Item 1. Business.
Introduction
OG&E generates, transmits, distributes and sells electric energy in Oklahoma and western Arkansas. Its operations are subject to regulation by the OCC, the APSC and the FERC. OG&E was incorporated in 1902 under the laws of the Oklahoma Territory. OG&E is the largest electric utility in Oklahoma and its franchised service territory includes the Fort Smith, Arkansas area. OG&E sold its retail natural gas business in 1928 and is no longer engaged in the natural gas distribution business. OG&E is a wholly-owned subsidiary of OGE Energy, an energy and energy services provider offering physical delivery and related services for both electricity and natural gas primarily in the south central United States. OG&E's principal executive offices are located at 321 North Harvey, P.O. Box 321, Oklahoma City, Oklahoma 73101-0321; telephone 405-553-3000.
OG&E Strategy
OGE Energy's mission, through OG&E and its equity interest in Enable, is to fulfill its critical role in the nation's electric utility and natural gas midstream pipeline infrastructure and meet individual customers' needs for energy and related services focusing on safety, efficiency, reliability, customer service and risk management.
OG&E is focused on:
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Providing exceptional customer experiences by continuing to improve customer interfaces, tools, products and services that deliver high customer satisfaction and operating productivity.
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Providing safe, reliable energy to the communities and customers we serve. A particular focus is on enhancing the value of the grid by improving distribution grid reliability by reducing the frequency and duration of customer interruptions and leveraging previous grid technology investments.
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Maintaining strong regulatory and legislative relationships for the long-term benefit of our customers, investors and members.
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Continuing to grow a zero-injury culture and deliver top-quartile safety results.
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Expanding transmission investments beyond traditional opportunities.
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Executing on OG&E’s Environmental Compliance Plan.
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Ensuring we have the necessary mix of generation resources to meet the long term needs of our customers.
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Continuing focus on operational excellence and efficiencies in order to protect the customer bill.
General
OG&E generates, transmits, distributes and sells electric energy in Oklahoma and western Arkansas. OG&E furnishes retail electric service in 267 communities and their contiguous rural and suburban areas. As of December 31, 2014, two rural electric cooperatives in Oklahoma and western Arkansas purchased electricity from OG&E for resale. The service area covers 30,000 square miles in Oklahoma and western Arkansas, including Oklahoma City, the largest city in Oklahoma, and Fort Smith, Arkansas, the second largest city in that state. Of the 267 communities that OG&E serves, 241 are located in Oklahoma and 26 in Arkansas. OG&E derived 90 percent of its total electric operating revenues in 2014 from sales in Oklahoma and the remainder from sales in Arkansas.
OG&E's system control area peak demand in 2014 was 6,339 MWs on August 25, 2014. OG&E's load responsibility peak demand was 5,813 MWs on August 25, 2014. As reflected in the table below and in the operating statistics that follow, there were 28.0 million MWH system sales in 2014, 28.2 million MWH system sales in 2013 and 28.0 million MWH system sales in 2012. Variations in system sales for the three years are reflected in the following table:
OG&E is subject to competition in various degrees from government-owned electric systems, municipally-owned electric systems, rural electric cooperatives and, in certain respects, from other private utilities, power marketers and cogenerators. Oklahoma law forbids the granting of an exclusive franchise to a utility for providing electricity.
Besides competition from other suppliers or marketers of electricity, OG&E competes with suppliers of other forms of energy. The degree of competition between suppliers may vary depending on relative costs and supplies of other forms of energy. It is possible that changes in regulatory policies or advances in newer technologies such as fuel cells, microturbines, windmills and photovoltaic solar cells will reduce costs of new technology to levels that are equal to or below that of most central station electricity production. Our ability to maintain relatively low cost, efficient and reliable operations is a significant determinate of our competitiveness.
Regulation and Rates
OG&E's retail electric tariffs are regulated by the OCC in Oklahoma and by the APSC in Arkansas. The issuance of certain securities by OG&E is also regulated by the OCC and the APSC. OG&E's wholesale electric tariffs, transmission activities, short-term borrowing authorization and accounting practices are subject to the jurisdiction of the FERC. The Secretary of the U.S. Department of Energy has jurisdiction over some of OG&E's facilities and operations. In 2014, 84 percent of OG&E's electric revenue was subject to the jurisdiction of the OCC, eight percent to the APSC and eight percent to the FERC.
The OCC issued an order in 1996 authorizing OG&E to reorganize into a subsidiary of OGE Energy. The order required that, among other things, (i) OGE Energy permit the OCC access to the books and records of OGE Energy and its affiliates relating to transactions with OG&E, (ii) OGE Energy employ accounting and other procedures and controls to protect against subsidization of non-utility activities by OG&E's customers and (iii) OGE Energy refrain from pledging OG&E assets or income for affiliate transactions. In addition, the Energy Policy Act of 2005 enacted the Public Utility Holding Company Act of 2005, which in turn granted to the FERC access to the books and records of OGE Energy and its affiliates as the FERC deems relevant to costs incurred by OG&E or necessary or appropriate for the protection of utility customers with respect to the FERC jurisdictional rates.
Completed Regulatory Matters
Market-Based Rate Authority
On June 29, 2012, OG&E filed its triennial market power update with the FERC to retain its market-based rate authorization in the SPP's energy imbalance service market but to surrender its market-based rate authorization for any market-based rates sales outside of the SPP's energy imbalance service market. On May 2, 2013, the FERC issued an order accepting OG&E's June 2012 triennial market power update.
On December 30, 2013, OG&E submitted to the FERC a market-based rate change in status filing and a revised market-based rate tariff that would authorize OG&E to (i) sell electric energy and capacity at market-based rates without geographic restriction, and (ii) sell ancillary services in the SPP and Midcontinent Independent System Operator, Inc. markets. The primary goal of this filing was to implement the market-based rate authority OG&E needs to fully participate in SPP’s Integrated Marketplace. On February 28, 2014, FERC issued a letter order accepting OG&E’s market-based rate filing and tariff effective March 1, 2014. FERC found that OG&E passed the market power screens and satisfied requirements related to horizontal market power and vertical market power.
Section 206 Complaint
On November 26, 2013, Arkansas Electric Cooperative Corporation filed a complaint at the FERC against OG&E, arguing that the wholesale formula rate contract between OG&E and Arkansas Electric Cooperative Corporation (formerly between OG&E and Arkansas Valley Electric Cooperative) is unjust and unreasonable with respect to several items. OG&E and Arkansas Electric Cooperative Corporation agreed to terms of a settlement and filed the offer of settlement with the FERC on February 24, 2014. On April 17, 2014, the FERC accepted the settlement making it effective March 1, 2014. The reduction in revenue for 2014 was $0.9 million.
Fuel Adjustment Clause Review for Calendar Year 2012
The OCC routinely reviews the costs recovered from customers through OG&E's fuel adjustment clause. On July 31, 2013, the OCC Staff filed an application to review OG&E's fuel adjustment clause for calendar year 2012, including the prudence of OG&E's electric generation, purchased power and fuel procurement costs. OG&E filed the necessary information and documents needed to satisfy the OCC's minimum filing requirement rules on October 9, 2013. On April 24, 2014, the OCC administrative law judge at the hearing, on the merits, recommended that the OCC find that OG&E's 2012 electric generation, purchased power and fuel procurement processes and costs were prudent. On June 10, 2014, the OCC issued an order approving OG&E’s practices, policies and judgment regarding its electric generation, purchased power, and fuel procurement processes and costs for the calendar year 2012. The order also found that the costs were prudent, reasonable, and mathematically correct.
Integrated Resource Plans
In June 2014, OG&E initiated the process to update its Integrated Resource Plans in Oklahoma and Arkansas at OG&E's discretion. The prior Integrated Resource Plan, submitted in 2012, assumed that the Oklahoma SIP would be followed to comply with Regional Haze requirements. Subsequent to holding technical conferences and public stakeholder meetings, OG&E submitted
its revised Integrated Resource Plans, which included its environmental compliance plan described below, to the OCC on August 4, 2014 and to the APSC on September 8, 2014.
Pending Regulatory Matters
FERC Order No. 1000, Final Rule on Transmission Planning and Cost Allocation
On July 21, 2011, the FERC issued Order No. 1000, which revised the FERC's existing regulations governing the process for planning enhancements and expansions of the electric transmission grid in a particular region, along with the corresponding process for allocating the costs of such expansions. Order No. 1000 leaves to individual regions to determine whether a previously-approved project is subject to reevaluation and is therefore governed by the new rule.
Order No. 1000 requires, among other things, public utility transmission providers, such as the SPP, to participate in a process that produces a regional transmission plan satisfying certain standards, and requires that each such regional process consider transmission needs driven by public policy requirements (such as state or Federal policies favoring increased use of renewable energy resources). Order No. 1000 also directs public utility transmission providers to coordinate with neighboring transmission planning regions. In addition, Order No. 1000 establishes specific regional cost allocation principles and directs public utility transmission providers to participate in regional and interregional transmission planning processes that satisfy these principles.
On the issue of determining how entities are to be selected to develop and construct the specific transmission projects, Order No. 1000 directs public utility transmission providers to remove from the FERC-jurisdictional tariffs and agreements provisions that establish any Federal "right of first refusal" for the incumbent transmission owner (such as OG&E) regarding transmission facilities selected in a regional transmission planning process, subject to certain limitations. However, Order No. 1000 is not intended to affect the right of an incumbent transmission owner (such as OG&E) to build, own and recover costs for upgrades to its own transmission facilities, and Order No. 1000 does not alter an incumbent transmission owner's use and control of existing rights of way. Order No. 1000 also clarifies that incumbent transmission owners may rely on regional transmission facilities to meet their reliability needs or service obligations. The SPP's pre-Order No. 1000 tariff included a "right of first refusal" for incumbent transmission owners and this provision has played a role in OG&E being selected by the SPP to build previous transmission projects in Oklahoma. These changes to the "right of first refusal" apply only to "new transmission facilities," which are facilities subject to evaluation or reevaluation (under the applicable local or regional transmission planning process) after November 13, 2012. On May 29, 2013, the Governor signed House Bill 1932 into law which establishes a right of first refusal for Oklahoma incumbent transmission owners, including OG&E, to build new transmission projects with voltages under 300 kilovolts that interconnect to those incumbent owners' existing facilities. OG&E believes this law is consistent with the language of Order No. 1000. On August 15, 2014, the U.S. Court of Appeals for the D.C. Circuit issued an order denying all appeals of Order No. 1000.
The FERC has issued two orders on the SPP's Order No. 1000 compliance filings. In its most recent order, issued October 16, 2014, the FERC confirmed that “right of first refusal” language should be removed from the SPP tariff and Membership Agreement as applied to most transmission facilities, but that several types of facilities would remain subject to a right of first refusal. Projects that retained the right of first refusal included facilities that would operate below 100 kilovolts, facilities selected as part of the SPP’s Aggregate Study process, and short-term reliability projects. The FERC also approved SPP’s new competitive solicitation process for projects that are not subject to a right of first refusal. FERC found that SPP may consider state and local laws and regulations when deciding whether SPP will hold a competitive solicitation for a proposed project. On December 15, 2014, OG&E filed an appeal in the District of Columbia Circuit Court of Appeals of a portion of the October 2014 FERC order requiring removal of the right of first refusal language from the Membership Agreement. The court has not yet acted on OG&E's appeal.
OGE Energy cannot, at this time, determine the precise impact of Order No. 1000 on OG&E. OGE Energy has no reason to believe that the implementation of Order No. 1000 will impact OG&E's transmission projects currently under development and construction for which OG&E has received a notice to proceed from the SPP.
Energy Efficiency Program Filing
On February 14, 2014, OG&E filed an application with the APSC requesting approval of interim modifications to approved Energy Efficiency Programs, new tariff revisions and the waiver of certain provisions of the Commission’s Rules for Conservation and Energy Efficiency Programs.
Environmental Compliance Plan
On August 6, 2014, OG&E filed an application with the OCC for approval of its plan to comply with EPA’s MATS and Regional Haze FIP while serving the best long-term interests of customers in light of future environmental uncertainties. The application seeks approval of the environmental compliance plan and for a recovery mechanism for the associated costs. The environmental compliance plan includes installing dry scrubbers at Sooner Units 1 and 2 and the conversion of Muskogee Units 4 and 5 to natural gas. The application also asks the Commission to predetermine the prudence of replacing OG&E's soon-to-be retired Mustang steam turbines in late 2017 (approximately 460 MW) with 400 MW of new, efficient combustion turbines at the Mustang site in 2018 and 2019 and approval for a recovery mechanism for the associated costs. OG&E estimates the total capital cost associated with its environmental compliance plan included in this application to be approximately $1.1 billion. The OCC hearing on OG&E's application is scheduled to commence on March 3, 2015. Multiple parties advocating a variety of positions have intervened in the proceeding. OG&E expects a ruling from the OCC in the second quarter of 2015. At this time, OG&E cannot predict the outcome of the proceeding. OG&E plans to file applications in the first quarter of 2015 seeking related approvals from the APSC.
Fuel Adjustment Clause Review for Calendar Year 2013
The OCC routinely reviews the costs recovered from customers through OG&E's fuel adjustment clause. On July 31, 2014, the OCC Staff filed an application to review OG&E's fuel adjustment clause for calendar year 2013, including the prudence of OG&E's electric generation, purchased power and fuel procurement costs. OG&E filed the necessary information and documents needed to satisfy the OCC's minimum filing requirement rules on September 29, 2014. A procedural schedule has not been established as of this date. OG&E expects an order in the second quarter of 2015.
Regulatory Assets and Liabilities
OG&E, as a regulated utility, is subject to accounting principles for certain types of rate-regulated activities, which provide that certain incurred costs that would otherwise be charged to expense can be deferred as regulatory assets, based on the expected recovery from customers in future rates. Likewise, certain actual or anticipated credits that would otherwise reduce expense can be deferred as regulatory liabilities, based on the expected flowback to customers in future rates. Management's expected recovery of deferred costs and flowback of deferred credits generally results from specific decisions by regulators granting such ratemaking treatment.
OG&E records certain incurred costs and obligations as regulatory assets or liabilities if it is probable, based on regulatory orders or other available evidence, that the cost or obligation will be included in amounts allowable for recovery or refund in future rates.
At December 31, 2014 and 2013, OG&E had regulatory assets of $508.6 million and $427.9 million, respectively, and regulatory liabilities of $287.4 million and $254.4 million, respectively. See Note 1 of Notes to Financial Statements for a further discussion.
Management continuously monitors the future recoverability of regulatory assets. When in management's judgment future recovery becomes impaired, the amount of the regulatory asset is adjusted, as appropriate. If OG&E were required to discontinue the application of accounting principles for certain types of rate-regulated activities for some or all of its operations, it could result in writing off the related regulatory assets, which could have significant financial effects.
Rate Structures
Oklahoma
OG&E's standard tariff rates include a cost-of-service component (including an authorized return on capital) plus a fuel adjustment clause mechanism that allows OG&E to pass through to customers the actual cost of fuel and purchased power.
OG&E offers several alternate customer programs and rate options. Under OG&E's Smart Grid enabled SmartHours® programs, "time-of-use" and "variable peak pricing" rates offer customers the ability to save on their electricity bills by shifting some of the electricity consumption to times when demand for electricity and costs are at their lowest. The guaranteed flat bill option for residential and small general service accounts allows qualifying customers the opportunity to purchase their electricity needs at a set monthly price for an entire year. A second tariff rate option provides a "renewable energy" resource to OG&E's Oklahoma retail customers. This renewable energy resource is a Renewable Energy Credit purchase program and is available as a voluntary option to all of OG&E's Oklahoma retail customers. OG&E's ownership and access to wind resources makes the renewable option a possible choice in meeting the renewable energy needs of our conservation-minded customers. Another program
being offered to OG&E's commercial and industrial customers is a voluntary load curtailment program called Load Reduction. This program provides customers with the opportunity to curtail usage on a voluntary basis when OG&E's system conditions merit curtailment action. Customers that curtail their usage will receive payment for their curtailment response. This voluntary curtailment program seeks customers that can curtail on most curtailment event days, but may not be able to curtail every time that a curtailment event is required. OG&E also offers certain qualifying customers "day-ahead price" and "flex price" rate options which allow participating customers to adjust their electricity consumption based on price signals received from OG&E. The prices for the "day-ahead price" and "flex price" rate options are based on OG&E's projected next day hourly operating costs.
OG&E also has two rate classes, Public Schools-Demand and Public Schools Non-Demand, that provide OG&E with flexibility to provide targeted programs for load management to public schools and their unique usage patterns. OG&E also provides service level, seasonal and time period fuel charge differentiation that allows customers to pay fuel costs that better reflect the underlying costs of providing electric service. Lastly, OG&E has a military base rider that demonstrates Oklahoma's continued commitment to our military partners.
The previously discussed rate options, coupled with OG&E's other rate choices, provide many tariff options for OG&E's Oklahoma retail customers. The revenue impacts associated with these options are not determinable in future years because customers may choose to remain on existing rate options instead of volunteering for the alternative rate option choices. Revenue variations may occur in the future based upon changes in customers' usage characteristics if they choose alternative rate options.
Arkansas
OG&E's standard tariff rates include a cost-of service component (including an authorized return on capital) plus an energy cost recovery mechanism that allows OG&E to pass through to customers the actual cost of fuel and purchased power. OG&E offers several alternate customer programs and rate options. The "time-of-use" and "variable peak pricing" tariffs allow participating customers to save on their electricity bills by shifting some of the electricity consumption to times when demand for electricity is lowest. A second tariff rate option provides a "renewable energy" resource to OG&E's Arkansas retail customers. This renewable energy resource is a Renewable Energy Credit purchase program and is available as a voluntary option to all of OG&E's Arkansas retail customers. OG&E's ownership and access to wind resources makes the renewable option a possible choice in meeting the renewable energy needs of our conservation-minded customers. OG&E offers its commercial and industrial customers a voluntary load curtailment program called Load Reduction. This program provides customers with the opportunity to curtail usage on a voluntary basis and receive a billing credit when OG&E's system conditions merit curtailment action. OG&E offers certain qualifying customers a "day-ahead price" rate option which allows participating customers to adjust their electricity consumption based on a price signal received from OG&E. The day-ahead price is based on OG&E's projected next day hourly operating costs.
Fuel Supply and Generation
In 2014, 61 percent of the OG&E-generated energy was produced by coal-fired units, 32 percent by natural gas-fired units and seven percent by wind-powered units. Of OG&E's 6,845 total MW capability reflected in the table under Item 2. Properties, 3,880 MWs, or 57 percent, are from natural gas generation, 2,516 MWs, or 37 percent, are from coal generation and 449 MWs, or six percent, are from wind generation. Over the last five years, the weighted average cost of fuel used, by type, was as follows:
The decrease in the weighted average cost of fuel in 2014 as compared to 2013 was primarily due to less natural gas used, offset by higher natural gas prices. The increase in the weighted average cost of fuel in 2013 as compared to 2012 was primarily due to higher gas prices. The decrease in the weighted average cost of fuel in 2012 as compared to 2011 was primarily due to lower natural gas prices. The decrease in the weighted average cost of fuel in 2011 as compared to 2010 was primarily due to lower natural gas prices and less natural gas used. These fuel costs are recovered through OG&E's fuel adjustment clauses that are approved by the OCC, the APSC and the FERC.
OG&E began participating in the SPP Integrated Marketplace effective March 1, 2014. The SPP Integrated Marketplace replaced the SPP Energy Imbalance Services market. As part of the Integrated Marketplace, the SPP assumed balancing authority responsibilities for its market participants. The SPP Integrated Marketplace functions as a centralized dispatch, where market
participants, including OG&E, submit offers to sell power to the SPP from their resources and bid to purchase power from the SPP for their customers. The SPP Integrated Marketplace is intended to allow the SPP to optimize supply offers and demand bids based upon reliability and economic considerations, and determine which generating units will run at any given time for maximum cost-effectiveness. As a result, OG&E's generating units may produce output that differs from OG&E's customer load requirements. Net fuel and purchased power costs are recovered through fuel adjustment clauses.
Coal
All of OG&E's coal-fired units, with an aggregate capability of 2,516 MWs, are designed to burn low sulfur western sub-bituminous coal. OG&E has contracted for approximately 82 percent of its forecasted annual coal usage via multi-year contracts that expire in 2016. Approximately 10 percent of 2015's usage will be contracted, but undelivered coal from 2014. The remainder of the forecast needs will be procured via the spot market if necessary. In 2014, OG&E purchased 8.2 million tons of coal from various Wyoming suppliers. The combination of all coal has a weighted average sulfur content of 0.23 percent. Based upon the average sulfur content and EPA certified emission data, OG&E's coal units have an approximate emission rate of 0.5 lbs. of SO2 per MMBtu. As discussed in "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Environmental Laws and Regulations," emission limits are expected to become more stringent.
During 2014, railroad cycle times for deliveries of coal to OG&E’s Sooner power plant were higher than historical cycle times. As a result, coal inventory at Sooner is below OG&E’s targeted inventory level. Currently, railroad cycle times are improving and OG&E believes the coal inventory level at Sooner will begin to revert towards OG&E’s targeted level during 2015.
See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Environmental Laws and Regulations" for a discussion of environmental matters which may affect OG&E in the future, including its utilization of coal.
Natural Gas
As a participant in the SPP integrated marketplace, OG&E now purchases a relatively small percentage of its supply through term gas agreements. Alternatively, OG&E relies on a combination of call natural gas agreements, whereby OG&E has the right but not the obligation to purchase a defined quantity of natural gas, combined with day and intra-day purchases to meet the demands of the SPP market.
On March 17, 2014, OG&E entered into a new five year firm no-notice load following gas transportation contract with Enable effective May 1, 2014.
Wind
OG&E's current wind power portfolio includes the following, in addition to the 120 MW Centennial, 101 MW OU Spirit and 227.5 MW Crossroads wind farms owned by OG&E: (i) access to up to 50 MWs of electricity generated at a wind farm near Woodward, Oklahoma from a 15-year contract OG&E entered into with FPL Energy that expires in 2018, (ii) access to up to 152 MWs of electricity generated at a wind farm in Woodward County, Oklahoma from a 20-year contract OG&E entered into with CPV Keenan that expires in 2030, (iii) access to up to 130 MWs of electricity generated at a wind farm in Dewey County, Oklahoma from a 20-year contract OG&E entered into with Edison Mission Energy that expires in 2030 and (iv) access to up to 60 MWs of electricity generated at a wind farm near Blackwell, Oklahoma from a 20-year contract OG&E entered into with NextEra Energy that expires in 2032.
Safety and Health Regulation
OG&E is subject to a number of Federal and state laws and regulations, including OSHA, EPA and comparable state statutes, whose purpose is to protect the safety and health of workers.
In addition, the OSHA hazard communication standard, the EPA Emergency Planning and Community Right-to-Know regulations under Title III of the Federal Superfund Amendment and Reauthorization Act and comparable state statutes require that information be maintained concerning hazardous materials stored, used or produced in OG&E's operations and that this information be provided or made available to employees, state and local government authorities and citizens. OG&E believes that it is in material compliance with all applicable laws and regulations relating to worker safety and health.
ENVIRONMENTAL MATTERS
General
The activities of OG&E are subject to numerous, stringent and complex Federal, state and local laws and regulations governing environmental protection. These laws and regulations can change, restrict or otherwise impact OG&E's business activities in many ways including the handling or disposal of waste material, future construction activities to avoid or mitigate harm to threatened or endangered species and requiring the installation and operation of emissions pollution control equipment. Failure to comply with these laws and regulations could result in the assessment of administrative, civil and criminal penalties, the imposition of remedial requirements and the issuance of orders enjoining future operations. OG&E believes that its operations are in substantial compliance with current Federal, state and local environmental standards.
The trend in environmental regulation, however, is to place more restrictions and limitations on activities that may affect the environment. OG&E cannot assure that future events, such as changes in existing laws, the promulgation of new laws or regulations, or the development or discovery of new facts or conditions will not cause it to incur significant costs. Management continues to evaluate its compliance with existing and proposed environmental legislation and regulations and implement appropriate environmental programs in a competitive market.
It is estimated that OG&E's total expenditures to comply with environmental laws, regulations and requirements for 2015 will be approximately $136.0 million, of which $116.0 million is for capital expenditures. It is estimated that OG&E's total expenditures to comply with environmental laws, regulations and requirements for 2016 will be approximately $159.0 million, of which $139.0 million is for capital expenditures. The amounts above include capital expenditures for low NOX burners, activated carbon injection and scrubbers. OG&E's management believes that all of its operations are in substantial compliance with current Federal, state and local environmental standards. Management continues to evaluate its compliance with existing and proposed environmental legislation and regulations and implement appropriate environmental programs in a competitive market.
For a further discussion of environmental matters that may affect OG&E, see "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Environmental Laws and Regulations."
FINANCE AND CONSTRUCTION
Future Capital Requirements and Financing Activities
Capital Requirements
OG&E's primary needs for capital are related to acquiring or constructing new facilities and replacing or expanding existing facilities. Other working capital requirements are expected to be primarily related to maturing debt, operating lease obligations, fuel clause under and over recoveries and other general corporate purposes. OG&E generally meets its cash needs through a combination of cash generated from operations, short-term borrowings (through a combination of bank borrowings, commercial paper and borrowings from OGE Energy) and permanent financings. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources" for a discussion of OG&E's capital requirements.
Capital Expenditures
OG&E's estimates of capital expenditures for the years 2015 through 2019 are shown in the following table. These capital expenditures represent the base maintenance capital expenditures (i.e., capital expenditures to maintain and operate OG&E's business) plus capital expenditures for known and committed projects.
(A)
Approximately 30% of revenue requirement allocated to SPP members other than OG&E.
(B)
Approximately 85% of revenue requirement allocated to SPP members other than OG&E.
(D)
Represent capital costs associated with OG&E’s Environmental Compliance Plan to comply with the EPA’s MATS and Regional Haze rules. More detailed discussion regarding Regional Haze and OG&E’s Environmental Compliance Plan can be found in Note 13 of Notes to Financial Statements under "Environmental Compliance Plan" in Item 8 of Part II of this Form 10-K, and under “Environmental Laws and Regulations” within “Management's Discussion and Analysis of Financial Condition and Results of Operations” under Part II, Item 7 of this Form 10-K.
