UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
S ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2012
OR
£ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from _____to_____
Commission File Number: 1-1097
OKLAHOMA GAS AND ELECTRIC COMPANY
(Exact name of registrant as specified in its charter)
Oklahoma | 73-0382390 | |
(State or other jurisdiction of | (I.R.S. Employer | |
incorporation or organization) | Identification No.) |
321 North Harvey
P.O. Box 321
Oklahoma City, Oklahoma 73101-0321
(Address of principal executive offices)
(Zip Code)
Registrant's telephone number, including area code: 405-553-3000
Securities registered pursuant to Section 12(b) of the Act: None
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
£ Yes R No
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act.£ Yes R No
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. R Yes £ No
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). R Yes £ No
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. R
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.
Large accelerated filer o | Accelerated filer o |
Non-accelerated filer R (Do not check if a smaller reporting company) | Smaller reporting company o |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). £ Yes R No
At June 29, 2012, the last business day of the registrant's most recently completed second fiscal quarter, the aggregate market value of shares of common stock held by non-affiliates was $0. As of such date, 40,378,745 shares of common stock, par value $2.50 per share, were outstanding, all of which were held by OGE Energy Corp.
At January 31, 2013, there were 40,378,745 shares of common stock, par value $2.50 per share, outstanding, all of which were held by OGE Energy Corp. There were no other shares of capital stock of the registrant outstanding at such date.
DOCUMENTS INCORPORATED BY REFERENCE
None
Oklahoma Gas and Electric Company meets the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K and is therefore filing this form with the reduced disclosure format permitted by General Instruction I(2).
OKLAHOMA GAS AND ELECTRIC COMPANY
FORM 10-K
FOR THE YEAR ENDED DECEMBER 31, 2012
TABLE OF CONTENTS
Page | |
Part I | |
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GLOSSARY OF TERMS
The following is a glossary of frequently used abbreviations that are found throughout this Form 10-K.
Abbreviation | Definition |
401(k) Plan | Qualified defined contribution retirement plan |
APSC | Arkansas Public Service Commission |
BART | Best available retrofit technology |
Code | Internal Revenue Code of 1986 |
Dodd-Frank Act | Dodd-Frank Wall Street Reform and Consumer Protection Act |
Dry Scrubbers | Dry flue gas desulfurization units with spray dryer absorber |
Enogex | Enogex Holdings LLC, collectively with its subsidiaries, a majority-owned subsidiary of OGE Energy |
EPA | U.S. Environmental Protection Agency |
Federal Clean Water Act | Federal Water Pollution Control Act of 1972, as amended |
FERC | Federal Energy Regulatory Commission |
FIP | Federal implementation plan |
GAAP | Accounting principles generally accepted in the United States |
MATS | Mercury and Air Toxics Standards |
MMBtu | Million British thermal unit |
MW | Megawatt |
MWH | Megawatt-hour |
NAAQS | National Ambient Air Quality Standards |
NOX | Nitrogen oxide |
NYMEX | New York Mercantile Exchange |
OCC | Oklahoma Corporation Commission |
Off-system sales | Sales to other utilities and power marketers |
OG&E | Oklahoma Gas and Electric Company, wholly-owned subsidiary of OGE Energy |
OGE Energy | OGE Energy Corp., parent company of OG&E |
OSHA | Federal Occupational Safety and Health Act of 1970 |
Pension Plan | Qualified defined benefit retirement plan |
PRM | Price risk management |
QF | Qualified cogeneration facilities |
QF contracts | Contracts with QFs and small power production producers |
Restoration of Retirement Income Plan | Supplemental retirement plan to the Pension Plan |
SIP | State implementation plan |
SO2 | Sulfur dioxide |
SPP | Southwest Power Pool |
System sales | Sales to OG&E's customers |
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FORWARD-LOOKING STATEMENTS
Except for the historical statements contained herein, the matters discussed in this Form 10-K, including those matters discussed in "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations," are forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements are intended to be identified in this document by the words "anticipate", "believe", "estimate", "expect", "intend", "objective", "plan", "possible", "potential", "project" and similar expressions. Actual results may vary materially from those expressed in forward-looking statements. In addition to the specific risk factors discussed in "Item 1A. Risk Factors" and "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" herein, factors that could cause actual results to differ materially from the forward-looking statements include, but are not limited to:
• | general economic conditions, including the availability of credit, access to existing lines of credit, access to the commercial paper markets, actions of rating agencies and their impact on capital expenditures; |
• | the ability of OG&E and OGE Energy to access the capital markets and obtain financing on favorable terms as well as inflation rates and monetary fluctuations; |
• | prices and availability of electricity, coal and natural gas; |
• | business conditions in the energy industry; |
• | competitive factors including the extent and timing of the entry of additional competition in the markets served by OG&E; |
• | unusual weather; |
• | availability and prices of raw materials for current and future construction projects; |
• | Federal or state legislation and regulatory decisions and initiatives that affect cost and investment recovery, have an impact on rate structures or affect the speed and degree to which competition enters OG&E's markets; |
• | environmental laws and regulations that may impact OG&E's operations; |
• | changes in accounting standards, rules or guidelines; |
• | the discontinuance of accounting principles for certain types of rate-regulated activities; |
• | the cost of protecting assets against, or damage due to, terrorism or cyber attacks and other catastrophic events; |
• | advances in technology; |
• | creditworthiness of suppliers, customers and other contractual parties and |
• | other risk factors listed in the reports filed by OG&E with the Securities and Exchange Commission including those listed in "Item 1A. Risk Factors" and in Exhibit 99.01 to this Form 10-K. |
OG&E undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.
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PART I
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 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. OGE Energy's corporate strategy is to continue to maintain its existing business mix and diversified asset position of its regulated electric utility business and unregulated natural gas midstream business while providing competitive energy products and services to customers primarily in the south central United States as well as seeking growth opportunities in both businesses.
OG&E is focused on increased investment to preserve system reliability and meet load growth by adding and maintaining infrastructure equipment and replacing aging transmission and distribution systems. OG&E expects to maintain a diverse generation portfolio while remaining environmentally responsible. OG&E is focused on maintaining strong regulatory and legislative relationships for the long-term benefit of its customers. In an effort to encourage more efficient use of electricity, OG&E is also providing energy management solutions to its customers through the Smart Grid program that utilizes newer technology to improve operational and environmental performance as well as allow customers to monitor and manage their energy usage, which should help reduce demand during critical peak times, resulting in lower capacity requirements. If these initiatives are successful, OG&E believes it may be able to defer the construction or acquisition of any incremental fossil fuel generation capacity until 2020. The Smart Grid program also provides benefits to OG&E, including more efficient use of its resources and access to increased information about customer usage, which should enable OG&E to have better distribution system planning data, better response to customer usage questions and faster detection and restoration of system outages. As the Smart Grid platform matures, OG&E anticipates providing new products and services to its customers. In addition, OG&E is also pursuing additional transmission-related opportunities within the SPP.
General
OG&E generates, transmits, distributes and sells electric energy in Oklahoma and western Arkansas. OG&E furnishes retail electric service in 268 communities and their contiguous rural and suburban areas. During 2012, one other community and 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 268 communities that OG&E serves, 242 are located in Oklahoma and 26 in Arkansas. OG&E derived 90 percent of its total electric operating revenues in 2012 from sales in Oklahoma and the remainder from sales in Arkansas.
OG&E's system control area peak demand in 2012 was 7,000 MWs on August 1, 2012. OG&E's load responsibility peak demand was 6,459 MWs on August 1, 2012. As reflected in the table below and in the operating statistics that follow, there were 28.0 million MWH system sales in 2012, 28.5 million MWH system sales in 2011 and 27.6 million MWH system sales in 2010. Variations in system sales for the three years are reflected in the following table:
Year ended December 31 | 2012 | 2012 vs. 2011 Decrease | 2011 | 2011 vs. 2010 Increase | 2010 |
System sales - millions of MWHs | 28.0 | (1.8)% | 28.5 | 3.3% | 27.6 |
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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.
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OKLAHOMA GAS AND ELECTRIC COMPANY | |||||||||
CERTAIN OPERATING STATISTICS | |||||||||
Year ended December 31 | 2012 | 2011 | 2010 | ||||||
ELECTRIC ENERGY (Millions of MWH) | |||||||||
Generation (exclusive of station use) | 26.3 | 26.7 | 25.6 | ||||||
Purchased | 5.0 | 4.9 | 4.7 | ||||||
Total generated and purchased | 31.3 | 31.6 | 30.3 | ||||||
OG&E use, free service and losses | (1.9 | ) | (2.1 | ) | (2.2 | ) | |||
Electric energy sold | 29.4 | 29.5 | 28.1 | ||||||
ELECTRIC ENERGY SOLD (Millions of MWH) | |||||||||
Residential | 9.1 | 9.9 | 9.6 | ||||||
Commercial | 7.0 | 6.9 | 6.7 | ||||||
Industrial | 4.0 | 3.9 | 3.8 | ||||||
Oilfield | 3.3 | 3.2 | 3.1 | ||||||
Public authorities and street light | 3.3 | 3.2 | 3.0 | ||||||
Sales for resale | 1.3 | 1.4 | 1.4 | ||||||
System sales | 28.0 | 28.5 | 27.6 | ||||||
Off-system sales | 1.4 | 1.0 | 0.5 | ||||||
Total sales | 29.4 | 29.5 | 28.1 | ||||||
ELECTRIC OPERATING REVENUES (In millions) | |||||||||
Residential | $ | 878.0 | $ | 943.5 | $ | 894.8 | |||
Commercial | 523.5 | 531.3 | 521.0 | ||||||
Industrial | 206.8 | 216.0 | 212.5 | ||||||
Oilfield | 163.4 | 165.1 | 162.8 | ||||||
Public authorities and street light | 202.4 | 207.4 | 200.8 | ||||||
Sales for resale | 54.9 | 65.3 | 65.8 | ||||||
System sales revenues | 2,029.0 | 2,128.6 | 2,057.7 | ||||||
Off-system sales revenues | 36.5 | 36.2 | 21.7 | ||||||
Other | 75.7 | 46.7 | 30.5 | ||||||
Total operating revenues | $ | 2,141.2 | $ | 2,211.5 | $ | 2,109.9 | |||
ACTUAL NUMBER OF ELECTRIC CUSTOMERS (At end of period) | |||||||||
Residential | 683,214 | 675,806 | 670,309 | ||||||
Commercial | 88,772 | 87,480 | 86,496 | ||||||
Industrial | 2,957 | 2,991 | 3,020 | ||||||
Oilfield | 6,426 | 6,451 | 6,418 | ||||||
Public authorities and street light | 16,695 | 16,374 | 16,264 | ||||||
Sales for resale | 46 | 44 | 51 | ||||||
Total | 798,110 | 789,146 | 782,558 | ||||||
AVERAGE RESIDENTIAL CUSTOMER SALES | |||||||||
Average annual revenue | $ | 1,292.11 | $ | 1,401.84 | $ | 1,339.81 | |||
Average annual use (kilowatt-hour) | 13,477 | 14,738 | 14,304 | ||||||
Average price per kilowatt-hour (cents) | $ | 9.59 | $ | 9.51 | $ | 9.37 |
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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 2012, 87 percent of OG&E's electric revenue was subject to the jurisdiction of the OCC, eight percent to the APSC and five 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
Contract and Wind Energy Purchase Agreement Filing
On December 1, 2011, OG&E filed an application with the OCC requesting approval of a 20-year agreement that is intended to provide wind power to help meet the current and future power generation needs of Oklahoma State University. The project called for OG&E to contract with NextEra Energy to build a 60 MW wind farm near Blackwell, Oklahoma, to support the Oklahoma State University project in which NextEra Energy built, owns and operates the wind farm and OG&E purchases the electric output. On February 22, 2012, OG&E, the Attorney General and the Public Utility Division of the OCC signed a settlement agreement whereby the stipulating parties requested that the OCC issue an order approving the agreement for electric service with Oklahoma State University. On March 12, 2012, OG&E received an order from the OCC approving the settlement agreement. Pursuant to the terms of the power purchase agreement between OG&E and NextEra Energy, OG&E has been purchasing the electric output of the wind farm since November 2012 and uses that power to provide service to Oklahoma State University and its other retail customers. The wind farm was fully in service in December 2012.
SPP Transmission Projects
The SPP is a regional transmission organization under the jurisdiction of the FERC that was created to ensure reliable supplies of power, adequate transmission infrastructure and competitive wholesale prices of electricity. The SPP does not build transmission though the SPP's tariff contains rules that govern the transmission construction process. Transmission owners complete the construction and then own, operate and maintain transmission assets within the SPP region. When the SPP Board of Directors approves a project, the transmission provider in the area where the project is needed currently has the first obligation to build; however, the process for deciding which entity constructs and owns a project may change as a result of FERC Order. No. 1000 discussed below.
There are several studies currently under review at the SPP including a 20-year plan to address issues of regional and interregional importance. The 20-year plan suggests overlaying the SPP footprint with a 345 kilovolt transmission system and integrating it with neighboring regional entities. In 2009, the SPP Board of Directors approved a new report that recommended restructuring the SPP's regional planning processes to focus on the construction of a robust transmission system, large enough in both scale and geography, to provide flexibility to meet the SPP's future needs. OG&E expects to actively participate in the ongoing study, development and transmission growth that may result from the SPP's plans.
In 2007, the SPP notified OG&E to construct 44 miles of a new 345 kilovolt transmission line originating at OG&E's existing Sooner 345 kilovolt substation and proceeding generally in a northerly direction to the Oklahoma/Kansas Stateline (referred to as the Sooner-Rose Hill project). At the Oklahoma/Kansas Stateline, the line connects to the companion line constructed in Kansas by Westar Energy. The transmission line was placed in service in April 2012. The total capital expenditures associated with this project were $45 million.
In January 2009, OG&E received notification from the SPP to begin construction on 50 miles of a new 345 kilovolt transmission line and substation upgrades at OG&E's Sunnyside substation, among other projects. In April 2009, Western Farmers Electric Cooperative assigned to OG&E the construction of 50 miles of line designated by the SPP to be built by Western Farmers Electric Cooperative. The new line extends from OG&E's Sunnyside substation near Ardmore, Oklahoma, 123.5 miles to the
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Hugo substation owned by Western Farmers Electric Cooperative near Hugo, Oklahoma. The transmission line was completed in April 2012. The total capital expenditures associated with this project were $157 million.
As discussed below, the OCC approved a settlement agreement in OG&E's 2011 Oklahoma rate case filing that included an expedited procedure for recovering the costs of the two projects. On July 31, 2012, OG&E filed an application with the OCC requesting an order authorizing recovery for the two projects through the SPP transmission systems additions rider. On October 2, 2012, all parties signed a settlement agreement in this matter which stated: (i) the parties agree not to oppose requested relief sought by OG&E, (ii) OG&E will host meetings to discuss the SPP’s transmission planning process, including any future transmission projects for which OG&E has received a notice to construct from the SPP, and (iii) there will be opportunities for parties to provide input related to transmission planning studies that the SPP performs to identify future transmission projects. On October 25, 2012, the OCC issued an order approving the settlement agreement and granting OG&E cost recovery for the two projects. OG&E initiated cost recovery beginning with the first billing cycle in November 2012.
2011 Oklahoma Rate Case Filing
On July 28, 2011, OG&E filed its application with the OCC requesting an annual rate increase of $73.3 million, or a 4.3 percent increase in its rates. OG&E requested a return on equity of 11.0 percent based on a common equity percentage of 53.0 percent. In its application, OG&E requested recovery of increases in its operating costs and to begin earning on approximately $500 million of new capital investments made on behalf of its Oklahoma customers during the previous two and one-half years. On July 2, 2012, OG&E and other parties associated with its rate increase reached a settlement agreement in this matter. On July 9, 2012, the OCC issued an order approving the settlement agreement in this matter. Key terms of the settlement agreement included: (i) an annual net increase of approximately $4.3 million in OG&E's rates to its Oklahoma retail customers, (ii) OG&E's Oklahoma retail authorized return on equity of 10.2 percent, (iii) the rate of return under various recovery riders previously approved by the OCC, including riders for OG&E's smart grid implementation and Crossroads wind farm, is based on OG&E's actual debt and equity ratios as reflected in OG&E's application and a 10.2 percent return on equity, (iv) depreciation rates were implemented in the same month new customer rates went into effect, (v) the pension and postretirement medical cost tracker remains in effect, (vi) a procedure was established to expedite the recovery of the cost of specified high-voltage transmission projects and (vii) extension of funding for OG&E's system hardening program. OG&E expects the impact of the rate increase on its customers and service territory to be minimal as the rate increase will be more than offset by lower fuel costs attributable to prior fuel over recoveries from lower than forecasted fuel costs. OG&E implemented the new rates effective in early August.
Smart Grid Project
On December 17, 2010, OG&E filed an application with the APSC requesting pre-approval for system-wide deployment of smart grid technology and a recovery rider, including a credit for the Smart Grid grant awarded by the U.S. Department of Energy under the American Recovery and Reinvestment Act of 2009. On June 22, 2011, OG&E reached a settlement agreement with all the parties in this matter. OG&E and the other parties in this matter agreed to ask the APSC to approve the settlement agreement including the following: (i) pre-approval of system-wide deployment of smart grid technology in Arkansas and authorization for OG&E to begin recovering the prudently incurred costs of the Arkansas system-wide deployment of smart grid technology through a rider mechanism that will become effective in accordance with the order approving the settlement agreement; (ii) cost recovery through the rider would commence when all of the smart meters to be deployed in Arkansas are in service; (iii) OG&E guarantees that customers will receive certain operations and maintenance cost reductions resulting from the smart grid deployment as a credit to the recovery rider; and (iv) the stranded costs associated with OG&E's existing meters which are being replaced by smart meters will be accumulated in a regulatory asset and recovered in base rates beginning after an order is issued in OG&E's next general rate case. On August 3, 2011, the APSC issued an order in this matter approving the settlement agreement. On November 5, 2012, OG&E filed a revised smart grid recovery rider rate schedule. On December 13, 2012, the APSC issued an order in this matter approving the revised smart grid recovery rider to be effective beginning with the first billing cycle in January 2013 through December 2013. OG&E began recovering the estimated capital costs of $14 million and associated operation and maintenance costs for deployment of smart grid technology, along with incremental costs for web portal access and education of $0.8 million. The APSC also found that the prudence of OG&E’s smart grid expenditures will be determined in OG&E's next Arkansas rate case and that revenues collected under the rider are subject to refund, with interest, only in the event that the APSC determines that OG&E's smart grid expenditures were not prudent. The costs recoverable from Oklahoma customers for system-wide deployment of smart grid technology and implementing the smart grid pilot program were capped at $366.4 million (inclusive of the U.S. Department of Energy grant award amount) subject to an offset for any recovery of those costs from Arkansas customers and 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. This project was completed in late 2012 and the smart grid project costs did not exceed $366.4 million.
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Demand and Energy Efficiency Program Filing
On July 2, 2012, OG&E filed an application with the OCC requesting approval of OG&E's 2013 demand portfolio, the authorization to recover the program costs, lost revenues associated with any achieved energy, demand savings and performance based incentives through the demand program rider and the recovery of costs associated with research and development investments. On July 16, 2012, OG&E filed an amended application which modified various calculations to reflect the rate of return authorized by the OCC in OG&E's 2011 rate case order and provided for consideration of a peak time rebate program. On December 20, 2012, the OCC approved a settlement with all parties in this matter. Key terms of the settlement included (i) approval of the program budgets proposed by OG&E and an additional amount of approximately $7 million over the three-year period for the energy efficiency programs, (ii) approval of OG&E’s proposed Demand Program Rider tariff, (iii) the recovery through the Demand Program Rider of the increased program costs and the net lost revenues, incentives and research and development investments requested by OG&E, with the exception of lost revenues resulting from the Integrated Volt Var Control program (automated intelligence to control voltage and power on the distribution lines) and incentives for the SmartHours® and Integrated Volt Var Control demand response programs, (iv) recovery of the program costs on a levelized basis over the three-year period, (v) consideration of implementing a peak time rebate program in 2015 and (vi) the periodic filing of additional reports. The Demand Program Rider became effective on January 1, 2013.
Fuel Adjustment Clause Review for Calendar Year 2010
The OCC routinely reviews the costs recovered from customers through OG&E’s fuel adjustment clause. On August 19, 2011, the OCC Staff filed an application to review OG&E’s fuel adjustment clause for calendar year 2010, including the prudence of OG&E’s electric generation, purchased power and fuel procurement costs. OG&E responded by filing direct testimony and the minimum filing review package on October 18, 2011. On September 26, 2012, the administrative law judge recommended that the OCC find that for the calendar year 2010 OG&E's generation, purchase power and fuel procurement processes and costs, including the cost of replacement power for the Sooner 2 outage, were prudent and no disallowance (as discussed below) for any of these expenses is warranted. On January 31, 2013, the OCC issued an order approving the administrative law judge's recommendation. Previously, the Oklahoma Industrial Energy Consumers recommended that the OCC disallow recovery of approximately $44 million of costs previously recovered through OG&E's fuel adjustment clause. These recommendations were based on allegations that OG&E's lower cost coal-fired generation was underutilized, that OG&E failed to aggressively pursue purchasing power at a cost lower than its marginal cost of generation and that OG&E should be found imprudent related to an unplanned outage at OG&E's Sooner 2 coal unit in November and December 2010. Previously, the OCC Staff recommended approval of OG&E's actions related to utilization of coal plants and practices related to purchasing power but recommended that OG&E refund $3 million to customers because of the Sooner 2 outage.
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 currently has 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 various transmission projects
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in Oklahoma. These changes to the "right of first refusal" apply only to "new transmission facilities," which are described as those subject to evaluation or reevaluation (under the applicable local or regional transmission planning process) subsequent to the effective date of the regulatory compliance filings required by the rule, which were filed on November 13, 2012.
OGE Energy cannot, at this time, determine the precise impact of Order No. 1000 on OG&E. OG&E has filed a petition for review in the D.C. Circuit relating to the same matter. Nevertheless, at the present time, 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.
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 rate sales outside the SPP's energy imbalance service market. A FERC order is pending.
Fuel Adjustment Clause Review for Calendar Year 2011
On July 31, 2012, the OCC Staff filed an application for a public hearing to review and monitor OG&E's application of the 2011 fuel adjustment clause and for a prudence review of OG&E's electric generation, purchased power and fuel procurement processes and costs in calendar year 2011. OG&E filed the necessary information and documents needed to satisfy the OCC's minimum filing requirement rules on October 1, 2012. On December 19, 2012, witnesses for the OCC Staff filed responsive testimony recommending that the OCC approve OG&E's fuel adjustment clause costs and recoveries for the calendar year 2011 and recommending that the OCC find that OG&E's electric generation, purchased power, fuel procurement and other fuel related practices, policies and decisions during calendar year 2011 were fair, just and reasonable and prudent. The Oklahoma Industrial Energy Consumers filed a statement of position on December 19, 2012 and did not challenge OG&E's application of its fuel adjustment clause or prudency. The Oklahoma Industrial Energy Consumers reserved its right to file rebuttal testimony, cross examine witnesses and amend its statement of position should circumstances change or additional information becomes available in the course of this proceeding. On January 7, 2013, the Oklahoma Attorney General filed a statement of position stating that after reviewing the case information the Attorney General has no reason at this time to dispute the findings of the OCC Staff. A hearing in this matter is scheduled for April 4, 2013.
Crossroads Wind Farm
As previously reported, OG&E signed memoranda of understanding in February 2010 for approximately 197.8 MWs of wind turbine generators and certain related balance of plant engineering, procurement and construction services associated with the Crossroads wind farm. Also as part of this project, on June 16, 2011, OG&E entered into an interconnection agreement with the SPP for the Crossroads wind farm which allowed the Crossroads wind farm to interconnect at 227.5 MWs. On August 31, 2012, OG&E filed an application with the APSC requesting approval to recover the Arkansas portion of the costs of the Crossroads wind farm through a rider until such costs are included in OG&E's base rates as part of its next general rate proceeding. On December 14, 2012, the APSC Staff filed testimony recommending that the APSC find that the Crossroads wind farm is in the public interest and that it approve interim recovery through the Energy Cost Recovery Rider effective August 31, 2012. OG&E concurred with the APSC Staff’s recommendations. On January 16, 2013, the APSC granted a motion made by OG&E and the APSC Staff to cancel the hearing previously scheduled and issue an order based on the filed record. On February 22, 2013, the APSC directed OG&E to respond to two questions in order to complete the record upon which they may rule. OG&E believes it is reasonable to expect a final order from the APSC by the end of the first quarter.
Fuel Adjustment Clause Review for Calendar Year 2009 Related to Enogex Gas Transportation and Storage Agreement
As previously reported, under the terms of a settlement agreement reached in 2011 regarding the prudency of OG&E's fuel adjustment clause for 2009, OG&E agreed to hire a third party expert to evaluate its prospective gas transportation and storage needs and to identify options for meeting those needs. Upon completion of the third party evaluation, OG&E agreed to file a cause to address the third party's evaluation, recommendations and conclusions. On January 31, 2013, OG&E filed a cause that included OG&E's response to the final evaluations and conclusions of the third party consultant, Black & Veatch, and OG&E's assessment of transportation and storage needs for the next three to five years.
Also, as part of this matter, on August 9, 2012, OG&E filed an application with the OCC requesting: (i) an order finding that a one-year extension to April 30, 2014 of OG&E's gas transportation and storage agreement with Enogex is prudent, (ii) a waiver of the OCC's competitive procurement rules and (iii) finding that the one-year extension of the gas transportation and storage agreement complies with the OCC's affiliate transaction rules. On September 14, 2012, OG&E filed a settlement agreement
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in which all parties to this matter agreed to the one-year extension of the Enogex contract and cost recovery from ratepayers at the rates currently in effect. On October 25, 2012, the OCC issued an order approving the settlement agreement.
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 actual or anticipated 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 actual or anticipated 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, 2012 and 2011, OG&E had regulatory assets of $537.6 million and $523.9 million, respectively, and regulatory liabilities of $386.2 million and $276.4 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 variances (either positive or negative) in the actual cost of fuel as compared to the fuel component in OG&E's most recently approved rate case.
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. Budget-minded customers that desire a fixed monthly bill may benefit from the guaranteed flat bill option. 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.
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OG&E's rate choices, reduction in cogeneration rates, acquisition of additional generation resources and overall low costs of production and deliverability are expected to provide valuable benefits for OG&E's customers for many years to come.
