was not determined to be impaired at December 31, 2012, it is reasonably possible that an impairment could occur in future periods, as higher priced sales contracts settle, adversely impacting projected cash flows.
In light of these economic and market conditions, as well as current and projected environmental regulatory requirements, PPL Energy Supply considered whether certain of its other generating assets were impaired, and determined that no impairment charges were required at December 31, 2012. PPL Energy Supply is unable to predict whether future environmental requirements or market conditions will result in impairment charges for other generating assets or other retirements.
PPL Energy Supply and its subsidiaries may also be impacted in future periods by the uncertainty in the worldwide financial and credit markets. In addition, PPL Energy Supply may be impacted by reductions in the credit ratings of financial institutions and evolving regulations in the financial sector. Collectively, these factors could reduce availability or restrict PPL Energy Supply and its subsidiaries' ability to maintain sufficient levels of liquidity, reduce capital market activities, change collateral posting requirements and increase the associated costs to PPL Energy Supply and its subsidiaries.
PPL Energy Supply cannot predict the future impact that these economic and market conditions and regulatory requirements may have on its financial condition or results of operations.
Susquehanna Turbine Blade Inspection
During 2012, PPL Energy Supply performed inspections of the Unit 1 and Unit 2 turbine blades at the PPL Susquehanna nuclear power plant to further address the issue of turbine blade cracking that was first identified in 2011. The after-tax earnings impact of these 2012 inspections, including reduced energy-sales margins and repair expenses, was approximately $53 million. The after-tax earnings impact of turbine blade related outages in 2011 was approximately $63 million.
Ironwood Acquisition
In April 2012, an indirect, wholly owned subsidiary of PPL Energy Supply completed the acquisition of the equity interests in the owner and operator of the Ironwood Facility. The Ironwood Facility began operation in 2001 and, since 2008, PPL EnergyPlus has supplied natural gas for the facility and received the facility's full electricity output and capacity value pursuant to a tolling agreement that expires in 2021. The acquisition provides PPL Energy Supply, through its subsidiaries, operational control of additional combined-cycle gas generation in PJM. See Note 10 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 for the District of Montana. At the time of the bankruptcy filing, SMGT was PPL EnergyPlus' largest unsecured credit exposure. This contract was accounted for as NPNS by PPL EnergyPlus.
The SMGT Contract provided for fixed volume purchases on a monthly basis at established prices. Pursuant to a court order and subsequent stipulations entered into between the SMGT bankruptcy trustee 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 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 March 2012, the U.S. Bankruptcy Court for the District of Montana issued an order approving the request of the SMGT bankruptcy trustee and PPL EnergyPlus to terminate the SMGT Contract. As a result, the SMGT Contract was terminated effective April 1, 2012, allowing PPL EnergyPlus to resell the electricity previously contracted to SMGT under the SMGT Contract to other customers.
PPL EnergyPlus' receivable under the SMGT Contract totaled approximately $21 million at December 31, 2012, which has been fully reserved.
In July 2012, PPL EnergyPlus filed its proof of claim in the SMGT bankruptcy proceeding. The total claim is approximately $375 million, including the above receivable, predominantly an unsecured claim representing the value for energy sales that will not occur as a result of the termination of the SMGT Contract. No assurance can be given as to the collectability of the claim, thus no amounts have been recorded in the 2012 financial statements.
PPL Energy Supply cannot predict any amounts that it may recover in connection with the SMGT bankruptcy or the prices and other terms on which it will be able to market to third parties the power that SMGT will not purchase from PPL EnergyPlus due to the termination of the SMGT Contract.
Results of Operations
The following discussion provides a summary of PPL Energy Supply's earnings and a description of factors that are expected to impact future earnings. This section ends with "Statement of Income Analysis," which includes explanations of significant year-to-year changes in Unregulated Gross Energy Margins by region and principal line items on PPL Energy Supply's Statements of Income.
The changes in the components of Net Income Attributable to PPL Energy Supply Member between these periods were due to the following factors, which reflect reclassifications for items included in the Unregulated Gross Energy Margins and 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 Unregulated Gross Energy Margins.
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Higher other operation and maintenance in 2012 compared with 2011 due to higher costs at PPL Susquehanna of $27 million including refueling outage costs, payroll-related costs and project costs, $18 million due to the Ironwood Acquisition, $13 million due to outages at eastern fossil and hydroelectric units and $10 million of charges from support groups partially offset by $34 million of trademark royalties with an affiliate in 2011 for which the agreement was terminated December 31, 2011.
Higher other operation and maintenance 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-related costs, higher costs at eastern fossil and hydroelectric units of $20 million, largely due to outages, and higher costs at western fossil and hydroelectric units of $15 million, largely resulting from insurance recoveries received in 2010.
·
Higher depreciation in 2012 compared with 2011 primarily due to a $16 million impact from PP&E additions and $17 million due to the Ironwood Acquisition.
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Lower interest expense in 2012 compared with 2011 of $14 million due to the impact of redeeming debt not replaced and redeeming debt replaced at a lower interest rate, $10 million due to lower interest on short-term borrowings and $7 million due to 2011 including the acceleration of deferred financing fees related to the July 2011 redemption, partially offset by a $12 million increase related to the debt assumed as a result of the Ironwood Acquisition.
·
Lower income taxes in 2012 compared with 2011 due to lower 2012 pre-tax income, which reduced income taxes by $110 million and $20 million related to lower adjustments to valuation allowances on Pennsylvania net operating losses, partially offset by $26 million related to the impact of prior period tax return adjustments.
Lower income taxes in 2011 compared with 2010, due to lower 2011 pre-tax income, which reduced income taxes by $196 million and a $26 million reduction in deferred tax liabilities related to an updated blended state tax rate as a result of a change in state apportionment. These decreases were partially offset by $74 million related to adjustments to valuation allowances on Pennsylvania net operating losses, $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.
·
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.
The following after-tax gains (losses), which management considers special items, also impacted the results.
(a)
See "Reconciliation of Economic Activity" below.
(b)
Gains recorded on completion of the sale of the Maine hydroelectric generation business. See Note 9 to the Financial Statements for additional information.
(c)
Primarily represents impairment charges of sulfur dioxide emission allowances.
(d)
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 Statement of Income.
(e)
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.
(f)
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.
(g)
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 Statement 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. See Note 15 to the Financial Statements for additional information.
(h)
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.
(i)
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.
(j)
In October 2011, a wholesale customer, SMGT, filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy code. In 2012, PPL EnergyPlus recorded an additional allowance for unpaid amounts under the long-term power contract. In March 2012, the U.S. Bankruptcy Court for the District of Montana approved the request to terminate the contract, effective April 1, 2012.
(k)
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 Energy Supply accrued its share of this additional revenue in 2011.
(l)
As a result of lower electricity and natural gas prices, coal-fired generation output decreased during 2012. Contract modification payments were incurred to reduce 2012 and 2013 contracted coal deliveries.
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.
2013 Outlook
Excluding special items, PPL Energy Supply projects lower earnings in 2013 compared with 2012, primarily driven by lower energy prices, higher fuel costs, higher operation and maintenance, higher depreciation and higher financing costs, which are partially offset by higher capacity prices and higher nuclear generation output despite scheduled outages for both Susquehanna units to implement a long-term solution to turbine blade issues.
Earnings in future periods 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 --
Unregulated Gross Energy 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 fluctuations 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" adjusted 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 adjusted 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 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 tables reconcile "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 2012, "Wholesale energy marketing - Realized" and "Energy purchases - Realized" include a net pre-tax loss of $35 million related to the monetization of certain full-requirement sales contracts. 2011 includes a net pre-tax loss of $216 million related to the monetization of certain full-requirement sales contracts and a net pre-tax gain of $19 million related to the amortization of option premiums. 2010 includes a net pre-tax gain of $37 million related to the monetization of certain full-requirement sales contracts and a net pre-tax gain of $32 million related to the amortization of option premiums.
(d)
Represents energy-related economic activity, which is subject to fluctuations 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 as described in "Commodity Price Risk (Non-trading) - Economic Activity" within Note 19 to the Financial Statements. 2012 includes a net pre-tax loss of $29 million related to coal contract modification payments. 2011 includes pre-tax 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)
Higher margins in 2011 compared with 2010 were driven by the monetization of loss contracts in 2010 and lower customer migration to alternative suppliers in 2011.
(b)
Volumes were lower in 2011 compared with 2010 as a result of unplanned outages and the sale of our interest in Safe Harbor Water Power Corporation.
(c)
Volumes were flat in 2012 compared to 2011 due to an uprate in the third quarter of 2011 offset by higher plant outage costs in 2012. Volumes were lower in 2011 compared with 2010 primarily as a result of the dual-unit turbine blade replacement outages beginning in May 2011.
(d)
See Note 10 to the Financial Statements for additional information.
Western U.S.
Non-trading margins were lower in 2012 compared with 2011 due to $34 million of lower wholesale volumes, including $31 million related to the bankruptcy of SMGT, $9 million of higher average fuel prices and $9 million of lower wholesale prices.
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 the coal unit output.
Energy-Related Businesses
The $10 million increase in contributions from energy-related businesses in 2012 compared with 2011 primarily relates to the mechanical services businesses, due to improved margins on construction and energy service projects in 2012 and a decrease in affiliate trademark expenses.
Other Operation and Maintenance
The increase (decrease) in other operation and maintenance was 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, in 2011 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)
2012 compared with 2011 was higher primarily due to $11 million of higher payroll-related costs, $7 million of higher project costs and $7 million of higher costs from the refueling outage. 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.
(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.
(e)
2012 compared with 2011 was higher primarily due to net plant outage costs of $13 million. 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.
(g)
There are no comparable amounts in the 2011 periods as the Ironwood Acquisition occurred in April 2012.
(h)
In 2011 and 2010, PPL Energy Supply was charged trademark royalties by an affiliate. The agreement was terminated in December 2011.
Depreciation
Depreciation increased by $41 million in 2012 compared with 2011, primarily due to $16 million attributable to PP&E additions and $17 million attributable to the Ironwood Acquisition in April 2012. Depreciation increased by $8 million in 2011 compared with 2010, primarily due to PP&E additions.
Taxes, Other Than Income
Taxes, other than income decreased by $2 million in 2012 compared with 2011, primarily due to a $7 million decrease in state capital stock tax offset by a $4 million increase in state gross receipts tax.
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.
Other Income (Expense) - net
See Note 17 to the Financial Statements for details.
Interest Income from Affiliates
Interest income from affiliates decreased by $6 million in 2012 compared with 2011, primarily due to lower average loan balances with PPL Energy Funding.
Interest Expense
The increase (decrease) in interest expense was due to:
(a)
The decrease was primarily due to the redemption of $250 million of 7.0% Senior Notes due 2046 in July 2011 along with the repayment of $500 million of 6.4% Senior Notes due 2011 and subsequent issuance of $500 million of 4.6% Senior Notes due 2021, both in the fourth quarter of 2011.
(b)
2012 compared with 2011 was lower primarily due to lower interest rates on 2012 short-term borrowings coupled with lower fees on credit facilities. 2011 compared with 2010 was higher primarily due to increased borrowings in 2011 and an increase in commitment fees on credit facilities.
(c)
The periods include the impact of accelerating the amortization of deferred financing fees of $7 million in 2011, due to the July 2011 redemption, as noted above, of its 7.00% Senior Notes due 2046. 2011 compared with 2010 was slightly offset by the impact of accelerating the amortization of deferred financing fees of $10 million in 2010, due to the September 2010 expiration and subsequent replacement of its $3.2 billion 5-year Syndicated Credit Facility.
(d)
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 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 2011 and 2010, PPL Montana recorded $4 million and $10 million of 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, in the fourth quarter of 2011 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 increase (decrease) in income taxes was due to:
(a)
During 2011, the Pennsylvania Department of Revenue issued interpretive guidance on the treatment of bonus depreciation for Pennsylvania income tax purposes. The guidance allows 100% bonus for qualifying assets in the same year bonus depreciation is allowed for federal income tax purposes. Due to the decrease in projected 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 carryforward period of the net operating losses during 2010.
(b)
Changes in state apportionment resulted in reductions to the future estimated state tax rate at December 31, 2012 and 2011. PPL Energy Supply recorded a $19 million deferred tax benefit in 2012 and a $26 million deferred tax benefit in 2011 related to its state deferred tax liabilities.
(c)
In December 2010, Congress enacted legislation allowing for 100% bonus depreciation on qualified property. The increased tax depreciation deduction eliminated the tax benefits related to domestic manufacturing deductions in 2012 and 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 related to an additional domestic manufacturing deduction resulting from revised bonus depreciation amounts.
(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. 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. 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, credit facilities and commercial paper issuances. In 2013, PPL Energy Supply anticipates receiving capital contributions from its member, as well.
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 that could affect 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 increased by 1%, or $8 million, in 2012 compared with 2011. This was primarily due to a $92 million decrease in net cash used in other operating activities (includes a $77 million reduction in defined benefit plan funding) and a $23 million decrease in net cash used in working capital (including a change of $156 million from counterparty collateral, offset by a $92 million change in accounts receivable). These impacts were offset by a $107 million decrease in net income, when adjusted for non-cash components.
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.
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, 2012 positions, it would have had to post additional collateral of approximately $368 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 2013 through 2017.
Net cash used in investing activities decreased $199 million in 2012 compared with 2011, primarily as a result of a $396 million change in notes receivable from affiliates and a $232 million change in restricted cash and cash equivalents, partially offset by $381 million less in asset sale proceeds (2011 sale of non-core generation facilities) and $84 million used to fund the 2012 Ironwood Acquisition (see Note 10 to the Financial Statements for additional information on this acquisition).
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.
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 for 2010.
Financing Activities
Net cash used in financing activities was $281 million in 2012 compared with $390 million in 2011 and $612 million in 2010. The decrease from 2011 to 2012 primarily reflects the 2011 distribution of cash included in the net assets of PPL Global to PPL Energy Funding and a decrease in net retirement of long-term debt, partially offset by higher net distributions to Member. 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.
In 2012, cash used in financing activities primarily consisted of $787 million in distributions to Member and a $44 million net decrease in short-term debt, partially offset by $563 million in contributions from Member.
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.
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.
Forecasted Sources of Cash
PPL Energy Supply expects to continue to have sufficient sources of liquidity available in the near term, including cash flows from operations, various credit facilities, commercial paper issuances, operating leases and contributions from member.
Credit Facilities
At December 31, 2012, PPL Energy Supply's total committed borrowing capacity under credit facilities and the use of this borrowing capacity were:
(a)
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)
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 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, 2012, 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
PPL Energy Supply maintains a $750 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, 2012, PPL Energy Supply had $356 million of commercial paper outstanding at a weighted-average interest rate of approximately 0.50%.
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.
See Note 11 to the Financial Statements for further discussion of the operating leases.
Contributions from Member
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 to fund capital expenditures and for other 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 2013 through 2017.
(a)
Construction expenditures include capitalized interest, which is expected to total approximately $82 million for the years 2013 through 2017.
(b)
Includes expenditures for certain intangible assets.
PPL Energy Supply's capital expenditure projections for the years 2013 through 2017 total approximately $2.5 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 153 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 2013 with cash from operations and equity contributions from PPL Energy Funding.
Contractual Obligations
PPL Energy Supply has assumed various financial obligations and commitments in the ordinary course of conducting its business. At December 31, 2012, 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.
(e)
The amounts represent contributions made or committed to be made for 2013 for PPL's U.S. pension plans. See Note 13 to the Financial Statements for a discussion of expected contributions.
(f)
At December 31, 2012, total unrecognized tax benefits of $30 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 distributions to its member.
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 Actions
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. The credit ratings of PPL Energy Supply and its subsidiaries affect its liquidity, access to capital markets and cost of borrowing under its credit facilities.
The following table sets forth PPL Energy Supply's and its subsidiaries' security credit ratings as of December 31, 2012.
A downgrade in PPL Energy Supply's or its subsidiaries' credit ratings could result in higher borrowing costs and reduced access to capital markets. PPL Energy Supply and its subsidiaries have no credit rating triggers that would result in the reduction of access to capital markets or the acceleration of maturity dates of outstanding debt.
In addition to the credit ratings noted above, the rating agencies took the following actions related to PPL Energy Supply and its subsidiaries in 2012.
In January 2012, S&P affirmed its rating and revised its outlook, from positive to stable, for PPL Montana's Pass Through Certificates due 2020.
Following the announcement of the then-pending acquisition of AES Ironwood, L.L.C. in February 2012, the rating agencies took the following actions:
·
In March 2012, Moody's placed AES Ironwood, L.L.C.'s senior secured bonds under review for possible ratings upgrade.
·
In April 2012, S&P affirmed the rating of AES Ironwood, L.L.C.'s senior secured bonds.
In May 2012, Fitch downgraded its rating, from BBB to BBB- and revised its outlook, from negative to stable, for PPL Montana's Pass Through Certificates due 2020.
In November 2012, S&P revised its outlook, from stable to negative, for PPL Montana's Pass Through Certificates due 2020.
In December 2012, Fitch affirmed the issuer default rating, individual security rating and revised the outlook, from stable to negative, for PPL Energy Supply.
In February 2013, Moody's upgraded its rating, from Ba1 to B2, and revised the outlook from under review to stable for PPL Ironwood.
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 that require 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, 2012. At December 31, 2012, 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 $385 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 under normal market conditions 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 net fair value of economic positions at December 31, 2012 and 2011 was a net asset/(liability) of $346 million and $(63) million. See Note 19 to the Financial Statements for additional information.
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 range in maturity through 2019.
The following table sets forth the changes in the net fair value of non-trading commodity derivative contracts at December 31, 2012. 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.
The following table segregates the net fair value of non-trading commodity derivative contracts at December 31, 2012, based on the level of observability of the information used to determine the fair value.
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 (or their 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. In connection with its bankruptcy proceedings, a significant counterparty, SMGT, had been purchasing lower volumes of electricity than prescribed in the contract and effective April 1, 2012 the contract was terminated. PPL Energy Supply cannot predict the prices or other terms on which it will be able to market to third parties the power that SMGT will not purchase from PPL EnergyPlus due to the termination of this contract. See Note 15 to the Financial Statements for additional information.
Commodity Price Risk (Trading)
PPL Energy Supply's trading commodity derivative contracts range in maturity through 2017. The following table sets forth changes in the net fair value of trading commodity derivative contracts at December 31, 2012 . 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.
The following table segregates the net fair value of trading commodity derivative contracts at December 31, 2012, based on the level of observability of the information used to determine the fair value.
VaR Models
A VaR model is utilized to measure commodity price risk in domestic 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. VaR is calculated using a Monte Carlo simulation technique based on a five-day holding period at a 95% confidence level. Given the company's disciplined hedging program, the non-trading VaR exposure is expected to be limited in the short-term. The VaR for portfolios using end-of-month results for the period was as follows.
The trading portfolio includes all proprietary trading positions, regardless of the delivery period. All positions not considered proprietary trading are considered non-trading. The non-trading portfolio includes the 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, 2012.
Interest Rate Risk
PPL Energy Supply and its subsidiaries issue 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, 2012 and 2011, 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, 2012 would increase the fair value of its debt portfolio by $52 million, compared with $53 million at December 31, 2011.
NDT Funds - Securities Price Risk
In connection with certain NRC requirements, PPL Susquehanna maintains trust funds to fund certain costs of decommissioning the PPL Susquehanna nuclear plant (Susquehanna). At December 31, 2012, 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 primarily 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, 2012, a hypothetical 10% increase in interest rates and a 10% decrease in equity prices would have resulted in an estimated $49 million reduction in the fair value of the trust assets, compared with $43 million at December 31, 2011. 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.
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 from time to time evaluates opportunities for potential acquisitions, divestitures and development projects. Development projects are 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.
Incremental capacity increases of 153 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, including the 2012 Ironwood Acquisition.
Environmental Matters
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 by the relevant agencies. Costs may take the form of increased capital expenditures or operating and maintenance expenses; monetary fines, penalties or other restrictions. Many of these environmental law considerations are also applicable to the operations of key suppliers, or customers, such as coal producers and industrial power users, and may impact the cost of their products or their demand for PPL Energy Supply's services.
Physical effects associated with climate change could include the impact of changes in weather patterns, such as storm frequency and intensity, and the resultant potential damage to PPL Energy Supply's generation assets as well as impacts on customers. In addition, changed weather patterns could potentially reduce annual rainfall in areas where PPL Energy Supply has hydro generating facilities or where river water is used to cool its fossil and nuclear powered generators. PPL Energy Supply cannot currently predict whether its businesses will experience these potential climate change-related risks or estimate the potential cost of their related consequences.
The below provides a discussion of the more significant environmental matters.
Coal Combustion Residuals (CCRs)
In June 2010, the EPA proposed two approaches to regulating CCRs (as either hazardous or non-hazardous) under existing solid waste regulations. A final rulemaking is currently expected before the end of 2015. However, the timing of the final regulations could be accelerated by certain litigation that could require the EPA to issue its regulations sooner. Regulations could impact handling, disposal and/or beneficial use of CCRs. The economic impact could be material if CCRs are regulated as hazardous waste, and significant if regulated as non-hazardous, in accordance with the proposed rule.
Effluent Limitation Guidelines
The EPA is to issue guidelines for technology-based limits in discharge permits for scrubber wastewater and is expected to require dry ash handling. The EPA agreed, in recent settlement negotiations with environmentalists, to propose revisions to its effluent limitation guidelines (ELGs) by April 2013, with a final rule in late 2014. Limits could be so stringent that plants may consider extensive new or modified wastewater treatment facilities and possibly zero liquid discharge operations, the cost of which could be significant. Impacts should be better understood after the proposed rule is issued.
316(b) Cooling Water Intake Structures Rule
In April 2011, the EPA published a draft regulation under Section 316(b) of the Clean Water Act, which regulates cooling water intakes for power plants. The draft rule has two provisions: one requires installation of Best Technology Available (BTA) to reduce mortality of aquatic organisms that are pulled into the plants cooling water system (entrainment), and the second imposes standards for reduction of mortality of aquatic organisms trapped on water intake screens (impingement). A final rule is expected in June 2013. The proposed regulation would apply to nearly all PPL Energy Supply-owned steam electric plants in Pennsylvania and Montana, potentially even including those equipped with closed-cycle cooling systems. PPL Energy Supply's compliance costs could be significant, especially if the final rule requires closed-cycle systems at plants that do not currently have them or conversions of once-through systems to closed-cycle.
GHG Regulations
In 2013, the EPA is expected to finalize limits on GHG emissions from new power plants and to begin working on a proposal for such emissions from existing power plants. The EPA's proposal on GHG emissions from new power plants would effectively preclude construction on any coal-fired plants and could even be difficult for new gas-fired plants to meet. With respect to existing power plants, the impact could be very significant, depending on the structure and stringency of the final rule. PPL Energy Supply, along with others in the industry, filed comments on the EPA's proposal related to GHG emissions from new plants. With respect to GHG limits for existing plants, PPL Energy Supply will advocate for reasonable, flexible requirements.
MATS
The EPA finalized MATS requiring fossil-fuel fired plants to reduce emissions of mercury and other hazardous air pollutants by April 16, 2015. The rule is being challenged by industry groups and states. The EPA has subsequently proposed changes to the rule with respect to new sources to address the concern that the rule effectively precludes new coal plants. PPL Energy Supply is generally well-positioned to comply with MATS due to its recent investment in, and installation of, environmental controls such as wet flue gas desulfurization systems. PPL Energy Supply is evaluating chemical additive systems for mercury control at Brunner Island, and modifications to existing controls at Colstrip for improved particulate matter reductions. In September 2012, PPL Energy Supply announced its intention to place its Corette plant in long-term reserve status beginning in April 2015 due to expected market conditions and costs to comply with MATS.
CSAPR and CAIR
In 2011, the EPA finalized its CSAPR regulating emissions of nitrous oxide and sulfur dioxide through new allowance trading programs which were to be implemented in two phases (2012 and 2014). Like its predecessor, the CAIR, CSAPR targeted sources in the eastern United States. In December 2011, the Court of Appeals for the D.C. Circuit (the Court) stayed implementation of CSAPR, leaving CAIR in place. Subsequently, in August 2012, the Court vacated and remanded CSAPR back to the EPA for further rulemaking, again leaving CAIR in place, pending further EPA action. PPL Energy Supply plants in Pennsylvania will continue to comply with CAIR through optimization of existing controls, balanced with emission allowance purchases. The Court's August decision leaves plants in CSAPR-affected states potentially exposed to more stringent emission reductions due to regional haze implementation (it was previously determined that CSAPR or CAIR participation satisfies regional haze requirements), and/or petitions to the EPA by downwind states under Section 126 of the Clean Air Act requesting the EPA to require plants that allegedly contribute to downwind non-attainment to take action to reduce emissions.
Regional Haze - Montana
The EPA signed its final Federal Implementation Plan (FIP) of the Regional Haze Rules for Montana in September 2012, with tighter emissions limits for Colstrip Units 1 & 2 based on the installation of new controls (no limits or additional controls were specified for Colstrip Units 3 & 4), and tighter emission limits for Corette (which are not based on additional controls). The cost of the potential additional controls for Colstrip Units 1 & 2, if required, could be significant. PPL Energy Supply expects to meet the tighter permit limits at Corette without any significant changes to operations, although other requirements have led to the planned suspension of operations at Corette beginning in April 2015 (see "MATS" discussion above).
See "Item 1. Business - Environmental Matters" and Note 15 to the Financial Statements for additional information on environmental matters.
Competition
See "Item 1. Business - Segment Information - Supply Segment - Competition" 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). 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.
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.
Defined Benefits
PPL Energy Supply subsidiaries sponsor and participate in various qualified funded and non-qualified unfunded defined benefit pension plans. A PPL Energy Supply subsidiary also sponsors 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 U.S. defined benefit plans, PPL Services and PPL Energy Supply start with a cash flow analysis of the expected benefit payment stream for their plans. The plan-specific cash flows are matched against the coupons and expected maturity values of individually selected bonds. This bond matching process begins with the full universe of Aa-rated non-callable (or callable with make-whole provisions) bonds, serving as the base from which those with the lowest and highest yields were eliminated to develop an appropriate subset of bonds. 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. At December 31, 2012, PPL Services decreased the discount rate for its U.S. pension plans from 5.07% to 4.22% and PPL Energy Supply decreased the discount rate for its pension plan from 5.12% to 4.25%. PPL Services decreased the discount rate for its other postretirement benefit plan from 4.81% to 4.02% and PPL Energy Supply decreased the discount rate for its other postretirement benefit plan from 4.60% to 3.77%.
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. At December 31, 2012, PPL Services' and PPL Energy Supply's expected return on plan assets remained at 7.00% for their U.S. pension plans and increased from 5.70% to 5.75% 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, 2012, PPL Services and PPL Energy Supply's rate of compensation increase decreased from 4.00% to 3.95% 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, 2012, PPL Services' and PPL Energy Supply's health care cost trend rates were 8.00% for 2013, 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, 2012, the defined benefit plans were recorded as follows.
Pension liabilities
$
(295)
Other postretirement benefit liabilities
(77)
The following chart reflects the sensitivities in the December 31, 2012 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 2012, PPL Energy Supply was allocated and recognized net periodic defined benefit costs charged to operating expense of $44 million. This amount represents a $10 million increase from 2011.
The following chart reflects the sensitivities in the 2012 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.
Asset Impairment (Excluding Investments)
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 amount 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 amount 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 amount 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.
In September 2012, PPL Energy Supply announced its intention, beginning in April 2015, to place the Corette coal-fired plant in Montana in long-term reserve status, suspending the plant's operation, due to expected market conditions and the costs to comply with MATS requirements. The Corette plant asset group's carrying amount at December 31, 2012 was approximately $68 million. An impairment analysis was performed for this asset group in the third and fourth quarters of 2012 and it was determined to not be impaired. It is reasonably possible that an impairment could occur in future periods, as higher priced sales contracts settle, adversely impacting projected cash flows.
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.
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 amount 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.
Beginning in 2012, PPL Energy Supply may elect either to initially make a qualitative evaluation about the likelihood of an impairment of goodwill or to bypass the qualitative evaluation and test goodwill for impairment using a two-step quantitative test. If the qualitative evaluation (referred to as "step zero") is elected and the assessment results in a determination that it is not more likely than not the fair value of the reporting unit is less than the carrying amount, the two-step quantitative impairment test is not necessary. However, the quantitative impairment test is required if PPL Energy Supply concludes it is more likely than not that the fair value of the reporting unit is less than the carrying amount based on the step zero assessment.
When the two-step quantitative impairment test is elected or required as a result of the step zero assessment, 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 amount, 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 of the quantitative test 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 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 PPL Energy Supply's goodwill.
PPL Energy Supply elected to perform the two-step quantitative impairment test of goodwill in the fourth quarter of 2012 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.
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 2012.
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.
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 disclosure of loss contingencies accrued and other potential loss contingencies that have not met the criteria for accrual.
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 statement of income, 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, 2012, AROs totaling $375 million were recorded on the Balance Sheet, of which $10 million is included in "Other current liabilities." Of the total amount, $316 million, or 84%, 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, 2012. 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.
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 derecognized, 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, 2012, 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 $30 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, audit-related and tax 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 defined 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, a summary of Net Income Available to PPL and a discussion of certain events related to 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 explanations of significant changes in principal items on PPL Electric's Statements of Income, comparing 2012 with 2011 and 2011 with 2010.
·
"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 forecasted sources and uses of cash and rating agency actions.
·
"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 transmission and distribution 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 for at least the next five years. 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 and strong liquidity position.
Timely recovery of costs to maintain and enhance the reliability of PPL Electric's delivery system including 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. See "Regulatory Matters - Pennsylvania Activities - Legislation - Regulatory Procedures and Mechanisms" in Note 6 to the Financial Statements for information on Pennsylvania's new alternative rate-making mechanism.
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 for 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
Net Income Available to PPL for 2012, 2011 and 2010 was $132 million, $173 million and $115 million. Earnings in 2012 decreased 24% from 2011 and earnings in 2011 increased 50% over 2010.
See "Results of Operations" below for further discussion and analysis of PPL Electric's earnings.
Redemption of Preference Stock
In June 2012, PPL Electric redeemed all 2.5 million shares of its 6.25% Series Preference Stock, par value $100 per share. The price paid for the redemption was the par value, without premium ($250 million in the aggregate). At December 31, 2011, the preference stock was reflected on PPL Electric's Balance Sheet in "Preferred securities."
Storm Costs
During 2012, PPL Electric experienced several PUC-reportable storms, including Hurricane Sandy, resulting in total restoration costs of $81 million, of which $61 million were initially recorded in "Other operation and maintenance" on the Statement of Income. In particular, in late October 2012, PPL Electric experienced widespread significant damage to its distribution network from Hurricane Sandy resulting in total restoration costs of $66 million, of which $50 million were initially recorded in "Other operation and maintenance" on the Statement of Income. Although PPL Electric had storm insurance coverage, the costs incurred from Hurricane Sandy exceeded the policy limits. Probable insurance recoveries recorded during 2012 were $18.25 million, of which $14 million were included in "Other operation and maintenance" on the Statements of Income. PPL Electric recorded a regulatory asset of $28 million in December 2012 (offset to "Other operation and maintenance" on the Statement of Income). In February 2013, PPL Electric received an order from the PUC granting permission to defer qualifying storm costs in excess of insurance recoveries associated with Hurricane Sandy.
See "Regulatory Matters - Pennsylvania Activities - Storm Costs" in Note 6 to the Financial Statements for information on $84 million of storm costs incurred in 2011.
Rate Case Proceeding
In March 2012, PPL Electric filed a request with the PUC to increase distribution rates by approximately $105 million, effective January 1, 2013. In its December 28, 2012 final order, the PUC approved a 10.4% return on equity and a total distribution revenue increase of about $71 million. The approved rates became effective January 1, 2013.
Also, in its December 28, 2012 final order, the PUC directed PPL Electric to file a proposed Storm Damage Expense Rider within 90 days following the order. PPL Electric plans to file a proposed Storm Damage Expense Rider with the PUC and, as part of that filing, request recovery of the $28 million of qualifying storm costs incurred as a result of the October 2012 landfall of Hurricane Sandy.
Regional Transmission Line Expansion Plan
Susquehanna-Roseland
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 was needed to prevent potential overloads that could occur on several existing transmission lines in the interconnected PJM system. PJM directed PPL Electric to construct the portion of the Susquehanna-Roseland line in Pennsylvania and Public Service Electric & Gas Company to construct the portion of the line in New Jersey.
On October 1, 2012, the National Park Service (NPS) issued its Record of Decision (ROD) on the proposed Susquehanna-Roseland transmission line affirming the route chosen by PPL Electric and Public Service Electric & Gas Company as the preferred alternative under the NPS's National Environmental Policy Act review. On October 15, 2012, a complaint was filed in the United States District Court for the District of Columbia by various environmental groups, including the Sierra Club, challenging the ROD and seeking to prohibit its implementation; and on December 6, 2012, the groups filed a petition for injunctive relief seeking to prohibit all construction activities until the court issues a final decision on the complaint. PPL Electric has intervened in the lawsuit. The chosen route had previously been approved by the PUC and New Jersey Board of Public Utilities.
On December 13, 2012, PPL Electric received federal construction and right of way permits to build on National Park Service lands.
Construction activities have begun on portions of the 101-mile route in Pennsylvania. The line is expected to be in service before the peak summer demand period of 2015. At December 31, 2012, PPL Electric's estimated share of the project cost was $560 million.
PPL and PPL Electric cannot predict the ultimate outcome or timing of any legal challenges to the project or what additional actions, if any, PJM might take in the event of a further delay to its scheduled in-service date for the new line.
Northeast/Pocono
In October 2012, the FERC issued an order in response to PPL Electric's December 2011 request for ratemaking incentives for the Northeast/Pocono Reliability project (a new 58-mile 230 kV transmission line, three new substations and upgrades to adjacent facilities). The incentives were specifically tailored to address the risks and challenges PPL Electric will face in building the project. The FERC granted the incentive for inclusion of all prudently incurred construction work in progress (CWIP) costs in rate base and denied the request for a 100 basis point adder to the return on equity incentive. The order required a follow-up compliance filing from PPL Electric to ensure proper accounting treatment of AFUDC and CWIP for the project, which PPL Electric will submit to the FERC in March 2013. PPL Electric expects the project to be completed in 2017. At December 31, 2012, PPL Electric estimates the total project costs to be approximately $200 million with approximately $190 million qualifying for the CWIP incentive.