Additional capital expenditures beyond those identified in the table above, including additional incremental growth opportunities in electric transmission assets, will be evaluated based upon their impact upon achieving OG&E's financial objectives.
Pension and Postretirement Benefit Plans
During 2013, OGE Energy made contributions to its Pension Plan of $35 million, of which none was OG&E's portion. During 2014, OGE Energy did not make any contributions to its Pension Plan. OGE Energy has not yet determined whether it will need to make any contributions to the Pension Plan in 2015. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources - Future Capital Requirements and Financing Activities" for a discussion of OGE Energy's pension and postretirement benefit plans.
Future Sources of Financing
Management expects that cash generated from operations, proceeds from the issuance of long and short-term debt and funds received from OGE Energy (from proceeds from the sales of its common stock to the public through OGE Energy's Automatic Dividend Reinvestment and Stock Purchase Plan or other offerings) will be adequate over the next three years to meet anticipated cash needs and to fund future growth opportunities. OG&E utilizes short-term borrowings (through a combination of bank borrowings, commercial paper and borrowings from OGE Energy) to satisfy temporary working capital needs and as an interim source of financing capital expenditures until permanent financing is arranged.
Short-Term Debt and Credit Facility
At December 31, 2014, there were $215.6 million in advances to OGE Energy as compared to $87.2 million in outstanding advances from OGE Energy in 2013. OG&E has an intercompany borrowing agreement with OGE Energy whereby OG&E has access to up to $400 million of OGE Energy's revolving credit amount. This agreement has a termination date of December 13, 2018. At December 31, 2014, there were no intercompany borrowings under this agreement. OG&E has a $400 million revolving credit facility which is available to back up OG&E's commercial paper borrowings and to provide revolving credit borrowings. This bank facility can also be used as a letter of credit facility. At December 31, 2014, there was $2.0 million supporting letters of credit at a weighted-average interest rate of 0.95 percent. There were no outstanding borrowings under this revolving credit agreement and no outstanding commercial paper borrowings at December 31, 2014. At December 31, 2014, OG&E had $398.0 million of net available liquidity under its revolving credit agreement. OG&E has the necessary regulatory approvals to incur up to $800 million in short-term borrowings at any one time for a two-year period beginning January 1, 2015 and ending December 31, 2016. See Note 10 of Notes to Financial Statements for a discussion of OG&E's short-term debt activity.
In December 2011, OG&E entered into an unsecured five-year revolving credit agreement for $400.0 million. This credit facility contained an option, which could be exercised up to two times, to extend the term for an additional year. In the third quarter of 2013, OG&E utilized one of these one-year extensions, and received consent from all of the lenders, to extend the maturity of its credit agreement from December 13, 2016 to December 13, 2017. In the second quarter of 2014, OG&E utilized its second extension to extend the maturity of its credit facility from December 13, 2017 to December 13, 2018. As of December 31, 2014, the commitment of a single existing lender with respect to approximately $8.7 million of OG&E's credit facility, however, was not extended and, unless the non-extending lender is replaced in accordance with the terms of the credit facility, the commitment will expire December 13, 2017.
Issuance of Long-Term Debt
On March 25, 2014, OG&E completed the issuance of $250 million of 4.55 percent senior notes due March 15, 2044. The proceeds from the issuance were added to OG&E's general funds and were used to repay debt, fund capital expenditures and general corporate expenses, and utilized for working capital purposes.
On December 11, 2014, OG&E completed the issuance of $250 million of 4.00 percent Senior Notes, Series due December 15, 2044. The proceeds from the issuance were added to OG&E's general funds and were used to repay short-term debt, fund capital expenditures and general corporate expenses, and utilized for working capital purposes.
Redemption of Long-Term Debt
On August 1, 2014, OG&E redeemed all $140 million principal amount outstanding of its 6.50 percent senior notes due August 1, 2034 at 103.25 percent of their principal amount, plus accrued interest. The redemption premium of $4.6 million was deferred and will be amortized through March 2044 to match the expected regulatory treatment.
EMPLOYEES
OG&E had 1,884 employees at December 31, 2014.
EXECUTIVE OFFICERS
The following persons were Executive Officers of the Registrant as of February 26, 2015:
No family relationship exists between any of the Executive Officers of the Registrant. Messrs. Delaney, Merrill, Trauschke, Bullard, Forbes, Renfrow, Walworth and Ms. Horn are also officers of OGE Energy. Each Executive Officer is to hold office until the Board of Directors meeting following the next Annual Meeting of Shareowners of OGE Energy, currently scheduled for May 14, 2015.
The business experience of each of the Executive Officers of the Registrant for the past five years is as follows:
ACCESS TO SECURITIES AND EXCHANGE COMMISSION FILINGS
OGE Energy's web site address is www.oge.com. Through OGE Energy's website under the heading "Corporate," "Investor Relations," "SEC Filings," OGE Energy makes available, free of charge, OGE Energy's and OG&E's annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 as soon as reasonably practicable after such material is electronically filed with or furnished to the Securities and Exchange Commission. Our Internet website and the information contained therein or connected thereto are not intended to be incorporated into this Form 10-K and should not be considered a part of this Form 10-K.
Item 1A.
Item 1A. Risk Factors.
In the discussion of risk factors set forth below, unless the context otherwise requires, the terms "we," "our" and "us" refer to OG&E. In addition to the other information in this Form 10-K and other documents filed by us with the Securities and Exchange Commission from time to time, the following factors should be carefully considered in evaluating OG&E. Such factors could affect actual results and cause results to differ materially from those expressed in any forward-looking statements made by or on behalf of us. Additional risks and uncertainties not currently known to us or that we currently view as immaterial may also impair our business operations.
REGULATORY RISKS
OG&E's profitability depends to a large extent on the ability to fully recover its costs from its customers and there may be changes in the regulatory environment that impair its ability to recover costs from its customers.
OG&E is subject to comprehensive regulation by several Federal and state utility regulatory agencies, which significantly influences its operating environment and its ability to fully recover its costs from utility customers. Recoverability of any under recovered amounts from OG&E's customers due to a rise in fuel costs is a significant risk. The utility commissions in the states where OG&E operates regulate many aspects of its utility operations including siting and construction of facilities, customer service and the rates that OG&E can charge customers. The profitability of the utility operations is dependent on OG&E's ability to fully recover costs related to providing energy and utility services to its customers.
In recent years, the regulatory environments in which OG&E operates have received an increased amount of attention. It is possible that there could be changes in the regulatory environment that would impair OG&E's ability to fully recover costs historically paid by OG&E's customers. State utility commissions generally possess broad powers to ensure that the needs of the utility customers are being met. OG&E cannot assure that the OCC, APSC and the FERC will grant rate increases in the future or in the amounts requested, and they could instead lower OG&E's rates.
OG&E is unable to predict the impact on its operating results from the future regulatory activities of any of the agencies that regulate OG&E. Changes in regulations or the imposition of additional regulations could have an adverse impact on OG&E's results of operations.
OG&E's rates are subject to rate regulation by the states of Oklahoma and Arkansas, as well as by a Federal agency, whose regulatory paradigms and goals may not be consistent.
OG&E is currently a vertically integrated electric utility. Most of its revenue results from the sale of electricity to retail customers subject to bundled rates that are approved by the applicable state utility commission and from the sale of electricity to wholesale customers subject to rates and other matters approved by the FERC.
OG&E operates in Oklahoma and western Arkansas and is subject to rate regulation by the OCC and the APSC, in addition to the FERC. Exposure to inconsistent state and Federal regulatory standards may limit our ability to operate profitably. Further alteration of the regulatory landscape in which we operate, including a change in our return on equity, may harm our financial position and results of operations.
Costs of compliance with environmental laws and regulations are significant and the cost of compliance with future environmental laws and regulations may adversely affect our results of operations, financial position, or liquidity.
We are subject to extensive Federal, state and local environmental statutes, rules and regulations relating to air quality, water quality, waste management, wildlife conservation, natural resources and health and safety that could, among other things, restrict or limit the output of certain facilities or the use of certain fuels required for the production of electricity and/or require
additional pollution control equipment and otherwise increase costs. There are significant capital, operating and other costs associated with compliance with these environmental statutes, rules and regulations and those costs may be even more significant in the future. As discussed in "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Environmental Laws and Regulations". As discussed in "Pending Regulatory Matters", OG&E is required to comply with the EPA's FIP by January 4, 2019 and has in response to this requirement, filed an application with the OCC for approval of its plan to comply with the EPA's MATS and Regional Haze FIP.
In response to recent regulatory and judicial decisions, emissions of greenhouse gases including, most significantly, carbon dioxide could be restricted in the future as a result of Federal or state legal requirements or litigation relating to greenhouse gas emissions. If mandatory reductions of carbon dioxide and other greenhouse gases are required in the future, this could result in significant additional compliance costs that would affect our future financial position, results of operations and cash flows if such costs are not recovered through regulated rates. The EPA has started a process to implement carbon dioxide emission limitations for existing electric generating units, and neither the outcome of the rule making process nor the timing of any required expenditures resulting from the EPA rule making process can be predicted with any certainty at this time.
There is inherent risk of the incurrence of environmental costs and liabilities in our operations and historical industry operations practices. These activities are subject to stringent and complex Federal, state and local laws and regulations that can restrict or impact OG&E's business activities in many ways, such as restricting the way it can handle or dispose of its wastes or requiring remedial action to mitigate pollution conditions that may be caused by its operations or that are attributable to former operators. OG&E may be unable to recover these costs from insurance. Moreover, the possibility exists that stricter laws, regulations or enforcement policies could significantly increase compliance costs and the cost of any remediation that may become necessary.
For a further discussion of environmental matters that may affect OG&E, see "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Environmental Laws and Regulations."
We may not be able to recover the costs of our substantial planned investment in capital improvements and additions.
OG&E's business plan calls for extensive investment in capital improvements and additions, including the installation of environmental upgrades and retrofits and modernizing existing infrastructure as well as other initiatives. Significant portions of OG&E's facilities were constructed many years ago. Older generation equipment, even if maintained in accordance with good engineering practices, may require significant capital expenditures to maintain efficiency, to comply with changing environmental requirements or to provide reliable operations. OG&E currently provides service at rates approved by one or more regulatory commissions. If these regulatory commissions do not approve adjustments to the rates OG&E charges, it would not be able to recover the costs associated with its planned extensive investment. This could adversely affect OG&E's financial position and results of operations. While OG&E may seek to limit the impact of any denied recovery by attempting to reduce the scope of its capital investment, there can no assurance as to the effectiveness of any such mitigation efforts, particularly with respect to previously incurred costs and commitments.
Our jurisdictions have fuel clauses that permit us to recover fuel costs through rates without a general rate case. While prudent capital investment and variable fuel costs each generally warrant recovery, in practical terms our regulators could limit the amount or timing of increased costs that we would recover through higher rates. Any such limitation could adversely affect our results of operations and financial position.
The regional power market in which OG&E operates has changing transmission regulatory structures, which may affect the transmission assets and related revenues and expenses.
OG&E currently owns and operates transmission and generation facilities as part of a vertically integrated utility. OG&E is a member of the SPP regional transmission organization and has transferred operational authority (but not ownership) of OG&E's transmission facilities to the SPP. On March 1, 2014, the SPP implemented and the FERC approved regional day ahead and real-time markets for energy and operating reserves, as well as associated transmission congestion rights. Collectively the three markets operate together under the global name, SPP Integrated Marketplace. OG&E represents owned and contracted generation assets and customer load in the SPP Integrated Marketplace for the sole benefit of its’ customers. OG&E has not participated in the SPP Integrated Marketplace for any speculative trading activities. OG&E records SPP Integrated Marketplace transactions as sales or purchases with results reported as Operating Revenues or Cost of Goods Sold in its Financial Statements. OG&E's revenues, expenses, assets and liabilities may be adversely affected by changes in the organization, operation and regulation of the SPP Integrated Marketplace by the FERC or the SPP.
Increased competition resulting from restructuring efforts could have a significant financial impact on OG&E and consequently decrease our revenue.
We have been and will continue to be affected by competitive changes to the utility and energy industries. Significant changes already have occurred and additional changes have been proposed to the wholesale electric market. Although retail restructuring efforts in Oklahoma and Arkansas have been postponed for the time being, if such efforts were renewed, retail competition and the unbundling of regulated energy service could have a significant financial impact on us due to possible impairments of assets, a loss of retail customers, lower profit margins and/or increased costs of capital. Any such restructuring could have a significant impact on our financial position, results of operations and cash flows. We cannot predict when we will be subject to changes in legislation or regulation, nor can we predict the impact of these changes on our financial position, results of operations or cash flows.
Events that are beyond our control have increased the level of public and regulatory scrutiny of our industry. Governmental and market reactions to these events may have negative impacts on our business, financial position, results of operations, cash flows and access to capital.
As a result of accounting irregularities at public companies in general, and energy companies in particular, and investigations by governmental authorities into energy trading activities, public companies, including those in the regulated and unregulated utility business, have been under public and regulatory scrutiny and suspicion. The accounting irregularities have caused regulators and legislators to review current accounting practices, financial disclosures and relationships between companies and their independent auditors. The capital markets and rating agencies also have increased their level of scrutiny. We believe that we are complying with all applicable laws and accounting standards, but it is difficult or impossible to predict or control what effect these types of events may have on our business, financial position, cash flows or access to the capital markets. It is unclear what additional laws or regulations may develop, and we cannot predict the ultimate impact of any future changes in accounting regulations or practices in general with respect to public companies, the energy industry or our operations specifically. Any new accounting standards could affect the way we are required to record revenues, expenses, assets, liabilities and equity. These changes in accounting standards could lead to negative impacts on reported earnings or decreases in assets or increases in liabilities that could, in turn, affect our results of operations and cash flows.
We are subject to substantial utility and energy regulation by governmental agencies. Compliance with current and future utility and energy regulatory requirements and procurement of necessary approvals, permits and certifications may result in significant costs to us.
We are subject to substantial regulation from Federal, state and local regulatory agencies. We are required to comply with numerous laws and regulations and to obtain permits, approvals and certificates from the governmental agencies that regulate various aspects of our businesses, including customer rates, service regulations, retail service territories, sales of securities, asset acquisitions and sales, accounting policies and practices and the operation of generating facilities. We believe the necessary permits, approvals and certificates have been obtained for our existing operations and that our business is conducted in accordance with applicable laws; however, we are unable to predict the impact on our operating results from future regulatory activities of these agencies.
In compliance with the Energy Policy Act of 2005, the FERC approved the North American Electric Reliability Corporation as the national energy reliability organization. The North American Electric Reliability Corporation is responsible for the development and enforcement of mandatory reliability and cyber security standards for the wholesale electric power system. OG&E's plan is to comply with all applicable standards and to expediently correct a violation should it occur. The North American Electric Reliability Corporation has authority to assess penalties up to $1.0 million per day per violation for noncompliance. In order to comply with new or updated security regulations, we may be required to make changes to our current operations which could also result in additional expenses. OG&E is subject to a North American Electric Reliability Corporation compliance audit every three years as well as periodic spot check audits and cannot predict the outcome of those audits.
OPERATIONAL RISKS
Our results of operations may be impacted by disruptions beyond our control.
We are exposed to risks related to performance of contractual obligations by our suppliers. We are dependent on coal and natural gas for much of our electric generating capacity. We rely on suppliers to deliver coal and natural gas in accordance with short and long-term contracts. We have certain supply contracts in place; however, there can be no assurance that the counterparties to these agreements will fulfill their obligations to supply coal and natural gas to us. The suppliers under these agreements may experience financial or technical problems that inhibit their ability to fulfill their obligations to us. In addition,
the suppliers under these agreements may not be required to supply coal and natural gas to us under certain circumstances, such as in the event of a natural disaster. Deliveries may be subject to short-term interruptions or reductions due to various factors, including transportation problems, weather and availability of equipment. Failure or delay by our suppliers of coal and natural gas deliveries could disrupt our ability to deliver electricity and require us to incur additional expenses to meet the needs of our customers.
Also, because our generation and transmission systems are part of an interconnected regional grid, we face the risk of possible loss of business due to a disruption or black-out caused by an event (severe storm, generator or transmission facility outage) on a neighboring system or the actions of a neighboring utility. Any such disruption could result in a significant decrease in revenues and significant additional costs to repair assets, which could have a material adverse impact on our financial position, results of operations and cash flows.
OG&E's electric generating facilities are subject to operational risks that could result in unscheduled plant outages, unanticipated operation and maintenance expenses and increased purchase power costs.
OG&E owns and operates coal-fired, natural gas-fired and wind-powered generating facilities. Operation of electric generating facilities involves risks that can adversely affect energy output and efficiency levels. Included among these risks are:
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increased prices for fuel and fuel transportation as existing contracts expire;
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facility shutdowns due to a breakdown or failure of equipment or processes or interruptions in fuel supply;
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operator error or safety related stoppages;
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disruptions in the delivery of electricity; and
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catastrophic events such as fires, explosions, tornadoes, floods, earthquakes or other similar occurrences.
Changes in technology and regulatory policies may cause our generating facilities to be less competitive.
OG&E primarily generates electricity at large central facilities. This method typically results in economies of scale and lower costs than newer technologies such as fuel cells, microturbines, windmills and photovoltaic solar cells. It is possible that advances in technologies or changes in regulatory policies will reduce costs of new technology to levels that are equal to or below that of most central station electricity production, which could have a material adverse effect on our results of operations.
Economic conditions could negatively impact our business and our results of operations.
Our operations are affected by local, national and worldwide economic conditions. The consequences of a prolonged recession could include a lower level of economic activity and uncertainty regarding energy prices and the capital and commodity markets. A lower level of economic activity could result in a decline in energy consumption, which could adversely affect our revenues and future growth. Instability in the financial markets, as a result of recession or otherwise, also could affect the cost of capital and our ability to raise capital.
Current economic conditions may be exacerbated by insufficient financial sector liquidity leading to potential increased unemployment, which could impact the ability of our customers to pay timely, increase customer bankruptcies, and could lead to increased bad debt. If such circumstances occur, we expect that commercial and industrial customers would be impacted first, with residential customers following.
In addition, economic conditions, particularly budget shortfalls, could lead to increased pressure on Federal, state and local governments to raise additional funds, including through increased corporate taxes and/or through delaying, reducing or eliminating tax credits, grants or other incentives, which could have a material adverse impact on our results of operations and cash flows.
We are subject to financial risks associated with climate change.
Climate change creates financial risk. Potential regulation associated with climate change legislation could pose financial risks to OG&E. In addition, to the extent that any climate change adversely affects the national or regional economic health through increased rates caused by the inclusion of additional regulatory imposed costs (carbon dioxide taxes or costs associated with additional regulatory requirements), OG&E may be adversely impacted. A declining economy could adversely impact the overall financial health of OG&E because of lack of load growth and decreased sales opportunities. To the extent financial markets view climate change and emissions of greenhouse gases as a financial risk, this could negatively affect our ability to access capital markets or cause us to receive less than ideal terms and conditions.
We are subject to cyber security risks and increased reliance on processes automated by technology.
In the regular course of our businesses, we handle a range of sensitive security and customer information. We are subject to laws and rules issued by different agencies concerning safeguarding and maintaining the confidentiality of this information. A security breach of our information systems such as theft or inappropriate release of certain types of information, including confidential customer information or system operating information, could have a material adverse impact on our financial position, results of operations and cash flows.
OG&E operates in a highly regulated industry that requires the continued operation of sophisticated information technology systems and network infrastructure. Despite implementation of security measures, the technology systems are vulnerable to disability, failures or unauthorized access. Such failures or breaches of the systems could impact the reliability of OG&E's generation, transmission and distribution systems (including smart grid) which may result in a loss of service to customers and also subjects OG&E to financial harm due to the significant expense to repair security breaches or system damage. The implementation of OG&E's smart grid program further increases potential risks associated with cyber security attacks. If the technology systems were to fail or be breached and not recovered in a timely way, critical business functions could be impaired and sensitive confidential data could be compromised, which could have a material adverse impact on its financial position, results of operations and cash flows.
Our security procedures, which include among others, virus protection software, cyber security and our business continuity planning, including disaster recovery policies and back-up systems, may not be adequate or implemented properly to fully address the adverse affect of cyber security attacks on our systems, which could adversely impact our operations.
Terrorist attacks, and the threat of terrorist attacks, have resulted in increased costs to our business. Continued hostilities in the Middle East or other sustained military campaigns may adversely impact our financial position, results of operations and cash flows.
The long-term impact of terrorist attacks and the magnitude of the threat of future terrorist attacks on the electric utility industry in general, and on us in particular, cannot be known. Increased security measures taken by us as a precaution against possible terrorist attacks have resulted in increased costs to our business. Uncertainty surrounding continued hostilities in the Middle East or other sustained military campaigns may affect our operations in unpredictable ways, including disruptions of supplies and markets for our products, and the possibility that our infrastructure facilities could be direct targets of, or indirect casualties of, an act of terror. Changes in the insurance markets attributable to terrorist attacks may make certain types of insurance more difficult for us to obtain. Moreover, the insurance that may be available to us may be significantly more expensive than existing insurance coverage.
Weather conditions such as tornadoes, thunderstorms, ice storms, wind storms, and prolonged droughts, as well as seasonal temperature variations may adversely affect our financial position, results of operations and cash flows.
Weather conditions directly influence the demand for electric power. In OG&E's service area, demand for power peaks during the hot summer months, with market prices also typically peaking at that time. As a result, overall operating results may fluctuate on a seasonal and quarterly basis. In addition, we have historically sold less power, and consequently received less revenue, when weather conditions are milder. Unusually mild weather in the future could reduce our revenues, net income, available cash and borrowing ability. Severe weather, such as tornadoes, thunderstorms, ice storms and wind storms, may cause outages and property damage which may require us to incur additional costs that are generally not insured and that may not be recoverable from customers. The effect of the failure of our facilities to operate as planned, as described above, would be particularly burdensome during a peak demand period. In addition, prolonged droughts could cause a lack of sufficient water for use in cooling during the electricity generating process.
FINANCIAL RISKS
Market performance, increased retirements, changes in retirement plan regulations and increasing costs associated with our Pension Plan, health care plans and other employee-related benefits may adversely affect our financial position, results of operations or cash flow.
OGE Energy has a Pension Plan that covers a significant amount of our employees hired before December 1, 2009. OGE Energy also has defined benefit postretirement plans that cover a significant amount of our employees hired prior to February 1, 2000. Assumptions related to future costs, returns on investments, interest rates and other actuarial assumptions with respect to the defined benefit retirement and postretirement plans have a significant impact on our results of operations and funding requirements. Based on our assumptions at December 31, 2014, OGE Energy expects to continue to make future contributions
to maintain required funding levels. At times, it has been OGE Energy's practice to also make voluntary contributions to maintain more prudent funding levels than minimally required. We may continue to make voluntary contributions in the future. These amounts are estimates and may change based on actual stock market performance, changes in interest rates and any changes in governmental regulations.
If the employees who participate in the Pension Plan retire when they become eligible for retirement over the next several years, or if our plan experiences adverse market returns on its investments, or if interest rates materially fall, our pension expense and contributions to the plans could rise substantially over historical levels. The timing and number of employees retiring and selecting the lump-sum payment option could result in pension settlement charges that could materially affect our results of operations if we are unable to recover these costs through our electric rates. In addition, assumptions related to future costs, returns on investments, interest rates and other actuarial assumptions, including projected retirements, have a significant impact on our financial position and results of operations. Those factors are outside of our control.
In addition to the costs of our Pension Plan, the costs of providing health care benefits to our employees and retirees have increased substantially in recent years. We believe that our employee benefit costs, including costs related to health care plans for our employees, will continue to rise. The increasing costs and funding requirements with our Pension Plan, health care plans and other employee benefits may adversely affect our financial position, results of operations or liquidity.
We face certain human resource risks associated with the availability of trained and qualified labor to meet our future staffing requirements.
Workforce demographic issues challenge employers nationwide and are of particular concern to the electric utility industry. The median age of utility workers is significantly higher than the national average. Over the next three years, 33 percent of our current employees will be eligible to retire with full pension benefits. Failure to hire and adequately train replacement employees, including the transfer of significant internal historical knowledge and expertise to the new employees, may adversely affect our ability to manage and operate our business.
We may be able to incur substantially more indebtedness, which may increase the risks created by our indebtedness.
The terms of the indentures governing our debt securities do not fully prohibit us from incurring additional indebtedness. If we are in compliance with the financial covenants set forth in our revolving credit agreement and the indentures governing our debt securities, we may be able to incur substantial additional indebtedness. If we incur additional indebtedness, the related risks that we and they now face may intensify.
Any reductions in our credit ratings could increase our financing costs and the cost of maintaining certain contractual relationships or limit our ability to obtain financing on favorable terms.
We cannot assure you that any of our current credit ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances so warrant. Our ability to access the commercial paper market could be adversely impacted by a credit ratings downgrade or major market disruptions. Pricing grids associated with OGE Energy's and OG&E's credit facilities could cause annual fees and borrowing rates to increase if an adverse rating impact occurs. The impact of any future downgrade could include an increase in the costs of our short-term borrowings, but a reduction in our credit ratings would not result in any defaults or accelerations. Any future downgrade of OGE Energy or OG&E could also lead to higher long-term borrowing costs and, if below investment grade, would require us to post collateral or letters of credit.
Our debt levels may limit our flexibility in obtaining additional financing and in pursuing other business opportunities.
We have a revolving credit agreement for working capital, capital expenditures, including acquisitions, and other corporate purposes. The levels of our debt could have important consequences, including the following:
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the ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or the financing may not be available on favorable terms;
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a portion of cash flows will be required to make interest payments on the debt, reducing the funds that would otherwise be available for operations and future business opportunities; and
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our debt levels may limit our flexibility in responding to changing business and economic conditions.
We are exposed to the credit risk of our key customers and counterparties, and any material nonpayment or nonperformance by our key customers and counterparties could adversely affect our financial position, results of operations and cash flows.