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. 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 2012, 52 percent of the OG&E-generated energy was produced by coal-fired units, 42 percent by natural gas-fired units and six percent by wind-powered units. Of OG&E's 6,807 total MW capability reflected in the table under Item 2. Properties, 3,816 MWs, or 56 percent, are from natural gas generation, 2,542 MWs, or 37 percent, are from coal generation and 449 MWs, or seven percent, are from wind generation. Though OG&E has a higher installed capability of generation from natural gas units, it has been more economical to generate electricity for our customers using lower priced coal. Over the last five years, the weighted average cost of fuel used, by type, was as follows:
Year ended December 31 (In Kilowatt-Hour - cents) | 2012 | 2011 | 2010 | 2009 | 2008 |
Natural gas | 2.930 | 4.328 | 4.638 | 3.696 | 8.455 |
Coal | 2.310 | 2.064 | 1.911 | 1.747 | 1.153 |
Weighted average | 2.437 | 2.897 | 3.012 | 2.474 | 3.337 |
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 lower natural gas generation. The increase in the weighted average cost of fuel in 2010 as compared to 2009 was primarily due to higher natural gas prices and increased natural gas generation. The decrease in the weighted average cost of fuel in 2009 as compared to 2008 was primarily due to decreased natural gas prices partially offset by increased coal transportation rates in 2009. A portion of these fuel costs is included in the base rates to customers and differs for each jurisdiction. The portion of recoverable fuel costs that is not included in the base rates is recovered through OG&E's fuel adjustment clauses that are approved by the OCC, the APSC and the FERC.
Coal
All of OG&E's coal-fired units, with an aggregate capability of 2,542 MWs, are designed to burn low sulfur western sub-bituminous coal. OG&E has contracted for approximately 60 percent of its forecasted annual coal usage via multi-year contracts that expire in 2015 and the remainder of its forecasted 2013 usage via one-year contracts that expire in 2013. In 2012, OG&E purchased 8.5 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.
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.
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Natural Gas
OG&E has entered into multiple month term natural gas contracts for 26.1 percent of its 2013 annual forecasted natural gas requirements. Additional gas supplies to fulfill OG&E's remaining 2013 natural gas requirements will be acquired through additional requests for proposal in early to mid-2013, along with monthly and daily purchases, all of which are expected to be made at market prices.
OG&E utilizes a natural gas storage facility for storage services that allows OG&E to maximize the value of its generation assets. Storage services are provided by Enogex as part of Enogex's gas transportation and storage contract with OG&E. At December 31, 2012, OG&E had 1.5 million MMBtu's in natural gas storage valued at $4.6 million.
Wind
OG&E's current wind power portfolio includes: (i) the 120 MW Centennial wind farm, (ii) the 101 MW OU Spirit wind farm, (iii) the 227.5 MW Crossroads wind farm, (iv) 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, (v) access to up to 150 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, (vi) 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 (vii) 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 and comparable state statutes, whose purpose is to protect the safety and health of workers. In addition, the OSHA hazard communication standard, the EPA 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 used or produced in OG&E's operations and that this information be provided 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 stringent and complex Federal, state and local laws and regulations governing environmental protection including the discharge of materials into the environment. These laws and regulations can restrict or impact business activities in many ways, such as restricting the way it can handle or dispose of its wastes, requiring remedial action to mitigate pollution conditions that may be caused by its operations or that are attributable to former operators, regulating future construction activities to mitigate harm to threatened or endangered species and requiring the installation and operation of pollution control equipment. Failure to comply with these laws and regulations may 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 2013 will be $63.0 million, of which $45.3 million is for capital expenditures. It is estimated that OG&E's total expenditures to comply for environmental laws, regulations and requirements for 2014 will be $37.7 million, of which $19.2 million is for capital expenditures. The amounts above include capital expenditures for low NOX burners and exclude certain other capital expenditures as discussed in the capital expenditures table and related footnote D in "Finance and Construction" below. 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."
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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, hedging activities, 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 2013 through 2017 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.
(In millions) | 2013 | 2014 | 2015 | 2016 | 2017 | ||||||||||
Base Transmission | $ | 65 | $ | 50 | $ | 50 | $ | 50 | $ | 50 | |||||
Base Distribution | 175 | 175 | 175 | 175 | 175 | ||||||||||
Base Generation | 80 | 75 | 75 | 75 | 75 | ||||||||||
Other | 15 | 15 | 15 | 15 | 15 | ||||||||||
Total Base Transmission, Distribution, Generation and Other | 335 | 315 | 315 | 315 | 315 | ||||||||||
Known and Committed Projects: | |||||||||||||||
Transmission Projects: | |||||||||||||||
Balanced Portfolio 3E Projects (A) | 205 | 25 | — | — | — | ||||||||||
SPP Priority Projects (B) | 165 | 110 | — | — | — | ||||||||||
SPP Integrated Transmission Projects (C) | 5 | 5 | — | 40 | 40 | ||||||||||
Total Transmission Projects | 375 | 140 | — | 40 | 40 | ||||||||||
Other Projects: | |||||||||||||||
Smart Grid Program | 25 | 25 | 10 | 10 | — | ||||||||||
System Hardening | 15 | — | — | — | — | ||||||||||
Environmental - low NOX burners | 30 | 20 | 25 | 20 | — | ||||||||||
Total Other Projects | 70 | 45 | 35 | 30 | — | ||||||||||
Total Known and Committed Projects | 445 | 185 | 35 | 70 | 40 | ||||||||||
Total (D) | $ | 780 | $ | 500 | $ | 350 | $ | 385 | $ | 355 |
(A) | Balanced Portfolio 3E includes three projects to be built by OG&E and includes: (i) construction of 135 miles of transmission line from OG&E's Seminole substation in a northeastern direction to OG&E's Muskogee substation at an estimated cost of $175 million for OG&E, which is expected to be in service by late 2013, (ii) construction of 96 miles of transmission line from OG&E's Woodward District Extra High Voltage substation in a southwestern direction to the Oklahoma/Texas Stateline to a companion transmission line to be built by Southwestern Public Service to its Tuco substation at an estimated cost of $115 million for OG&E, which is expected to be in service by mid-2014 and (iii) construction of 39 miles of transmission line from OG&E's Sooner substation in an eastern direction to the Grand River Dam Authority Cleveland substation at an estimated cost of $45 million for OG&E, which was placed in service in February 2013. |
(B) | The Priority Projects consist of several transmission projects, two of which have been assigned to OG&E. The 345 kilovolt projects include: (i) construction of 99 miles of transmission line from OG&E's Woodward District Extra High Voltage substation to a companion transmission line to be built by Southwestern Public Service to its Hitchland substation in the Texas Panhandle at an estimated cost of $185 million for OG&E, which is expected to be in service by mid-2014 and (ii) construction of 77 miles of transmission line from OG&E's Woodward District Extra High Voltage substation to a companion transmission line at the Kansas border to be built by either Mid-Kansas Electric Company or another company assigned by Mid-Kansas Electric Company at an estimated cost of $150 million to OG&E, which is expected to be in service by late 2014. OG&E |
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began construction on the Hitchland project in November 2012 and expects to begin construction on the Kansas project in June 2013.
(C) | On January 31, 2012, the SPP approved the Integrated Transmission Plan Near Term and Integrated Transmission Plan 10-year projects. These plans include two projects to be built by OG&E: (i) construction of 47 miles of transmission line from OG&E's Gracemont substation in a northwestern direction to a companion transmission line to be built by American Electric Power to its Elk City substation at an estimated cost of $75 million for OG&E, which is expected to be in service by early 2018, and (ii) construction of 126 miles of transmission line from OG&E's Woodward District Extra High Voltage substation in a southeastern direction to OG&E's Cimarron substation and construction of a new substation on this transmission line, the Mathewson substation, at an estimated cost of $210 million for OG&E, which is expected to be in service by early 2021. On April 9, 2012, OG&E received a notice to construct these projects from the SPP. On June 26, 2012, OG&E responded to the SPP that OG&E will construct the projects discussed above and is moving forward with more detailed cost estimates that must be reviewed and approved by the SPP. OG&E and American Electric Power are currently in discussions regarding how much of the 94 mile Elk City to Gracemont transmission line will be built by OG&E and American Electric Power. American Electric Power has argued for a larger portion of such transmission line than the traditional 50 percent split. The capital expenditures related to these projects are presented in the summary of capital expenditures for known and committed projects above. |
(D) | The capital expenditures above exclude any environmental expenditures associated with: |
• | Pollution control equipment related to controlling SO2 emissions under the regional haze requirements due to the uncertainty regarding the approach and timing for such pollution control equipment. The SO2 emissions standards in the EPA's FIP could require the installation of Dry Scrubbers or fuel switching. OG&E estimates that installing such Dry Scrubbers could cost more than $1.0 billion. The FIP is being challenged by OG&E and the state of Oklahoma. On June 22, 2012, OG&E was granted a stay of the FIP by the U.S. Court of Appeals for the Tenth Circuit, which delays the timing of required implementation of the SO2 emissions standards in the rule. The merits of the appeal have been fully briefed, and oral argument is scheduled to occur on March 6, 2013. Neither the outcome of the challenge to the FIP nor the timing of any required capital expenditures can be predicted with any certainty at this time, but such capital expenditures could be significant. |
• | Installation of control equipment for compliance with MATS by a deadline of April 16, 2015, with the possibility of a one-year extension. OG&E is currently planning to utilize activated carbon injection and low levels of dry sorbent injection at each of its five coal-fired units. Due to various uncertainties about the final design, the potential use of this technology relating to regional haze measures and the specifications for the control equipment, the resulting cost estimates currently range from $34 million to $72 million per unit. |
OG&E is currently evaluating options to comply with environmental requirements. For further information, see "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Environmental Laws and Regulations" below.
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 2012 and 2011, OGE Energy made contributions to its Pension Plan of $35 million and $50 million, respectively, of which $33 million in 2012 and $47 million in 2011 was OG&E's portion, to help ensure that the Pension Plan maintains an adequate funded status. During 2013, OGE Energy expects to contribute up to $35 million to its Pension Plan, of which $33 million is expected to be OG&E's portion. 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.
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Short-Term Debt and Credit Facility
At December 31, 2012 and 2011, there were $90.3 million and $97.2 million, respectively, in net outstanding advances to OGE Energy. 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, 2016. At December 31, 2012, 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, 2012, there was $2.2 million supporting letters of credit at a weighted-average interest rate of 0.53 percent. There were no outstanding borrowings under this revolving credit agreement and no outstanding commercial paper borrowings at December 31, 2012. At December 31, 2012, OG&E had $397.8 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, 2013 and ending December 31, 2014. At December 31, 2012, OG&E had less than $0.1 million in cash and cash equivalents. See Note 10 of Notes to Financial Statements for a discussion of OG&E's short-term debt activity.
Expected Issuance of Long-Term Debt
OG&E expects to issue up to $250 million of long-term debt in the first half of 2013, depending on market conditions, to fund capital expenditures, repay short-term borrowings and for general corporate purposes.
EMPLOYEES
OG&E had 1,987 employees at December 31, 2012.
EXECUTIVE OFFICERS
The following persons were Executive Officers of the Registrant as of February 27, 2013:
Name | Age | Title |
Peter B. Delaney | 59 | Chairman of the Board, President and Chief Executive Officer |
Sean Trauschke | 46 | Vice President and Chief Financial Officer |
William J. Bullard | 64 | General Counsel |
Scott Forbes | 55 | Controller and Chief Accounting Officer |
Patricia D. Horn | 54 | Vice President - Governance, Environmental and Corporate Secretary |
Gary D. Huneryager | 62 | Vice President - Internal Audits |
Jesse B. Langston | 50 | Vice President - Retail Energy |
Jean C. Leger, Jr. | 54 | Vice President - Utility Operations |
Cristina F. McQuistion | 48 | Vice President - Strategic Planning, Performance Improvement and Chief Information Officer |
Max J. Myers | 38 | Treasurer |
Jerry A. Peace | 50 | Chief Risk Officer |
Paul L. Renfrow | 56 | Vice President - Public Affairs, Human Resources and Health & Safety |
No family relationship exists between any of the Executive Officers of the Registrant. Messrs. Delaney, Trauschke, Bullard, Forbes, Huneryager, Myers, Peace, Renfrow and Ms. Horn and Ms. McQuistion are also officers of OGE Energy. Messrs. Delaney, Trauschke, Myers and Ms. Horn are also officers of Enogex Holdings and/or its subsidiaries. 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 16, 2013.
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The business experience of each of the Executive Officers of the Registrant for the past five years is as follows:
Name | Business Experience | |
Peter B. Delaney | 2012 - Present: | Chairman of the Board, President and Chief Executive Officer of OGE Energy Corp. and OG&E |
2010 - 2011: | Chairman of the Board and Chief Executive Officer of OGE Energy Corp. and OG&E | |
2010 - Present: | Chief Executive Officer of Enogex Holdings | |
2008 - Present: | Chief Executive Officer of Enogex LLC | |
2008 - 2010: | Chairman of the Board, President and Chief Executive Officer of OGE Energy Corp. and OG&E | |
2008: | Chief Executive Officer of Enogex Inc. | |
Sean Trauschke | 2009 - Present: | Vice President and Chief Financial Officer of OGE Energy Corp. and OG&E |
2010 - Present: | Chief Financial Officer of Enogex Holdings | |
2009 - Present: | Chief Financial Officer of Enogex LLC | |
2008 - 2009: | Senior Vice President - Investor Relations and Financial Planning of Duke Energy (electric utility) | |
William J. Bullard | 2010 - Present: | Assistant General Counsel of OGE Energy Corp.; General Counsel of OG&E |
2008 - 2010: | Assistant General Counsel of OGE Energy Corp. and OG&E | |
Scott Forbes | 2008 - Present: | Controller and Chief Accounting Officer of OGE Energy Corp. and OG&E |
2008 - 2009: | Interim Chief Financial Officer of OGE Energy Corp. and OG&E | |
Patricia D. Horn | 2012 - Present: | Vice President - Governance, Environmental and Corporate Secretary of OGE Energy Corp. and OG&E; Secretary of Enogex Holdings; Corporate Secretary of Enogex LLC |
2010 - 2012: | Vice President - Governance, Environmental, Health & Safety; Corporate Secretary of OGE Energy Corp. and OG&E; Secretary of Enogex Holdings; Corporate Secretary of Enogex LLC | |
2008 - 2010: | Vice President - Legal, Regulatory, Environmental Health & Safety, General Counsel and Secretary of Enogex LLC | |
2008 - 2010: | Assistant General Counsel of OGE Energy Corp. | |
2008: | Vice President - Legal, Regulatory, Environmental Health & Safety, General Counsel and Secretary of Enogex Inc. | |
Gary D. Huneryager | 2008 - Present: | Vice President - Internal Audits of OGE Energy Corp. and OG&E |
Jesse B. Langston | 2011 - Present: | Vice President - Retail Energy of OG&E |
2008 - 2011: | Vice President - Utility Commercial Operations of OG&E | |
Jean C. Leger, Jr. | 2008 - Present: | Vice President - Utility Operations of OG&E |
2008: | Vice President of Operations of Enogex Inc. | |
Cristina F. McQuistion | 2013 - Present: | Vice President - Strategic Planning, Performance Improvement and Chief Information Officer of OGE Energy Corp. and OG&E |
2011 - 2013: | Vice President - Strategy and Performance Improvement of OGE Energy Corp. and OG&E | |
2008 - 2011: | Vice President - Process and Performance Improvement of OGE Energy Corp. and OG&E | |
2008: | Executive Vice President and General Manager Point of Sale Systems of Teleflora (floral industry and software services to floral industry company) | |
Max J. Myers | 2009 - Present: | Treasurer of OGE Energy Corp. and OG&E |
2010 - Present: | Treasurer of Enogex Holdings | |
2008 - 2009: | Managing Director of Corporate Development and Finance of OGE Energy Corp. and OG&E | |
2008: | Manager of Corporate Development of OGE Energy Corp. and OG&E | |
Jerry A. Peace | 2008 - Present: | Chief Risk Officer of OGE Energy Corp. and OG&E |
2008: | Chief Risk Officer and Compliance Officer of OGE Energy Corp. and OG&E | |
Paul L. Renfrow | 2012 - Present | Vice President - Public Affairs, Human Resources and Health & Safety of OGE Energy Corp. and OG&E |
2011 - 2012: | Vice President - Public Affairs and Human Resources of OGE Energy Corp. and OG&E | |
2008 - 2011: | Vice President - Public Affairs of OGE Energy Corp. and OG&E |
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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 "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. 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 and 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
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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", in 2011, the EPA accepted a portion of the Oklahoma SIP for regional haze, which requires the installation of low NOX burners on OG&E's affected units within five years at a cost of approximately $95 million. The EPA rejected Oklahoma's SO2 BART determination with respect to the four affected coal-fired units at the Sooner and Muskogee generating stations and issued a FIP in its place. The SO2 emissions standards in the EPA's FIP could require the installation of Dry Scrubbers or fuel switching. OG&E estimates that installing such Dry Scrubbers could cost more than $1.0 billion. OG&E, the state of Oklahoma and other parties, filed an appeal to challenge this determination, which has delayed the implementation of the regional haze rule in Oklahoma. Neither the outcome of the appeal nor the timing of any required expenditures for pollution control equipment can be predicted with any certainty at this time.
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.
There is inherent risk of the incurrence of environmental costs and liabilities in our operations due to our handling of natural gas, air emissions related to our operations and historical industry operations and waste disposal practices. These activities are subject to stringent and complex Federal, state and local laws and regulations governing environmental protection including the discharge of materials into the environment. These laws and regulations 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. The SPP implemented a regional energy imbalance service market on February 1, 2007. OG&E participates in the SPP energy imbalance service market to aid in the optimization of its physical assets to serve OG&E's customers. OG&E has not participated in the SPP energy imbalance service market for any speculative trading activities. The SPP purchases and sales are not allocated to individual customers. OG&E records the hourly sales to the SPP at market rates in Operating Revenues and the hourly purchases from the SPP at market rates in 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 by
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the FERC or the SPP, including the forthcoming SPP integrated marketplace, which is scheduled to begin operation in March 2014.
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 an increased amount of 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
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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 power purchase 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:
• | increased prices for fuel and fuel transportation as existing contracts expire; |
• | facility shutdowns due to a breakdown or failure of equipment or processes or interruptions in fuel supply; |
• | operator error or safety related stoppages; |
• | disruptions in the delivery of electricity; and |
• | catastrophic events such as fires, explosions, floods or other similar occurrences. |
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.
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
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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.
OG&E may engage in commodity hedging activities to minimize the impact of commodity price risk, which may have a volatile effect on our results of operations and cash flows.
OG&E is exposed to changes in commodity prices in its operations. OG&E occasionally uses commodity price swap contracts to manage its commodity price risk exposures. Natural gas swaps are used to manage OG&E's natural gas exposure associated with a wholesale power sales contract.
From time to time, OG&E has instituted a hedging program that was intended to reduce the commodity price risk associated with OG&E's wholesale power sales contract. Management will continue to evaluate whether to enter into any new hedging arrangements and there can be no assurance that OG&E will enter into any new hedging arrangements. To the extent OG&E hedges its commodity price and interest rate exposures, OG&E may forego the benefits that otherwise would be experienced if commodity prices or interest rates were to change in OG&E's favor. In addition, even though management monitors OG&E's hedging activities, these activities can result in substantial losses. Such losses could occur under various circumstances, including if a counterparty does not perform its obligations under the applicable hedging arrangement, the hedging arrangement is imperfect or ineffective, or the hedging policies and procedures are not followed or do not work as planned.
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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 liquidity.
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, 2012, OGE Energy expects to continue to make future contributions to maintain required funding levels. It has been OGE Energy's practice in the past 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, 36 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.
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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:
• | 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; |
• | 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 |
• | 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. Unresolved Staff Comments.
None.
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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 6,807 MWs at December 31, 2012. The following tables set forth information with respect to OG&E's electric generating facilities, all of which are located in Oklahoma.
2012 Capacity Factor (A) | Unit Capability (MW) | Station Capability (MW) | ||||||||||
Year Installed | Fuel Capability | Unit Run Type | ||||||||||
Station & Unit | Unit Design Type | |||||||||||
Seminole | 1 | 1971 | Steam-Turbine | Gas | Base Load | 24.8 | % | 465 | ||||
1GT | 1971 | Combustion-Turbine | Gas | Peaking | 0.2 | % | (B) | 16 | ||||
2 | 1973 | Steam-Turbine | Gas | Base Load | 18.9 | % | 490 | |||||
3 | 1975 | Steam-Turbine | Gas/Oil | Base Load | 26.3 | % | 477 | 1,448 | ||||
Muskogee | 4 | 1977 | Steam-Turbine | Coal | Base Load | 57.8 | % | 489 | ||||
5 | 1978 | Steam-Turbine | Coal | Base Load | 62.5 | % | 509 | |||||
6 | 1984 | Steam-Turbine | Coal | Base Load | 52.7 | % | 508 | 1,506 | ||||
Sooner | 1 | 1979 | Steam-Turbine | Coal | Base Load | 61.2 | % | 516 | ||||
2 | 1980 | Steam-Turbine | Coal | Base Load | 62.7 | % | 520 | 1,036 | ||||
Horseshoe Lake | 6 | 1958 | Steam-Turbine | Gas/Oil | Base Load | 17.7 | % | 171 | ||||
7 | 1963 | Combined Cycle | Gas/Oil | Base Load | 15.5 | % | 222 | |||||
8 | 1969 | Steam-Turbine | Gas | Base Load | 12.3 | % | 399 | |||||
9 | 2000 | Combustion-Turbine | Gas | Peaking | 3.7 | % | (B) | 45 | ||||
10 | 2000 | Combustion-Turbine | Gas | Peaking | 3.4 | % | (B) | 45 | 882 | |||
Redbud (C) | 1 | 2003 | Combined Cycle | Gas | Base Load | 62.7 | % | 148 | ||||
2 | 2003 | Combined Cycle | Gas | Base Load | 65.4 | % | 149 | |||||
3 | 2003 | Combined Cycle | Gas | Base Load | 70.7 | % | 146 | |||||
4 | 2003 | Combined Cycle | Gas | Base Load | 47.1 | % | 151 | 594 | ||||
Mustang | 1 | 1950 | Steam-Turbine | Gas | Peaking | 3.2 | % | (B) | 52 | |||
2 | 1951 | Steam-Turbine | Gas | Peaking | 4.6 | % | (B) | 52 | ||||
3 | 1955 | Steam-Turbine | Gas | Base Load | 16.3 | % | 117 | |||||
4 | 1959 | Steam-Turbine | Gas | Base Load | 13.8 | % | 250 | |||||
5A | 1971 | Combustion-Turbine | Gas/Jet Fuel | Peaking | 0.7 | % | (B) | 34 | ||||
5B | 1971 | Combustion-Turbine | Gas/Jet Fuel | Peaking | 0.8 | % | (B) | 33 | 538 | |||
McClain (D) | 1 | 2001 | Combined Cycle | Gas | Base Load | 85.8 | % | 354 | 354 | |||
Total Generating Capability (all stations, excluding wind stations) (E) | 6,358 | |||||||||||
2012 Capacity Factor (A) | Unit Capability (MW) | Station Capability (MW) | ||||||||||
Year Installed | Number of Units | Fuel Capability | ||||||||||
Station | Location | |||||||||||
Crossroads | 2011 | Woodward, OK | 99 | Wind | 45.8 | % | 2.3 | 227.5 | ||||
Centennial | 2007 | Woodward, OK | 80 | Wind | 33.2 | % | 1.5 | 120 | ||||
OU Spirit | 2009 | Woodward, OK | 44 | Wind | 36.9 | % | 2.3 | 101 | ||||
Total Generating Capability (wind stations) | 448.5 |
(A) | 2012 Capacity Factor = 2012 Net Actual Generation / (2012 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. |
(E) | In December 2012, the Enid and Woodward generating stations were retired. |
At December 31, 2012, OG&E's transmission system included: (i) 51 substations with a total capacity of 11.9 million kilovolt-amps and 4,426 structure miles of lines in Oklahoma and (ii) seven substations with a total capacity of 2.4 million kilovolt-amps and 279 structure miles of lines in Arkansas. OG&E's distribution system included: (i) 353 substations with a total capacity of 9.4 million kilovolt-amps, 29,103 structure miles of overhead lines, 2,110 miles of underground conduit and 10,580 miles of underground conductors in Oklahoma and (ii) 38 substations with a total capacity of 1.1 million kilovolt-amps, 2,778 structure miles of overhead lines, 219 miles of underground conduit and 700 miles of underground conductors in Arkansas.
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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, 2012, OG&E's gross property, plant and equipment (excluding construction work in progress) additions were $2.2 billion and gross retirements were $291.5 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 25.8 percent of gross property, plant and equipment (excluding construction work in progress) at December 31, 2012.
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, except as set forth below, under "Environmental Laws and Regulations" in Item 7 of Part II of this Form 10-K and in Notes 12 and 13 of Notes to Financial Statements, 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. Mine Safety Disclosures.
Not Applicable.
PART II
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 2012 and 2010, OG&E declared dividends to OGE Energy of $75.0 million and $60.2 million, respectively. In 2011, OG&E declared no dividends to OGE Energy.