Legislation - Regulatory Procedures and Mechanisms
Act 11 authorizes the PUC to approve two specific ratemaking mechanisms - the use of a fully projected future test year in base rate proceedings and, subject to certain conditions, the use of a DSIC. Such alternative ratemaking procedures and mechanisms provide opportunity for accelerated cost-recovery and, therefore, are important to PPL Electric as it begins a period of significant capital investment to maintain and enhance the reliability of its delivery system, including the replacement of aging distribution assets. In August 2012, the PUC issued a final implementation order adopting procedures, guidelines and a model tariff for the implementation of Act 11. Act 11 requires utilities to file an LTIIP as a prerequisite to filing for recovery through the DISC. The LTIIP is mandated to be a five- to ten-year plan describing projects eligible for inclusion in the DISC. In September 2012, PPL Electric filed its LTIIP describing projects eligible for inclusion in the DSIC. The PUC approved the LTIIP on January 10, 2013 and PPL Electric filed a petition requesting permission to establish a DSIC on January 15, 2013, with rates proposed to be effective beginning May 1, 2013.
FERC Formula Rates
In March 2012, PPL Electric filed a request with the FERC seeking recovery of its 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. At December 31, 2012 and December 31, 2011, $52 million and $53 million respectively, are classified as taxes recoverable through future rates and are included on the Balance Sheets in "Other Noncurrent Assets - Regulatory assets." In May 2012, the FERC issued an order approving PPL Electric's request recover the deferred tax regulatory asset over a 34 year period beginning June 1, 2012.
Results of Operations
The following discussion provides a summary of PPL Electric's earnings and a description of factors that are expected to impact future earnings. This section ends with "Statement of Income Analysis," which includes explanations of significant year-to-year changes in Pennsylvania Gross Delivery Margins by component and principal line items on PPL Electric's Statements of Income.
The utility business is influenced by seasonality in the weather. As a result, operating revenues (and associated operating expenses) are not generated evenly throughout the year. Revenue is generally higher during the first and third quarters of a year due to higher demand as a result of winter and summer periods. On the other hand, revenue tends to be lower during the second and fourth quarters due to lower demand as a result of milder weather.
The changes in the components of Net Income Available to PPL between these periods were due to the following factors which reflect reclassifications for items included in gross delivery margins.
·
See "Statement of Income Analysis - Margins - Changes in Non-GAAP Financial Measures" for an explanation of Pennsylvania Gross Delivery Margins.
·
Higher other operation and maintenance for 2012 compared with 2011, primarily due to $17 million in higher payroll-related costs due to less project costs being capitalized in 2012, higher support group costs of $11 million and $10 million for increased vegetation management.
·
Higher depreciation for 2012 compared with 2011 and 2011 compared with 2010 primarily due to PP&E additions.
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Higher taxes, other than income for 2012 primarily due to a $10 million tax provision related to gross receipts tax.
·
Income taxes were flat in 2012 compared with 2011 primarily due to the $22 million impact of lower 2012 pre-tax income primarily offset by $9 million of depreciation not normalized and $9 million of income tax return adjustments, largely related to changes in flow-through regulated tax depreciation.
Income taxes were higher in 2011 compared with 2010, due to the $26 million impact of higher 2011 pre-tax income, partially offset by a $14 million tax benefit related to changes in flow-through regulated tax depreciation.
·
Lower distributions on preferred securities in 2012 compared to 2011 due to the preference stock redemption in June 2012.
2013 Outlook
PPL Electric projects higher earnings in 2013 compared with 2012, due to higher distribution revenues from a distribution base rate increase effective January 1, 2013, and higher transmission margins, partially offset by higher depreciation.
Earnings in future periods 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," 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 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 excluded from Margins.
(b)
As reported on the Statements 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
Margins decreased in 2012 compared with 2011, primarily due to a $14 million unfavorable effect of mild weather early in 2012 and lower revenue applicable to certain energy-related costs of $3 million due to fewer PLR customers in 2012, partially offset by a $7 million charge recorded in 2011 to reduce a portion of the transmission service charge regulatory asset associated with a 2005 undercollection that was not included in any subsequent rate reconciliations filed with the PUC.
Margins increased in 2011 compared with 2010, largely due to the PPL Electric distribution rate case which increased rates by approximately 1.6% effective January 1, 2011, resulting in improved residential distribution margins of $68 million. Additionally, residential volume variances increased margins by an additional $4 million in 2011, compared with 2010, offset by unfavorable weather of $3 million for residential customers in 2011 compared with 2010. 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.
Transmission
Margins increased in 2012 compared with 2011, primarily due to increased investment in plant and the recovery of additional costs through the FERC formula-based rates.
Other Operation and Maintenance
The increase (decrease) in other operation and maintenance was due to:
(a)
Relates to costs associated with PPL Electric's PUC-approved energy efficiency and conservation plan. These costs are recovered in customer rates. There were initially 15 Act 129 programs which began in 2010 and continued to ramp up in 2011. Some of the energy efficiency programs were reduced or closed in 2012 resulting in lower operation and maintenance expense.
(b)
PPL Electric incurred more expense in 2010 and 2012 compared to 2011 due to increased vegetation management activities related to transmission lines to comply with federal reliability requirements as well as increased vegetation management for the distribution system in 2012 in an effort to maintain and increase system reliability.
(c)
Higher payroll costs of $17 million in 2012 compared to 2011 due to less project costs being capitalized.
Taxes, Other Than Income
Taxes, other than income increased by $1 million in 2012 compared with 2011. The increase was primarily a result of the net effect of the fully amortized PURTA refund to customers of $10 million in 2011, partially offset by a decrease in gross receipts tax of $7 million in 2012.
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 on lower 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."
Depreciation
Depreciation increased by $14 million in 2012 compared with 2011 and by $10 million in 2011 compared with 2010, primarily due to PP&E additions as part of ongoing investments to replace aging infrastructure.
Financing Costs
The increase (decrease) in financing costs, which includes "Interest Expense", "Interest Expense with Affiliate" and "Distributions on Preferred Securities," was due to:
(a)
Decreases for both periods are due to the redemption of preference stock in 2012 and preferred stock in 2010.
(b)
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 increase (decrease) in income taxes was 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.
(b)
PPL Electric changed its method of accounting for repair expenditures for tax purposes effective for its 2008 tax year. In August, 2011, the IRS issued guidance regarding the use and evaluation of statistical samples and sampling estimates for network assets. The IRS guidance provided a safe harbor method of determining whether the repair expenditures for electric transmission and distribution property can be currently deducted for tax purposes. PPL Electric adopted the safe harbor method with the filing of its 2011 federal income tax return and recorded a $5 million adjustment to federal and state income tax expense resulting from the reversal of prior years' state income tax benefits related to regulated depreciation.
During 2011, PPL Electric recorded a $5 million federal and state income tax benefit as a result of filing its 2010 federal and state income tax returns. The tax benefit primarily related to the flow-through impact of Pennsylvania regulated 100% bonus tax depreciation.
(c)
During 2011, the Pennsylvania Department of Revenue issued interpretive guidance on the treatment of bonus depreciation for Pennsylvania income tax purposes. The guidance 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. The federal provision for 100% bonus depreciation generally applies to property placed in service before January 1, 2012. The placed in-service deadline is extended to January 1, 2013 for property that has a cost in excess of $1 million, has a production period longer that one year and has a tax life of at least ten years. The PPL Electric's tax deduction for 100% bonus depreciation was significantly lower in 2012 than in 2011.
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, credit facilities and commercial paper issuances. Additionally, subject to market conditions, PPL Electric currently plans to issue long-term debt in 2013.
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
·
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 that could affect 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 decreased by 7%, or $31 million, in 2012 compared with 2011, primarily due to changes in working capital of $82 million partially offset by a decrease in defined benefit plan contributions of $54 million. Changes in working capital included $108 million from regulatory assets and liabilities, net and $56 million from prepayments, partially offset by $95 million from accounts payable.
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 2011 and recorded as a long-term regulatory asset.
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 2013 through 2017.
Net cash used in investing activities was $613 million in 2012 compared with $477 million in 2011. The change from 2011 to 2012 primarily reflects an increase of $143 million in capital expenditures in 2012.
Net cash used in investing activities was $477 million in 2011 compared with $403 million in 2010. The change from 2010 to 2011 primarily reflects an increase of $80 million in capital expenditures in 2011.
Financing Activities
Net cash provided by financing activities was $44 million in 2012 compared with $173 million in 2011. The change from 2011 to 2012 primarily reflects the $250 million preference stock redemption in 2012, offset by a $62 million increase in net debt issuances and a $50 million increase in contributions from PPL.
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.
PPL Electric's debt and equity financing activity in 2012 was:
See Note 7 to the Financial Statements for more detailed information regarding PPL Electric's financing activities in 2012.
Forecasted Sources of Cash
PPL Electric expects to continue to have sufficient sources of liquidity available in the near term, including cash flows from operations, credit facilities, commercial paper issuances and the issuance of long-term debt.
Credit Facilities
At December 31, 2012, PPL Electric's total committed borrowing capacity under its credit facilities and the use of this borrowing capacity were:
(a)
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.
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 5% of the total committed capacity.
(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 $100 million from a commercial paper conduit sponsored by a financial institution. At December 31, 2012, based on accounts receivable and unbilled revenue pledged, the amount available for borrowing under this facility was $100 million.
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, 2012, 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 $300 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 currently supported by PPL Electric's Syndicated Credit Facility. PPL Electric had no commercial paper outstanding at December 31, 2012.
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 Securities
PPL Electric currently plans to incur, subject to market conditions, up to $400 million of long-term indebtedness in 2013, the proceeds of which will be used to fund capital expenditures and for other general corporate purposes.
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 included the deployment of smart grid technology to strengthen reliability, save energy and improve electric service for 60,000 Harrisburg, Pennsylvania area customers. It also provides benefits beyond the Harrisburg region, helping to speed power restoration across PPL Electric's 29-county service territory. Work on the grant project is complete as of December 31, 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 stock 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 2013 through 2017.
(a)
Construction expenditures include AFUDC, which is expected to total approximately $54 million for the years 2013 through 2017.
(b)
Includes expenditures for intangible assets.
PPL Electric's capital expenditure projections for the years 2013 through 2017 total approximately $3.8 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 2013 with cash from operations, equity contributions from PPL, and proceeds from the issuance of debt securities.
Contractual Obligations
PPL Electric has assumed various financial obligations and commitments in the ordinary course of conducting its business. At December 31, 2012, 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.
(d)
The amounts represent contributions made or committed to be made for 2013 for PPL's U.S. pension plans. See Note 13 to the Financial Statements for a discussion of expected contributions.
(e)
At December 31, 2012, total unrecognized tax benefits of $26 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.
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 Actions
Moody's, S&P and Fitch periodically review the credit ratings on the debt 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. PPL Electric's credit ratings affect its liquidity, access to capital markets and cost of borrowing under its credit facilities.
The following table sets forth PPL Electric's security credit ratings as of December 31, 2012.
A downgrade in PPL Electric's credit ratings could result in higher borrowing costs and reduced access to capital markets. PPL Electric does not have credit rating triggers that would result in the reduction of access to capital markets or the acceleration of maturity dates of outstanding debt.
In addition to the credit ratings noted above, the rating agencies took the following actions related to PPL Electric in 2012.
In August 2012, Fitch assigned a rating and outlook to PPL Electric's $250 million First Mortgage Bonds.
In August 2012, S&P and Moody's assigned a rating to PPL Electric's $250 million First Mortgage Bonds.
In December 2012, Fitch affirmed the issuer default rating, individual security rating and the outlook for 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 issues debt to finance its operations, which exposes it to interest rate risk. At December 31, 2012 and 2011, PPL Electric had no potential annual exposure to increased interest expense, based on its current debt portfolio. PPL Electric is also exposed to changes in the fair value of its debt portfolio. PPL Electric estimated that a 10% decrease in interest rates at December 31, 2012 would increase the fair value of its debt portfolio by $93 million, compared with $94 million at December 31, 2011.
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 all of its 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, 2012, most 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. A small portion of bidders were required to post collateral, which totaled less than $1 million, under the Agreement. There is no instance under the Agreement in which PPL Electric is required to post collateral to its suppliers.
See 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
Physical effects associated with climate change could include the impact of changes in weather patterns, such as storm frequency and intensity, and the resultant potential damage to PPL Electric's electricity transmission and distribution systems, as well as impacts on customers. PPL Electric cannot currently predict whether its businesses will experience these potential climate change-related risks or estimate the potential cost of their related consequences.
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). 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.
Defined Benefits
PPL Electric participates in a qualified funded defined benefit pension plan, an unfunded non-qualified defined benefit plan and a funded 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 for amounts that are expected to be recovered through regulated customer rates. 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 U.S. defined benefit plans, PPL Services starts with a cash flow analysis of the expected benefit payment stream for its plans. The plan-specific cash flows are matched against the coupons and expected maturity values of individually selected bonds. This bond matching process begins with the full universe of Aa-rated non-callable (or callable with make-whole provisions) bonds, serving as the base from which those with the lowest and highest yields were eliminated to develop an appropriate subset of bonds. 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. At December 31, 2012, PPL Services decreased the discount rate for its U.S. pension plans from 5.07% to 4.22% and decreased the discount rate for its other postretirement benefit plans from 4.81% to 4.02%.
The expected long-term rates of return for PPL Services' 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. At December 31, 2012, PPL Services' expected return on plan assets remained at 7.00% for its U.S. pension plan and increased from 5.70% to 5.75% 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, 2012, PPL Services' rate of compensation increase decreased from 4.00% to 3.95% for its U.S. plans.
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, 2012, PPL Services' health care cost trend rates were 8.00% for 2013, 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, 2012, the defined benefit plans were recorded as follows.
The following chart reflects the sensitivities in the December 31, 2012 Balance Sheet associated with a change in certain assumptions based on PPL Services' primary defined benefit plans.
(a)
Only impacts other postretirement benefits.
In 2012, PPL Electric was allocated net periodic defined benefit costs charged to operating expense of $22 million. This amount represents a $4 million increase compared with the charge recognized during 2011.
The following chart reflects the sensitivities in the 2012 Statement of Income (excluding income tax effects) associated with a change in certain assumptions based on PPL Services' primary defined benefit plans.
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 2012.
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.
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 disclosure of loss contingencies accrued and other potential loss contingencies that have not met the criteria for accrual.
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 derecognized, 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, 2012, it was reasonably possible that during the next 12 months the total amount of unrecognized tax benefits could increase by as much as $11 million or decrease by up to $25 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.
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, 2012, PPL Electric had regulatory assets of $853 million and regulatory liabilities of $60 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.
See Note 6 to the Financial Statements for additional information on regulatory assets and liabilities.
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, 2012 and 2011, PPL Electric had unbilled revenue of $110 million and $102 million.
Other Information
PPL's Audit Committee has approved the independent auditor to provide audit, audit-related and tax 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 Consolidated Financial Statements and the accompanying Notes. Capitalized terms and abbreviations are defined 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, a summary of Net Income and a discussion of certain events related to 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 explanations of significant changes in principal items on LKE's Statements of Income, comparing 2012 with 2011 and 2011 with 2010.
·
"Financial Condition - Liquidity and Capital Resources" provides an analysis of LKE's liquidity position and credit profile. This section also includes a discussion of forecasted sources and uses of cash and rating agency actions.
·
"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 holding 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 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, competitively priced energy to its customers and reasonable returns on regulated investments to its member.
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. 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 have not changed as a result of the acquisition.
Financial and Operational Developments
Net Income
Net Income for 2012, 2011 and 2010 was $219 million, $265 million and $237 million. Earnings in 2012 decreased 17% from 2011 and earnings in 2011 increased 12% from 2010.
See "Results of Operations" for a discussion and analysis of LKE's earnings.
Rate Case Proceedings
In June 2012, LG&E and KU filed requests with the KPSC for increases in annual base electric rates of approximately $62 million at LG&E and approximately $82 million at KU and an increase in annual base gas rates of approximately $17 million at LG&E. In November 2012, LG&E and KU along with all of the parties filed a unanimous settlement agreement. Among other things, the settlement provided for increases in annual base electric rates of $34 million at LG&E and $51 million at KU and an increase in annual base gas rates of $15 million at LG&E. The settlement agreement also included revised depreciation rates that result in reduced annual electric depreciation expense of approximately $9 million for LG&E and approximately $10 million for KU. The settlement agreement included an authorized return on equity at LG&E and KU of 10.25%. On December 20, 2012, the KPSC issued orders approving the provisions in the settlement agreement. The new rates became effective on January 1, 2013. In addition to the increased base rates, the KPSC approved a gas line tracker mechanism for LG&E to provide for recovery of costs associated with LG&E's gas main replacement program, gas service lines and risers.
Equity Method Investment
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. KU's direct exposure to loss as a result of its involvement with EEI is generally limited to the value of its investment. During the fourth quarter of 2012, KU concluded that an other-than-temporary decline in the value of its investment in EEI had occurred. Accordingly, KU recorded a $15 million impairment charge, net of taxes, related to this investment as of December 31, 2012, bringing the investment balance to zero. The impairment charge is shown in the line "Other-Than-Temporary Impairments" on the Statement of Income for the year ended December 31, 2012.
Registered Debt Exchange Offer by LKE
In June 2012, LKE completed an exchange of all its outstanding 4.375% Senior Notes due 2021 issued in September 2011 in a transaction not registered under the Securities Act of 1933, for similar securities that were issued in a transaction registered under the Securities Act of 1933. See Note 7 to the Financial Statements for additional information.
Commercial Paper
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, if and when necessary. Commercial paper issuances are supported by the issuer's credit facility. At December 31, 2012, $125 million of commercial paper was outstanding.
Terminated 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, pending receipt of applicable regulatory approvals. In May 2012, the KPSC issued an order approving the request to purchase the Bluegrass CTs. In November 2011, LG&E and KU filed an application with the FERC under the Federal Power Act requesting approval to purchase the Bluegrass CTs. In May 2012, the FERC issued an order conditionally authorizing the acquisition of the Bluegrass CTs, subject to approval by the FERC of satisfactory mitigation measures to address market-power concerns. After a review of potentially available mitigation options, LG&E and KU determined that the options were not commercially justifiable. In June 2012, LG&E and KU terminated the asset purchase agreement for the Bluegrass CTs in accordance with its terms and made applicable filings with the KPSC and FERC.
Cane Run Unit 7 Construction
In September 2011, LG&E and KU filed a CPCN with the KPSC requesting approval to build Cane Run Unit 7. In May 2012, the KPSC issued an order approving the request. A formal request for recovery of the costs associated with the construction was not included in the CPCN filing with the KPSC but is expected to be included in future rate case proceedings. LG&E and KU commenced preliminary construction activities in the third quarter of 2012 and project construction is expected to be completed by May 2015. The project, which includes building a natural gas supply pipeline and related transmission projects, has an estimated cost of approximately $600 million.
In conjunction with this construction and to meet new, more stringent EPA regulations with a 2015 compliance date, LG&E and KU anticipate retiring five older coal-fired electric generating units at the Cane Run and Green River plants, which have a combined summer capacity rating of 726 MW. In addition, KU retired the remaining 71 MW unit at the Tyrone plant in February 2013.
Future Capacity Needs
In addition to the construction of a combined cycle gas unit at the Cane Run station, LG&E and KU continue to assess future capacity needs. As a part of the assessment, LG&E and KU issued an RFP in September 2012 for up to 700 MW of capacity beginning as early as 2015.
Results of Operations
As previously noted, LKE's results for the periods after October 31, 2010 are on a basis of accounting different from its results for periods prior to November 1, 2010. 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 and fourth quarters due to weather.
The following table summarizes the significant components of net income for 2012, 2011 and 2010 and the changes therein:
Earnings
The changes in the components of Net Income between these periods were due to the following factors, which reflect reclassifications for items included in Margins and 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 Margins.
·
Higher other operation and maintenance in 2012 compared with 2011 primarily due to $11 million of expenses related to an increased scope of scheduled outages and a $6 million credit to establish a regulatory asset recorded when approved in 2011 related to 2009 storm costs.
·
Higher depreciation in 2012 compared with 2011 due to PP&E additions.
Higher depreciation in 2011 compared with 2010 primarily due to TC2 commencing dispatch in January 2011.
·
Higher taxes, other than income 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.
·
Lower other income (expense) - net in 2012 compared with 2011 primarily due to losses from the EEI investment.
Lower other income (expense) - net in 2011 compared with 2010 primarily due to $19 million of other income from the establishment of a regulatory asset in 2010 for previously recorded losses on interest rate swaps.
·
Lower interest expense in 2011 compared with 2010 due to lower interest rates and lower average long-term debt balances. Lower interest rates contributed $17 million to the decrease in interest expense, as the interest rates on the first mortgage bonds were lower than the rates on the loans from E.ON AG affiliates, which were replaced.
·
Lower income taxes in 2012 compared with 2011 primarily due to lower pre-tax income.
Higher income taxes in 2011 compared with 2010 primarily due to higher pre-tax income.
The following after-tax gains (losses), which management considers special items, also impacted earnings.
(a)
KU recorded an impairment of its equity method investment in EEI. See Note 18 to the Financial Statements for additional information.
(b)
2012 includes an adjustment to an indemnification liability.
(c)
Represents net unrealized gains (losses) on contracts that economically hedge anticipated cash flows.
(d)
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.
2013 Outlook
Excluding special items, LKE projects higher earnings in 2013 compared with 2012, primarily driven by electric and gas base rate increases effective January 1, 2013, returns on additional environmental capital investments and retail load growth, partially offset by higher operation and maintenance.
Earnings in future periods 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 --
Margins
Non-GAAP Financial Measure
The following discussion includes financial information prepared in accordance with GAAP, as well as a non-GAAP financial measure, "Margins." Margins 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. Margins is a single financial performance measure of LKE's electricity generation,
transmission and distribution operations as well as its distribution and sale of natural gas. In calculating this measure, fuel and energy purchases are deducted from revenues. In addition, utility revenues and expenses associated with approved cost recovery mechanisms are offset. These mechanisms allow for recovery of certain expenses, returns on capital investments primarily associated with environmental regulations and performance incentives. Certain costs associated with these mechanisms, primarily ECR and DSM, are recorded as "Other operation and maintenance" and "Depreciation." 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 operations and analyze actual results compared with budget.
Reconciliation of Non-GAAP Financial Measures
The following tables reconcile "Operating Income" to "Margins" as defined by LKE for 2012, 2011 and 2010.
(a)
Represents amounts excluded from Margins.
(b)
As reported on the Statements of Income.
Changes in Non-GAAP Financial Measures
Margins decreased by $8 million for 2012 compared with 2011, primarily due to $6 million of lower wholesale margins resulting from lower market prices. Retail margins were $2 million lower, as volumes were impacted by unseasonably mild weather during the first four months of 2012. Total heating degree days decreased 11% compared to 2011, partially offset by a 6% increase in cooling degree days.
Margins increased 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)
Coal plant maintenance costs increased in 2012 compared with 2011 primarily due to $11 million of expenses related to an increased scope of scheduled outages, as well as $5 million of increased maintenance at the Ghent plant on the scrubber system and primary fuel combustion system.
(b)
Distribution maintenance costs increased in 2012 compared with 2011 primarily due to a $6 million credit to establish a regulatory asset recorded when approved in 2011 related to 2009 storm costs.
Distribution maintenance costs increased in 2011 compared with 2010 primarily due to $17 million of expenses related to amortization of storm restoration-related costs, a hazardous tree removal project initiated in August 2010 and an increase in pipeline integrity work. This increase was offset by a $6 million credit to establish a regulatory asset recorded when approved in 2011 related to 2009 storm costs.
(c)
Administrative and general costs decreased in 2012 compared with 2011 primarily due to a decrease in pension expense resulting from pension funding and lower interest cost.
(d)
Steam operation costs increased in 2011 compared with 2010 primarily due to higher variable costs as a result of TC2 commencing dispatch in 2011.
(e)
Fuel handling costs are included in other operation and maintenance on the Statements of Income for the Successor periods and are in fuel on the Statement of Income for the Predecessor period.
Depreciation
The increase (decrease) in depreciation was due to:
Taxes, Other Than Income
Taxes, other than income increased by $9 million in 2012 compared with 2011 due in part to a $4 million increase in property taxes resulting from property additions, higher assessed values and changes in property classifications to categories with higher tax rates.
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.
Other Income (Expense) - net
The increase (decrease) in other income (expense) - net was due to:
(a)
A regulatory asset was established in 2010 for previously recorded losses on interest rate swaps.
Other-Than-Temporary Impairments
Other-than-temporary impairments increased by $25 million in 2012 compared with 2011 due to the $25 million pre-tax impairment of the EEI investment. See Notes 1 and 18 to the Financial Statements for additional information.
Interest Expense
The increase (decrease) in interest expense was due to:
(a)
Interest expense decreased in 2011 compared with 2010 primarily due to lower interest rates on senior notes and first mortgage bonds issued in November 2010 compared with the rates on the loans from E.ON AG affiliates that were in place through October 2010.
(b)
Interest expense increased in 2012 compared with 2011 due to the LKE $250 million senior notes that were issued in September 2011.
Interest expense decreased in 2011 compared with 2010 as the long-term debt balances were lower for the majority of 2011. The debt balances increased in September 2011 due to the issuance of the LKE $250 million senior notes.
(a)
Adjustments to deferred taxes related to net operating loss carryforwards based on income tax return adjustments.
Income (Loss) from Discontinued Operations (net of income taxes)
Income (loss) from discontinued operations (net of income taxes) decreased by $5 million in 2012 compared with 2011 primarily related to an adjustment to the estimated liability for indemnifications related to the termination of the WKE lease in 2009.
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, including commercial paper issuances. Additionally, subject to market conditions, subsidiaries of LKE currently plan to access capital markets in 2013.
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 commodity prices that may increase the cost of producing or purchasing 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 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)
Borrowings in 2012 were made under LG&E's and KU's commercial paper programs and borrowings in 2010 were made under LG&E's 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:
Operating Activities
Net cash provided by operating activities decreased by 4%, or $34 million, in 2012 compared with 2011, primarily as a result of:
·
Net income adjusted for non-cash items declined by $94 million, which included an $85 million reduction in deferred income taxes due primarily to the utilization of a capital loss carry forward in 2011.
·
Working capital cash flow changes declined by $66 million driven primarily by changes in receivables and unbilled revenues due to milder December weather in 2011 than in 2012 and 2010 and more income tax receivables collected in 2011 than in 2012.
·
These items were offset by $126 million increase in other operating cash flows driven by $100 million reduction in pension funding.
Net cash provided by operating activities increased by 52%, or $267 million, in 2011 compared with 2010, primarily as a result of:
·
an increase in net income adjusted for non-cash effects of $178 million (deferred income taxes and investment tax credits of $101 million, depreciation of $50 million, amortization of regulatory assets of $24 million and other noncash items of $3 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 cash provided from accounts receivable and unbilled revenues of $75 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 $28 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.
Investing Activities
Net cash used in investing activities increased by 173%, or $479 million, in 2012 compared with 2011, primarily as a result of:
·
an increase in capital expenditures of $291 million, primarily due to coal combustion residuals projects at Ghent and E.W. Brown, environmental air projects at Mill Creek and Ghent, and construction of Cane Run Unit 7; and
·
a decrease in the proceeds from the sale of other investments of $163 million in 2011.
Net cash used in investing activities decreased by 57%, or $360 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 $122 million, primarily due to the completion of KU's scrubber program in 2010 and TC2 being dispatched in 2011; and
·
an increase from a change in 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.
See "Forecasted Uses of Cash" for detail regarding capital expenditures for the years 2013 through 2017.
Financing Activities
Net cash used in financing activities was $7 million in 2012 compared with net cash used in financing activities of $456 million in 2011, primarily as a result of decrease in distributions to PPL.
In 2012, cash used in financing activities consisted of:
·
distributions to PPL of $155 million; partially offset by
·
the issuance of $125 million of short-term debt in the form of commercial paper; and
·
an increase in notes payable with affiliates of $25 million.
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.
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.
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, 2012 was:
(a)
In June 2012, LKE completed an exchange of all of its outstanding 4.375% Senior Notes due 2021 issued in September 2011, in a transaction not registered under the Securities Act of 1933, for similar securities that were issued in a transaction registered under the Securities Act of 1933.
See Note 7 to the Financial Statements for additional information about long-term debt securities.
Auction Rate Securities
At December 31, 2012, 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 period ended December 31, 2012, the weighted-average rate on LG&E's and KU's auction rate bonds in total was 0.22%.
Forecasted Sources of Cash
LKE expects to continue to have sufficient sources of cash available in the near term, including various credit facilities, its commercial paper programs, issuance of debt securities and operating cash flow.
Credit Facilities
At December 31, 2012, LKE's total committed borrowing capacity under its credit facilities and the use of this borrowing capacity were:
(a)
In November 2012, LG&E and KU amended their syndicated credit facilities to extend the expiration dates to November 2017. In addition, LG&E increased its credit facility's capacity to $500 million.
(b)
In August 2012, the KU letter of credit facility agreement was amended and restated to allow for certain payments under the letter of credit facility to be converted to loans rather than requiring immediate payment.
(c)
The $1.098 billion of commitments under LG&E's and KU'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 11% of the total committed capacity; however, the PPL affiliate provided a commitment of approximately 21% of the total facilities listed above. The syndicated credit facilities, as well as KU's letter of credit facility, each contain a financial covenant requiring debt to total capitalization not to exceed 70% for LG&E or KU, as calculated in accordance with the facility, and other customary covenants.
(d)
Each company pays customary fees under their respective syndicated credit facilities, as well as KU's letter of credit facility, and borrowings generally bear interest at LIBOR-based rates plus an applicable margin.
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.
Capital Contributions from PPL
From time to time PPL may make capital contributions to LKE. LKE may use these contributions to fund capital expenditures, make capital contributions to its subsidiaries and for other general corporate purposes.
Long-term Debt Securities
LG&E and KU currently plan to issue, subject to market conditions, up to $350 million for LG&E and $300 million for KU, of first mortgage bond indebtedness in 2013, the proceeds of which will be used to fund capital expenditures and for other general corporate purposes.
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, distributions to PPL 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 2013 through 2017.
(a)
LKE generally expects to recover these costs over a period equivalent to the related depreciable lives of the assets through rates. The 2013 total excludes amounts included in accounts payable as of December 31, 2012.
LKE's capital expenditure projections for the years 2013 through 2017 total approximately $6.1 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 existing and proposed EPA compliance standards. Actual costs may be significantly lower or higher depending on the final requirements and market conditions. 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 2013 with cash on hand, cash from operations, short-term debt and issuance of debt securities.
Contractual Obligations
LKE has assumed various financial obligations and commitments in the ordinary course of conducting its business. LKE is not liable for the debts of LG&E and KU, nor are LG&E and KU liable for the debts of one another. Accordingly, creditors of LG&E and KU may not satisfy their debts from the assets of LKE absent a specific contractual undertaking by LKE or LG&E and KU to pay the creditors or as required by applicable law or regulation. At December 31, 2012, 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 has no 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 Mill Creek and Ghent environmental air projects, Cane Run Unit 7, Ghent landfill and Ohio Falls refurbishment 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.
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 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 Actions
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. The credit ratings of LKE and its subsidiaries affect its liquidity, access to capital markets and cost of borrowing under its credit facilities.
The following table sets forth LKE's and its subsidiaries' security credit ratings as of December 31, 2012.
In addition to the credit ratings noted above, the rating agencies took the following actions related to LKE and its subsidiaries:
In February 2012, Fitch assigned ratings to the two newly established commercial paper programs for LG&E and KU.
In March 2012, Moody's affirmed the following ratings:
·
the long-term ratings of the First Mortgage Bonds for LG&E and KU;
·
the issuer ratings for LG&E and KU; and
·
the bank loan ratings for LG&E and KU.
Also in March 2012, Moody's and S&P each assigned short-term ratings to the two newly established commercial paper programs for LG&E and KU.
In March and May 2012, Moody's, S&P and Fitch affirmed the long-term ratings for LG&E's 2003 Series A, and 2007 Series B pollution control bonds.
In November 2012, Moody's and S&P affirmed the long-term ratings for LG&E's 2007 Series A pollution control bonds.
In December 2012, Fitch affirmed the issuer default ratings, individual security ratings and outlooks for LKE, LG&E and KU.
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, 2012. At December 31, 2012, 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 $78 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
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 sells excess economic generation 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. 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, 2012, 2011 and 2010 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 issue 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, 2012 and 2011, 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, 2012, would increase the fair value of its debt portfolio by $113 million compared with $125 million at December 31, 2011.
(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 and cash flow 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, 2012 mature through 2043.
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.
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 expenditures 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.
Physical effects associated with climate change could include the impact of changes in weather patterns, such as storm frequency and intensity, and the resultant potential damage to LKE's generation assets and electricity transmission and distribution systems, as well as impacts on customers. In addition, changed weather patterns could potentially reduce annual rainfall in areas where LKE has hydro generating facilities or where river water is used to cool its fossil powered generators. LKE cannot currently predict whether its businesses will experience these potential climate change-related risks or estimate the potential cost of their related consequences.
See "Item 1. Business - Environmental Matters" and Note 15 to the Financial Statements for a discussion of environmental matters.
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). 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.
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 electricity and gas delivered to customers since the date of the last reading of their meters. The 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, 2012 and 2011, LKE had unbilled revenue balances of $156 million and $146 million.
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. The plan-specific cash flows are matched against the coupons and expected maturity values of individually selected bonds. This bond matching process begins with the full universe of Aa-rated non-callable (or callable with make-whole provisions) bonds, serving as the base from which those with the lowest and highest yields are eliminated to develop an appropriate subset of bonds. 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. At December 31, 2012, LKE decreased the discount rate for its pension plans from 5.08% to 4.24% and decreased the discount rate for its other postretirement benefit plan from 4.78% to 3.99%.
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, 2012, LKE's expected return on plan assets decreased from 7.25% to 7.10%.
In selecting a rate of compensation increase, LKE considers past experience in light of movements in inflation rates. At December 31, 2012, LKE's rate of compensation increase remained at 4.00%.