We are exposed to credit risks in our generation and retail distribution operations. Credit risk includes the risk that counterparties that owe us money or energy will breach their obligations. If the counterparties to these arrangements fail to perform, we may be forced to enter into alternative arrangements. In that event, our financial results could be adversely affected and we could incur losses.
Item 1B.
Item 1B. Unresolved Staff Comments.
None.
Item 2.
Item 2. Properties.
OG&E owns and operates an interconnected electric generation, transmission and distribution system, located in Oklahoma and western Arkansas, which included 10 generating stations with an aggregate capability of 6,845 MWs at December 31, 2014. The following tables set forth information with respect to OG&E's electric generating facilities, all of which are located in Oklahoma.
(A)
2014 Capacity Factor = 2014 Net Actual Generation / (2014 Net Maximum Capacity (Nameplate Rating in MWs) x Period Hours (8,760 Hours)).
(B)
Peaking units are used when additional short-term capacity is required.
(C)
Represents OG&E's 51 percent ownership interest in the Redbud Plant.
(D)
Represents OG&E's 77 percent ownership interest in the McClain Plant.
At December 31, 2014, OG&E's transmission system included: (i) 53 substations with a total capacity of 13.0 million kilovolt-amps and 4,888 structure miles of lines in Oklahoma and (ii) seven substations with a total capacity of 2.4 million kilovolt-amps and 277 structure miles of lines in Arkansas. OG&E's distribution system included: (i) 354 substations with a total capacity of 9.7 million kilovolt-amps, 29,197 structure miles of overhead lines, 2,369 miles of underground conduit and 10,646 miles of underground conductors in Oklahoma and (ii) 31 substations with a total capacity of 1.0 million kilovolt-amps, 2,778 structure miles of overhead lines, 243 miles of underground conduit and 694 miles of underground conductors in Arkansas.
OG&E owns 140,133 square feet of office space at its executive offices at 321 North Harvey, Oklahoma City, Oklahoma 73102. In addition to its executive offices, OG&E owns numerous facilities throughout its service territory that support its operations. These facilities include, but are not limited to, service centers, fleet and equipment service facilities, operation support and other properties.
During the three years ended December 31, 2014, OG&E's gross property, plant and equipment (excluding construction work in progress) additions were $2.3 billion and gross retirements were $260.2 million. These additions were provided by cash generated from operations, short-term borrowings (through a combination of bank borrowings, commercial paper and borrowings from OGE Energy), long-term borrowings and permanent financings. The additions during this three-year period amounted to 23.3 percent of gross property, plant and equipment (excluding construction work in progress) at December 31, 2014.
Item 3.
Item 3. Legal Proceedings.
In the normal course of business, OG&E is confronted with issues or events that may result in a contingent liability. These generally relate to lawsuits or claims made by third parties, including governmental agencies. When appropriate, management consults with legal counsel and other appropriate experts to assess the claim. If, in management's opinion, OG&E has incurred a probable loss as set forth by GAAP, an estimate is made of the loss and the appropriate accounting entries are reflected in OG&E's Financial Statements. At the present time, based on currently available information, OG&E believes that any reasonably possible losses in excess of accrued amounts arising out of pending or threatened lawsuits or claims would not be quantitatively material to its financial statements and would not have a material adverse effect on OG&E's financial position, results of operations or cash flows.
1. Patent Infringement Case. On September 16, 2011, TransData, Inc., a Texas corporation, sued OG&E in the Western District of Oklahoma, accusing OG&E of infringing three of their U.S. patents by using OG&E's General Electric "smart" meters with Silver Spring Networks wireless modules. The complaint seeks a judgment of infringement, unspecified damages, a permanent injunction, costs and attorneys fees. OG&E was served with the complaint on September 21, 2011 and has notified both General Electric and Silver Springs Network of the lawsuit and its intent to seek indemnity from those companies for any damages that it may incur from this lawsuit. TransData, Inc. sought to consolidate its OG&E lawsuit with similar lawsuits in the Eastern District of Texas, however, on December 13, 2011, the TransData, Inc. cases were consolidated in the Western District of Oklahoma. OG&E has filed a motion for extension of time to answer the complaint. On December 30, 2011, OG&E and General Electric agreed to terms for General Electric to provide OG&E with an unqualified defense in the matter and to indemnify OG&E for costs, expenses and damages awarded against OG&E subject to a reservation of rights. While OG&E cannot predict the outcome of this lawsuit at this time, OG&E intends to vigorously defend this action and believes that its ultimate resolution will not be material to OG&E's financial position, results of operations or cash flows.
Item 4.
Item 4. Mine Safety Disclosures.
Not Applicable.
PART II
Item 5.
Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.
Currently, all of OG&E's outstanding common stock is held by OGE Energy. Therefore, there is no public trading market for OG&E's common stock.
In 2014, 2013 and 2012, OG&E declared dividends to OGE Energy of $120.0 million, $170.0 million and $75.0 million, respectively.
Item 6.
Item 6. Selected Financial Data
HISTORICAL DATA
(A)
Capitalization ratios = [Total stockholder's equity / (Total stockholder's equity + Long-term debt + Long-term debt due within one year)] and [(Long-term debt + Long-term debt due within one year) / (Total stockholder's equity + Long-term debt + Long-term debt due within one year)].
(B)
For purposes of computing the ratio of earnings to fixed charges, (i) earnings consist of pre-tax income plus fixed charges, less allowance for borrowed funds used during construction and (ii) fixed charges consist of interest on long-term debt, related amortization, interest on short-term borrowings and a calculated portion of rents considered to be interest.
Item 7.
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations.
Introduction
OG&E generates, transmits, distributes and sells electric energy in Oklahoma and western Arkansas. Its operations are subject to regulation by the OCC, the APSC and the FERC. OG&E was incorporated in 1902 under the laws of the Oklahoma Territory. OG&E is the largest electric utility in Oklahoma and its franchised service territory includes the Fort Smith, Arkansas area. OG&E sold its retail natural gas business in 1928 and is no longer engaged in the natural gas distribution business. OG&E is a wholly-owned subsidiary of OGE Energy, an energy and energy services provider offering physical delivery and related services for both electricity and natural gas primarily in the south central United States.
Overview
OG&E Strategy
OGE Energy's mission, through OG&E and its equity interest in Enable, is to fulfill its critical role in the nation's electric utility and natural gas midstream pipeline infrastructure and meet individual customers' needs for energy and related services focusing on safety, efficiency, reliability, customer service and risk management.
OG&E is focused on:
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Providing exceptional customer experiences by continuing to improve customer interfaces, tools, products and services that deliver high customer satisfaction and operating productivity.
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Providing safe, reliable energy to the communities and customers we serve. A particular focus is on enhancing the value of the grid by improving distribution grid reliability by reducing the frequency and duration of customer interruptions and leveraging previous grid technology investments.
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Maintaining strong regulatory and legislative relationships for the long-term benefit of our customers, investors and members.
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Continuing to grow a zero-injury culture and deliver top-quartile safety results.
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Expanding transmission investments beyond traditional opportunities.
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Executing on OG&E’s Environmental Compliance Plan.
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Ensuring we have the necessary mix of generation resources to meet the long term needs of our customers.
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Continuing focus on operational excellence and efficiencies in order to protect the customer bill.
Summary of Operating Results
2014 compared to 2013. OG&E reported net income of $292.0 million and $292.6 million, respectively, in 2014 and 2013, a decrease of $0.6 million, or 0.2 percent, reflecting an increase in depreciation expense due to additional assets being placed in service in 2014, a decrease in gross margin related to milder weather compared to 2013, an increase in other operation and maintenance expense and an increase in interest expense related to the issuance of debt. Partially offsetting these items was an increase in wholesale transmission revenues, an increase in customer growth and a decrease in incentive compensation
2013 compared to 2012. OG&E reported net income of $292.6 million and $280.3 million, respectively, in 2013 and 2012, an increase of $12.3 million, or 4.4 percent, driven by higher gross margin primarily related to increased wholesale transmission revenue and lower other operation and maintenance expense, partially offset by higher interest expense related to the issuance of debt in May 2013
2015 Outlook
OG&E projects to earn approximately $282 million to $298 million, in 2015 and is based on the following assumptions:
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Normal weather patterns are experienced for the remainder of the year;
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Gross margin on revenues of approximately $1.375 billion to $1.385 billion based on sales growth of approximately 1 percent on a weather-adjusted basis;
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Approximately $114 million of gross margin is primarily attributed to regionally allocated transmission projects;
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Operating expenses of approximately $844 million to $861 million, with operation and maintenance expenses comprising 54 percent of the total;
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Interest expense of approximately $146 million which assumes a $5 million allowance for borrowed funds used during construction reduction to interest expense;
•
Other income of approximately $17 million including approximately $9 million of allowance for equity funds used during construction; and
•
An effective tax rate of approximately 27 percent.
OG&E has significant seasonality in its earnings. OG&E typically shows minimal earnings in the first and fourth quarters with a majority of earnings in the third quarter due to the seasonal nature of air conditioning demand.
Gross Margin is defined by OG&E as operating revenues less fuel, purchased power and certain transmission expenses. Gross margin is a non-GAAP financial measure because it excludes depreciation and amortization, and other operation and maintenance expenses. Expenses for fuel and purchased power are recovered through fuel adjustment clauses and as a result changes in these expenses are offset in operating revenues with no impact on net income. OG&E believes gross margin provides a more meaningful basis for evaluating its operations across periods than operating revenues because gross margin excludes the revenue effect of fluctuations in these expenses. Gross margin is used internally to measure performance against budget and in reports for management and the Board of Directors. OG&E's definition of gross margin may be different from similar terms used by other companies.
Reconciliation of gross margin to revenue:
(A)
Based on the midpoint of OG&E earnings guidance for 2015.
Results of Operations
The following discussion and analysis presents factors that affected OG&E's results of operations for the years ended December 31, 2014, 2013 and 2012 and OG&E's financial position at December 31, 2014 and 2013. The following information should be read in conjunction with the Financial Statements and Notes thereto. Known trends and contingencies of a material nature are discussed to the extent considered relevant.
(A)
Degree days are calculated as follows: The high and low degrees of a particular day are added together and then averaged. If the calculated average is above 65 degrees, then the difference between the calculated average and 65 is expressed as cooling degree days, with each degree of difference equaling one cooling degree day. If the calculated average is below 65 degrees, then the difference between the calculated average and 65 is expressed as heating degree days, with each degree of difference equaling one heating degree day. The daily calculations are then totaled for the particular reporting period.
2014 compared to 2013. OG&E's net income decreased 0.6 million, or 0.2 percent, in 2014 as compared to 2013 primarily due to higher gross margin, which was almost offset by higher other operations and maintenance expense, higher depreciation and amortization expense, and interest expense.
Gross Margin
Gross Margin is defined by OG&E as operating revenues less fuel, purchased power and certain transmission expenses. Gross margin is a non-GAAP financial measure because it excludes depreciation and amortization, and other operation and maintenance expenses. Expenses for fuel and purchased power are recovered through fuel adjustment clauses and as a result changes in these expenses are offset in operating revenues with no impact on net income. OG&E believes gross margin provides a more meaningful basis for evaluating its operations across periods than operating revenues because gross margin excludes the revenue effect of fluctuations in these expenses. Gross margin is used internally to measure performance against budget and in reports for management and the Board of Directors. OG&E's definition of gross margin may be different from similar terms used by other companies.
Operating revenues were $2,453.1 million in 2014 as compared to $2,262.2 million in 2013, an increase of $190.9 million, or 8.4 percent. Cost of sales were $1,106.6 million in 2014 as compared to $965.9 million in 2013, an increase of $140.7 million, or 14.6 percent. Gross margin was $1,346.5 million in 2014 as compared to $1,296.3 million in 2013, an increase of $50.2 million, or 3.9 percent. The below factors contributed to the change in gross margin:
(A)
Increased primarily due to higher investments related to certain FERC approved transmission projects included in formula rates.
(B)
Increased due to higher rider revenues primarily from the Oklahoma Demand Program rider, the Oklahoma Storm Recovery rider and the Arkansas Demand Program rider partially offset by lower rider revenues from the Oklahoma Crossroads rider, Oklahoma Smart Grid rider, Oklahoma System Hardening rider and the Arkansas Crossroads rider.
Cost of sales for OG&E consists of fuel used in electric generation, purchased power and transmission related charges. Fuel expense was $627.5 million in 2014 as compared to $672.7 million in 2013, a decrease of $45.2 million, or 6.7 percent, primarily due to lower natural gas used offset by higher natural gas prices. In 2014, OG&E's fuel mix was 61 percent coal, 32 percent natural gas and seven percent wind. In 2013, OG&E's fuel mix was 53 percent coal, 40 percent natural gas and seven percent wind. Purchased power costs were $444.1 million in 2014 as compared to $267.6 million in 2013, an increase of $176.5 million, or 66.0 percent, primarily due to an increase in purchases from the SPP, reflecting the impact of OG&E's participation in the SPP Integrated Market, which began on March 1, 2014. Transmission related charges were $35.0 million in 2014 as compared to $25.6 million in 2013, an increase of $9.4 million, or 36.7 percent, primarily due to higher SPP charges for the base plan projects of other utilities.
The actual cost of fuel used in electric generation and certain purchased power costs are passed through to OG&E's customers through fuel adjustment clauses. The fuel adjustment clauses are subject to periodic review by the OCC, the APSC and the FERC. The OCC, the APSC and the FERC have authority to review the appropriateness of gas transportation charges or other fees OG&E pays to its affiliate, Enable.
Operating Expenses
Other operation and maintenance expenses were $453.2 million in 2014 as compared to $438.8 million in 2013, an increase of $14.4 million, or 3.3 percent. The below factors contributed to the change in other operations and maintenance expense:
(A)
Portion of labor costs capitalized into projects decreased as a result of less work performed on storm restoration.
(B)
Increased primarily due to higher allocated costs from the holding company resulting from the formation of Enable during 2013.
(C)
Increased primarily due to demand side management customer payments which are recovered through a rider partially offset by a reduction in media services expense.
(D)
Increased as a result of higher expenditures related to Smart Grid software.
(E)
Increased primarily due to higher SPP administration and assessment fees.
(F)
Decreased primarily due to increased spending on system hardening in 2013 which includes costs that are being recovered through a rider.
(G)
Decreased primarily due to lower pension expense, postretirement and other benefits.
(H)
Decreased primarily due to incentive compensation and lower overtime wages partially offset by higher regular salaries and wages.
Depreciation and amortization expense was $270.8 million in 2014 as compared to $248.4 million in 2013, an increase of $22.4 million, or 9.0 percent, primarily due to additional assets being placed in service primarily related to transmission lines being placed in service throughout 2013 and 2014, along with an increase resulting from the amortization of the deferred pension credits regulatory liability which was fully amortized in July 2014. These were offset by the pension regulatory asset which was fully amortized in July 2013.
Additional Information
Allowance for Equity Funds Used During Construction. Allowance for equity funds used during construction was $4.2 million in 2014 as compared to $6.6 million in 2013, a decrease of $2.4 million or 36.4 percent, primarily due to lower construction work in progress balances resulting from transmission projects being placed in service in 2014.
Other Income. Other income was $4.8 million in 2014 as compared to $8.1 million in 2013, a decrease of $3.3 million or 40.7 percent, primarily due to decreased margins recognized in the guaranteed flat bill program during 2014 as a result of cooler weather in the first quarter as compared to the same period in 2013 along with a decrease in the tax gross up related to the allowance for equity funds used during construction.
Other Expense. Other expense was $1.9 million in 2014 as compared to $4.6 million in 2013, a decrease of $2.7 million or 58.7 percent, primarily due to decreased charitable donations during 2014.
Interest Expense. Interest expense was $141.5 million in 2014 as compared to $129.3 million in 2013, an increase of $12.2 million, or 9.4 percent, primarily due to a $9.1 million increase in interest on long term debt related to a $250 million debt issuance that occurred in May 2013, a $250 million debt issuance that occurred in March 2014 and an additional $250 million debt issuance that occurred in December 2014 partially offset by the early redemption of $140 million senior notes in August
2014. In addition, there was a $2.0 million increase reflecting a reduction in 2013 interest expense related to tax matters offset by a decrease in the allowance for borrowed funds used during construction of $1.0 million.
Income Tax Expense. Income tax expense was $111.6 million in 2014 as compared to $113.5 million in 2013, a decrease of $1.9 million, or 1.7 percent. The reduction reflects lower pretax income partially offset by a reduction in state tax credits recognized during the year and an increase in Federal credits recognized.
2013 compared to 2012. OG&E's net income increased $12.3 million, or 4.4 percent, in 2013 as compared to 2012 primarily due to higher gross margin and lower other operations and maintenance expense, offset in part by higher interest expense and income taxes.
Gross Margin
Operating revenues were $2,262.2 million in 2013 as compared to $2,141.2 million in 2012, an increase of $121.0 million, or 5.7 percent. Cost of sales were $965.9 million in 2013 as compared to $879.1 million in 2012, an increase of $86.8 million, or 9.9 percent. Gross margin was $1,296.3 million in 2013 as compared to $1,262.1 million in 2012, an increase of $34.2 million, or 2.7 percent. The below factors contributed to the change in gross margin:
(A)
Increased primarily due to higher investments related to certain FERC approved transmission projects included in formula rates.
(B)
Decreased primarily due to sales and customer mix.
Cost of sales for OG&E consists of fuel used in electric generation, purchased power and transmission related charges. Fuel expense was $672.7 million in 2013 as compared to $642.4 million in 2012, an increase of $30.3 million, or 4.7 percent, primarily due to higher natural gas prices. OG&E's electric generating capability is fairly evenly divided between coal and natural gas and provides for flexibility to use either fuel to the best economic advantage for OG&E and its customers. In 2013, OG&E's fuel mix was 53 percent coal, 40 percent natural gas and seven percent wind. In 2012, OG&E's fuel mix was 52 percent coal, 42 percent natural gas and six percent wind. Purchased power costs were $267.6 million in 2013 as compared to $223.0 million in 2012, an increase of $44.6 million, or 20.0 percent, primarily due to an increase in purchases in the energy imbalance service market and short-term power agreements. Transmission related charges were $25.6 million in 2013 as compared to $13.7 million in 2012, an increase of $11.9 million, or 86.9 percent, primarily due to higher SPP charges for the base plan projects of other utilities.
Operating Expenses
Other operation and maintenance expenses were $438.8 million in 2013 as compared to $446.3 million in 2012, a decrease of $7.5 million, or 1.7 percent. The below factors contributed to the change in other operations and maintenance expense:
(A)
Decreased primarily due to lower recoverable amounts of pension expense and postretirement medical expense allowed in the August 2012 rate case, a decrease in medical expense, and a decrease in worker's compensation accruals.
(B)
Decreased primarily due to lower salaries and wages as a result of lower headcount in 2013 and a decrease in incentive pay, partially offset by annual salary increases and an increase in overtime wages related to 2013 storms.
(C)
Includes costs that are being recovered through a rider.
Depreciation and amortization expense was $248.4 million in 2013 as compared to $248.7 million in 2012, a decrease of $0.3 million, primarily due to the amortization of the deferred pension credits regulatory liability and a decrease in the amortization of the storm regulatory asset (see Note 1). These decreases in depreciation and amortization expense were partially offset by:
•
increases in depreciation rates from the August 2012 rate case; and
•
additional assets being placed in service throughout 2013 and 2012, including the Sooner-Rose Hill and Sunnyside-Hugo transmission projects, which were fully in service in April 2012, the smart grid project which was completed in late 2012 and the Cleveland to Sooner transmission project which was fully in service in February 2013.
Taxes other than income was $83.8 million in 2013 as compared to $77.7 million in 2012, an increase of $6.1 million, or 7.9 percent, primarily due to higher ad valorem taxes.
Additional Information
Interest Expense. Interest expense was $129.3 million in 2013 as compared to $124.6 million in 2012, an increase of $4.7 million, or 3.8 percent, primarily due to a $6.4 million increase in interest on long term debt related to a $250 million debt issuance that occurred in May 2013, partially offset by a $2.0 million decrease in interest related to tax matters.
Income Tax Expense. Income tax expense was $113.5 million in 2013 as compared to $94.6 million in 2012, an increase of $18.9 million, or 20.0 percent. The increase in income tax expense was primarily due to higher pre-tax income and a reserve related to a portion of the Oklahoma investment tax credits generated in years prior to 2013 but not yet utilized.
Off-Balance Sheet Arrangement
Railcar Lease Agreement
OG&E has a noncancellable operating lease with purchase options, covering 1,387 coal rotary gondola railcars to transport coal from Wyoming to OG&E's coal-fired generation units. Rental payments are charged to Fuel Expense and are recovered through OG&E's tariffs and fuel adjustment clauses. On December 15, 2010, OG&E renewed the lease agreement effective February 1, 2011. At the end of the new lease term, which is February 1, 2016, OG&E has the option to either purchase the railcars at a stipulated fair market value or renew the lease. If OG&E chooses not to purchase the railcars or renew the lease agreement and the actual fair value of the railcars is less than the stipulated fair market value, OG&E would be responsible for the difference in those values up to a maximum of $22.8 million. OG&E is also required to maintain all of the railcars it has under the operating lease and has entered into an agreement with a non-affiliated company to furnish this maintenance.
On January 11, 2012, OG&E executed a five-year lease agreement for 135 railcars to replace railcars that have been taken out of service or destroyed. OG&E has a unilateral right to terminate this lease upon a 6-month notice effective April 2016.
On October 14, 2014, OG&E signed a three-year lease effective beginning December 2014 for 131 railcars to replace railcars that have been taken out of service or destroyed.
Liquidity and Capital Resources
Working Capital
Working capital is defined as the amount by which current assets exceed current liabilities. OG&E's working capital requirements are driven generally by changes in accounts receivable, accounts payable, commodity prices, credit extended to, and the timing of collections from, customers, the level and timing of spending for maintenance and expansion activity, inventory levels and fuel recoveries.
The balance of Advances to Parent was $215.6 million at December 31, 2014 with no balance at December 31, 2013, primarily due to proceeds received from a $250 million bond issuance in December 2014.
The balance of Fuel Inventories was $58.5 million and $74.4 million at December 31, 2014 and 2013, respectively, a decrease of $15.9 million, or 21.4 percent, primarily due to lower coal inventory balances at OG&E's coal fired plants resulting from higher generation related to OG&E's participation in the Integrated Market along with lower deliveries due to market constraints.
The balance of Deferred Income Tax assets was $170.8 million and $189.2 million at December 31, 2014 and 2013, respectively, a decrease of $18.4 million, or 9.7 percent, primarily due to a decrease in deferred income taxes reflecting the expected utilization of net operating losses.
The balance of Fuel Clause Under Recoveries was $68.3 million and $26.2 million at December 31, 2014 and 2013, respectively, an increase of $42.1 million, primarily due to lower amounts billed to OG&E retail customers as compared to the actual cost of fuel and purchased power. The fuel recovery clauses are designed to smooth the impact of fuel price volatility on customers' bills. As a result, OG&E under recovers fuel costs when the actual fuel and purchased power cost recoveries exceed fuel adjustment clause recoveries and over recovers fuel costs when the actual fuel and purchased power costs are below the fuel adjustment clause recoveries. Provisions in the fuel clauses are intended to allow OG&E to amortize under and over recovery balances into future cost recoveries.
The balance of Accounts Payable was $163.3 million and $239.0 million at December 31, 2014 and 2013, respectively, a decrease of $75.7 million, or 31.7 percent, primarily due to a decrease of fuel and purchased power mainly due to participation in the SPP Integrated Marketplace along with milder weather in 2014. Additionally, there was a decrease in accounts payable related to the timing of vendor payments.
Advances from Parent had no balance as of December 31, 2014 compared to $87.2 million at December 31, 2013, primarily due to proceeds received from $250 million bond issuance that was used to pay off advances to OGE Energy.
Cash Flows
* Percentage is greater than 100 percent.
Operating Activities
The increase of $42.6 million, or 7.8 percent, in net cash provided from operating activities in 2014 as compared to 2013 was primarily due to:
•
the absence of fuel refunds to customers during the twelve months ended December 31, 2014, partially offset by fuel under recoveries in the same period; and
•
an increase in cash received during the twelve months ended December 31, 2014 from transmission revenue.
These increases were partially offset by an increase in amounts paid to vendors.
The decrease of $192.3 million, or 26.1 percent, in net cash provided from operating activities in 2013 as compared to 2012 was primarily due to fuel refunds in 2013 as compared to higher fuel recoveries in 2012.
Investing Activities
The decrease of $232.1 million, or 29.1 percent, in net cash used in investing activities in 2014 as compared to 2013 was primarily due to lower levels of capital expenditures due to a decrease in transmission projects.
The increase of $120.5 million, or 17.8 percent, in net cash used in investing activities in 2013 as compared to 2012 primarily related to increased capital expenditures in 2013 related to various transmission projects.
Financing Activities
The increase of $274.7 million in net cash used in financing activities in 2014 as compared to 2013 was primarily due to:
•
a decrease in net advances with OGE Energy during 2014
•
the payment of $140 million in long-term debt; and
•
an increase in dividend payments in 2014.
These increases were partially offset by proceeds received from the issuance of long-term debt.
The increase of $312.8 million in net cash provided from financing activities in 2013 as compared to 2012 was primarily due to:
•
proceeds received from the issuance of long-term debt in May 2013; and
•
an increase in net advances with OGE Energy during 2013.
These increases in net cash provided from financing activities were partially offset by dividend payments in 2013.
Future Capital Requirements and Financing Activities
OG&E's primary needs for capital are related to acquiring or constructing new facilities and replacing or expanding existing facilities. Other working capital requirements are expected to be primarily related to maturing debt, operating lease obligations, fuel clause under and over recoveries and other general corporate purposes. OG&E generally meets its cash needs through a combination of cash generated from operations, short-term borrowings (through a combination of bank borrowings, commercial paper and borrowings from OGE Energy) and permanent financings.
Capital Expenditures
OG&E's estimates of capital expenditures for the years 2015 through 2019 are shown in the following table. These capital expenditures represent the base maintenance capital expenditures (i.e., capital expenditures to maintain and operate OG&E's business) plus capital expenditures for known and committed projects.