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Item 6. Selected Financial Data
HISTORICAL DATA
Year ended December 31 | 2012 | 2011 | 2010 | 2009 | 2008 | ||||||||||
SELECTED FINANCIAL DATA | |||||||||||||||
(In millions) | |||||||||||||||
Results of Operations Data: | |||||||||||||||
Operating revenues | $ | 2,141.2 | $ | 2,211.5 | $ | 2,109.9 | $ | 1,751.2 | $ | 1,959.5 | |||||
Cost of goods sold | 879.1 | 1,013.5 | 1,000.2 | 796.3 | 1,114.9 | ||||||||||
Gross margin on revenues | 1,262.1 | 1,198.0 | 1,109.7 | 954.9 | 844.6 | ||||||||||
Operating expenses | 772.7 | 725.7 | 696.0 | 600.8 | 566.3 | ||||||||||
Operating income | 489.4 | 472.3 | 413.7 | 354.1 | 278.3 | ||||||||||
Interest income | 0.2 | 0.5 | 0.1 | 1.1 | 4.4 | ||||||||||
Allowance for equity funds used during construction | 6.2 | 20.4 | 11.4 | 15.1 | — | ||||||||||
Other income | 8.0 | 8.0 | 6.5 | 20.4 | 3.6 | ||||||||||
Other expense | 4.3 | 8.4 | 1.6 | 6.7 | 11.8 | ||||||||||
Interest expense | 124.6 | 111.6 | 103.4 | 93.6 | 79.1 | ||||||||||
Income tax expense | 94.6 | 117.9 | 111.0 | 90.0 | 52.4 | ||||||||||
Net income | $ | 280.3 | $ | 263.3 | $ | 215.7 | $ | 200.4 | $ | 143.0 | |||||
Balance Sheet Data (at period end): | |||||||||||||||
Property, plant and equipment, net | $ | 6,044.1 | $ | 5,550.9 | $ | 4,877.3 | $ | 4,467.6 | $ | 3,955.5 | |||||
Total assets | $ | 7,222.4 | $ | 6,620.9 | $ | 5,898.1 | $ | 5,478.1 | $ | 4,851.2 | |||||
Long-term debt | $ | 2,050.3 | $ | 2,039.2 | $ | 1,790.4 | $ | 1,541.8 | $ | 1,541.4 | |||||
Total stockholder's equity | $ | 2,703.1 | $ | 2,494.0 | $ | 2,178.1 | $ | 2,024.3 | $ | 1,824.3 | |||||
Capitalization Ratios (A) | |||||||||||||||
Stockholder's equity | 56.9 | % | 55.0 | % | 54.9 | % | 56.8 | % | 54.2 | % | |||||
Long-term debt | 43.1 | % | 45.0 | % | 45.1 | % | 43.2 | % | 45.8 | % | |||||
Ratio of Earnings to Fixed Charges (B) | |||||||||||||||
Ratio of earnings to fixed charges | 3.87 | 4.01 | 3.90 | 3.71 | 3.25 |
(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. |
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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 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. OGE Energy's corporate strategy is to continue to maintain its existing business mix and diversified asset position of its regulated electric utility business and unregulated natural gas midstream business while providing competitive energy products and services to customers primarily in the south central United States as well as seeking growth opportunities in both businesses.
OG&E is focused on increased investment to preserve system reliability and meet load growth by adding and maintaining infrastructure equipment and replacing aging transmission and distribution systems. OG&E expects to maintain a diverse generation portfolio while remaining environmentally responsible. OG&E is focused on maintaining strong regulatory and legislative relationships for the long-term benefit of its customers. In an effort to encourage more efficient use of electricity, OG&E is also providing energy management solutions to its customers through the Smart Grid program that utilizes newer technology to improve operational and environmental performance as well as allow customers to monitor and manage their energy usage, which should help reduce demand during critical peak times, resulting in lower capacity requirements. If these initiatives are successful, OG&E believes it may be able to defer the construction or acquisition of any incremental fossil fuel generation capacity until 2020. The Smart Grid program also provides benefits to OG&E, including more efficient use of its resources and access to increased information about customer usage, which should enable OG&E to have better distribution system planning data, better response to customer usage questions and faster detection and restoration of system outages. As the Smart Grid platform matures, OG&E anticipates providing new products and services to its customers. In addition, OG&E is also pursuing additional transmission-related opportunities within the SPP.
Summary of Operating Results
2012 compared to 2011. OG&E reported net income of $280.3 million and $263.3 million, respectively, in 2012 and 2011, an increase of $17.0 million, or 6.5 percent, primarily due to a higher gross margin and lower income tax expense. The higher gross margin was primarily due to increased recovery of investments and increased transmission revenue partially offset by milder weather in OG&E's service territory. These increases were partially offset by higher other operation and maintenance expense, higher depreciation and amortization expense, lower allowance for equity funds used during construction and higher interest expense.
2011 compared to 2010. OG&E reported net income of $263.3 million and $215.7 million, respectively, in 2011 and 2010, an increase of $47.6 million, or 22.1 percent, primarily due to a higher gross margin primarily from warmer weather in OG&E's service territory partially offset by higher other operation and maintenance expense, higher interest expense and higher income tax expense. Income tax expense was higher due to higher pre-tax income which more than offset the effects of the one-time, non-cash charge in 2010 of $7.0 million related to the elimination of the tax deduction for the Medicare Part D subsidy (as previously reported in OG&E's Form 10-K for the year ended December 31, 2010).
Recent Developments and Regulatory Matters
SPP Transmission Projects
In 2007, the SPP notified OG&E to construct 44 miles of a new 345 kilovolt transmission line originating at OG&E's existing Sooner 345 kilovolt substation and proceeding generally in a northerly direction to the Oklahoma/Kansas Stateline (referred to as the Sooner-Rose Hill project). At the Oklahoma/Kansas Stateline, the line connects to the companion line constructed in Kansas by Westar Energy. The transmission line was placed in service in April 2012. The total capital expenditures associated with this project were $45 million.
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In January 2009, OG&E received notification from the SPP to begin construction on 50 miles of a new 345 kilovolt transmission line and substation upgrades at OG&E's Sunnyside substation, among other projects. In April 2009, Western Farmers Electric Cooperative assigned to OG&E the construction of 50 miles of line designated by the SPP to be built by Western Farmers Electric Cooperative. The new line extends from OG&E's Sunnyside substation near Ardmore, Oklahoma, 123.5 miles to the Hugo substation owned by Western Farmers Electric Cooperative near Hugo, Oklahoma. The transmission line was completed in April 2012. The total capital expenditures associated with this project were $157 million.
As discussed in Note 13 of Notes to Financial Statements, the OCC approved a settlement agreement in OG&E's 2011 Oklahoma rate case filing that included an expedited procedure for recovering the costs of the two projects. On July 31, 2012, OG&E filed an application with the OCC requesting an order authorizing recovery for the two projects through the SPP transmission systems additions rider. On October 2, 2012, all parties signed a settlement agreement in this matter which stated: (i) the parties agree not to oppose requested relief sought by OG&E, (ii) OG&E will host meetings to discuss the SPP’s transmission planning process, including any future transmission projects for which OG&E has received a notice to construct from the SPP, and (iii) there will be opportunities for parties to provide input related to transmission planning studies that the SPP performs to identify future transmission projects. On October 25, 2012, the OCC issued an order approving the settlement agreement and granting OG&E cost recovery for the two projects. OG&E initiated cost recovery beginning with the first billing cycle in November 2012.
Demand and Energy Efficiency Program Filing
On July 2, 2012, OG&E filed an application with the OCC requesting approval of OG&E's 2013 demand portfolio, the authorization to recover the program costs, lost revenues associated with any achieved energy, demand savings and performance based incentives through the demand program rider and the recovery of costs associated with research and development investments. On July 16, 2012, OG&E filed an amended application which modified various calculations to reflect the rate of return authorized by the OCC in OG&E's 2011 rate case order and provided for consideration of a peak time rebate program. On December 20, 2012, the OCC approved a settlement with all parties in this matter. Key terms of the settlement included (i) approval of the program budgets proposed by OG&E and an additional amount of approximately $7 million over the three-year period for the energy efficiency programs, (ii) approval of OG&E’s proposed Demand Program Rider tariff, (iii) the recovery through the Demand Program Rider of the increased program costs and the net lost revenues, incentives and research and development investments requested by OG&E, with the exception of lost revenues resulting from the Integrated Volt Var Control program (automated intelligence to control voltage and power on the distribution lines) and incentives for the SmartHours® and Integrated Volt Var Control demand response programs, (iv) recovery of the program costs on a levelized basis over the three-year period, (v) consideration of implementing a peak time rebate program in 2015 and (vi) the periodic filing of additional reports. The Demand Program Rider became effective on January 1, 2013.
Fuel Adjustment Clause Review for Calendar Year 2010
The OCC routinely reviews the costs recovered from customers through OG&E’s fuel adjustment clause. On August 19, 2011, the OCC Staff filed an application to review OG&E’s fuel adjustment clause for calendar year 2010, including the prudence of OG&E’s electric generation, purchased power and fuel procurement costs. OG&E responded by filing direct testimony and the minimum filing review package on October 18, 2011. On September 26, 2012, the administrative law judge recommended that the OCC find that for the calendar year 2010 OG&E's generation, purchase power and fuel procurement processes and costs, including the cost of replacement power for the Sooner 2 outage, were prudent and no disallowance (as discussed below) for any of these expenses is warranted. On January 31, 2013, the OCC issued an order approving the administrative law judge's recommendation. Previously, the Oklahoma Industrial Energy Consumers recommended that the OCC disallow recovery of approximately $44 million of costs previously recovered through OG&E's fuel adjustment clause. These recommendations were based on allegations that OG&E's lower cost coal-fired generation was underutilized, that OG&E failed to aggressively pursue purchasing power at a cost lower than its marginal cost of generation and that OG&E should be found imprudent related to an unplanned outage at OG&E's Sooner 2 coal unit in November and December 2010. Previously, the OCC Staff recommended approval of OG&E's actions related to utilization of coal plants and practices related to purchasing power but recommended that OG&E refund $3 million to customers because of the Sooner 2 outage.
2013 Outlook
OGE Energy projects OG&E to earn approximately $280 million to $290 million in 2013 and is based on the following assumptions:
• | Normal weather patterns are experienced for the remainder of the year; |
• | Gross margin on revenues of approximately $1.290 billion to $1.295 billion based on sales growth of approximately 1.5 percent on a weather-adjusted basis; |
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• | Approximately $75 million of gross margin is primarily attributed to regionally allocated transmission projects; |
• | Operating expenses of approximately $770 million to $780 million, with operation and maintenance expenses comprising 57 percent of the total; |
• | Interest expense of approximately $130 million to $135 million which assumes a $3 million allowance for borrowed funds used during construction reduction to interest expense and $250 million of long-term debt issued in the first half of 2013; |
• | Allowance for equity funds used during construction of approximately $10 million; and |
• | An effective tax rate of approximately 28 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.
Results of Operations
The following discussion and analysis presents factors that affected OG&E's results of operations for the years ended December 31, 2012, 2011 and 2010 and OG&E's financial position at December 31, 2012 and 2011. 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.
Year ended December 31 (In millions) | 2012 | 2011 | 2010 | ||||||
Operating income | $ | 489.4 | $ | 472.3 | $ | 413.7 | |||
Net income | $ | 280.3 | $ | 263.3 | $ | 215.7 |
In reviewing its operating results, OG&E believes that it is appropriate to focus on operating income as reported in its Statements of Income as operating income indicates the ongoing profitability of OG&E excluding the cost of capital and income taxes.
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Year ended December 31 (Dollars in millions) | 2012 | 2011 | 2010 | ||||||
Operating revenues | $ | 2,141.2 | $ | 2,211.5 | $ | 2,109.9 | |||
Cost of goods sold | 879.1 | 1,013.5 | 1,000.2 | ||||||
Gross margin on revenues | 1,262.1 | 1,198.0 | 1,109.7 | ||||||
Other operation and maintenance | 446.3 | 436.0 | 418.1 | ||||||
Depreciation and amortization | 248.7 | 216.1 | 208.7 | ||||||
Taxes other than income | 77.7 | 73.6 | 69.2 | ||||||
Operating income | 489.4 | 472.3 | 413.7 | ||||||
Interest income | 0.2 | 0.5 | 0.1 | ||||||
Allowance for equity funds used during construction | 6.2 | 20.4 | 11.4 | ||||||
Other income | 8.0 | 8.0 | 6.5 | ||||||
Other expense | 4.3 | 8.4 | 1.6 | ||||||
Interest expense | 124.6 | 111.6 | 103.4 | ||||||
Income tax expense | 94.6 | 117.9 | 111.0 | ||||||
Net income | $ | 280.3 | $ | 263.3 | $ | 215.7 | |||
Operating revenues by classification | |||||||||
Residential | $ | 878.0 | $ | 943.5 | $ | 894.8 | |||
Commercial | 523.5 | 531.3 | 521.0 | ||||||
Industrial | 206.8 | 216.0 | 212.5 | ||||||
Oilfield | 163.4 | 165.1 | 162.8 | ||||||
Public authorities and street light | 202.4 | 207.4 | 200.8 | ||||||
Sales for resale | 54.9 | 65.3 | 65.8 | ||||||
System sales revenues | 2,029.0 | 2,128.6 | 2,057.7 | ||||||
Off-system sales revenues | 36.5 | 36.2 | 21.7 | ||||||
Other | 75.7 | 46.7 | 30.5 | ||||||
Total operating revenues | $ | 2,141.2 | $ | 2,211.5 | $ | 2,109.9 | |||
MWH sales by classification (In millions) | |||||||||
Residential | 9.1 | 9.9 | 9.6 | ||||||
Commercial | 7.0 | 6.9 | 6.7 | ||||||
Industrial | 4.0 | 3.9 | 3.8 | ||||||
Oilfield | 3.3 | 3.2 | 3.1 | ||||||
Public authorities and street light | 3.3 | 3.2 | 3.0 | ||||||
Sales for resale | 1.3 | 1.4 | 1.4 | ||||||
System sales | 28.0 | 28.5 | 27.6 | ||||||
Off-system sales | 1.4 | 1.0 | 0.5 | ||||||
Total sales | 29.4 | 29.5 | 28.1 | ||||||
Number of customers | 798,110 | 789,146 | 782,558 | ||||||
Weighted-average cost of energy per kilowatt-hour - cents | |||||||||
Natural gas | 2.930 | 4.328 | 4.638 | ||||||
Coal | 2.310 | 2.064 | 1.911 | ||||||
Total fuel | 2.437 | 2.897 | 3.012 | ||||||
Total fuel and purchased power | 2.806 | 3.215 | 3.309 | ||||||
Degree days (A) | |||||||||
Heating - Actual | 2,667 | 3,359 | 3,528 | ||||||
Heating - Normal | 3,349 | 3,631 | 3,631 | ||||||
Cooling - Actual | 2,561 | 2,776 | 2,328 | ||||||
Cooling - Normal | 2,092 | 1,911 | 1,911 |
(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. |
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2012 compared to 2011. OG&E's operating income increased $17.1 million, or 3.6 percent, in 2012 as compared to 2011 primarily due to a higher gross margin partially offset by higher other operation and maintenance expense and higher depreciation and amortization expense.
Gross Margin
Operating revenues were $2,141.2 million in 2012 as compared to $2,211.5 million in 2011, a decrease of $70.3 million, or 3.2 percent. Cost of goods sold was $879.1 million in 2012 as compared to $1,013.5 million in 2011, a decrease of $134.4 million, or 13.3 percent. Gross margin was $1,262.1 million in 2012 as compared to $1,198.0 million in 2011, an increase of $64.1 million, or 5.4 percent. The below factors contributed to the change in gross margin:
$ Change | |||
(In millions) | |||
Price variance (A) | $ | 54.1 | |
Wholesale transmission revenue (B) | 28.5 | ||
New customer growth | 11.5 | ||
Non-residential demand and related revenues | 4.9 | ||
Enogex transportation credit (C) | 3.3 | ||
Arkansas rate increase | 2.8 | ||
Oklahoma rate increase | 2.7 | ||
Renewal of wholesale contract with customer | 1.3 | ||
Other | 0.3 | ||
Quantity variance (primarily weather) | (45.3 | ) | |
Change in gross margin | $ | 64.1 |
(A) | Increased due to revenues from the recovery of investments, including the Crossroads wind farm and smart grid. |
(B) | Increased primarily due to the inclusion of construction work in progress in transmission rates for specific FERC approved projects that previously accrued allowance for funds used during construction. |
(C) | Increased due to a credit to OG&E's customers in 2011 related to the settlement of OG&E's 2009 fuel adjustment clause review. |
Cost of goods sold for OG&E consists of fuel used in electric generation, purchased power and transmission related charges. Fuel expense was $642.4 million in 2012 as compared to $775.0 million in 2011, a decrease of $132.6 million, or 17.1 percent, primarily due to lower 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 2012, OG&E's fuel mix was 52 percent coal, 42 percent natural gas and six percent wind. In 2011, OG&E's fuel mix was 58 percent coal, 39 percent natural gas and three percent wind. Purchased power costs were $223.0 million in 2012 as compared to $230.7 million in 2011, a decrease of $7.7 million, or 3.3 percent, primarily due to a decrease in cogeneration purchases and purchases in the energy imbalance service market due to milder weather partially offset by an increase in short-term power purchases. Transmission related charges were $13.7 million in 2012 as compared to $7.8 million in 2011, an increase of $5.9 million, or 75.6 percent, primarily due to higher SPP charges for the base plan projects of other utilities.
Variances in the actual cost of fuel used in electric generation and certain purchased power costs, as compared to the fuel component included in the cost-of-service for ratemaking, 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 Enogex.
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Operating Expenses
Other operation and maintenance expenses were $446.3 million in 2012 as compared to $436.0 million in 2011, an increase of $10.3 million, or 2.4 percent. The below factors contributed to the change in other operations and maintenance expense:
$ Change | |||
(In millions) | |||
Salaries and wages (A) | $ | 6.4 | |
Contract professional and technical services (related to smart grid) (B) | 4.2 | ||
Employee benefits (C) | 3.4 | ||
Administration and assessment fees (primarily SPP and North American Electric Reliability Corporation) | 3.4 | ||
Wind farm lease expense (primarily Crossroads) (B) | 3.0 | ||
Injuries and damages | 1.9 | ||
Ongoing maintenance at power plants (B) | 1.9 | ||
Software (primarily smart grid) (B) | 1.8 | ||
Other | 0.2 | ||
Temporary labor | (1.7 | ) | |
Uncollectibles | (2.4 | ) | |
Vegetation management (primarily system hardening) (B) | (3.0 | ) | |
Allocations from holding company (primarily lower contract professional services and lower payroll and benefits) | (3.1 | ) | |
Capitalized labor | (5.7 | ) | |
Change in other operation and maintenance expense | $ | 10.3 |
(A) | Increased primarily due to salary increases and an increase in incentive compensation expense partially offset by lower headcount in 2012 and a decrease in overtime expense. |
(B) | Includes costs that are being recovered through a rider. |
(C) | Increased primarily due to an increase in worker's compensation accruals, an increase in medical expense and an increase in postretirement medical expense partially offset by a decrease in pension expense. |
Depreciation and amortization expense was $248.7 million in 2012 as compared to $216.1 million in 2011, an increase of $32.6 million, or 15.1 percent, primarily due to additional assets being placed in service throughout 2011 and 2012, including the Crossroads wind farm, which was fully in service in January 2012, the Sooner-Rose Hill and Sunnyside-Hugo transmission projects, which were fully in service in April 2012, and the smart grid project which was completed in late 2012.
Additional Information
Allowance for Equity Funds Used During Construction. Allowance for equity funds used during construction was $6.2 million in 2012 as compared to $20.4 million in 2011, a decrease of $14.2 million, or 69.6 percent, primarily due to higher levels of construction costs for the Crossroads wind farm in 2011.
Other Income. Other income was $8.0 million in both 2012 and 2011. Factors affecting other income included an increased margin of $8.8 million recognized in the guaranteed flat bill program in 2012 as a result of milder weather offset by a decrease of $8.9 million related to the benefit associated with the tax gross-up of allowance for equity funds used during construction.
Other Expense. Other expense was $4.3 million in 2012 as compared to $8.4 million in 2011, a decrease of $4.1 million, or 48.8 percent primarily due to a decrease in charitable contributions.
Interest Expense. Interest expense was $124.6 million in 2012 as compared to $111.6 million in 2011, an increase of $13.0 million, or 11.6 percent, primarily due to a $6.9 million increase in interest expense related to lower allowance for borrowed funds used during construction costs for the Crossroads wind farm in 2011 and a $5.5 million increase in interest expense related to the issuance of long-term debt in May 2011.
Income Tax Expense. Income tax expense was $94.6 million in 2012 as compared to $117.9 million in 2011, a decrease of $23.3 million, or 19.8 percent. The decrease in income tax expense was primarily due to an increase in the amount of Federal
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renewable energy tax credits recognized associated with the Crossroads wind farm and lower pre-tax income in 2012 as compared to 2011.
2011 compared to 2010. OG&E's operating income increased $58.6 million, or 14.2 percent, in 2011 as compared to 2010 primarily due to a higher gross margin partially offset by higher other operation and maintenance expense.
Gross Margin
Operating revenues were $2,211.5 million in 2011 as compared to $2,109.9 million in 2010, an increase of $101.6 million, or 4.8 percent. Cost of goods sold was $1,013.5 million in 2011 as compared to $1,000.2 million in 2010, an increase of $13.3 million, or 1.3 percent. Gross margin was $1,198.0 million in 2011 as compared to $1,109.7 million in 2010, an increase of $88.3 million, or 8.0 percent. The below factors contributed to the change in gross margin:
$ Change | |||
(In millions) | |||
Quantity variance (primarily weather) | $ | 27.4 | |
Price variance (A) | 23.9 | ||
Transmission revenue (B) | 15.3 | ||
New customer growth | 13.1 | ||
Arkansas rate increase | 6.0 | ||
Non-residential demand and related revenues | 5.0 | ||
Renewal of wholesale contract with customer | 3.1 | ||
Other | 0.2 | ||
Enogex transportation credit (C) | (5.7 | ) | |
Change in gross margin | $ | 88.3 |
(A) | Increased due to revenues from the recovery of investments, including the Windspeed transmission line, Oklahoma demand program, smart grid, system hardening, storm recovery, the Crossroads wind farm and the OU Spirit wind farm, and higher revenues from industrial and oilfield customers. |
(B) | Increased primarily due to the inclusion of construction work in progress in transmission rates for specific FERC approved projects that previously accrued allowance for funds used during construction. |
(C) | Decreased due to a credit to OG&E's customers in 2011 related to the settlement of OG&E's 2009 fuel adjustment clause review. |
Fuel expense was $775.0 million in 2011 as compared to $771.0 million in 2010, an increase of $4.0 million, or 0.5 percent, primarily due to higher generation primarily due to warmer weather in OG&E's service territory. 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 2011, OG&E's fuel mix was 58 percent coal, 39 percent natural gas and three percent wind. In 2010, OG&E's fuel mix was 55 percent coal, 42 percent natural gas and three percent wind. Purchased power costs were $230.7 million in 2011 as compared to $226.5 million in 2010, an increase of $4.2 million, or 1.9 percent, primarily due to an increase in short-term power purchases partially offset by a decrease in purchases in the energy imbalance service market and a decrease in cogeneration cost.
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Operating Expenses
Other operation and maintenance expenses were $436.0 million in 2011 as compared to $418.1 million in 2010, an increase of $17.9 million, or 4.3 percent. The below factors contributed to the change in other operations and maintenance expense:
$ Change | |||
(In millions) | |||
Allocations from holding company (A) | $ | 15.5 | |
Salaries and wages (B) | 12.1 | ||
Other marketing and sales expense (primarily demand-side management initiatives) (C) | 4.6 | ||
Uncollectible expense | 3.1 | ||
Fleet transportation expense (primarily higher fuel costs in 2011) | 1.6 | ||
Temporary labor expense | 1.3 | ||
Administration and assessment fees (primarily SPP) | 1.2 | ||
Vegetation management (primarily system hardening) (C) | (2.9 | ) | |
Other | (3.8 | ) | |
Injuries and damages (primarily higher reserves on claims in 2010) | (5.0 | ) | |
Employee benefits (D) | (9.8 | ) | |
Change in other operation and maintenance expense | $ | 17.9 |
(A) | Increased primarily related to payroll and benefits expense, contract technical and construction services and contract professional services. |
(B) | Increased primarily due to salary increases in 2011, increased incentive compensation expense and increased overtime expense primarily due to storms in April and August 2011. |
(C) | Includes costs that are being recovered through a rider. |
(D) | Decreased primarily due to a decrease in postretirement benefits expense related to amendments to OGE Energy's retiree medical plan adopted in January 2011 (see Note 11 of Notes to Financial Statements) partially offset by a modification to OG&E's pension tracker and a decrease in worker's compensation accruals in 2011. |
Allowance for Equity Funds Used During Construction. Allowance for equity funds used during construction was $20.4 million in 2011 as compared to $11.4 million in 2010, an increase of $9.0 million, or 78.9 percent, primarily due to higher levels of construction costs for the Crossroads wind farm in 2011.
Other Income. Other income was $8.0 million in 2011 as compared to $6.5 million in 2010, an increase of $1.5 million, or 23.1 percent. The increase in other income was primarily due to a benefit of $5.6 million associated with the tax gross-up of allowance for equity funds used during construction partially offset by increased losses of $4.2 million recognized in the guaranteed flat bill program in 2011 from higher than expected usage resulting from warmer weather.
Other Expense. Other expense was $8.4 million in 2011 as compared to $1.6 million in 2010, an increase of $6.8 million, primarily due to an increase in charitable contributions of $6.4 million as the holding company made the charitable contributions in 2010.
Interest Expense. Interest expense was $111.6 million in 2011 as compared to $103.4 million in 2010, an increase of $8.2 million, or 7.9 percent, primarily due to a $14.0 million increase related to the issuance of long-term debt in June 2010 and May 2011. This increase in interest expense was partially offset by:
• | a $4.9 million decrease in interest expense due to a higher allowance for borrowed funds used during construction primarily due to construction costs for the Crossroads wind farm; and |
• | a $1.4 million decrease in interest expense in 2011 due to interest to customers related to the fuel over recovery balance in 2010. |
Income Tax Expense. Income tax expense was $117.9 million in 2011 as compared to $111.0 million in 2010, an increase of $6.9 million, or 6.2 percent. The increase in income tax expense was primarily due to higher pre-tax income in 2011 as compared to 2010. This increase in income tax expense was partially offset by:
• | the one-time, non-cash charge in 2010 for the elimination of the tax deduction for the Medicare Part D subsidy; |
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• | the write-off of previously recognized Oklahoma investment tax credits in 2010 primarily due to expenditures no longer eligible for the Oklahoma investment tax credit related to the change in the tax method of accounting for capitalization of repair expenditures; and |
• | higher Oklahoma investment tax credits in 2011 as compared to 2010. |
Off-Balance Sheet Arrangement
Railcar Lease Agreement
OG&E has a noncancellable operating lease with purchase options, covering 1,389 coal hopper 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.
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 is also required to maintain all of the railcars it has under lease to transport coal from Wyoming and has entered into agreements with Progress Rail Services and WATCO, both of which are non-affiliated companies, to furnish this maintenance.
OG&E is also required to maintain all of the railcars it has under lease to transport coal from Wyoming and has entered into agreements with Progress Rail Services and WATCO, both of which are non-affiliated companies, to furnish this maintenance.
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 Accounts Receivable, Net and Accrued Unbilled Revenues was $218.9 million and $241.7 million at December 31, 2012 and 2011, respectively, a decrease of $22.8 million, or 9.4 percent, primarily due to a decrease in billings to OG&E's customers in 2012 due to milder weather in 2012 partially offset by higher transmission revenue and increased rates.