In selecting health care cost trend rates LKE considers past performance and forecasts of health care costs. At December 31, 2012, LKE's health care cost trend rates were 8.00% for 2013, 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, 2012, 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, 2012 Balance Sheet associated with a change in certain assumptions based on LKE's primary defined benefit plans.
(a)
Only impacts other postretirement benefits.
In 2012, LKE recognized net periodic defined benefit costs charged to operating expense of $40 million. This amount represents an $11 million decrease from 2011. This decrease in expense for 2012 was primarily attributable to the increase in the expected return on plan assets resulting from pension contributions of $57 million, a reduction in the amortization of outstanding losses and lower interest cost.
The following chart reflects the sensitivities in the 2012 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.
Asset Impairment (Excluding Investments)
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 amount 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 amount 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 amount 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.
Goodwill is tested for impairment at the reporting unit level. LKE'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 amount 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.
Beginning in 2012, LKE may elect either to initially make a qualitative evaluation about the likelihood of an impairment of goodwill or to bypass the qualitative assessment and directly test goodwill for impairment using a two-step quantitative test. If the qualitative evaluation (referred to as "step zero") is elected and the assessment results in a determination that it is not more likely than not the fair value of a reporting unit is less than the carrying amount, the two-step quantitative impairment test is not necessary. However, the quantitative impairment test is required if LKE concludes it is more likely than not the fair value of a reporting unit is less than the carrying amount based on the step zero assessment.
When the two-step quantitative impairment test is elected or required as a result of the step zero assessment in step one, LKE identifies a potential impairment by comparing the estimated fair value of a reporting unit with its carrying amount, including goodwill, on the measurement date. If the estimated fair value of a reporting unit 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 of the quantitative test 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 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 elected to perform the two-step quantitative impairment test of goodwill for all of its reporting units in the fourth quarter of 2012 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.
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 2012, the estimated liability for indemnifications related to the 2009 termination of the WKE lease was increased.
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."
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.
See Note 15 to the Financial Statements for additional information.
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. Since costs of removal are collected in rates, 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, 2012, LKE had AROs comprised of current and noncurrent amounts, totaling $131 million recorded on the Balance Sheet. Of the total amount, $90 million, or 69%, 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, 2012:
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 derecognized, 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, 2012, LKE's existing reserve exposure to either increases or decreases in unrecognized tax benefits during the next 12 months is $1 million. This change could result from subsequent recognition, derecognition 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.
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.
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, 2012, LKE had regulatory assets of $649 million and regulatory liabilities of $1,011 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.
See Note 6 to the Financial Statements for additional information on regulatory assets and liabilities.
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 defined 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, a summary of Net Income and a discussion of certain events related to 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 explanations of significant changes in principal items on LG&E's Statements of Income, comparing 2012 with 2011 and 2011 with 2010.
·
"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 forecasted sources and uses of cash and rating agency actions.
·
"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 holding 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, competitively priced energy to its customers and reasonable returns on regulated investments to its shareowner.
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. 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 LG&E have not changed as a result of the acquisition.
Financial and Operational Developments
Net Income
Net Income for 2012, 2011 and 2010 was $123 million, $124 million and $128 million. Earnings in 2012 decreased 1% from 2011 and earnings in 2011 decreased 3% from 2010.
See "Results of Operations" for a discussion and analysis of LG&E's earnings.
Rate Case Proceedings
In June 2012, LG&E filed a request with the KPSC for an increase in annual base electric rates of approximately $62 million and an increase in annual base gas rates of approximately $17 million. In November 2012, LG&E along with all of the parties filed a unanimous settlement agreement. Among other things, the settlement provided for increases in annual base electric rates of $34 million and an increase in annual base gas rates of $15 million. The settlement agreement also included revised depreciation rates that result in reduced annual electric depreciation expense of approximately $9 million. The settlement agreement included an authorized return on equity of 10.25%. On December 20, 2012, the KPSC issued an order approving the provisions in the settlement agreement. The new rates became effective on January 1, 2013. In addition to the increased base rates, the KPSC approved a gas line tracker mechanism to provide for recovery of costs associated with LG&E's gas main replacement program, gas service lines and risers.
Commercial Paper
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, if and when necessary. Commercial paper issuances are supported by LG&E's Syndicated Credit Facility. At December 31, 2012, LG&E had $55 million of commercial paper outstanding.
Terminated 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, pending receipt of applicable regulatory approvals. In May 2012, the KPSC issued an order approving the request to purchase the Bluegrass CTs. In November 2011, LG&E and KU filed an application with the FERC under the Federal Power Act requesting approval to purchase the Bluegrass CTs. In May 2012, the FERC issued an order conditionally authorizing the acquisition of the Bluegrass CTs, subject to approval by the FERC of satisfactory mitigation measures to address market-power concerns. After a review of potentially available mitigation options, LG&E and KU determined that the options were not commercially justifiable. In June 2012, LG&E and KU terminated the asset purchase agreement for the Bluegrass CTs in accordance with its terms and made applicable filings with the KPSC and FERC.
Cane Run Unit 7 Construction
In September 2011, LG&E and KU filed a CPCN with the KPSC requesting approval to build Cane Run Unit 7. In May 2012, the KPSC issued an order approving the request. LG&E will own a 22% undivided interest and KU will own a 78% undivided interest in the new generating unit. A formal request for recovery of the costs associated with the construction was not included in the CPCN filing with the KPSC but is expected to be included in future rate case proceedings. LG&E and KU commenced preliminary construction activities in the third quarter of 2012 and project construction is expected to be completed by May 2015. The project, which includes building a natural gas supply pipeline and related transmission projects, has an estimated cost of approximately $600 million.
In conjunction with this construction and to meet new, more stringent EPA regulations with a 2015 compliance date, LG&E anticipates retiring three older coal-fired electric generating units at the Cane Run plant, which have a combined summer capacity rating of 563 MW.
Future Capacity Needs
In addition to the construction of a combined cycle gas unit at the Cane Run station, LG&E and KU continue to assess future capacity needs. As a part of the assessment, LG&E and KU issued an RFP in September 2012 for up to 700 MW of capacity beginning as early as 2015.
Results of Operations
As previously noted, LG&E's results for the periods after October 31, 2010 are on a basis of accounting different from its results for periods prior to November 1, 2010. 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 and fourth quarters due to weather.
The following table summarizes the significant components of net income for 2012, 2011 and 2010 and the changes therein:
Earnings
The changes in the components of Net Income between these periods were due to the following factors, which reflect reclassifications for items included in Margins and certain items that management considers special.
The net unrealized gains (losses) on contracts that economically hedge anticipated cash flows are considered special items by management. There were no unrealized gains (losses) in 2012.
·
See "Statement of Income Analysis - Margins - Changes in Non-GAAP Financial Measures" for an explanation of Margins.
·
Higher other operation and maintenance in 2011 compared with 2010 primarily due to higher distribution maintenance costs of $8 million due to amortization of storm restoration related costs and a hazardous tree removal project initiated in August 2010.
·
Higher depreciation in 2011 compared with 2010 primarily due to TC2 commencing dispatch in January 2011.
·
Lower other income (expense) - net in 2011 compared with 2010 primarily due to $19 million of other income from the establishment of a regulatory asset in 2010 for previously recorded losses on interest rate swaps.
2013 Outlook
Excluding special items, LG&E projects higher earnings in 2013 compared with 2012, primarily driven by electric and gas base rate increases effective January 1, 2013, returns on additional environmental capital investments and retail load growth, partially offset by higher operation and maintenance.
Earnings in future periods 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 --
Margins
Non-GAAP Financial Measure
The following discussion includes financial information prepared in accordance with GAAP, as well as a non-GAAP financial measure, "Margins." Margins 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. Margins is a single financial performance measure of LG&E's electricity generation, transmission and distribution operations as well as its distribution and sale of natural gas. In calculating this measure, fuel and energy purchases are deducted from revenues. In addition, utility revenues and expenses associated with approved cost recovery mechanisms are offset. These mechanisms allow for recovery of certain expenses, returns on capital investments primarily associated with environmental regulations and performance incentives. Certain costs associated with these mechanisms, primarily ECR and DSM, are recorded as "Other operation and maintenance" and "Depreciation." 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 "Margins" as defined by LG&E for 2012, 2011 and 2010.
(a)
Represents amounts excluded from Margins.
(b)
As reported on the Statements of Income.
Changes in Non-GAAP Financial Measures
Margins increased by $3 million for 2012 compared with 2011, primarily due to $9 million of higher retail margins as a result of new environmental investments. This increase was partially offset by lower wholesale margins of $6 million as volumes were impacted by lower market prices. Retail volumes were consistent with the prior year as increased industrial sales offset declines associated with unseasonably mild weather during the first four months of 2012. Total heating degree days decreased 13% compared to 2011, partially offset by a 7% increase in cooling degree days.
Margins increased by $39 million for 2011 compared with 2010. New KPSC rates went into effect on August 1, 2010, contributing to 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)
Administrative and general costs decreased in 2012 compared with 2011 primarily due to a decrease in pension expense resulting from pension funding and lower interest cost.
(b)
Distribution maintenance costs increased in 2011 compared with 2010 primarily due to amortization of storm restoration-related costs, a hazardous tree removal project initiated in August 2010 and an increase in pipeline integrity work.
(c)
Fuel handling costs are included in other operation and maintenance on the Statements of Income for the Successor periods and are in fuel on the Statement of Income for the Predecessor period.
(d)
Coal plant maintenance costs increased in 2012 compared with 2011 primarily due to an increased scope of scheduled outages.
Coal plant maintenance costs decreased in 2011 compared with 2010 primarily due to the timing of scheduled maintenance outages and non-outage boiler maintenance.
Depreciation
Depreciation increased by $5 million in 2012 compared with 2011 due to PP&E additions.
Depreciation increased by $9 million in 2011 compared with 2010 primarily due to TC2 commencing dispatch in January 2011.
Taxes, Other Than Income
Taxes, other than income increased by $5 million in 2012 compared with 2011 due in part to a $2 million increase in property taxes resulting from property additions, higher assessed values and changes in property classifications to categories with higher tax rates.
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
Other income (expense) - net decreased by $16 million 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
The increase (decrease) in interest expense was due to:
(a)
Interest expense decreased in 2011 compared with 2010 due to lower interest rates on first mortgage bonds issued in November 2010 compared with the rates on the loans from E.ON AG affiliates that were in place through October 2010.
(b)
Interest expense increased in 2011 compared with 2010 due to 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, including commercial paper issuances. Additionally, subject to market conditions, LG&E currently plans to access capital markets in 2013.
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 commodity prices that may increase the cost of producing or purchasing 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 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)
Borrowings in 2012 were made under LG&E's commercial paper program and borrowings in 2010 were made under LG&E's 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:
Operating Activities
Net cash provided by operating activities decreased by 5%, or $17 million, in 2012 compared with 2011, primarily as a result of:
·
Working capital cash flow changes declined by $65 million driven primarily by changes in receivables and unbilled revenues due to milder December weather in 2011 than in 2012 and 2010, and lower inventory levels in 2011 as compared with 2010 driven by lower gas prices.
·
The decline was offset by $44 million increase in other operating cash flows driven by $43 million reduction in pension funding.
Net cash provided by operating activities increased by 80%, or $144 million, in 2011 compared with 2010, primarily as a result of:
·
a decrease in working capital related to accounts receivable and unbilled revenues of $86 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 $34 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, partially offset by unrealized (gains) losses on derivatives of $14 million, defined benefit plans - expense of $3 million and other noncash items 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.
Investing Activities
Net cash used in investing activities increased by $247 million, in 2012 compared with 2011, primarily as a result of:
·
a decrease in the proceeds from the sale of other investments of $163 million in 2011; and
·
an increase in capital expenditures of $90 million due primarily to construction of Cane Run Unit 7 and Mill Creek environmental air projects.
Net cash used in investing activities decreased by 75%, or $128 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 $24 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.
See "Forecasted Uses of Cash" for detail regarding projected capital expenditures for the years 2013 through 2017.
Financing Activities
Net cash used in financing activities was $22 million, in 2012 compared with $260 million in 2011, primarily as a result of changes in short-term debt.
In 2012, cash used in financing activities consisted of:
·
the payment of common stock dividends to LKE of $75 million; partially offset by
·
the issuance of short-term debt in the form of commercial paper of $55 million.
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.
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.
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 had no long-term debt securities activity during the year.
See Note 7 to the Financial Statements for additional information about long-term debt securities.
Auction Rate Securities
At December 31, 2012, 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, 2012, the weighted-average rate on LG&E's auction rate bonds in total was 0.20%.
Forecasted Sources of Cash
LG&E expects to continue to have sufficient sources of cash available in the near term, including various credit facilities, its commercial paper program, issuance of debt securities and operating cash flow.
Credit Facilities
At December 31, 2012, LG&E's total committed borrowing capacity under its Syndicated Credit Facility and the use of this borrowing capacity were:
(a)
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 6% of the total committed capacity available to LG&E.
(b)
In November 2012, LG&E amended the Syndicated Credit Facility to extend the expiration date to November 2017. In addition, LG&E increased the credit facility capacity to $500 million.
(c)
LG&E pays customary fees under its syndicated credit facility, and borrowings generally bear interest at LIBOR-based rates plus an applicable margin.
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, 2012, there was no balance outstanding.
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.
Capital Contributions from LKE
From time to time LKE may make capital contributions to LG&E. LG&E may use these contributions to fund capital expenditures and for other general corporate purposes.
Long-term Debt Securities
LG&E currently plans to issue, subject to market conditions, up to $350 million of first mortgage bond indebtedness in 2013, the proceeds of which will be used to fund capital expenditures and for other general corporate purposes.
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 stock 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 2013 through 2017.
(a)
LG&E generally expects to recover these costs over a period equivalent to the related depreciable lives of the assets through rates. The 2013 total excludes amounts included in accounts payable as of December 31, 2012.
LG&E's capital expenditure projections for the years 2013 through 2017 total approximately $3.0 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 existing and proposed EPA compliance standards. Actual costs may be significantly lower or higher depending on the final requirements and market conditions. 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 2013 with cash on hand, cash from operations, short-term debt and issuance of debt securities.
Contractual Obligations
LG&E has assumed various financial obligations and commitments in the ordinary course of conducting its business. At December 31, 2012, 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 has no 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 Mill Creek environmental air projects, Cane Run Unit 7 and Ohio Falls refurbishment which are also reflected in the Capital Expenditures table presented above.
(g)
Based on the current funded status of LG&E's qualified pension plan and 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.
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 $500 million revolving line of credit facility. This covenant restricts the 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 LG&E.
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 Actions
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. The credit ratings of LG&E affect its liquidity, access to capital markets and cost of borrowing under its credit facilities.
The following table sets forth LG&E's security credit ratings as of December 31, 2012.
In addition to the credit ratings noted above, the rating agencies took the following actions related to LG&E:
In February 2012, Fitch assigned ratings to LG&E's newly established commercial paper program.
In March 2012, Moody's affirmed the following ratings:
· the long-term ratings of the First Mortgage Bonds for LG&E;
· the issuer ratings for LG&E; and
· the bank loan ratings for LG&E.
Also in March 2012, Moody's and S&P each assigned short-term ratings to LG&E's newly established commercial paper program.
In March and May 2012, Moody's, S&P and Fitch affirmed the long-term ratings for LG&E's 2003 Series A and 2007 Series B pollution control bonds.
In November 2012, Moody's and S&P affirmed the long-term ratings for LG&E's 2007 Series A pollution control bonds.
In December 2012, Fitch affirmed the issuer default ratings, individual security ratings and outlook 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, 2012. At December 31, 2012, 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 $57 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
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 sells excess economic generation 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. 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, 2012, 2011 and 2010 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 issues 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, 2012 and 2011, 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, 2012, would increase the fair value of its debt portfolio by $27 million. This estimate is unchanged from December 31, 2011.
(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 and cash flow 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, 2012 mature through 2043.
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.
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 expenditures 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.
Physical effects associated with climate change could include the impact of changes in weather patterns, such as storm frequency and intensity, and the resultant potential damage to LG&E's generation assets and electricity transmission and distribution systems, as well as impacts on customers. In addition, changed weather patterns could potentially reduce annual rainfall in areas where LG&E has hydro generating facilities or where river water is used to cool its fossil powered generators. LG&E cannot currently predict whether its businesses will experience these potential climate change-related risks or estimate the potential cost of their related consequences.
See "Item 1. Business - Environmental Matters" and Note 15 to the Financial Statements for a discussion of environmental matters.
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). 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.
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 electricity and gas delivered to customers since the date of the last reading of their meters. The 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, 2012 and 2011, LG&E had unbilled revenue balances of $72 million and $65 million.
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. The plan-specific cash flows are matched against the coupons and expected maturity values of individually selected bonds. This bond matching process begins with the full universe of Aa-rated non-callable (or callable with make-whole provisions) bonds, serving as the base from which those with the lowest and highest yields are eliminated to develop an appropriate subset of bonds. 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. At December 31, 2012, LKE decreased the discount rate for its pension plan from 5.12% to 4.26%. LG&E decreased the discount rate for its pension plan from 5.05% to 4.20%. LKE decreased the discount rate for its other postretirement benefit plan from 4.78% to 3.99%.
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, 2012, LKE's and LG&E's expected return on plan assets decreased from 7.25% to 7.10%.
In selecting a rate of compensation increase, LKE and LG&E consider past experience in light of movements in inflation rates. At December 31, 2012, LKE's and LG&E's rate of compensation increase remained at 4.00%.
In selecting health care cost trend rates, LKE considers past performance and forecasts of health care costs. At December 31, 2012, LKE's health care cost trend rates were 8.00% for 2013, 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, 2012, the defined benefit plans were recorded as follows:
The following chart reflects the sensitivities in the December 31, 2012 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 2012, LG&E recognized net periodic defined benefit costs charged to operating expense of $18 million. This amount represents a $3 million decrease from 2011. This decrease in expense for 2012 was primarily attributable to the increase in the expected return on plan assets resulting from pension contributions of $21 million, a reduction in the amortization of outstanding losses and lower interest cost.
The following chart reflects the sensitivities in the 2012 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.
Asset Impairment (Excluding Investments)
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 amount 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 amount 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 amount 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 2012, 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 amount 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.
Beginning in 2012, LG&E may elect either to initially make a qualitative evaluation about the likelihood of an impairment of goodwill or to bypass the qualitative assessment and directly test goodwill for impairment using a two-step quantitative test. If the qualitative evaluation (referred to as "step zero") is elected and the assessment results in a determination that it is not more likely than not the fair value of the reporting unit is less than the carrying amount, the two-step quantitative impairment test is not necessary. However, the quantitative impairment test is required if LG&E concludes it is more likely than not the fair value of the reporting unit is less than the carrying amount based on the step zero assessment.
When the two-step quantitative impairment test is elected or required as a result of the step zero assessment, in step one, LG&E identifies a potential impairment by comparing the estimated fair value of LG&E (the goodwill reporting unit) with its carrying amount, 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 of the quantitative test 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 LG&E's 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 LG&E's goodwill.
LG&E elected to perform the two-step quantitative impairment test of goodwill in the fourth quarter of 2012 and no impairment was recognized. Management used both discounted cash flows and market multiples, which required significant assumptions, to estimate the fair value of LG&E. 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.
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 2012, no significant adjustments were made to LG&E's existing contingencies.
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."
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.
See Note 15 to the Financial Statements for additional information.
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. Since costs of removal are collected in rates, 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, 2012, LG&E had AROs comprised of current and noncurrent amounts, totaling $62 million recorded on the Balance Sheet. Of the total amount, $39 million, or 63%, 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, 2012:
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 derecognized, 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, 2012, LG&E'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, derecognition 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.
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.
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, 2012, LG&E had regulatory assets of $419 million and regulatory liabilities of $475 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.
See Note 6 to the Financial Statements for additional information on regulatory assets and liabilities.
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.
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 defined 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, a summary of Net Income and a discussion of certain events related to 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 explanations of significant changes in principal items on KU's Statements of Income, comparing 2012 with 2011 and 2011 with 2010.
·
"Financial Condition - Liquidity and Capital Resources" provides an analysis of KU's liquidity position and credit profile. This section also includes a discussion of forecasted sources and uses of cash and rating agency actions.
·
"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 holding 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, competitively priced energy to its customers and reasonable returns on regulated investments to its shareowner.
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. 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 KU have not changed as a result of the acquisition.
Financial and Operational Developments
Net Income
Net Income for 2012, 2011 and 2010 was $137 million, $178 million and $175 million. Earnings in 2012 decreased 23% from 2011 and earnings in 2011 increased 2% from 2010.
See "Results of Operations" for a discussion and analysis of KU's earnings.
Rate Case Proceedings
In June 2012, KU filed a request with the KPSC for an increase in annual base electric rates of approximately $82 million. In November 2012, KU along with all of the parties filed a unanimous settlement agreement. Among other things, the settlement provided for increases in annual base electric rates of $51 million. The settlement agreement also included revised depreciation rates that result in reduced annual depreciation expense of approximately $10 million. The settlement agreement included an authorized return on equity of 10.25%. On December 20, 2012, the KPSC issued an order approving the provisions in the settlement agreement. The new rates became effective on January 1, 2013.
Equity Method Investment
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. KU's direct exposure to loss as a result of its involvement with EEI is generally limited to the value of its investment. During the fourth quarter of 2012, KU concluded that an other-than-temporary decline in the value of its investment in EEI had occurred. Accordingly, KU recorded a $15 million impairment charge, net of taxes, related to this investment as of December 31, 2012, bringing the investment balance to zero. The impairment charge is shown in the line "Other-Than-Temporary Impairments" on the Statement of Income for the year ended December 31, 2012.
Commercial Paper
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, if and when necessary. Commercial paper issuances are supported by KU's Syndicated Credit Facility. At December 31, 2012, KU had $70 million of commercial paper outstanding.
Terminated Bluegrass CTs Acquisition
In September 2011, KU and LG&E 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, pending receipt of applicable regulatory approvals. In May 2012, the KPSC issued an order approving the request to purchase the Bluegrass CTs. In November 2011, KU and LG&E filed an application with the FERC under the Federal Power Act requesting approval to purchase the Bluegrass CTs. In May 2012, the FERC issued an order conditionally authorizing the acquisition of the Bluegrass CTs, subject to approval by the FERC of satisfactory mitigation measures to address market-power concerns. After a review of potentially available mitigation options, KU and LG&E determined that the options were not commercially justifiable. In June 2012, KU and LG&E terminated the asset purchase agreement for the Bluegrass CTs in accordance with its terms and made applicable filings with the KPSC and FERC.
Cane Run Unit 7 Construction
In September 2011, KU and LG&E filed a CPCN with the KPSC requesting approval to build Cane Run Unit 7. In May 2012, the KPSC issued an order approving the request. KU will own a 78% undivided interest and LG&E will own a 22% undivided interest in the new generating unit. A formal request for recovery of the costs associated with the construction was not included in the CPCN filing with the KPSC but is expected to be included in future rate case proceedings. KU and LG&E commenced preliminary construction activities in the third quarter of 2012 and project construction is expected to be completed by May 2015. The project, which includes building a natural gas supply pipeline and related transmission projects, has an estimated cost of approximately $600 million.
In conjunction with this construction and to meet new, more stringent EPA regulations with a 2015 compliance date, KU anticipates retiring two older coal-fired electric generating units at the Green River plant, which have a combined summer capacity rating of 163 MW. In addition, KU retired the remaining 71 MW unit at the Tyrone plant in February 2013.
Future Capacity Needs
In addition to the construction of a combined cycle gas unit at the Cane Run station, KU and LG&E continue to assess future capacity needs. As a part of the assessment, KU and LG&E issued an RFP in September 2012 for up to 700 MW of capacity beginning as early as 2015.
Results of Operations
As previously noted, KU's results for the periods after October 31, 2010 are on a basis of accounting different from its results for periods prior to November 1, 2010. 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 and fourth quarters due to weather.
The following table summarizes the significant components of net income for 2012, 2011 and 2010 and the changes therein:
The changes in the components of Net Income between these periods were due to the following factors, which reflect reclassifications for items included in Margins and certain items that management considers special.
As a result of low energy prices and environmental regulations, KU assessed the recoverability of its equity method investment in EEI. KU determined it was impaired, and recorded a $15 million impairment charge, net of taxes, as of December 31, 2012. This impairment is considered a special item by management.
·
See "Statement of Income Analysis - Margins - Changes in Non-GAAP Financial Measures" for an explanation of Margins.
·
Higher other operation and maintenance in 2012 compared with 2011 primarily due to $8 million of higher coal plant maintenance costs related to an increased scope of scheduled outages and a $6 million credit to establish a regulatory asset recorded when approved in 2011 related to 2009 storm costs.
Higher other operation and maintenance in 2011 compared with 2010 primarily due to $19 million of higher coal plant maintenance costs related to an increased scope of scheduled outages and higher variable costs from increased generation due to TC2 commencing dispatch in January 2011. This increase was partially offset by a $6 million credit to establish a regulatory asset recorded when approved in 2011 related to 2009 storm costs.
·
Higher depreciation in 2011 compared with 2010 primarily due to TC2 commencing dispatch in January 2011.
·
Lower interest expense in 2011 compared with 2010 primarily due to $18 million less expense primarily related to lower interest rates on the first mortgage bonds issued in November 2010 compared with the rates on the loans from E.ON AG affiliates in place through October 2010. This decrease was partially offset by $8 million of higher expense resulting from higher long-term debt balances.
·
Lower income taxes in 2012 compared with 2011 primarily due to lower pre-tax income.
2013 Outlook
Excluding special items, KU projects higher earnings in 2013 compared with 2012, primarily driven by electric base rate increases effective January 1, 2013, returns on additional environmental capital investments and retail load growth, partially offset by higher operation and maintenance.
Earnings in future periods 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 --
Margins
Non-GAAP Financial Measure
The following discussion includes financial information prepared in accordance with GAAP, as well as a non-GAAP financial measure, "Margins." Margins 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. Margins is a single financial performance measure of KU's electricity generation, transmission and distribution operations. In calculating this measure, fuel and energy purchases are deducted from revenues. In addition, utility revenues and expenses associated with approved cost recovery mechanisms are offset. These mechanisms allow for recovery of certain expenses, returns on capital investments primarily associated with environmental regulations and performance incentives. Certain costs associated with these mechanisms, primarily ECR and DSM, are recorded as "Other operation and maintenance" and "Depreciation." 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 "Margins" as defined by KU for 2012, 2011 and 2010.
(a)
Represents amounts excluded from Margins.
(b)
As reported on the Statements of Income.
Changes in Non-GAAP Financial Measures
Margins decreased by $10 million for 2012 compared with 2011, primarily due to $10 million of lower retail margins, as volumes were impacted by unseasonably mild weather during the first four months of 2012. Total heating degree days decreased 9% compared to 2011, partially offset by a 4% increase in cooling degree days.
Margins increased by $52 million for 2011 compared with 2010. New KPSC rates went into effect on August 1, 2010, contributing to an additional $64 million in operating revenue over the prior year. Partially offsetting the rate increase were lower retail volumes resulting from weather and economic conditions.
(a)
Coal plant maintenance costs increased in 2012 compared with 2011 primarily due to $8 million of expenses related to an increased scope of scheduled outages, as well as $5 million of increased maintenance on the scrubber system and primary fuel combustion system at the Ghent plant.
Coal plant maintenance costs increased in 2011 compared with 2010 primarily due to $8 million of expenses related to an increased scope of scheduled outages.
(b)
Distribution maintenance increased in 2012 compared with 2011 primarily due to a $6 million credit to establish a regulatory asset recorded when approved in 2011 related to 2009 storm costs.
(c)
Administrative and general costs decreased in 2012 compared with 2011 primarily due to a decrease in pension expense resulting from pension funding and lower interest cost.
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.
(d)
Fuel handling costs are included in other operation and maintenance on the Statements of Income for the Successor periods and are in fuel on the Statement of Income for the Predecessor period.
(e)
Steam operation costs increased in 2011 compared with 2010 due to increased generation as a result of TC2 commencing dispatch in 2011.
Depreciation
The increase (decrease) in depreciation was due to:
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.
Other Income (Expense) - net
Other income (expense) - net decreased by $7 million in 2012 compared with 2011 primarily due to $8 million losses from the EEI investment recorded in 2012.
Other-Than-Temporary Impairments
Other-than-temporary impairments increased by $25 million in 2012 compared with 2011 due to the $25 million pre-tax impairment of the EEI investment. See Notes 1 and 18 to the Financial Statements for additional information.
Interest Expense
Interest expense decreased by $8 million in 2011 compared with 2010, primarily due to $18 million less expense primarily related to lower interest rates on the first mortgage bonds issued in November 2010 compared with the rates on the loans from E.ON AG affiliates in place through October 2010. This decrease was partially offset by $8 million of higher expense resulting from higher long-term debt balances.
Income Taxes
Income taxes decreased by $26 million in 2012 compared with 2011, primarily due to the decrease in pre-tax income.
Income taxes increased by $6 million in 2011 compared with 2010, primarily due to the increase in pre-tax income.
Financial Condition
Liquidity and Capital Resources
KU expects to continue to have adequate liquidity available through operating cash flows, cash and cash equivalents, its credit facilities and commercial paper issuances. Additionally, subject to market conditions, KU currently plans to access capital markets in 2013.
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 commodity prices that may increase the cost of producing or purchasing 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 facilities that KU does not own or control to deliver its electricity;
·
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:
(a)
Represents borrowings made under KU's commercial paper program. See Note 7 to the Financial Statements for additional information.
The changes in KU's cash and cash equivalents position resulted from:
Operating Activities
Net cash provided by operating activities increased by 13%, or $56 million, in 2012 compared with 2011, primarily as a result of:
·
Other operating cash flows increased by $45 million driven by a $29 million reduction in pension funding.
·
Working capital cash flows increased by $11 million driven by lower income tax payments as a result of lower taxable income in 2012, offset by changes in receivables and unbilled revenues due to milder December weather in 2011 than in 2012 and 2010.
Net cash provided by operating activities increased by 19%, or $70 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 $19 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 $28 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.
Investing Activities
Net cash used in investing activities increased by 72%, or $201 million, in 2012 compared with 2011, as a result of an increase in capital expenditures of $201 million, primarily due to coal combustion residuals projects at Ghent and E.W. Brown, construction of Cane Run Unit 7 and Ghent environmental air projects.
See "Forecasted Uses of Cash" for detail regarding projected capital expenditures for the years 2013 through 2017.
Net cash used in investing activities decreased by 35%, or $150 million, in 2011 compared with 2010, as a result of a decrease in capital expenditures of $150 million primarily due to the completion of KU's scrubber program in 2010 and TC2 being dispatched in 2011.
Financing Activities
Net cash used in financing activities was $30 million in 2012 compared with net cash provided by financing activities of $137 million in 2011, primarily as a result of less long-term debt issuances and higher dividends to LKE.
In 2012, cash used in financing activities consisted of:
·
the payment of common stock dividends to LKE of $100 million; partially offset by
·
the issuance of short-term debt in the form of commercial paper $70 million.
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.
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.
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 had no long-term debt securities activity during the year.
See Note 7 to the Financial Statements for additional information about long-term debt securities.
Auction Rate Securities
At December 31, 2012, 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, 2012, the weighted-average rate on KU's auction rate bonds in total was 0.25%.
Forecasted Sources of Cash
KU expects to continue to have sufficient sources of cash available in the near term, including various credit facilities, its commercial paper program, issuance of debt securities and operating cash flow.
Credit Facilities
At December 31, 2012, KU's total committed borrowing capacity under its credit facilities and the use of this borrowing capacity were:
(a)
In November 2012, KU amended its Syndicated Credit Facility to extend the expiration date to November 2017.
(b)
In August 2012, the KU letter of credit facility agreement was amended and restated to allow for certain payments under the letter of credit facility to be converted to loans rather than requiring immediate payment.
(c)
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.
(d)
KU pays customary fees under its syndicated credit facility as well as its letter of credit facility, and borrowings generally bear interest at LIBOR-based rates plus an applicable margin.
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, 2012 there was no balance outstanding.
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.
Capital Contributions from LKE
From time to time LKE may make capital contributions to KU. KU may use these contributions to fund capital expenditures and for other general corporate purposes.
Long-term Debt Securities
KU currently plans to issue, subject to market conditions, up to $300 million of first mortgage bond indebtedness in 2013, the proceeds of which will be used to fund capital expenditures and for other general corporate purposes.
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 stock 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 2013 through 2017.
(a)
KU generally expects to recover these costs over a period equivalent to the related depreciable lives of the assets through rates. The 2013 total excludes amounts included in accounts payable as of December 31, 2012.
KU's capital expenditure projections for the years 2013 through 2017 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 existing and proposed EPA compliance standards. Actual costs may be significantly lower or higher depending on the final requirements and market conditions. 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 2013 with cash on hand, cash from operations, short-term debt and issuance of debt securities.
Contractual Obligations
KU has assumed various financial obligations and commitments in the ordinary course of conducting its business. At December 31, 2012, 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 has no 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 environmental air projects, Cane Run Unit 7 and Ghent landfill 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.
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%. See Note 7 to the Financial Statements for other restrictions related to distributions on capital interests for KU.
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 Actions
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. The credit ratings of KU affect its liquidity, access to capital markets and cost of borrowing under its credit facilities.
The following table sets forth KU's security credit ratings as of December 31, 2012.
In addition to the credit ratings noted above, the rating agencies took the following actions related to KU:
In February 2012, Fitch assigned ratings to KU's newly established commercial paper program.
In March 2012, Moody's affirmed the following ratings:
· the long-term ratings of the First Mortgage Bonds for KU;
· the issuer ratings for KU; and
· the bank loan ratings for KU.
Also in March 2012, Moody's and S&P each assigned short-term ratings to KU's newly established commercial paper program.
In December 2012, Fitch affirmed the issuer default ratings, individual security ratings and outlook 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, 2012. At December 31, 2012, 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 $21 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
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 sells excess economic generation 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. 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, 2012, 2011 and 2010 were not significant.
Interest Rate Risk
KU issues debt to finance its operations, which exposes it to interest rate risk. KU utilizes various financial derivative instruments to adjust the mix of fixed and floating interest rates in its debt portfolio when appropriate. Risk limits under KU's risk management program are designed to balance risk, exposure to volatility in interest expense and changes in the fair value of KU's debt portfolio due to changes in the absolute level of interest rates.