(A)
Approximately 30% of revenue requirement allocated to SPP members other than OG&E.
(B)
Approximately 85% of revenue requirement allocated to SPP members other than OG&E.
(D)
Represent capital costs associated with OG&E’s Environmental Compliance Plan to comply with the EPA’s MATS and Regional Haze rules. More detailed discussion regarding Regional Haze and OG&E’s Environmental Compliance Plan can be found in Note 13 of Notes to Financial Statements under "Environmental Compliance Plan" in Item 8 of Part II of this Form 10-K, and under “Environmental Laws and Regulations” within “Management's Discussion and Analysis of Financial Condition and Results of Operations” under Part II, Item 7 of this Form 10-K.
Additional capital expenditures beyond those identified in the table above, including additional incremental growth opportunities in electric transmission assets, will be evaluated based upon their impact upon achieving OG&E's financial objectives.
Contractual Obligations
The following table summarizes OG&E's contractual obligations at December 31, 2014. See OG&E's Statements of Capitalization and Note 12 of Notes to Financial Statements for additional information.
(A)
Maturities of OG&E's long-term debt during the next five years consist of $0.2 million, $110.2 million, $125.1 million, $250.1 million and $250.1 million in years 2015, 2016, 2017, 2018 and 2019, respectively.
(B)
Includes expected recoveries of costs incurred for OG&E's railcar operating lease obligations, OG&E's expected cogeneration energy payments, OG&E's minimum fuel purchase commitments and OG&E's expected wind purchase commitments.
OG&E also has 440 MWs of QF contracts to meet its current and future expected customer needs. OG&E will continue reviewing all of the supply alternatives to these QF contracts that minimize the total cost of generation to its customers, including exercising its options (if applicable) to extend these QF contracts at pre-determined rates.
The actual cost of fuel used in electric generation (which includes the operating lease obligations for OG&E's railcar leases shown above) and certain purchased power costs are passed through to OG&E's customers through fuel adjustment clauses. Accordingly, while the cost of fuel related to operating leases and the vast majority of minimum fuel purchase commitments of OG&E noted above may increase capital requirements, such costs are recoverable through fuel adjustment clauses and have little, if any, impact on net capital requirements and future contractual obligations. The fuel adjustment clauses are subject to periodic review by the OCC, the APSC and the FERC.
Pension and Postretirement Benefit Plans
At December 31, 2014, 33.0 percent of the Pension Plan investments were in listed common stocks with the balance primarily invested in U.S Government securities, bonds, debentures and notes, a commingled fund and a common collective trust as presented in Note 11 of Notes to Financial Statements. In 2014, asset returns on the Pension Plan were 12.8 percent due to the gains in fixed income and equity investments. During the same time, corporate bond yields, which are used in determining the discount rate for future pension obligations, decreased. During 2013, OGE Energy made contributions to its Pension Plan of $35 million of which none was OG&E's portion. The level of funding is dependent on returns on plan assets and future discount rates. During 2014, OGE Energy did not make any contributions to its Pension Plan. OGE Energy has not yet determined whether it will need to make any contributions to the Pension Plan in 2015. OGE Energy could be required to make additional contributions if the value of its pension trust and postretirement benefit plan trust assets are adversely impacted by a major market disruption in the future.
The following table presents the status of OG&E's portion of OGE Energy's Pension Plan, the Restoration of Retirement Income Plan and the postretirement benefit plans at December 31, 2014 and 2013. These amounts have been recorded in Accrued
Benefit Obligations with the offset recorded as a regulatory asset in OG&E's Balance Sheet as discussed in Note 1 of Notes to Financial Statements. The regulatory asset represents a net periodic benefit cost to be recognized in the Statements of Income in future periods.
In accordance with ASC Topic 715, "Compensation - Retirement Benefits," a one-time settlement charge is required to be recorded by an organization when lump sum payments or other settlements that relieve the organization from the responsibility for the pension benefit obligation during a plan year exceed the service cost and interest cost components of the organization’s net periodic pension cost. During 2013, OG&E experienced an increase in both the number of employees electing to retire and the amount of lump sum payments to be paid to such employees upon retirement. As a result, and based in part on OG&E's historical experience regarding eligible employees who elect to retire in the last quarter of a particular year, OG&E recorded pension settlement charges of $17.6 million in the fourth quarter of 2013, of which $17.0 million related to OG&E’s Oklahoma jurisdiction and has been included in the pension tracker. The pension settlement charge did not require a cash outlay by OG&E and did not increase OG&E’s total pension expense over time, as the charges were an acceleration of costs that otherwise would be recognized as pension expense in future periods.
Security Ratings
Access to reasonably priced capital is dependent in part on credit and security ratings. Generally, lower ratings lead to higher financing costs. Pricing grids associated with OGE Energy's and OG&E's credit facilities could cause annual fees and borrowing rates to increase if an adverse rating impact occurs. The impact of any future downgrade could include an increase in the costs of OGE Energy's and OG&E's short-term borrowings, but a reduction in OGE Energy's and OG&E's credit ratings would not result in any defaults or accelerations. Any future downgrade of OGE Energy or OG&E could also lead to higher long-term borrowing costs and, if below investment grade, would require OG&E to post collateral or letters of credit.
On November 8, 2013, Moody's Investors Services placed the credit ratings of OG&E on review for possible upgrade. On January 31, 2014, Moody's upgraded the long-term senior unsecured rating of OG&E to A1 primarily due to their more favorable view of the relative credit supportiveness of the U.S. regulatory environment.
A security rating is not a recommendation to buy, sell or hold securities. Such rating may be subject to revision or withdrawal at any time by the credit rating agency and each rating should be evaluated independently of any other rating.
Future financing requirements may be dependent, to varying degrees, upon numerous factors such as general economic conditions, abnormal weather, load growth, commodity prices, acquisitions of other businesses and/or development of projects, actions by rating agencies, inflation, changes in environmental laws or regulations, rate increases or decreases allowed by regulatory agencies, new legislation and market entry of competing electric power generators.
2014 Capital Requirements, Sources of Financing and Financing Activities
Total capital requirements, consisting of capital expenditures and maturities of long-term debt, were $705.6 million and contractual obligations, net of recoveries through fuel adjustment clauses, were $87.4 million resulting in total net capital requirements and contractual obligations of $793.0 million in 2014, of which $31.5 million was to comply with environmental regulations. This compares to net capital requirements of $797.7 million and net contractual obligations of $89.2 million totaling $886.9 million in 2013, of which $42.0 million was to comply with environmental regulations.
In 2014, OG&E's sources of capital were cash generated from operations and proceeds from the issuance of short- and long - term debt. Changes in working capital reflect the seasonal nature of OG&E's business, the revenue lag between billing and
collection from customers and fuel inventories. See "Working Capital" for a discussion of significant changes in net working capital requirements as it pertains to operating cash flow and liquidity.
Issuance of Long-Term Debt
On March 25, 2014, OG&E completed the issuance of $250 million of 4.55 percent senior notes due March 15, 2044. The proceeds from the issuance were added to OG&E's general funds and were used to repay debt, fund capital expenditures and general corporate expenses, and utilized for working capital purposes.
On December 11, 2014, OG&E completed the issuance of $250 million of 4.000 percent Senior Notes, Series due December 15, 2044. The proceeds from the issuance were added to OG&E's general funds and were used to repay short-term debt, fund capital expenditures and general corporate expenses, and utilized for working capital purposes.
Redemption of Long-Term Debt
On August 1, 2014, OG&E redeemed all $140 million principal amount outstanding of its 6.50 percent senior notes due August 1, 2034 at 103.25 percent of their principal amount, plus accrued interest. The redemption premium of $4.6 million was deferred and will be amortized through March 2044 to match the expected regulatory treatment.
The Dodd-Frank Act
Derivative instruments are utilized in managing OG&E's commodity price exposures. On July 21, 2010, President Obama signed into law the Dodd-Frank Act. Among other things, the Dodd-Frank Act provides for a new regulatory regime for derivatives, including mandatory clearing of certain swaps and margin requirements. The Dodd-Frank Act contains provisions that should exempt certain derivatives end-users such as OG&E from much of the clearing requirements. The regulations require that the decision on whether to use the end-user exception from mandatory clearing for derivative transactions be reviewed and approved by an "appropriate committee" of the Board of Directors. On January 12, 2015, President Obama signed into law an amendment to the Dodd-Frank Act that exempts from margin requirements swaps used by end-users to hedge or mitigate commercial risk. There are, however, some rulemakings that have no yet been finalized. Even if OG&E qualifies for the end-user exception to clearing and margin requirements are not imposed on end-users, its derivative counterparties may be subject to new capital, margin and business conduct requirements as a result of the new regulations, which may increase OG&E's transaction costs or make it more difficult to enter into derivative transactions on favorable terms. OG&E's inability to enter into derivative transactions on favorable terms, or at all, could increase operating expenses and put OG&E at increased exposure to risks of adverse changes in commodities prices. The impact of the provisions of the Dodd-Frank Act on OG&E cannot be fully determined at this time due to uncertainty over forthcoming regulations and potential changes to the derivatives markets arising from new regulatory requirements.
Future Sources of Financing
Management expects that cash generated from operations, proceeds from the issuance of long and short-term debt and funds received from OGE Energy (from proceeds from the sales of its common stock to the public through OGE Energy's Automatic Dividend Reinvestment and Stock Purchase Plan or other offerings) will be adequate over the next three years to meet anticipated cash needs and to fund future growth opportunities. OG&E utilizes short-term borrowings (through a combination of bank borrowings, commercial paper and borrowings from OGE Energy) to satisfy temporary working capital needs and as an interim source of financing capital expenditures until permanent financing is arranged.
Short-Term Debt and Credit Facility
At December 31, 2014, there were $215.6 million in advances to OGE Energy as compared to $87.2 million in outstanding advances from OGE Energy in 2013. OG&E has an intercompany borrowing agreement with OGE Energy whereby OG&E has access to up to $400 million of OGE Energy's revolving credit amount. This agreement has a termination date of December 13, 2018. At December 31, 2014, there were no intercompany borrowings under this agreement. OG&E has a $400 million revolving credit facility which is available to back up OG&E's commercial paper borrowings and to provide revolving credit borrowings. This bank facility can also be used as a letter of credit facility. At December 31, 2014, there was $2.0 million supporting letters of credit at a weighted-average interest rate of 0.95 percent. There were no outstanding borrowings under this revolving credit agreement and no outstanding commercial paper borrowings at December 31, 2014. At December 31, 2014, OG&E had $398.0 million of net available liquidity under its revolving credit agreement. OG&E has the necessary regulatory approvals to incur up to $800
million in short-term borrowings at any one time for a two-year period beginning January 1, 2015 and ending December 31, 2016. See Note 10 of Notes to Financial Statements for a discussion of OG&E's short-term debt activity.
In December 2011, OG&E entered into an unsecured five-year revolving credit agreement for $400.0 million. This credit facility contained an option, which could be exercised up to two times, to extend the term for an additional year. In the third quarter of 2013, OG&E utilized one of these one-year extensions, and received consent from all of the lenders, to extend the maturity of its credit agreement from December 13, 2016 to December 13, 2017. In the second quarter of 2014, OG&E utilized its second extension to extend the maturity of its credit facility from December 13, 2017 to December 13, 2018. As of December 31, 2014, the commitment of a single existing lender with respect to approximately $8.7 million of OG&E's credit facility, however, was not extended and, unless the non-extending lender is replaced in accordance with the terms of the credit facility, the commitment will expire December 13, 2017.
Critical Accounting Policies and Estimates
The Financial Statements and Notes to Financial Statements contain information that is pertinent to Management's Discussion and Analysis. In preparing the Financial Statements, management is required to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and contingent liabilities at the date of the Financial Statements and the reported amounts of revenues and expenses during the reporting period. Changes to these assumptions and estimates could have a material effect on OG&E's Financial Statements. However, OG&E believes it has taken reasonable positions where assumptions and estimates are used in order to minimize the negative financial impact to OG&E that could result if actual results vary from the assumptions and estimates. In management's opinion, the areas of OG&E where the most significant judgment is exercised includes the determination of Pension Plan assumptions, income taxes, contingency reserves, asset retirement obligations, and depreciable lives of property, plant and equipment, the existence of regulatory assets and liabilities and unbilled revenues. The selection, application and disclosure of the following critical accounting estimates have been discussed with OGE Energy's Audit Committee. OG&E discusses its significant accounting policies, including those that do not require management to make difficult, subjective, or complex judgments or estimates, in Note 1 of Notes to Financial Statements.
Pension and Postretirement Benefit Plans
OGE Energy has a Pension Plan that covers a significant amount of OG&E's employees hired before December 1, 2009. Also, effective December 1, 2009, OGE Energy's Pension Plan is no longer being offered to employees hired on or after December 1, 2009. OGE Energy also has defined benefit postretirement plans that cover a significant amount of its employees. Pension and other postretirement plan expenses and liabilities are determined on an actuarial basis and are affected by the market value of plan assets, estimates of the expected return on plan assets, assumed discount rates and the level of funding. Actual changes in the fair market value of plan assets and differences between the actual return on plan assets and the expected return on plan assets could have a material effect on the amount of pension expense ultimately recognized. The pension plan rate assumptions are shown in Note 12 of Notes to Financial Statements. The assumed return on plan assets is based on management's expectation of the long-term return on the plan assets portfolio. The discount rate used to compute the present value of plan liabilities is based generally on rates of high-grade corporate bonds with maturities similar to the average period over which benefits will be paid. The level of funding is dependent on returns on plan assets and future discount rates. Higher returns on plan assets and an increase in discount rates will reduce funding requirements to the Pension Plan. The following table indicates the sensitivity of the Pension Plan funded status to these variables.
Income Taxes
OG&E uses the asset and liability method of accounting for income taxes. Under this method, a deferred tax asset or liability is recognized for the estimated future tax effects attributable to temporary differences between the financial statement basis and the tax basis of assets and liabilities as well as tax credit carry forwards and net operating loss carry forwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in the period of the change.
The application of income tax law is complex. Laws and regulations in this area are voluminous and often ambiguous. Interpretations and guidance surrounding income tax laws and regulations change over time. Accordingly, it is necessary to make judgments regarding income tax exposure. As a result, changes in these judgments can materially affect amounts OG&E recognized in its financial statements. Tax positions taken by OG&E on its income tax returns that are recognized in the financial statements must satisfy a more likely than not recognition threshold, assuming that the position will be examined by taxing authorities with full knowledge of all relevant information.
Asset Retirement Obligations
OG&E has previously recorded asset retirement obligations that are being amortized over their respective lives ranging from 4 to 74 years. The inputs used in the valuation of asset retirement obligations include the assumed life of the asset placed into service, the average inflation rate, market risk premium, the credit-adjusted risk free interest rate and the timing of incurring costs related to the retirement of the asset.
Hedging Policies
From time to time, OG&E may engage in cash flow and fair value hedge transactions to modify interest rate exposure and not to modify the overall leverage of the debt portfolio.
Hedges are evaluated prior to execution with respect to the impact on the volatility of forecasted earnings and are evaluated at least quarterly after execution for the impact on earnings.
Regulatory Assets and Liabilities
OG&E, as a regulated utility, is subject to accounting principles for certain types of rate-regulated activities, which provide that certain incurred costs that would otherwise be charged to expense can be deferred as regulatory assets, based on the expected recovery from customers in future rates. Likewise, certain actual or anticipated credits that would otherwise reduce expense can be deferred as regulatory liabilities, based on the expected flowback to customers in future rates. Management's expected recovery of deferred costs and flowback of deferred credits generally results from specific decisions by regulators granting such ratemaking treatment.
OG&E records certain incurred costs and obligations as regulatory assets or liabilities if it is probable, based on regulatory orders or other available evidence, that the cost or obligation will be included in amounts allowable for recovery or refund in future rates. The benefit obligations regulatory asset is comprised of expenses recorded which are probable of future recovery and that have not yet been recognized as components of net periodic benefit cost, including net loss and prior service cost.
Unbilled Revenues
OG&E reads its customers' meters and sends bills to its customers throughout each month. As a result, there is a significant amount of customers' electricity consumption that has not been billed at the end of each month. Unbilled revenue is presented in Accrued Unbilled Revenues on the Balance Sheets and in Operating Revenues on the Statements of Income based on estimates of usage and prices during the period. At December 31, 2014, if the estimated usage or price used in the unbilled revenue calculation were to increase or decrease by one percent, this would cause a change in the unbilled revenues recognized of $0.3 million. At December 31, 2014 and 2013, Accrued Unbilled Revenues were $55.5 million and $58.7 million, respectively. The estimates that management uses in this calculation could vary from the actual amounts to be paid by customers.
Allowance for Uncollectible Accounts Receivable
Customer balances are generally written off if not collected within six months after the final billing date. The allowance for uncollectible accounts receivable for OG&E is calculated by multiplying the last six months of electric revenue by the provision rate. The provision rate is based on a 12-month historical average of actual balances written off. To the extent the historical collection rates are not representative of future collections, there could be an effect on the amount of uncollectible expense recognized. Also, a portion of the uncollectible provision related to fuel within the Oklahoma jurisdiction is being recovered through the fuel adjustment clause. At December 31, 2014, if the provision rate were to increase or decrease by 10 percent, this would cause a change in the uncollectible expense recognized of $0.1 million. The allowance for uncollectible accounts receivable is a reduction to Accounts Receivable on the Balance Sheets and is included in Other Operation and Maintenance Expense on the Statements of Income. The allowance for uncollectible accounts receivable was $1.6 million and $1.9 million at December 31, 2014 and 2013, respectively.
Accounting Pronouncements
See Note 2 of Notes to Financial Statements for discussion of a current accounting pronouncement that is applicable to OG&E.
Commitments and Contingencies
In the normal course of business, OG&E is confronted with issues or events that may result in a contingent liability. These generally relate to lawsuits or claims made by third parties, including governmental agencies. When appropriate, management consults with legal counsel and other appropriate experts to assess the claim. If, in management's opinion, OG&E has incurred a probable loss as set forth by GAAP, an estimate is made of the loss and the appropriate accounting entries are reflected in OG&E's Financial Statements. At the present time, based on currently available information, OG&E believes that any reasonably possible losses in excess of accrued amounts arising out of pending or threatened lawsuits or claims would not be quantitatively material to its financial statements and would not have a material adverse effect on OG&E's financial position, results of operations or cash flows. See Notes 12 and 13 of Notes to Financial Statements and Item 3 of Part I in this Form 10-K for a discussion of OG&E's commitments and contingencies.
Environmental Laws and Regulations
The activities of OG&E are subject to numerous, stringent and complex Federal, state and local laws and regulations governing environmental protection. These laws and regulations can change, restrict or otherwise impact OG&E's business activities in many ways including the handling or disposal of waste material, future construction activities to avoid or mitigate harm to threatened or endangered species and requiring the installation and operation of emissions pollution control equipment. Failure to comply with these laws and regulations could result in the assessment of administrative, civil and criminal penalties, the imposition of remedial requirements and the issuance of orders enjoining future operations. OG&E believes that its operations are in substantial compliance with current Federal, state and local environmental standards.
Environmental regulation can increase the cost of planning, design, initial installation and operation of OG&E's facilities. Historically, OG&E's total expenditures for environmental control facilities and for remediation have not been significant in relation to its financial position or results of operations. OG&E believes, however, that it is reasonably likely that the trend in environmental legislation and regulations will continue towards more restrictive standards. Compliance with these standards is expected to increase the cost of conducting business. Management continues to evaluate its compliance with existing and proposed environmental legislation and regulations and implement appropriate environmental programs in a competitive market.
OG&E expects that environmental expenditures necessary to comply with the environmental laws and regulations discussed below will qualify as part of a pre-approval plan to handle state and Federally mandated environmental upgrades which will be recoverable in Oklahoma from OG&E's retail customers under House Bill 1910, which was enacted into law in May 2005.
It is estimated that OG&E's total expenditures to comply with environmental laws, regulations and requirements for 2015 will be approximately $136.0 million, of which $116.0 million is for capital expenditures. It is estimated that OG&E's total expenditures to comply with environmental laws, regulations and requirements for 2016 will be approximately $159.0 million, of which $139.0 million is for capital expenditures. The amounts above include capital expenditures for low NOX burners, activated carbon injection and scrubbers.
Air
Federal Clean Air Act Overview
OG&E’s operations are subject to the Federal Clean Air Act as amended, and comparable state laws and regulations. These laws and regulations regulate emissions of air pollutants from various industrial sources, including electric generating units, and also impose various monitoring and reporting requirements. Such laws and regulations may require that OG&E obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions or result in the increase of existing air emissions, obtain and strictly comply with air permits containing various emissions and operational limitations or install emission control equipment. OG&E likely will be required to incur certain capital expenditures in the future for air pollution control equipment and technology in connection with obtaining and maintaining operating permits and approvals for air emissions.
Regional Haze Control Measures
The EPA's 2005 regional haze rule is intended to protect visibility in certain national parks and wilderness areas throughout the United States that may be impacted by air pollutant emissions.
On February 18, 2010, Oklahoma submitted its SIP to the EPA, which set forth the state's plan for compliance with the Federal regional haze rule. The SIP was subject to the EPA's review and approval.
The Oklahoma SIP included requirements for reducing emissions of NOX and SO2 from OG&E's seven BART-eligible units at the Seminole, Muskogee and Sooner generating stations. The SIP also included a waiver from BART requirements for all eligible units at the Horseshoe Lake generating station based on air modeling that showed no significant impact on visibility in nearby national parks and wilderness areas. The SIP concluded that BART for reducing NOX emissions at all of the subject units should be the installation of low NOX burners with overfired air (flue gas recirculation was also required on two of the units) and set forth associated NOX emission rates and limits.
On December 28, 2011, the EPA issued a final rule in which it rejected the SO2 portion of the Oklahoma SIP and issued a FIP its place. OG&E and the State of Oklahoma's subsequent appeal of the FIP with the Tenth Circuit of Appeals and the U.S. Supreme Court ended on May 27, 2014 when the Supreme Court denied OG&E's Petition for Certiorari, upholding the EPA's FIP for SO2. The FIP compliance date is now January 4, 2019.
On August 6, 2014, OG&E filed an application with the OCC for approval of its plan to comply with EPA’s MATS and Regional Haze FIP while serving the best long-term interests of customers in light of future environmental uncertainties. The application seeks approval of the environmental compliance plan and for a recovery mechanism for the associated costs. The environmental compliance plan includes installing dry scrubbers at Sooner Units 1 and 2 and the conversion of Muskogee Units 4 and 5 to natural gas. The application also asks the Commission to predetermine the prudence of replacing OG&E's soon-to-be retired Mustang steam turbines in late 2017 (approximately 460 MW) with 400 MW of new, efficient combustion turbines at the Mustang site in 2018 and 2019 and approval for a recovery mechanism for the associated costs. OG&E estimates the total capital cost associated with its environmental compliance plan included in this application to be approximately $1.1 billion. The OCC hearing on OG&E's application is scheduled to commence on March 3, 2015. Multiple parties advocating a variety of positions have intervened in the proceeding. OG&E expects a ruling from the OCC in the second quarter of 2015. At this time, OG&E cannot predict the outcome of the proceeding. OG&E plans to file applications in the first quarter of 2015 seeking related approvals from the APSC.
Cross-State Air Pollution Rule
In August 2011, the EPA published its Cross-State Air Pollution Rule that would require 27 states to reduce power plant emissions that contribute to ozone and particulate matter pollution in other states. In December 2011, the EPA published a supplemental Cross-State Air Pollution Rule, which would make six additional states, including Oklahoma, subject to the Cross-State Air Pollution Rule for NOX emissions during the ozone-season from May 1 through September 30. Under the rule, OG&E would have been required to reduce ozone-season NOX emissions from its electrical generating units within the state beginning in 2012. In response to legal challenges of the final rule on December 30, 2011, the U.S. Court of Appeals issued a stay of the rule, which includes the supplemental rule, pending a decision on the merits. By order dated August 21, 2012, the Court of Appeals vacated the Cross-State Air Pollution Rule and ordered the EPA to promulgate a replacement rule. On April 29, 2014, the U.S. Supreme Court reversed the decision by the Court of Appeals. On October 23, 2014, the Court of Appeals for the District of Columbia Circuit granted the EPA's request that the court lift the stay of the Cross-State Air Pollution Rules. The EPA subsequently clarified that compliance with the Cross-State Air Pollution Rule would begin in 2015 using the amount of allowances originally scheduled to be available in 2012. OG&E already has installed low NOx burners on many of its generating units, and OG&E is continuing to evaluate what additional measures, if any, will be needed for compliance with the rule. In the meantime, the petitions for review of the Cross-State Air Pollution Rule and the supplemental rule remain pending before the DC Circuit Court of Appeals for consideration of issues not addressed by the Supreme Court's decision.
Hazardous Air Pollutants Emission Standards
On April 16, 2012, regulations governing emissions of certain hazardous air pollutants from electric generating units were published as the final MATS rule. To comply with this rule, OG&E is currently planning to utilize activated carbon injection for the removal of mercury at each of its five coal-fired units, the capital costs of which are estimated to be approximately $20 million over a three year period and are included in the capital expenditures table in "Future Capital Requirements and Financing
Activities" above. The final MATS rule has been appealed by several parties and is now before the US Supreme Court. OG&E is not a party to the appeals and cannot predict the outcome of any such appeals.
Federal Clean Air Act New Source Review Litigation
As previously reported, in July 2008, OG&E received a request for information from the EPA regarding Federal Clean Air Act compliance at OG&E's Muskogee and Sooner generating plants.
On July 8, 2013, the Department of Justice filed a complaint against OG&E in United States District Court for the Western District of Oklahoma alleging that OG&E did not follow the Federal Clean Air Act procedures for projecting emission increases attributable to eight projects that occurred between 2003 and 2006. This complaint seeks to have OG&E submit a new assessment of whether the projects were likely to result in a significant emissions increase. The Sierra Club intervened in this proceeding. On August 30, 2013, the Government filed a Motion for Summary Judgment and on September 6, 2013, OG&E filed a Motion to Dismiss the case. On January 15, 2015, U.S. District Judge Timothy DeGuisti dismissed the complaints filed by EPA and Sierra Club. The Court held that it lacked subject matter jurisdiction over Plaintiffs’ claims because Plaintiffs failed to present an actual “case or controversy” as required by Article III of the Constitution. The court also ruled in the alternative that, even if Plaintiffs had presented a case or controversy, it would have nonetheless “decline[d] to exercise jurisdiction.” EPA and the Sierra Club have until March 16, 2015 to file an appeal of the Court’s ruling.