The balance of Accounts Payable was $186.7 million and $193.4 million at December 31, 2012 and 2011, respectively, a decrease of $6.7 million, or 3.5 percent, primarily due to the timing of ad valorem payments.
Cash Flows
2012 vs. 2011 | 2011 vs. 2010 | ||||||||||||||||||
Year ended December 31 (In millions) | 2012 | 2011 | 2010 | $ Change | % Change | $ Change | % Change | ||||||||||||
Net cash provided from operating activities | $ | 737.4 | $ | 549.3 | $ | 465.7 | $ | 188.1 | 34.2 | % | $ | 83.6 | 18.0 | % | |||||
Net cash used in investing activities | (676.3 | ) | (794.3 | ) | (602.1 | ) | 118.0 | (14.9 | )% | (192.2 | ) | 31.9 | % | ||||||
Net cash provided from (used in) financing activities | (61.1 | ) | 245.0 | 136.4 | (306.1 | ) | * | 108.6 | 79.6 | % |
* Percentage is greater than 100 percent.
Operating Activities
The increase of $188.1 million, or 34.2 percent, in net cash provided from operating activities in 2012 as compared to 2011 was primarily due to:
• | higher fuel recoveries in 2012 as compared to 2011; and |
• | an increase in cash received in 2012 from transmission revenue and the recovery of investments including the Crossroads wind farm and smart grid partially offset by milder weather in 2012. |
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The increase of $83.6 million, or 18.0 percent, in net cash provided from operating activities in 2011 as compared to 2010 was primarily due to:
• | lower fuel refunds in 2011 as compared to 2010; and |
• | cash received in 2011 from an increase in billings to OG&E's customers due to warmer weather in OG&E's service territory in 2011. |
These increases in net cash provided from operating activities was partially offset by income tax refunds received in 2010 related to a carry back of the 2008 tax loss resulting from a change in tax method of accounting for capitalization of repair expenditures and accelerated tax bonus depreciation.
Investing Activities
The decrease of $118.0 million, or 14.9 percent, in net cash used in investing activities in 2012 as compared to 2011 was primarily due to lower levels of capital expenditures in 2012 related to the Crossroads wind farm.
The increase of $192.2 million, or 31.9 percent, in net cash used in investing activities in 2011 as compared to 2010 primarily related to higher levels of capital expenditures in 2011 related to various transmission projects and the Crossroads wind farm.
Financing Activities
The decrease of $306.1 million in net cash provided from financing activities in 2012 as compared to 2011 was primarily due to:
• | proceeds received from the issuance of long-term debt during 2011; |
• | dividend payments in 2012; and |
• | a capital contribution from OGE Energy during 2011. |
These decreases in net cash provided from financing activities were partially offset by an increase in net advances with OGE Energy during 2012.
The increase of $108.6 million, or 79.6 percent, in net cash provided from financing activities in 2011 as compared to 2010 was primarily due to a capital contribution from OGE Energy and a decrease in dividends paid.
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, hedging activities, 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.
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Capital Expenditures
OG&E's estimates of capital expenditures for the years 2013 through 2017 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.
(In millions) | 2013 | 2014 | 2015 | 2016 | 2017 | ||||||||||
Base Transmission | $ | 65 | $ | 50 | $ | 50 | $ | 50 | $ | 50 | |||||
Base Distribution | 175 | 175 | 175 | 175 | 175 | ||||||||||
Base Generation | 80 | 75 | 75 | 75 | 75 | ||||||||||
Other | 15 | 15 | 15 | 15 | 15 | ||||||||||
Total Base Transmission, Distribution, Generation and Other | 335 | 315 | 315 | 315 | 315 | ||||||||||
Known and Committed Projects: | |||||||||||||||
Transmission Projects: | |||||||||||||||
Balanced Portfolio 3E Projects (A) | 205 | 25 | — | — | — | ||||||||||
SPP Priority Projects (B) | 165 | 110 | — | — | — | ||||||||||
SPP Integrated Transmission Projects (C) | 5 | 5 | — | 40 | 40 | ||||||||||
Total Transmission Projects | 375 | 140 | — | 40 | 40 | ||||||||||
Other Projects: | |||||||||||||||
Smart Grid Program | 25 | 25 | 10 | 10 | — | ||||||||||
System Hardening | 15 | — | — | — | — | ||||||||||
Environmental - low NOX burners | 30 | 20 | 25 | 20 | — | ||||||||||
Total Other Projects | 70 | 45 | 35 | 30 | — | ||||||||||
Total Known and Committed Projects | 445 | 185 | 35 | 70 | 40 | ||||||||||
Total (D) | $ | 780 | $ | 500 | $ | 350 | $ | 385 | $ | 355 |
(A) | Balanced Portfolio 3E includes three projects to be built by OG&E and includes: (i) construction of 135 miles of transmission line from OG&E's Seminole substation in a northeastern direction to OG&E's Muskogee substation at an estimated cost of $175 million for OG&E, which is expected to be in service by late 2013, (ii) construction of 96 miles of transmission line from OG&E's Woodward District Extra High Voltage substation in a southwestern direction to the Oklahoma/Texas Stateline to a companion transmission line to be built by Southwestern Public Service to its Tuco substation at an estimated cost of $115 million for OG&E, which is expected to be in service by mid-2014 and (iii) construction of 39 miles of transmission line from OG&E's Sooner substation in an eastern direction to the Grand River Dam Authority Cleveland substation at an estimated cost of $45 million for OG&E, which was placed in service in February 2013. |
(B) | The Priority Projects consist of several transmission projects, two of which have been assigned to OG&E. The 345 kilovolt projects include: (i) construction of 99 miles of transmission line from OG&E's Woodward District Extra High Voltage substation to a companion transmission line to be built by Southwestern Public Service to its Hitchland substation in the Texas Panhandle at an estimated cost of $185 million for OG&E, which is expected to be in service by mid-2014 and (ii) construction of 77 miles of transmission line from OG&E's Woodward District Extra High Voltage substation to a companion transmission line at the Kansas border to be built by either Mid-Kansas Electric Company or another company assigned by Mid-Kansas Electric Company at an estimated cost of $150 million to OG&E, which is expected to be in service by late 2014. OG&E began construction on the Hitchland project in November 2012 and expects to begin construction on the Kansas project in June 2013. |
(C) | On January 31, 2012, the SPP approved the Integrated Transmission Plan Near Term and Integrated Transmission Plan 10-year projects. These plans include two projects to be built by OG&E: (i) construction of 47 miles of transmission line from OG&E's Gracemont substation in a northwestern direction to a companion transmission line to be built by American Electric Power to its Elk City substation at an estimated cost of $75 million for OG&E, which is expected to be in service by early 2018, and (ii) construction of 126 miles of transmission line from OG&E's Woodward District Extra High Voltage substation in a southeastern direction to OG&E's Cimarron substation and construction of a new substation on this transmission line, the Mathewson substation, at an estimated cost of $210 million for OG&E, which is expected to be in service by early 2021. On April 9, 2012, OG&E received a notice to construct these projects from the SPP. On June 26, 2012, OG&E responded to the SPP that OG&E will construct the projects discussed above and is moving forward with more detailed cost estimates that must be reviewed and approved by the SPP. OG&E and American Electric Power are currently in discussions regarding how much of the 94 mile Elk City to Gracemont transmission line will be built by OG&E and American Electric Power. American Electric Power has argued for a larger portion of such transmission line than the traditional 50 percent split. The capital |
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expenditures related to these projects are presented in the summary of capital expenditures for known and committed projects above.
(D) | The capital expenditures above exclude any environmental expenditures associated with: |
• | Pollution control equipment related to controlling SO2 emissions under the regional haze requirements due to the uncertainty regarding the approach and timing for such pollution control equipment. The SO2 emissions standards in the EPA's FIP could require the installation of Dry Scrubbers or fuel switching. OG&E estimates that installing such Dry Scrubbers could cost more than $1.0 billion. The FIP is being challenged by OG&E and the state of Oklahoma. On June 22, 2012, OG&E was granted a stay of the FIP by the U.S. Court of Appeals for the Tenth Circuit, which delays the timing of required implementation of the SO2 emissions standards in the rule. The merits of the appeal have been fully briefed, and oral argument is scheduled to occur on March 6, 2013. Neither the outcome of the challenge to the FIP nor the timing of any required capital expenditures can be predicted with any certainty at this time, but such capital expenditures could be significant. |
• | Installation of control equipment for compliance with MATS by a deadline of April 16, 2015, with the possibility of a one-year extension. OG&E is currently planning to utilize activated carbon injection and low levels of dry sorbent injection at each of its five coal-fired units. Due to various uncertainties about the final design, the potential use of this technology relating to regional haze measures and the specifications for the control equipment, the resulting cost estimates currently range from $34 million to $72 million per unit. |
OG&E is currently evaluating options to comply with environmental requirements. For further information, see "Environmental Laws and Regulations" below.
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, 2012. See OG&E's Statements of Capitalization and Note 12 of Notes to Financial Statements for additional information.
(In millions) | 2013 | 2014-2015 | 2016-2017 | After 2017 | Total | ||||||||||
Maturities of long-term debt (A) | $ | 0.2 | $ | 0.4 | $ | 235.4 | $ | 1,820.1 | $ | 2,056.1 | |||||
Operating lease obligations | |||||||||||||||
Railcars | 3.2 | 5.5 | 27.3 | — | 36.0 | ||||||||||
Wind farm land leases | 2.0 | 4.2 | 4.5 | 51.2 | 61.9 | ||||||||||
Total operating lease obligations | 5.2 | 9.7 | 31.8 | 51.2 | 97.9 | ||||||||||
Other purchase obligations and commitments | |||||||||||||||
Cogeneration capacity and fixed operation and maintenance payments | 87.9 | 170.3 | 162.5 | 315.3 | 736.0 | ||||||||||
Expected cogeneration energy payments | 58.6 | 134.3 | 168.3 | 468.7 | 829.9 | ||||||||||
Minimum fuel purchase commitments | 452.5 | 535.6 | — | — | 988.1 | ||||||||||
Expected wind purchase commitments | 57.5 | 116.9 | 120.6 | 838.0 | 1,133.0 | ||||||||||
Long-term service agreement commitments | 8.0 | 34.5 | 12.6 | 53.0 | 108.1 | ||||||||||
Total other purchase obligations and commitments | 664.5 | 991.6 | 464.0 | 1,675.0 | 3,795.1 | ||||||||||
Total contractual obligations | 669.9 | 1,001.7 | 731.2 | 3,546.3 | 5,949.1 | ||||||||||
Amounts recoverable through fuel adjustment clause (B) | (571.8 | ) | (792.3 | ) | (316.2 | ) | (1,306.7 | ) | (2,987.0 | ) | |||||
Total contractual obligations, net | $ | 98.1 | $ | 209.4 | $ | 415.0 | $ | 2,239.6 | $ | 2,962.1 |
(A) | Maturities of OG&E's long-term debt during the next five years consist of $0.2 million, $0.2 million, $0.2 million, $110.2 million and $125.2 million in years 2013, 2014, 2015, 2016 and 2017, 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. |
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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.
Variances in 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, as compared to the fuel component included in the cost-of-service for ratemaking, 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, 2012, 42.3 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 2012, asset returns on the Pension Plan were 10.6 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, have continued to decline. During 2012 and 2011, OGE Energy made contributions to its Pension Plan of $35 million and $50 million, respectively, of which $33 million in 2012 and $47 million in 2011 was OG&E's portion, to help ensure that the Pension Plan maintains an adequate funded status. The level of funding is dependent on returns on plan assets and future discount rates. During 2013, OGE Energy expects to contribute up to $35 million to its Pension Plan, of which $33 million is expected to be OG&E's portion. 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, 2012 and 2011. 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.
Pension Plan | Restoration of Retirement Income Plan | Postretirement Benefit Plans | ||||||||||||||||
December 31 (In millions) | 2012 | 2011 | 2012 | 2011 | 2012 | 2011 | ||||||||||||
Benefit obligations | $ | (574.6 | ) | $ | (546.9 | ) | $ | (2.2 | ) | $ | (2.2 | ) | $ | (236.4 | ) | $ | (223.1 | ) |
Fair value of plan assets | 519.0 | 485.9 | — | — | 55.5 | 57.2 | ||||||||||||
Funded status at end of year | $ | (55.6 | ) | $ | (61.0 | ) | $ | (2.2 | ) | $ | (2.2 | ) | $ | (180.9 | ) | $ | (165.9 | ) |
Security Ratings
Moody’s Investors Services | Standard & Poor's Ratings Services | Fitch Ratings | |
Senior Notes | A2 | BBB+ | A+ |
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.
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,
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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.
2012 Capital Requirements, Sources of Financing and Financing Activities
Total capital requirements, consisting of capital expenditures and maturities of long-term debt, were $677.0 million and contractual obligations, net of recoveries through fuel adjustment clauses, were $91.3 million resulting in total net capital requirements and contractual obligations of $768.3 million in 2012, of which $12.4 million was to comply with environmental regulations. This compares to net capital requirements of $794.8 million and net contractual obligations of $91.0 million totaling $885.8 million in 2011, of which $6.4 million was to comply with environmental regulations.
In 2012, OG&E's sources of capital were cash generated from operations and proceeds from the issuance of short-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.
Potential Collateral Requirements
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. The scope of the margin requirements and their potential direct impact on OG&E remain unclear because final rules have not been issued. Further, 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, 2012 and 2011, there were $90.3 million and $97.2 million, respectively, in net outstanding advances to OGE Energy. 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, 2016. At December 31, 2012, 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, 2012, there was $2.2 million supporting letters of credit at a weighted-average interest rate of 0.53 percent. There were no outstanding borrowings under this revolving credit agreement and no outstanding commercial paper borrowings at December 31, 2012. At December 31, 2012, OG&E had $397.8 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, 2013 and ending December 31, 2014. At December 31, 2012, OG&E had less than $0.1 million in cash and cash equivalents. See Note 10 of Notes to Financial Statements for a discussion of OG&E's short-term debt activity.
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Expected Issuance of Long-Term Debt
OG&E expects to issue up to $250 million of long-term debt in the first half of 2013, depending on market conditions, to fund capital expenditures, repay short-term borrowings and for general corporate purposes.
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, but conservative, 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, impairment estimates of long-lived assets (including intangible assets), income taxes, contingency reserves, asset retirement obligations, fair value and cash flow hedges, the allowance for uncollectible accounts receivable, the valuation 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 11 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.
Change | Impact on Funded Status | |
Actual plan asset returns | +/- 1 percent | +/- $6.3 million |
Discount rate | +/- 0.25 percent | +/- $16.7 million |
Contributions | +/- $10 million | +/- $10 million |
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.
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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.
Except as disclosed otherwise in this Form 10-K, 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.
Asset Retirement Obligations
OG&E has previously recorded asset retirement obligations that are being amortized over their respective lives ranging from five 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
OG&E designates as cash flow hedges derivatives used to manage commodity price risk exposure for its natural gas exposure associated with a wholesale power sales contract that expires in December 2013. 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.
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.
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 actual or anticipated 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 actual or anticipated 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, prior service cost and net transition obligation.
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, 2012, 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, 2012 and 2011, Accrued Unbilled Revenues were $57.4 million and $59.3 million, respectively. The estimates that management uses in this calculation could vary from the actual amounts to be paid by customers.
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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 is being recovered through the fuel adjustment clause. At December 31, 2012, if the provision rate were to increase or decrease by 10 percent, this would cause a change in the uncollectible expense recognized of $0.3 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 $2.6 million and $3.7 million at December 31, 2012 and 2011, respectively.
Accounting Pronouncement
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, except as disclosed otherwise in this Form 10-K, 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 stringent and complex Federal, state and local laws and regulations governing environmental protection including the discharge of materials into the environment. These laws and regulations can restrict or impact business activities in many ways, such as restricting the way it can handle or dispose of its wastes, requiring remedial action to mitigate pollution conditions that may be caused by its operations or that are attributable to former operators, regulating future construction activities to mitigate harm to threatened or endangered species and requiring the installation and operation of pollution control equipment. Failure to comply with these laws and regulations may 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 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.
OG&E expects that significant future capital 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 2013 will be $63.0 million, of which $45.3 million is for capital expenditures. It is estimated that OG&E's total expenditures to comply for environmental laws, regulations and requirements for 2014 will be $37.7 million, of which $19.2 million is for capital expenditures. The amounts above include capital expenditures for low NOX burners and exclude certain other capital expenditures as discussed in the capital expenditures table and related footnote D in "Future Capital Requirements and Financing Activities" above. 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.
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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
On June 15, 2005, the EPA issued final amendments to its 1999 regional haze rule. Regional haze is visibility impairment caused by the cumulative air pollutant emissions from numerous sources over a wide geographic area. The regional haze rule is intended to protect visibility in certain national parks and wilderness areas throughout the United States. In Oklahoma, the Wichita Mountains are the only area covered under the rule. However, Oklahoma's impact on parks in other states must also be evaluated.
As required by the Federal regional haze rule, the state of Oklahoma evaluated the installation of BART to reduce emissions that cause or contribute to regional haze from certain sources within the state that were built between 1962 and 1977. Certain of OG&E’s units at the Horseshoe Lake, Seminole, Muskogee and Sooner generating stations were evaluated for BART. 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 overfire air (flue gas recirculation was also required on two of the units) and set forth associated NOX emission rates and limits. OG&E preliminarily estimates that the total capital cost of installing and operating these NOX controls on all covered units, based on recent industry experience and past projects, will be approximately $95 million. With respect to SO2 emissions, the SIP included an agreement between the Oklahoma Department of Environmental Quality and OG&E that established BART for SO2 control at the four affected coal-fired units located at OG&E's Sooner and Muskogee generating stations as the continued use of low sulfur coal (along with associated emission rates and limits). The SIP specifically rejected the installation and operation of Dry Scrubbers as BART for SO2 control from these units because the state determined that Dry Scrubbers were not cost effective on these units.
On December 28, 2011, the EPA issued a final rule in which it rejected portions of the Oklahoma SIP and issued a FIP in their place. While the EPA accepted Oklahoma's BART determination for NOX in the final rule, it rejected Oklahoma's SO2 BART determination with respect to the four coal-fired units at the Sooner and Muskogee generating stations. The EPA is instead requiring that OG&E meet an SO2 emission rate of 0.06 pounds per MMBtu within five years. OG&E could meet the proposed standard by either installing and operating Dry Scrubbers or fuel switching at the four affected units. OG&E estimates that installing Dry Scrubbers on these units would include capital costs to OG&E of more than $1.0 billion. OG&E and the state of Oklahoma filed an administrative stay request with the EPA on February 24, 2012. The EPA has not yet responded to this request. OG&E and other parties also filed a petition for review of the FIP in the U.S. Court of Appeals for the Tenth Circuit on February 24, 2012 and a stay request on April 4, 2012. On June 22, 2012, the U.S. Court of Appeals for the Tenth Circuit granted the stay request. The stay will remain in place until a decision on the petition for review is complete, which will delay the implementation of the regional haze rule in Oklahoma. The merits of the appeal have been fully briefed and oral argument is scheduled to occur on March 6, 2013. Neither the outcome of the appeal nor the timing of any required expenditures for pollution control equipment can be predicted with any certainty at this time.
Cross-State Air Pollution Rule
On July 7, 2011, the EPA finalized its Cross-State Air Pollution Rule to replace the former Clean Air Interstate Rule that was remanded by a Federal court as a result of legal challenges. The final rule would require 27 states to reduce power plant emissions that contribute to ozone and particulate matter pollution in other states. On December 27, 2011, the EPA published a
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supplemental 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. The Cross-State Air Pollution Rule was challenged in court by numerous states and power generators. 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 U.S. Court of Appeals vacated the Cross-State Air Pollution Rule and ordered the EPA to promulgate a replacement rule. On January 25, 2013, the U.S. Court of Appeals denied the EPA's request for an en banc reconsideration of the court's decision vacating the rule. OG&E cannot predict the outcome of such challenges.
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. This rule includes numerical standards for particulate matter (as a surrogate for toxic metals), hydrogen chloride and mercury emissions from coal-fired boilers. In addition, the regulations include work practice standards for dioxins and furans. Compliance is required within three years after the effective date of the rule with the possibility of a one-year extension. To comply with this rule, OG&E is currently planning to utilize activated carbon injection and low levels of dry sorbent injection at each of its five coal-fired units. Due to various uncertainties about the final design, the potential use of this technology relating to regional haze measures and the specifications for the control equipment, the resulting cost estimates currently range from $34 million to $72 million per unit. OG&E is evaluating the results of field testing to finalize cost estimates and implementation schedules. The final MATS rule has been appealed by several parties. OG&E is not a party to the appeals and cannot predict the outcome of any such appeals.
Notice of Violation
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. In recent years, the EPA has issued similar requests to numerous other electric utilities seeking to determine whether various maintenance, repair and replacement projects should have required permits under the Federal Clean Air Act's new source review process. In January 2012, OG&E received a supplemental request for an update of the previously provided information and for some additional information not previously requested. On May 1, 2012, OG&E responded to the EPA's supplemental request for information. OG&E believes it has acted in full compliance with the Federal Clean Air Act and new source review process and is cooperating with the EPA. On April 26, 2011, the EPA issued a notice of violation alleging that 13 projects occurred at OG&E's Muskogee and Sooner generating plants between 1993 and 2006 without the required new source review permits. The notice of violation also alleges that OG&E's visible emissions at its Muskogee and Sooner generating plants are not in accordance with applicable new source performance standards. OG&E has met with the EPA regarding the notice but cannot predict at this time what, if any, further actions may be necessary as a result of the notice. The EPA could seek to require OG&E to install additional pollution control equipment 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. The cost of any required pollution control equipment could also be significant.
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 2012, 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.
Acid Rain Program
The Federal Clean Air Act includes an Acid Rain Program. The goal of the Acid Rain Program is to achieve environmental and public health benefits through reductions in SO2 and NOX emissions, which are the primary causes of acid rain. To achieve this goal, the program employs both traditional and market-based approaches for controlling air pollution.
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The Acid Rain Program introduces an allowance trading system that uses the free market to reduce pollution. Under this system, affected utility units are allocated allowances based on their historic fuel consumption and a specific emissions rate. Each allowance permits a unit to emit one ton of SO2 from the chimney during or after a specified year. For each ton of SO2 emitted in a given year, one allowance is retired, that is, it can no longer be used. Allowances may be bought, sold or banked.
During Phase II of the program (now in effect), the Federal Clean Air Act set a permanent ceiling (or cap) of 8.95 million total annual allowances allocated to utilities. This cap firmly restricts emissions and ensures that environmental benefits will be achieved and maintained. Due to OG&E's earlier decision to burn low sulfur coal, these restrictions have had no significant financial impact.
The Acid Rain Program also focuses on one set of sources that emit NOX, coal-fired electric utility boilers. As with the SO2 emission reduction requirements, the NOX program was implemented in two phases, beginning in 1996 and 2000. The NOX program embodies many of the same principles of the SO2 trading program. However, it does not cap NOX emissions as the SO2 program does, nor does it utilize an allowance trading system.
Emission limitations for NOX focus on the emission rate to be achieved (expressed in pounds of NOX per MMBtu of heat input). In general, two options for compliance with the emission limitations are provided: compliance with an individual emission rate for a boiler; or averaging of emission rates over two or more units to meet an overall emission rate limitation.
Since becoming subject to the Acid Rain Program, OG&E has met all obligations and limitations requirements.
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 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.
Following from the Supreme Court's interpretation of the Clean Air Act's applicability to greenhouse gases in Massachusetts v. EPA, the EPA has proposed regulations for new power plants. In 2010, the EPA also issued a final rule that makes certain existing sources subject to permitting requirements for greenhouse gas emissions. This rule requires sources that emit greater than 100,000 tons per year of greenhouse gases to obtain a permit for those emissions, even if they are not otherwise required to obtain a new or modified permit. Such sources that undergo construction or modification may have to install best available control technology to control greenhouse gas emissions. Although these rules currently do not have a material impact on OG&E's existing facilities, they ultimately could result in significant changes to OG&E's operations, significant capital expenditures by OG&E and a significant increase in OG&E's cost of conducting business.
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.
OG&E is continuing to review and evaluate available options for reducing, avoiding, offsetting or sequestering its greenhouse gas emissions. OG&E is a partner in the EPA Sulfur Hexafluoride Voluntary Reduction Program.
OG&E also seeks to utilize renewable energy sources that do not emit greenhouse gases. OG&E's service territory is in central Oklahoma and borders one of the nation's best wind resource areas. OG&E has leveraged its advantageous 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
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significantly 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. A final decision regarding listing is anticipated to be completed by September 30, 2013. Although the lesser prairie chicken and its habitat are located in potential development areas of OG&E, the impact of a final decision to list this species as threatened cannot be determined at this time.
Waste
OG&E's operations generate hazardous 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 hazardous waste.
For OG&E, these laws impose strict "cradle to grave" requirements on generators regarding their treatment, storage and disposal of hazardous waste. OG&E routinely generates small quantities of hazardous waste throughout its system and occasional larger quantities from periodic power generation related activities. These wastes are treated, stored and disposed at facilities that are permitted to manage them.
In June 2010, the EPA proposed new rules under Federal Resource Conservation and Recovery Act of 1976 that could alter the classification of OG&E's coal-fired power plants as conditionally exempt hazardous waste generators and make the management of coal ash more costly. The extent to which the EPA intends to regulate coal ash is uncertain due to the fact that the new rules propose to regulate coal ash as a hazardous waste or as a nonhazardous solid waste. In November 2010, OG&E submitted written comments opposing the regulation of coal ash as a hazardous waste while supporting its regulation as a nonhazardous waste. The EPA continues to consider numerous comments received on the proposal and has stated that no definitive timetable for issuing a final rule regarding the regulation of coal ash can be provided.
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 2012, OG&E obtained refunds of $6.3 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 analogous state laws and regulations. These laws and regulations impose detailed requirements and strict controls regarding the discharge of pollutants into state and Federal waters. The discharge of pollutants, including discharges resulting from a spill or leak, is prohibited unless authorized by a permit or other agency approval. The Federal Clean Water Act and regulations implemented thereunder also prohibit discharges of dredged and fill material in wetlands and other waters of the United States unless authorized by an appropriately issued permit. Existing cooling water intake structures are regulated under the Federal Clean Water Act to minimize their impact on the environment.