At December 31, 2012 and 2011, 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, 2012, would increase the fair value of its debt portfolio by $67 million compared with $72 million at December 31, 2011.
(a)
KU 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 KU is exposed to changes in the fair value of these instruments, any realized changes in the fair value of such cash flow 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, 2012 mature through 2043.
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.
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 expenditures 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.
Physical effects associated with climate change could include the impact of changes in weather patterns, such as storm frequency and intensity, and the resultant potential damage to KU's generation assets and electricity transmission and distribution systems, as well as impacts on customers. In addition, changed weather patterns could potentially reduce annual rainfall in areas where KU has hydro generating facilities or where river water is used to cool its fossil powered generators. KU cannot currently predict whether its businesses will experience these potential climate change-related risks or estimate the potential cost of their related consequences.
See "Item 1. Business - Environmental Matters" and Note 15 to the Financial Statements for a discussion of environmental matters.
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). 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.
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 electricity delivered to customers since the date of the last reading of their meters. The 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, 2012 and 2011, KU had unbilled revenue balances of $84 million and $81 million.
Defined Benefits
KU participates in a qualified funded defined benefit pension plan and a funded other postretirement benefit 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. The plan-specific cash flows are matched against the coupons and expected maturity values of individually selected bonds. This bond matching process begins with the full universe of Aa-rated non-callable (or callable with make-whole provisions) bonds, serving as the base from which those with the lowest and highest yields are eliminated to develop an appropriate subset of bonds. 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. At December 31, 2012, LKE decreased the discount rate for its pension plan from 5.12% to 4.26% and decreased the discount rate for its other postretirement benefit plan from 4.78% to 3.99%.
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, 2012, LKE's expected return on plan assets decreased from 7.25% to 7.10%.
In selecting a rate of compensation increase, LKE considers past experience in light of movements in inflation rates. At December 31, 2012, LKE's rate of compensation increase remained at 4.00%.
In selecting health care cost trend rates LKE considers past performance and forecasts of health care costs. At December 31, 2012, LKE's health care cost trend rates were 8.00% for 2013, 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, 2012, the defined benefit plans were recorded as follows:
The following chart reflects the sensitivities in the December 31, 2012 Balance Sheet associated with a change in certain assumptions based on KU's primary defined benefit plans.
(a)
Only impacts other postretirement benefits.
In 2012 KU recognized net periodic defined benefit costs charged to operating expense of $11 million. This amount represents a $3 million decrease from 2011. This decrease in expense for 2012 was primarily attributable to the increase in the expected return on plan assets resulting from pension contributions of $15 million, a reduction in the amortization of outstanding losses and lower interest cost.
The following chart reflects the sensitivities in the 2012 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.
Asset Impairment (Excluding Investments)
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 amount 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;
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a significant adverse change in the extent or manner in which an asset is being used or in its physical condition;
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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;
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a current-period operating or cash flow loss combined with a history of losses or a forecast that demonstrates continuing losses; or
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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 amount 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 amount 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, 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.
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 amount 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.
Beginning in 2012, KU may elect either to initially make a qualitative evaluation about the likelihood of an impairment of goodwill or to bypass the qualitative assessment and directly test goodwill for impairment using a two-step quantitative test. If the qualitative evaluation (referred to as "step zero") is elected and the assessment results in a determination that it is not more likely than not the fair value of the reporting unit is less than the carrying amount, the two-step quantitative impairment test is not necessary. However, the quantitative impairment test is required if KU concludes it is more likely than not the fair value of the reporting unit is less than the carrying amount based on the step zero assessment.
When the two-step quantitative impairment test is elected or required as a result of the step zero assessment, in step one, KU identifies a potential impairment by comparing the estimated fair value of KU (the goodwill reporting unit) with its carrying amount, 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 of the quantitative test 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 KU's 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 KU's goodwill.
KU elected to perform the two-step quantitative impairment test of goodwill in the fourth quarter of 2012 and no impairment was recognized. Management used both discounted cash flows and market multiples, which required significant assumptions, to estimate the fair value of KU. 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.
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 2012, no significant adjustments were made to KU's existing contingencies.
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."
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.
See Note 15 to the Financial Statements for additional information.
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. Since costs of removal are collected in rates, 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, 2012, KU had AROs totaling $69 million recorded on the Balance Sheet. Of the total amount, $51 million, or 74%, relates to KU's ash ponds and landfill. 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 and landfill at December 31, 2012:
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 derecognized, 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, 2012, 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, derecognition 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.
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.
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, 2012, KU had regulatory assets of $230 million and regulatory liabilities of $536 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.
See Note 6 to the Financial Statements for additional information on regulatory assets and liabilities.
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."
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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, 2012 and 2011, 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, 2012. 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 did not audit the 2010 financial statements of LG&E and KU Energy LLC (LKE), a wholly owned subsidiary, which statements reflect total revenues of $494 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, 2012 and 2011, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2012, in conformity with U.S. generally accepted accounting principles.
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, 2012, 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, 2013 expressed an unqualified opinion thereon.
/s/ Ernst & Young LLP
Philadelphia, Pennsylvania
February 28, 2013
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, 2012, 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.
In our opinion, PPL Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2012 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, 2012 and 2011, 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, 2012 and our report dated February 28, 2013 expressed an unqualified opinion thereon.
/s/ Ernst & Young LLP
Philadelphia, Pennsylvania
February 28, 2013
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, 2012 and 2011, 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, 2012. 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, 2012 and 2011, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2012, in conformity with U.S. generally accepted accounting principles.
/s/ Ernst & Young LLP
Philadelphia, Pennsylvania
February 28, 2013
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, 2012 and 2011, and the related consolidated statements of income, shareowners' equity, and cash flows for each of the three years in the period ended December 31, 2012. 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, 2012 and 2011, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2012, in conformity with U.S. generally accepted accounting principles.
/s/ Ernst & Young LLP
Philadelphia, Pennsylvania
February 28, 2013
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 sheets of LG&E and KU Energy LLC and subsidiaries as of December 31, 2012 and 2011, and the related consolidated statements of income and comprehensive income, cash flows, and equity for each of the two years in the period ended December 31, 2012. 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 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 LG&E and KU Energy LLC and subsidiaries at December 31, 2012 and 2011, and the consolidated results of their operations and their cash flows for each of the two years in the period ended December 31, 2012, 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, 2013
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, comprehensive income, cash flows, and equity present fairly, in all material respects, the results of operations and cash flows of LG&E and KU Energy LLC and its subsidiaries (Successor Company) 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, comprehensive income, cash flows, and equity 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 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 Board of Directors and Stockholder of Louisville Gas and Electric Company
We have audited the accompanying balance sheets of Louisville Gas and Electric Company as of December 31, 2012 and 2011, and the related statements of income and comprehensive income, cash flows, and equity for each of the two years in the period ended December 31, 2012. 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 financial position of Louisville Gas and Electric Company at December 31, 2012 and 2011, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2012, in conformity with U.S. generally accepted accounting principles.
/s/ Ernst & Young LLP
Louisville, Kentucky
February 28, 2013
Report of Independent Registered Public Accounting Firm
To the Stockholder of Louisville Gas and Electric Company
In our opinion, the accompanying statements of income, comprehensive income, cash flows, and equity present fairly, in all material respects, the results of operations and cash flows of Louisville Gas and Electric Company (Successor Company) 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, comprehensive income, cash flows, and equity 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 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 Board of Directors and Stockholder of Kentucky Utilities Company
We have audited the accompanying balance sheets of Kentucky Utilities Company as of December 31, 2012 and 2011, and the related statements of income and comprehensive income, cash flows, and equity for each of the two years in the period ended December 31, 2012. 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 financial position of Kentucky Utilities Company at December 31, 2012 and 2011, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2012, in conformity with U.S. generally accepted accounting principles.
/s/ Ernst & Young LLP
Louisville, Kentucky
February 28, 2013
Report of Independent Registered Public Accounting Firm
To the Stockholder of Kentucky Utilities Company
In our opinion, the accompanying statements of income, comprehensive income, cash flows, and equity present fairly, in all material respects, the results of operations and cash flows of Kentucky Utilities Company (Successor Company) 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, comprehensive income, cash flows, and equity 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 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
(a)
At December 31, 2012 and December 31, 2011, includes $428 million and $416 million of PP&E, consisting primarily of "Generation," including leasehold improvements, and $10 million 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; 581,944 and 578,405 shares issued and outstanding at December 31, 2012 and December 31, 2011.
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 at 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, and 2010 includes the June issuance of 103.5 million shares of common stock. See Note 7 for additional information. All years presented include shares of common stock issued through various stock and incentive compensation plans.
(d)
2011 includes $123 million for the 2011 Purchase Contracts and $20 million of related fees and expenses, net of tax. 2010 includes $157 million for the 2010 Purchase Contracts and $19 million of related fees and expenses, net of tax. See Note 7 for additional information.
(e)
2012, 2011 and 2010 include $47 million, $33 million and $26 million of stock-based compensation expense related to new and existing unvested equity awards, and $(29) million, $(23) million and $(18) million related primarily to the reclassification from "Stock-based compensation" to "Common stock issued" for the issuance of common stock after applicable equity award vesting periods and tax adjustments related to stock-based compensation.
(f)
"Earnings reinvested" includes dividends and dividend equivalents on PPL common stock and restricted stock units. "Noncontrolling interests" includes dividends, redemptions and distributions to noncontrolling interests. In April 2010 and June 2012, collectively, PPL Electric redeemed all of its outstanding preferred securities. See Note 3 for additional information on both redemptions.
The accompanying Notes to Financial Statements are an integral part of the financial statements.
(a)
At December 31, 2012 and December 31, 2011, includes $428 million and $416 million of PP&E, consisting primarily of "Generation," including leasehold improvements, and $10 million 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)
Net income approximates comprehensive income.
The accompanying Notes to Financial Statements are an integral part of the financial statements.
(a)
170,000 shares authorized; 66,368 shares issued and outstanding at December 31, 2012 and December 31, 2011.
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 and June 2012, collectively, PPL Electric redeemed all of its outstanding preferred securities. See Note 3 for additional information on both redemptions.
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.
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, 2012 and December 31, 2011.
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.
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, 2012 and December 31, 2011.
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). PPL's corporate level financing subsidiary is PPL Capital Funding.
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. WPD Midlands' operating results are included in PPL's results of operations for the full year of 2012, but as PPL is consolidating WPD Midlands on a one-month lag, eight months of 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 years of 2012 and 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 and PPL Energy Supply)
In April 2012, an indirect, wholly owned subsidiary of PPL Energy Supply completed the Ironwood Acquisition. See Note 10 for additional information.
(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 in Tennessee.
(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. 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.
(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 all 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 operates in an incentive-based regulatory structure under distribution licenses granted by Ofgem. Electricity distribution revenues are set by Ofgem every five years through price control reviews 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. As a result, WPD is not subject to accounting for the effects of certain types of regulation as prescribed by GAAP and does not record regulatory assets and liabilities.
Accounting Records (PPL, PPL Electric, LKE, LG&E and KU)
The system of accounts for domestic regulated entities 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 realization is assured.
Changes in Classification
The classification of certain amounts in the 2011 and 2010 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, 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)
See Note 9 for additional information.
LG&E had an AOCI balance that was a loss of $10 million at December 31, 2009 (a Predecessor period). LG&E had no AOCI balances at December 31, 2010, 2011 or 2012 (Successor periods). During the ten months ended October 31, 2010 (a Predecessor period), LG&E had $10 million of gains on qualifying derivatives that were recorded in OCI.
KU had no AOCI balances at December 31, 2009 (a Predecessor period), 2010 or 2011 (Successor periods). KU had an AOCI balance that was a gain of $1 million at December 31, 2012 (a Successor period) related to an equity investee's AOCI. KU recorded $2 million of losses related to an equity investee's OCI 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 floating-rate debt instruments or forecasted fixed-rate issuances of debt. Foreign currency exchange contracts are used to hedge foreign currency exchange exposures, primarily associated with PPL's investments in U.K. subsidiaries. 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, markets are periodically assessed to determine whether market mechanisms have evolved that would 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. The portion of derivative positions that deliver within a year are included in "Current Assets" and "Current Liabilities," while the portion of derivative positions that deliver beyond a year are recorded in "Other Noncurrent Assets" and "Deferred Credits and Other Noncurrent Liabilities."
Energy and energy-related contracts are assigned a strategy and accounting classification. Processes exist that allow for subsequent review and validation of the contract 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 contract 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 NPNS.
·
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 recorded at fair value through earnings.
·
Derivative transactions that do not qualify for NPNS or hedge accounting treatment are recorded at 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, to the extent the forecasted debt issuances remain probable of occurring.
·
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 foreign currency swaps and options to hedge GBP earnings translation risk associated with PPL's U.K. subsidiaries that report their financial statements in GBP. 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.
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)
For the years ended December 31, 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. 2010 includes two months of revenue for LKE.
(b)
Represents electric distribution revenue from the operation of WPD's distribution networks. 2011 includes eight months of revenue for WPD Midlands.
Revenue Recognition
(PPL, PPL Energy Supply, PPL Electric, LKE, LG&E and KU)
Operating revenues, except for certain energy and energy-related contracts that meet the definition of derivative instruments and "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. Any difference between estimated and actual revenues is adjusted the following month.
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 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. 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. Under recoveries are recovered and recorded in the next regulatory year. Over recoveries are reflected in the current period as a liability and are not included in revenue.
(PPL and PPL Energy Supply)
PPL Energy Supply records non-derivative energy marketing activity in the period when the energy is delivered. Generally, sales contracts 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 net hourly position. Certain energy and energy-related contracts that meet the definition of derivative instruments are recorded at fair value with subsequent changes in fair value recognized as revenue or expense (see Note 19), unless hedge accounting is applied. If derivatives meet cash flow hedging criteria, changes in fair value are recorded in AOCI. Derivative and non-derivative contracts that are designated as proprietary trading activities are reported net on the Statements of Income within "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 $12 million and $15 million at December 31, 2012 and 2011, and the amount of billings in excess of costs and estimated earnings was $70 million and $59 million at December 31, 2012 and 2011.
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)
In accordance with a PUC-approved purchase of accounts receivable program, PPL Electric purchases certain accounts receivable from alternative suppliers (including PPL EnergyPlus) at a nominal discount, which reflects a provision for uncollectible accounts. The alternative suppliers 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 2012, 2011 and 2010, PPL Electric purchased $848 million, $875 million and $617 million of accounts receivable from unaffiliated third parties. During 2012, 2011 and 2010, PPL Electric purchased $313 million, $264 million and $215 million of accounts receivable from 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 the 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)
Funds received by WPD, which are to be spent on approved initiatives to support a low carbon environment.
(b)
Funds required by law to be held by WPD's captive insurance company to meet claims.
(c)
Funds deposited with a trustee to defease PPL Electric's 1945 First Mortgage Bonds.
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" or "Other current assets" 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.
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 require that 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.
Unrealized gains and losses on available-for-sale equity securities are reported, net of tax, in OCI. When an equity security's decline in fair value below amortized cost is determined to be an other-than-temporary impairment, the unrealized loss is recognized currently in earnings. See Notes 18 and 23 for additional information on investments in debt and equity securities.
Equity Method Investment (PPL, LKE and KU)
Investments in entities over which PPL, LKE and KU have the ability to exercise significant influence, but not control, are accounted for using the equity method of accounting and are reported in "Other Investments" on PPL's Balance Sheet and in "Investments" on LKE's and KU's Balance Sheets. In accordance with the accounting guidance for equity method investments, the recoverability of the investment is periodically assessed. If an identified event or change in circumstances requires an impairment evaluation, the fair value of the investment is assessed. The difference between the carrying amount of the investment and its estimated fair value is recognized as an impairment loss when the loss in value is deemed other-than-temporary and such loss is included in "Other-Than-Temporary Impairments" on the Statements of Income.
KU owns 20% of the common stock of EEI, which is accounted for as an equity method investment. KU's direct exposure to loss as a result of its involvement with EEI is generally limited to the value of its investment. During 2012, KU recorded gains (losses) of $(8) million from its share of EEI's operating results. In December 2012, KU concluded that an other-than-temporary decline in the value of its investment in EEI had occurred. KU recorded an impairment charge of $25 million ($15 million, after-tax) which reduced the investment balance to zero, the estimated fair value at December 31, 2012. See Note 18 for additional information.
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. 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 approximately 134 MW for LG&E and approximately 60 MW for KU.
LG&E's 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 their investments; 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 an offsetting regulatory liability, both of which are being amortized using the units-of-production method until March 2026, the expiration date of the agreement. 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. PP&E acquired in a business combination is recorded at fair value at the time of acquisition. 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 associated with planned major maintenance projects are accrued in advance of the period in which the work is performed. 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 "Asset Retirement Obligations" below and Note 6 for additional information.
(PPL and PPL Energy Supply)
The original cost for the PP&E acquired in the Ironwood Acquisition is its fair value on April 13, 2012. See Note 10 for additional information on the acquisition.
(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. LKE and KU have 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.
Capitalized interest, excluding AFUDC for PPL, is as follows.
Depreciation
(PPL, PPL Energy Supply, PPL Electric, LKE, LG&E and KU)
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.
(PPL, LKE, LG&E and KU)
The KPSC approved new lower depreciation rates for LG&E and KU as part of the rate-case settlement agreement reached in November 2012. The new rates became effective January 1, 2013 and will result in lower depreciation of approximately $19 million ($9 million for LG&E and $10 million for KU) in 2013, exclusive of net additions to PP&E.
(PPL, PPL Energy Supply, PPL Electric, LKE, LG&E and KU)
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 obtain an initial license and 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. 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 (Excluding Investments)
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. See Note 18 for a discussion of impairments related to certain intangible assets.
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. See Note 15 for a discussion of the Corette coal-fired plant in Montana which was determined to not be impaired.
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.
PPL, PPL Energy Supply, LKE, LG&E and KU review goodwill 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 in circumstances when a portion of goodwill has been allocated to a business to be disposed of. PPL's, PPL Energy Supply's, LKE's, LG&E's and KU's reporting units are at the operating segment level. 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 U.K. Regulated segment. See Note 10 for additional information regarding the acquisition.
PPL, PPL Energy Supply, LKE, LG&E and KU tested the goodwill of all of their reporting units for impairment in the fourth quarter of 2012 and no impairment was recognized.
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 12 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 term of 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 future periods.
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, 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."
(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. The entity that generates a tax benefit is the entity that is entitled to the tax 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. At December 31, the following intercompany tax receivables (payables) were recorded.
Taxes, Other Than Income (PPL, PPL Energy Supply, PPL Electric, LKE, LG&E and KU)
The Registrants present sales taxes in "Other current liabilities" and PPL presents value-added taxes in "Taxes" on the 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)
The Registrants 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.
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)
WPD's functional currency is the GBP, which is the local currency in the U.K. As such, assets and liabilities are translated to U.S. dollars 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 foreign currency translation are recorded in OCI.
Gains or losses relating to foreign currency transactions are recognized in "Other Income (Expense) - net" on the Statements of Income. See Note 17 for additional information.
New Accounting Guidance Adopted (PPL, PPL Energy Supply, PPL Electric, LKE, LG&E and KU)
Fair Value Measurements
Effective January 1, 2012, the Registrants prospectively adopted accounting guidance that was issued to clarify existing fair value measurement guidance and to 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 Levels 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 fair value hierarchy classification for assets and liabilities whose fair value is disclosed only in the notes to the financial statements.
The adoption of this standard resulted in additional disclosures but did not have a significant impact on the Registrants. See Note 18 for additional disclosures required by this guidance.
Testing Goodwill for Impairment
Effective January 1, 2012, the Registrants prospectively adopted accounting guidance which allows 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 that 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 that the fair value of a reporting unit is less than the carrying amount based on the qualitative assessment.
The adoption of this standard did not have a significant impact on the Registrants.
2. Segment and Related Information
(PPL)
Since the acquisition of LKE on November 1, 2010, PPL is organized into four segments: Kentucky Regulated, U.K. Regulated (name change in 2012 from International Regulated to more specifically reflect the focus of the segment), Pennsylvania Regulated and Supply. Other than the name change for the U.K. Regulated segment, there were no other changes to this segment. 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 is allocated certain financing costs. See Note 10 for additional information regarding the acquisition.
The U.K. 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 U.K. Regulated segment is also allocated certain WPD Midlands acquisition-related costs and financing costs. 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.
The results of operations 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 Shareowners" the operating results from these facilities and businesses have been excluded from the income statement data tables below.
"Corporate and Other" represents costs incurred at the corporate level that have not been allocated or assigned to the segments, which is presented to reconcile segment information to PPL's consolidated results. For 2012 and 2011, there were no significant costs in this category. For 2010, these costs represent LKE acquisition-related costs including advisory, accounting and legal fees, certain internal costs and 2010 Bridge Facility costs.
Beginning in 2013, PPL anticipates more costs to be included in the Corporate and Other category primarily due to an anticipated increase in the use of financing issued by PPL Capital Funding not directly attributable to a particular segment. PPL's recent growth in rate-regulated businesses provides the organization with an enhanced corporate level financing alternative, through PPL Capital Funding, that further enables PPL to support targeted credit profiles cost effectively across all of PPL's rated companies. As a result, PPL plans to further utilize PPL Capital Funding in addition to continued direct financing by the operating companies, as appropriate. The financing costs associated primarily with PPL Capital Funding's future securities issuances are not expected to be directly assignable or allocable to any segment and generally will be reflected in Corporate and Other beginning in 2013.
Financial data for the segments are:
(a)
See Note 1 for additional information on Utility Revenue.
(b)
Includes unrealized gains and losses from economic activity. See Note 19 for additional information.
(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)
Represents both current and deferred income taxes, including investment tax credits.
(f)
Represents a non-cash expense item that is also included in "Income Taxes."
(PPL Energy Supply, PPL Electric, LKE, LG&E and KU)
PPL Energy Supply, PPL Electric, LKE, LG&E and KU each operate within a single reportable segment.
3. Preferred Securities
(PPL)
PPL classifies preferred securities of subsidiaries as "Noncontrolling interests" on the Balance Sheets and related dividend requirements of $4 million for 2012, $16 million for 2011 and $17 million for 2010 have been included in "Net Income Attributable to Noncontrolling Interests" on the Statements of Income. In June 2012, PPL Electric redeemed all of its Preference Stock at par value, without premium ($250 million in the aggregate).
Preferred Stock
PPL is authorized to issue up to 10 million shares of preferred stock. No PPL preferred stock was issued or outstanding in 2012, 2011, or 2010.
(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. In April 2010, PPL Electric redeemed all of its outstanding preferred stock (247,524 shares of 4-1/2% Preferred Stock and 257,665 shares of four series of preferred stock), with a par value in the aggregate of $51 million, for $54 million including accumulated dividends.
(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 2012, 2011 or 2010.
(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 2012, 2011 or 2010.
Preference Stock
(PPL Electric)
PPL Electric is authorized to issue up to 10 million shares of Preference Stock and had 2.5 million shares of 6.25% Series Preference Stock (Preference Shares) issued and outstanding at December 31, 2011 and 2010. In June 2012, PPL Electric redeemed all 2.5 million shares of its outstanding Preference Shares, par value of $100 per share. The price paid for the redemption was the par value, without premium ($250 million in the aggregate).
The Preference Shares were held by a bank that acted as depositary for 10 million depositary shares, each of which represented a one-quarter interest in a Preference Share. Holders of the depositary shares were 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 ranked senior to PPL Electric's common stock but had no voting rights, except as provided by law, and they had a liquidation preference of $100 per share (equivalent to $25 per depositary share).
(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 2012, 2011 or 2010.
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 2012, 2011 and 2010, these securities included stock options and performance units granted under incentive compensation plans and the Purchase Contracts associated with the 2011 and 2010 Equity Units. For 2012, these securities also included the PPL common stock forward sale agreements. See Note 7 for additional information on the forward sale agreements. The forward sale agreements were dilutive under the treasury stock method for 2012 because the average stock price of PPL's common shares exceeded the forward sale price indicated in the forward sale agreements.
The Purchase Contracts are dilutive under the treasury stock method if the average VWAP of PPL common stock for a certain period exceeds approximately $30.99 and $28.80 for the 2011 and 2010 Purchase Contracts. The 2010 Purchase Contracts were dilutive for 2012 and 2011. Subject to antidilution adjustments at December 31, 2012, the maximum number of shares issuable to settle the Purchase Contracts was 93.8 million shares, including 86.6 million shares that could be issued under standard provisions of the Purchase Contracts and 7.2 million 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 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 2012, PPL issued 936,218 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 279,945 and 2,326,917 shares of common stock related to its ESOP and DRIP during 2012. See Note 12 for a discussion of PPL's stock-based compensation plans.
The following stock options to purchase PPL common stock and performance units were excluded from the computations of diluted EPS for the years ended December 31 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 and liabilities 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:
At December 31, PPL had the following loss and tax credit carryforwards.
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)
The reduction of the U.K. statutory income tax rate resulted in a reduction in deferred tax assets and the corresponding valuation allowances. See "Reconciliation of Income Tax Expense" below for more information on the impact of the U.K. Finance Act of 2012.
(b)
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.
(c)
The reduction of the U.K. statutory income tax rate resulted in a $35 million reduction in deferred tax assets and the corresponding valuation allowances. See "Reconciliation of Income Tax Expense" below for more information on the impact of the U.K. Finance Act of 2011.
(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.
PPL Global does not pay or record U.S. income taxes on the undistributed earnings of WPD, with the exception of certain financing entities, 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 indefinitely reinvested at December 31, 2012 and 2011 were $2.0 billion and $1.2 billion. If the WPD undistributed 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 and state tax expense (benefit) recorded to Discontinued Operations of $(4) million in 2012, $2 million in 2011 and $(6) million in 2010. Excludes realized tax expense (benefits) related to stock-based compensation, recorded as a decrease (increase) to additional paid-in capital of $(1) million in 2012, $3 million in 2011 and an insignificant amount in 2010. Excludes tax benefits related to the issuance costs of the Purchase Contracts, recorded as an increase to additional paid-in capital of an insignificant amount in 2012, $5 million in 2011 and $10 million in 2010, offset by an insignificant amount of related valuation allowances for state deferred taxes in 2012 and 2011. Also excludes federal, state, and foreign tax expense (benefit) recorded to OCI of $(526) million in 2012, $(137) million in 2011 and $83 million in 2010, and related valuation allowances for state deferred taxes of an insignificant amount in 2012 and $3 million in 2011.
(a)
During 2011, the Pennsylvania Department of Revenue issued interpretive guidance on the treatment of bonus depreciation for Pennsylvania income tax purposes. The guidance 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 projected 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 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. The federal provision for 100% bonus depreciation generally applies to property placed into service before January 1, 2012. The placed in-service deadline is extended to January 1, 2013 for property that has a cost in excess of $1 million, has a production period longer than one year and has a tax life of at least ten years. PPL's tax deduction for 100% bonus regulated tax depreciation was significantly lower in 2012 than in 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 in 2010, PPL recorded a $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)
The U.K.'s Finance Act of 2012, enacted in July 2012, reduced the U.K. statutory income tax rate from 25% to 24% retroactive to April 1, 2012 and from 24% to 23% effective April 1, 2013. As a result, PPL reduced its net deferred tax liabilities and recognized a deferred tax benefit during 2012 related to both rate decreases.
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 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.
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, PPL reduced its net deferred tax liabilities and recognized a deferred tax benefit during 2010.
(c)
During 2012, PPL recorded a $23 million adjustment to federal income tax expense related to the recalculation of 2010 U.K. earnings and profits and $19 million of U.S. income tax expense on foreign earnings of certain U.K. financing entities not indefinitely reinvested.
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 primarily resulting from increased taxable dividends.
(d)
In 1997, the U.K. imposed a Windfall Profits Tax (WPT) on privatized utilities, including WPD. PPL filed its federal income 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, 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. In February 2012, PPL filed a petition for rehearing of the Third Circuit's opinion. In March 2012, the Third Circuit denied PPL's petition. In June 2012, the U.S. Court of Appeals for the Fifth Circuit issued a contrary opinion in an identical case involving another company. In July 2012, PPL filed a petition for a writ of certiorari seeking U.S. Supreme Court review of the Third Circuit's opinion. The Supreme Court granted PPL's petition on October 29, 2012, and oral argument was held on February 20, 2013. PPL expects the case to be decided before the end of the Supreme Court's current term in June 2013 and cannot predict the outcome of this matter.
In July 2010, the 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.
PPL recorded a tax benefit of $6 million during 2012 and 2011 and $7 million during 2010 to federal and state income tax reserves related to stranded cost securitization.
(e)
During 2012, PPL recorded a foreign tax benefit following resolution of a U.K. tax issue related to interest expense.
During 2011, WPD reached an agreement with HMRC 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 utilized.
(f)
During 2012, PPL recorded federal and state income tax expense related to the filing of the 2011 federal and state income tax returns. Of this amount, $5 million relates to the reversal of prior years' state income tax benefits related to regulated depreciation. PPL changed its method of accounting for repair expenditures for tax purposes effective for its 2008 tax year. In August 2011, the IRS issued guidance regarding the use and evaluation of statistical samples and sampling estimates for network assets. The IRS guidance provided a safe harbor method of determining whether the repair expenditures for electric transmission and distribution property can be currently deducted for tax purposes. PPL adopted the safe harbor method with the filing of its 2011 federal income tax return.
During 2011, PPL recorded 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 related to an additional domestic manufacturing deduction resulting from revised bonus depreciation amounts and $3 million in tax benefits related to the flow-through impact of Pennsylvania regulated state tax depreciation.
(g)
In December 2010, Congress enacted legislation allowing for 100% bonus depreciation on qualified property. The increased tax depreciation eliminated the tax benefits related to domestic manufacturing deductions in 2012 and 2011.
(h)
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.
(i)
During 2012, 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)
In 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 reductions in the future estimated state tax rate, PPL recorded deferred tax benefits related to its December 31, 2012 and 2011 state deferred tax liabilities.
(k)
During 2012, PPL recorded adjustments to deferred taxes related to net operating loss carryforwards of LKE based on income tax return adjustments.
(l)
During 2012 and 2011, PPL recorded foreign income tax benefits related to interest expense on intercompany loans for which there was no domestic income tax expense.
(a)
The increase between 2011 and 2010 is due primarily to the acquisition of WPD Midlands on April 1, 2011. See Note 10 for additional information.
(b)
The increase between 2011 and 2010 is due primarily to the acquisition of LKE on November l, 2010. See Note 10 for additional information.
(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. 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:
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.
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 and $(5) million in 2010. Also, excludes federal, state and foreign tax expense (benefit) recorded to OCI of $(267) million in 2012, $(83) million in 2011 and $132 million in 2010. The deferred tax benefit of operating loss carryforwards was insignificant for 2011 and 2010.
(a)
During 2011, the Pennsylvania Department of Revenue issued interpretive guidance on the treatment of bonus depreciation for Pennsylvania income tax purposes. The guidance 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 projected 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)
In 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 reductions in the future estimated state tax rate, PPL Energy Supply recorded deferred tax benefits related to its December 31, 2012 and 2011 state deferred tax liabilities.
(c)
In December 2010, Congress enacted legislation allowing for 100% bonus depreciation on qualified property. The increased tax depreciation deduction eliminated the tax benefits related to domestic manufacturing deductions in 2012 and 2011.
(d)
During 2011, PPL recorded 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 related to an additional domestic manufacturing deduction resulting from revised bonus depreciation amounts.
(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 2012, 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 and liabilities 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 liabilities and the amount that otherwise would be recorded under GAAP is deferred and included in "Regulatory assets" or "Regulated liabilities" 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.
PPL Electric recorded a tax benefit of $6 million during 2012 and 2011 and $7 million during 2010 to federal and state income tax reserves related to stranded cost securitization.
(b)
PPL Electric changed its method of accounting for repair expenditures for tax purposes effective for its 2008 tax year. In August 2011, the IRS issued guidance regarding the use and evaluation of statistical samples and sampling estimates for network assets. The IRS guidance provided a safe harbor method of determining whether the repair expenditures for electric transmission and distribution property can be currently deducted for tax purposes. PPL Electric adopted the safe harbor method with the filing of its 2011 federal income tax return and recorded a $5 million adjustment to federal and state income tax expense resulting from the reversal of prior years' state income tax benefits related to regulated depreciation.
During 2011, PPL Electric recorded a $5 million federal and state income tax benefit as a result of filing its 2010 federal and state income tax returns. Of this amount, $3 million in tax benefits related to the flow-through impact of Pennsylvania regulated 100% bonus tax depreciation.
(c)
During 2011, the Pennsylvania Department of Revenue issued interpretive guidance on the treatment of bonus depreciation for Pennsylvania income tax purposes. The guidance 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. The federal provision for 100% bonus depreciation generally applies to property placed into service before January 1, 2012. The placed in-service deadline is extended to January 1, 2013 for property that has a cost in excess of $1 million, has a production period longer than one year and has a tax life of at least ten years. PPL Electric's tax deduction for 100% bonus depreciation was significantly lower in 2012 than in 2011.
(a)
2011 includes PURTA tax that was refunded to PPL Electric customers in 2011.
(LKE)
The provision for LKE's deferred income taxes for regulated assets and liabilities 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 liabilities and the amount that otherwise would be recorded under GAAP is deferred and included in "Regulatory assets" or "Regulatory liabilities" on the Balance Sheets.
Significant components of LKE's deferred income tax assets and liabilities were as follows:
LKE expects to have adequate levels of taxable income to realize its recorded deferred income tax assets.
At December 31, LKE had the following loss and tax credit carryforwards.
Changes in deferred tax valuation allowances were:
(a)
Primarily related to the expiration of state capital loss carryforwards.
(b)
A valuation allowance was recorded against deferred tax assets for state capital loss carryforwards.
(c)
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 (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 and state tax expense (benefit) recorded to Discontinued Operations of $(4) million in 2012, $(1) million in 2011, $1 million for the two month period ended December 31, 2010 and $(1) million for the ten month period ended October 31, 2010. Also, excludes deferred federal and state tax expense (benefit) recorded to OCI of $(12) million in 2012, $(1) million in 2011, $3 million for the two month period ended December 31, 2010 and $(7) million for the ten month period ended October 31, 2010.
(a)
During 2012, LKE recorded adjustments to deferred taxes related to net operating loss carryforwards based on income tax return adjustments.