On August 12, 2013, the Sierra Club filed a separate complaint against OG&E in the United States District Court for the Eastern District of Oklahoma alleging that OG&E projects at Muskogee Unit 6 in 2008 were made without obtaining a prevention of significant deterioration permit and that the plant had exceeded emissions limits for opacity and particulate matter. The Sierra Club seeks a permanent injunction preventing OG&E from operating the Muskogee generating plant. On March 4, 2014, the Eastern District dismissed the prevention of significant deterioration permit claim based on the statute of limitations, but allowed the opacity and particulate matter claims to proceed. To obtain the right to appeal this decision, the Sierra Club subsequently withdrew a Notice of Intent to Sue for additional Clean Air Act violations and asked the Eastern District to dismiss its remaining claims with prejudice. On August 27, 2014, the Eastern District granted the Sierra Club's request. The Sierra Club has filed a Notice of Appeal with the 10th Circuit where oral argument is currently scheduled for March 18, 2015.
At this time, OG&E continues to believe that it has acted in compliance with the Federal Clean Air Act, and OG&E expects to vigorously defend against the claims that have been asserted. If OG&E does not prevail in the remainder of the proceedings, the EPA and the Sierra Club could seek to require OG&E to install additional pollution control equipment, including scrubbers, baghouses and selective catalytic reduction systems with capital costs in excess of $1.1 billion and pay fines and significant penalties as a result of the allegations in the notice of violation. Section 113 of the Federal Clean Air Act (along with the Federal Civil Penalties Inflation Adjustment Act of 1996) provides for civil penalties as much as $37,500 per day for each violation. Due to the uncertain and preliminary nature of this litigation, OG&E cannot provide a range of reasonably possible loss in this case.
National Ambient Air Quality Standards
The EPA is required to set NAAQS for certain pollutants considered to be harmful to public health or the environment. The Clean Air Act requires the EPA to review each NAAQS every five years. As a result of these reviews, the EPA periodically has taken action to adopt more stringent NAAQS for those pollutants. If any areas of Oklahoma were to be designated as not attaining the NAAQS for a particular pollutant, OG&E could be required to install additional emission controls on its facilities to help the state achieve attainment with the NAAQS. As of the end of 2014, no areas of Oklahoma had been designated as non-attainment for pollutants that are likely to affect OG&E's operations. Several processes are under way to designate areas in Oklahoma as attaining or not attaining revised NAAQS. OG&E is monitoring those processes and their possible impact on its operations but, at this time, cannot determine with any certainty whether they will cause a material impact to OG&E's financial results.
Climate Change and Greenhouse Gas Emissions
There is continuing discussion and evaluation of possible global climate change in certain regulatory and legislative arenas. The focus is generally on emissions of greenhouse gases, including carbon dioxide, sulfur hexafluoride and methane, and whether these emissions are contributing to the warming of the Earth's atmosphere. There are various international agreements that restrict greenhouse gas emissions, but none of them have a binding effect on sources located in the United States. The U.S. Congress has not passed legislation to reduce emissions of greenhouse gases and the future prospects for any such legislation are uncertain, but the EPA believes it has existing authority under the Clean Air Act to regulate greenhouse gas emissions from stationary sources. Several states have passed laws, adopted regulations or undertaken regulatory initiatives to reduce the emission
of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. Oklahoma and Arkansas are not among them. If legislation or regulations are passed at the Federal or state levels in the future requiring mandatory reductions of carbon dioxide and other greenhouse gases on OG&E's facilities, this could result in significant additional compliance costs that would affect OG&E’s future financial position, results of operations and cash flows if such costs are not recovered through regulated rates.
In 2009, the EPA adopted a comprehensive national system for reporting emissions of carbon dioxide and other greenhouse gases produced by major sources in the United States. The reporting requirements apply to large direct emitters of greenhouse gases with emissions equal to or greater than a threshold of 25,000 metric tons per year, which includes certain OG&E facilities. OG&E also reports quarterly its carbon dioxide emissions from generating units subject to the Federal Acid Rain Program. OG&E has submitted the reports required by the applicable reporting rules.
In January 2014, the EPA used the Clean Air Act authority and re-proposed New Source Performance Standards that specify permissible levels of greenhouse gas emissions from newly-constructed fossil fuel-fired electric generating units. The proposed New Source Performance Standards set separate standards for natural gas combined cycle units and coal-fired generating units.
The EPA published proposed standards for existing units on June 18, 2014. As proposed by the rule, states must then submit their individual plans for reducing power plants' greenhouse gas emissions to EPA between June 2016 and June 2018 depending on whether they choose to develop a compliance plan as an individual state or as a group of states. In Oklahoma, the proposal sets a target of 43 percent reduction in the carbon emissions rate (lb/MWh) from existing sources. EPA received over 3.5 million comments on this proposal including comments from OG&E.
On January 7, 2015, EPA announced that it will simultaneously finalize the proposed rules for new and existing sources to an unspecified date during the summer of 2015. With these rules, EPA also plans to propose a federal plan for States to achieve the emissions targets in the existing-unit rule which States could adopt rather than developing their own state plans. EPA expects to issue a final federal plan in the summer of 2016. As proposed rules, OG&E is unable to assess the impact to OG&E at this time however continues to monitor the rule’s development.
On June 23, 2014, the U.S. Supreme Court issued an opinion rejecting the EPA’s determination that its regulation of greenhouse gas emissions from new motor vehicles triggered permitting requirements under the Clean Air Act for stationary sources that emit greenhouse gases. However, the Court held that EPA can require best available control technology for greenhouse gas emissions from sources otherwise subject to review under the Prevention of Significant Deterioration program. The opinion is not expected to have a direct impact on OG&E because none of its sources has been, or is expected to be, required to undergo such a review for greenhouse gas emissions.
It is not possible to determine what the legal standards for greenhouse gas emissions will be in the future. Nonetheless, OG&E’s current business strategy will result in a reduced carbon emissions rate compared to current levels. As discussed in “Pending Regulatory Matters”, OG&E has filed an application with the OCC for approval of its plan to comply with EPA’s MATS and Regional Haze FIP by converting two coal-fired generating units at Muskogee Station to natural gas, among other measures. OG&E’s deployment of Smart Grid technology helps to reduce the peak load demand. OG&E also seeks to utilize renewable energy sources that do not emit greenhouse gases. OG&E's service territory borders one of the nation's best wind resource areas. OG&E has leveraged its geographic position to develop renewable energy resources and transmission to deliver the renewable energy. The SPP has begun to authorize the construction of transmission lines capable of bringing renewable energy out of the wind resource area in western Oklahoma, the Texas Panhandle and western Kansas to load centers by planning for more transmission to be built in the area. In addition to increasing overall system reliability, these new transmission resources should provide greater access to additional wind resources that are currently constrained due to existing transmission delivery limitations.
Endangered Species
Certain Federal laws, including the Bald and Golden Eagle Protection Act, the Migratory Bird Treaty Act and the Endangered Species Act, provide special protection to certain designated species. These laws and any state equivalents provide for significant civil and criminal penalties for unpermitted activities that result in harm to or harassment of certain protected animals and plants, including damage to their habitats. If such species are located in an area in which OG&E conducts operations, or if additional species in those areas become subject to protection, OG&E’s operations and development projects, particularly transmission, wind or pipeline projects, could be restricted or delayed, or OG&E could be required to implement expensive mitigation measures. The U.S. Fish and Wildlife Service announced a proposed rule to list the lesser prairie chicken as threatened on November 30, 2012. The decision applies to a 5-state area including parts of Oklahoma where OG&E has undertaken the development of certain large transmission projects. On March 10, 2014, OG&E enrolled in the Western Association of Fish and
Wildlife Agencies’ Range-Wide Conservation Plan for the lesser prairie chicken. This Range-Wide Conservation Plan consists of industry-specific conservation practices that apply to projects and activities in the impacted area. The Range-Wide Conservation Plan has been approved by the U.S. Fish and Wildlife Service and incorporated as part of the agency’s final decision on March 27, 2014 to list the lesser prairie chicken as a threatened species.
Air Quality Control System
On September 10, 2014, OG&E executed a contract for the design, engineering and fabrication of two circulating dry scrubber systems to be installed at Sooner Units 1 and 2. OG&E entered into an agreement on February 9, 2015, to install the scrubber systems. The scrubbers are part of OG&E’s Environmental Compliance Plan and scheduled to be completed by 2019. More detail regarding the Environmental Plan can be found under the “Pending Regulatory Matters” section of "Notes to Financial Statements" of Part II, Item 8 of this Form 10-K.
Waste
OG&E's operations generate wastes that are subject to the Federal Resource Conservation and Recovery Act of 1976 as well as comparable state laws which impose detailed requirements for the handling, storage, treatment and disposal of waste.
On December 19, 2014, EPA finalized a rule under the Federal Resource Conservation and Recovery Act for the handling and disposal of coal combustion residuals or coal ash. The final rule regulates coal ash as a solid waste rather than a hazardous waste, which would have made the management of coal ash more costly. OG&E operations are regulated by this rule however; OG&E is still currently evaluating the potential impacts of the final rule and as such, cannot yet assess the cost of compliance from the rule.
OG&E has sought and will continue to seek pollution prevention opportunities and to evaluate the effectiveness of its waste reduction, reuse and recycling efforts. In 2014, OG&E obtained refunds of $3.4 million from the recycling of scrap metal, salvaged transformers and used transformer oil. This figure does not include the additional savings gained through the reduction and/or avoidance of disposal costs and the reduction in material purchases due to the reuse of existing materials. Similar savings are anticipated in future years.
Water
OG&E's operations are subject to the Federal Clean Water Act, and comparable state laws and regulations. These laws and regulations impose detailed requirements and strict controls regarding the discharge of pollutants into state and Federal waters.
In March 2011, the EPA proposed rules to implement Section 316(b) of the Federal Clean Water Act, which requires that power plant cooling water intake structure location, design, construction and capacity reflect the best available technology for minimizing their adverse environmental impact via the impingement and entrainment of aquatic organisms. The EPA issued a final rule on May 19, 2014. OG&E is currently evaluating the impacts of the final rule and plans to seek state approval of the compliance plan in 2015, at which point in time OG&E expects to be able to provide a reasonable estimate of any material costs associated with the rule.
Site Remediation
The Comprehensive Environmental Response, Compensation and Liability Act of 1980 and comparable state laws impose liability, without regard to the legality of the original conduct, on certain classes of persons responsible for the release of hazardous substances into the environment. Because OG&E utilizes various products and generate wastes that are considered hazardous substances for purposes of the Comprehensive Environmental Response, Compensation and Liability Act of 1980, OG&E could be subject to liability for the costs of cleaning up and restoring sites where those substances have been released to the environment. At this time, it is not anticipated that any associated liability will cause a significant impact to OG&E.
For a further discussion regarding contingencies relating to environmental laws and regulations, see Note 12 of Notes to Financial Statements.
Item 7A.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk.
Market risks are, in most cases, risks that are actively traded in a marketplace and have been well studied in regards to quantification. Market risks include, but are not limited to, changes in interest rates and commodity prices. OG&E's exposure to
changes in interest rates relates primarily to short-term variable-rate debt and commercial paper. OG&E is exposed to commodity prices in its operations.
Risk Oversight Committee
Management monitors market risks using a risk committee structure. OG&E's Risk Oversight Committee, which consists primarily of corporate officers, is responsible for the overall development, implementation and enforcement of strategies and policies for all market risk management activities of OG&E. This committee's emphasis is a holistic perspective of risk measurement and policies targeting OG&E's overall financial performance. On a quarterly basis, the Risk Oversight Committee reports to the Audit Committee of OGE Energy's Board of Directors on OGE Energy's risk profile affecting anticipated financial results, including any significant risk issues.
OG&E also has a Corporate Risk Management Department. This group, in conjunction with the aforementioned committees, is responsible for establishing and enforcing OG&E's risk policies.
Risk Policies
Management utilizes risk policies to control the amount of market risk exposure. These policies are designed to provide the Audit Committee of OGE Energy's Board of Directors and senior executives of OG&E with confidence that the risks taken on by OG&E's business activities are in accordance with their expectations for financial returns and that the approved policies and controls related to market risk management are being followed.
Interest Rate Risk
OG&E's exposure to changes in interest rates primarily relates to short-term variable-rate debt and commercial paper. OG&E manages its interest rate exposure by monitoring and limiting the effects of market changes in interest rates. OG&E may utilize interest rate derivatives to alter interest rate exposure in an attempt to reduce the effects of these changes. Interest rate derivatives are used solely to modify interest rate exposure and not to modify the overall leverage of the debt portfolio.
The fair value of OG&E's long-term debt is based on quoted market prices and estimates of current rates available for similar issues with similar maturities or by calculating the net present value of the monthly payments discounted by OG&E's .current borrowing rate. The following table shows OG&E's long-term debt maturities and the weighted-average interest rates by maturity date.
(A)
Prior to or when these debt obligations mature, OG&E may refinance all or a portion of such debt at then-existing market interest rates which may be more or less than the interest rates on the maturing debt.
(B)
A hypothetical change of 100 basis points in the underlying variable interest rate incurred by OG&E would change interest expense by $1.4 million annually.
Item 8.
Item 8. Financial Statements and Supplementary Data.
OKLAHOMA GAS AND ELECTRIC COMPANY
STATEMENTS OF INCOME
The accompanying Notes to Financial Statements are an integral part hereof.
OKLAHOMA GAS AND ELECTRIC COMPANY
STATEMENTS OF COMPREHENSIVE INCOME
The accompanying Notes to Financial Statements are an integral part hereof.
OKLAHOMA GAS AND ELECTRIC COMPANY
STATEMENTS OF CASH FLOWS
The accompanying Notes to Financial Statements are an integral part hereof.
OKLAHOMA GAS AND ELECTRIC COMPANY
BALANCE SHEETS
The accompanying Notes to Financial Statements are an integral part hereof.
OKLAHOMA GAS AND ELECTRIC COMPANY
BALANCE SHEETS (Continued)
The accompanying Notes to Financial Statements are an integral part hereof.
OKLAHOMA GAS AND ELECTRIC COMPANY
STATEMENTS OF CAPITALIZATION
The accompanying Notes to Financial Statements are an integral part hereof.
OKLAHOMA GAS AND ELECTRIC COMPANY
STATEMENTS OF CHANGES IN STOCKHOLDER'S EQUITY
The accompanying Notes to Financial Statements are an integral part hereof.
OKLAHOMA GAS AND ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
1.
Summary of Significant Accounting Policies
Organization
OG&E generates, transmits, distributes and sells electric energy in Oklahoma and western Arkansas. Its operations are subject to regulation by the OCC, the APSC and the FERC. OG&E was incorporated in 1902 under the laws of the Oklahoma Territory. OG&E is the largest electric utility in Oklahoma and its franchised service territory includes the Fort Smith, Arkansas area. OG&E sold its retail natural gas business in 1928 and is no longer engaged in the natural gas distribution business. OG&E is a wholly-owned subsidiary of OGE Energy, an energy and energy services provider offering physical delivery and related services for both electricity and natural gas primarily in the south central United States.
Basis of Presentation
In the opinion of management, all adjustments necessary to fairly present the financial position of OG&E at December 31, 2014 and 2013 and the results of its operations and cash flows for the years ended December 31, 2014, 2013 and 2012, have been included and are of a normal recurring nature except as otherwise disclosed.
Accounting Records
The accounting records of OG&E are maintained in accordance with the Uniform System of Accounts prescribed by the FERC and adopted by the OCC and the APSC. Additionally, OG&E, as a regulated utility, is subject to accounting principles for certain types of rate-regulated activities, which provide that certain incurred costs that would otherwise be charged to expense can be deferred as regulatory assets, based on the expected recovery from customers in future rates. Likewise, certain actual or anticipated credits that would otherwise reduce expense can be deferred as regulatory liabilities, based on the expected flowback to customers in future rates. Management's expected recovery of deferred costs and flowback of deferred credits generally results from specific decisions by regulators granting such ratemaking treatment.
OG&E records certain incurred costs and obligations as regulatory assets or liabilities if it is probable, based on regulatory orders or other available evidence, that the cost or obligation will be included in amounts allowable for recovery or refund in future rates.
The following table is a summary of OG&E's regulatory assets and liabilities at:
(A)
Included in Other Current Assets on the Balance Sheets.
(B)
Included in Other Current Liabilities on the Balance Sheets.
Fuel clause under recoveries are generated from under recoveries from OG&E's customers when OG&E's cost of fuel exceeds the amount billed to its customers. Fuel clause over recoveries are generated from over recoveries from OG&E's customers when the amount billed to its customers exceeds OG&E's cost of fuel. OG&E's fuel recovery clauses are designed to smooth the impact of fuel price volatility on customers' bills. As a result, OG&E under recovers fuel costs in periods of rising fuel prices above the baseline charge for fuel and over recovers fuel costs when prices decline below the baseline charge for fuel. Provisions in the fuel clauses are intended to allow OG&E to amortize under and over recovery balances.
OG&E recovers program costs related to the Demand and Energy Efficiency Program. An extension of the demand program rider was approved in December 2012, which allows for the recovery of demand program costs, lost revenues associated with certain achieved energy, demand savings and performance based incentives and the recovery of costs associated with research and development investments through December 2015.
OG&E recovers a return on the capital expenditures along with operation and maintenance expense and depreciation expense related to the Crossroads wind farm through riders established by the OCC and APSC. OG&E began recovery in the fourth quarter of 2011 in Oklahoma and June of 2013 in Arkansas, and believes the rider will continue until new rates are implemented in OG&E's next general rate case in each jurisdiction.
The benefit obligations regulatory asset is comprised of expenses recorded which are probable of future recovery and that have not yet been recognized as components of net periodic benefit cost, including net loss and prior service cost. These expenses are recorded as a regulatory asset as OG&E had historically recovered and currently recovers pension and postretirement benefit plan expense in its electric rates. If, in the future, the regulatory bodies indicate a change in policy related to the recovery of pension and postretirement benefit plan expenses, this could cause the benefit obligations regulatory asset balance to be reclassified to Accumulated other comprehensive income.
The following table is a summary of the components of the benefit obligations regulatory asset at:
The following amounts in the benefit obligations regulatory asset at December 31, 2014 are expected to be recognized as components of net periodic benefit cost in 2015:
Income taxes recoverable from customers, which represents income tax benefits previously used to reduce OG&E's revenues, are treated as regulatory assets and liabilities and are being amortized over the estimated remaining life of the assets to which they relate. These amounts are being recovered in rates as the temporary differences that generated the income tax benefit turn around. The income tax related regulatory assets and liabilities are netted in Income taxes recoverable from customers, net in the regulatory assets and liabilities table above.
OG&E recovers the cost of system-wide deployment of smart grid technology and implementing the smart grid pilot program, the incremental costs for web portal access, education and providing home energy reports. These amounts are currently being recovered through a rider which will remain in effect until the smart grid project costs are included in base rates in OG&E's next general rate case. Costs not included in the rider are the incremental costs for web portal access, education and home energy reports, which are capped at $6.9 million, and the stranded costs associated with OG&E's analog electric meters, which have been replaced by smart meters, which were accumulated during the smart grid deployment and have been included in the Smart Grid asset in the Regulatory Assets/Liabilities table above. These costs are expected to be recovered in base rates in OG&E's next general rate case.
OG&E defers annual Oklahoma storm-related operation and maintenance expenses in excess of $2.7 million and includes in expense any Oklahoma storm-related operation and maintenance expenses up to $2.7 million. OG&E will recover the amounts deferred each year, over a five-year period.
Unamortized loss on reacquired debt is comprised of unamortized debt issuance costs related to the early retirement of OG&E's long-term debt. These amounts are recorded in interest expenses and are being amortized over the term of the long-term debt which replaced the previous long-term debt. The unamortized loss on reacquired debt is not included in OG&E's rate base and does not otherwise earn a rate of return.
Accrued removal obligations represent asset retirement costs previously recovered from ratepayers for other than legal obligations.
OG&E recovers specific amounts of pension and postretirement medical costs in rates approved in its Oklahoma rate cases. In accordance with approved orders, OG&E defers the difference between actual pension and postretirement medical expenses and the amount approved in its last Oklahoma rate case as a regulatory asset or regulatory liability. These amounts have been recorded in the Pension tracker in the regulatory assets and liabilities table above.
Management continuously monitors the future recoverability of regulatory assets. When in management's judgment future recovery becomes impaired, the amount of the regulatory asset is adjusted, as appropriate. If OG&E were required to discontinue the application of accounting principles for certain types of rate-regulated activities for some or all of its operations, it could result in writing off the related regulatory assets, which could have significant financial effects.
Use of Estimates
In preparing the Financial Statements, management is required to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and contingent liabilities at the date of the Financial Statements and the reported amounts of revenues and expenses during the reporting period. Changes to these assumptions and estimates could have a material effect on OG&E's Financial Statements. However, OG&E believes it has taken reasonable positions where assumptions and estimates are used in order to minimize the negative financial impact to OG&E that could result if actual results vary from the assumptions and estimates. In management's opinion, the areas of OG&E where the most significant judgment is exercised includes the determination of Pension Plan assumptions, income taxes, contingency reserves, asset retirement obligations, and depreciable lives of property, plant and equipment, the existence of regulatory assets and liabilities and unbilled revenues.
Cash and Cash Equivalents
For purposes of the Financial Statements, OG&E considers all highly liquid debt instruments purchased with an original maturity of three months or less to be cash equivalents. These investments are carried at cost, which approximates fair value.
Allowance for Uncollectible Accounts Receivable
Customer balances are generally written off if not collected within six months after the final billing date. The allowance for uncollectible accounts receivable for OG&E is calculated by multiplying the last six months of electric revenue by the provision rate. The provision rate is based on a 12-month historical average of actual balances written off. To the extent the historical collection rates are not representative of future collections, there could be an effect on the amount of uncollectible expense recognized. Also, a portion of the uncollectible provision related to fuel within the Oklahoma jurisdiction is being recovered through the fuel adjustment clause. The allowance for uncollectible accounts receivable was $1.6 million and $1.9 million at December 31, 2014 and 2013, respectively.
New business customers are required to provide a security deposit in the form of cash, bond or irrevocable letter of credit that is refunded when the account is closed. New residential customers, whose outside credit scores indicate an elevated risk, are required to provide a security deposit that is refunded based on customer protection rules defined by the OCC and the APSC. The payment behavior of all existing customers is continuously monitored and, if the payment behavior indicates sufficient risk within the meaning of the applicable utility regulation, customers will be required to provide a security deposit.
Fuel Inventories
Fuel inventories for the generation of electricity consist of coal, natural gas and oil. OG&E uses the weighted-average cost method of accounting for inventory that is physically added to or withdrawn from storage or stockpiles. The amount of fuel inventory was $66.7 million and $74.4 million at December 31, 2014 and 2013, respectively. Effective May 1, 2014, the gas storage services agreement with Enable was terminated. As a result of this contract termination, approximately 5.3 BCF of cushion gas owned by OG&E on the Enable system is being directed to OG&E's power plants over a five year period during peak time of June 1 to August 31 at a rate of 11,500 MMBtu/day for a total of 1.06 Bcf per year. Therefore, approximately $11.0 million of cushion gas was reclassified from Plant-in-Service to Deferred Charges and Other Assets and an additional $2.7 million was reclassified to current Fuel Inventories on the Balance Sheets. As of December 31, 2014, the balance of cushion gas in Other Assets is approximately $8.2 million.
Property, Plant and Equipment
All property, plant and equipment is recorded at cost. Newly constructed plant is added to plant balances at cost which includes contracted services, direct labor, materials, overhead, transportation costs and the allowance for funds used during construction. Replacements of units of property are capitalized as plant. For assets that belong to a common plant account, the replaced plant is removed from plant balances and the cost of such property is charged to Accumulated Depreciation. For assets that do not belong to a common plant account, the replaced plant is removed from plant balances with the related accumulated depreciation and the remaining balance net of any salvage proceeds is recorded as a loss in the Statements of Income as Other
Expense. Repair and replacement of minor items of property are included in the Statements of Income as Other Operation and Maintenance Expense.
The table below presents OG&E's ownership interest in the jointly-owned McClain Plant and the jointly-owned Redbud Plant, and, as disclosed below, only OG&E's ownership interest is reflected in the property, plant and equipment and accumulated depreciation balances in these tables. The owners of the remaining interests in the McClain Plant and the Redbud Plant are responsible for providing their own financing of capital expenditures. Also, only OG&E's proportionate interests of any direct expenses of the McClain Plant and the Redbud Plant such as fuel, maintenance expense and other operating expenses are included in the applicable financial statement captions in the Statement of Income.
(A)
Construction work in progress was $0.5 million and $0.4 million for the McClain and Redbud Plants, respectively.
(B)
This amount includes a plant acquisition adjustment of $148.3 million and accumulated amortization of $34.3 million.
(A)
Construction work in progress was $0.1 million and $39.5 million for the McClain and Redbud Plants, respectively.
(B)
This amount includes a plant acquisition adjustment of $148.3 million and accumulated amortization of $28.8 million.
OG&E's property, plant and equipment and related accumulated depreciation are divided into the following major classes at:
(A)
This amount includes a plant acquisition adjustment of $148.3 million and accumulated amortization of $34.3 million.
(B)
This amount includes a plant acquisition adjustment of $3.3 million and accumulated amortization of $0.4 million.
(A)
This amount includes a plant acquisition adjustment of $148.3 million and accumulated amortization of $28.8 million.
(B)
This amount includes a plant acquisition adjustment of $3.3 million and accumulated amortization of $0.3 million.
The unamortized computer software costs were $33.6 million and $16.8 million at December 31, 2014 and 2013, respectively. In 2014, 2013 and 2012, amortization expense for computer software costs was $5.2 million, $4.0 million and $4.2 million, respectively.