With respect to cooling water intake structures, Section 316(b) of the Federal Clean Water Act requires that their location, design, construction and capacity reflect the best available technology for minimizing their adverse environmental impact via the impingement and entrainment of aquatic organisms. In March 2011, the EPA proposed rules to implement Section 316(b). On August 18, 2011, OG&E filed comments with the EPA on the proposed rules. In June 2012, the EPA published a Notice of Data Availability requesting additional comments on a number of impingement mortality-related issues based on new information received during the initial public comment period. On July 11, 2012, OG&E filed comments regarding the Notice of Data Availability. In July 2012, the EPA entered into a settlement agreement in a pending litigation matter, which extended the deadline by which the proposed rules will be finalized to June 2013. In the interim, the state of Oklahoma requires OG&E to implement best management practices related to the operation and maintenance of its existing cooling water intake structures as a condition
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of renewing its discharge permits. Once the EPA promulgates the final rules, OG&E may incur additional capital and/or operating costs to comply with them. The costs of complying with the final water intake standards are not currently determinable, but could be significant.
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. 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 Committee and Oversight
Management monitors market risks using a risk committee structure. The Board of Directors appoints the Chief Risk Officer of OG&E. The Chief Risk Officer serves as chairman of OG&E's Risk Oversight Committee, which consists primarily of corporate officers, and 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, through the Chief Risk Officer, 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 led by OGE Energy's Chief Risk Officer. 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. Some of the measures in these policies include value-at-risk limits, position limits, tenor limits and stop loss limits.
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 utilizes 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.
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Year ended December 31 (Dollars in millions) | 2013 | 2014 | 2015 | 2016 | 2017 | Thereafter | Total | 12/31/12 Fair Value | ||||||||||||||||
Fixed-rate debt (A) | ||||||||||||||||||||||||
Principal amount | $ | 0.2 | $ | 0.2 | $ | 0.2 | $ | 110.2 | $ | 125.2 | $ | 1,684.7 | $ | 1,920.7 | $ | 2,411.6 | ||||||||
Weighted-average interest rate | 2.71 | % | 2.71 | % | 2.71 | % | 5.15 | % | 6.49 | % | 6.40 | % | 6.33 | % | ||||||||||
Variable-rate debt (B) | ||||||||||||||||||||||||
Principal amount | $ | — | $ | — | $ | — | $ | — | $ | — | $ | 135.4 | $ | 135.4 | $ | 135.4 | ||||||||
Weighted-average interest rate | — | — | — | — | — | 0.24 | % | 0.24 | % |
(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. |
Commodity Price Risk
OG&E occasionally uses commodity price swap contracts to manage its commodity price risk exposures. Natural gas swaps are used to manage OG&E's natural gas exposure associated with a wholesale power sales contract as discussed in Note 4 of Notes to Financial Statements.
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Item 8. Financial Statements and Supplementary Data.
OKLAHOMA GAS AND ELECTRIC COMPANY
STATEMENTS OF INCOME
Year ended December 31 (In millions) | 2012 | 2011 | 2010 | ||||||
OPERATING REVENUES | $ | 2,141.2 | $ | 2,211.5 | $ | 2,109.9 | |||
COST OF GOODS SOLD (exclusive of depreciation and amortization shown below) | 879.1 | 1,013.5 | 1,000.2 | ||||||
Gross margin on revenues | 1,262.1 | 1,198.0 | 1,109.7 | ||||||
OPERATING EXPENSES | |||||||||
Other operation and maintenance | 446.3 | 436.0 | 418.1 | ||||||
Depreciation and amortization | 248.7 | 216.1 | 208.7 | ||||||
Taxes other than income | 77.7 | 73.6 | 69.2 | ||||||
Total operating expenses | 772.7 | 725.7 | 696.0 | ||||||
OPERATING INCOME | 489.4 | 472.3 | 413.7 | ||||||
OTHER INCOME (EXPENSE) | |||||||||
Interest income | 0.2 | 0.5 | 0.1 | ||||||
Allowance for equity funds used during construction | 6.2 | 20.4 | 11.4 | ||||||
Other income | 8.0 | 8.0 | 6.5 | ||||||
Other expense | (4.3 | ) | (8.4 | ) | (1.6 | ) | |||
Net other income | 10.1 | 20.5 | 16.4 | ||||||
INTEREST EXPENSE | |||||||||
Interest on long-term debt | 124.2 | 118.7 | 104.7 | ||||||
Allowance for borrowed funds used during construction | (3.5 | ) | (10.4 | ) | (5.5 | ) | |||
Interest on short-term debt and other interest charges | 3.9 | 3.3 | 4.2 | ||||||
Interest expense | 124.6 | 111.6 | 103.4 | ||||||
INCOME BEFORE TAXES | 374.9 | 381.2 | 326.7 | ||||||
INCOME TAX EXPENSE | 94.6 | 117.9 | 111.0 | ||||||
NET INCOME | $ | 280.3 | $ | 263.3 | $ | 215.7 |
The accompanying Notes to Financial Statements are an integral part hereof.
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OKLAHOMA GAS AND ELECTRIC COMPANY
STATEMENTS OF COMPREHENSIVE INCOME
Year ended December 31 (In millions) | 2012 | 2011 | 2010 | ||||||
Net income | $ | 280.3 | $ | 263.3 | $ | 215.7 | |||
Other comprehensive income (loss), net of tax | |||||||||
Deferred commodity contracts hedging losses reclassified in net income, net of tax of $0.9, $0.6 and $0.3, respectively | 1.5 | 0.9 | 0.5 | ||||||
Deferred commodity contracts hedging losses, net of tax of ($0.2), ($0.7) and ($1.4), respectively | (0.3 | ) | (1.3 | ) | (2.2 | ) | |||
Other comprehensive income (loss), net of tax | 1.2 | (0.4 | ) | (1.7 | ) | ||||
Comprehensive income (loss) | $ | 281.5 | $ | 262.9 | $ | 214.0 |
The accompanying Notes to Financial Statements are an integral part hereof.
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OKLAHOMA GAS AND ELECTRIC COMPANY
STATEMENTS OF CASH FLOWS
Year ended December 31 (In millions) | 2012 | 2011 | 2010 | ||||||
CASH FLOWS FROM OPERATING ACTIVITIES | |||||||||
Net income | $ | 280.3 | $ | 263.3 | $ | 215.7 | |||
Adjustments to reconcile net income to net cash provided from operating activities | |||||||||
Depreciation and amortization | 248.7 | 216.1 | 208.7 | ||||||
Deferred income taxes and investment tax credits, net | 103.3 | 95.0 | 118.8 | ||||||
Allowance for equity funds used during construction | (6.2 | ) | (20.4 | ) | (11.4 | ) | |||
Stock-based compensation expense | 2.6 | 3.0 | — | ||||||
Regulatory assets | 20.3 | 14.0 | 24.1 | ||||||
Regulatory liabilities | (14.8 | ) | (1.9 | ) | (12.4 | ) | |||
Other assets | (4.5 | ) | 2.0 | 4.8 | |||||
Other liabilities | (28.7 | ) | (62.9 | ) | (55.8 | ) | |||
Change in certain current assets and liabilities | |||||||||
Accounts receivable, net | 20.9 | (40.1 | ) | 3.6 | |||||
Accrued unbilled revenues | 1.9 | (2.5 | ) | 0.4 | |||||
Fuel, materials and supplies inventories | 6.5 | 54.0 | (37.5 | ) | |||||
Gas imbalance assets | — | 0.1 | — | ||||||
Fuel clause under recoveries | 1.8 | (0.8 | ) | (0.7 | ) | ||||
Other current assets | (6.6 | ) | (7.6 | ) | (5.2 | ) | |||
Accounts payable | 9.7 | 13.4 | 41.4 | ||||||
Accounts payable - affiliates | (0.6 | ) | (3.1 | ) | (0.2 | ) | |||
Income taxes payable - parent | (7.1 | ) | 23.0 | 106.6 | |||||
Fuel clause over recoveries | 101.5 | (22.2 | ) | (157.6 | ) | ||||
Other current liabilities | 8.4 | 26.9 | 22.4 | ||||||
Net Cash Provided from Operating Activities | 737.4 | 549.3 | 465.7 | ||||||
CASH FLOWS FROM INVESTING ACTIVITIES | |||||||||
Capital expenditures (less allowance for equity funds used during construction) | (704.4 | ) | (844.5 | ) | (631.6 | ) | |||
Proceeds from sale of assets | 0.6 | 0.6 | 1.3 | ||||||
Reimbursement of capital expenditures | 27.5 | 49.6 | 28.2 | ||||||
Net Cash Used in Investing Activities | (676.3 | ) | (794.3 | ) | (602.1 | ) | |||
CASH FLOWS FROM FINANCING ACTIVITIES | |||||||||
Dividends paid on common stock | (75.0 | ) | — | (60.2 | ) | ||||
Payment of long-term debt | (0.1 | ) | — | — | |||||
Proceeds from long-term debt | — | 246.3 | 246.2 | ||||||
Capital contribution from OGE Energy | — | 50.0 | — | ||||||
Changes in advances with parent | 14.0 | (51.3 | ) | (49.6 | ) | ||||
Net Cash Provided from (Used in) Financing Activities | (61.1 | ) | 245.0 | 136.4 | |||||
NET CHANGE IN CASH AND CASH EQUIVALENTS | — | — | — | ||||||
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD | — | — | — | ||||||
CASH AND CASH EQUIVALENTS AT END OF PERIOD | $ | — | $ | — | $ | — |
The accompanying Notes to Financial Statements are an integral part hereof.
51
OKLAHOMA GAS AND ELECTRIC COMPANY
BALANCE SHEETS
December 31 (In millions) | 2012 | 2011 | ||||
ASSETS | ||||||
CURRENT ASSETS | ||||||
Accounts receivable, less reserve of $2.6 and $3.7, respectively | $ | 161.5 | $ | 182.4 | ||
Accrued unbilled revenues | 57.4 | 59.3 | ||||
Advances to parent | 90.3 | 97.2 | ||||
Fuel inventories | 76.8 | 76.9 | ||||
Materials and supplies, at average cost | 74.7 | 81.1 | ||||
Deferred income taxes | 138.7 | 10.3 | ||||
Fuel clause under recoveries | — | 1.8 | ||||
Other | 34.6 | 28.0 | ||||
Total current assets | 634.0 | 537.0 | ||||
OTHER PROPERTY AND INVESTMENTS, at cost | 2.7 | 2.7 | ||||
PROPERTY, PLANT AND EQUIPMENT | ||||||
In service | 8,498.3 | 7,808.8 | ||||
Construction work in progress | 251.4 | 334.4 | ||||
Total property, plant and equipment | 8,749.7 | 8,143.2 | ||||
Less accumulated depreciation | 2,705.6 | 2,592.3 | ||||
Net property, plant and equipment | 6,044.1 | 5,550.9 | ||||
DEFERRED CHARGES AND OTHER ASSETS | ||||||
Regulatory assets | 510.6 | 507.9 | ||||
Other | 31.0 | 22.4 | ||||
Total deferred charges and other assets | 541.6 | 530.3 | ||||
TOTAL ASSETS | $ | 7,222.4 | $ | 6,620.9 |
The accompanying Notes to Financial Statements are an integral part hereof.
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OKLAHOMA GAS AND ELECTRIC COMPANY
BALANCE SHEETS (Continued)
December 31 (In millions) | 2012 | 2011 | ||||
LIABILITIES AND STOCKHOLDER'S EQUITY | ||||||
CURRENT LIABILITIES | ||||||
Accounts payable - affiliates | $ | 0.7 | $ | 1.3 | ||
Accounts payable - other | 186.7 | 193.4 | ||||
Customer deposits | 68.5 | 65.7 | ||||
Accrued taxes | 35.0 | 33.5 | ||||
Accrued interest | 43.2 | 43.2 | ||||
Accrued compensation | 33.2 | 26.6 | ||||
Price risk management | 2.1 | 2.2 | ||||
Fuel clause over recoveries | 109.2 | 7.7 | ||||
Other | 53.9 | 56.5 | ||||
Total current liabilities | 532.5 | 430.1 | ||||
LONG-TERM DEBT | 2,050.3 | 2,039.2 | ||||
DEFERRED CREDITS AND OTHER LIABILITIES | ||||||
Accrued benefit obligations | 240.9 | 230.8 | ||||
Deferred income taxes | 1,377.8 | 1,146.0 | ||||
Deferred investment tax credits | 3.9 | 6.1 | ||||
Regulatory liabilities | 245.1 | 230.7 | ||||
Price risk management | — | 1.8 | ||||
Other | 68.8 | 42.2 | ||||
Total deferred credits and other liabilities | 1,936.5 | 1,657.6 | ||||
Total liabilities | 4,519.3 | 4,126.9 | ||||
COMMITMENTS AND CONTINGENCIES (NOTE 12) | ||||||
STOCKHOLDER'S EQUITY | ||||||
Common stockholder's equity | 1,014.0 | 1,011.4 | ||||
Retained earnings | 1,690.4 | 1,485.1 | ||||
Accumulated other comprehensive loss, net of tax | (1.3 | ) | (2.5 | ) | ||
Total stockholder's equity | 2,703.1 | 2,494.0 | ||||
TOTAL LIABILITIES AND STOCKHOLDER'S EQUITY | $ | 7,222.4 | $ | 6,620.9 |
The accompanying Notes to Financial Statements are an integral part hereof.
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OKLAHOMA GAS AND ELECTRIC COMPANY
STATEMENTS OF CAPITALIZATION
December 31 (In millions) | 2012 | 2011 | |||||
STOCKHOLDER'S EQUITY | |||||||
Common stock, par value $2.50 per share; authorized 100.0 shares; and outstanding 40.4 and 40.4 shares, respectively | $ | 100.9 | $ | 100.9 | |||
Premium on common stock | 913.1 | 910.5 | |||||
Retained earnings | 1,690.4 | 1,485.1 | |||||
Accumulated other comprehensive loss, net of tax | (1.3 | ) | (2.5 | ) | |||
Total stockholder's equity | 2,703.1 | 2,494.0 | |||||
LONG-TERM DEBT | |||||||
SERIES | DUE DATE | ||||||
Senior Notes | |||||||
5.15% | Senior Notes, Series Due January 15, 2016 | 110.0 | 110.0 | ||||
6.50% | Senior Notes, Series Due July 15, 2017 | 125.0 | 125.0 | ||||
6.35% | Senior Notes, Series Due September 1, 2018 | 250.0 | 250.0 | ||||
8.25% | Senior Notes, Series Due January 15, 2019 | 250.0 | 250.0 | ||||
6.65% | Senior Notes, Series Due July 15, 2027 | 125.0 | 125.0 | ||||
6.50% | Senior Notes, Series Due April 15, 2028 | 100.0 | 100.0 | ||||
6.50% | Senior Notes, Series Due August 1, 2034 | 140.0 | 140.0 | ||||
5.75% | Senior Notes, Series Due January 15, 2036 | 110.0 | 110.0 | ||||
6.45% | Senior Notes, Series Due February 1, 2038 | 200.0 | 200.0 | ||||
5.85% | Senior Notes, Series Due June 1, 2040 | 250.0 | 250.0 | ||||
5.25% | Senior Notes, Series Due May 15, 2041 | 250.0 | 250.0 | ||||
3.70% | Tinker Debt, Due August 31, 2062 | 10.7 | — | ||||
Other Bonds | |||||||
0.22% - 0.40% | Garfield Industrial Authority, January 1, 2025 | 47.0 | 47.0 | ||||
0.21% - 0.41% | Muskogee Industrial Authority, January 1, 2025 | 32.4 | 32.4 | ||||
0.20% - 0.47% | Muskogee Industrial Authority, June 1, 2027 | 56.0 | 56.0 | ||||
Unamortized discount | (5.8 | ) | (6.2 | ) | |||
Total long-term debt | 2,050.3 | 2,039.2 | |||||
Total Capitalization | $ | 4,753.4 | $ | 4,533.2 |
The accompanying Notes to Financial Statements are an integral part hereof.
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OKLAHOMA GAS AND ELECTRIC COMPANY
STATEMENTS OF CHANGES IN STOCKHOLDER'S EQUITY
(In millions) | Common Stock | Premium on Common Stock | Retained Earnings | Accumulated Other Comprehensive Income (Loss) | Total | ||||||||||
Balance at December 31, 2009 | $ | 100.9 | $ | 857.5 | $ | 1,066.3 | $ | (0.4 | ) | $ | 2,024.3 | ||||
Comprehensive income (loss) | |||||||||||||||
Net income | — | — | 215.7 | — | 215.7 | ||||||||||
Other comprehensive income (loss), net of tax | — | — | — | (1.7 | ) | (1.7 | ) | ||||||||
Comprehensive income (loss) | — | — | 215.7 | (1.7 | ) | 214.0 | |||||||||
Dividends declared on common stock | — | — | (60.2 | ) | — | (60.2 | ) | ||||||||
Balance at December 31, 2010 | $ | 100.9 | $ | 857.5 | $ | 1,221.8 | $ | (2.1 | ) | $ | 2,178.1 | ||||
Comprehensive income (loss) | |||||||||||||||
Net income | — | — | 263.3 | — | 263.3 | ||||||||||
Other comprehensive income (loss), net of tax | — | — | — | (0.4 | ) | (0.4 | ) | ||||||||
Comprehensive income (loss) | — | — | 263.3 | (0.4 | ) | 262.9 | |||||||||
Stock-based compensation | — | 3.0 | — | — | 3.0 | ||||||||||
Capital contribution from OGE Energy | — | 50.0 | — | — | 50.0 | ||||||||||
Balance at December 31, 2011 | $ | 100.9 | $ | 910.5 | $ | 1,485.1 | $ | (2.5 | ) | $ | 2,494.0 | ||||
Comprehensive income (loss) | |||||||||||||||
Net income | — | — | 280.3 | — | 280.3 | ||||||||||
Other comprehensive income (loss), net of tax | — | — | — | 1.2 | 1.2 | ||||||||||
Comprehensive income (loss) | — | — | 280.3 | 1.2 | 281.5 | ||||||||||
Dividends declared on common stock | — | — | (75.0 | ) | — | (75.0 | ) | ||||||||
Stock-based compensation | — | 2.6 | — | — | 2.6 | ||||||||||
Balance at December 31, 2012 | $ | 100.9 | $ | 913.1 | $ | 1,690.4 | $ | (1.3 | ) | $ | 2,703.1 |
The accompanying Notes to Financial Statements are an integral part hereof.
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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, 2012 and 2011 and the results of its operations and cash flows for the years ended December 31, 2012, 2011 and 2010, 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 actual or anticipated 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 actual or anticipated 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.
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The following table is a summary of OG&E's regulatory assets and liabilities at:
December 31 (In millions) | 2012 | 2011 | ||||
Regulatory Assets | ||||||
Current | ||||||
Crossroads wind farm rider under recovery (A) | $ | 14.9 | $ | 2.5 | ||
Oklahoma demand program rider under recovery (A) | 9.2 | 8.1 | ||||
Fuel clause under recoveries | — | 1.8 | ||||
Other (A) | 2.9 | 3.6 | ||||
Total Current Regulatory Assets | $ | 27.0 | $ | 16.0 | ||
Non-Current | ||||||
Benefit obligations regulatory asset | $ | 370.6 | $ | 359.2 | ||
Income taxes recoverable from customers, net | 54.7 | 54.0 | ||||
Smart Grid | 42.8 | 37.2 | ||||
Unamortized loss on reacquired debt | 13.0 | 14.2 | ||||
Deferred storm expenses | 12.7 | 23.8 | ||||
Deferred pension expenses | 4.5 | 9.1 | ||||
Other | 12.3 | 10.4 | ||||
Total Non-Current Regulatory Assets | $ | 510.6 | $ | 507.9 | ||
Regulatory Liabilities | ||||||
Current | ||||||
Fuel clause over recoveries | $ | 109.2 | $ | 7.7 | ||
Smart Grid rider over recovery (B) | 24.1 | 24.3 | ||||
Other (B) | 7.8 | 13.7 | ||||
Total Current Regulatory Liabilities | $ | 141.1 | $ | 45.7 | ||
Non-Current | ||||||
Accrued removal obligations, net | $ | 218.2 | $ | 208.2 | ||
Deferred pension credits | 17.7 | — | ||||
Pension tracker | 9.2 | 22.5 | ||||
Total Non-Current Regulatory Liabilities | $ | 245.1 | $ | 230.7 |
(A) | Included in Other Current Assets on the Balance Sheets. |
(B) | Included in Other Current Liabilities on the Balance Sheets. |
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 a rider established by the OCC. OG&E began recovery in the fourth quarter of 2011 and believes the rider will continue until new rates are implemented in OG&E's next general rate case.
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 any achieved energy, demand savings and performance based incentives and the recovery of costs associated with research and development investments through December 2015.
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.
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, prior service cost and net transition obligation. These expenses were allowed to be recorded as a regulatory asset as OG&E had historically recovered and currently recovers pension and postretirement benefit plan expense in its electric rates and there was no negative evidence that the existing regulatory treatment would change. 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.
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The following table is a summary of the components of the benefit obligations regulatory asset at:
December 31 (In millions) | 2012 | 2011 | ||||
Pension Plan and Restoration of Retirement Income Plan: | ||||||
Net loss | $ | 278.6 | $ | 266.3 | ||
Prior service cost | 4.5 | 7.0 | ||||
Postretirement plans: | ||||||
Net loss | 134.6 | 144.2 | ||||
Prior service cost | (47.1 | ) | (60.8 | ) | ||
Net transition obligation | — | 2.5 | ||||
Total | $ | 370.6 | $ | 359.2 |
The following amounts in the benefit obligations regulatory asset at December 31, 2012 are expected to be recognized as components of net periodic benefit cost in 2013:
(In millions) | |||
Pension Plan and Restoration of Retirement Income Plan: | |||
Net loss | $ | 19.8 | |
Prior service cost | 2.0 | ||
Postretirement plans: | |||
Net loss | 18.1 | ||
Prior service cost | (13.7 | ) | |
Total | $ | 26.2 |
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 and stranded costs associated with OG&E's existing meters. The costs recoverable from Oklahoma customers for system-wide deployment of smart grid technology and implementing the smart grid pilot program were capped at $366.4 million (inclusive of the U.S. Department of Energy grant award amount) subject to an offset for any recovery of those costs from Arkansas customers and 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. This project was completed in late 2012 and the smart grid project costs did not exceed $366.4 million. The incremental costs for web portal access, education and home energy reports are capped at $6.9 million and will be recovered in base rates in OG&E's next general rate case. The stranded costs associated with OG&E's existing meters, which have been replaced by smart meters, were accumulated during the smart grid deployment and recovery of the stranded costs will be included in future rate cases. OG&E began recovering the estimated capital costs of $14 million and associated operation and maintenance costs for deployment of smart grid technology, along with incremental costs for web portal access and education of $0.8 million, through a rider beginning with the first billing cycle in January 2013 through December 2013.
OG&E defers the Oklahoma storm-related operation and maintenance expenses in excess of $2.7 million and reserves for any Oklahoma storm-related operation and maintenance expenses less than $2.7 million. OG&E will recover the deferred amounts over a five-year period ending in August 2017.
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 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.
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
58
expenses and the amount approved in its last Oklahoma rate case as a regulatory asset or regulatory liability. These amounts have been recorded in Pension tracker regulatory liability in the regulatory assets and liabilities table above.
In July 2009, OG&E was allowed to recover previously deferred pension costs over a four-year period ending in August 2013. OG&E also recovers its 2006 and 2007 pension settlement costs in Arkansas, which are being amortized over a 10-year period ending in January 2020. Both the Oklahoma and Arkansas pension plan expenses are reflected in Deferred Pension expenses asset in the regulatory assets and liabilities table above.
In September 2011, OG&E was allowed to include postretirement medical expenses in its pension tracker. In August 2012, OG&E was allowed to recover pension and postretirement medical expenses over a two-year period ending July 2014 which is included in Deferred Pension credits liability in the regulatory assets and liabilities table above.
Accrued removal obligations represent asset retirement costs previously recovered from ratepayers for other than legal obligations.
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, but conservative, 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, impairment estimates of long-lived assets (including intangible assets), income taxes, contingency reserves, asset retirement obligations, fair value and cash flow hedges, the allowance for uncollectible accounts receivable, the valuation 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 is being recovered through the fuel adjustment clause. The allowance for uncollectible accounts receivable was $2.6 million and $3.7 million at December 31, 2012 and 2011, 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 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 $76.8 million and $76.9 million at December 31, 2012 and 2011, respectively.
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Gas Imbalances
Gas imbalances occur when the actual amounts of natural gas delivered from or received by OG&E differ from the amounts scheduled to be delivered or received. OG&E values all imbalances at an average of current market indices applicable to OG&E's operations, not to exceed net realizable value.
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.
December 31, 2012 (In millions) | Percentage Ownership | Total Property, Plant and Equipment | Accumulated Depreciation | Net Property, Plant and Equipment | |||||||
McClain Plant | 77 | % | $ | 182.1 | $ | 56.3 | $ | 125.8 | |||
Redbud Plant (A) | 51 | % | $ | 458.5 | $ | 69.5 | $ | 389.0 |
(A) | This amount includes a plant acquisition adjustment of $148.3 million and accumulated amortization of $23.3 million. |
OG&E's property, plant and equipment and related accumulated depreciation are divided into the following major classes at:
December 31, 2012 (In millions) | Total Property, Plant and Equipment | Accumulated Depreciation | Net Property, Plant and Equipment | ||||||
Distribution assets | $ | 3,222.7 | $ | 969.6 | $ | 2,253.1 | |||
Electric generation assets (A) | 3,446.6 | 1,242.4 | 2,204.2 | ||||||
Transmission assets (B) | 1,712.6 | 359.8 | 1,352.8 | ||||||
Intangible plant | 50.2 | 25.0 | 25.2 | ||||||
Other property and equipment | 317.6 | 108.8 | 208.8 | ||||||
Total property, plant and equipment | $ | 8,749.7 | $ | 2,705.6 | $ | 6,044.1 |
(A) | This amount includes a plant acquisition adjustment of $148.3 million and accumulated amortization of $23.3 million. |
(B) | This amount includes a plant acquisition adjustment of $3.3 million and accumulated amortization of $0.3 million. |
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December 31, 2011 (In millions) | Total Property, Plant and Equipment | Accumulated Depreciation | Net Property, Plant and Equipment | ||||||
Distribution assets | $ | 2,981.3 | $ | 920.3 | $ | 2,061.0 | |||
Electric generation assets (A) | 3,360.6 | 1,215.8 | 2,144.8 | ||||||
Transmission assets (B) | 1,464.2 | 339.6 | 1,124.6 | ||||||
Intangible plant | 43.2 | 20.3 | 22.9 | ||||||
Other property and equipment | 293.9 | 96.3 | 197.6 | ||||||
Total property, plant and equipment | $ | 8,143.2 | $ | 2,592.3 | $ | 5,550.9 |
(A) | This amount includes a plant acquisition adjustment of $148.3 million and accumulated amortization of $17.9 million. |
(B) | This amount includes a plant acquisition adjustment of $3.3 million and accumulated amortization of $0.2 million. |
The unamortized computer software costs were $17.6 million and $6.7 million at December 31, 2012 and 2011, respectively. In 2012, 2011 and 2010, amortization expense for computer software costs was $4.2 million, $1.8 million and $2.6 million, respectively.