(LG&E)
The provision for LG&E's deferred income taxes for regulated assets and liabilities 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 liabilities and the amount that otherwise would be recorded under GAAP is deferred and included in "Regulatory assets" or "Regulatory liabilities" on the Balance Sheets.
Significant components of LG&E's deferred income tax assets and liabilities were as follows:
LG&E expects to have adequate levels of taxable income to realize its recorded deferred income tax assets.
At December 31, 2012, LG&E had $22 million of state net operating loss carryforwards that expire in 2030.
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.
(KU)
The provision for KU's deferred income taxes for regulated assets and liabilities 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 liabilities and the amount that otherwise would be recorded under GAAP is deferred and included in "Regulatory assets" or "Regulatory liabilities" on the Balance Sheets.
Significant components of KU's deferred income tax assets and liabilities were as follows:
KU expects to have adequate levels of taxable income to realize its recorded deferred income tax assets.
At December 31, 2012, KU had $56 million of federal net operating loss carryforwards that expire in 2032.
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 in 2012 and $(1) million for the ten month period ended October 31, 2010.
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, 2012 and December 31, 2011.
At December 31, 2012, 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, 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 agreement 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, 2012, 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 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.
Other (PPL and PPL Energy Supply)
PPL changed its method of accounting for repair expenditures for tax purposes effective for its 2008 tax year for Pennsylvania operations. PPL made the same change for its Montana operations for tax year 2009. In 2011, the IRS issued guidance on repair expenditures related to network assets providing a safe harbor method of determining whether the repair expenditures can be currently deducted for tax purposes. The IRS has not yet issued guidance to provide a safe harbor method related to 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 established an adequate reserve for this contingency.
Tax Legislation (PPL, PPL Energy Supply, PPL Electric, LKE, LG&E and KU)
On January 2, 2013, H.R. 8, The American Taxpayer Relief Act of 2012, was signed into law. The most significant extension of tax relief under this Act applicable to PPL is the extension of bonus depreciation. This provision extends the current 50% expensing provision for qualifying property purchased and placed in service before January 1, 2014 (before January 1, 2015 for certain longer-lived and transportation assets). PPL is still evaluating the changes. However, PPL does not expect that the changes related to this legislation will have a material impact on income tax expense.
6. Utility Rate Regulation
Regulatory Assets and Liabilities
(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 short-term debt) including certain adjustments to exclude non-regulated investments and costs recovered separately through other rate mechanisms. As such, LG&E and KU earn a return on the net cash invested in regulatory assets and regulatory liabilities.
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 LKE's 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)
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.
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.
Act 129 Compliance Rider
In compliance with Pennsylvania's Act 129 of 2008 and implementing regulations, PPL Electric's energy efficiency and conservation plan was approved by a 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 recovered 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.
Transmission Formula Rates
PPL Electric's transmission revenues are billed in accordance with a FERC-approved open access transmission tariff that utilizes a formula-based rate recovery mechanism. The formula rate is based on prior year expenditures and forecasted current calendar year transmission plant additions. An adjustment to the prior year expenditures is recorded as a regulatory asset or liability.
(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 and are amortized over the average service lives of plan participants. 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, costs of $60 million for PPL, $22 million for PPL Electric, $38 million for LKE, $24 million for LG&E and $14 million for KU are expected to be amortized into net periodic defined benefit costs in 2013.
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.
Accumulated Cost of Removal of Utility Plant
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 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 typically recovered within 12 months. LG&E and KU are authorized to receive a 10.63% and 10.10% return on projects associated with the 2009 and 2011 compliance plans. As a result of the settlement agreement in the 2012
rate case, beginning in 2013, LG&E and KU will receive a 10.25% return on all ECR projects included in the 2009 and 2011 compliance plans.
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 Adjustment Clauses
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 typically 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 OCI 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)
In November 2012, LG&E and KU entered into forward-starting interest rate swaps with PPL that hedge the interest payments on new debt that is expected to be issued in 2013. These hedging instruments have terms identical to forward-starting swaps entered into by PPL with third parties. LG&E and KU believe that realized gains and losses from the swaps are probable of recovery through regulated rates; as such, the fair value of these derivatives have been reclassified from AOCI to regulatory assets or liabilities. The gains and losses will be recognized in "Interest Expense" on the Statements of Income over the life of the underlying debt. See Note 19 for additional information related to the forward-starting interest rate swaps.
AROs
As discussed 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.
Power Purchase Agreement - OVEC
As a result of purchase accounting associated with PPL's acquisition of LKE, the fair values of the OVEC power purchase agreement were recorded on the balance sheets of LKE, LG&E and KU 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.
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)
Rate Case Proceedings
In June 2012, LG&E and KU filed requests with the KPSC for increases in annual base electric rates of approximately $62 million at LG&E and approximately $82 million at KU and an increase in annual base gas rates of approximately $17 million at LG&E. In November 2012, LG&E and KU along with all of the parties filed a unanimous settlement agreement. Among other things, the settlement provided for increases in annual base electric rates of $34 million at LG&E and $51 million at KU and an increase in annual base gas rates of $15 million at LG&E. The settlement agreement also included revised depreciation rates that result in reduced annual electric depreciation expense of approximately $9 million for LG&E and approximately $10 million for KU. The settlement agreement included an authorized return on equity at LG&E and KU of 10.25%. On December 20, 2012, the KPSC issued orders approving the provisions in the settlement agreement. The new rates became effective on January 1, 2013. In addition to the increased base rates, the KPSC approved a gas line tracker mechanism for LG&E to provide for recovery of costs associated with LG&E's gas main replacement program, gas service lines and risers.
Independent Transmission Operators
In September 2012, LG&E and KU completed the transition of their independent transmission operator contractual arrangements from Southwest Power Pool, Inc. to TranServ International, Inc. This change had previously received approvals of the FERC and the KPSC.
(PPL, LKE and LG&E)
CPCN Filing
In October 2012, LG&E filed an application with the KPSC to construct a new wet scrubber to serve Unit 3 at the Mill Creek Generating Station. The application partially modifies the existing authority granted by the KPSC in 2011, which authorized LG&E to build two new scrubbers to serve Mill Creek Units 1 and 2 and another to serve Mill Creek Unit 4. Additionally, authority was granted allowing the Mill Creek Unit 3 to be served by the existing Unit 4 scrubber. The CPCN sought approval to construct a new wet scrubber on Mill Creek Unit 3 instead of utilizing the Unit 4 scrubber. In February 2013, LG&E received the requested KPSC approval to construct a new wet scrubber to serve Unit 3 at the Mill Creek Generating Station.
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 the request. On December 20, 2012, the KPSC in the approval of the unanimous rate case settlement agreement, authorized regulatory asset recovery effective January 1, 2013, over a five year period.
Pennsylvania Activities (PPL and PPL Electric)
Rate Case Proceeding
In March 2012, PPL Electric filed a request with the PUC to increase distribution rates by approximately $105 million, effective January 1, 2013. In its December 28, 2012 final order, the PUC approved a 10.4% return on equity and a total distribution revenue increase of about $71 million. The approved rates became effective January 1, 2013.
Also, in its December 28, 2012 final order, the PUC directed PPL Electric to file a proposed Storm Damage Expense Rider within 90 days following the order. PPL Electric plans to file a proposed Storm Damage Expense Rider with the PUC and, as part of that filing, request recovery of the $28 million of qualifying storm costs incurred as a result of the October 2012 landfall of Hurricane Sandy. See "Storm Costs" below for additional information regarding Hurricane Sandy.
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 reduce overall electricity consumption by 1.0% by May 2011 and, by May 2013, reduce overall electricity consumption by 3.0% and reduce peak demand by 4.5%. The peak demand reduction must occur for the 100 hours of highest demand, which is determined by actual demand reduction during the June 2012 through September 2012 period. EDCs will be able to recover the costs (capped at 2.0% of the EDC's 2006 revenue) of implementing their EE&C Plans. In October 2009, the PUC approved PPL Electric's EE&C Plan, and in March 2012 confirmed that PPL Electric met the 2011 requirement. PPL Electric will determine if it met the peak demand reduction target and the May 2013 energy reduction target after it completes the final program evaluation on November 5, 2013.
Act 129 requires the PUC to evaluate the costs and benefits of the EE&C program by November 30, 2013 and adopt additional reductions if the benefits of the program exceed the costs. In August 2012, after receiving input from stakeholders, the PUC issued a Final Implementation Order establishing a three-year Phase II program, ending May 31, 2016, with individual consumption reduction targets for each EDC. PPL Electric's reduction target is 2.1%. The PUC did not establish demand reduction targets for the Phase II program. PPL Electric filed its Phase II EE&C Plan with the PUC on November 15, 2012 and the PUC is expected to issue its decision in March 2013. Act 129 also requires the Default Service Provider (DSP) to provide electric generation supply service to customers pursuant to a PUC-approved default service 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 load unless otherwise approved by the PUC. The DSP will be able to recover the costs associated with a competitive procurement plan.
The PUC has approved PPL Electric's procurement plan for the period January 1, 2011 through May 31, 2013, and PPL Electric concluded all competitive solicitations to procure power for its PLR obligations under that plan.
The PUC has directed all EDCs to file default service procurement plans for the period June 1, 2013 through May 31, 2015. PPL Electric filed its plan in May 2012. In that plan, PPL Electric proposed a process to obtain supply for its default service customers and a number of initiatives designed to encourage more customers to purchase electricity from the competitive retail market. In its January 24, 2013 final order, the PUC approved PPL Electric's plan with modifications and directed PPL Electric to establish collaborative processes to address several retail competition issues.
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 was 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. In August 2012, PPL Electric filed with the PUC an annual report describing the actions it was taking under its Smart Meter plan in 2012 and its planned actions for 2013. PPL Electric also submitted revised SMR charges which became effective January 1, 2013.
PUC Investigation of Retail Electricity 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 existing retail market and explored potential changes. Questions issued by the PUC for this phase of the investigation focused primarily on default service issues. Phase two was initiated in July 2011 to develop specific proposals for changes to the retail market and default service model. 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. In March 2012, the PUC entered a final order on the intermediate work plan, issued three possible models for the default service "end state" and held a hearing regarding those three models. In September 2012, the PUC issued a Secretarial Letter setting forth an "RMI End State Proposal" for discussion. The PUC issued a tentative implementation order in early November 2012, following which parties had 30 days to provide comment. PPL Electric and PPL EnergyPlus filed joint comments. A final implementation order was issued on February 15, 2013. Although the final implementation order contains provisions that will require numerous modifications to PPL Electric's current default service model for retail customers, those modifications are not expected to have a material adverse effect on PPL Electric's results of operations.
Legislation - Regulatory Procedures and Mechanisms
Act 11 authorizes the PUC to approve two specific ratemaking mechanisms - the use of a fully projected future test year in base rate proceedings and, subject to certain conditions, the use of a DSIC. Such alternative ratemaking procedures and mechanisms provide opportunity for accelerated cost-recovery and, therefore, are important to PPL Electric as it begins a period of significant capital investment to maintain and enhance the reliability of its delivery system, including the replacement of aging distribution assets. In August 2012, the PUC issued a Final Implementation Order adopting procedures, guidelines and a model tariff for the implementation of Act 11. Act 11 requires utilities to file an LTIIP as a prerequisite to filing for recovery through the DSIC. The LTIIP is mandated to be a five- to ten-year plan describing projects eligible for inclusion in the DSIC. In September 2012, PPL Electric filed its LTIIP describing projects eligible for inclusion in the DSIC. The PUC approved the LTIIP on January 10, 2013 and PPL Electric filed a petition requesting permission to establish a DSIC on January 15, 2013, with rates proposed to be effective beginning May 1, 2013.
Storm Costs
During 2012, PPL Electric experienced several PUC-reportable storms, including Hurricane Sandy, resulting in total restoration costs of $81 million, of which $61 million were initially recorded in "Other operation and maintenance" on the Statement of Income. In particular, in late October 2012, PPL Electric experienced widespread significant damage to its distribution network from Hurricane Sandy resulting in total restoration costs of $66 million, of which $50 million were initially recorded in "Other operation and maintenance" on the Statement of Income. Although PPL Electric had storm insurance coverage, the costs incurred from Hurricane Sandy exceeded the policy limits. Probable insurance recoveries recorded during 2012 were $18.25 million, of which $14 million were included in "Other operation and maintenance" on the Statement of Income. PPL Electric recorded a regulatory asset of $28 million in December 2012 (offset to "Other operation and maintenance" on the Statement of Income). In February 2013, PPL Electric received an order from the PUC granting permission to defer qualifying storm costs in excess of insurance recoveries associated with Hurricane Sandy. See "Rate Case Proceeding" above for information regarding PPL Electric's plan to file a proposed Storm Damage Expense Rider with the PUC.
PPL Electric experienced several PUC-reportable storms during 2011 including Hurricane Irene and a late October snow storm. Total restoration costs were $84 million, of which $54 million were initially recorded in "Other operation and maintenance" on the Statement of Income. Although PPL Electric had storm insurance coverage with a PPL affiliate, the costs associated with the unusually high number of PUC-reportable storms 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 Statements 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 2011 snowstorm. PPL Electric recorded a regulatory asset of $25 million in December 2011 (offset to "Other operation and maintenance" on the Statement of Income). The PUC granted PPL Electric's recovery of the 2011 storm costs in its final order in the 2012 rate case. Recovery began in January 2013 and will continue over a five year period.
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.
PPL Electric has initiated its formula rate 2012, 2011 and 2010 Annual Updates. Each update has been subsequently challenged by a group of municipal customers, which challenges have been opposed by PPL Electric. In August 2011, the FERC issued an order substantially rejecting the 2010 formal challenge and the municipal customers filed a request for rehearing of that order. In September 2012, the FERC issued an order setting for evidentiary hearings and settlement judge procedures a number of issues raised in the 2010 and 2011 formal challenges. Settlement conferences were held in late 2012 and early 2013. In February 2013, the FERC set for evidentiary hearings and settlement judge procedures a number of issues in the 2012 formal challenge and consolidated that challenge with the 2010 and 2011 challenges. PPL Electric anticipates that there will be additional settlement conferences held in 2013. PPL and PPL Electric cannot predict the outcome of the foregoing proceedings, which remain pending before the FERC.
In March 2012, PPL Electric filed a request with the FERC seeking recovery of its 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. At December 31, 2012 and 2011, $52 million and $53 million respectively, are classified as taxes recoverable through future rates and included on the Balance Sheets in "Other Noncurrent Assets - Regulatory assets." In May 2012, the FERC issued an order approving PPL Electric's request to recover the deferred tax regulatory asset over a 34-year period beginning June 1, 2012.
U.K. Activities (PPL)
Ofgem Review of Line Loss Calculation
WPD had a $94 million liability recorded at December 31, 2012, compared with $170 million at December 31, 2011, related to the close-out of line losses for the prior price control period, DPCR4. Ofgem is currently consulting on the methodology to be used by all network operators 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. In March 2012, Ofgem issued a decision regarding the preferred methodology. In July 2012, Ofgem issued a
consultation paper regarding certain aspects of the preferred methodology as it relates to the DPCR4 line loss incentive/penalty and a proposal to delay the target date for making a final decision until April 2013. In October 2012, a license modification was issued to allow Ofgem to publish the final decisions on these matters by April 2013. In November 2012, Ofgem issued an additional consultation on the final DPCR4 line loss close-out that published values for each DNO and further indicated the preferred methodology that would replace the methodology under WPD's licenses. Based on applying the preferred methodology for DPCR4, the liability was reduced by $79 million, with a credit recorded in "Utility" on the Statement of Income, to reflect what WPD expects to be the final close-out settlement under Ofgem's preferred methodology. This consultation also confirmed the final decisions will be published by April 2013. In February 2013, Ofgem issued additional consultation proposing to delay the April 2013 decision date. PPL cannot predict when this matter will be resolved.
Ofgem also stated in the November 2012 consultation that the line loss incentive implemented at the last rate review will be withdrawn and no incentive will apply for the DPCR5 period. That decision resulted in the elimination of the DPCR5 liability of $11 million, with a credit recorded in "Utility" on the Statement of Income.
European Market Infrastructure Regulation
Regulation No. 648/2012 of the European Parliament and of the Council, commonly referred to as the European Market Infrastructure Regulation (EMIR), entered into force on August 16, 2012 and the European Commission adopted most of the Regulatory Technical Standards without modification in December 2012. The EMIR establishes certain transaction clearing and other recordkeeping requirements for parties to over-the-counter derivatives transactions. Included in the derivative transactions that are subject to EMIR are certain interest rate and currency derivative contracts utilized by WPD. Generally, WPD is expected to qualify under the EMIR as a non-financial counterparty to the transactions in which it engages and further to qualify for certain exemptions that will relieve WPD from the mandatory clearing obligations imposed by the EMIR. Although the EMIR will potentially impose significant additional recordkeeping requirements on WPD, the effect of the EMIR is not currently expected to have a significant adverse impact on WPD's financial condition or results of operation.
7. Financing Activities
Credit Arrangements and Short-term Debt
(PPL, PPL Energy Supply, PPL Electric, LKE, LG&E and KU)
The Registrants maintain credit facilities to enhance liquidity, provide credit support, and provide a backstop to commercial paper programs. For reporting purposes, on a consolidated basis, the credit facilities of PPL Energy Supply, PPL Electric, LG&E and KU also apply to PPL and the credit facilities of LG&E and KU also apply to LKE. The following credit facilities were in place at:
(a)
Amounts borrowed are recorded as "Short-term debt" on the Balance Sheets.
(b)
In December 2012, the PPL WW credit facility was subsequently replaced with a credit facility expiring in December 2016 and the capacity was increased to £210 million.
(c)
The facilities contain financial covenants that require the company 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, calculated in accordance with the credit facility.
(d)
Under these facilities, WPD (East Midlands) and WPD (West Midlands) each have the ability to request the lenders to issue up to £80 million of letters of credit in lieu of borrowing.
(e)
The total amounts borrowed at December 31, 2012 and 2011 were USD-denominated borrowings of $171 million and $178 million, which equated to £106 million and £111 million at the time of the borrowings. The interest rates at December 31, 2012 and 2011 were 0.8452% and 1.05%. At December 31, 2012, the unused capacity of WPD's credit facilities was approximately $1.6 billion.
(f)
Each company pays customary fees under its respective facility and borrowings generally bear interest at LIBOR-based rates plus an applicable margin.
(g)
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.
(h)
The facilities contain a financial covenant requiring debt to total capitalization not to exceed 65% for PPL Energy Supply and 70% for PPL Electric, LG&E and KU, as calculated in accordance with the facilities and other customary covenants. Additionally, as it relates to the syndicated credit facilities and subject to certain conditions, PPL Energy Supply may request that its facility's capacity be increased by up to $500 million and PPL Electric and KU each may request up to a $100 million increase in its facility's' capacity.
(i)
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, 2012 and December 31, 2011, $238 million and $251 million of accounts receivable and $106 million and $98 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, 2012, the amount available for borrowing under the facility was $100 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.
(j)
KU's letter of credit facility agreement allows for certain payments under the letter of credit facility to be converted to loans rather than requiring immediate payment.
(k)
In February 2013, PPL Energy Supply extended the expiration date of the agreement to March 2014 and, effective April 2013, the capacity will be reduced to $150 million.
(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, 2012, 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, 2012. The facility expires in November 2017, but is subject to automatic one-year renewals under certain conditions. There were no secured obligations outstanding under this facility at December 31, 2012.
In April 2012, PPL Energy Supply increased the capacity of its commercial paper program from $500 million to $750 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 Energy Supply's Syndicated Credit Facility. At December 31, 2012 and 2011, PPL Energy Supply had $356 million and $400 million of commercial paper outstanding, included in "Short-term debt" on the Balance Sheet, at weighted-average interest rates of 0.50% and 0.53%.
(PPL and PPL Electric)
In May 2012, PPL Electric increased the capacity of its commercial paper program from $200 million to $300 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, 2012.
(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 are supported by LG&E's and KU's Syndicated Credit Facilities. At December 31, 2012, LG&E had $55 million of commercial paper outstanding at a weighted-average interest rate of 0.42% and KU had $70 million of commercial paper outstanding at a weighted-average interest rate of 0.42%, included in "Short-term debt" on the Balance Sheet.
(PPL Energy Supply, 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. 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. 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).
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)
Includes $300 million of 5.70% REset Put Securities due 2035 (REPS). 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. 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.
(b)
Includes lease financing consolidated through a VIE. See Note 22 for additional information.
(c)
Includes PPL Electric's senior secured and first mortgage bonds that are secured by the lien of PPL Electric's 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 $4.3 billion and $3.9 billion at December 31, 2012 and 2011.
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 $2.7 billion and $2.6 billion at December 31, 2012 and December 31, 2011.
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 $4.4 billion and $4.1 billion at December 31, 2012 and December 31, 2011.
(d)
Includes PPL Electric's series of senior secured bonds that 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 (c) above. This amount includes $224 million that may be redeemed at par beginning in 2015 and $90 million that 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.
(e)
Includes LG&E's and KU's series of first mortgage bonds that were issued 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 (c) 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, 2012, the aggregate tax-exempt revenue bonds issued on behalf of LG&E and KU that were in a term rate mode totaled $321 million for LKE, comprised of $294 million and $27 million for LG&E and KU. At December 31, 2012, the aggregate tax-exempt revenue bonds issued on behalf of LG&E and KU that were in a variable rate mode totaled $604 million for LKE, comprised of $280 million and $324 million for 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, 2012, 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.
(f)
Includes £225 million ($361 million at December 31, 2012) 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.
(g)
The principal amount of the notes issued by WPD (South West) and WPD (East Midlands) are adjusted based on changes in a specified index, as detailed in the terms of the related indentures. The adjustment to the principal amounts from 2011 to 2012 was an increase of approximately £9 million ($14 million) resulting from inflation. In addition, this amount includes £225 million ($361 million at December 31, 2012) of notes issued by WPD (South West) that 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.
(h)
Includes £3.3 billion ($5.3 billion at December 31, 2012) 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 are withdrawn by any of the rating agencies (Moody's, S&P or Fitch) or reduced to a non-investment grade rating of Ba1 or BB+ in connection with a restructuring event which includes the loss of, or a material adverse change to, the distribution licenses under which the issuer operates.
None of the outstanding debt securities noted above have sinking fund requirements. The aggregate maturities of long-term debt for the periods 2013 through 2017 and thereafter are as follows.
Long-term Debt and Equity Securities Activities
(PPL)
In April 2012, PPL made a registered underwritten public offering of 9.9 million shares of its common stock. In conjunction with that offering, the underwriters exercised an option to purchase 591 thousand additional shares of PPL common stock solely to cover over-allotments.
In connection with the registered public offering, PPL entered into forward sale agreements with two counterparties covering the 9.9 million shares of PPL common stock. Settlement of these initial forward sale agreements will occur no later than April 2013. As a result of the underwriters' exercise of the overallotment option, PPL entered into additional forward sale agreements covering the 591 thousand additional shares of PPL common stock. Settlement of the subsequent forward sale agreements will occur no later than July 2013. Upon any physical settlement of any forward sale agreement, PPL will issue and deliver to the forward counterparties shares of its common stock in exchange for cash proceeds per share equal to the forward sale price. The forward sale price will be calculated based on an initial forward price of $27.02 per share reduced during the period the contracts are outstanding as specified in the forward sale agreements. PPL may, in certain circumstances, elect cash settlement or net share settlement for all or a portion of its rights or obligations under the forward sale agreements.
PPL will not receive any proceeds or issue any shares of common stock until settlement of the forward sale agreements. PPL intends to use any net proceeds that it receives upon settlement to repay short-term debt obligations and for other general corporate purposes.
The forward sale agreements are classified as equity transactions. As a result, no amounts will be recorded in the consolidated financial statements until the settlement of the forward sale agreements. Prior to those settlements, the only impact to the financial statements will be the inclusion of incremental shares within the calculation of diluted EPS using the treasury stock method. See Note 4 for information on the forward sale agreements impact on the calculation of diluted EPS.
In April 2012, WPD (East Midlands) issued £100 million aggregate principal amount of 5.25% Senior Notes due 2023. WPD (East Midlands) received proceeds of £111 million, which equated to $178 million at the time of issuance, net of underwriting fees. The net proceeds were used for general corporate purposes.
In June 2012, PPL Capital Funding issued $400 million of 4.20% Senior Notes due 2022. The notes may be redeemed at PPL Capital Funding's option any time prior to maturity at make-whole redemption prices. PPL Capital Funding received proceeds of $396 million, net of a discount and underwriting fees, which were used for general corporate purposes.
In August 2012, PPL Capital Funding redeemed at par, plus accrued interest, the $99 million outstanding principal amount of its 6.85% Senior Notes due 2047.
In October 2012, PPL Capital Funding issued $400 million of 3.50% Senior Notes due 2022. The notes may be redeemed at PPL Capital Funding's option any time prior to maturity at make-whole redemption prices. PPL Capital Funding received proceeds of $397 million, net of a discount and underwriting fees, which were used to repay short-term debt obligations, including commercial paper borrowings and for general corporate purposes.
(PPL and PPL Energy Supply)
In April 2012, an indirect, wholly owned subsidiary of PPL Energy Supply completed the Ironwood Acquisition. See Note 10 for information on the transaction and the long-term debt of PPL Ironwood, LLC assumed through consolidation as part of the acquisition.
In February 2013, PPL Energy Supply completed an exchange offer to exchange up to all, but not less than a majority, of 8.857% Senior Secured Bonds due 2025 of its wholly owned subsidiary, PPL Ironwood (the "Ironwood Bonds") for newly issued PPL Energy Supply Senior Notes, Series 4.60% due 2021. A total of $167 million aggregate principal amount of outstanding Ironwood Bonds was exchanged for $212 million aggregate principal amount of PPL Energy Supply Senior Notes, Series 4.60% due 2021.
(PPL and PPL Electric)
See Note 3 for information regarding PPL Electric's June 2012 redemption of all 2.5 million shares of its 6.25% Series Preference Stock, par value $100 per share.
In August 2012, PPL Electric issued $250 million of 2.50% First Mortgage Bonds due 2022. The notes may be redeemed at PPL Electric's option any time prior to maturity at make-whole redemption prices. PPL Electric received proceeds of $247 million, net of a discount and underwriting fees. The net proceeds were used to repay short-term debt incurred to fund PPL Electric's redemption of its 6.25% Series Preference Stock in June 2012 and for other general corporate purposes.
(PPL and LKE)
In June 2012, LKE completed an exchange of $250 million of 4.375% Senior Notes due 2021 issued in September 2011 in a transaction not registered under the Securities Act of 1933, for similar securities that were issued in a transaction registered with the SEC.
(PPL)
2011 Equity Units
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
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 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)
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 2012, PPL declared its quarterly common stock dividend, payable January 2, 2013, at 36.0 cents per share (equivalent to $1.44 per annum). In February 2013, PPL declared its quarterly common stock dividend, payable April 1, 2013, at 36.75 cents per share (equivalent to $1.47 per annum). Future dividends, declared at the discretion of the Board of Directors, will depend 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, 2012, no payments were deferred on any 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. In February 2012, LG&E and KU petitioned the FERC requesting authorization to pay dividends in the future based on retained earnings balances calculated without giving effect to the impact of purchase accounting adjustments for the acquisition of LKE by PPL. In May 2012, FERC approved the petitions with the further condition that each utility may not pay dividends if such payment would cause its adjusted equity ratio to fall below 30% of total capitalization. Accordingly, at December 31, 2012, net assets of $2.3 billion ($893 million for LG&E and $1.4 billion for KU) were restricted for purposes of paying dividends to LKE, and net assets of $2.3 billion ($917 million for LG&E and $1.4 billion for KU) were available for payment of dividends to LKE. LG&E and KU believe they will not be required to change their current dividend practices as a result of the foregoing requirement. In addition, 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 and KU to obtain prior consent or approval before lending amounts to PPL.
(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.
(PPL)
WPD subsidiaries 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.
8. Acquisitions, Development and Divestitures
(PPL, PPL Energy Supply, PPL Electric, LKE, LG&E and KU)
The Registrants from time to time evaluate opportunities for potential acquisitions, divestitures and development projects. Development projects are 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 2011 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 in 2011 and prior years that were presented as discontinued operations by PPL, PPL Energy Supply and LKE. See Note 10 for information on PPL's and PPL Energy Supply's 2012 Ironwood Acquisition and PPL's 2011 acquisition of WPD Midlands and 2010 acquisition of LKE.
(PPL, LKE, LG&E and KU)
Acquisition
Terminated 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, pending receipt of applicable regulatory approvals. In May 2012, the KPSC issued an order approving the request to purchase the Bluegrass CTs. In November 2011, LG&E and KU filed an application with the FERC under the Federal Power Act requesting approval to purchase the Bluegrass CTs. In May 2012, the FERC issued an order conditionally authorizing the acquisition of the Bluegrass CTs, subject to approval by the FERC of satisfactory mitigation measures to address market-power concerns. After a review of potentially available mitigation options, LG&E and KU determined that the options were not commercially justifiable. In June 2012, LG&E and KU terminated the asset purchase agreement for the Bluegrass CTs in accordance with its terms and made applicable filings with the KPSC and FERC.
Development
Cane Run Unit 7 Construction
In September 2011, LG&E and KU filed a CPCN with the KPSC requesting approval to build Cane Run Unit 7. In May 2012, the KPSC issued an order approving the request. LG&E will own a 22% undivided interest, and KU will own a 78% undivided interest in the new generating unit. A formal request for recovery of the costs associated with the construction was not included in the CPCN filing with the KPSC but is expected to be included in future rate proceedings. LG&E and KU commenced preliminary construction activities in the third quarter of 2012 and project construction is expected to be completed by May 2015. The project, which includes building a natural gas supply pipeline and related transmission projects, has an estimated cost of approximately $600 million.
In conjunction with this construction and to meet new, more stringent EPA regulations with a 2015 compliance date, LG&E and KU anticipate retiring five older coal-fired electric generating units at the Cane Run and Green River plants, which have a combined summer capacity rating of 726 MW. In addition, KU retired the remaining 71 MW unit at the Tyrone plant in February 2013.
Future Capacity Needs
In addition to the construction of a combined cycle gas unit at the Cane Run station, LG&E and KU continue to assess future capacity needs. As a part of the assessment, LG&E and KU issued an RFP in September 2012 for up to 700 MW of capacity beginning as early as 2015.
(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 $443 million. Construction continues on the project, with commercial operations scheduled to begin in 2013. At December 31, 2012, expected remaining expenditures are $84 million.
In 2009, PPL Montana received FERC approval for its request to redevelop the Rainbow hydroelectric facility at Great Falls, Montana. The project's expected cost is $209 million. Commercial operations is scheduled to begin in 2013. At December 31, 2012, expected remaining expenditures were insignificant.
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 2012, 2011 and 2010, PPL Energy Supply recorded deferred investment tax credits of $40 million, $52 million and $52 million. PPL Energy Supply anticipates recognizing an additional $23 million in investment tax credits for tax year 2013. These credits reduce PPL Energy Supply's tax liability and will be amortized over the life of the related assets.
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 2015.
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 2013 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 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 $205 million through 2015 on the COLA and other permitting costs necessary for construction, which is expected to be sufficient to fund the project through receipt of the license. At December 31, 2012 and 2011, $154 million and $131 million of costs, which includes capitalized interest, associated with the licensing application were capitalized and are included on the Balance Sheets in noncurrent "Other intangibles." PPL Bell Bend believes that the estimated fair value of the COLA currently exceeds the costs expected to be capitalized for the licensing application.
Regional Transmission Line Expansion Plan (PPL and PPL Electric)
Susquehanna-Roseland
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 was needed to prevent potential overloads that could occur on several existing transmission lines in the interconnected PJM system. PJM directed PPL Electric to construct the portion of
the Susquehanna-Roseland line in Pennsylvania and Public Service Electric & Gas Company to construct the portion of the line in New Jersey.
On October 1, 2012, the National Park Service (NPS) issued its Record of Decision (ROD) on the proposed Susquehanna-Roseland transmission line affirming the route chosen by PPL Electric and Public Service Electric & Gas Company as the preferred alternative under the NPS's National Environmental Policy Act review. On October 15, 2012, a complaint was filed in the United States District Court for the District of Columbia by various environmental groups, including the Sierra Club, challenging the ROD and seeking to prohibit its implementation, and on December 6, 2012, the groups filed a petition for injunctive relief seeking to prohibit all construction activities until the court issues a final decision on the complaint. PPL Electric has intervened in the lawsuit. The chosen route had previously been approved by the PUC and the New Jersey Board of Public Utilities.
On December 13, 2012, PPL Electric received federal construction and right of way permits to build on National Park Service lands.
Construction activities have begun on portions of the 101-mile route in Pennsylvania. The line is expected to be completed before the peak summer demand period of 2015. At December 31, 2012, PPL Electric's estimated share of the project cost was $560 million.
PPL and PPL Electric cannot predict the ultimate outcome or timing of any legal challenges to the project or what additional actions, if any, PJM might take in the event of a further delay to the scheduled in-service date for the new line.
Northeast/Pocono
In October 2012, the FERC issued an order in response to PPL Electric's December 2011 request for ratemaking incentives for the Northeast/Pocono Reliability project (a new 58-mile 230 kV transmission line, three new substations and upgrades to adjacent facilities). The incentives were specifically tailored to address the risks and challenges PPL Electric will face in building the project. The FERC granted the incentive for inclusion of all prudently incurred construction work in progress (CWIP) costs in rate base and denied the request for a 100 basis point adder to the return on equity incentive. The order required a follow-up compliance filing from PPL Electric to ensure proper accounting treatment of AFUDC and CWIP for the project, which PPL Electric will submit with the FERC in March 2013. PPL Electric expects the project to be completed in 2017. At December 31, 2012, PPL Electric estimates the total project costs to be approximately $200 million with approximately $190 million qualifying for the CWIP incentive.
9. Discontinued Operations
(PPL and PPL Energy Supply)
Sale of Certain Non-core Generation Facilities
In 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, a pre-tax impairment charge of $96 million ($58 million after tax) was recorded and $5 million ($4 million after tax) of allocated goodwill was written off. These charges are included in "Income (Loss) from Discontinued Operations (net of income taxes)" on the 2010 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.