Depreciation and Amortization
The provision for depreciation, which was 2.8 percent of the average depreciable utility plant for both 2014 and 2013, is provided on a straight-line method over the estimated service life of the utility assets. Depreciation is provided at the unit level for production plant and at the account or sub-account level for all other plant, and is based on the average life group method. In 2015, the provision for depreciation is projected to be 2.8 percent of the average depreciable utility plant. Amortization of intangible assets is computed using the straight-line method. Of the remaining amortizable intangible plant balance at December 31, 2014, 96.0 percent will be amortized over 9 years with 4.0 percent of the remaining amortizable intangible plant balance at December 31, 2014 being amortized over 26 years. Amortization of plant acquisition adjustments is provided on a straight-line basis over the estimated remaining service life of the acquired asset. Plant acquisition adjustments include $148.3 million for the Redbud Plant, which are being amortized over a 27-year life and $3.3 million for certain substation facilities in OG&E's service territory, which are being amortized over a 37 to 59-year period.
Asset Retirement Obligations
OG&E has previously recorded asset retirement obligations that are being amortized over their respective lives ranging from 4 to 74 years.
The following table summarizes changes to OG&E's asset retirement obligations during the years ended December 31, 2014 and 2013.
Allowance for Funds Used During Construction
Allowance for funds used during construction is calculated according to the FERC pronouncements for the imputed cost of equity and borrowed funds. Allowance for funds used during construction, a non-cash item, is reflected as an increase to net other income and a reduction to interest expense in the Statements of Income and as an increase to Construction Work in Progress in the Balance Sheets. Allowance for funds used during construction rates, compounded semi-annually, were 6.92 percent, 8.33 percent and 8.93 percent for the years ended December 31, 2014, 2013 and 2012, respectively. The decrease in the allowance for funds used during construction rates in 2014 was primarily due to two factors. First, an increase in the average daily balance of short-term debt resulted in less equity being required to finance construction projects, which caused the equity portion of allowance for funds using during construction to decrease. Second, that same increase in the average daily balance of short-term debt allowed the interest and fixed commercial paper fees to be lower per dollar of short term debt, resulting in a lower short term debt rate which caused the debt portion of allowance for funds used during construction to decrease.
Collection of Sales Tax
In the normal course of its operations, OG&E collects sales tax from its customers. OG&E records a current liability for sales taxes when it bills its customers and eliminates this liability when the taxes are remitted to the appropriate governmental authorities. OG&E excludes the sales tax collected from its operating revenues.
Revenue Recognition
General
OG&E reads its customers' meters and sends bills to its customers throughout each month. As a result, there is a significant amount of customers' electricity consumption that has not been billed at the end of each month. Unbilled revenue is presented in Accrued Unbilled Revenues on the Balance Sheets and in Operating Revenues on the Statements of Income based on estimates of usage and prices during the period. The estimates that management uses in this calculation could vary from the actual amounts to be paid by customers.
SPP Purchases and Sales
OG&E currently owns and operates transmission and generation facilities as part of a vertically integrated utility. OG&E is a member of the SPP regional transmission organization and has transferred operational authority, but not ownership, of OG&E's transmission facilities to the SPP. On March 1, 2014, the SPP implemented FERC approved regional day ahead and real-time markets for energy and operating services, as well as associated transmission congestion rights. Collectively the three markets operate together under the global name, SPP Integrated Marketplace. OG&E represents owned and contracted generation assets, and customer load in the SPP Integrated Marketplace for the sole benefit of its customers. OG&E has not participated in the SPP Integrated Marketplace for any speculative trading activities. OG&E records SPP Integrated Marketplace transactions as sales or purchases per FERC Order 668, which requires that purchases and sales be recorded on a net basis for each settlement period of the SPP Integrated Marketplace. These results are reported as Operating Revenues or Cost of Goods Sold in its Financial Statements. OG&E revenues, expenses, assets and liabilities may be adversely affected by changes in the organization, operating and regulation by the FERC or the SPP.
Fuel Adjustment Clauses
The actual cost of fuel used in electric generation and certain purchased power costs are passed through to OG&E's customers through fuel adjustment clauses. The fuel adjustment clauses are subject to periodic review by the OCC, the APSC and the FERC. The OCC, the APSC and the FERC have authority to review the appropriateness of gas transportation charges or other fees OG&E pays to its affiliate, Enable.
Income Taxes
OG&E is a member of an affiliated group that files consolidated income tax returns in the U.S. Federal jurisdiction and various state jurisdictions. Income taxes are generally allocated to each company in the affiliated group based on its stand-alone taxable income or loss. Federal investment tax credits previously claimed on electric utility property have been deferred and are being amortized to income over the life of the related property. OG&E uses the asset and liability method of accounting for income taxes. Under this method, a deferred tax asset or liability is recognized for the estimated future tax effects attributable to temporary differences between the financial statement basis and the tax basis of assets and liabilities as well as tax credit carry forwards and net operating loss carry forwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in the period of the change. OG&E recognizes interest related to unrecognized tax benefits in interest expense and recognizes penalties in other expense.
Accrued Vacation
OG&E accrues vacation pay monthly by establishing a liability for vacation earned. Vacation may be taken as earned and is charged against the liability. At the end of each year, the liability represents the amount of vacation earned, but not taken.
Environmental Costs
Accruals for environmental costs are recognized when it is probable that a liability has been incurred and the amount of the liability can be reasonably estimated. Costs are charged to expense or deferred as a regulatory asset based on expected recovery from customers in future rates, if they relate to the remediation of conditions caused by past operations or if they are not expected to mitigate or prevent contamination from future operations. Where environmental expenditures relate to facilities currently in use, such as pollution control equipment, the costs may be capitalized and depreciated over the future service periods. Estimated remediation costs are recorded at undiscounted amounts, independent of any insurance or rate recovery, based on prior experience, assessments and current technology. Accrued obligations are regularly adjusted as environmental assessments and estimates are revised, and remediation efforts proceed. For sites where OG&E has been designated as one of several potentially responsible
parties, the amount accrued represents OG&E's estimated share of the cost. OG&E had $7.5 million and $6.2 million in accrued environmental liabilities at December 31, 2014 and 2013, respectively, which are included in the asset retirement obligations table.
2.
Accounting Pronouncement
In May 2014, the FASB issued ASU 2014-09, "Revenue from Contracts with Customers" (ASC Topic 606). The new standard provides guidance for all revenue arising from contracts with customers and provides a model for the measurement and recognition of gains and losses arising from the sale of certain nonfinancial assets such as property and equipment, including real estate. The core principle of the revenue model is that an entity should recognize revenue at an amount that reflects the consideration to which the entity expects to be entitled in exchange for transferring goods or services to a customer. The principles of the standard will be applied in five steps:
1.	Identify the contract(s) with a customer
2.	Identify the performance obligations in the contract
3.	Determine the transaction price
4.	Allocate the transaction price to the performance obligations in the contract
5.	Recognize revenue when (or as) the entity satisfies a performance obligation
The new guidance is effective for fiscal years beginning after December 15, 2016 and must be adopted using either a full retrospective approach for all periods presented or a modified retrospective approach. Early adoption is not permitted. OG&E is currently evaluating the potential impact the adoption will have on its financial statements.
3.
Related Party Transactions
OGE Energy charged operating costs to OG&E of $120.3 million, $120.1 million and $118.4 million in 2014, 2013 and 2012, respectively. OGE Energy charges operating costs to OG&E based on several factors. Operating costs directly related to OG&E are assigned as such. Operating costs incurred for the benefit of OG&E are allocated either as overhead based primarily on labor costs or using the "Distrigas" method.
The following table summarizes related party transactions between OG&E and its affiliate, Enable, during 2014, 2013 and 2012.
In 2014, 2013 and 2012, OG&E declared dividends to OGE Energy of $120.0 million, $170.0 million and $75.0 million, respectively.
4.
Fair Value Measurements
The classification of OG&E's fair value measurements requires judgment regarding the degree to which market data are observable or corroborated by observable market data. GAAP establishes a fair value hierarchy that prioritizes the inputs used to measure fair value based on observable and unobservable data. The hierarchy categorizes the inputs into three levels, with the highest priority given to quoted prices in active markets for identical unrestricted assets or liabilities (Level 1) and the lowest priority given to unobservable inputs (Level 3). Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The three levels defined in the fair value hierarchy are as follows:
Level 1 inputs are quoted prices in active markets for identical unrestricted assets or liabilities that are accessible at the measurement date.
Level 2 inputs are inputs other than quoted prices in active markets included within Level 1 that are either directly or indirectly observable at the reporting date for the asset or liability for substantially the full term of the asset or liability. Level 2 inputs include quoted prices for similar assets or liabilities in active markets and quoted prices for identical or similar assets or liabilities in markets that are not active.
Level 3 inputs are prices or valuation techniques for the asset or liability that require inputs that are both significant to the fair value measurement and unobservable (i.e., supported by little or no market activity). Unobservable inputs reflect the reporting entity's own assumptions about the assumptions that market participants would use in pricing the asset or liability (including assumptions about risk).
OG&E had no financial instruments measured at fair value on a recurring basis at December 31, 2014 and December 31, 2013.
The carrying value of the financial instruments included in the Balance Sheets approximates fair value except for long-term debt which is valued at the carrying amount. The fair value of OG&E's long-term debt is based on quoted market prices and estimates of current rates available for similar issues with similar maturities and is classified as Level 2 in the fair value hierarchy. The following table summarizes the fair value and carrying amount of OG&E's financial instruments at December 31, 2014 and December 31, 2013.
5.
Stock-Based Compensation
In 2013, OGE Energy adopted, and its shareowners approved, the 2013 Stock Incentive Plan. The 2013 Plan replaced the 2008 Plan and no further awards will be granted under the 2008 Plan. Under the 2013 Stock Incentive Plan, restricted stock, restricted stock units, stock options, stock appreciation rights and performance units may be granted to officers, directors and other key employees of OGE Energy and its subsidiaries. OGE Energy has authorized the issuance of up to 7,400,000 shares under the 2013 Stock Incentive Plan.
The following table summarizes OG&E's pre-tax compensation expense and related income tax benefit for the years ended December 31, 2014, 2013 and 2012 related to performance units and restricted stock for OG&E employees.
OGE Energy has issued new shares to satisfy stock option exercises, restricted stock grants and payouts of earned performance units. In 2014, 2013 and 2012, there were 100,640 shares, 139,706 shares and 205,838 shares, respectively, of new common stock issued to OG&E's employees pursuant to OGE Energy's stock incentive plans related to exercised stock options, restricted stock grants (net of forfeitures) and payouts of earned performance units. In 2014, there were 1,076 shares of restricted stock returned to OGE Energy to satisfy tax liabilities.
Performance Units
Under the Stock Incentive Plan, OGE Energy has issued performance units which represent the value of one share of OGE Energy's common stock. The performance units provide for accelerated vesting if there is a change in control (as defined in the Stock Incentive Plan). Each performance unit is subject to forfeiture if the recipient terminates employment with OGE Energy or a subsidiary prior to the end of the three-year award cycle for any reason other than death, disability or retirement. In the event of death, disability or retirement, a participant will receive a prorated payment based on such participant's number of full months of service during the award cycle, further adjusted based on the achievement of the performance goals during the award cycle.
The performance units granted based on total shareholder return are contingently awarded and will be payable in shares of OGE Energy's common stock subject to the condition that the number of performance units, if any, earned by the employees upon the expiration of a three-year award cycle (i.e., three-year cliff vesting period) is dependent on OGE Energy's total shareholder return ranking relative to a peer group of companies. The performance units granted based on earnings per share are contingently awarded and will be payable in shares of OGE Energy's common stock based on OGE Energy's earnings per share growth over a three-year award cycle (i.e., three-year cliff vesting period) compared to a target set at the time of the grant by the Compensation Committee of OGE Energy's Board of Directors. All of these performance units are classified as equity in OGE Energy's Consolidated Balance Sheet. If there is no or only a partial payout for the performance units at the end of the award cycle, the unearned performance units are cancelled. Payout requires approval of the Compensation Committee of OGE Energy's Board of Directors. Payouts, if any, are all made in common stock and are considered made when the payout is approved by the Compensation Committee.
Performance Units - Total Shareholder Return
The fair value of the performance units based on total shareholder return was estimated on the grant date using a lattice-based valuation model that factors in information, including the expected dividend yield, expected price volatility, risk-free interest rate and the probable outcome of the market condition, over the expected life of the performance units. Compensation expense for the performance units is a fixed amount determined at the grant date fair value and is recognized over the three-year award cycle regardless of whether performance units are awarded at the end of the award cycle. Dividends were not accrued or paid for awards prior to February 2014, and were therefore not included in the fair value calculation. Beginning with the February 2014 performance unit awards, dividends are accrued on a quarterly basis pending achievement of payout criteria, and were therefore included in the fair value calculations. Expected price volatility is based on the historical volatility of OGE Energy's common stock for the past three years and was simulated using the Geometric Brownian Motion process. The risk-free interest rate for the performance unit grants is based on the three-year U.S. Treasury yield curve in effect at the time of the grant. The expected life of the units is based on the non-vested period since inception of the award cycle. There are no post-vesting restrictions related to OGE Energy's performance units based on total shareholder return. The number of performance units granted based on total shareholder return and the assumptions used to calculate the grant date fair value of the performance units based on total shareholder return are shown in the following table.
Performance Units - Earnings Per Share
The fair value of the performance units based on earnings per share is based on grant date fair value which is equivalent to the price of one share of OGE Energy's common stock on the date of grant. The fair value of performance units based on earnings per share varies as the number of performance units that will vest is based on the grant date fair value of the units and the probable outcome of the performance condition. OGE Energy reassesses at each reporting date whether achievement of the performance condition is probable and accrues compensation expense if and when achievement of the performance condition is probable. As a result, the compensation expense recognized for these performance units can vary from period to period. There are no post-vesting restrictions related to OGE Energy's performance units based on earnings per share. The number of performance units granted based on earnings per share and the grant date fair value are shown in the following table.
Restricted Stock
Under the Stock Incentive Plan and beginning in 2008, OGE Energy issued restricted stock to certain existing non-officer employees as well as other executives upon hire to attract and retain individuals to be competitive in the marketplace. The restricted stock vests in one-third annual increments. Prior to vesting, each share of restricted stock is subject to forfeiture if the recipient ceases to render substantial services to OGE Energy or a subsidiary for any reason other than death, disability or retirement. These shares may not be sold, assigned, transferred or pledged and are subject to a risk of forfeiture.
The fair value of the restricted stock was based on the closing market price of OGE Energy's common stock on the grant date. Compensation expense for the restricted stock is a fixed amount determined at the grant date fair value and is recognized as services are rendered by employees over a three-year vesting period. Also, OG&E treats its restricted stock as multiple separate awards by recording compensation expense separately for each tranche whereby a substantial portion of the expense is recognized in the earlier years in the requisite service period. Dividends are accrued and paid during the vesting period on all restricted stock awards prior to July 2014, and therefore included in the fair value calculation. For all awards after July 2014, dividends will only be paid on any restricted stock awards that vest, accordingly dividends are no longer included in the fair value calculations. The expected life of the restricted stock is based on the non-vested period since inception of the three-year award cycle. There are no post-vesting restrictions related to OGE Energy's restricted stock. The number of shares of restricted stock granted related to OG&E employees and the grant date fair value are shown in the following table.
A summary of the activity for OGE Energy's performance units and restricted stock applicable to OG&E's employees at December 31, 2014 and changes in 2014 are shown in the following table.
(A)
For performance units, this represents the target number of performance units granted. Actual number of performance units earned, if any, is dependent upon performance and may range from 0 percent to 200 percent of the target.
(B)
These amounts represent performance units that vested at December 31, 2013 which were settled in February 2014.
(C)
Due to certain employees transferring between OG&E and its affiliates.
A summary of the activity for OGE Energy's non-vested performance units and restricted stock applicable to OG&E's employees at December 31, 2014 and changes in 2014 are shown in the following table.
(A)
For performance units, this represents the target number of performance units granted. Actual number of performance units earned, if any, is dependent upon performance and may range from 0 percent to 200 percent of the target.
(B)
Due to certain employees transferring between OG&E and its affiliates.
(C)
The intrinsic value of the performance units based on total shareholder return and earnings per share is $0.0 million and $1.5 million, respectively.
Fair Value of Vested Performance Units and Restricted Stock
A summary of OG&E's fair value for its vested performance units and restricted stock is shown in the following table.
Unrecognized Compensation Cost
A summary of OG&E's unrecognized compensation cost for its non-vested performance units and restricted stock and the weighted-average periods over which the compensation cost is expected to be recognized are shown in the following table.
Stock Options
OGE Energy last issued stock options in 2004 and as of December 31, 2006, all stock options were fully vested and expensed. All stock options had a contractual life of 10 years.
A summary of the activity for OG&E's exercised stock options in 2013 and 2012 are shown in the following table.
(A)
The difference between the market value on the date of exercise and the option exercise price.
6.
Supplemental Cash Flow Information
The following table discloses information about investing and financing activities that affected recognized assets and liabilities but which did not result in cash receipts or payments. Also disclosed in the table is cash paid for interest, net of interest capitalized, and cash paid for income taxes, net of income tax refunds.
(A)
Net of interest capitalized of $2.4 million, $3.4 million and $3.5 million in 2014, 2013 and 2012, respectively.
7.
Income Taxes
The items comprising income tax expense are as follows:
OG&E is a member of an affiliated group that files consolidated income tax returns in the U.S. Federal jurisdiction and various state jurisdictions. With few exceptions, OG&E is no longer subject to U.S. Federal tax examinations by tax authorities for years prior to 2011 or state and local tax examinations by tax authorities for years prior to 2010. Income taxes are generally allocated to each company in the affiliated group based on its stand-alone taxable income or loss. Federal investment tax credits previously claimed on electric utility property have been deferred and are being amortized to income over the life of the related property. OG&E earns both Federal and Oklahoma state tax credits associated with production from its wind farms and earns Oklahoma state tax credits associated with its investments in electric generating facilities which further reduce OG&E's effective tax rate.
The following schedule reconciles the statutory tax rates to the effective income tax rate:
(A)
Represents credits associated with the production from OG&E's wind farms.
The deferred tax provisions are recognized as costs in the ratemaking process by the commissions having jurisdiction over the rates charged by OG&E. The components of Deferred Income Taxes at December 31, 2014 and 2013, respectively, were as follows:
As of December 31, 2014, OG&E has classified $10.5 million of unrecognized tax benefits as a reduction of deferred tax assets recorded. Management is currently unaware of any issues under review that could result in significant additional payments, accruals, or other material deviation from this amount.
Following is a reconciliation of the OG&E’s total gross unrecognized tax benefits as of the years ended December 31, 2014, 2013, and 2012.
Where applicable, OG&E classifies income tax-related interest and penalties as interest expense and other operation and maintenance expense, respectively. During the year ended December 31, 2014, there were no income tax-related interest or penalties recorded with regard to uncertain tax positions. The total amount of unrecognized tax benefits that would impact the effective tax rate, if recognized, was $10.5 million as of December 31, 2014.
As previously reported, in January 2013, OG&E determined that a portion of certain Oklahoma investment tax credits previously recognized but not yet utilized may not be available for utilization in future years. During 2014, OG&E recorded an additional reserve for this item of $4.2 million ($2.7 million after the federal tax benefit) related to the same Oklahoma investment tax credits generated in the current year but not yet utilized due to management's determination that it is more likely than not that it will be unable to utilize these credits.
Other
OG&E sustained Federal and state tax operating losses through 2013 caused primarily by bonus depreciation and other book verses tax temporary differences. As a result, OG&E had accrued Federal and state income tax benefits carrying into 2014. As OG&E can no longer carry these losses back to prior periods, these losses are being carried forward for utilization in future years. In addition to the operating losses, OG&E was unable to utilize the various tax credits that were generating during these years. These tax losses and credits are being carried as deferred tax assets and will be utilized in future periods. Under current law, OG&E anticipates future taxable income will be sufficient to utilize all of the losses and credits before they begin to expire, accordingly no valuation allowance is considered necessary. The following table summarizes these carry forwards:
OG&E projects full utilization of all Federal operating losses in 2015 as well as partial utilization of State operating loss carryforwards. Accordingly, a current deferred tax asset of $153.2 million has been reflected on the balance sheet.
Prior to 2014, OG&E had a Federal tax operating loss primarily caused by the accelerated tax "bonus" depreciation provision contained within the Tax Relief, Unemployment Insurance Reauthorization and Job Creation Act of 2010 which allowed OG&E to record a current income tax deduction for 100 percent of the cost of certain property placed into service in 2011 and 50 percent for certain property placed into service in 2012. During 2013, OG&E began to utilize these net operating losses.
On December 19, 2014, the Tax Increase Prevention Act of 2014 was signed into law. Among other things, the law included an extension of bonus depreciation for one year for property generally placed in service before January 1, 2015. The impact of the new law was reflected in OG&E's 2014 Financial Statements as an increase in Deferred Tax Liabilities with a
corresponding increase in Deferred Tax Assets related to the net operating loss. With this extension of bonus depreciation OG&E's utilization of net operating losses will continue into 2015.
8.
Common Stock and Cumulative Preferred Stock
There were no new shares of common stock issued in 2014, 2013 or 2012.
9.
Long-Term Debt
A summary of OG&E's long-term debt is included in the Statements of Capitalization. At December 31, 2014, OG&E was in compliance with all of its debt agreements.
Industrial Authority Bonds
OG&E has tax-exempt pollution control bonds with optional redemption provisions that allow the holders to request repayment of the bonds on any business day. The bonds, which can be tendered at the option of the holder during the next 12 months, are as follows:
All of these bonds are subject to an optional tender at the request of the holders, at 100 percent of the principal amount, together with accrued and unpaid interest to the date of purchase. The bond holders, on any business day, can request repayment of the bond by delivering an irrevocable notice to the tender agent stating the principal amount of the bond, payment instructions for the purchase price and the business day the bond is to be purchased. The repayment option may only be exercised by the holder of a bond for the principal amount. When a tender notice has been received by the trustee, a third party remarketing agent for the bonds will attempt to remarket any bonds tendered for purchase. This process occurs once per week. Since the original issuance of these series of bonds in 1995 and 1997, the remarketing agent has successfully remarketed all tendered bonds. If the remarketing agent is unable to remarket any such bonds, OG&E is obligated to repurchase such unremarketed bonds. As OG&E has both the intent and ability to refinance the bonds on a long-term basis and such ability is supported by an ability to consummate the refinancing, the bonds are classified as long-term debt in OG&E's Financial Statements. OG&E believes that it has sufficient liquidity to meet these obligations.
Issuance of Long-Term Debt
On March 25, 2014, OG&E completed the issuance of $250 million of 4.55 percent senior notes due March 15, 2044. The proceeds from the issuance were added to OG&E's general funds and were used to repay debt, fund capital expenditures and general corporate expenses, and utilized for working capital purposes.
On December 11, 2014, OG&E completed the issuance of $250 million of 4.00 percent Senior Notes, Series due December 15, 2044. The proceeds from the issuance were added to OG&E's general funds and were used to repay short-term debt, fund capital expenditures and general corporate expenses, and utilized for working capital purposes.
Redemption of Long-Term Debt
On August 1, 2014, OG&E redeemed all $140 million principal amount outstanding of its 6.50 percent senior notes due August 1, 2034 at 103.25 percent of their principal amount, plus accrued interest. The redemption premium of $4.6 million was deferred and will be amortized through March 2044 to match the expected regulatory treatment.
Long-Term Debt Maturities
Maturities of OG&E's long-term debt during the next five years consist of $0.2 million, $110.2 million, $125.1 million, $250.1 million and $250.1 million in years 2015, 2016, 2017, 2018 and 2019, respectively.
OG&E has previously incurred costs related to debt refinancings. Unamortized loss on reacquired debt is classified as a Non-Current Regulatory Asset, unamortized debt expense is classified as Deferred Charges and Other Assets and the unamortized premium and discount on long-term debt is classified as Long-Term Debt, respectively, in the Balance Sheets and are being amortized over the life of the respective debt.
10.
Short-Term Debt and Credit Facility
At December 31, 2014, there were $215.6 million in advances to OGE Energy as compared to $87.2 million in outstanding advances from OGE Energy in 2013. OG&E has an intercompany borrowing agreement with OGE Energy whereby OG&E has access to up to $400 million of OGE Energy's revolving credit amount. Effective July 29, 2013, OG&E extended the termination date of this agreement to December 13, 2017. At December 31, 2014, there were no intercompany borrowings under this agreement. OG&E has a $400 million unsecured five-year revolving credit facility which is available to back up OG&E's commercial paper borrowings and to provide revolving credit borrowings. This bank facility can also be used as a letter of credit facility. At December 31, 2014, there was $2.0 million supporting letters of credit at a weighted-average interest rate of 0.95 percent. There were no outstanding borrowings under this revolving credit agreement and no outstanding commercial paper borrowings at December 31, 2014.
In December 2011, OG&E entered into an unsecured five-year revolving credit agreement for $400.0 million. This credit facility contained an option, which could be exercised up to two times, to extend the term for an additional year. In the third quarter of 2013, OG&E utilized one of these one-year extensions, and received consent from all of the lenders, to extend the maturity of its credit agreement from December 13, 2016 to December 13, 2017. In the second quarter of 2014, OG&E utilized its second extension to extend the maturity of its credit facility from December 13, 2017 to December 13, 2018. As of December 31, 2014, the commitment of a single existing lender with respect to approximately $8.7 million of OG&E's credit facility, however, was not extended and, unless the non-extending lender is replaced in accordance with the terms of the credit facility, the commitment will expire December 13, 2017.
OGE Energy's and OG&E's ability to access the commercial paper market could be adversely impacted by a credit ratings downgrade or major market disruptions. Pricing grids associated with OGE Energy's and OG&E's credit facilities could cause annual fees and borrowing rates to increase if an adverse rating impact occurs. The impact of any future downgrade could include an increase in the costs of OGE Energy's and OG&E's short-term borrowings, but a reduction in OGE Energy's and OG&E's credit ratings would not result in any defaults or accelerations. Any future downgrade of OGE Energy or OG&E could also lead to higher long-term borrowing costs and, if below investment grade, would require OG&E to post collateral or letters of credit.