Depreciation and Amortization
The provision for depreciation, which was 3.0 percent and 2.9 percent, respectively, of the average depreciable utility plant for 2012 and 2011, 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. Amortization of intangible assets is computed using the straight-line method. Of the remaining amortizable intangible plant balance at December 31, 2012, 92.4 percent will be amortized over 9.25 years with 7.6 percent of the remaining amortizable intangible plant balance at December 31, 2012 being amortized over their respective lives ranging from three to five 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 26 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 five to 74 years.
The following table summarizes changes to OG&E's asset retirement obligations during the years ended December 31, 2012 and 2011.
(In millions) | 2012 | 2011 | ||||
Balance at January 1 | $ | 24.8 | $ | 11.1 | ||
Liabilities incurred (A) | — | 13.0 | ||||
Accretion expense | 1.9 | 0.7 | ||||
Revisions in estimated cash flows (B) | 26.9 | — | ||||
Balance at December 31 | $ | 53.6 | $ | 24.8 |
(A) | Due to OG&E's Crossroads wind farm. |
(B) | Due to changes to OG&E's asset retirement obligations related to its wind farms due to a change in the assumption related to the timing of removal used in the valuation of the asset retirement obligations. |
Allowance for Funds Used During Construction
For OG&E, 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 8.93 percent, 8.71 percent and 8.89 percent for the years ended December 31, 2012, 2011 and 2010, respectively. The increase in the allowance for funds used during construction rates in 2012 was primarily due to an increase in commercial paper fees in 2012 which resulted in an increase in the cost of short-term debt borrowings.
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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 participates in the SPP energy imbalance service market in a dual role as a load serving entity and as a generation owner. The energy imbalance service market requires cash settlements for over or under schedules of generation and load. Market participants, including OG&E, are required to submit resource plans and can submit offer curves for each resource available for dispatch. A function of interchange accounting is to match participants' MWH entitlements (generation plus scheduled bilateral purchases) against their MWH obligations (load plus scheduled bilateral sales) during every hour of every day. If the net result during any given hour is an entitlement, the participant is credited with a spot-market sale to the SPP at the respective market price for that hour; if the net result is an obligation, the participant is charged with a spot-market purchase from the SPP at the respective market price for that hour. The SPP purchases and sales are not allocated to individual customers. OG&E records the hourly sales to the SPP at market rates in Operating Revenues and the hourly purchases from the SPP at market rates in Cost of Goods Sold in its Financial Statements.
Fuel Adjustment Clauses
Variances in the actual cost of fuel used in electric generation and certain purchased power costs, as compared to the fuel component included in the cost-of-service for ratemaking, 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 Enogex.
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.
Accumulated Other Comprehensive Loss
The balance of Accumulated Other Comprehensive Loss was $1.3 million and $2.5 million at December 31, 2012 and 2011, respectively, related to deferred commodity contracts hedging activity.
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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 $5.8 million and $5.5 million in accrued environmental liabilities at December 31, 2012 and 2011, respectively, which are included in the summary of asset retirement obligations above.
Related Party Transactions
OGE Energy charged operating costs to OG&E of $118.4 million, $129.7 million and $106.9 million in 2012, 2011 and 2010, respectively. OGE Energy charges operating costs to its subsidiaries based on several factors. Operating costs directly related to specific subsidiaries are assigned to those subsidiaries. Where more than one subsidiary benefits from certain expenditures, the costs are shared between those subsidiaries receiving the benefits. Operating costs incurred for the benefit of all subsidiaries are allocated among the subsidiaries, either as overhead based primarily on labor costs or using the "Distrigas" method. The Distrigas method is a three-factor formula that uses an equal weighting of payroll, net operating revenues and gross property, plant and equipment. OGE Energy adopted the Distrigas method in January 1996 as a result of a recommendation by the OCC Staff. OGE Energy believes this method provides a reasonable basis for allocating common expenses.
In each of 2012, 2011 and 2010, OG&E recorded an expense from its affiliate, Enogex, of $34.8 million for transporting gas to OG&E's natural gas-fired generating facilities. In 2012, 2011 and 2010, OG&E recorded an expense from Enogex of $12.9 million, $12.7 million and $12.7 million, respectively, for natural gas storage services. In 2012, 2011 and 2010, OG&E also recorded natural gas purchases from Enogex of $20.4 million, $34.7 million and $50.3 million, respectively. There are $1.0 million and $1.7 million of natural gas purchases recorded at December 31, 2012 and 2011, respectively, which are included in Accounts Payable – Affiliates in the Balance Sheets for these activities. In 2012, 2011 and 2010, OG&E recorded revenues from Enogex of $12.4 million, $8.1 million and $6.8 million, respectively, for electricity used at Enogex's compression sites.
On July 1, 2009, OG&E and Enogex entered into hedging transactions to offset natural gas long positions at Enogex with short natural gas exposures at OG&E resulting from the cost of generation associated with a wholesale power sales contract with the Oklahoma Municipal Power Authority. These transactions are for 50,000 MMBtu per month from August 2009 to December 2013 (see Note 4).
In 2012 and 2010, OG&E declared dividends to OGE Energy of $75.0 million and $60.2 million, respectively. In 2011, OG&E declared no dividends to OGE Energy.
In June 2011, OGE Energy made a capital contribution to OG&E for $50.0 million.
2. | Accounting Pronouncement |
In February 2013, the Financial Accounting Standards Board issued "Comprehensive Income: Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income." The new standard requires an entity to provide information about the amounts reclassified out of accumulated other comprehensive income by component. In addition, the new standard requires an entity to present, either on the face of the statement where net income is presented or in the notes, significant amounts reclassified out of accumulated other comprehensive income by the respective line items in net income but only if the amount reclassified is required under GAAP to be reclassified to net income in its entirety in the same reporting period. For other amounts that are not required under GAAP to be reclassified in their entirety to net income, an entity is required to cross-reference to other disclosures required under GAAP that provide additional detail about those amounts. The new standard is applicable for all entities that issue financial statements that are presented in conformity with GAAP and that report items of other comprehensive income. The new standard is effective for interim and annual reporting periods for fiscal years beginning after December 15, 2012 and is required to be applied prospectively. OG&E adopted this new standard effective January 1, 2013 and will provide any additional disclosures necessary to comply with the new standard in its Form 10-Q for the quarter ended March 31, 2013.
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3. | 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. Instruments classified as Level 2 include hedging transactions to offset natural gas long positions at Enogex with short natural gas exposures at OG&E resulting from the cost of generation associated with a wholesale power sales contract with the Oklahoma Municipal Power Authority.
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 utilizes the market approach in determining the fair value of its derivative positions by using either NYMEX published market prices, independent broker pricing data or broker/dealer valuations. Over-the-counter derivatives with NYMEX based prices are considered Level 2 due to the impact of counterparty credit risk.
The impact to the fair value of derivatives due to credit risk is calculated using the probability of default based on Standard & Poor's Ratings Services and/or internally generated ratings. The fair value of derivative assets is adjusted for credit risk. The fair value of derivative liabilities is adjusted for credit risk only if the impact is deemed material.
At December 31, 2012 and 2011, OG&E had no gross derivative assets measured at fair value on a recurring basis. At December 31, 2012 and 2011, OG&E had $2.1 million and $4.0 million, respectively, of gross derivative liabilities measured at fair value on a recurring basis which are considered level 2 in the fair value hierarchy.
The following table summarizes the fair value and carrying amount of OG&E's financial instruments, including derivative contracts related to OG&E's PRM activities, at:
2012 | 2011 | |||||||||||
December 31 (In millions) | Carrying Amount | Fair Value | Carrying Amount | Fair Value | ||||||||
PRM Liabilities | ||||||||||||
Energy Derivative Contracts | $ | 2.1 | $ | 2.1 | $ | 4.0 | $ | 4.0 | ||||
Long-Term Debt | ||||||||||||
Senior Notes | $ | 1,904.2 | $ | 2,401.6 | $ | 1,903.8 | $ | 2,383.8 | ||||
Industrial Authority Bonds | 135.4 | 135.4 | 135.4 | 135.4 | ||||||||
Tinker Debt (A) | 10.7 | 10.0 | — | — |
(A) | In September 2012, OG&E purchased the electric distribution system at Tinker Air Force Base for $10.7 million and began making installment payments over a 50-year term. The fair value of this debt was based on calculating the net present value of the monthly payments discounted by OG&E's current borrowing rate. Since the debt was valued using unobservable inputs, it was classified as Level 3 in the fair value hierarchy. This was a non-cash investing and financing activity as discussed in Note 6. |
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 valuation of OG&E's energy derivative contracts was determined generally based on quoted market prices. The valuation of instruments also considers the credit risk of the counterparties. The fair value
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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.
4. | Derivative Instruments and Hedging Activities |
OG&E is exposed to certain risks relating to its ongoing business operations. The primary risks managed using derivatives instruments are commodity price risk and interest rate risk. OG&E is also exposed to credit risk in its business operations.
Commodity Price Risk
OG&E occasionally uses commodity price swap contracts to manage its commodity price risk exposures. Natural gas swaps are used to manage OG&E's natural gas exposure associated with a wholesale power sales contract.
On July 1, 2009, OG&E and Enogex entered into hedging transactions to offset natural gas long positions at Enogex with short natural gas exposures at OG&E resulting from the cost of generation associated with a wholesale power sales contract with the Oklahoma Municipal Power Authority. These transactions are for 50,000 MMBtu per month from August 2009 to December 2013.
Normal purchases and normal sales contracts are not recorded in PRM Assets or Liabilities in the Balance Sheets and earnings recognition is recorded in the period in which physical delivery of the commodity occurs. Management applies normal purchases and normal sales treatment to: (i) electric power contracts and (ii) fuel procurement.
OG&E recognizes its non-exchange traded derivative instruments as PRM Assets or Liabilities in the Balance Sheets at fair value with such amounts classified as current or long-term based on their anticipated settlement.
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 utilizes 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.
Credit Risk
OG&E is exposed to certain credit risks relating to its ongoing business operations. Credit risk includes the risk that counterparties that owe OG&E money or energy will breach their obligations. If the counterparties to these arrangements fail to perform, OG&E may be forced to enter into alternative arrangements. In that event, OG&E's financial results could be adversely affected and OG&E could incur losses.
Cash Flow Hedges
For derivatives that are designated and qualify as a cash flow hedge, the effective portion of the change in fair value of the derivative instrument is reported as a component of Accumulated Other Comprehensive Income (Loss) and recognized into earnings in the same period during which the hedged transaction affects earnings. The ineffective portion of a derivative's change in fair value or hedge components excluded from the assessment of effectiveness is recognized currently in earnings. OG&E measures the ineffectiveness of commodity cash flow hedges using the change in fair value method whereby the change in the expected future cash flows designated as the hedge transaction are compared to the change in fair value of the hedging instrument. Forecasted transactions, which are designated as the hedged transaction in a cash flow hedge, are regularly evaluated to assess whether they continue to be probable of occurring. If the forecasted transactions are no longer probable of occurring, hedge accounting will cease on a prospective basis and all future changes in the fair value of the derivative will be recognized directly in earnings.
At December 31, 2012 and 2011, the only derivative instruments that were designated as cash flow hedges were the related party natural gas swaps with Enogex discussed above.
Fair Value Hedges
For derivative instruments that are designated and qualify as a fair value hedge, the gain or loss on the derivative as well as the offsetting loss or gain on the hedged item attributable to the hedge risk are recognized currently in earnings. OG&E includes the gain or loss on the hedged items in Operating Revenues as the offsetting loss or gain on the related hedging derivative.
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At December 31, 2012 and 2011, OG&E had no derivative instruments that were designated as fair value hedges.
Derivatives Not Designated As Hedging Instruments
For derivative instruments not designated as hedging instruments, the gain or loss on the derivative is recognized currently in earnings.
At December 31, 2012 and 2011, OG&E had no material derivative instruments that were not designated as hedging instruments.
Credit-Risk Related Contingent Features in Derivative Instruments
At December 31, 2012, OG&E had no derivative instruments that contain credit-risk related contingent features.
5. | Stock-Based Compensation |
In 2008, OGE Energy adopted, and its shareowners approved, the 2008 Stock Incentive Plan. Under the 2008 Stock Incentive Plan, restricted stock, 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 2,750,000 shares under the 2008 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, 2012, 2011 and 2010 related to performance units and restricted stock for OG&E employees.
Year ended December 31 (In millions) | 2012 | 2011 | 2010 | ||||||
Performance units | |||||||||
Total shareholder return | $ | 1.7 | $ | 1.6 | $ | 1.4 | |||
Earnings per share | 0.9 | 1.1 | 0.5 | ||||||
Total performance units | 2.6 | 2.7 | 1.9 | ||||||
Restricted stock | 0.1 | 0.2 | 0.2 | ||||||
Total compensation expense | $ | 2.7 | $ | 2.9 | $ | 2.1 | |||
Income tax benefit | $ | 1.2 | $ | 1.2 | $ | 0.8 |
OGE Energy has issued new shares to satisfy stock option exercises, restricted stock grants and payouts of earned performance units. In 2012, 2011 and 2010, there were 102,919 shares, 56,801 shares and 53,582 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 2012, there were 497 shares of restricted stock returned to OGE Energy to satisfy tax liabilities.
Performance Units
Under the 2008 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 2008 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
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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 are not accrued or paid during the performance period and, therefore, are not included in the fair value calculation. 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.
2012 | 2011 | 2010 | |||||||
Number of units granted to OG&E employees | 40,561 | 43,302 | 43,027 | ||||||
Fair value of units granted | $ | 51.82 | $ | 46.09 | $ | 39.43 | |||
Expected dividend yield | 3.0 | % | 3.2 | % | 3.9 | % | |||
Expected price volatility | 22.0 | % | 33.0 | % | 34.0 | % | |||
Risk-free interest rate | 0.38 | % | 1.40 | % | 1.42 | % | |||
Expected life of units (in years) | 2.87 | 2.87 | 2.87 |
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.
2012 | 2011 | 2010 | |||||||
Number of units granted to OG&E employees | 13,519 | 14,431 | 14,344 | ||||||
Fair value of units granted | $ | 47.63 | $ | 41.61 | $ | 32.44 |
Restricted Stock
Under the 2008 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 and, therefore, are included in the fair value calculation. The expected life of the restricted stock is based on the non-vested period since inception
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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.
2012 | 2011 | 2010 | |||||||
Shares of restricted stock granted to OG&E employees | 1,108 | 2,234 | 2,038 | ||||||
Fair value of restricted stock granted | $ | 53.86 | $ | 47.21 | $ | 44.99 |
A summary of the activity for OGE Energy's performance units and restricted stock applicable to OG&E'S employees at December 31, 2012 and changes in 2012 are shown in the following table.
Performance Units | |||||||||||||||
Total Shareholder Return | Earnings Per Share | Restricted Stock | |||||||||||||
(dollars in millions) | Number of Units | Aggregate Intrinsic Value | Number of Units | Aggregate Intrinsic Value | Number of Shares | Aggregate Intrinsic Value | |||||||||
Units/Shares Outstanding at 12/31/11 | 132,835 | 44,277 | 3,593 | ||||||||||||
Granted (A) | 40,561 | 13,519 | 1,108 | ||||||||||||
Converted (B) | (55,510 | ) | $ | 5.8 | (18,503 | ) | $ | 1.9 | N/A | ||||||
Vested | N/A | N/A | (1,298 | ) | $ | 0.1 | |||||||||
Forfeited | (6,092 | ) | (2,030 | ) | (380 | ) | |||||||||
Employee migration (C) | 212 | 72 | — | ||||||||||||
Units/Shares Outstanding at 12/31/12 | 112,006 | $ | 10.0 | 37,335 | $ | 2.8 | 3,023 | $ | 0.2 | ||||||
Units/Shares Fully Vested at 12/31/12 | 37,726 | $ | 4.2 | 12,576 | $ | 1.4 |
(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, 2011 which were settled in February 2012. |
(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, 2012 and changes in 2012 are shown in the following table.
Performance Units | |||||||||||||||||
Total Shareholder Return | Earnings Per Share | Restricted Stock | |||||||||||||||
Number of Units | Weighted-Average Grant Date Fair Value | Number of Units | Weighted-Average Grant Date Fair Value | Number of Shares | Weighted-Average Grant Date Fair Value | ||||||||||||
Units/Shares Non-Vested at 12/31/11 | 77,325 | $ | 42.71 | 25,774 | $ | 36.95 | 3,593 | $ | 46.37 | ||||||||
Granted | 40,561 | (A) | $ | 51.82 | 13,519 | (A) | $ | 47.63 | 1,108 | $ | 53.86 | ||||||
Vested | (37,726 | ) | $ | 39.43 | (12,576 | ) | $ | 32.44 | (1,298 | ) | $ | 46.15 | |||||
Forfeited | (6,092 | ) | $ | 46.62 | (2,030 | ) | $ | 41.64 | (380 | ) | $ | 46.18 | |||||
Employee migration | 212 | (B) | $ | 34.87 | 72 | (B) | $ | 30.52 | — | $ | — | ||||||
Units/Shares Non-Vested at 12/31/12 | 74,280 | $ | 49.01 | 24,759 | $ | 44.67 | 3,023 | $ | 49.24 | ||||||||
Units/Shares Expected to Vest | 70,760 | 23,584 | 3,023 |
(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. |
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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.
Year ended December 31 (In millions) | 2012 | 2011 | 2010 | ||||||
Performance units | |||||||||
Total shareholder return | $ | 1.4 | $ | 1.2 | $ | 1.0 | |||
Earnings per share | 0.8 | 0.6 | 0.4 | ||||||
Restricted stock | 0.1 | 0.3 | 0.2 |
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.
December 31, 2012 | Unrecognized Compensation Cost (in millions) | Weighted Average to be Recognized (in years) | ||
Performance units | ||||
Total shareholder return | $ | 1.8 | 1.64 | |
Earnings per share | 0.8 | 1.14 | ||
Total performance units | 2.6 | |||
Restricted stock | 0.1 | 2.10 | ||
Total | $ | 2.7 |
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 have a contractual life of 10 years. A summary of the activity for OGE Energy's stock options applicable to OG&E'S employees at December 31, 2012 and changes during 2012 are shown in the following table.
(dollars in��millions) | Number of Options | Weighted-Average Exercise Price | Aggregate Intrinsic Value | Weighted-Average Remaining Contractual Term | ||||||
Options Outstanding at 12/31/11 | 7,100 | $ | 20.57 | |||||||
Exercised | (3,600 | ) | $ | 21.87 | $ | 0.2 | ||||
Options Outstanding at 12/31/12 | 3,500 | $ | 19.24 | $ | 0.1 | 0.44 | years | |||
Options Fully Vested and Exercisable at 12/31/12 | 3,500 | $ | 19.24 | $ | 0.1 | 0.44 | years |
A summary of the activity for OG&E's exercised stock options in 2012, 2011 and 2010 are shown in the following table.
Year ended December 31 (In millions) | 2012 | 2011 | 2010 | ||||||
Intrinsic value (A) | $ | 0.2 | $ | 0.3 | $ | 0.6 |
(A) | The difference between the market value on the date of exercise and the option exercise price. |
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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.
Year ended December 31 (In millions) | 2012 | 2011 | 2010 | ||||||
NON-CASH INVESTING AND FINANCING ACTIVITIES | |||||||||
Installment payments for Tinker electric distribution system | $ | 10.6 | $ | — | $ | — | |||
Power plant long-term service agreement | — | 1.7 | 2.7 | ||||||
Future installment payments to wind farm developer | — | — | 2.3 | ||||||
SUPPLEMENTAL CASH FLOW INFORMATION | |||||||||
Cash Paid During the Period for | |||||||||
Interest (net of interest capitalized) (A) | $ | 122.1 | $ | 108.2 | $ | 100.2 | |||
Income taxes (net of income tax refunds) | (1.2 | ) | 4.5 | (113.9 | ) |
(A) | Net of interest capitalized of $3.5 million, $10.4 million and $5.5 million in 2012, 2011 and 2010, respectively. |
7. | Income Taxes |
The items comprising income tax expense are as follows:
Year ended December 31 (In millions) | 2012 | 2011 | 2010 | ||||||
Provision (Benefit) for Current Income Taxes | |||||||||
Federal | $ | (9.0 | ) | $ | 23.4 | $ | (11.2 | ) | |
State | 0.3 | (0.5 | ) | 3.4 | |||||
Total Provision (Benefit) for Current Income Taxes | (8.7 | ) | 22.9 | (7.8 | ) | ||||
Provision for Deferred Income Taxes, net | |||||||||
Federal | 111.4 | 98.0 | 117.0 | ||||||
State | (5.9 | ) | 0.3 | 5.5 | |||||
Total Provision for Deferred Income Taxes, net | 105.5 | 98.3 | 122.5 | ||||||
Deferred Federal Investment Tax Credits, net | (2.2 | ) | (3.3 | ) | (3.7 | ) | |||
Total Income Tax Expense | $ | 94.6 | $ | 117.9 | $ | 111.0 |
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 2009 or state and local tax examinations by tax authorities for years prior to 2005. 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 Federal tax rate to the effective income tax rate:
Year ended December 31 | 2012 | 2011 | 2010 | |||
Statutory Federal tax rate | 35.0 | % | 35.0 | % | 35.0 | % |
Amortization of net unfunded deferred taxes | 1.0 | 0.9 | 1.0 | |||
Medicare Part D subsidy | — | 0.4 | 2.3 | |||
Federal investment tax credits, net | (0.6 | ) | (0.9 | ) | (1.1 | ) |
State income taxes, net of Federal income tax benefit | (0.7 | ) | 0.1 | 1.6 | ||
Federal renewable energy credit (A) | (9.4 | ) | (4.4 | ) | (4.7 | ) |
Other | (0.1 | ) | (0.2 | ) | (0.1 | ) |
Effective income tax rate | 25.2 | % | 30.9 | % | 34.0 | % |
(A) | These are credits associated with the production from OG&E's wind farms. |
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At December 31, 2012 and 2011 OG&E had no material unrecognized tax benefits related to uncertain tax positions.
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, 2012 and 2011, respectively, were as follows:
December 31 (In millions) | 2012 | 2011 | ||||
Current Deferred Income Tax Assets | ||||||
Net operating losses | $ | 113.8 | $ | — | ||
Accrued liabilities | 14.0 | 4.6 | ||||
Federal tax credits | 6.0 | — | ||||
Accrued vacation | 3.1 | 3.3 | ||||
Uncollectible accounts | 1.0 | 1.4 | ||||
Derivative instruments | 0.8 | 0.9 | ||||
Other | — | 0.1 | ||||
Total Current Deferred Income Tax Assets | $ | 138.7 | $ | 10.3 | ||
Non-Current Deferred Income Tax Liabilities | ||||||
Accelerated depreciation and other property related differences | $ | 1,648.5 | $ | 1,425.1 | ||
OG&E pension plan | 102.2 | 94.5 | ||||
Income taxes refundable to customers, net | 21.2 | 28.0 | ||||
Regulatory asset | 18.8 | 21.2 | ||||
Bond redemption-unamortized costs | 4.0 | 4.4 | ||||
Total Non-Current Deferred Income Tax Liabilities | 1,794.7 | 1,573.2 | ||||
Non-Current Deferred Income Tax Assets | ||||||
Net operating losses | (150.0 | ) | (205.6 | ) | ||
State tax credits | (78.1 | ) | (58.8 | ) | ||
Regulatory liabilities | (71.4 | ) | (65.3 | ) | ||
Federal tax credits | (69.5 | ) | (49.6 | ) | ||
Postretirement medical and life insurance benefits | (42.1 | ) | (36.0 | ) | ||
Deferred Federal investment tax credits | (1.5 | ) | (2.4 | ) | ||
Derivative instruments | — | (0.7 | ) | |||
Other | (4.3 | ) | (8.8 | ) | ||
Total Non-Current Deferred Income Tax Assets | (416.9 | ) | (427.2 | ) | ||
Non-Current Deferred Income Tax Liabilities, net | $ | 1,377.8 | $ | 1,146.0 |
During 2012 and 2011, 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. For financial accounting purposes, OG&E recorded an increase in its Non-Current Deferred Income Taxes Liability at December 31, 2012 and 2011 on OG&E's Balance Sheet to recognize the financial statement impact of this new law.
On January 2, 2013, the American Taxpayer Relief Act of 2012 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, 2014. Because this new law was enacted in 2013, GAAP requires the law to be considered retroactive legislation, the impact of which must be recorded in the period enacted. The impact of the new law will be reflected in OG&E's 2013 Financial Statements as an increase in Deferred Tax Liabilities with a corresponding increase in Deferred Tax Assets related to the net operating loss.
In June 2010, new legislation was passed in Oklahoma that created a moratorium, from July 1, 2010 through June 30, 2012, on 30 income tax credits. For income tax purposes, credits affected by the moratorium could not be claimed for any event, transaction, investment, expenditure or other act for which the credits would otherwise be allowable. During this two-year period, affected credits generated by OG&E were deferred and will be utilized at a future date. For financial accounting purposes, OG&E is receiving the benefits as most of these credits did not expire if they were not utilized in the period they were generated.
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Other
OG&E sustained Federal and state tax operating losses in 2012 and 2011 caused primarily by bonus depreciation and other book verses tax temporary differences. As a result, OG&E accrued Federal and state income tax benefits in 2012 and 2011. OG&E can no longer carry these losses back to prior periods, therefore, these losses are being carried forward. 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:
(In millions) | Carry Forward Amount | Deferred Tax Asset | Earliest Expiration Date | ||||
Net operating losses | |||||||
State operating loss | $ | 804.3 | $ | 29.6 | 2030 | ||
Federal operating loss | 669.2 | 234.2 | 2030 | ||||
Federal tax credits | 75.5 | 75.5 | 2029 | ||||
State tax credits | |||||||
Oklahoma investment tax credits | 91.9 | 59.7 | N/A | ||||
Oklahoma capital investment board credits | 7.3 | 7.3 | N/A | ||||
Oklahoma zero emission tax credits | 16.2 | 11.1 | 2020 |
Under tax law in effect at December 31, 2012, OG&E projected utilization of $500.7 million of tax loss carry forward in 2013 and recorded a current deferred tax asset of $113.8 million. The remaining $150.0 million was recorded as a non-current deferred tax asset for utilization in periods after 2013. With the passage of the American Taxpayer Relief Act of 2012 on January 2, 2013, OG&E now expects much lower utilization will result in 2013. The impact of the new law will be reflected in OG&E's 2013 Financial Statements as a decrease in Current Deferred Tax Assets with a corresponding increase in Deferred Tax Liabilities related to the net operating loss.