Sale of Long Island Generation Business
In 2010, PPL Energy Supply subsidiaries completed the sale of the Long Island generation business, which was included in the Supply segment. Proceeds from the sale approximated $124 million. There was no significant impact on earnings in 2010 from the operation of this business or as a result of the sale.
Sale of Maine Hydroelectric Generation Business
In 2010, a PPL Energy Supply subsidiary completed the sale of its Maine hydroelectric generation business, which was included in the Supply segment. The business included eight hydroelectric facilities as well as a 50% equity interest in another hydroelectric facility. The majority of the business was sold in 2009. The remaining three hydroelectric facilities were sold in 2010 for $24 million, and also resulted in the receipt of an additional $14 million in contingent consideration in connection with the 2009 sale. As a result of the consideration received in 2010, PPL Energy Supply recorded a gain of $25 million ($15 million after tax), reflected in "Income (Loss) from Discontinued Operations (net of income taxes)" on the 2010 Statement of Income.
Distribution of Membership Interest in PPL Global to Parent (PPL Energy Supply)
In January 2011, PPL Energy Supply distributed its entire membership interest in PPL Global, which represented the entire U.K. 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 Statement of Income.
(a)
No interest was allocated, as PPL Global was sufficiently capitalized.
The amount of cash and cash equivalents of PPL Global at the time of the distribution was reflected as a financing activity in the 2011 Statement of Cash Flows.
WKE
(PPL and LKE)
WKE had a 25-year lease for and operated generating facilities of BREC, and a coal-fired generating facility owned by the City of Henderson, Kentucky. WKE terminated the lease in 2009 prior to PPL acquiring LKE. See Note 15 for additional information related to the termination of the lease. In 2012, an adjustment was made to the liability for certain WKE indemnifications, which is reflected in Discontinued Operations. See "Guarantees and Other Assurances" in Note 15 for additional information on the adjustment and related indemnification. The results of operations for the 2012, 2011 and 2010 periods were not significant.
10. Business Acquisitions
Ironwood Acquisition (PPL and PPL Energy Supply)
On April 13, 2012, an indirect, wholly owned subsidiary of PPL Energy Supply completed the acquisition of all of the equity interests of two subsidiaries of The AES Corporation, AES Ironwood, L.L.C. (subsequently renamed PPL Ironwood, LLC) and AES Prescott, L.L.C. (subsequently renamed PPL Prescott, LLC), which own and operate, respectively, the Ironwood Facility. The Ironwood Facility began operation in 2001 and, since 2008, PPL EnergyPlus has supplied natural gas for the facility and received the facility's full electricity output and capacity value pursuant to a tolling agreement that expires in 2021. The acquisition provides PPL Energy Supply, through its subsidiaries, operational control of additional combined-cycle gas generation in PJM.
The fair value of the consideration paid for this acquisition was as follows.
(a)
The long-term debt assumed through consolidation consisted of $226 million aggregate principal amount of 8.857% senior secured bonds to be fully repaid by 2025, plus $8 million of debt service reserve loans, and a $24 million fair value adjustment.
Purchase Price Allocation
The following table summarizes the allocation of the purchase price to the fair value of the major classes of assets acquired and liabilities assumed through consolidation, and the effective settlement of the tolling agreement through consolidation.
(a)
Represents non-cash activity excluded from the 2012 Statement of Cash Flows.
(b)
Prior to the acquisition, PPL EnergyPlus had recorded primarily an intangible asset, which represented its rights to and the related accounting for the tolling agreement with PPL Ironwood, LLC. On the acquisition date, PPL Ironwood, LLC recorded a liability, recognized at fair value, for its obligation to PPL EnergyPlus. The tolling agreement assets of PPL EnergyPlus and the tolling agreement liability of PPL Ironwood, LLC eliminate in consolidation for PPL and PPL Energy Supply as a result of the acquisition, and therefore the agreement is considered effectively settled. The difference between the tolling agreement assets and liability resulted in an insignificant loss on the effective settlement of the agreement.
During the fourth quarter of 2012, the purchase price allocation was finalized with no material adjustments made to the preliminary valuation.
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 increased 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 achieved from the combined operations of these entities.
The fair value of the consideration paid for this acquisition 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.
Purchase Price Allocation
The following table summarizes (in billions) the allocation of the purchase price 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 U.K. 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 - U.K. Regulated Segment
In connection with the 2011 acquisition, PPL completed a reorganization designed to transition WPD Midlands from a functional operating structure to a regional operating structure requiring a smaller combined support structure, reducing duplication and implementing more efficient procedures. As a result of the reorganization, 729 employees of WPD Midlands have been terminated.
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 related to severance compensation and $45 million related to ERDC. WPD Midlands recorded an additional $15 million of total separation benefits in 2012, of which $13 million related to severance compensation and $2 million related to ERDC. The accrued severance compensation is reflected in "Other current liabilities" and the ERDC reduced "Other noncurrent assets" on the Balance Sheets. All separation benefits are included in "Other operation and maintenance" on the Statements of Income.
The changes in the carrying amounts of accrued severance were as follows.
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.
Other
WPD Midlands 2011 financial results included in PPL's Statement of Income and included in the U.K. Regulated segment were as follows.
Pro forma Information
The pro forma financial information, which includes LKE, discussed below, as if the acquisition had occurred January 1, 2009 and WPD Midlands as if the acquisition had occurred January 1, 2010, is 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, which was acquired on April 1, 2011. 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 financial information presented above includes adjustments to depreciation, net periodic pension costs, interest expense and the related income tax effects to reflect the impact of the acquisition. The pre-tax nonrecurring credits (expenses) presented in the following table were directly attributable to the WPD Midlands and LKE acquisitions and adjustments were included in the calculation of pro forma operating revenue and net income to remove the effect of these nonrecurring items and the related income tax effects.
(a)
The 2011 Bridge Facility costs, primarily commitment and structuring fees, were incurred to establish a bridge facility for purposes of funding the WPD Midlands acquisition purchase price.
(b)
The 2011 Bridge Facility was denominated in GBP. The amount includes a $42 million foreign currency loss on PPL Capital Funding's repayment of its 2011 Bridge Facility borrowing and a $15 million foreign currency loss 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.
(c)
The repayment of borrowings on the 2011 Bridge Facility was economically hedged to mitigate the effects of changes in foreign currency exchange rates with forward contracts to purchase GBP, which resulted in net hedge gains.
(d)
The hedge ineffectiveness includes 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, both associated with the acquisition financing.
(e)
The U.K. stamp duty tax represents a tax on the transfer of ownership of property in the U.K. incurred in connection with the acquisition.
(f)
See "Separation Benefits - U.K. Regulated Segment" above.
(g)
Primarily includes acquisition-related 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."
(h)
Primarily commitment and structuring fees, incurred to establish a bridge facility for purposes of funding the acquisition purchase price.
(i)
Primarily includes acquisition-related advisory, accounting and legal fees.
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 reapportions 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 this acquisition 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 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. The goodwill is not 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 2010 LKE financial results included in PPL's Statement of Income and included in the Kentucky Regulated segment were 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 LKE used $100 million to return capital to PPL. The majority of these proceeds, together with a borrowing by LG&E under its available credit facilities, were used 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.
(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 gains (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 was being amortized over the expected remaining useful life of plant and equipment at EEI, which was estimated to be over 20 years. During the fourth quarter of 2012, KU recorded an impairment in EEI. See Notes 1 and 18 for additional information.
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.
Kentucky Acquisition Commitments
(PPL, LKE, LG&E and KU)
In connection with the September 2010 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 exceeds 10.75%, half of the excess amount will be deferred as a regulatory liability and ultimately returned to customers. The first ASSD filing with the KPSC was made on March 30, 2012 based on the 2011 calendar year. On July 2, 2012, the KPSC issued an order approving the calculations contained in the 2011 ASSD filing and determined that such calculations produced no deferral amounts for the purpose of establishing regulatory liabilities and are proper and in accordance with the settlement agreement. The ASSD methodology for each of LG&E's and KU's utility operations terminated on January 1, 2013, when new rates went into effect. Therefore, no further ASSD filings will be made.
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 including the repurchase price 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, 2012 that could be required to be paid by LKE is $5 million, by LG&E is $2 million and by KU is $3 million. LKE has guaranteed the payment of these potential default payments of LG&E and KU.
(PPL and PPL Energy Supply)
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 $301 million at December 31, 2012.
Kerr Dam
Under the Kerr Hydroelectric Project No. 5 joint operating license issued by the FERC, PPL Montana is responsible to make payments to the Confederated Salish and Kootenai Tribes of the Flathead Nation for the use of certain of their tribal lands in connection with the operation of Kerr Dam. This payment arrangement, 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, at a conveyance price to be determined in accordance with the provisions in the FERC license. Exercise of the option by the tribes would result in the termination of this payment arrangement obligation for PPL Montana. The payment arrangement has been treated as an operating lease for accounting purposes. In February 2013, the parties to the license submitted the issue of the appropriate amount of the conveyance price to arbitration.
(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:
12. Stock-Based Compensation
(PPL, PPL Energy Supply, PPL Electric and LKE)
In 2012, shareowners approved the PPL SIP. This new equity plan replaces the PPL ICP and incorporates the following changes:
·
Eliminates the potential to pay dividend equivalents on stock options.
·
Eliminates the automatic lapse of restrictions on all equity awards in the event of a "potential" change in control and requires that a termination of employment occur in the event of a change in control before restrictions lapse.
·
Changes the treatment of outstanding stock options upon retirement to limit the exercise period to the earlier of the end of the term (ten years from grant) or five years after retirement.
To further align the executives' interests with those of PPL shareowners, this plan provides that each restricted stock unit entitles the executive to accrue additional restricted stock units equal to the amount of quarterly dividends paid on PPL stock. These additional restricted stock units would be deferred and payable in shares of PPL common stock at the end of the restriction period. Dividend equivalents on restricted stock unit awards prior to 2013 are currently paid in cash when dividends are declared by PPL.
Under the ICP, SIP and the 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 SIP, and by the PPL Corporate Leadership Council (CLC), in the case of the ICPKE.
The following table details the award limits under each of the plans.
(a)
Applicable to outstanding awards granted from January 27, 2006 to January 26, 2012. During 2012, the total plan award limit was reached and the ICP was replaced by the SIP.
Any portion of these awards 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, in certain situations, as defined by each of 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 and 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 and restricted stock units granted to retirement-eligible employees is recognized as compensation expense immediately upon the date of grant. Recipients of restricted stock and 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 and restricted stock units are subject to forfeiture or accelerated payout under the plan provisions for termination, retirement, disability and death of employees. Restricted stock and restricted stock units vest fully, in certain situations, as defined by each of 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 2012 was:
Substantially all restricted stock and restricted stock unit awards are expected to vest.
The total fair value of restricted stock and 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 3-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 the case of the 2010 and 2011 awards, the S&P 500 Electric Utilities Index, and in the case of the 2012 awards, the Philadelphia Electric Utilities Index. Awards granted in 2010 are 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 and 2012 are payable on a graduated basis similar to 2010, except that the 2011 awards provide for a minimum payment at 25% of the Target Award if performance falls below the 40th percentile of the index group, and in 2012 the minimum payment was eliminated, with no award payable if performance falls below the 25th percentile. 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 as compensation expense on a straight-line basis over the 3-year performance period. Performance units vest on a pro rata basis, in certain situations, as defined by each of the Plans.
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 the companies in the index group. PPL had used historical volatility to value its performance units in 2010. 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 2012 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, 2012, 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 in certain situations, as defined by each of the Plans. The fair value of options granted is recognized as compensation expense 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 as compensation expense 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, expected 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. 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 2013. The assumptions used in the model were:
The weighted-average grant date fair value of options granted was:
Stock option activity for 2012 was:
PPL received $6 million in cash from stock options exercised in 2012. The related tax savings were not significant for 2012. Substantially all stock option awards are expected to vest.
The total intrinsic value of stock options exercised for the years ended December 31, 2012, 2011 and 2010 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:
The income tax benefit related to above compensation expense was as follows:
The income tax benefit PPL realized from stock-based awards vested or exercised for 2012 was not significant.
At December 31, 2012, 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 are 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.
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 also 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 are eligible to participate in the new PPL Retirement Savings Plan. PPL Montana does not expect a significant near-term cost impact as a result of the change.
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.
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 defined benefit pension plan was closed to most new employees, except for those meeting specific grandfathered participation rights. 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. New employees not eligible to participate in the plan are offered benefits under a defined contribution plan.
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 may be paid from 401(h) accounts established as part of the PPL Retirement Plan and the LG&E and KU Retirement Plan within the PPL Services Corporation Master Trust, 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.
(PPL)
The following disclosures distinguish between the domestic (U.S.) and WPD (U.K.) pension plans.
(a)
Related to the WPD Midlands separations in the U.K.
(b)
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.
For PPL's U.S. pension benefits and for other postretirement benefits, the amounts recognized in OCI and regulatory assets/liabilities for the years ended December 31 were as follows:
The estimated amounts to be amortized from AOCI and regulatory assets/liabilities into net periodic defined benefit costs in 2013 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.
Actuarial loss of $3 million related to PPL Energy Supply's U.S. pension plan is expected to be amortized from AOCI into net periodic defined benefit costs in 2013.
(LKE)
The following table provides the components of net periodic defined benefit costs for LKE's pension and other postretirement benefit plans for the years ended December 31, 2012, and 2011, and November 1, 2010 through December 31, 2010, for the Successor and January 1, 2010 through October 31, 2010, for the Predecessor.
For LKE's pension and other postretirement benefits, the amounts recognized in OCI and regulatory assets/liabilities are as follows at December 31, 2012, 2011 and 2010 for the Successor, and at October 31, 2010 for the Predecessor.
The estimated amounts to be amortized from AOCI and regulatory assets/liabilities into net periodic defined benefit costs for LKE in 2013 are as follows.
(LG&E)
The following table provides the components of net periodic defined benefit costs for LG&E's pension benefit plan for the years ended December 31, 2012 and 2011, and November 1, 2010 through December 31, 2010, for the Successor and January 1, 2010 through October 31, 2010, for the Predecessor.
The estimated amounts to be amortized from regulatory assets into net periodic defined benefit costs for LG&E in 2013 are as follows.
(PPL, PPL Energy Supply and PPL Electric)
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 9 for additional information.
(b)
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.
In the table above, for PPL Energy Supply, amounts include 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:
(LKE, LG&E and KU)
The following table provides net periodic defined benefit costs charged to operating expense for the years ended December 31, 2012, and 2011, and November 1, 2010 through December 31, 2010, for the Successor and January 1, 2010 through October 31, 2010, for the Predecessor.
(a)
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.
In the table above, for LG&E, amounts include 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.
(PPL and PPL Energy Supply)
The following weighted-average assumptions were used in the valuation of the benefit obligations at December 31.
(LKE and LG&E)
The following table provides the weighted-average assumptions used in the valuation of the benefit obligations at December 31.
(PPL and PPL Energy Supply)
The following weighted-average assumptions were used to determine the net periodic defined benefit costs for the year ended December 31.
(LKE and LG&E)
The following table provides the weighted-average assumptions used to determine the net periodic defined benefit costs for the years ended December 31, 2012, and 2011, and November 1, 2010 through December 31, 2010, for the Successor and January 1, 2010 through October 31, 2010, for the Predecessor.
(PPL, PPL Energy Supply, LKE and LG&E)
(a)
The expected long-term rates of return for PPL's, PPL Energy Supply's, LKE's 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.
(PPL and PPL Energy Supply)
The following table provides the assumed health care cost trend rates for the year ended December 31:
(LKE)
The following table provides the assumed health care cost trend rates for the years ended December 31, 2012, 2011 and November 1, 2010 through December 31, 2010, for the Successor and January 1, 2010 through October 31, 2010, for the Predecessor.
(PPL and LKE)
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 2012:
(PPL Energy Supply)
The effects on PPL Energy Supply's other postretirement benefit plan would not have been significant.
(PPL)
The funded status of the PPL plans was as follows:
(a)
Includes the pension plans of WPD Midlands, which was acquired in 2011. See Note 10 for additional information.
(b)
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.
For PPL's U.S. pension and other postretirement benefit plans, the amounts recognized in AOCI and regulatory assets/liabilities at December 31 were as follows:
All of PPL's U.S. pension plans had projected and accumulated benefit obligations in excess of plan assets at December 31, 2012 and 2011. All of PPL's other postretirement benefit plans had accumulated postretirement benefit obligations in excess of plan assets at December 31, 2012 and 2011.
For the U.K. pension plans of PPL WEM, projected benefit obligations of $4.3 billion were in excess of plan assets of $4.1 billion at December 31, 2012.
For the U.K. pension plans of PPL WW, projected and accumulated benefit obligations were in excess of plan assets at December 31 as follows (in billions):
(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.
PPL Energy Supply's pension plan had projected and accumulated benefit obligations in excess of plan assets at December 31, 2012 and 2011. PPL Energy Supply's other postretirement benefit plan had accumulated postretirement benefit obligations in excess of plan assets at December 31, 2012 and 2011.
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. Allocations to PPL Energy Supply resulted in liabilities at December 31 as follows:
(LKE)
The funded status of the LKE plans was as follows.
At December 31, the amounts recognized in AOCI and regulatory assets/liabilities are as follows.
All of LKE's pension plans had projected and accumulated benefit obligations in excess of plan assets at December 31, 2012 and 2011. LKE's other postretirement benefit plan had accumulated postretirement benefit obligations in excess of plan assets at December 31, 2012 and 2011.
(LG&E)
The funded status of the LG&E plan was as follows.
LG&E's pension plan had projected and accumulated benefit obligations in excess of plan assets at December 31, 2012 and 2011.
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. Allocations to LG&E resulted in liabilities at December 31 as follows.
(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 2012, $5 million for 2011 and $4 million for 2010. At the date the financial statements were issued, the Form 5500 was not available for the plan year ending in 2012. Therefore, the following disclosures specific to this plan are being made based on the Form 5500s filed for the plan years ended December 31, 2011 and 2010. 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 yellow and red, without utilizing an extended amortization period, as of December 31, 2011 and 2010. 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, 2012, the liability was $3 million. The liability is the net of $67 million of estimated future benefit payments offset by $35 million of assets in a retired miners VEBA trust and an additional $29 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. Allocations to PPL Electric resulted in liabilities at December 31 as follows:
(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. Allocations to KU resulted in liabilities at December 31 as follows.
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, including LG&E's plan, 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 has no significant concentration of risk.
The investment policy of the PPL Services Corporation Master Trust outlines investment objectives and defines the responsibilities of the EBPB, external investment managers, investment advisor and trustee and custodian. The investment policy is 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 on a plan basis based on input from external consultants with a goal of limiting funded status volatility. The EBPB monitors the investments in each portfolio on a plan basis, 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. EBPB investment guidelines on a plan basis, as well as the weighted average of such guidelines, as of the end of 2012 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)
Allocations exclude consideration of cash for the WKE Bargaining Employees' Retirement Plan and a guaranteed annuity contract held by the LG&E and KU Retirement Plan.
(b)
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 was 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.
(PPL Energy Supply)
PPL Montana, a subsidiary of PPL Energy Supply, has a pension plan whose assets are invested solely in the PPL Services Corporation Master Trust, which is fully disclosed below. The fair value of this plan's assets of $149 million at December 31, 2012 represents an interest of approximately 4% in the master trust.
(LKE)
LKE has pension plans, including LG&E's plan, whose assets, effective January 1, 2012, are invested solely in the PPL Services Corporation Master Trust, which is fully disclosed below. The fair value of these plans' assets of $1.1 billion at December 31, 2012 represents an interest of approximately 26% in the master trust.
(LG&E)
LG&E has a pension plan whose assets, effective January 1, 2012, are invested solely in the PPL Services Corporation Master Trust, which is fully disclosed below. The fair value of this plan's assets of $287 million at December 31, 2012 represents an interest of approximately 7% in the master trust. At December 31, 2011, this plan's assets were invested solely in the LG&E and KU Energy LLC Pension Trusts, which is also fully disclosed below. The fair value of this plan's assets of $256 million at December 31, 2011 represents an interest of approximately 26% in the pension trust.
(PPL, PPL Energy Supply, LKE and LG&E)
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, 2012 is as follows:
A reconciliation of U.S. pension trust assets classified as Level 3 at December 31, 2011 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 equity and debt funds are categorized as equity securities. These investments are classified as Level 2, except for exchange-traded funds, which are classified as Level 1 based on quoted prices in active markets. The fair value measurements for Level 2 investments 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 commingled equity funds, these securities represent investments that are measured against the Russell 1000 Growth Index, the Russell 1000 Index, the Russell 3000 Index and the MSCI EAFE Index. Commingled debt funds are described in greater detail in the following discussion of debt securities.
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; investments in debt securities issued by foreign governments and corporations; and exchange traded funds as well as commingled fund investments. Investments in commingled funds include a fund that invests in a diversified portfolio of emerging market debt obligations that is measured against the JP Morgan EMBI Global Diversified Index, as well as funds that invest in investment grade long duration fixed income securities that are measured against the Barclays Long A or Better Index. During the first ten months of 2011 for the LG&E and KU Energy LLC Pension Trusts, debt securities within commingled trusts were measured 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 Energy LLC 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, 2012 have a weighted-average coupon of 3.49% and a weighted-average maturity of 21 years.
Investments in commodities represent ownership of units of a commingled fund that is invested as a long-only, unleveraged portfolio of exchange-traded futures and forward contracts in tangible commodities to obtain broad exposure to all principal groups in the global commodity markets, including energies, agriculture and metals (both precious and industrial) using proprietary commodity trading strategies. The fund has daily liquidity with a specified notification period. The fund's fair value is based upon a unit value as calculated by the fund's trustee.
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 $73 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 funds represent investments in three hedge fund of funds. 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 the 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. The 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. The fair value for two of the funds has been estimated using the net asset value per share and the third 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 primarily represent investments in interest rate swaps and swaptions (the option to enter into an interest rate swap) which are valued based on the swap details, such as swap curves, notional amount, index and term of index, reset frequency, volatility 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, 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 and LKE's investment strategy with respect to its other postretirement benefit obligations is to fund VEBA trusts and/or 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 in 2012 and LG&E and KU Energy LLC Pension Trusts in 2011 discussed in Plan Assets - U.S. Pension Plans above, PPL's and LKE'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. Equity securities include investments in domestic large-cap commingled funds. Ownership interests in commingled funds that invest entirely in debt securities are classified as equity securities, but treated by PPL and LKE as debt securities for asset allocation and target allocation purposes. Ownership interests in commingled money market funds that invest entirely in money market securities are classified as equity securities, but treated by PPL and LKE 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:
(a)
LKE's other postretirement benefit plan was invested primarily in a 401(h) account as disclosed in the PPL Services Corporation Master trust in 2012 and the LG&E and KU Energy LLC Pension Trusts in 2011.
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 long-duration fixed income securities that are managed to track the Barclays U.S. Long Credit Index, as well as a fund that is tracked to the Barclays U.S. Long Treasury Index. Redemptions can be made weekly on these funds.
Investments in commingled money market funds represent investments in 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 this fund.
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 $394 million to its U.S. pension plans in January 2013.
PPL sponsors various non-qualified supplemental pension plans for which no assets are segregated from corporate assets. PPL expects to make approximately $7 million of benefit payments under these plans in 2013.
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 $24 million to its other postretirement benefit plans in 2013.
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. Therefore, no contributions are expected for 2013.
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 $150 million to its pension plans in January 2013.
LKE sponsors various non-qualified supplemental pension plans for which no assets are segregated from corporate assets. LKE expects to make $3 million of benefit payments under these plans in 2013.
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 $12 million to its other postretirement benefit plan in 2013.
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 $11 million to its pension plan in January 2013.
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 plan, to determine contribution requirements for 2013 and forward. Future contributions for PPL WEM were evaluated in accordance with the latest valuation performed as of June 30, 2011, in respect of PPL WEM's principal pension plan, to determine contribution requirements for 2013 and forward. WPD expects to make contributions of approximately $136 million in 2013. 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.
Savings Plans (PPL, PPL Energy Supply, PPL Electric, LKE, LG&E and KU)
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:
The increase for PPL in 2012 and 2011 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 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 2012, 2011 and 2010. 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, 2012 were 7,857,222, 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. Until December 1, 2012, certain employees separated were 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. As of December 1, 2012, separation benefits for certain employees were changed to eliminate accelerated stock award vesting and enhanced pension and postretirement medical benefits. Also, the continuation of group health and welfare coverage was replaced with a single sum payment approximating the dollar amount of premium payments that would be incurred for continuation of group health and welfare coverage. Separation benefits are recorded when such amounts are probable and estimable.
Separation benefits were not significant in 2012 and 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 recorded income tax expense of $8 million; and
·
PPL Energy Supply recorded income tax expense of $5 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 provisions 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, 2012 and 2011, the Balance Sheets reflect the owned interests in the facilities listed below.
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.
In addition to the interests mentioned above, at December 31, 2012 and 2011, 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, 2012 and 2011, NorthWestern owned a 30% interest in Colstrip Unit 4. PPL Montana and NorthWestern have a sharing agreement that governs each party's responsibilities and rights relating to the operation of Colstrip Units 3 and 4. Under the terms of that agreement, each party is responsible for 15% of the total non-coal operating and construction costs of Colstrip Units 3 and 4, regardless of whether a particular cost is specific to Colstrip Unit 3 or 4, and is entitled to take up to the same percentage of the available generation from Units 3 and 4.
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 energy and energy related contracts which include commitments to purchase:
(a)
PPL Energy Supply enters into long-term purchase contracts to supply the coal requirements for its coal-fired generation facilities. As a result of lower electricity and natural gas prices, coal unit utilization has decreased. To mitigate the risk of exceeding available coal storage, PPL Energy Supply incurred pre-tax charges of $29 million during 2012 to reduce its 2012 and 2013 contracted coal deliveries. These charges were recorded to "Fuel" on the Statement of Income.
(PPL, LKE, LG&E and KU)
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. These contracts include the following commitments:
LG&E and KU have a power purchase agreement with OVEC expiring in June 2040. 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 $135 million at December 31, 2012, consisting of LG&E's share of $93 million and KU's share of $42 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:
(PPL and PPL Electric)
In 2009, the PUC approved PPL Electric's procurement plan for the period January 2011 through May 2013. To date, PPL Electric has conducted all of its 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. In May 2012, PPL Electric filed a plan with the PUC to purchase its electricity supply for default customers for the period June 2013 through May 2015. The PUC subsequently approved PPL Electric's plan on January 24, 2013. The approved plan proposes that PPL Electric procure this electricity through competitive solicitations conducted twice each plan year beginning in April 2013.
(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 into 2019, excluding long-term renewable energy agreements that extend into 2038.
(PPL Energy Supply)
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 issued by the FERC jointly 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. While the tribes have indicated their intent to exercise the option at the earliest possible date, 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 $6 million between 2013 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 $30 million between 2013 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.
WKE Indemnification (PPL and LKE)
See footnote (l) to the table in "Guarantees and Other Assurances" below for information on an LKE indemnity relating to its former WKE lease, including related legal proceedings.
(PPL and PPL Energy Supply)
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 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 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 pre-tax charge of $56 million ($34 million after tax), 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 pre-tax charge recorded on the Statement of Income was $49 million in "Other operation and maintenance" and $7 million in "Interest Expense."
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, and in February 2012 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, in the fourth quarter of 2011 PPL Montana reversed its total loss accrual of $89 million ($53 million after-tax) which had been recorded prior to the U.S. Supreme Court decision. The amount reversed was recorded on the Statement 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. In April 2012, the case was returned by the Montana Supreme Court to the Montana First Judicial District Court. Further proceedings have not yet been scheduled by the District Court. 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 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 for the District of Montana. At the time of the bankruptcy filing, SMGT was PPL EnergyPlus' largest unsecured credit exposure. This contract was accounted for as NPNS by PPL EnergyPlus.
The SMGT Contract provided for fixed volume purchases on a monthly basis at established prices. Pursuant to a court order and subsequent stipulations entered into between the SMGT bankruptcy trustee 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 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 March 2012, the U.S. Bankruptcy Court for the District of Montana issued an order approving the request of the SMGT trustee and PPL EnergyPlus to terminate the SMGT Contract. As a result, the SMGT Contract was terminated effective April 1, 2012, allowing PPL EnergyPlus to resell to other customers the electricity previously contracted to SMGT.
PPL EnergyPlus' receivable under the SMGT Contract, representing non-performance by SMGT prior to termination of the SMGT Contract, totaled approximately $21 million at December 31, 2012, which has been fully reserved.
In July 2012, PPL EnergyPlus filed its proof of claim in the SMGT bankruptcy proceeding. The total claim, including the above receivable, is approximately $375 million, predominantly an unsecured claim representing the value for energy sales that will not occur as a result of the termination of the SMGT Contract. No assurance can be given as to the collectability of the claim, thus no amounts have been recorded in the 2012 financial statements.
PPL Energy Supply cannot predict any amount that it may recover in connection with the SMGT bankruptcy or the prices and other terms on which it will be able to market to third parties the power that SMGT will not purchase from PPL EnergyPlus due to the termination of the SMGT Contract.
Notices of Intent to Sue Colstrip Owners
In July 2012, PPL Montana received a Notice of Intent to Sue for violations of the Clean Air Act at Colstrip Steam Electric Station (Notice) from counsel on behalf of the Sierra Club and the MEIC. An Amended Notice was received on September 4, 2012, and a Second Amended Notice was received in October 2012. A Supplemental Notice was received in December 2012. The Notice, Amended Notice, Second Amended Notice, and Supplemental Notice (the Notices) were all addressed to the Owner or Managing Agent of Colstrip, and to the other Colstrip co-owners: Avista Corporation, Puget Sound Energy, Portland General Electric Company, NorthWestern Energy and PacifiCorp. The Notice alleges certain violations of the Clean Air Act, including New Source Review, Title V and opacity requirements. The Amended Notice alleges additional opacity violations at Colstrip, and the Second Amended Notice alleges additional Title V violations. The Supplemental Notice includes additional New Source Review Claims. All four notices state that Sierra Club and MEIC will request a United States District Court to impose injunctive relief and civil penalties, require a beneficial environmental project in the areas affected by the alleged air pollution and require reimbursement of Sierra Club's and MEIC's costs of litigation and attorney's fees. Under the Clean Air Act, lawsuits cannot be filed until 60 days after the applicable notice date. PPL is evaluating the allegations set forth in the Notices and cannot at this time predict the outcome of this matter.
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)
The Dodd-Frank Act became effective in July 2010 and 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 U.S. Commodity Futures Trading Commission (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. The rulemakings are scheduled to become effective at different times beginning with the October 12, 2012 effective date of the definitional rule for the term "swap". In particular, the CFTC's Final Rule (Final Rule), defining key terms such as "swap dealer" and "major swap participant", took effect with the effectiveness of the swap definitional rule.
The heightened thresholds and requirements for these entity classifications set forth in the Final Rule resulted in the Registrants currently being designated neither swap dealers nor major swap participants. The Dodd-Frank Act and its implementing regulations, however, will impose on the Registrants significant additional and costly recordkeeping and reporting requirements. Also, the Registrants could face significantly higher operating costs or may be required to post additional collateral if they or their counterparties are subject to capital or 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 and its implementing regulations. 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 significant costs related to compliance with the Dodd-Frank Act.
(PPL, PPL Energy Supply and PPL Electric)
New Jersey Capacity Legislation
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 the generation that 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. Several parties have filed appeals of the FERC's order. 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. In September 2012, the U.S. District Court denied all summary judgment motions, and the litigation is continuing. Trial is scheduled to begin in March 2013. 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.
Maryland Capacity Order
In April 2012, the Maryland Public Service Commission (MD PSC) ordered three electric utilities in Maryland to enter into long-term contracts to support the construction of new electric generating facilities in Maryland, specifically a 661 MW natural gas-fired combined-cycle generating facility to be owned by CPV Maryland, LLC. PPL believes the intent and effect of the action by the MD PSC is to encourage the construction of new generation in Maryland even when, under the FERC-approved PJM economic model, such new generation would not be economic. The MD PSC action 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 encourage necessary generation investment throughout PJM.
In April 2012, PPL and several other generating companies filed a complaint in U.S. District Court in Maryland challenging the MD PSC order on the grounds that it violates well-established principles under the Supremacy and Commerce clauses of the U.S. Constitution. In this action, the plaintiffs request declaratory and injunctive relief barring implementation of the order by the Commissioners of the MD PSC. In August 2012, the court denied the MD PSC and CPV Maryland, LLC motions to dismiss the proceeding and the litigation is continuing. Trial is scheduled to begin in March 2013. 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. At June 30, 2012, there were two remaining claims against PPL Energy Supply totaling $73 million. In July 2012, PPL Montana and the City of Tacoma, one of the parties claiming refunds at FERC, reached a settlement whereby PPL Montana would pay $75 thousand to resolve the City of Tacoma's $23 million claim, $9 million of which represents interest. The settlement does not resolve the remaining claim outstanding at December 31, 2012 of approximately $50 million.
Although PPL and its subsidiaries believe 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 1998, the FERC authorized LG&E, KU and PPL EnergyPlus to make wholesale sales of electric power and related products at market-based rates. In those orders, the FERC directed LG&E, 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 and Western regions. 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 BREC 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, PPL Electric, 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.
Electric 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. Under the Federal Power Act, the FERC may assess civil penalties of up to $1 million per day, per violation, for certain violations.
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 (including RFC or SERC) determination concerning the resolution of violations of the Reliability Standards remains subject to the approval of the NERC and the FERC.
In the course of implementing their programs 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. 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 October 2012, the FERC issued a Notice of Proposed Rulemaking (NOPR) concerning Reliability Standards for Geomagnetic Disturbances. The FERC proposes to direct NERC to submit for approval Reliability Standards that address the impact of geomagnetic disturbances on the reliable operation of the bulk-power system, including one or more measures to protect against damage to the bulk-power system, such as the installation of equipment that blocks geomagnetically induced currents on implicated transformers. If the NOPR is adopted by the FERC, it is expected to require the Registrants either or both to make significant expenditures in new equipment or modifications to their facilities. The Registrants are unable to predict whether the NOPR will be adopted as proposed by the FERC or the amount of any expenditures that may be required as a result of the adoption of any Reliability Standards for geomagnetic disturbances.