OG&E must obtain regulatory approval from the FERC in order to borrow on a short-term basis. OG&E has the necessary regulatory approvals to incur up to $800 million in short-term borrowings at any one time for a two-year period beginning January 1, 2015 and ending December 31, 2016.
11.
Retirement Plans and Postretirement Benefit Plans
Pension Plan and Restoration of Retirement Income Plan
OG&E's employees participate in OGE Energy's Pension Plan and Restoration of Retirement Income Plan.
It is OGE Energy's policy to fund the Pension Plan on a current basis based on the net periodic pension expense as determined by OGE Energy's actuarial consultants. During 2013, OGE Energy made contributions to its Pension Plan of $35 million of which none was OG&E's portion. to help ensure that the Pension Plan maintains an adequate funded status. Such contributions are intended to provide not only for benefits attributed to service to date, but also for those expected to be earned in the future. During 2014, OGE Energy did not make any contributions to its Pension Plan. OGE Energy has not yet determined whether it will need to make any contributions to the Pension Plan in 2015. Any contribution to the Pension Plan during 2015 would be a discretionary contribution, anticipated to be in the form of cash, and is not required to satisfy the minimum regulatory funding requirement specified by the Employee Retirement Income Security Act of 1974, as amended. OGE Energy could be required to make additional contributions if the value of its pension trust and postretirement benefit plan trust assets are adversely impacted by a major market disruption in the future.
In accordance with ASC Topic 715, "Compensation - Retirement Benefits," a one-time settlement charge is required to be recorded by an organization when lump sum payments or other settlements that relieve the organization from the responsibility for the pension benefit obligation during a plan year exceed the service cost and interest cost components of the organization’s net periodic pension cost. During 2013, OG&E experienced an increase in both the number of employees electing to retire and
the amount of lump sum payments to be paid to such employees upon retirement. As a result, and based in part on OG&E's historical experience regarding eligible employees who elect to retire in the last quarter of a particular year, OG&E recorded pension settlement charges of $17.6 million in the fourth quarter of 2013, of which $17.0 million related to OG&E’s Oklahoma jurisdiction and has been included in the pension tracker. The pension settlement charge did not require a cash outlay by OG&E and did not increase OG&E’s total pension expense over time, as the charges were an acceleration of costs that otherwise would be recognized as pension expense in future periods.
OGE Energy provides a Restoration of Retirement Income Plan to those participants in OGE Energy's Pension Plan whose benefits are subject to certain limitations of the Code. Participants in the Restoration of Retirement Income Plan receive the same benefits that they would have received under OGE Energy's Pension Plan in the absence of limitations imposed by the Federal tax laws. The Restoration of Retirement Income Plan is intended to be an unfunded plan.
Obligations and Funded Status
The following table presents the status of OG&E's Pension Plan, the Restoration of Retirement Income Plan and the postretirement benefit plans for 2014 and 2013. These amounts have been recorded in Accrued Benefit Obligations with the offset recorded as a regulatory asset in OG&E's Balance Sheet as discussed in Note 1. The regulatory asset represents a net periodic benefit cost to be recognized in the Statements of Income in future periods. OG&E's portion of the benefit obligation for OGE Energy's Pension Plan and the Restoration of Retirement Income Plan represents the projected benefit obligation, while the benefit obligation for the postretirement benefit plans represents the accumulated postretirement benefit obligation. The accumulated postretirement benefit obligation for OG&E's Pension Plan and Restoration of Retirement Income Plan differs from the projected benefit obligation in that the former includes no assumption about future compensation levels. The accumulated postretirement benefit obligation for the Pension Plan and the Restoration of Retirement Income Plan at December 31, 2014 was $522.1 million and $2.6 million, respectively. The accumulated postretirement benefit obligation for the Pension Plan and the Restoration of Retirement Income Plan at December 31, 2013 was $483.0 million and $1.9 million, respectively. The details of the funded status of the Pension Plan, the Restoration of Retirement Income Plan and the postretirement benefit plans and the amounts included in the Balance Sheets are as follows:
Net Periodic Benefit Cost
(A)
Unamortized prior service cost is amortized on a straight-line basis over the average remaining service period to the first eligibility age of participants who are expected to receive a benefit and are active at the date of the plan amendment.
(B)
In addition to the $14.2 million, $46.7 million and $34.1 million of net periodic benefit cost recognized in 2014, 2013 and 2012, respectively, OG&E recognized the following:
•
an increase in pension expense in 2014, 2013 and 2012 of $11.2 million, $5.8 million and $8.3 million, respectively, to maintain the allowable amount to be recovered for pension expense in the Oklahoma jurisdiction, which are included in the Pension tracker regulatory asset or liability (see Note 1);
•
an increase in postretirement medical expense in 2014, 2013 and 2012 of $5.2 million, $0.6 million and $0.8 million, respectively, to maintain the allowable amount to be recovered for postretirement medical expense in the Oklahoma jurisdiction which are included in the Pension tracker regulatory asset or liability (see Note 1); and
•
a deferral of pension expense in 2013 of $17.0 million which includes a portion of OGE Energy's pension settlement charge, related to the pension settlement charge of $17.6 million which is included in the Pension tracker regulatory account (see Note 1).
Rate Assumptions
N/A - not applicable
The overall expected rate of return on plan assets assumption was 7.50 percent and 8.00 percent in 2014 and 2013 , respectively, in determining net periodic benefit cost due to recent returns on OGE Energy's long-term investment portfolio. The rate of return on plan assets assumption is the average long-term rate of earnings expected on the funds currently invested and to be invested for the purpose of providing benefits specified by the Pension Plan or postretirement benefit plans. This assumption is reexamined at least annually and updated as necessary. The rate of return on plan assets assumption reflects a combination of historical return analysis, forward-looking return expectations and the plans' current and expected asset allocation.
The assumed health care cost trend rates have a significant effect on the amounts reported for postretirement medical benefit plans. Future health care cost trend rates are assumed to be 7.85 percent in 2015 with the rates trending downward to 4.48 percent by 2028. A one-percentage point change in the assumed health care cost trend rate would have the following effects:
Plan Investments, Policies and Strategies
The Pension Plan assets are held in a trust which follows an investment policy and strategy designed to reduce the funded status volatility of the Plan by utilizing liability driven investing. The purpose of liability driven investing is to structure the asset portfolio to more closely resemble the pension liability and thereby more effectively hedge against changes in the liability. The investment policy follows a glide path approach that shifts a higher portfolio weighting to fixed income as the Plan's funded status increases. The table below sets forth the targeted fixed income and equity allocations at different funded status levels.
Within the portfolio's overall allocation to equities, the funds are allocated according to the guidelines in the table below.
OGE Energy has retained an investment consultant responsible for the general investment oversight, analysis, monitoring investment guideline compliance and providing quarterly reports to certain of OG&E's members and OGE Energy's Investment Committee. The various investment managers used by the trust operate within the general operating objectives as established in the investment policy and within the specific guidelines established for each investment manager's respective portfolio.
The portfolio is rebalanced at least on an annual basis to bring the asset allocations of various managers in line with the target asset allocation listed above. More frequent rebalancing may occur if there are dramatic price movements in the financial markets which may cause the trust's exposure to any asset class to exceed or fall below the established allowable guidelines.
To evaluate the progress of the portfolio, investment performance is reviewed quarterly. It is, however, expected that performance goals will be met over a full market cycle, normally defined as a three to five year period. Analysis of performance is within the context of the prevailing investment environment and the advisors' investment style. The goal of the trust is to provide a rate of return consistently from three percent to five percent over the rate of inflation (as measured by the national Consumer Price Index) on a fee adjusted basis over a typical market cycle of no less than three years and no more than five years. Each investment manager is expected to outperform its respective benchmark. Below is a list of each asset class utilized with appropriate comparative benchmark(s) each manager is evaluated against:
The fixed income managers are expected to use discretion over the asset mix of the trust assets in its efforts to maximize risk-adjusted performance. Exposure to any single issuer, other than the U.S. government, its agencies, or its instrumentalities (which have no limits) is limited to five percent of the fixed income portfolio as measured by market value. At least 75 percent of the invested assets must possess an investment grade rating at or above Baa3 or BBB- by Moody's Investors Services, Standard & Poor's Ratings Services or Fitch Ratings. The portfolio may invest up to 10 percent of the portfolio's market value in convertible bonds as long as the securities purchased meet the quality guidelines. A portfolio may invest up to 25 percent of the portfolio's market value in private placement, including 144A securities with or without registration rights and allow for futures to be traded in the portfolio. The purchase of any of OGE Energy's equity, debt or other securities is prohibited.
The domestic value equity managers focus on stocks that the manager believes are undervalued in price and earn an average or less than average return on assets, and often pays out higher than average dividend payments. The domestic growth equity manager will invest primarily in growth companies which consistently experience above average growth in earnings and sales, earn a high return on assets, and reinvest cash flow into existing business. The domestic mid-cap equity portfolio manager focuses on companies with market capitalizations lower than the average company traded on the public exchanges with the following characteristics: price/earnings ratio at or near the Russell Midcap Index, small dividend yield, return on equity at or near the Russell Midcap Index and an earnings per share growth rate at or near the Russell Midcap Index. The domestic small-cap equity manager will purchase shares of companies with market capitalizations lower than the average company traded on the public exchanges with the following characteristics: price/earnings ratio at or near the Russell 2000, small dividend yield, return on equity at or near the Russell 2000 and an earnings per share growth rate at or near the Russell 2000. The international global equity manager invests primarily in non-dollar denominated equity securities. Investing internationally diversifies the overall trust across the global equity markets. The manager is required to operate under certain restrictions including: regional constraints, diversification requirements and percentage of U.S. securities. The Morgan Stanley Capital International All Country World ex-US Index is the benchmark for comparative performance purposes. The Morgan Stanley Capital International All Country World ex-US Index is a market value weighted index designed to measure the combined equity market performance of developed and emerging markets countries, excluding the United States. All of the equities which are purchased for the international portfolio are thoroughly researched. Only companies with a market capitalization in excess of $100 million are allowable. No more than five percent of the portfolio can be invested in any one stock at the time of purchase. All securities are freely traded on a recognized stock exchange and there are no over-the-counter derivatives. The following investment categories are excluded: options (other than traded currency options), commodities, futures (other than currency futures or currency hedging), short sales/margin purchases, private placements, unlisted securities and real estate (but not real estate shares).
For all domestic equity investment managers, no more than eight percent (five percent for mid-cap and small-cap equity managers) can be invested in any one stock at the time of purchase and no more than 16 percent (10 percent for mid-cap and small-cap equity managers) after accounting for price appreciation. Options or financial futures may not be purchased unless prior approval of OGE Energy's Investment Committee is received. The purchase of securities on margin is prohibited as is securities lending. Private placement or venture capital may not be purchased. All interest and dividend payments must be swept on a daily
basis into a short-term money market fund for re-deployment. The purchase of any of OGE Energy's equity, debt or other securities is prohibited. The purchase of equity or debt issues of the portfolio manager's organization is also prohibited. The aggregate positions in any company may not exceed one percent of the fair market value of its outstanding stock.
Plan Investments
The following tables summarize OG&E's portion of OGE Energy's Pension Plan's investments that are measured at fair value on a recurring basis at December 31, 2014 and 2013. There were no Level 3 investments held by the Pension Plan at December 31, 2014 and 2013.
(A)
This category represents U.S. treasury notes and bonds with a Moody's Investors Services rating of Aaa and Government Agency Bonds with a Moody's Investors Services rating of A1 or higher.
(B)
This category primarily represents U.S. corporate bonds with an investment grade rating at or above Baa3 or BBB- by Moody's Investors Services, Standard & Poor's Ratings Services or Fitch Ratings.
(C)
This category represents units of participation in a commingled fund that primarily invested in stocks of international companies and emerging markets.
(D)
This category represents units of participation in an investment pool which primarily invests in foreign or domestic bonds, debentures, mortgages, equipment or other trust certificates, notes, obligations issued or guaranteed by the U.S. Government or its agencies, bank certificates of deposit, bankers' acceptances and repurchase agreements, high grade commercial paper and other instruments with money market characteristics with a fixed or variable interest rate. There are no restrictions on redemptions in the common/collective trust.
The three levels defined in the fair value hierarchy and examples of each are as follows:
Level 1 inputs are quoted prices in active markets for identical unrestricted assets or liabilities that are accessible by the Pension Plan at the measurement date. Instruments classified as Level 1 include investments in common and preferred stocks, U.S. treasury notes and bonds, mutual funds and interest-bearing cash.
Level 2 inputs are inputs other than quoted prices in active markets included within Level 1 that are either directly or indirectly observable at the reporting date for the asset or liability for substantially the full term of the asset or liability. Level 2 inputs include quoted prices for similar assets or liabilities in active markets and quoted prices for identical or similar assets or liabilities in markets that are not active. Instruments classified as Level 2 include corporate fixed income and other securities, mortgage-backed securities, other U.S. Government obligations, commingled fund, a common/collective trust, U.S. municipal bonds, foreign government bonds, a repurchase agreement, money market fund and forward contracts.
Level 3 inputs are prices or valuation techniques for the asset or liability that require inputs that are both significant to the fair value measurement and unobservable (i.e., supported by little or no market activity). Unobservable inputs reflect the Plan's own assumptions about the assumptions that market participants would use in pricing the asset or liability (including assumptions about risk).
Postretirement Benefit Plans
In addition to providing pension benefits, OGE Energy provides certain medical and life insurance benefits for eligible retired members. Regular, full-time, active employees hired prior to February 1, 2000 whose age and years of credited service total or exceed 80 or have attained at least age 55 with 10 or more years of service at the time of retirement are entitled to postretirement medical benefits while employees hired on or after February 1, 2000 are not entitled to postretirement medical benefits. Eligible retirees must contribute such amount as OGE Energy specifies from time to time toward the cost of coverage for postretirement benefits. The benefits are subject to deductibles, co-payment provisions and other limitations. OG&E charges to expense the postretirement benefit costs and includes an annual amount as a component of the cost-of-service in future ratemaking proceedings.
OGE Energy's contribution to the medical costs for pre-65 aged eligible retirees are fixed at the 2011 level and OGE Energy covers future annual medical inflationary cost increases up to five percent. Increases in excess of five percent annually are covered by the pre-65 aged retiree in the form of premium increases. OGE Energy provides Medicare-eligible retirees and their Medicare-eligible spouses an annual fixed contribution to OGE Energy's sponsored health reimbursement arrangement. OGE Energy's Medicare-eligible retirees are able to purchase individual insurance policies supplemental to Medicare through a third-party administrator and use their health reimbursement arrangement funds for reimbursement of medical premiums and other eligible medical expenses.
Plan Investments
The following tables summarize OG&E's portion of OGE Energy's postretirement benefit plans investments that are measured at fair value on a recurring basis at December 31, 2014 and 2013. There were no Level 2 investments held by the postretirement benefit plans at December 31, 2014 and 2013.
(A)
This category represents a group retiree medical insurance contract which invests in a pool of common stocks, bonds and money market accounts, of which a significant portion is comprised of mortgage-backed securities.
The postretirement benefit plans Level 3 investment includes an investment in a group retiree medical insurance contract. The unobservable input included in the valuation of the contract includes the approach for determining the allocation of the postretirement benefit plans pro-rata share of the total assets in the contract.
The following table summarizes the postretirement benefit plans investments that are measured at fair value on a recurring basis using significant unobservable inputs (Level 3).
Medicare Prescription Drug, Improvement and Modernization Act of 2003
The Medicare Prescription Drug, Improvement and Modernization Act of 2003 expanded coverage for prescription drugs. The following table summarizes the gross benefit payments OG&E expects to pay related to its postretirement benefit plans, including prescription drug benefits.
The following table summarizes the benefit payments OG&E expects to pay related to its Pension Plan and Restoration of Retirement Income Plan. These expected benefits are based on the same assumptions used to measure OGE Energy's benefit obligation at the end of the year and include benefits attributable to estimated future employee service.
Post-Employment Benefit Plan
Disabled employees receiving benefits from OGE Energy's Group Long-Term Disability Plan are entitled to continue participating in OGE Energy's Medical Plan along with their dependents. The post-employment benefit obligation represents the actuarial present value of estimated future medical benefits that are attributed to employee service rendered prior to the date as of which such information is presented. The obligation also includes future medical benefits expected to be paid to current employees participating in OGE Energy's Group Long-Term Disability Plan and their dependents, as defined in OGE Energy's Medical Plan.
The post-employment benefit obligation is determined by an actuary on a basis similar to the accumulated postretirement benefit obligation. The estimated future medical benefits are projected to grow with expected future medical cost trend rates and are discounted for interest at the discount rate and for the probability that the participant will discontinue receiving benefits from
OGE Energy's Group Long-Term Disability Plan due to death, recovery from disability, or eligibility for retiree medical benefits. OG&E's post-employment benefit obligation was $1.1 million and $1.4 million at December 31, 2014 and 2013, respectively.
401(k) Plan
OGE Energy provides a 401(k) Plan. Each regular full-time employee of OGE Energy or a participating affiliate is eligible to participate in the 401(k) Plan immediately. All other employees of OGE Energy or a participating affiliate are eligible to become participants in the 401(k) Plan after completing one year of service as defined in the 401(k) Plan. Participants may contribute each pay period any whole percentage between two percent and 19 percent of their compensation, as defined in the 401(k) Plan, for that pay period. Participants who have attained age 50 before the close of a year are allowed to make additional contributions referred to as "Catch-Up Contributions," subject to certain limitations of the Code. Participants may designate, at their discretion, all or any portion of their contributions as: (i) a before-tax contribution under Section 401(k) of the Code subject to the limitations thereof; or (ii) a contribution made on an after-tax basis. The 401(k) Plan also includes an eligible automatic contribution arrangement and provides for a qualified default investment alternative consistent with the U.S. Department of Labor regulations. Participants may elect, in accordance with the 401(k) Plan procedures, to have his or her future salary deferral rate to be automatically increased annually on a date and in an amount as specified by the participant in such election. For employees hired or rehired on or after December 1, 2009, OGE Energy contributes to the 401(k) Plan, on behalf of each participant, 200 percent of the participant's contributions up to five percent of compensation.
No OGE Energy contributions are made with respect to a participant's Catch-Up Contributions, rollover contributions, or with respect to a participant's contributions based on overtime payments, pay-in-lieu of overtime for exempt personnel, special lump-sum recognition awards and lump-sum merit awards included in compensation for determining the amount of participant contributions. Once made, OGE Energy's contribution may be directed to any available investment option in the 401(k) Plan. OGE Energy match contributions vest over a three-year period. After two years of service, participants become 20 percent vested in their OGE Energy contribution account and become fully vested on completing three years of service. In addition, participants fully vest when they are eligible for normal or early retirement under the Pension Plan, in the event of their termination due to death or permanent disability or upon attainment of age 65 while employed by OGE Energy or its affiliates. OG&E contributed $8.2 million, $7.8 million and $7.6 million in 2014, 2013 and 2012, respectively, to the 401(k) Plan.
Deferred Compensation Plan
OGE Energy provides a nonqualified deferred compensation plan which is intended to be an unfunded plan. The plan's primary purpose is to provide a tax-deferred capital accumulation vehicle for a select group of management, highly compensated employees and non-employee members of the Board of Directors of OGE Energy and to supplement such employees' 401(k) Plan contributions as well as offering this plan to be competitive in the marketplace.
Eligible employees who enroll in the plan have the following deferral options: (i) eligible employees may elect to defer up to a maximum of 70 percent of base salary and 100 percent of annual bonus awards or (ii) eligible employees may elect a deferral percentage of base salary and bonus awards based on the deferral percentage elected for a year under the 401(k) Plan with such deferrals to start when maximum deferrals to the qualified 401(k) Plan have been made because of limitations in that plan. Eligible directors who enroll in the plan may elect to defer up to a maximum of 100 percent of directors' meeting fees and annual retainers. OGE Energy matches employee (but not non-employee director) deferrals to make up for any match lost in the 401(k) Plan because of deferrals to the deferred compensation plan, and to allow for a match that would have been made under the 401(k) Plan on that portion of either the first six percent of total compensation or the first five percent of total compensation, depending on prior participant elections, deferred that exceeds the limits allowed in the 401(k) Plan. Matching credits vest based on years of service, with full vesting after three years or, if earlier, on retirement, disability, death, a change in control of OGE Energy or termination of the plan. Deferrals, plus any OGE Energy match, are credited to a recordkeeping account in the participant's name. Earnings on the deferrals are indexed to the assumed investment funds selected by the participant. In 2014, those investment options included an OGE Energy Common Stock fund, whose value was determined based on the stock price of OGE Energy's Common Stock.
Supplemental Executive Retirement Plan
OGE Energy provides a supplemental executive retirement plan in order to attract and retain lateral hires or other executives designated by the Compensation Committee of OGE Energy's Board of Directors who may not otherwise qualify for a sufficient level of benefits under OGE Energy's Pension Plan and Restoration of Retirement Income Plan. The supplemental executive retirement plan is intended to be an unfunded plan and not subject to the benefit limitations of the Code.
12.
Commitments and Contingencies
Operating Lease Obligations
OG&E has operating lease obligations expiring at various dates, primarily for railcar leases and wind farm land leases. Future minimum payments for noncancellable operating leases are as follows:
Payments for operating lease obligations were $5.9 million, $5.7 million and $5.8 million for the years ended December 31, 2014, 2013 and 2012, respectively.
Railcar Lease Agreement
OG&E has a noncancellable operating lease with purchase options, covering 1,387 coal rotary gondola railcars to transport coal from Wyoming to OG&E's coal-fired generation units. Rental payments are charged to Fuel Expense and are recovered through OG&E's tariffs and fuel adjustment clauses. On December 15, 2010, OG&E renewed the lease agreement effective February 1, 2011. At the end of the new lease term, which is February 1, 2016, OG&E has the option to either purchase the railcars at a stipulated fair market value or renew the lease. If OG&E chooses not to purchase the railcars or renew the lease agreement and the actual fair value of the railcars is less than the stipulated fair market value, OG&E would be responsible for the difference in those values up to a maximum of $22.8 million. OG&E is also required to maintain all of the railcars it has under the operating lease and has entered into an agreement with a non-affiliated company to furnish this maintenance.
On January 11, 2012, OG&E executed a five-year lease agreement for 135 railcars to replace railcars that have been taken out of service or destroyed. OG&E has a unilateral right to terminate this lease upon a 6-month notice effective April 2016.
On October 14, 2014, OG&E signed a three-year lease effective beginning December 2014 for 131 railcars to replace railcars that have been taken out of service or destroyed.
Wind Farm Land Lease Agreements
OG&E has wind farm land operating leases for its Centennial, OU Spirit and Crossroads wind farms expiring at various dates. The Centennial lease has rent escalations which increase annually based on the Consumer Price Index. The OU Spirit and Crossroads leases have rent escalations which increase after five and 10 years. Although the leases are cancellable, OG&E is required to make annual lease payments as long as the wind turbines are located on the land. OG&E does not expect to terminate the leases until the wind turbines reach the end of their economic life.
Other Purchase Obligations and Commitments
OG&E's other future purchase obligations and commitments estimated for the next five years are as follows:
Public Utility Regulatory Policy Act of 1978
At December 31, 2014, OG&E has QF contracts having terms of 15 to 32 years. These contracts were entered into pursuant to the Public Utility Regulatory Policy Act of 1978. Stated generally, the Public Utility Regulatory Policy Act of 1978 and the regulations thereunder promulgated by the FERC require OG&E to purchase power generated in a manufacturing process from a QF. The rate for such power to be paid by OG&E was approved by the OCC. The rate generally consists of two components: one is a rate for actual electricity purchased from the QF by OG&E; the other is a capacity charge, which OG&E must pay the QF for having the capacity available. However, if no electrical power is made available to OG&E for a period of time (generally three months), OG&E's obligation to pay the capacity charge is suspended. The total cost of cogeneration payments is recoverable in rates from customers. For the 320 MW AES-Shady Point, Inc. QF contract and the 120 MW Oklahoma Cogeneration, LLC QF contract, OG&E purchases 100 percent of the electricity generated by the QFs.
For the years ended December 31, 2014, 2013 and 2012, OG&E made total payments to cogenerators of $129.4 million, $134.8 million and $135.1 million, respectively, of which $72.3 million, $74.4 million and $77.1 million, respectively, represented capacity payments. All payments for purchased power, including cogeneration, are included in the Statements of Income as Cost of Sales.
Minimum Fuel Purchase Commitments
OG&E purchased necessary fuel supplies of coal and natural gas for its generating units of $625.8 million, $680.8 million and $653.7 million for the years ended December 31, 2014, 2013 and 2012, respectively. OG&E has coal contracts for purchases through December 2016. As a participant in the SPP integrated marketplace, OG&E now purchases a relatively small percentage of its supply through term gas agreements. Alternatively, OG&E relies on a combination of call natural gas agreements, whereby OG&E has the right but not the obligation to purchase a defined quantity of natural gas, combined with day and intra-day purchases to meet the demands of the SPP market.
Wind Purchase Commitments
OG&E's current wind power portfolio includes the following, in addition to the 120 MW Centennial, 101 MW OU Spirit and 227.5 MW Crossroads wind farms owned by OG&E: (i) access to up to 50 MWs of electricity generated at a wind farm near Woodward, Oklahoma from a 15-year contract OG&E entered into with FPL Energy that expires in 2018, (ii) access to up to 152 MWs of electricity generated at a wind farm in Woodward County, Oklahoma from a 20-year contract OG&E entered into with CPV Keenan that expires in 2030, (iii) access to up to 130 MWs of electricity generated at a wind farm in Dewey County, Oklahoma from a 20-year contract OG&E entered into with Edison Mission Energy that expires in 2030 and (iv) access to up to 60 MWs of electricity generated at a wind farm near Blackwell, Oklahoma from a 20-year contract OG&E entered into with NextEra Energy that expires in 2032.
The following table summarizes OG&E's wind power purchases for the years ended December 31, 2014, 2013 and 2012.