In January 2013, OG&E learned that a portion of certain Oklahoma investment tax credits previously recognized but not yet utilized may not be available for utilization in future years. If management determines that it is more likely than not that it will be unable to utilize these credits, OG&E will be required to record a reserve of $7.8 million ($5.1 million after tax) at such time.
8. | Common Stock and Cumulative Preferred Stock |
There were no new shares of common stock issued in 2012, 2011 or 2010.
9. | Long-Term Debt |
A summary of OG&E's long-term debt is included in the Statements of Capitalization. At December 31, 2012, 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:
SERIES | DATE DUE | AMOUNT | ||
(In millions) | ||||
0.22% - 0.40% | Garfield Industrial Authority, January 1, 2025 | $ | 47.0 | |
0.21% - 0.41% | Muskogee Industrial Authority, January 1, 2025 | 32.4 | ||
0.20% - 0.47% | Muskogee Industrial Authority, June 1, 2027 | 56.0 | ||
Total (redeemable during next 12 months) | $ | 135.4 |
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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.
Long-Term Debt Maturities
Maturities of OG&E's long-term debt during the next five years consist of $0.2 million, $0.2 million, $0.2 million, $110.2 million and $125.2 million in years 2013, 2014, 2015, 2016 and 2017, 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, 2012 and 2011, there were $90.3 million and $97.2 million, respectively, in net outstanding advances to OGE Energy. 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, 2016. At December 31, 2012, 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, 2012, there was $2.2 million supporting letters of credit at a weighted-average interest rate of 0.53 percent. There were no outstanding borrowings under this revolving credit agreement and no outstanding commercial paper borrowings at December 31, 2012. At December 31, 2012, OG&E had less than $0.1 million in cash and cash equivalents.
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, 2013 and ending December 31, 2014.
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. In October 2009, OGE Energy's Pension Plan and OGE Energy's 401(k) Plan were amended, effective January 1, 2010 to provide eligible employees a choice to select a future retirement benefit combination from OGE Energy's Pension Plan and OGE Energy's 401(k) Plan.
Employees hired or rehired on or after December 1, 2009 do not participate in the Pension Plan but are eligible to participate in the 401(k) Plan where, for each pay period, 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.
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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 2012 and 2011, OGE Energy made contributions to its Pension Plan of $35 million and $50 million, respectively, of which $33 million in 2012 and $47 million in 2011 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 2013, OGE Energy expects to contribute up to $35 million to its Pension Plan, of which $33 million is expected to be OG&E's portion. The expected contribution to the Pension Plan during 2013 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.
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.
The following table presents the status of OG&E's portion of OGE Energy's Pension Plan and Restoration of Retirement Income Plan at December 31, 2012 and 2011. 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.
Pension Plan | Restoration of Retirement Income Plan | |||||||||||
December 31 (In millions) | 2012 | 2011 | 2012 | 2011 | ||||||||
Benefit obligations | $ | (574.6 | ) | $ | (546.9 | ) | $ | (2.2 | ) | $ | (2.2 | ) |
Fair value of plan assets | 519.0 | 485.9 | — | — | ||||||||
Funded status at end of year | $ | (55.6 | ) | $ | (61.0 | ) | $ | (2.2 | ) | $ | (2.2 | ) |
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.
(In millions) | Projected Benefit Payments | ||
2013 | $ | 61.5 | |
2014 | 76.5 | ||
2015 | 67.7 | ||
2016 | 60.1 | ||
2017 | 53.2 | ||
After 2017 | 203.0 |
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.
Projected Benefit Obligation Funded Status Thresholds | <90% | 95% | 100% | 105% | 110% | 115% | 120% |
Fixed income | 50% | 58% | 65% | 73% | 80% | 85% | 90% |
Equity | 50% | 42% | 35% | 27% | 20% | 15% | 10% |
Total | 100% | 100% | 100% | 100% | 100% | 100% | 100% |
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Within the portfolio's overall allocation to equities, the funds are allocated according to the guidelines in the table below.
Asset Class | Target Allocation | Minimum | Maximum |
Domestic All-Cap/Large Cap Equity | 50% | 50% | 60% |
Domestic Mid-Cap Equity | 15% | 5% | 25% |
Domestic Small-Cap Equity | 15% | 5% | 25% |
International Equity | 20% | 10% | 30% |
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 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:
Asset Class | Comparative Benchmark(s) |
Core Fixed Income | Barclays Capital Aggregate Index |
Interest Rate Sensitive Fixed Income | Barclays Capital Aggregate Index |
Long Duration Fixed Income | Barclays Long Government/Credit |
Equity Index | Standard & Poor's 500 Index |
All-Cap Equity | Russell 3000 Index |
Russell 3000 Value Index | |
Mid-Cap Equity | Russell Midcap Index |
Russell Midcap Value Index | |
Small-Cap Equity | Russell 2000 Index |
Russell 2000 Value Index | |
International Equity | Morgan Stanley Capital Investment ACWI ex-US |
The fixed income manager is 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. 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
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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 144-A securities and 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, 2012 and 2011. There were no Level 3 investments held by the Pension Plan at December 31, 2012 and 2011.
(In millions) | December 31, 2012 | Level 1 | Level 2 | ||||||
Common stocks | |||||||||
U.S. common stocks | $ | 232.2 | $ | 232.2 | $ | — | |||
Foreign common stocks | 39.9 | 39.9 | — | ||||||
U.S. Government obligations | |||||||||
U.S. treasury notes and bonds (A) | 138.6 | 138.6 | — | ||||||
Mortgage-backed securities | 55.8 | — | 55.8 | ||||||
Bonds, debentures and notes (B) | |||||||||
Corporate fixed income and other securities | 98.4 | — | 98.4 | ||||||
Mortgage-backed securities | 13.5 | — | 13.5 | ||||||
Commingled fund (C) | 34.9 | — | 34.9 | ||||||
Common/collective trust (D) | 25.6 | — | 25.6 | ||||||
Foreign government bonds | 3.9 | — | 3.9 | ||||||
U.S. municipal bonds | 0.8 | — | 0.8 | ||||||
Interest-bearing cash | 0.2 | 0.2 | — | ||||||
Forward contracts | |||||||||
Receivable (foreign currency) | 0.4 | — | 0.4 | ||||||
Payable (foreign currency) | (0.4 | ) | — | (0.4 | ) | ||||
Total Plan investments | $ | 643.8 | $ | 410.9 | $ | 232.9 | |||
Receivable from broker for securities sold | 0.8 | ||||||||
Interest and dividends receivable | 2.8 | ||||||||
Payable to broker for securities purchased | (21.4 | ) | |||||||
Plan investments attributable to affiliates | (107.0 | ) | |||||||
Total Plan assets | $ | 519.0 |
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(In millions) | December 31, 2011 | Level 1 | Level 2 | ||||||
Common stocks | |||||||||
U.S. common stocks | $ | 179.7 | $ | 179.7 | $ | — | |||
Foreign common stocks | 59.5 | 59.5 | — | ||||||
U.S. Government obligations | |||||||||
U.S. treasury notes and bonds (A) | 118.8 | 118.8 | — | ||||||
Mortgage-backed securities | 72.0 | — | 72.0 | ||||||
Other securities | 1.0 | — | 1.0 | ||||||
Bonds, debentures and notes (B) | |||||||||
Corporate fixed income and other securities | 95.3 | — | 95.3 | ||||||
Mortgage-backed securities | 17.2 | — | 17.2 | ||||||
Commingled fund (E) | 38.5 | — | 38.5 | ||||||
Common/collective trust (D) | 29.6 | — | 29.6 | ||||||
Foreign government bonds | 2.9 | — | 2.9 | ||||||
Interest-bearing cash | 2.1 | 2.1 | — | ||||||
U.S. municipal bonds | 1.7 | — | 1.7 | ||||||
Preferred stocks (foreign) | 0.6 | 0.6 | — | ||||||
Forward contracts | |||||||||
Receivable (foreign currency) | 4.1 | — | 4.1 | ||||||
Payable (foreign currency) | (4.1 | ) | — | (4.1 | ) | ||||
Total Plan investments | $ | 618.9 | $ | 360.7 | $ | 258.2 | |||
Receivable from broker for securities sold | 4.8 | ||||||||
Interest and dividends receivable | 3.1 | ||||||||
Payable to broker for securities purchased | (37.0 | ) | |||||||
Plan investments attributable to affiliates | (103.9 | ) | |||||||
Total Plan assets | $ | 485.9 |
(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. |
(E) | This category represents units of participation in a commingled fund that primarily invest in stocks and bonds of U.S. companies. |
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).
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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.
In January 2011, OGE Energy adopted several amendments to its retiree medical plan. Effective January 1, 2012, 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. Also, effective January 1, 2012, Medicare-eligible retirees are no longer eligible to participate in the retiree medical plan. Instead, OGE Energy began providing Medicare-eligible retirees and their Medicare-eligible spouses an annual fixed contribution to OGE Energy's sponsored health reimbursement arrangement. The contribution was determined based on OGE Energy's expected average 2011 premium for medical and drug coverage. 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. The effect of these plan amendments was reflected in OGE Energy's 2011 Consolidated Balance Sheet as a reduction to the accumulated postretirement benefit obligation of $91.3 million, an increase in other comprehensive income of $16.9 million and a reduction to OG&E's benefit obligations regulatory asset of $74.4 million.
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, 2012 and 2011. There were no Level 2 investments held by the postretirement benefit plans at December 31, 2012 and 2011.
(In millions) | December 31, 2012 | Level 1 | Level 3 | ||||||
Group retiree medical insurance contract (A) | $ | 53.3 | $ | — | $ | 53.3 | |||
Mutual funds investment | |||||||||
U.S. equity investments | 6.0 | 6.0 | — | ||||||
Money market funds investment | 0.3 | 0.3 | — | ||||||
Total Plan investments | $ | 59.6 | $ | 6.3 | $ | 53.3 | |||
Plan investments attributable to affiliates | (4.1 | ) | |||||||
Total Plan assets | $ | 55.5 |
(In millions) | December 31, 2011 | Level 1 | Level 3 | ||||||
Group retiree medical insurance contract (A) | $ | 54.3 | $ | — | $ | 54.3 | |||
Mutual funds investment | |||||||||
U.S. equity investments | 5.3 | 5.3 | — | ||||||
Money market funds investment | 0.7 | 0.7 | — | ||||||
Cash | 0.7 | 0.7 | — | ||||||
Total Plan investments | $ | 61.0 | $ | 6.7 | $ | 54.3 | |||
Plan investments attributable to affiliates | (3.8 | ) | |||||||
Total Plan assets | $ | 57.2 |
(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.
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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).
Year ended December 31 (In millions) | 2012 | ||
Group retiree medical insurance contract | |||
Beginning balance | $ | 54.3 | |
Net unrealized gains related to instruments held at the reporting date | 5.5 | ||
Interest income | 1.2 | ||
Dividend income | 0.6 | ||
Realized gains | 0.6 | ||
Administrative expenses and charges | (0.1 | ) | |
Claims paid | (8.8 | ) | |
Ending balance | $ | 53.3 |
The following table presents the status of OG&E's portion of OGE Energy's postretirement benefit plans at December 31, 2012 and 2011. 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.
December 31 (In millions) | 2012 | 2011 | ||||
Benefit obligations | $ | (236.4 | ) | $ | (223.1 | ) |
Fair value of plan assets | 55.5 | 57.2 | ||||
Funded status at end of year | $ | (180.9 | ) | $ | (165.9 | ) |
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 8.55 percent in 2013 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:
ONE-PERCENTAGE POINT INCREASE | |||||||||
Year ended December 31 (In millions) | 2012 | 2011 | 2010 | ||||||
Effect on aggregate of the service and interest cost components | $ | — | $ | — | $ | 2.4 | |||
Effect on accumulated postretirement benefit obligations | 0.1 | 0.1 | 0.5 |
ONE-PERCENTAGE POINT DECREASE | |||||||||
Year ended December 31 (In millions) | 2012 | 2011 | 2010 | ||||||
Effect on aggregate of the service and interest cost components | $ | 0.1 | $ | 0.1 | $ | 2.0 | |||
Effect on accumulated postretirement benefit obligations | 0.7 | 0.4 | 1.2 |
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.
(In millions) | Gross Projected Postretirement Benefit Payments | ||
2013 | $ | 13.1 | |
2014 | 13.6 | ||
2015 | 14.1 | ||
2016 | 14.5 | ||
2017 | 14.7 | ||
After 2017 | 75.4 |
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Obligations and Funded Status
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 for 2012 and 2011. 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 OGE Energy'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, 2012 was $549.3 million and $2.1 million, respectively. The accumulated postretirement benefit obligation for the Pension Plan and the Restoration of Retirement Income Plan at December 31, 2011 was $521.5 million and $2.1 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:
Pension Plan | Restoration of Retirement Income Plan | Postretirement Benefit Plans | ||||||||||||||||
December 31 (In millions) | 2012 | 2011 | 2012 | 2011 | 2012 | 2011 | ||||||||||||
Change in Benefit Obligation | ||||||||||||||||||
Beginning obligations | $ | (546.9 | ) | $ | (509.2 | ) | $ | (2.2 | ) | $ | (1.9 | ) | $ | (223.1 | ) | $ | (271.1 | ) |
Service cost | (10.9 | ) | (10.8 | ) | (0.1 | ) | (0.1 | ) | (2.7 | ) | (2.4 | ) | ||||||
Interest cost | (23.5 | ) | (26.2 | ) | (0.1 | ) | (0.1 | ) | (9.4 | ) | (10.0 | ) | ||||||
Plan amendments | — | — | — | — | — | 74.4 | ||||||||||||
Participants' contributions | — | — | — | — | (2.5 | ) | (6.4 | ) | ||||||||||
Medicare subsidies received | — | — | — | — | (0.5 | ) | (1.8 | ) | ||||||||||
Actuarial gains (losses) | (43.7 | ) | (36.1 | ) | (0.4 | ) | (0.2 | ) | (9.4 | ) | (20.8 | ) | ||||||
Benefits paid | 50.4 | 35.4 | 0.6 | 0.1 | 11.2 | 15.0 | ||||||||||||
Ending obligations | $ | (574.6 | ) | $ | (546.9 | ) | $ | (2.2 | ) | $ | (2.2 | ) | $ | (236.4 | ) | $ | (223.1 | ) |
Change in Plans' Assets | ||||||||||||||||||
Beginning fair value | $ | 485.9 | $ | 467.7 | $ | — | $ | — | $ | 57.2 | $ | 55.4 | ||||||
Actual return on plans' assets | 50.5 | 6.6 | — | — | 4.3 | 2.7 | ||||||||||||
Employer contributions | 33.0 | 47.0 | 0.6 | 0.1 | 2.2 | 5.9 | ||||||||||||
Participants' contributions | — | — | — | — | 2.5 | 6.4 | ||||||||||||
Medicare subsidies received | — | — | — | — | 0.5 | 1.8 | ||||||||||||
Benefits paid | (50.4 | ) | (35.4 | ) | (0.6 | ) | (0.1 | ) | (11.2 | ) | (15.0 | ) | ||||||
Ending fair value | $ | 519.0 | $ | 485.9 | $ | — | $ | — | $ | 55.5 | $ | 57.2 | ||||||
Funded status at end of year | $ | (55.6 | ) | $ | (61.0 | ) | $ | (2.2 | ) | $ | (2.2 | ) | $ | (180.9 | ) | $ | (165.9 | ) |
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Net Periodic Benefit Cost
Pension Plan | Restoration of Retirement Income Plan | Postretirement Benefit Plans | |||||||||||||||||||||||||
Year ended December 31 (In millions) | 2012 | 2011 | 2010 | 2012 | 2011 | 2010 | 2012 | 2011 | 2010 | ||||||||||||||||||
Service cost | $ | 10.9 | $ | 10.8 | $ | 10.1 | $ | 0.1 | $ | 0.1 | $ | — | $ | 2.7 | $ | 2.4 | $ | 2.9 | |||||||||
Interest cost | 23.5 | 26.2 | 25.4 | 0.1 | 0.1 | 0.1 | 9.4 | 10.0 | 13.7 | ||||||||||||||||||
Expected return on plan assets | (38.2 | ) | (37.3 | ) | (34.3 | ) | — | — | — | (2.8 | ) | (4.9 | ) | (6.6 | ) | ||||||||||||
Amortization of transition obligation | — | — | — | — | — | — | 2.5 | 2.6 | 2.6 | ||||||||||||||||||
Amortization of net loss | 19.3 | 15.6 | 17.6 | 0.1 | 0.1 | 0.1 | 17.4 | 15.5 | 10.2 | ||||||||||||||||||
Amortization of unrecognized prior service cost (A) | 2.2 | 2.5 | 2.5 | 0.2 | 0.2 | 0.2 | (13.6 | ) | (13.7 | ) | — | ||||||||||||||||
Settlement | — | — | — | 0.3 | — | — | — | — | — | ||||||||||||||||||
Net periodic benefit cost (B) | $ | 17.7 | $ | 17.8 | $ | 21.3 | $ | 0.8 | $ | 0.5 | $ | 0.4 | $ | 15.6 | $ | 11.9 | $ | 22.8 |
(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 $34.1 million, $30.2 million and $44.5 million of net periodic benefit cost recognized in 2012, 2011 and 2010, respectively, OG&E recognized the following: |
• | an increase in pension expense in 2012, 2011 and 2010 of $8.3 million, $10.8 million and $8.1 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 liability (see Note 1); and |
• | an increase in postretirement medical expense in 2012 and 2011 of $0.8 million and $3.5 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 liability (see Note 1). |
The capitalized portion of the net periodic pension benefit cost was $5.5 million, $5.3 million and $5.7 million at December 31, 2012, 2011 and 2010, respectively. The capitalized portion of the net periodic postretirement benefit cost was $4.7 million, $3.3 million and $5.8 million at December 31, 2012, 2011 and 2010, respectively.
Rate Assumptions
Pension Plan and Restoration of Retirement Income Plan | Postretirement Benefit Plans | |||||||||||
Year ended December 31 | 2012 | 2011 | 2010 | 2012 | 2011 | 2010 | ||||||
Discount rate | 3.70 | % | 4.50 | % | 5.30 | % | 3.60 | % | 4.50 | % | 5.30 | % |
Rate of return on plans' assets | 8.00 | % | 8.00 | % | 8.50 | % | 4.00 | % | 6.50 | % | 8.50 | % |
Compensation increases | 4.20 | % | 4.40 | % | 4.40 | % | N/A | N/A | N/A | |||
Assumed health care cost trend: | ||||||||||||
Initial trend | N/A | N/A | N/A | 8.55 | % | 8.75 | % | 8.99 | % | |||
Ultimate trend rate | N/A | N/A | N/A | 4.48 | % | 4.48 | % | 5.00 | % | |||
Ultimate trend year | N/A | N/A | N/A | 2028 | 2028 | 2020 |
N/A - not applicable
The overall expected rate of return on plan assets assumption remained at 8.00 percent in 2011 and 2012 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.
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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 $2.2 million and $1.8 million at December 31, 2012 and 2011, 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.
The 401(k) Plan was amended in October 2009, as discussed previously, whereby participants could select from the options below.
Employment Date | Option 1 | Option 2 | Option 3 |
Before February 1, 2000 | < 20 years of service - 50% Company match up to 6% of compensation | 200% Company match up to 5% of compensation | 100% Company match up to 6% of compensation |
> 20 years of service - 75% Company match up to 6% of compensation | 200% Company match up to 5% of compensation | 100% Company match up to 6% of compensation | |
After February 1, 2000 and before December 1, 2009 | 100% Company match up to 6% of compensation | 200% Company match up to 5% of compensation | N/A |
After December 1, 2009 | 200% Company match up to 5% of compensation | N/A | N/A |
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 $7.6 million, $7.0 million and $6.9 million in 2012, 2011 and 2010, 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
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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 the option the participant elected under the choice provided to eligible employees in the qualified 401(k) Plan discussed above, 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 2012, 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, and various money market, bond and equity funds.
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:
Year ended December 31 (In millions) | 2013 | 2014 | 2015 | 2016 | 2017 | After 2017 | Total | ||||||||||||||
Operating lease obligations | |||||||||||||||||||||
Railcars | $ | 3.2 | $ | 2.8 | $ | 2.7 | $ | 27.3 | $ | — | $ | — | $ | 36.0 | |||||||
Wind farm land leases | 2.0 | 2.1 | 2.1 | 2.1 | 2.4 | 51.2 | 61.9 | ||||||||||||||
Total operating lease obligations | $ | 5.2 | $ | 4.9 | $ | 4.8 | $ | 29.4 | $ | 2.4 | $ | 51.2 | $ | 97.9 |
Payments for operating lease obligations were $5.8 million, $4.2 million and $5.5 million for the years ended December 31, 2012, 2011 and 2010, respectively.
Railcar Lease Agreement
OG&E has a noncancellable operating lease with purchase options, covering 1,389 coal hopper 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.
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 is also required to maintain all of the railcars it has under lease to transport coal from Wyoming and has entered into agreements with Progress Rail Services and WATCO, both of which are non-affiliated companies, to furnish this maintenance.
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OG&E is also required to maintain all of the railcars it has under lease to transport coal from Wyoming and has entered into agreements with Progress Rail Services and WATCO, both of which are non-affiliated companies, to furnish this maintenance.
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:
(In millions) | 2013 | 2014 | 2015 | 2016 | 2017 | Total | ||||||||||||
Other purchase obligations and commitments | ||||||||||||||||||
Cogeneration capacity and fixed operation and maintenance payments | $ | 87.9 | $ | 85.8 | $ | 84.5 | $ | 82.4 | $ | 80.1 | $ | 420.7 | ||||||
Expected cogeneration energy payments | 58.6 | 63.8 | 70.5 | 81.0 | 87.3 | 361.2 | ||||||||||||
Minimum fuel purchase commitments | 452.5 | 535.6 | — | — | — | 988.1 | ||||||||||||
Expected wind purchase commitments | 57.5 | 58.0 | 58.9 | 59.8 | 60.8 | 295.0 | ||||||||||||
Long-term service agreement commitments | 8.0 | 27.8 | 6.7 | 6.2 | 6.4 | 55.1 | ||||||||||||
Total other purchase obligations and commitments | $ | 664.5 | $ | 771.0 | $ | 220.6 | $ | 229.4 | $ | 234.6 | $ | 2,120.1 |
Public Utility Regulatory Policy Act of 1978
At December 31, 2012, 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 PowerSmith Cogeneration Project, L.P. QF contract, OG&E purchases 100 percent of the electricity generated by the QFs.
For the years ended December 31, 2012, 2011 and 2010, OG&E made total payments to cogenerators of $135.1 million, $140.7 million and $147.3 million, respectively, of which $77.1 million, $78.0 million and $80.7 million, respectively, represented capacity payments. All payments for purchased power, including cogeneration, are included in the Statements of Income as Cost of Goods Sold.
Minimum Fuel Purchase Commitments
OG&E purchased necessary fuel supplies of coal and natural gas for its generating units of $653.7 million, $729.8 million and $819.3 million for the years ended December 31, 2012, 2011 and 2010, respectively. OG&E has coal contracts for purchases from January 2012 through December 2015. OG&E has entered into multiple month term natural gas contracts for 26.1 percent of its 2013 annual forecasted natural gas requirements. Additional gas supplies to fulfill OG&E's remaining 2013 natural gas requirements will be acquired through additional requests for proposal in early to mid-2013, along with monthly and daily purchases, all of which are expected to be made at market prices.
Wind Purchase Commitments
OG&E's current wind power portfolio includes: (i) the 120 MW Centennial wind farm, (ii) the 101 MW OU Spirit wind farm, (iii) the 227.5 MW Crossroads wind farm, (iv) 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, (v) access to up to 150 MWs of electricity generated at a wind farm in Woodward County, Oklahoma from a 20-year contract OG&E entered into with CPV Keenan
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that expires in 2030, (vi) 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 (vii) 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, 2012, 2011 and 2010.
Year ended December 31 (In millions) | 2012 | 2011 | 2010 | ||||||
CPV Keenan | $ | 25.1 | $ | 24.5 | $ | 3.8 | |||
Edison Mission Energy | 20.2 | 8.5 | — | ||||||
FPL Energy | 3.4 | 3.7 | 3.9 | ||||||
NextEra Energy | 0.8 | — | — | ||||||
Total wind power purchased | $ | 49.5 | $ | 36.7 | $ | 7.7 |
Long-Term Service Agreement Commitments
In July 2004, OG&E acquired a 77 percent interest in the McClain Plant. As part of that acquisition, OG&E became subject to an existing long-term parts and service maintenance contract for the upkeep of the natural gas-fired combined cycle generation facility. The contract was initiated in December 1999, and runs for the earlier of 96,000 factored-fired hours or 4,800 factored-fired starts. Based on historical usage and current expectations for future usage, this contract is expected to run until 2015. The contract requires payments based on both a fixed and variable cost component, depending on how much the McClain Plant is used.
In September 2008, OG&E acquired a 51 percent interest in the Redbud Plant. As part of that acquisition, OG&E became subject to an existing long-term parts and service maintenance contract for the upkeep of the natural gas-fired combined cycle generation facility. The contract was initiated in January 2001, and runs for the earlier of 120,000 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 2027. The contract requires payments based on both a fixed and variable cost component, depending on how much the Redbud Plant is used.
Environmental Laws and Regulations
The activities of OG&E are subject to stringent and complex Federal, state and local laws and regulations governing environmental protection including the discharge of materials into the environment. These laws and regulations can restrict or impact business activities in many ways, such as restricting the way it can handle or dispose of its wastes, requiring remedial action to mitigate pollution conditions that may be caused by its operations or that are attributable to former operators, regulating future construction activities to mitigate harm to threatened or endangered species and requiring the installation and operation of pollution control equipment. Failure to comply with these laws and regulations may 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.