Settled Litigation (PPL and PPL Energy Supply)
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. PPL Susquehanna recorded credits totaling $56 million to "Fuel" on the Statement of Income in 2011 to recognize recovery, under the settlement agreement, of certain costs to store spent nuclear fuel at the Susquehanna plant. The amounts recorded through September 2011 cover costs incurred from 1998 through December 2010. PPL Susquehanna is eligible to receive payment of annual claims for allowed costs, as set forth in the settlement agreement, that are incurred through December 31, 2013. 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 plan through December 31, 2013.
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, it may be necessary for the Registrants to modify, curtail, replace or cease operating certain facilities or operations to comply with statutes, regulations and other requirements of regulatory bodies or courts. In addition, legal challenges to new environmental permits or rules add to the uncertainty of estimating the future cost impact of these permits and rules.
LG&E and KU are entitled to recover, through the ECR mechanism, certain costs of complying with the Clean Air Act as amended and those federal, state, or local environmental requirements which apply to coal combustion wastes and by-products from facilities utilized for production of energy from coal in accordance with their approved compliance plans. Costs not covered by the ECR for LG&E and KU and all such costs for PPL Electric are subject to rate recovery before their respective state regulatory authorities, or the FERC, if applicable. Because PPL Electric does not own any generating plants, its exposure to environmental compliance costs is reduced. As PPL Energy Supply is not a rate regulated entity, it does not have any mechanism for seeking rate recovery of environmental compliance costs. PPL, PPL Electric, LKE, LG&E and KU can provide no assurances as to the ultimate outcome of future environmental or rate proceedings before regulatory authorities.
(PPL, PPL Energy Supply, LKE, LG&E and KU)
Air
CSAPR (formerly Clean Air Transport Rule) and CAIR
In July 2011, the EPA adopted the CSAPR, which was intended to finalize and rename the Clean Air Transport Rule (Transport Rule) proposed in August 2010. The CSAPR replaced the EPA's previous CAIR which was invalidated 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, CSAPR only applied to PPL's fossil-fueled generating plants located in Kentucky and Pennsylvania.
In December 2011, the Court stayed implementation of the CSAPR and left CAIR in effect pending a final decision on the validity of the rule. In August 2012, the Court issued a ruling invalidating CSAPR, remanding the rule to the EPA for further action, and leaving CAIR in place during the interim. A further revised rule is not expected from the EPA for at least two years.
The CSAPR was meant to facilitate attainment of ambient air quality standards for ozone and fine particulates by requiring reductions in sulfur dioxide and nitrogen oxides emissions. The CSAPR established new sulfur dioxide and nitrogen oxide emission allowance cap and trade programs that were more restrictive than previously under CAIR. The CSAPR provided for two-phased programs of sulfur dioxide and nitrogen oxide emissions reductions, with initial reductions in 2012 and more stringent reductions in 2014.
The Kentucky fossil-fueled generating plants can meet the CAIR sulfur dioxide emission requirements by utilizing sulfur dioxide allowances (including banked allowances). To meet nitrogen oxide standards, under the CAIR, the Kentucky companies will need to buy allowances and/or make operational changes. LG&E and KU do not currently anticipate that the costs of meeting these reinstated CAIR requirements or standards will be significant.
PPL Energy Supply's Pennsylvania fossil-fueled generating plants can meet the CAIR sulfur dioxide emission requirements with the existing scrubbers that were placed in service in 2008 and 2009. To meet nitrogen oxide standards, under the CAIR, PPL Energy Supply will need to buy allowances and/or make operational changes, the costs of which are 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 CAIR for its Pennsylvania and Kentucky plants, PPL's fossil-fueled generating 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.
In 2010, the EPA 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 that are in attainment or that are unclassifiable, states are required to develop maintenance plans by mid-2013 that demonstrate continued attainment. In December 2012, the EPA issued final rules that strengthen the particulate standards. Under the final rule, states and the EPA have until the end of 2014 to identify initial non-attainment areas, and states have until 2020 to achieve attainment status for those areas. States can request an extension to 2025 to comply with the rule. Until particulate matter and sulfur dioxide maintenance and compliance plans are developed, PPL, PPL Energy Supply, LKE, LG&E and KU cannot predict which of their facilities may be located in a non-attainment area and what measures would be required to achieve attainment status.
PPL, PPL Energy Supply, LKE, LG&E and KU anticipate that some of the measures required for compliance with the CAIR, the MATS, or the Regional Haze requirements, such as upgraded or new sulfur dioxide scrubbers at some of their plants and, in the case of LG&E and KU, the previously announced retirement of coal-fired generating units at the Cane Run, Green River and Tyrone plants, will help to achieve compliance with the new one-hour sulfur dioxide standard. If additional reductions were to be required, the financial 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. In February 2012, the EPA published the final rule, known as the MATS, with an effective date of April 16, 2012. The rule is being challenged by industry groups and states. The EPA issued a proposed rule in November 2012 reconsidering limited aspects of its MATS and New Source Performance Standards (NSPS) to which PPL responded with comments.
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 chemical additive and fabric-filter baghouses to remove certain hazardous air pollutants. Recovery of the cost of certain controls was granted by the KPSC in December 2011. See Note 6 for information on LG&E's and KU's anticipated retirement of certain coal-fired electric generating units in response to this and other environmental regulations. With the publication of the final MATS rule, LG&E and KU are currently assessing whether any revisions of their approved compliance plans will be necessary.
With respect to PPL Energy Supply's Pennsylvania plants, PPL Energy Supply believes that certain coal-fired plants may require installation of chemical additive systems, the cost of which is not expected to be significant. With respect to PPL Energy Supply's Montana plants, modifications to the current air pollution controls installed on Colstrip may be required, the cost of which is not expected to be significant. For the Corette plant, PPL Energy Supply announced in September 2012 its intention, beginning in April 2015, to place the plant in long-term reserve status, suspending the plant's operation due to expected market conditions and the costs to comply with the MATS requirements. The Corette plant asset group's carrying amount at December 31, 2012 was approximately $68 million. Although the Corette plant asset group was not determined to be impaired at December 31, 2012, it is reasonably possible that an impairment could occur in future periods as higher priced sales contracts settle, adversely impacting projected cash flows. PPL Energy Supply, LG&E and KU are continuing to conduct in-depth reviews of the MATS, including the potential implications to scrubber wastewater discharges. See the discussion of effluent limitations guidelines and standards below.
Regional Haze and Visibility
In January 2012, the EPA proposed limited approval of the Pennsylvania regional haze State Implementation Plan (PA SIP). That proposal 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. Previously, the EPA had determined that implementation of the CAIR requirements would meet regional haze requirements.
In 2012, the EPA finalized a rule providing that implementation of the CSAPR would also meet the Best Available Retrofit Technology (BART) requirements for sulfur dioxide and nitrogen oxides. This rule also addresses the PA SIP deficiency arising from the CAIR remand. However, in August 2012, the U.S. Court of Appeals for the District of Columbia Circuit (Court) vacated and remanded the CSAPR back to the EPA for further rulemaking (as discussed above). In September 2012, several environmental groups filed a petition for review with the Court challenging the EPA's approval of the PA SIP. At this time, it is not known whether the EPA will reinstate its previous determination that CAIR satisfies the BART requirement or will require states to conduct source-specific BART studies.
In Montana, the EPA Region 8 developed 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 emissions for Colstrip Units 1 and 2 and Corette. PPL's analyses concluded that further reductions are not warranted, except that the EPA concurred with the installation of Separated Overfire Air (SOFA) and lime injection for Units 1 and 2. PPL has also submitted data and analyses of various air emission control options under the rules to reduce air emissions related to the non-BART-affected emission sources of Colstrip Units 3 and 4. The analyses show that any incremental reductions would not be cost-effective and that further analysis is not warranted.
In September 2012, the EPA issued its final Federal Implementation Plans (FIP) for the Montana regional haze rule. The final FIP indicated that no additional controls were required for Corette or Colstrip Units 3 and 4 but proposed tighter limits for Corette and Colstrip Units 1 and 2. PPL Energy Supply expects to meet these tighter permit limits at Corette without any significant changes to operations, although other requirements have led to the planned suspension of operations at Corette beginning in April 2015. See "Mercury and Other Hazardous Air Pollutants" discussion above. Under the final FIP, Colstrip Units 1 and 2 will require additional controls, including the possible installation of an SNCR and other technology, to meet more stringent nitrogen oxide and sulfur dioxide limits. The cost of these potential additional controls, if required, could be significant. In November 2012, PPL filed a petition for review of the Montana Regional Haze FIP with the U.S. Court of Appeals for the Ninth Circuit. Environmental groups have also filed a petition for review. The two matters have been consolidated, and the parties have agreed to a briefing schedule.
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 SIP to the EPA which requires the Mill Creek plant to reduce its sulfuric acid mist emissions from Units 3 and 4, the costs of which are not expected to be significant. After approval of the Kentucky SIP by the EPA and revision of the Mill Creek plant's air permit under Title V, LG&E intends to install sorbent injection controls at the plant to reduce sulfuric acid mist emissions.
New Source Review (NSR)
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 in the early 2000s 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. In May and November 2012, PPL Montana received information requests from the EPA regarding projects undertaken during the Spring 2012 maintenance outage at Colstrip Unit 1. In September 2012, PPL Montana received an information request from the Montana Department of Environmental Quality regarding the Unit 1 and other projects. 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 received information requests for the Mill Creek and Trimble County plants, and KU received requests for the Ghent plant, but they 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 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. In September 2012, the parties reached a tentative settlement addressing the Ghent NSR matter and a September 2007 notice of violation alleging opacity violations at the plant. A consent decree was lodged in the U.S. District Court for the Eastern District of Kentucky in December 2012. PPL, LKE and KU cannot predict the outcome of this matter until the consent decree is entered by the Court, but currently do not expect such outcome to result in costs in excess of amounts already accrued, which amounts are not material.
If PPL subsidiaries are found to have violated NSR regulations, PPL, PPL Energy Supply, LKE, LG&E and KU 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 provided notice of their intention to initiate enforcement actions and litigation alleging violations of the NSR regulations by coal-fired generating plants. See "Legal Matters" above for information on a notice of intent to sue received in July 2012 (and amended multiple times thereafter) by PPL Montana and other owners of Colstrip. PPL, PPL Energy Supply, LKE, LG&E and KU are unable to predict whether such actions will be brought against any of their other plants.
Colstrip and Corette Air Permits (PPL and PPL Energy Supply)
In January 2013, Earthjustice, on behalf of the Sierra Club and the MEIC filed an administrative appeal with the Board of Environmental Review, setting forth challenges to certain components of the Title V permits for Colstrip and Corette. These challenges include: 1) the regional haze requirements should have been included in the Title V permits for Corette and Colstrip; 2) the MATS requirements should have been included in the Title V permits for Corette and Colstrip; 3) the particulate monitoring methodology is inadequate at Corette and Colstrip; and 4) sulfur dioxide monitoring is inadequate at Corette. PPL Montana intends to participate in this proceeding and cannot predict its outcome.
On January 31, 2013, the Sierra Club and the MEIC alleged identical claims in their joint petition to the EPA, requesting that the EPA object to the MDEQ's issuance of Colstrip's and Corette's Title V permits. PPL Montana cannot predict the outcome of this parallel matter pending before the EPA.
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 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 actively considered in 2009-2010, such legislation has not significantly progressed. Since that time, although the U.S. House of Representatives passed legislation attempting to bar the EPA from regulating GHG emissions under the existing authority of the Clean Air Act, the Senate never took up the legislation. The timing and elements of future federal legislation addressing GHG emission reductions are uncertain at this time.
Greenhouse Gas Regulations and Tort Litigation
As a result of the April 2007 U.S. Supreme Court decision that the EPA has authority under the Clean Air Act to regulate GHG emissions from new motor vehicles, in April 2010, the EPA and the U.S. Department of Transportation issued new light-duty vehicle emissions standards that apply beginning with 2012 model year vehicles. The EPA also clarified that this standard, beginning in 2011, authorized regulation of GHG emissions from stationary sources under the NSR and Title V operating permit provisions of the Clean Air Act. As a result, any new sources or major modifications to existing GHG sources causing a net significant emissions increase requires the BACT permit limits for GHGs. The rules were challenged, and in June 2012, the U.S. Court of Appeals for the District of Columbia Circuit upheld the EPA's regulations. In December 2012, the Court denied petitions for rehearing pertaining to the Court's June 2012 opinion.
In addition, in April 2012, the EPA proposed NSPS for carbon dioxide emissions from new coal-fired generating units, combined-cycle natural gas units, and integrated gasification combined-cycle units. The proposal would require new coal plants to achieve the same stringent limitations on carbon dioxide emissions as the best performing new gas plants. There presently is no commercially available technology to allow new coal plants to achieve these limitations and, as a result, the EPA's proposal would effectively preclude future construction of new coal-fired generation. In December 2012, the U.S. Court of Appeals for the District of Columbia Circuit dismissed consolidated challenges to the NSPS holding that the proposed rule is not a final agency action. The EPA is expected to finalize the NSPS for new sources in early 2013.
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 25 MW. The MOU also provides for a 10% reduction, by 2019, in carbon dioxide emissions from base levels.
Pennsylvania has not stated an intention to join the RGGI, but 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 and identified 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 solar supply requirements and restrict eligible solar projects to those located in Pennsylvania. PPL and PPL Energy Supply cannot predict at this time whether this legislation will be enacted.
Eleven western states and certain Canadian provinces established the Western Climate Initiative (WCI) in 2003. The WCI established a goal of reducing carbon dioxide emissions by 15% below 2005 levels by 2020 and developed GHG emission allocations, offsets, and reporting recommendations. Montana was once a partner in the WCI, but by 2011 withdrew, along with several other western states.
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 not issued 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 plants, 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 addition, in Comer v. Murphy Oil (Comer case), the U.S. Court of Appeals for the Fifth Circuit (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 Fifth Circuit's 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. In March 2012, the Mississippi federal court granted defendants' motions to dismiss the state common law claims because plaintiffs had previously raised the same claims, plaintiffs lacked standing, plaintiffs' claims were displaced by the Clean Air Act, and other grounds. In April 2012, plaintiffs filed a notice of appeal in the Fifth Circuit. 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 2012, PPL's power plants emitted approximately 70 million tons of carbon dioxide compared with 74 million tons in 2011. The totals reflect 35 million tons from PPL Generation and 35 million tons from LG&E's and KU's generating fleet. All tons are U.S. short tons (2,000 pounds/ton).
Renewable Energy Legislation (PPL, PPL Energy Supply, LKE, LG&E and KU)
There has been interest in renewable energy legislation at both the state and federal levels. Federal legislation on renewable energy is not expected to be introduced this year. In Pennsylvania, bills were recently introduced in both the Senate and House amending the existing AEPS to accelerate the current solar generation obligation, but no action was taken before the end of the 2011-2012 legislative session. Future bills are expected calling for an increase in AEPS Tier 1 (renewable resources, such as wind and solar) obligations and to create a $25 million permanent funding program for solar. Bills have also been introduced in Montana to add hydropower as a qualified source to the renewable portfolio standard.
PPL, PPL Energy Supply, LKE, LG&E and KU believe there are financial, regulatory and logistical uncertainties related to the implementation of renewable energy mandates that will need to be resolved before the impact of such requirements on them can be estimated. Such uncertainties, among others, include the need to provide back-up supply to augment intermittent renewable generation, potential generation over-supply 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 sources. These uncertainties are not directly addressed by proposed legislation. PPL and PPL Energy Supply cannot predict at this time the effect on their merchant plants' future competitive position, results of operation, cash flows and financial position of renewable energy mandates 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 (as either hazardous or non-hazardous) 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 materially increase costs and result in early retirements of many coal-fired plants, as it would require plants to retrofit their operations to comply with full hazardous waste requirements for the generation of CCRs and associated waste waters through generation, 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 (non-hazardous) 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. In addition, the U.S. House of Representatives in September 2012 approved a bill that was revised in the Senate to modify Subtitle D of the RCRA to provide for the proper management and disposal of CCRs and to preclude the EPA from regulating CCRs under Subtitle C of the RCRA. This revised bill is being considered in the Senate and the prospect for passage 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 deadline for the EPA to issue strict CCR regulations. In February 2012, two CCR recycling companies also issued a 60-day notice of intent to sue the EPA over its timeliness in issuing CCR regulations, but they requested that the EPA take a Subtitle D approach that would allow for continued recycling of CCRs. The coalition filed its lawsuit in April 2012 and litigation is continuing.
A final rulemaking is currently expected before the end of 2015. However, the timing of the final regulations could be accelerated by the outcome of the above litigation, which could require the EPA to issue its regulations sooner.
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 financial impact could be material if regulated as a hazardous waste under Subtitle C and significant if regulated under Subtitle D.
Martins Creek Fly Ash Release (PPL and PPL Energy Supply)
In 2005, approximately 100 million gallons of water containing fly ash was released 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 PADEP submitted its National Resource Damage Assessment report to the court and to the interveners. In December 2011, the interveners commented on the PADEP report and in February 2012 the PADEP and PPL filed separate responses with the court. In March 2012, the court dismissed the interveners' case, but the interveners have appealed the dismissal to the Pennsylvania Supreme Court and a decision by the court is still pending.
Through December 31, 2012, 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 nature of any other regulatory or 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 significant 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, PPL Energy Supply, LKE, LG&E and KU plants. PPL, PPL Energy Supply, LKE, LG&E and KU have completed or are completing assessments of seepages or groundwater infiltration at various facilities and have completed or are 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 due to seepage from plant wastewater ponds. 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 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 appealed the October 2011 order to the Montana Supreme Court, which affirmed the district court's order enforcing the settlement on December 31, 2012 and denied plaintiff's motion for rehearing on February 5, 2013. The parties have 60 days after the February 5, 2013 decision to complete the settlement. PPL Montana's share of the settlement is not expected to be significant.
In August 2012, PPL Montana entered into an Administrative Order on Consent (AOC) with the MDEQ which establishes a comprehensive process to investigate and remediate groundwater seepage impacts related to the wastewater facilities at the Colstrip power plant. The AOC requires that within five years, PPL Montana provide financial assurance to the MDEQ for the costs associated with closure and future monitoring of the waste-water treatment facilities. PPL Montana cannot predict at this time if the actions required under the AOC will create the need to adjust the existing ARO related to these facilities.
In September 2012, Earthjustice filed an affidavit pursuant to Montana's Major Facility Siting Act (MFSA) that sought review of the AOC by Montana's Board of Environmental Review (BER), on behalf of the Sierra Club, the MEIC, and the National Wildlife Federation (NWF). In September 2012, PPL Montana filed an election with the BER to have this proceeding conducted in Montana state district court as contemplated by the MFSA. In October 2012, Earthjustice filed a petition for review of the AOC in the Montana state district court in Rosebud County.
In late October 2012, Earthjustice filed a second complaint against the MDEQ and PPL Montana in state district court in Lewis and Clark County on behalf of the Sierra Club, the MEIC and the NWF. This complaint alleges that the defendants have failed to take action under the MFSA and the Montana Water Quality Act to effectively monitor and correct issues of coal ash disposal and wastewater ponds at the Colstrip plant. The complaint seeks a declaration that the operations of the impoundments violate the statutes addressed above, requests a writ of mandamus directing the MDEQ to enforce the same, and seeks recovery of attorneys' fees and costs. PPL is vigorously defending these allegations, and PPL and PPL Energy Supply cannot predict the outcome of this matter.
Clean Water Act 316(b) (PPL, PPL Energy Supply, LKE, LG&E and KU)
The EPA finalized requirements in 2004 for new or modified cooling water intake structures. These requirements affect where generating plants are built, establish intake design standards and could lead to requirements for cooling towers at new and modified power plants. 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 on new or modified cooling water intake structures in April 2011. The industry and PPL reviewed the proposed rule and submitted comments. The EPA has been evaluating comments and meeting with industry groups to discuss options. Two NODAs have been issued on the rule that indicate the EPA may be willing to amend the rule based on certain industry group comments, and the EPA's comment period on the NODAs has ended. The final rule is expected to be issued in 2013. 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 the 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 the remaining useful life of the plant. PPL, PPL Energy Supply, LKE, LG&E and KU cannot reasonably estimate a range of reasonably possible costs, if any, 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.
Effluent Limitations Guidelines and Standards (PPL, PPL Energy Supply, LKE, LG&E and KU)
In October 2009, the EPA released its Final Detailed Study of the Steam Electric Power Generating effluent limitations guidelines and standards. The EPA is expected to issue the final regulations in 2014. PPL, PPL Energy Supply, LKE, LG&E and KU expect the revised guidelines and standards to be more stringent than the current standards especially for sulfur dioxide scrubber wastewater. The guidelines are also expected to require dry ash handling, which could result in additional costs for technology retrofits for closure of wet basins. In the interim, states may impose more stringent limits on a case-by-case basis under existing authority as permits are renewed. Under the Clean Water Act, permits are subject to renewal every five years. PPL, PPL Energy Supply, LKE, LG&E and KU are unable to predict the outcome of this matter or estimate a range of reasonably possible costs, but the costs could be significant.
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 for 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, 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 plants, 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. The EPA is planning to propose the revised regulations in late 2013. PCBs are found, in varying degrees, in all of the Registrants' operations. The Registrants 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.
A PPL Energy Supply subsidiary signed a Consent Order and Agreement (COA) with the PADEP in July 2008 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 and fish mortality. A barrier has been constructed to prevent debris from entering the river water intake area at a cost that was not significant.
PPL Energy Supply's subsidiary has also investigated alternatives to exclude fish from the discharge channel, but the subsidiary and the PADEP have concluded that a barrier method to exclude fish is not workable. In June 2012, a new COA was signed that allows the subsidiary to study a change in a cooling tower operational method that may keep fish from entering the channel. Should this approach fail, the new COA requires a retrofit of impingement control technology at the intakes to the cooling towers, the cost of which could be significant.
In May 2010, the subsidiary received a draft NPDES permit (renewed) for the Brunner Island plant from the PADEP. This permit includes new water quality-based limits for the scrubber wastewater plant. Some of these limits may not be achievable with the existing treatment system. Several agencies and environmental groups commented on the draft permit, raising issues that must be resolved to obtain a final permit for the plant. PPL Energy Supply cannot predict the outcome of the final resolution of the permit issues at this time, or what impact, if any, they would have on this facility, but the costs could be significant.
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 the Trimble Circuit Court, but the case was subsequently transferred to the Franklin Circuit 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" 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 on the
Registrants as a result of any eventual expansion of this interpretation cannot reliably be estimated at this time but could be significant.
Superfund and Other Remediation (PPL, PPL Energy Supply, PPL Electric, LKE, LG&E and KU)
PPL Electric is potentially responsible for costs 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 substantially 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 plants 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.
Depending on the outcome of investigations at sites where investigations have not begun or been completed or developments at sites for which PPL Electric, LG&E and KU currently lack information, the costs of remediation and other liabilities could be material. PPL, PPL Electric, LKE, LG&E and KU cannot 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 plants. PPL, PPL Electric, LKE, LG&E and KU 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, 2012, PPL Energy Supply had accrued a discounted liability of $26 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 8.19%. Expected undiscounted payments are estimated at $3 million for 2013, $1 million for each of the years from 2014 through 2017, and $139 million for work after 2017.
From time to time, PPL Energy Supply, PPL Electric, LG&E and KU undertake remedial action in response to spills or other releases at various on-site and off-site locations, negotiate with the EPA and state and local agencies regarding actions necessary for compliance with applicable requirements, negotiate with property owners and other third parties alleging impacts from PPL's operations and undertake similar actions necessary to resolve environmental matters which arise in the course of normal operations. Based on analyses to date, resolution of these environmental matters is not expected to have a significant adverse impact on their operations.
Future cleanup or remediation work at sites currently under review, or at sites not currently identified, may result in significant additional costs for the Registrants.
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 $45 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.
There are no other material legal or administrative proceedings pending against or related to WPD with respect to environmental matters.
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, 2012, this maximum assessment was $48 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 as amended. 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 as amended, PPL Susquehanna could be assessed up to $235 million per incident, payable at $35 million per year.
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 engage.
(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, 2012. The total recorded liability at December 31, 2012 and 2011 was $24 million and $14 million for PPL and $20 million and $11 million for LKE. The probability of expected payment/performance under each of these guarantees is remote except for "WPD guarantee of pension and other obligations of unconsolidated entities" and "Indemnification of lease termination and other divestitures." For reporting purposes, on a consolidated basis, all guarantees of PPL Energy Supply (other than the letters of credit), PPL Electric, LKE, LG&E and KU also apply to PPL, and all guarantees of LG&E and KU also apply to LKE.
(a)
Represents the estimated maximum potential amount of future payments that could be required to be made under the guarantee.
(b)
Prior to PPL's acquisition, WPD Midlands Holdings Limited had agreed 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 the expiration date is not specified in the transaction documents.
(c)
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.
(d)
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, 2012, 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.
(e)
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.
(f)
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.
(g)
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.
(h)
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. The indemnification provisions described below are in each case 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.
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 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 provisions for most representations and warranties expired in the fourth quarter of 2012.
Subsidiaries of PPL Energy Supply have agreed to provide indemnification to the purchasers of certain non-core generation facilities sold in March 2011 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 for most representations and warranties expired in the first quarter of 2012.
(i)
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 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 exposure shown reflects the PPL Energy Supply subsidiary's share of the maximum obligation. The agreements do not have an expiration date.
(j)
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, secured by a lien on the purchaser's stock of Safe Harbor, in the event PPL Energy Supply is required to make a payment under the guarantee. The exposure noted reflects principal only. See Note 9 for additional information on the sale of this interest.
(k)
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.
(l)
LKE provides certain indemnifications, the most significant of which relate to the termination of the WKE lease in July 2009. See Note 9 for additional information. 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 government fines and penalties fall outside the cumulative cap. LKE has contested the applicability of the indemnification requirement relating to one matter presented by a counterparty under this guarantee. Another guarantee with a maximum exposure of $100 million covering other indemnifications expires in 2023. In May 2012, LKE's indemnitee received an arbitration panel's decision affecting this matter, which granted LKE's indemnitee certain rights of first refusal to purchase excess power at a market-based price rather than at an absolute fixed price. In January 2013, LKE's indemnitee commenced a proceeding in the Kentucky Court of Appeals appealing a December 2012 order of the Henderson Circuit Court confirming the arbitration award. LKE believes its indemnification obligations in this matter remain subject to various uncertainties, including the potential for additional legal challenges regarding the arbitration decision as well as future prices, availability and demand for the subject excess power. LKE continues to evaluate various legal and commercial options with respect to this indemnification matter. The ultimate outcomes of the WKE termination-related indemnifications 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 exposures 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. In the second quarter of 2012, LKE adjusted its estimated liability for certain of these indemnifications by $9 million ($5 million after-tax), which is reflected in "Income (Loss) from Discontinued Operations (net of income taxes)" on the Statement of Income. The adjustment was recorded in the Kentucky Regulated segment for PPL. LKE cannot predict the ultimate outcomes of such indemnification circumstances, but does not currently expect such outcomes to result in significant losses above the amounts recorded.
(m)
As described in the "Energy Purchase Commitments" above, pursuant to the OVEC power purchase contract, expiring in June 2040, LG&E and KU are obligated to pay a demand charge which includes, among other charges, debt service and amortization toward principal retirement, decommissioning costs, post-retirement and post-employment benefits costs (other than pensions), and reimbursement of plant operating, maintenance and other expenses. The demand charge is expected to cover LG&E's and KU's shares of the cost of the listed 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 debt service, post-retirement and decommissioning costs. The maximum exposure and the expiration date of these potential obligations are not presently determinable.
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
PPL Electric holds competitive solicitations for PLR generating supply. PPL EnergyPlus has been awarded a portion of the PLR generation supply through these competitive solicitations. See Note 15 for additional information on the solicitations. The sales and purchases between PPL EnergyPlus and PPL Electric 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, 2012. 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, 2012, PPL Energy Supply had a net credit exposure of $27 million to PPL Electric from its commitment as a PLR supplier and from the sale of its accounts receivable to PPL Electric.
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 both 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 such services when they can be specifically identified. The cost of the 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 charged the following amounts for the years ended December 31, which PPL management believes are reasonable, including amounts applied to accounts that are further distributed between capital and expense.
(a)
Represents costs allocated during the two months ended 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 periodically holds revolving lines of credit and demand notes from certain affiliates that are reflected in "Note receivable from affiliates" on the Balance Sheet. At December 31, 2012, there were no outstanding balances. At December 31, 2011, a note with PPL Energy Funding had an outstanding balance of $198 million with an interest rate of 3.77%. Interest earned on these revolving facilities is included in "Interest Income from Affiliates" on the Statements of Income. For 2012, interest earned on borrowings was insignificant. For 2011, interest earned on borrowings,
which was substantially attributable to borrowings by PPL Energy Funding as discussed above, was $8 million. For 2010, interest earned on borrowings, excluding the term notes discussed below, was $5 million with interest rates equal to one-month LIBOR plus a spread.
(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 included in "Interest Income from Affiliates" for PPL Energy Supply and "Interest Expense with Affiliate" for LKE, LG&E and KU. When balances were outstanding, interest on these notes was insignificant for 2010.
(LKE)
LKE maintains a $300 million revolving line of credit with a PPL Energy Funding 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. At December 31, 2012, $25 million was outstanding and was reflected in "Notes payable with affiliates" on the Balance Sheet. The interest rate on the outstanding borrowing at December 31, 2012 was 1.71%. The line of credit was held by another PPL subsidiary in 2011. No balance was outstanding at December 31, 2011. Interest on the revolving line of credit was not significant for 2012 or 2011.
LKE maintains an agreement with a PPL affiliate that has a $300 million borrowing limit whereby LKE can loan funds on a short-term basis at market-based rates. At December 31, 2012, there was no outstanding balance. At December 31, 2011, $15 million was outstanding and was reflected in "Notes receivable from affiliates" on the Balance Sheet. The interest rates on loans are based on the PPL affiliate's credit rating and are currently equal to one-month LIBOR plus a spread. The interest rate on the outstanding borrowing at December 31, 2011 was 2.27%. Interest income on this note was not significant in 2012 or 2011.
(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, 2012 and 2011, there was no balance outstanding. Interest expense incurred and interest income earned on the money pool agreement with LKE and/or KU was not significant for 2012, 2011 or 2010.
(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, 2012 and 2011, there was no balance outstanding. Interest expense incurred and interest income earned on the money pool agreement with LKE and/or LG&E was not significant for 2012, 2011 or 2010.
Intercompany Derivatives (LKE, LG&E and KU)
In November 2012, LG&E and KU entered into forward-starting interest rate swaps with PPL for notional amounts of $150 million each. These hedging instruments have terms identical to forward-starting swaps entered into by PPL with third parties. See Note 19 for additional information on intercompany derivatives.
(PPL Energy Supply)
Trademark Royalties
A PPL subsidiary owns PPL trademarks and billed certain affiliates for their use under a licensing agreement. This agreement was terminated in December 2011. PPL Energy Supply was charged $40 million of license fees in 2011 and 2010. These charges are primarily included in "Other operation and maintenance" on the Statements of Income.
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 2012 and 2011, PPL Electric exceeded its deductible for both policy years. Probable recoveries on insurance claims with PPL Power Insurance of $18.25 million for 2012 and $26.5 million for 2011 were recorded in those years, of which $14 million and $16 million were included in "Other operation and maintenance" on the Statements of Income. In both years, the remainder was recorded in PP&E on the Balance Sheets. In September 2012, PPL Electric received $26.5 million from the settlement of its 2011 claims.
Effective January 1, 2013, PPL Electric no longer has storm insurance with PPL Power Insurance.
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 a gain on foreign currency contracts that hedged the repayment of the 2011 Bridge Facility borrowing.
(b)
In July 2011, as a result of PPL Electric's 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.
(c)
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.
(d)
Represents a foreign currency loss related to the repayment of the 2011 Bridge Facility borrowing.
"Other Income (Expense) - net" for the years ended December 31, 2012, 2011 and 2010 is primarily earnings on securities in NDT funds for PPL Energy Supply and the equity component of AFUDC for PPL Electric.
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). 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) are used to measure the fair value of an asset or liability, as appropriate. 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 fair value of a group of financial assets and liabilities is measured on a net basis. Transfers between levels are recognized at end-of-reporting-period values. During 2012, there were no transfers between Level 1 and Level 2.
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" and the long-term portion is included in "Other noncurrent assets" on the Balance Sheets.
(d)
Included in "Other noncurrent assets" 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.
(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.
(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.
The significant unobservable inputs used in the fair value measurement of assets and liabilities classified as Level 3 at December 31, 2012 are as follows:
(a)
For energy commodities and auction rate securities, the range and weighted average represent the percentage of fair value derived from the unobservable inputs. For cross-currency swaps, the range and weighted average represent the percentage decrease in fair value due to the unobservable inputs used in the model to calculate the credit valuation adjustment.
(b)
Retail natural gas sales contracts extend into 2017. $11 million of the fair value is scheduled to deliver within the next 12 months. As the forward price of natural gas increases/(decreases), the fair value of the contracts (decreases)/increases.
(c)
Power sales contracts extend into 2014. $(4) million of the fair value is scheduled to deliver within the next 12 months. As the forward price of basis increases/(decreases), the fair value of the contracts (decreases)/increases.
(d)
FTR purchase contracts extend into 2015. $2 million of the fair value is scheduled to deliver within the next 12 months. As the forward implied spread increases/(decreases), the fair value of the contracts increases/(decreases).
(e)
Auction rate securities have a weighted average contractual maturity of 23 years. The model used to calculate fair value incorporates an assumption that the auctions will continue to fail. As the modeled forward rates of the SIFMA Index increase/(decrease), the fair value of the securities increases/(decreases).
(f)
Cross-currency swaps extend into 2017. The credit valuation adjustment incorporates projected probabilities of default and estimated recovery rates. As the credit valuation adjustment increases/(decreases), the fair value of the swaps (decreases)/increases.
Net gains and losses on assets and liabilities classified as Level 3 and included in earnings for the years ended December 31 were reported in the Statements of Income as follows:
Price Risk Management Assets/Liabilities - Energy Commodities (PPL and PPL Energy Supply)
Energy commodity contracts are generally valued using the income approach, except for exchange-traded derivative gas and oil contracts, which are valued using the market approach and are classified as Level 1. When the lowest level inputs that are significant to the fair value measurement of a contract are observable, the contract is classified as Level 2. Level 2 contracts are valued using inputs which may include quotes obtained from an exchange (where there is insufficient market liquidity to warrant inclusion in Level 1), binding and non-binding broker quotes, prices posted by ISOs or published tariff rates. Furthermore, independent quotes are obtained from the market to validate the forward price curves. These contracts include
forwards, swaps, options and structured transactions 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 contracts may be valued using models, including standard option valuation models and standard industry models. For example, the fair value of a full-requirement sales contract 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 or historical prices.