Long-Term Service Agreement Commitments
OG&E has a long-term parts and service maintenance contract for the upkeep of the McClain Plant. The previous contract expired on January 1, 2015. The current contract, which was signed in May 2013, is expected to run for the earlier of 128,000 factored-fired hours or 3,600 factored-fired starts. Based on historical usage and current expectations for future usage, this contract is expected to run until 2030. The contract requires payments based on both a fixed and variable cost component, depending on how much the McClain Plant is used.
OG&E has a long-term parts and service maintenance contract for the upkeep of the Redbud Plant. In March 2013, the contract was amended to extend the contract coverage for an additional 24,000 factored-fired hours resulting in a maximum of the earlier of 144,000 factored-fired hours or 4,500 factored-fired starts. Based on historical usage and current expectations for
future usage, this contract is expected to run until 2031. The contract requires payments based on both a fixed and variable cost component, depending on how much the Redbud Plant is used.
Enable Gas Transportation and Storage Agreement
OG&E contracts with Enable for gas transportation and storage services. The stated term of this contract expired April 30, 2009, but remained in effect from year-to-year thereafter. On January 31, 2014, in anticipation of entering into a new, five-year contract, OG&E provided written notice of termination of the contract, effective April 30, 2014. On March 17, 2014, OG&E entered into a new five year firm no-notice load following gas transportation contract with Enable effective May 1, 2014.
Environmental Laws and Regulations
The activities of OG&E are subject to numerous, stringent and complex Federal, state and local laws and regulations governing environmental protection. These laws and regulations can change, restrict or otherwise impact OG&E's business activities in many ways including the handling or disposal of waste material, future construction activities to avoid or mitigate harm to threatened or endangered species and requiring the installation and operation of emissions pollution control equipment. Failure to comply with these laws and regulations could result in the assessment of administrative, civil and criminal penalties, the imposition of remedial requirements and the issuance of orders enjoining future operations. OG&E believes that its operations are in substantial compliance with current Federal, state and local environmental standards.
Environmental regulation can increase the cost of planning, design, initial installation and operation of OG&E's facilities. Historically, OG&E's total expenditures for environmental control facilities and for remediation have not been significant in relation to its financial position or results of operations. OG&E believes, however, that it is reasonably likely that the trend in environmental legislation and regulations will continue towards more restrictive standards. Compliance with these standards is expected to increase the cost of conducting business. Management continues to evaluate its compliance with existing and proposed environmental legislation and regulations and implement appropriate environmental programs in a competitive market.
OG&E is managing several significant uncertainties about the scope and timing for the acquisition, installation and operation of additional pollution control equipment and compliance costs for a variety of the EPA rules that are being challenged in court. OG&E is unable to predict the financial impact of these matters with certainty at this time.
Federal Clean Air Act New Source Review Litigation
As previously reported, in July 2008, OG&E received a request for information from the EPA regarding Federal Clean Air Act compliance at OG&E's Muskogee and Sooner generating plants.
On July 8, 2013, the Department of Justice filed a complaint against OG&E in United States District Court for the Western District of Oklahoma alleging that OG&E did not follow the Federal Clean Air Act procedures for projecting emission increases attributable to eight projects that occurred between 2003 and 2006. This complaint seeks to have OG&E submit a new assessment of whether the projects were likely to result in a significant emissions increase. The Sierra Club intervened in this proceeding. On August 30, 2013, the Government filed a Motion for Summary Judgment and on September 6, 2013, OG&E filed a Motion to Dismiss the case. On January 15, 2015, U.S. District Judge Timothy DeGuisti dismissed the complaints filed by EPA and Sierra Club. The Court held that it lacked subject matter jurisdiction over Plaintiffs’ claims because Plaintiffs failed to present an actual “case or controversy” as required by Article III of the Constitution. The court also ruled in the alternative that, even if Plaintiffs had presented a case or controversy, it would have nonetheless “decline[d] to exercise jurisdiction.” EPA and the Sierra Club have until March 16, 2015 to file an appeal of the Court’s ruling.
On August 12, 2013, the Sierra Club filed a separate complaint against OG&E in the United States District Court for the Eastern District of Oklahoma alleging that OG&E projects at Muskogee Unit 6 in 2008 were made without obtaining a prevention of significant deterioration permit and that the plant had exceeded emissions limits for opacity and particulate matter. The Sierra Club seeks a permanent injunction preventing OG&E from operating the Muskogee generating plant. On March 4, 2014, the Eastern District dismissed the prevention of significant deterioration permit claim based on the statute of limitations, but allowed the opacity and particulate matter claims to proceed. To obtain the right to appeal this decision, the Sierra Club subsequently withdrew a Notice of Intent to Sue for additional Clean Air Act violations and asked the Eastern District to dismiss its remaining claims with prejudice. On August 27, 2014, the Eastern District granted the Sierra Club's request. The Sierra Club has filed a Notice of Appeal with the 10th Circuit where oral argument is currently scheduled for March 18, 2015.
At this time, OG&E continues to believe that it has acted in compliance with the Federal Clean Air Act, and OG&E expects to vigorously defend against the claims that have been asserted. If OG&E does not prevail in the remainder of the
proceedings, the EPA and the Sierra Club could seek to require OG&E to install additional pollution control equipment, including scrubbers, baghouses and selective catalytic reduction systems with capital costs in excess of $1.1 billion and pay fines and significant penalties as a result of the allegations in the notice of violation. Section 113 of the Federal Clean Air Act (along with the Federal Civil Penalties Inflation Adjustment Act of 1996) provides for civil penalties as much as $37,500 per day for each violation. Due to the uncertain and preliminary nature of this litigation, OG&E cannot provide a range of reasonably possible loss in this case.
Air Quality Control System
On September 10, 2014, OG&E executed a contract for the design, engineering and fabrication of two circulating dry scrubber systems to be installed at Sooner Units 1 and 2. OG&E entered into an agreement on February 9, 2015, to install the scrubber systems. The scrubbers are part of OG&E’s Environmental Compliance Plan and scheduled to be completed by 2019. More detail regarding the Environmental Plan can be found under the “Pending Regulatory Matters” in Note 13.
Other
In the normal course of business, OG&E is confronted with issues or events that may result in a contingent liability. These generally relate to lawsuits or claims made by third parties, including governmental agencies. When appropriate, management consults with legal counsel and other appropriate experts to assess the claim. If, in management's opinion, OG&E has incurred a probable loss as set forth by GAAP, an estimate is made of the loss and the appropriate accounting entries are reflected in OG&E's Financial Statements. At the present time, based on currently available information, OG&E believes that any reasonably possible losses in excess of accrued amounts arising out of pending or threatened lawsuits or claims would not be quantitatively material to its financial statements and would not have a material adverse effect on OG&E's financial position, results of operations or cash flows.
13.
Rate Matters and Regulation
Regulation and Rates
OG&E's retail electric tariffs are regulated by the OCC in Oklahoma and by the APSC in Arkansas. The issuance of certain securities by OG&E is also regulated by the OCC and the APSC. OG&E's wholesale electric tariffs, transmission activities, short-term borrowing authorization and accounting practices are subject to the jurisdiction of the FERC. The Secretary of the U.S. Department of Energy has jurisdiction over some of OG&E's facilities and operations. In 2014, 84 percent of OG&E's electric revenue was subject to the jurisdiction of the OCC, eight percent to the APSC and eight percent to the FERC.
The OCC issued an order in 1996 authorizing OG&E to reorganize into a subsidiary of OGE Energy. The order required that, among other things, (i) OGE Energy permit the OCC access to the books and records of OGE Energy and its affiliates relating to transactions with OG&E, (ii) OGE Energy employ accounting and other procedures and controls to protect against subsidization of non-utility activities by OG&E's customers and (iii) OGE Energy refrain from pledging OG&E assets or income for affiliate transactions. In addition, the Energy Policy Act of 2005 enacted the Public Utility Holding Company Act of 2005, which in turn granted to the FERC access to the books and records of OGE Energy and its affiliates as the FERC deems relevant to costs incurred by OG&E or necessary or appropriate for the protection of utility customers with respect to the FERC jurisdictional rates.
Completed Regulatory Matters
Market-Based Rate Authority
On June 29, 2012, OG&E filed its triennial market power update with the FERC to retain its market-based rate authorization in the SPP's energy imbalance service market but to surrender its market-based rate authorization for any market-based rates sales outside of the SPP's energy imbalance service market. On May 2, 2013, the FERC issued an order accepting OG&E's June 2012 triennial market power update.
On December 30, 2013, OG&E submitted to the FERC a market-based rate change in status filing and a revised market-based rate tariff that would authorize OG&E to (i) sell electric energy and capacity at market-based rates without geographic restriction, and (ii) sell ancillary services in the SPP and Midcontinent Independent System Operator, Inc. markets. The primary goal of this filing was to implement the market-based rate authority OG&E needs to fully participate in SPP’s Integrated Marketplace. On February 28, 2014, FERC issued a letter order accepting OG&E’s market-based rate filing and tariff effective March 1, 2014. FERC found that OG&E passed the market power screens and satisfied requirements related to horizontal market power and vertical market power.
Section 206 Complaint
On November 26, 2013, Arkansas Electric Cooperative Corporation filed a complaint at the FERC against OG&E, arguing that the wholesale formula rate contract between OG&E and Arkansas Electric Cooperative Corporation (formerly between OG&E and Arkansas Valley Electric Cooperative) is unjust and unreasonable with respect to several items. OG&E and Arkansas Electric Cooperative Corporation agreed to terms of a settlement and filed the offer of settlement with the FERC on February 24, 2014. On April 17, 2014, the FERC accepted the settlement making it effective March 1, 2014. The reduction in revenue for 2014 was $0.9 million.
Fuel Adjustment Clause Review for Calendar Year 2012
The OCC routinely reviews the costs recovered from customers through OG&E's fuel adjustment clause. On July 31, 2013, the OCC Staff filed an application to review OG&E's fuel adjustment clause for calendar year 2012, including the prudence of OG&E's electric generation, purchased power and fuel procurement costs. OG&E filed the necessary information and documents needed to satisfy the OCC's minimum filing requirement rules on October 9, 2013. On April 24, 2014, the OCC administrative law judge at the hearing, on the merits, recommended that the OCC find that OG&E's 2012 electric generation, purchased power and fuel procurement processes and costs were prudent. On June 10, 2014, the OCC issued an order approving OG&E’s practices, policies and judgment regarding its electric generation, purchased power, and fuel procurement processes and costs for the calendar year 2012. The order also found that the costs were prudent, reasonable, and mathematically correct.
Integrated Resource Plans
In June 2014, OG&E initiated the process to update its Integrated Resource Plans in Oklahoma and Arkansas at OG&E's discretion. The prior Integrated Resource Plan, submitted in 2012, assumed that the Oklahoma SIP would be followed to comply with Regional Haze requirements. Subsequent to holding technical conferences and public stakeholder meetings, OG&E submitted its revised Integrated Resource Plans, which included its environmental compliance plan described below, to the OCC on August 4, 2014 and to the APSC on September 8, 2014.
Pending Regulatory Matters
FERC Order No. 1000, Final Rule on Transmission Planning and Cost Allocation
On July 21, 2011, the FERC issued Order No. 1000, which revised the FERC's existing regulations governing the process for planning enhancements and expansions of the electric transmission grid in a particular region, along with the corresponding process for allocating the costs of such expansions. Order No. 1000 leaves to individual regions to determine whether a previously-approved project is subject to reevaluation and is therefore governed by the new rule.
Order No. 1000 requires, among other things, public utility transmission providers, such as the SPP, to participate in a process that produces a regional transmission plan satisfying certain standards, and requires that each such regional process consider transmission needs driven by public policy requirements (such as state or Federal policies favoring increased use of renewable energy resources). Order No. 1000 also directs public utility transmission providers to coordinate with neighboring transmission planning regions. In addition, Order No. 1000 establishes specific regional cost allocation principles and directs public utility transmission providers to participate in regional and interregional transmission planning processes that satisfy these principles.
On the issue of determining how entities are to be selected to develop and construct the specific transmission projects, Order No. 1000 directs public utility transmission providers to remove from the FERC-jurisdictional tariffs and agreements provisions that establish any Federal "right of first refusal" for the incumbent transmission owner (such as OG&E) regarding transmission facilities selected in a regional transmission planning process, subject to certain limitations. However, Order No. 1000 is not intended to affect the right of an incumbent transmission owner (such as OG&E) to build, own and recover costs for upgrades to its own transmission facilities, and Order No. 1000 does not alter an incumbent transmission owner's use and control of existing rights of way. Order No. 1000 also clarifies that incumbent transmission owners may rely on regional transmission facilities to meet their reliability needs or service obligations. The SPP's pre-Order No. 1000 tariff included a "right of first refusal" for incumbent transmission owners and this provision has played a role in OG&E being selected by the SPP to build previous transmission projects in Oklahoma. These changes to the "right of first refusal" apply only to "new transmission facilities," which are facilities subject to evaluation or reevaluation (under the applicable local or regional transmission planning process) after November 13, 2012. On May 29, 2013, the Governor signed House Bill 1932 into law which establishes a right of first refusal for Oklahoma incumbent transmission owners, including OG&E, to build new transmission projects with voltages under 300 kilovolts that interconnect to those incumbent owners' existing facilities. OG&E believes this law is consistent with the language
of Order No. 1000. On August 15, 2014, the U.S. Court of Appeals for the D.C. Circuit issued an order denying all appeals of Order No. 1000.
The FERC has issued two orders on the SPP's Order No. 1000 compliance filings. In its most recent order, issued October 16, 2014, the FERC confirmed that “right of first refusal” language should be removed from the SPP tariff and Membership Agreement as applied to most transmission facilities, but that several types of facilities would remain subject to a right of first refusal. Projects that retained the right of first refusal included facilities that would operate below 100 kilovolts, facilities selected as part of the SPP’s Aggregate Study process, and short-term reliability projects. The FERC also approved SPP’s new competitive solicitation process for projects that are not subject to a right of first refusal. FERC found that SPP may consider state and local laws and regulations when deciding whether SPP will hold a competitive solicitation for a proposed project. On December 15, 2014, OG&E filed an appeal in the District of Columbia Circuit Court of Appeals of a portion of the October 2014 FERC order requiring removal of the right of first refusal language from the Membership Agreement. The court has not yet acted on OG&E's appeal.
OGE Energy cannot, at this time, determine the precise impact of Order No. 1000 on OG&E. OGE Energy has no reason to believe that the implementation of Order No. 1000 will impact OG&E's transmission projects currently under development and construction for which OG&E has received a notice to proceed from the SPP.
Energy Efficiency Program Filing
On February 14, 2014, OG&E filed an application with the APSC requesting approval of interim modifications to approved Energy Efficiency Programs, new tariff revisions and the waiver of certain provisions of the Commission’s Rules for Conservation and Energy Efficiency Programs.
Environmental Compliance Plan
On August 6, 2014, OG&E filed an application with the OCC for approval of its plan to comply with EPA’s MATS and Regional Haze FIP while serving the best long-term interests of customers in light of future environmental uncertainties. The application seeks approval of the environmental compliance plan and for a recovery mechanism for the associated costs. The environmental compliance plan includes installing dry scrubbers at Sooner Units 1 and 2 and the conversion of Muskogee Units 4 and 5 to natural gas. The application also asks the Commission to predetermine the prudence of replacing OG&E's soon-to-be retired Mustang steam turbines in late 2017 (approximately 460 MW) with 400 MW of new, efficient combustion turbines at the Mustang site in 2018 and 2019 and approval for a recovery mechanism for the associated costs. OG&E estimates the total capital cost associated with its environmental compliance plan included in this application to be approximately $1.1 billion. The OCC hearing on OG&E's application is scheduled to commence on March 3, 2015. Multiple parties advocating a variety of positions have intervened in the proceeding. OG&E expects a ruling from the OCC in the second quarter of 2015. At this time, OG&E cannot predict the outcome of the proceeding. OG&E plans to file applications in the first quarter of 2015 seeking related approvals from the APSC.
Fuel Adjustment Clause Review for Calendar Year 2013
The OCC routinely reviews the costs recovered from customers through OG&E's fuel adjustment clause. On July 31, 2014, the OCC Staff filed an application to review OG&E's fuel adjustment clause for calendar year 2013, including the prudence of OG&E's electric generation, purchased power and fuel procurement costs. OG&E filed the necessary information and documents needed to satisfy the OCC's minimum filing requirement rules on September 29, 2014. A procedural schedule has not been established as of this date. OG&E expects an order in the second quarter of 2015.
14.
Quarterly Financial Data (Unaudited)
Due to the seasonal fluctuations and other factors of OG&E's business, the operating results for interim periods are not necessarily indicative of the results that may be expected for the year. In OG&E's opinion, the following quarterly financial data includes all adjustments, consisting of normal recurring adjustments, necessary to fairly present such amounts. Summarized quarterly unaudited financial data is as follows:
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Stockholder
Oklahoma Gas and Electric Company
We have audited the accompanying balance sheets and statements of capitalization of Oklahoma Gas and Electric Company as of December 31, 2014 and 2013, and the related statements of income, comprehensive income, cash flows and changes in stockholder's equity for each of the three years in the period ended December 31, 2014. Our audits also included the financial statement schedule listed in the Index at Item 15(a). These financial statements and schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.
We 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 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 Oklahoma Gas and Electric Company at December 31, 2014 and 2013, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2014, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Oklahoma Gas and Electric Company's internal control over financial reporting as of December 31, 2014, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) and our report dated February 26, 2015 expressed an unqualified opinion thereon.
Oklahoma City, Oklahoma
February 26, 2015
Item 9.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.
None.
Item 9A.
Item 9A. Controls and Procedures.
OG&E maintains a set of disclosure controls and procedures designed to ensure that information required to be disclosed by OG&E in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission rules and forms. In addition, the disclosure controls and procedures ensure that information required to be disclosed is accumulated and communicated to management, including the chief executive officer and chief financial officer, allowing timely decisions regarding required disclosure. As of the end of the period covered by this report, based on an evaluation carried out under the supervision and with the participation of OG&E's management, including the chief executive officer and chief financial officer, of the effectiveness of OG&E's disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15(d)-15(e) under the Securities Exchange Act of 1934), the chief executive officer and chief financial officer have concluded that OG&E's disclosure controls and procedures are effective.
No change in OG&E's internal control over financial reporting has occurred during OG&E's most recently completed fiscal quarter that has materially affected, or is reasonably likely to materially affect, OG&E's internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934).
Management's Report on Internal Control Over Financial Reporting
The management of OG&E is responsible for establishing and maintaining adequate internal control over financial reporting. OG&E's internal control system was designed to provide reasonable assurance to OG&E's management and Board of Directors regarding the preparation and fair presentation of published financial statements. All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.
OG&E management assessed the effectiveness of OG&E's internal control over financial reporting as of December 31, 2014. In making this assessment, it used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control-Integrated Framework (2013). Based on our assessment, we believe that, as of December 31, 2014,OG&E's internal control over financial reporting is effective based on those criteria.
OG&E's independent auditors have issued an attestation report on OG&E's internal control over financial reporting. This report appears on the following page.
/s/ Peter B. Delaney
/s/ Scott Forbes
Peter B. Delaney, Chairman of the Board
Scott Forbes, Controller
and Chief Executive Officer
and Chief Accounting Officer
/s/ Stephen Merrill
Stephen Merrill
Chief Financial Officer
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Stockholder
Oklahoma Gas and Electric Company
We have audited Oklahoma Gas and Electric Company's internal control over financial reporting as of December 31, 2014, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). Oklahoma Gas and Electric Company'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 the accompanying Management's Report on Internal Control Over Financial Reporting. 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 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, Oklahoma Gas and Electric Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2014, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the balance sheets and statements of capitalization of Oklahoma Gas and Electric Company as of December 31, 2014 and 2013, and the related statements of income, comprehensive income, cash flows and changes in stockholder's equity for each of the three years in the period ended December 31, 2014 of Oklahoma Gas and Electric Company and our report dated February 26, 2015 expressed an unqualified opinion thereon.
Oklahoma City, Oklahoma
February 26, 2015
Item 9B.
Item 9B. Other Information.
None.
PART III
Item 10.
Item 10. Directors, Executive Officers and Corporate Governance.
Code of Ethics Policy
OGE Energy maintains a code of ethics for our chief executive officer and senior financial officers, including the chief financial officer and chief accounting officer, which is available for public viewing on OGE Energy's web site address www.oge.com under the heading "Investor Relations", "Corporate Governance." The code of ethics will be provided, free of charge, upon request. OGE Energy intends to satisfy the disclosure requirements under Section 5, Item 5.05 of Form 8-K regarding an amendment to, or waiver from, a provision of the code of ethics by posting such information on its web site at the location specified above. OGE Energy will also include in its proxy statement information regarding the Audit Committee financial experts.
Under the reduced disclosure format permitted by General Instruction I(2)(c) of Form 10-K, the information otherwise required by Item 10 has been omitted.
Item 11.
Item 11. Executive Compensation.
Under the reduced disclosure format permitted by General Instruction I(2)(c) of Form 10-K, the information otherwise required by Item 11 has been omitted.
Item 12.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.
Under the reduced disclosure format permitted by General Instruction I(2)(c) of Form 10-K, the information otherwise required by Item 12 has been omitted.
Item 13.
Item 13. Certain Relationships and Related Transactions, and Director Independence.
Under the reduced disclosure format permitted by General Instruction I(2)(c) of Form 10-K, the information otherwise required by Item 13 has been omitted.
Item 14.
Item 14. Principal Accounting Fees and Services.
The following discussion relates to the audit fees paid by OGE Energy to its principal independent accountants for the services provided to OGE Energy and its subsidiaries, including OG&E
Fees for Principal Independent Accountants
(A)
Includes reviews of the financial statements included in OGE Energy's and OG&E's Quarterly Reports on Form 10-Q, audits of OGE Energy's subsidiaries, preparation for Audit Committee meetings and fees for consulting with OGE Energy's and OG&E's executives regarding accounting issues.
(B)
The aggregate audit fees include fees billed for the audit of OGE Energy's and OG&E's annual financial statements and for the reviews of the financial statements included in OGE Energy's and OG&E's Quarterly Reports on Form 10-Q. For 2014, this amount includes estimated billings for the completion of the 2014 audit, which services were rendered after year-end.
(C)
Includes the U.S. Department of Energy Smart Grid grant audits.
All Other Fees
There were no other fees billed by the principal independent accountants to OGE Energy in 2014 and 2013 for other services.
Audit Committee Pre-Approval Procedures
Rules adopted by the Securities and Exchange Commission in order to implement requirements of the Sarbanes-Oxley Act of 2002 require public company audit committees to pre-approve audit and non-audit services. OGE Energy's Audit Committee follows procedures pursuant to which audit, audit-related and tax services, and all permissible non-audit services are pre-approved by category of service. The fees are budgeted, and actual fees versus the budget are monitored throughout the year. During the year, circumstances may arise when it may become necessary to engage the principal independent accountants for additional services not contemplated in the original pre-approval. In those instances, OGE Energy will obtain the specific pre-approval of the Audit Committee before engaging the principal independent accountants. The procedures require the Audit Committee to be informed of each service, and the procedures do not include any delegation of the Audit Committee's responsibilities to management. The Audit Committee may delegate pre-approval authority to one or more of its members. The member to whom such authority is delegated will report any pre-approval decisions to the Audit Committee at its next scheduled meeting.
For 2014, 100 percent of the audit fees, audit-related fees and tax fees were pre-approved by the Audit Committee or the Chairman of the Audit Committee pursuant to delegated authority.
PART IV
Item 15.
Item 15. Exhibits, Financial Statement Schedules.
(a) 1. Financial Statements
The following Financial Statements are included in Part II, Item 8 of this Annual Report:
•
Statements of Income for the years ended December 31, 2014, 2013 and 2012
•
Statements of Comprehensive Income for the years ended December 31, 2014, 2013 and 2012
•
Statements of Cash Flows for the years ended December 31, 2014, 2013 and 2012
•
Balance Sheets at December 31, 2014 and 2013
•
Statements of Capitalization at December 31, 2014 and 2013
•
Statements of Changes in Stockholder's Equity for the years ended December 31, 2014, 2013 and 2012
•
Notes to Financial Statements
•
Report of Independent Registered Public Accounting Firm (Audit of Financial Statements)
•
Management's Report on Internal Control Over Financial Reporting
•
Report of Independent Registered Public Accounting Firm (Audit of Internal Control)
2. Financial Statement Schedule (included in Part IV)
•
Schedule II - Valuation and Qualifying Accounts
All other schedules have been omitted since the required information is not applicable or is not material, or because the information required is included in the respective Financial Statements or Notes thereto.
3. Exhibits
OKLAHOMA GAS AND ELECTRIC COMPANY
SCHEDULE II - Valuation and Qualifying Accounts
(A)
Uncollectible accounts receivable written off, net of recoveries.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, as amended, the Registrant has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Oklahoma City, and State of Oklahoma on the 26th day of February, 2015.
OKLAHOMA GAS AND ELECTRIC COMPANY
(Registrant)
By /s/
Peter B. Delaney
Peter B. Delaney
Chairman of the Board, President
and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, as amended, this Report has been signed below by the following persons on behalf of the Registrant in the capacities and on the dates indicated.
Signature
Title
Date
/s/ Peter B. Delaney
Peter B. Delaney
Principal Executive
Officer and Director;
February 26, 2015
/s/ Stephen Merrill
Stephen Merrill
Principal Financial Officer;
February 26, 2015
/s/ Scott Forbes
Scott Forbes
Principal Accounting Officer.
February 26, 2015
James H. Brandi
Director;
Wayne H. Brunetti
Director;
Luke R. Corbett
Director;
John D. Groendyke
Director;
Kirk Humphreys
Director;
Robert Kelley
Director;
Robert O. Lorenz
Director;
Judy R. McReynolds
Director;
Sheila G. Talton
Director;
Supplemental Information to Be Furnished With Reports Filed Pursuant to Section 15(d) of the Act by Registrants Which Have Not Registered Securities Pursuant to Section 12 of the Act.
The Registrant has not sent, and does not expect to send, an annual report or proxy statement to its security holders.