When unobservable inputs are significant to the fair value measurement, a contract is classified as Level 3. The fair value of contracts classified as Level 3 has been calculated using PPL proprietary models which include significant unobservable inputs such as delivery at a location where pricing is unobservable, assumptions for customer migration or delivery dates that are beyond the dates for which independent quotes are available. Forward transactions, including forward transactions classified as Level 3, are analyzed by PPL's Risk Management department, which reports to the Chief Financial Officer (CFO). Accounting personnel, who also report to the CFO, interpret the analysis quarterly to appropriately classify the forward transactions in the fair value hierarchy. Valuation techniques are evaluated periodically. 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 which is used by accounting personnel to calculate the credit valuation adjustment.
In certain instances, energy commodity contracts are transferred between Level 2 and Level 3. The primary reasons for the transfers during 2012 and 2011 were changes in the availability of market information and changes in the significance of the unobservable inputs utilized in the valuation 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 (PPL, LKE, LG&E and KU)
To manage interest rate risk, PPL, LKE, LG&E and KU use interest rate contracts such as forward-starting swaps, floating-to-fixed swaps and fixed-to-floating swaps. To manage foreign currency exchange risk, PPL uses foreign currency contracts such as forwards, options, and cross-currency swaps that contain characteristics of both interest rate and foreign currency contracts. An income approach is used 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, market information cannot practicably be obtained to value credit risk and therefore internal models are relied upon. These models use projected probabilities of default and estimated recovery rates based on historical observances. When the credit valuation adjustment is significant to the overall valuation, the contracts are classified as Level 3. The primary reason for the transfers during 2012 and 2011 was the change in the significance of the credit valuation adjustment. Cross-currency swaps classified as Level 3 are valued by PPL's Corporate Finance department, which reports to the CFO. Accounting personnel, who also report to the CFO, interpret analysis quarterly to appropriately classify the contracts in the fair value hierarchy. Valuation techniques are evaluated periodically.
(PPL and PPL Energy Supply)
NDT Funds
The market approach is used 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 Total Market Index.
·
Investments in commingled equity funds are classified as Level 2 and represent securities that track the S&P 500 Index, Dow Jones U.S. Total Stock Market Index and the Dow Jones U.S. Completion Total Stock Market 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, 2012 have a weighted-average coupon of 4.11% and a weighted-average maturity of 8.26 years.
Auction Rate Securities
Auction rate securities include Federal Family Education Loan Program guaranteed student loan revenue bonds, as well as various municipal bond issues. The exposure to realize losses on these securities is not significant.
The fair value of auction rate securities is estimated using an income approach that includes readily observable inputs, such as principal payments and discount curves for bonds with credit ratings and maturities similar to the securities, and unobservable inputs, such as future interest rates that are estimated based on the SIFMA Index, creditworthiness, and liquidity assumptions driven by the impact of auction failures. When the present value of future interest payments is significant to the overall valuation, the auction rate securities are classified as Level 3. The primary reason for the transfer out of Level 3 in 2012 was the change in the significance of the present value of future interest payments as maturity dates approach.
Auction rate securities are valued by PPL's Treasury department, which reports to the CFO. Accounting personnel, who also report to the CFO, interpret the analysis quarterly to appropriately classify the contracts in the fair value hierarchy. Valuation techniques are evaluated periodically.
Nonrecurring Fair Value Measurements (PPL, PPL Energy Supply, LKE and KU)
The following nonrecurring fair value measurements occurred during the reporting periods, resulting in asset impairments.
(a)
Represents carrying value before fair value measurement.
(b)
The loss on the EEI investment was recorded in the Kentucky Regulated segment and included in "Other-Than-Temporary Impairments" on the Statement of Income. 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 were recorded in the Supply segment and included in "Income (Loss) from Discontinued Operations (net of income taxes)" on the Statement of Income.
(c)
Current and long-term sulfur dioxide emission allowances and RECs are included in "Other current assets" and "Other intangibles" in their respective areas on the Balance Sheets.
Equity Investment in EEI (PPL, LKE and KU)
During the fourth quarter 2012, KU recorded an other-than-temporary decline in the value of its equity investment in EEI. KU performed an internal analysis using an income approach based on discounted cash flows to assess the current fair value of its investment based on several factors. KU considered the following factors: long-dated forward power and fuel price curves, the cost of compliance with environmental standards, and the majority owner and operator's announcement in the fourth quarter 2012 to exit from the merchant generation business. Assumptions used in the fair value assessment were forward energy price curves, expectations for capacity (demand) for energy in EEI's market, and expected capital expenditures used in the calculation that were comparable to assumptions used by KU for internal budgeting and forecasting purposes. Through this analysis, KU determined the fair value to be zero.
(PPL and PPL Energy Supply)
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.
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 Purchase Contract component of the 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, which incorporate the credit risk of the Registrants. These instruments are classified as Level 2. 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 and is classified as Level 2. The carrying value of held-to-maturity, short-term investments at December 31, 2011 approximated 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)
Contracts are entered into 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 to manage credit risk, including master netting arrangements and collateral requirements.
(PPL)
At December 31, 2012, PPL had credit exposure of $1.8 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 $688 million. The top ten counterparties accounted for $367 million, or 53%, of the net exposure and all had investment grade credit ratings from S&P or Moody's.
(PPL Energy Supply)
At December 31, 2012, PPL Energy Supply had credit exposure of $1.8 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 $688 million. The top ten counterparties accounted for $367 million, or 53%, of the net exposure and all had investment grade credit ratings from S&P or Moody's. See Note 16 for information regarding the related party credit exposure.
(PPL Electric)
At December 31, 2012, 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, 2012, 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 (including price, liquidity and volumetric risk) and credit risk (including non-performance risk and payment default 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.
Market Risk
Market risk includes the potential loss that may be incurred as a result of price changes associated with a particular financial or commodity instrument as well as liquidity and volumetric risks. Forward contracts, futures contracts, options, swaps and structured transactions, such as tolling agreements, are utilized 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. Many of the contracts meet the definition of a derivative. All derivatives are recognized on the Balance Sheets at their fair value, unless they qualify for NPNS.
The table below summarizes the market risks that affect PPL and its subsidiaries.
X
= PPL and PPL Energy Supply actively mitigate market risks through their risk management programs described above.
M
= The regulatory environments for PPL's regulated entities, by definition, significantly mitigate market risk.
Commodity price and volumetric risks
·
PPL Energy Supply is exposed to 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 and gas 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;
·
PPL Electric is exposed to commodity price and volumetric risks from its obligation as PLR; however, its PUC-approved cost recovery mechanism substantially eliminates its exposure to market risk. PPL Electric also mitigates its exposure to volumetric risk by entering into full-requirement supply agreements to serve its PLR customers. These supply agreements transfer the volumetric risk associated with the PLR obligation to the energy suppliers; and
·
LG&E's and KU's rates include 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.
Interest rate risk
·
PPL and its subsidiaries are exposed to interest rate risk associated with forecasted fixed-rate and existing floating-rate debt issuances. WPD holds over-the-counter cross currency swaps to limit exposure to market fluctuations on interest and principal payments from foreign currency exchange rates. LG&E utilizes over-the-counter interest rate swaps to limit exposure to market fluctuations on floating-rate debt and LG&E and KU utilize forward starting interest rate swaps to hedge changes in benchmark interest rates.
·
PPL and its subsidiaries are exposed to interest rate risk associated with debt securities held by defined benefit plans. Additionally, PPL Energy Supply is exposed to interest rate risk associated with debt securities held by the NDT.
Equity securities price risk
·
PPL and its subsidiaries are exposed to equity securities price risk associated with equity securities held by defined benefit plans. Additionally, PPL Energy Supply is exposed to equity securities price risk in the NDT funds.
·
PPL is exposed to equity securities price risk from future stock sales and/or purchases.
Foreign currency risk
·
PPL is exposed to foreign currency exchange risk primarily associated with its investments in U.K. affiliates.
Credit Risk
Credit risk is the potential loss that may be incurred due to a counterparty's non-performance, including defaults on payments and energy commodity deliveries.
PPL is exposed to credit risk from "in-the-money" 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 "in-the-money" commodity derivatives with its energy trading partners, which include other energy companies, fuel suppliers and financial institutions.
LKE, LG&E and KU are exposed to credit risk from "in-the-money" interest rate derivatives with financial institutions.
The majority of credit risk stems from 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 or better 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, thus mitigating the risk for these entities.
PPL and its subsidiaries have credit policies in place to manage 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 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 energy trading partners.
Master Netting Arrangements
Net derivative positions are not offset 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 $112 million and $147 million at December 31, 2012 and December 31, 2011.
PPL Electric, LKE, and LG&E had no obligation to return cash collateral under master netting arrangements at December 31, 2012 and December 31, 2011.
PPL, LKE and LG&E had posted cash collateral under master netting arrangements of $32 million at December 31, 2012 and $29 million at December 31, 2011.
PPL Energy Supply and PPL Electric had not posted any cash collateral under master netting arrangements at December 31, 2012 and December 31, 2011.
(PPL and PPL Energy Supply)
Commodity Price Risk (Non-trading)
Commodity price risk, including basis and volumetric risk, is 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 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 Energy Supply maximizes the value of its wholesale and retail energy portfolios through the use of non-trading strategies that include sales of competitive baseload generation, optimization of competitive intermediate and peaking generation and marketing activities.
PPL Energy Supply has a formal hedging program to economically hedge the forecasted purchase and sale of electricity and related fuels for its competitive baseload generation fleet, which includes 7,275 MW (summer rating) of nuclear, coal and hydroelectric generating capacity. PPL Energy Supply attempts to optimize the overall value of its competitive intermediate and peaking fleet, which includes 3,316 MW (summer rating) of natural gas and oil-fired generation. PPL Energy Supply's marketing portfolio is comprised of full-requirement sales contracts and related supply contracts, retail natural gas and electricity sales contracts and other marketing activities. The strategies that PPL Energy Supply uses to hedge its full-
requirement sales contracts include purchasing energy (at a liquid trading hub or directly at the load delivery zone), capacity and RECs in the market and/or supplying the energy, capacity and RECs from its generation assets.
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, natural 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 non-trading activities into two categories: cash flow hedges 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
Certain 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, 2012 range in maturity through 2016. At December 31, 2012, the accumulated net unrecognized after-tax gains (losses) that are expected to be reclassified into earnings during the next 12 months were $124 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 2012 and 2011 such reclassifications were insignificant. For 2010, such reclassifications were after-tax gains (losses) of $(89) 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.
Hedge ineffectiveness associated with energy derivatives was insignificant in 2012. For 2011 and 2010, after-tax gains (losses) from hedge ineffectiveness were $(22) million and $(30) million.
Prior to the adoption of new accounting guidance, in 2010, after-tax gains of $82 million, which had been recognized in a previous period due to ineffectiveness on cash flow hedges, were reversed from earnings based on prospective regression analysis demonstrating that these hedges were expected to be highly effective over their term.
Economic Activity
Many derivative contracts economically hedge the commodity price risk associated with electricity, natural gas, oil and other commodities but do not receive hedge accounting treatment because they were not eligible for hedge accounting or for which hedge accounting was not elected. These derivatives hedge a portion of the economic value of 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, 2012 range in maturity through 2019.
Examples of economic activity include hedges on sales of baseload generation, 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 Spread hedging contracts, retail electric and natural 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, price exposure is generally limited to the cost of the 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 2012, 2011 and 2010.
The net fair value of economic positions at December 31, 2012 and December 31, 2011 was a net asset (liability) of $346 million and $(63) million for PPL and PPL Energy Supply. The unrealized gains (losses) for economic activity were as follows.
The net gains (losses) recorded in "Wholesale energy marketing" resulted primarily from hedges of baseload generation, from certain full-requirement sales contracts, from hedge ineffectiveness, as discussed in "Cash Flow Hedges" above, and from the monetization of certain full-requirement sales contracts in 2010, also discussed above. The net gains (losses) recorded in "Energy purchases" resulted primarily from certain purchase contracts to supply the full-requirement sales contracts noted above, from hedge ineffectiveness, and from purchase contracts that no longer hedge the full-requirement sales contracts that were monetized in 2010.
(PPL and PPL Energy Supply)
Commodity Price Risk (Trading)
PPL Energy Supply also has a proprietary trading strategy which is utilized 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. The proprietary trading portfolio is not a significant part of PPL Energy Supply's business and is shown in "Net energy trading margins" on the Statements of Income.
Commodity Volumetric Activity
As of December 31, 2012, the net notional volumes of derivative (sales)/purchase contracts used in support of the various strategies discussed above were as follows.
Interest Rate Risk
(PPL, LKE, LG&E and KU)
PPL and its subsidiaries issue debt to finance their operations, which exposes them to interest rate risk. Various financial derivative instruments are utilized to adjust the mix of fixed and floating interest rates in their debt portfolio, adjust the duration of the debt portfolio and lock in benchmark interest rates in anticipation of future financing, when appropriate. Risk limits under PPL's risk management program are designed to balance risk exposure to volatility in interest expense and changes in the fair value of the subsidiaries' debt portfolio due to changes in benchmark interest rates.
Cash Flow Hedges
(PPL)
Interest rate risks include exposure to adverse interest rate movements for outstanding variable rate debt and for future anticipated financings. Financial interest rate swap contracts that qualify as cash flow hedges may be entered into to hedge floating interest rate risk associated with both existing and anticipated debt issuances. Outstanding interest rate swap contracts ranged in maturity through 2024 for WPD and through 2043 for PPL's domestic interest rate swaps. These swaps had an aggregate notional value of $1.2 billion at December 31, 2012, of which £290 million (approximately $465 million based on spot rates) was related to WPD. Included in this total are forward-starting interest rate swaps entered into by PPL on behalf of LG&E and KU. LG&E and KU believe that realized gains and losses from the swaps are probable of recovery through regulated rates; as such, the fair value of these derivatives have been reclassified from AOCI to regulatory assets or liabilities. The gains and losses will be recognized in "Interest Expense" on the Statements of Income over the life of the underlying debt when the hedged transaction occurs.
PPL holds a notional position in cross-currency interest rate swaps totaling $1.3 billion that mature through 2028 to hedge the interest payments and principal of WPD's U.S. dollar-denominated senior notes.
For 2012, hedge ineffectiveness associated with interest rate derivatives was insignificant. For 2011, hedge ineffectiveness associated with these derivatives resulted in a net after-tax gain (loss) of $(9) million, 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.
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 2012 and 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.
At December 31, 2012, 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 $(13) million. Amounts are reclassified as the hedged interest payments are made.
(LKE, LG&E and KU)
In November 2012, LG&E and KU entered into forward-starting interest rate swaps with PPL that hedge the interest payments on new debt that is expected to be issued in 2013. These hedging instruments have terms identical to forward-starting swaps entered into by PPL with third parties. LG&E and KU believe that realized gains and losses from the swaps are probable of recovery through regulated rates; as such, the fair value of these derivatives have been reclassified from AOCI to regulatory assets or liabilities. The gains and losses will be recognized in "Interest Expense" on the Statements of Income over the life of the underlying debt when the hedged transaction occurs. At December 31, 2012, LG&E and KU each held contracts with aggregate notional amounts of $150 million that range in maturity through 2043.
(PPL Energy Supply)
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 risk associated with investments in U.K. affiliates. For 2010, hedge ineffectiveness associated with these derivatives was insignificant for
interest rate cross-currency swaps contracts. For 2010, PPL Energy Supply had no reclassifications for cash flows hedges that were discontinued when it was no longer probable that the original forecasted transaction would occur by the end of the originally specified period.
Fair Value Hedges
(PPL)
PPL is exposed to changes in the fair value of its debt portfolio. To manage this risk, financial contracts may be entered into to hedge fluctuations in the fair value of existing debt issuances due to changes in benchmark interest rates. In July 2012, contracts held by PPL that ranged in maturity through 2047 and had a notional value of $99 million were canceled without penalties by the counterparties. PPL did not hold any such contracts at December 31, 2012. PPL 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 or from hedges of debt issuances that no longer qualified as fair value hedges for 2012, 2011 and 2010.
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.
(PPL Energy Supply)
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 risk associated with investments in U.K. affiliates. 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 or resulting from hedges of debt issuances that no longer qualified as fair value hedges for 2010.
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, 2012, 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 $58 million and $60 million at December 31, 2012 and 2011, with equal offsetting amounts recorded as regulatory assets.
Foreign Currency Risk
(PPL)
PPL is exposed to foreign currency risk, primarily through investments in U.K. affiliates. 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.
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. The contracts outstanding at December 31, 2012 had an aggregate notional amount of £162 million (approximately $261 million based on contracted rates). The settlement dates of these contracts range from May 2013 through December 2013. At December 31, 2012 and 2011, the fair value of these positions was a net asset (liability) of $(2) million and $7 million.
Additionally, in 2012, a PPL Global subsidiary that has a U.S. dollar functional currency entered into a GBP intercompany loan payable with a PPL WEM subsidiary that has a GBP functional currency. The loan qualifies as a net investment hedge for the PPL Global subsidiary. As such, the foreign currency gains and losses on the intercompany loan for the PPL Global subsidiary are recorded to the foreign currency translation adjustment component of AOCI. At December 31, 2012, the intercompany loan outstanding was £47 million (approximately $76 million based on spot rates).
For 2012, PPL recognized after-tax net investment hedge gains (losses) of $(5) million in the foreign currency translation adjustment component of AOCI. For 2011 and 2010, PPL recognized after-tax net investment hedge gains (losses) of $4 million in the foreign currency translation adjustment component of AOCI. At December 31, 2012 and 2011, PPL had $14 million and $19 million of accumulated net investment hedge after-tax gains (losses) that were included in the foreign currency translation adjustment component of AOCI.
(PPL Energy Supply)
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 foreign currency exchange risk associated with investments in U.K. affiliates. For 2010, PPL Energy Supply recognized insignificant amounts in the foreign currency translation adjustment component of AOCI.
Cash Flow Hedges
(PPL)
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, 2012, 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 2012, 2011 and 2010, 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, 2012, there were no existing contracts of this nature and no gains or losses recorded for 2012, 2011 and 2010 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.
Economic Activity
PPL enters into foreign currency contracts on behalf of a subsidiary to economically hedge GBP-denominated anticipated earnings. At December 31, 2012, the total exposure hedged by PPL was approximately £1.3 billion (approximately $2.0 billion based on contracted rates) and the net fair value of these positions was an asset (liability) of $(42) million. These contracts had termination dates ranging from January 2013 through February 2015. Realized and unrealized gains (losses) on these contracts are included in "Other Income (Expense) - net" on the Statements of Income and were $(52) million for 2012. At December 31, 2011, the total exposure hedged by PPL was £288 million and the net fair value of these positions was an asset (liability) of $11 million. Realized and unrealized gains (losses) were $10 million for 2011 and insignificant for 2010.
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, 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 Energy Supply)
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 earnings denominated in British pounds sterling. PPL Energy Supply recorded 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 2010, PPL Energy Supply recorded insignificant gains (losses).
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 purchases and 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 fair value of derivatives not designated as NPNS are recognized currently in earnings unless specific hedge accounting criteria are met, except for the changes in fair value of LG&E's and KU's interest rate swaps, which beginning in the third quarter of 2010, are recognized as regulatory assets or liabilities. See Note 6 for amounts recorded in regulatory assets at December 31, 2012 and 2011.
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)
$300 million and $237 million of net gains associated with derivatives that were no longer designated as hedging instruments are recorded in AOCI at December 31, 2012 and 2011.
(b)
Represents the location on the Balance Sheet.
The after-tax balances of accumulated net gains (losses) (excluding net investment hedges) in AOCI were $132 million, $527 million and $695 million at December 31, 2012, 2011 and 2010.
The following tables present the pre-tax effect of derivative instruments recognized in income, OCI or regulatory assets and regulatory liabilities.
(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)
$300 million and $237 million of net gains associated with derivatives that were no longer designated as hedging instruments are recorded in AOCI at December 31, 2012 and 2011.
(b)
Represents the location on the Balance Sheet.
The after-tax balances of accumulated net gains (losses) (excluding net investment hedges) in AOCI were $210 million, $605 million and $733 million at December 31, 2012, 2011 and 2010. 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. There were no gains (losses) on interest rate swaps for 2012.
(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)
The following table presents the fair value and location of derivative 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 and regulatory liabilities for the periods ended December 31, 2012, 2011 and 2010, for the Successor and Predecessor.
(LG&E)
The following table presents the fair value and location of derivative 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 and regulatory liabilities for the periods ended December 31, 2012, 2011 and 2010, for the Successor and Predecessor.
(KU)
At December 31, 2012, KU had interest rate swaps, which were designated as hedging instruments, of $7 million recorded in "Other current assets" on the Balance Sheet. KU recognized a $7 million, pre-tax gain on the derivative instruments in "Noncurrent regulatory liabilities" at December 31, 2012.
Credit Risk-Related Contingent Features (PPL, PPL Energy Supply, LKE, LG&E and KU)
Certain derivative contracts contain credit risk-related contingent features 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, KU or certain of their subsidiaries. Most of these provisions would require the transfer of 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 and 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 on derivative instruments in net liability positions.
Additionally, certain derivative contracts contain credit risk-related contingent provisions that require adequate assurance of performance be provided if the other party has reasonable concerns regarding the performance of PPL's 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, 2012, the effect of a decrease in credit ratings below investment grade on derivative contracts that contain credit risk-related 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)
Represents goodwill recognized as a result of the acquisition of WPD Midlands. See Note 10 for additional information.
(c)
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)
In 2012, intangible assets related to a tolling agreement were eliminated in consolidation as a result of the Ironwood Acquisition. See Note 10 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)
The gross carrying amount includes $269 million of coal contracts related to LKE, which represents the fair value of contracts with terms that are favorable to market recognized as a result of the 2010 acquisition of LKE 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.
(d)
PPL Energy Supply emission allowances/RECs are expensed when consumed or sold. Consumption expense was $12 million, $16 million, and $45 million in 2012, 2011 and 2010. Consumption expense is expected to be insignificant in future periods.
(e)
Includes emission allowances of LKE. An offsetting regulatory liability is recorded related to these emission allowances, which is being amortized as the emission allowances are consumed, eliminating any income statement impact. The carrying amounts of these emission allowances were insignificant at December 31, 2012 and 2011. Consumption related to these emission allowances was insignificant in 2012 and $11 million in 2011.
(f)
During 2011, PPL recorded $7 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)
In 2012, intangible assets related to a tolling agreement were eliminated in consolidation as a result of the Ironwood acquisition. See Note 10 for additional information.
(b)
These emission allowances/RECs are expensed when consumed or sold. Consumption expense was $12 million, $16 million, and $46 million in 2012, 2011, and 2010. Consumption expense is expected to be insignificant in future periods.
(c)
During 2011, PPL Energy Supply recorded $7 million of impairment charges. See Note 18 for additional information.
(d)
"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.
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 2012, 2011 and 2010, and is expected to be insignificant in future years.
(a)
Gross carrying amount represents the fair value of coal 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 includes $14 million, which 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 is 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 insignificant in 2012 and $11 million in 2011.
(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 are included in "Other current assets" on the Balance Sheets. Long-term intangible assets are presented as "Other intangibles" on the Balance Sheets.
(a)
Gross carrying amount represents the fair value of coal 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 includes $6 million, which 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 is 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 insignificant in 2012 and $5 million in 2011.
(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 are included in "Other current assets" on the Balance Sheets. Long-term intangible assets are presented as "Other intangibles" on the Balance Sheets.
(a)
Gross carrying amount represents the fair value of coal 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 includes $8 million, which 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 is 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 for 2011. KU had no consumption related to these emission allowances in 2012.
(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 are included in "Other current assets" on the Balance Sheets. Long-term intangible assets are presented as "Other intangibles" 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 nuclear plant. The accrued nuclear decommissioning obligation was $316 million and $292 million at December 31, 2012 and 2011. The fair value of investments that are legally restricted for the decommissioning of the Susquehanna nuclear plant was $712 million and $640 million at December 31, 2012 and 2011, 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 was 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 as follows.
(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.
Substantially all of the ARO balances are classified as noncurrent at December 31, 2012 and 2011.
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 debt and $18 million of "Noncontrolling interests" at December 31, 2012 and December 31, 2011, is secured by, among other things, the generation facility, the carrying amount of which is disclosed on the Balance Sheets. The debt matures in December 2013, the end of the initial lease term, and therefore has been classified in "Long-term debt due within one year" at December 31, 2012. As a result of the consolidation, PPL Energy Supply has recorded interest expense in lieu of rent expense. For 2012, 2011 and 2010, additional depreciation on the generation facility of $16 million was recorded each year.
23. Available-for-Sale Securities
(PPL, PPL Energy Supply, LKE and LG&E)
Certain short-term investments, securities held by the NDT funds and auction rate securities are classified as available-for-sale.
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.
There were no securities with credit losses at December 31, 2012 and 2011.
The following table shows the scheduled maturity dates of debt securities held at December 31, 2012.
(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 on 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. 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.
NDT Funds (PPL and PPL Energy Supply)
Amounts previously collected from PPL Electric's customers for decommissioning the Susquehanna nuclear plant, 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 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 $1 million, $6 million and $3 million for 2012, 2011 and 2010. These impairments are reflected on the Statements of Income in "Other-Than-Temporary Impairments."
24. New Accounting Guidance Pending Adoption
(PPL, PPL Energy Supply, PPL Electric, LKE, LG&E and KU)
Improving Disclosures about Offsetting Balance Sheet Items
Effective January 1, 2013, the Registrants will retrospectively adopt accounting guidance issued to enhance disclosures about 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.
Testing Indefinite-Lived Intangible Assets for Impairment
Effective January 1, 2013, the Registrants will prospectively adopt accounting guidance that allows an entity to elect the option to first make a qualitative evaluation about the likelihood of an impairment of an indefinite-lived intangible asset. If, based on this assessment, the entity determines that it is more likely than not that the fair value of the indefinite-lived intangible asset exceeds the carrying amount, the fair value of that asset does not need to be calculated. If the entity concludes otherwise, a quantitative impairment test must be performed by determining the fair value of the asset and comparing it with the carrying value. The entity would record an impairment charge, if necessary.
Upon adoption, the guidance is not expected to have a significant impact on the Registrants.
Reporting Amounts Reclassified Out of AOCI
Effective January 1, 2013, the Registrants will prospectively adopt accounting guidance issued to improve the reporting of reclassifications out of AOCI. The Registrants will be required to provide information about the effects on net income of significant amounts reclassified out of AOCI by their respective statement of income line item, if the item is required to be reclassified to net income in its entirety. For items not reclassified to net income in their entirety, the Registrants will be required to reference other disclosures that provide details on these amounts.
Upon adoption, the enhanced disclosure requirements are not expected to have a significant impact on the Registrants.
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
LKE provides certain indemnifications, the most significant of which relate to the termination of the WKE lease in July 2009. See Note 9 to LKE's consolidated financial statements for additional information. 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 government fines and penalties fall outside the cumulative cap. LKE has contested the applicability of the indemnification requirement relating to one matter presented by a counterparty under this guarantee. Another guarantee with a maximum exposure of $100 million covering other indemnifications expires in 2023. In May 2012, LKE's indemnitee received an arbitration panel's decision affecting this matter, which granted LKE's indemnitee certain rights of first refusal to purchase excess power at a market-based price rather than at an absolute fixed price. In January 2013, LKE's indemnitee commenced a proceeding in the Kentucky Court of Appeals appealing a December 2012 order of the Henderson Circuit Court confirming the arbitration award. LKE believes its indemnification obligations in this matter remain subject to various uncertainties, including the potential for additional legal challenges regarding the arbitration decision as well as future prices, availability and demand for the subject excess power. LKE continues to evaluate various legal and commercial options with respect to this indemnification matter. The ultimate outcomes of the WKE termination-related indemnifications 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 exposures 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. In the second quarter of 2012, LKE adjusted its investments in subsidiaries for certain of these indemnifications by $9 million ($5 million after-tax), which is reflected in "Equity in Earnings of Subsidiaries" on the Statement of Income. LKE cannot predict the ultimate outcomes of such indemnification circumstances, but does not currently expect such outcomes to result in significant losses above the amounts recorded.
(a)
Quarterly results can vary depending on, among other things, weather and the forward pricing of power. 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, 2012, 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.
(b)
Changes in internal control over financial reporting.
PPL Corporation
The registrant's principal executive officer and principal financial officer have concluded that there were no 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.
As reported in the 2011 Form 10-K, PPL's principal executive officer and principal financial officer concluded that a systems migration related to the WPD Midlands acquisition created a material change to its internal control over financial reporting in 2012. In December 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.
Risks related to the systems 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 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, 2012. 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 197.
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). Each of the aforementioned companies' internal control over financial reporting is a process designed to provide reasonable assurance to management and Board of Directors of these companies 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 the principal executive officers and principal financial officers of the companies listed above, 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," management of these companies concluded that our internal control over financial reporting was effective as of December 31, 2012. 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 for these non-accelerated filer companies. The effectiveness of internal control over financial reporting for the aforementioned companies was not subject to attestation by the companies' registered public accounting firm pursuant to rules of the Securities and Exchange Commission that permit these 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 2013 Notice of Annual Meeting and Proxy Statement, which will be filed with the SEC not later than 120 days after December 31, 2012, 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 2012 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-us/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-us/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, 2012.
PPL Corporation
Name
Age
Positions Held During the Past Five Years
Dates
William H. Spence (a)
Chairman, President and Chief Executive Officer
April 2012 - present
President and Chief Executive Officer
November 2011 - March 2012
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 (b)
Executive Vice President, General Counsel and Secretary
November 2012 - present
Senior Vice President, General Counsel and Secretary
March 1996 - November 2012
David G. DeCampli (c) (f)
President-PPL Energy Supply
March 2012 - present
President-PPL Electric
April 2007 - March 2012
Gregory N. Dudkin (d) (f)
President-PPL Electric
March 2012 - present
Senior Vice President-Operations-PPL Electric
June 2009 - March 2012
Independent Consultant
February 2009 - June 2009
Senior Vice-President of Technical Operations and
June 2006 - January 2009
Fulfillment-Comcast Corporation
Robert D. Gabbard (f)
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 (f)
President-PPL Global
August 2004 - present
Victor A. Staffieri (f)
Chairman of the Board, President and Chief Executive
Officer-LKE
May 2001 - present
Mark F. Wilten (e)
Vice President-Finance and Treasurer
June 2012 - present
Treasurer-Nissan North America and Nissan Motor
August 2010 - May 2012
Acceptance Corporation
Assistant Treasurer-Nissan Motor Acceptance Corporation
August 2008 - August 2010
Group Treasurer-Kensington Group plc
October 2004 - January 2008
Vincent Sorgi
Vice President and Controller
March 2010 - present
Controller-Supply Accounting
June 2008 - March 2010
Controller-PPL EnergyPlus
April 2007 - June 2008
(a)
On April 1, 2012, William H. Spence was elected Chairman, President and Chief Executive Officer.
(b)
On November 1, 2012, Robert J. Grey was elected Executive Vice President, General Counsel and Secretary.
(c)
On March 4, 2012, David G. DeCampli resigned as President of PPL Electric. On March 5, 2012, Mr. DeCampli was elected as
President of PPL Energy Supply.
(d)
On March 4, 2012, Gregory N. Dudkin resigned as Senior Vice President-Operations of PPL Electric. On March 5, 2012, Mr.
Dudkin was elected as President of PPL Electric.
(e)
On June 4, 2012, Mark F. Wilten was elected Vice President-Finance and Treasurer.
(f)
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 2013 Notice of Annual Meeting and Proxy Statement, which will be filed with the SEC not later than 120 days after December 31, 2012, 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 2013 Notice of Annual Meeting and Proxy Statement, which will be filed with the SEC not later than 120 days after December 31, 2012, and which information is incorporated herein by reference. In addition, provided below in tabular format is information as of December 31, 2012, 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; (c) the PPL 2012 SIP approved by shareowners in 2012 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 and its subsidiaries; and (d) 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, SIP and ICPKE as of December 31, 2012. In addition, as of December 31, 2012, the following other securities had been awarded and are outstanding under the ICP, SIP, ICPKE and DDCP: 30,400 shares of restricted stock, 400,660 restricted stock units and 324,387 performance units under the ICP; 40,000 shares of restricted stock, 1,856 restricted stock units and 3,927 performance units under the SIP; 24,600 shares of restricted stock, 2,006,254 restricted stock units and 265,889 performance units under the ICPKE; and 467,741 stock units under the DDCP.
(4)
Based upon the following aggregate award limitations under the ICP, SIP, 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 SIP, 10,000,000 awards; (c) 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 (d) under the DDCP, the number of shares available for issuance was reduced to 2,000,000 shares in March 2012. 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 2013 Notice of Annual Meeting and Proxy Statement, which will be filed with the SEC not later than 120 days after December 31, 2012, 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 2012 and 2011" in PPL's 2013 Notice of Annual Meeting and Proxy Statement, which will be filed with the SEC not later than 120 days after December 31, 2012, 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, 2012 and 2011, 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, Ironwood purchase accounting, and review, consultation and analysis related to investment tax credits and related capital expenditures on certain hydro-electric plant upgrades.
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, 2012 and 2011, 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)
Includes fees for tax advice in connection with non-income tax processes, sales and use tax matters and analysis related to the deductibility of certain transmission and distribution costs.
LG&E and KU Energy LLC
The following table presents an allocation of fees billed, including expenses, by EY to LKE for the fiscal years ended December 31, 2012 and 2011, for professional services rendered for the audits of LKE'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 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
The following table presents an allocation of fees billed, including expenses, by EY to LG&E for the fiscal years ended December 31, 2012 and 2011, for professional services rendered for the audits of LG&E'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 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
The following table presents an allocation of fees billed, including expenses, by EY to KU for the fiscal years ended December 31, 2012 and 2011, for professional services rendered for the audits of KU'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 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 2012 and 2011 services provided by EY.
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.