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. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Environmental Laws and Regulations" for a discussion of OG&E's environmental matters.
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
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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, except as otherwise stated above, in Note 13 below, in Item 3 of Part I and under "Environmental Laws and Regulations" in Item 7 of Part II of this Form 10-K, 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 2012, 87 percent of OG&E's electric revenue was subject to the jurisdiction of the OCC, eight percent to the APSC and five 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
Contract and Wind Energy Purchase Agreement Filing
On December 1, 2011, OG&E filed an application with the OCC requesting approval of a 20-year agreement that is intended to provide wind power to help meet the current and future power generation needs of Oklahoma State University. The project called for OG&E to contract with NextEra Energy to build a 60 MW wind farm near Blackwell, Oklahoma, to support the Oklahoma State University project in which NextEra Energy built, owns and operates the wind farm and OG&E purchases the electric output. On February 22, 2012, OG&E, the Attorney General and the Public Utility Division of the OCC signed a settlement agreement whereby the stipulating parties requested that the OCC issue an order approving the agreement for electric service with Oklahoma State University. On March 12, 2012, OG&E received an order from the OCC approving the settlement agreement. Pursuant to the terms of the power purchase agreement between OG&E and NextEra Energy, OG&E has been purchasing the electric output of the wind farm since November 2012 and uses that power to provide service to Oklahoma State University and its other retail customers. The wind farm was fully in service in December 2012.
SPP Transmission Projects
The SPP is a regional transmission organization under the jurisdiction of the FERC that was created to ensure reliable supplies of power, adequate transmission infrastructure and competitive wholesale prices of electricity. The SPP does not build transmission though the SPP's tariff contains rules that govern the transmission construction process. Transmission owners complete the construction and then own, operate and maintain transmission assets within the SPP region. When the SPP Board of Directors approves a project, the transmission provider in the area where the project is needed currently has the first obligation to build; however, the process for deciding which entity constructs and owns a project may change as a result of FERC Order. No. 1000 discussed below.
There are several studies currently under review at the SPP including a 20-year plan to address issues of regional and interregional importance. The 20-year plan suggests overlaying the SPP footprint with a 345 kilovolt transmission system and integrating it with neighboring regional entities. In 2009, the SPP Board of Directors approved a new report that recommended restructuring the SPP's regional planning processes to focus on the construction of a robust transmission system, large enough in both scale and geography, to provide flexibility to meet the SPP's future needs. OG&E expects to actively participate in the ongoing study, development and transmission growth that may result from the SPP's plans.
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In 2007, the SPP notified OG&E to construct 44 miles of a new 345 kilovolt transmission line originating at OG&E's existing Sooner 345 kilovolt substation and proceeding generally in a northerly direction to the Oklahoma/Kansas Stateline (referred to as the Sooner-Rose Hill project). At the Oklahoma/Kansas Stateline, the line connects to the companion line constructed in Kansas by Westar Energy. The transmission line was placed in service in April 2012. The total capital expenditures associated with this project were $45 million.
In January 2009, OG&E received notification from the SPP to begin construction on 50 miles of a new 345 kilovolt transmission line and substation upgrades at OG&E's Sunnyside substation, among other projects. In April 2009, Western Farmers Electric Cooperative assigned to OG&E the construction of 50 miles of line designated by the SPP to be built by Western Farmers Electric Cooperative. The new line extends from OG&E's Sunnyside substation near Ardmore, Oklahoma, 123.5 miles to the Hugo substation owned by Western Farmers Electric Cooperative near Hugo, Oklahoma. The transmission line was completed in April 2012. The total capital expenditures associated with this project were $157 million.
As discussed below, the OCC approved a settlement agreement in OG&E's 2011 Oklahoma rate case filing that included an expedited procedure for recovering the costs of the two projects. On July 31, 2012, OG&E filed an application with the OCC requesting an order authorizing recovery for the two projects through the SPP transmission systems additions rider. On October 2, 2012, all parties signed a settlement agreement in this matter which stated: (i) the parties agree not to oppose requested relief sought by OG&E, (ii) OG&E will host meetings to discuss the SPP’s transmission planning process, including any future transmission projects for which OG&E has received a notice to construct from the SPP, and (iii) there will be opportunities for parties to provide input related to transmission planning studies that the SPP performs to identify future transmission projects. On October 25, 2012, the OCC issued an order approving the settlement agreement and granting OG&E cost recovery for the two projects. OG&E initiated cost recovery beginning with the first billing cycle in November 2012.
2011 Oklahoma Rate Case Filing
On July 28, 2011, OG&E filed its application with the OCC requesting an annual rate increase of $73.3 million, or a 4.3 percent increase in its rates. OG&E requested a return on equity of 11.0 percent based on a common equity percentage of 53.0 percent. In its application, OG&E requested recovery of increases in its operating costs and to begin earning on approximately $500 million of new capital investments made on behalf of its Oklahoma customers during the previous two and one-half years. On July 2, 2012, OG&E and other parties associated with its rate increase reached a settlement agreement in this matter. On July 9, 2012, the OCC issued an order approving the settlement agreement in this matter. Key terms of the settlement agreement included: (i) an annual net increase of approximately $4.3 million in OG&E's rates to its Oklahoma retail customers, (ii) OG&E's Oklahoma retail authorized return on equity of 10.2 percent, (iii) the rate of return under various recovery riders previously approved by the OCC, including riders for OG&E's smart grid implementation and Crossroads wind farm, is based on OG&E's actual debt and equity ratios as reflected in OG&E's application and a 10.2 percent return on equity, (iv) depreciation rates were implemented in the same month new customer rates went into effect, (v) the pension and postretirement medical cost tracker remains in effect, (vi) a procedure was established to expedite the recovery of the cost of specified high-voltage transmission projects and (vii) extension of funding for OG&E's system hardening program. OG&E expects the impact of the rate increase on its customers and service territory to be minimal as the rate increase will be more than offset by lower fuel costs attributable to prior fuel over recoveries from lower than forecasted fuel costs. OG&E implemented the new rates effective in early August.
Smart Grid Project
On December 17, 2010, OG&E filed an application with the APSC requesting pre-approval for system-wide deployment of smart grid technology and a recovery rider, including a credit for the Smart Grid grant awarded by the U.S. Department of Energy under the American Recovery and Reinvestment Act of 2009. On June 22, 2011, OG&E reached a settlement agreement with all the parties in this matter. OG&E and the other parties in this matter agreed to ask the APSC to approve the settlement agreement including the following: (i) pre-approval of system-wide deployment of smart grid technology in Arkansas and authorization for OG&E to begin recovering the prudently incurred costs of the Arkansas system-wide deployment of smart grid technology through a rider mechanism that will become effective in accordance with the order approving the settlement agreement; (ii) cost recovery through the rider would commence when all of the smart meters to be deployed in Arkansas are in service; (iii) OG&E guarantees that customers will receive certain operations and maintenance cost reductions resulting from the smart grid deployment as a credit to the recovery rider; and (iv) the stranded costs associated with OG&E's existing meters which are being replaced by smart meters will be accumulated in a regulatory asset and recovered in base rates beginning after an order is issued in OG&E's next general rate case. On August 3, 2011, the APSC issued an order in this matter approving the settlement agreement. On November 5, 2012, OG&E filed a revised smart grid recovery rider rate schedule. On December 13, 2012, the APSC issued an order in this matter approving the revised smart grid recovery rider to be effective beginning with the first billing cycle in January 2013 through December 2013. OG&E began recovering the estimated capital costs of $14 million and associated operation and maintenance costs for deployment of smart grid technology, along with incremental costs for web portal access and education
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of $0.8 million. The APSC also found that the prudence of OG&E’s smart grid expenditures will be determined in OG&E's next Arkansas rate case and that revenues collected under the rider are subject to refund, with interest, only in the event that the APSC determines that OG&E's smart grid expenditures were not prudent. The costs recoverable from Oklahoma customers for system-wide deployment of smart grid technology and implementing the smart grid pilot program were capped at $366.4 million (inclusive of the U.S. Department of Energy grant award amount) subject to an offset for any recovery of those costs from Arkansas customers and 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. This project was completed in late 2012 and the smart grid project costs did not exceed $366.4 million.
Demand and Energy Efficiency Program Filing
On July 2, 2012, OG&E filed an application with the OCC requesting approval of OG&E's 2013 demand portfolio, the authorization to recover the program costs, lost revenues associated with any achieved energy, demand savings and performance based incentives through the demand program rider and the recovery of costs associated with research and development investments. On July 16, 2012, OG&E filed an amended application which modified various calculations to reflect the rate of return authorized by the OCC in OG&E's 2011 rate case order and provided for consideration of a peak time rebate program. On December 20, 2012, the OCC approved a settlement with all parties in this matter. Key terms of the settlement included (i) approval of the program budgets proposed by OG&E and an additional amount of approximately $7 million over the three-year period for the energy efficiency programs, (ii) approval of OG&E’s proposed Demand Program Rider tariff, (iii) the recovery through the Demand Program Rider of the increased program costs and the net lost revenues, incentives and research and development investments requested by OG&E, with the exception of lost revenues resulting from the Integrated Volt Var Control program (automated intelligence to control voltage and power on the distribution lines) and incentives for the SmartHours® and Integrated Volt Var Control demand response programs, (iv) recovery of the program costs on a levelized basis over the three-year period, (v) consideration of implementing a peak time rebate program in 2015 and (vi) the periodic filing of additional reports. The Demand Program Rider became effective on January 1, 2013.
Fuel Adjustment Clause Review for Calendar Year 2010
The OCC routinely reviews the costs recovered from customers through OG&E’s fuel adjustment clause. On August 19, 2011, the OCC Staff filed an application to review OG&E’s fuel adjustment clause for calendar year 2010, including the prudence of OG&E’s electric generation, purchased power and fuel procurement costs. OG&E responded by filing direct testimony and the minimum filing review package on October 18, 2011. On September 26, 2012, the administrative law judge recommended that the OCC find that for the calendar year 2010 OG&E's generation, purchase power and fuel procurement processes and costs, including the cost of replacement power for the Sooner 2 outage, were prudent and no disallowance (as discussed below) for any of these expenses is warranted. On January 31, 2013, the OCC issued an order approving the administrative law judge's recommendation. Previously, the Oklahoma Industrial Energy Consumers recommended that the OCC disallow recovery of approximately $44 million of costs previously recovered through OG&E's fuel adjustment clause. These recommendations were based on allegations that OG&E's lower cost coal-fired generation was underutilized, that OG&E failed to aggressively pursue purchasing power at a cost lower than its marginal cost of generation and that OG&E should be found imprudent related to an unplanned outage at OG&E's Sooner 2 coal unit in November and December 2010. Previously, the OCC Staff recommended approval of OG&E's actions related to utilization of coal plants and practices related to purchasing power but recommended that OG&E refund $3 million to customers because of the Sooner 2 outage.
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.
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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 currently has 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 various transmission projects in Oklahoma. These changes to the "right of first refusal" apply only to "new transmission facilities," which are described as those subject to evaluation or reevaluation (under the applicable local or regional transmission planning process) subsequent to the effective date of the regulatory compliance filings required by the rule, which were filed on November 13, 2012.
OGE Energy cannot, at this time, determine the precise impact of Order No. 1000 on OG&E. OG&E has filed a petition for review in the D.C. Circuit relating to the same matter. Nevertheless, at the present time, 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.
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 rate sales outside the SPP's energy imbalance service market. A FERC order is pending.
Fuel Adjustment Clause Review for Calendar Year 2011
On July 31, 2012, the OCC Staff filed an application for a public hearing to review and monitor OG&E's application of the 2011 fuel adjustment clause and for a prudence review of OG&E's electric generation, purchased power and fuel procurement processes and costs in calendar year 2011. OG&E filed the necessary information and documents needed to satisfy the OCC's minimum filing requirement rules on October 1, 2012. On December 19, 2012, witnesses for the OCC Staff filed responsive testimony recommending that the OCC approve OG&E's fuel adjustment clause costs and recoveries for the calendar year 2011 and recommending that the OCC find that OG&E's electric generation, purchased power, fuel procurement and other fuel related practices, policies and decisions during calendar year 2011 were fair, just and reasonable and prudent. The Oklahoma Industrial Energy Consumers filed a statement of position on December 19, 2012 and did not challenge OG&E's application of its fuel adjustment clause or prudency. The Oklahoma Industrial Energy Consumers reserved its right to file rebuttal testimony, cross examine witnesses and amend its statement of position should circumstances change or additional information becomes available in the course of this proceeding. On January 7, 2013, the Oklahoma Attorney General filed a statement of position stating that after reviewing the case information the Attorney General has no reason at this time to dispute the findings of the OCC Staff. A hearing in this matter is scheduled for April 4, 2013.
Crossroads Wind Farm
As previously reported, OG&E signed memoranda of understanding in February 2010 for approximately 197.8 MWs of wind turbine generators and certain related balance of plant engineering, procurement and construction services associated with the Crossroads wind farm. Also as part of this project, on June 16, 2011, OG&E entered into an interconnection agreement with the SPP for the Crossroads wind farm which allowed the Crossroads wind farm to interconnect at 227.5 MWs. On August 31, 2012, OG&E filed an application with the APSC requesting approval to recover the Arkansas portion of the costs of the Crossroads wind farm through a rider until such costs are included in OG&E's base rates as part of its next general rate proceeding. On December 14, 2012, the APSC Staff filed testimony recommending that the APSC find that the Crossroads wind farm is in the public interest and that it approve interim recovery through the Energy Cost Recovery Rider effective August 31, 2012. OG&E concurred with the APSC Staff’s recommendations. On January 16, 2013, the APSC granted a motion made by OG&E and the APSC Staff to cancel the hearing previously scheduled and issue an order based on the filed record. On February 22, 2013, the APSC directed OG&E to respond to two questions in order to complete the record upon which they may rule. OG&E believes it is reasonable to expect a final order from the APSC by the end of the first quarter.
Fuel Adjustment Clause Review for Calendar Year 2009 Related to Enogex Gas Transportation and Storage Agreement
As previously reported, under the terms of a settlement agreement reached in 2011 regarding the prudency of OG&E's fuel adjustment clause for 2009, OG&E agreed to hire a third party expert to evaluate its prospective gas transportation and storage
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needs and to identify options for meeting those needs. Upon completion of the third party evaluation, OG&E agreed to file a cause to address the third party's evaluation, recommendations and conclusions. On January 31, 2013, OG&E filed a cause that included OG&E's response to the final evaluations and conclusions of the third party consultant, Black & Veatch, and OG&E's assessment of transportation and storage needs for the next three to five years.
Also, as part of this matter, on August 9, 2012, OG&E filed an application with the OCC requesting: (i) an order finding that a one-year extension to April 30, 2014 of OG&E's gas transportation and storage agreement with Enogex is prudent, (ii) a waiver of the OCC's competitive procurement rules and (iii) finding that the one-year extension of the gas transportation and storage agreement complies with the OCC's affiliate transaction rules. On September 14, 2012, OG&E filed a settlement agreement in which all parties to this matter agreed to the one-year extension of the Enogex contract and cost recovery from ratepayers at the rates currently in effect. On October 25, 2012, the OCC issued an order approving the settlement agreement.
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:
Quarter ended (In millions) | March 31 | June 30 | September 30 | December 31 | Total | |||||||||||
Operating revenues | 2012 | $ | 426.7 | $ | 528.0 | $ | 721.0 | $ | 465.5 | $ | 2,141.2 | |||||
2011 | $ | 422.1 | $ | 568.7 | $ | 774.8 | $ | 445.9 | $ | 2,211.5 | ||||||
Operating income | 2012 | $ | 39.8 | $ | 127.8 | $ | 258.0 | $ | 63.8 | $ | 489.4 | |||||
2011 | $ | 26.0 | $ | 133.3 | $ | 258.7 | $ | 54.3 | $ | 472.3 | ||||||
Net income | 2012 | $ | 12.1 | $ | 73.4 | $ | 167.2 | $ | 27.6 | $ | 280.3 | |||||
2011 | $ | 6.4 | $ | 78.6 | $ | 158.6 | $ | 19.7 | $ | 263.3 |
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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, 2012 and 2011, 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, 2012. Our audits also included the financial statement schedule listed in the Index at Item 15(a). These financial statements and schedule are the responsibility of the company's management. Our responsibility is to express an opinion on these financial statements 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, 2012 and 2011, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2012, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.
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, 2012, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 27, 2013 expressed an unqualified opinion thereon.
/s/ Ernst & Young LLP | ||
Ernst & Young LLP |
Oklahoma City, Oklahoma
February 27, 2013
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Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.
None.
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).
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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, 2012. 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. Based on our assessment, we believe that, as of December 31, 2012,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, President | Scott Forbes, Controller | |
and Chief Executive Officer | and Chief Accounting Officer | |
/s/ Sean Trauschke | ||
Sean Trauschke, Vice President | ||
and Chief Financial Officer |
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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, 2012, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (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, 2012, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the balance sheets and statements of capitalization of Oklahoma Gas and Electric Company as of December 31, 2012 and 2011, 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, 2012 of Oklahoma Gas and Electric Company and our report dated February 27, 2013 expressed an unqualified opinion thereon.
/s/ Ernst & Young LLP | ||
Ernst & Young LLP |
Oklahoma City, Oklahoma
February 27, 2013
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Item 9B. Other Information.
None.
PART III
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. 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. 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. 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.
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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
Year ended December 31 | 2012 | 2011 | ||||
Integrated audit of OGE Energy and its subsidiaries financial statements and internal control over financial reporting | $ | 1,610,000 | $ | 1,610,000 | ||
Services in support of debt and stock offerings | 7,500 | 60,000 | ||||
Other (A) | 447,100 | 456,200 | ||||
Total audit fees (B) | 2,064,600 | 2,126,200 | ||||
Employee benefit plan audits | 120,000 | 116,000 | ||||
Other (C) | 130,665 | 106,840 | ||||
Total audit-related fees | 250,665 | 222,840 | ||||
Assistance with examinations and other return issues | 175,215 | 107,850 | ||||
Review of Federal and state tax returns | 27,500 | 26,000 | ||||
Total tax preparation and compliance fees | 202,715 | 133,850 | ||||
Total tax fees | 202,715 | 133,850 | ||||
Total fees | $ | 2,517,980 | $ | 2,482,890 |
(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 2012, this amount includes estimated billings for the completion of the 2012 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 2012 and 2011 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 2012, 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.
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PART IV
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, 2012, 2011 and 2010 |
• | Statements of Comprehensive Income for the years ended December 31, 2012, 2011 and 2010 |
• | Statements of Cash Flows for the years ended December 31, 2012, 2011 and 2010 |
• | Balance Sheets at December 31, 2012 and 2011 |
• | Statements of Capitalization at December 31, 2012 and 2011 |
• | Statements of Changes in Stockholder's Equity for the years ended December 31, 2012, 2011 and 2010 |
• | 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.
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3. Exhibits
Exhibit No. | Description |
2.01 | Asset Purchase Agreement, dated as of August 18, 2003 by and between OG&E and NRG McClain LLC. (Certain exhibits and schedules were omitted and registrant agrees to furnish supplementally a copy of such omitted exhibits and schedules to the Commission upon request) (Filed as Exhibit 2.01 to OGE Energy's Form 8-K filed August 20, 2003 (File No. 1-12579) and incorporated by reference herein) |
2.02 | Amendment No. 1 to Asset Purchase Agreement, dated as of October 22, 2003 by and between OG&E and NRG McClain LLC. (Filed as Exhibit 2.03 to OGE Energy's Form 10-K for the year ended December 31, 2003 (File No. 1-12579) and incorporated by reference herein) |
2.03 | Amendment No. 2 to Asset Purchase Agreement, dated as of October 27, 2003 by and between OG&E and NRG McClain LLC. (Filed as Exhibit 2.04 to OGE Energy's Form 10-K for the year ended December 31, 2003 (File No. 1-12579) and incorporated by reference herein) |
2.04 | Amendment No. 3 to Asset Purchase Agreement, dated as of November 25, 2003 by and between OG&E and NRG McClain LLC. (Filed as Exhibit 2.05 to OGE Energy's Form 10-K for the year ended December 31, 2003 (File No. 1-12579) and incorporated by reference herein) |
2.05 | Amendment No. 4 to Asset Purchase Agreement, dated as of January 28, 2004 by and between OG&E and NRG McClain LLC. (Filed as Exhibit 2.06 to OGE Energy's Form 10-K for the year ended December 31, 2003 (File No. 1-12579) and incorporated by reference herein) |
2.06 | Amendment No. 5 to Asset Purchase Agreement, dated as of February 13, 2004 by and between OG&E and NRG McClain LLC. (Filed as Exhibit 2.07 to OGE Energy's Form 10-K for the year ended December 31, 2003 (File No. 1-12579) and incorporated by reference herein) |
2.07 | Amendment No. 6 to Asset Purchase Agreement, dated as of March 12, 2004 by and between OG&E and NRG McClain LLC. (Filed as Exhibit 2.01 to OGE Energy's Form 10-Q for the quarter ended March 31, 2004 (File No. 1-12579) and incorporated by reference herein) |
2.08 | Amendment No. 7 to Asset Purchase Agreement, dated as of April 15, 2004 by and between OG&E and NRG McClain LLC. (Filed as Exhibit 2.02 to OGE Energy's Form 10-Q for the quarter ended March 31, 2004 (File No. 1-12579) and incorporated by reference herein) |
2.09 | Amendment No. 8 to Asset Purchase Agreement, dated as of May 15, 2004 by and between OG&E and NRG McClain LLC. (Filed as Exhibit 2.01 to OGE Energy's Form 10-Q for the quarter ended June 30, 2004 (File No. 1-12579) and incorporated by reference herein) |
2.10 | Amendment No. 9 to Asset Purchase Agreement, dated as of June 2, 2004 by and between OG&E and NRG McClain LLC. (Filed as Exhibit 2.02 to OGE Energy's Form 10-Q for the quarter ended June 30, 2004 (File No. 1-12579) and incorporated by reference herein) |
2.11 | Amendment No. 10 to Asset Purchase Agreement, dated as of June 17, 2004 by and between OG&E and NRG McClain LLC. (Filed as Exhibit 2.03 to OGE Energy's Form 10-Q for the quarter ended June 30, 2004 (File No. 1-12579) and incorporated by reference herein) |
2.12 | Purchase and Sale Agreement, dated as of January 21, 2008, entered into by and among Redbud Energy I, LLC, Redbud Energy II, LLC and Redbud Energy III, LLC and OG&E. (Certain exhibits and schedules hereto have been omitted and the registrant agrees to furnish supplementally a copy of such omitted exhibits and schedules to the Commission upon request) (Filed as Exhibit 2.01 to OGE Energy's Form 8-K filed January 25, 2008 (File No. 1-12579) and incorporated by reference herein) |
2.13 | Asset Purchase Agreement, dated as of January 21, 2008, entered into by and among OG&E, the Oklahoma Municipal Power Authority and the Grand River Dam Authority. (Certain exhibits and schedules hereto have been omitted and the registrant agrees to furnish supplementally a copy of such omitted exhibits and schedules to the Commission upon request) (Filed as Exhibit 2.01 to OGE Energy's Form 8-K filed January 25, 2008 (File No. 1-12579) and incorporated by reference herein) |
3.01 | Copy of Restated Oklahoma Gas and Electric Company Certificate of Incorporation. (Filed as Exhibit 3.01 to OG&E's Form 8-K filed May 19, 2011 (File No. 1-1097) and incorporated by reference herein) |
3.02 | Copy of Amended Oklahoma Gas and Electric Company By-laws dated May 19, 2011. (Filed as Exhibit 3.02 to OG&E's Form 8-K filed May 19, 2011 (File No. 1-1097) and incorporated by reference herein) |
4.01 | Trust Indenture dated October 1, 1995, from OG&E to Boatmen's First National Bank of Oklahoma, Trustee. (Filed as Exhibit 4.29 to Registration Statement No. 33-61821 and incorporated by reference herein) |
4.02 | Supplemental Indenture No. 2, dated as of July 1, 1997, being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 4.01 to OG&E's Form 8-K filed July 17, 1997 (File No. 1-1097) and incorporated by reference herein) |
4.03 | Supplemental Indenture No. 3, dated as of April 1, 1998, being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 4.01 to OG&E's Form 8-K filed April 16, 1998 (File No. 1-1097) and incorporated by reference herein) |
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4.04 | Supplemental Indenture No. 5 dated as of October 24, 2001, being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 4.06 to Registration Statement No. 333-104615 and incorporated by reference herein) |
4.05 | Supplemental Indenture No. 6 dated as of August 1, 2004, being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 4.02 to OG&E's Form 8-K filed August 6, 2004 (File No 1-1097) and incorporated by reference herein) |
4.06 | Supplemental Indenture No. 7 dated as of January 1, 2006 being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 4.08 to OG&E's Form 8-K filed January 6, 2006 (File No. 1-1097) and incorporated by reference herein) |
4.07 | Supplemental Indenture No. 8 dated as of January 15, 2008 being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 4.01 to OG&E's Form 8-K filed January 31, 2008 (File No. 1-1097) and incorporated by reference herein) |
4.08 | Supplemental Indenture No. 9 dated as of September 1, 2008 being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 4.01 to OG&E's Form 8-K filed September 9, 2008 (File No. 1-1097) and incorporated by reference herein) |
4.09 | Supplemental Indenture No. 10 dated as of December 1, 2008 being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 4.01 to OG&E's Form 8-K filed December 11, 2008 (File No. 1-1097) and incorporated by reference herein) |
4.10 | Supplemental Indenture No. 11 dated as of June 1, 2010 being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 4.01 to OG&E's Form 8-K filed June 8, 2010 (File No. 1-1097) and incorporated by reference herein) |
4.11 | Supplemental Indenture No. 12 dated as of May 15, 2011 being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 4.01 to OG&E's Form 8-K filed May 27, 2011 (File No. 1-1097) and incorporated by reference herein) |
10.01* | OGE Energy's 1998 Stock Incentive Plan. (Filed as Exhibit 10.07 to OGE Energy's Form 10-K for the year ended December 31, 1998 (File No. 1-12579) and incorporated by reference herein) |
10.02* | OGE Energy's 2003 Stock Incentive Plan. (Filed as Annex A to OGE Energy's Proxy Statement for the 2003 Annual Meeting of Shareowners (File No. 1-12579) and incorporated by reference herein) |
10.03 | Copy of Settlement Agreement with Oklahoma Corporation Commission Staff, the Oklahoma Attorney General and others relating to OG&E's rate case. (Filed as Exhibit 99.02 to OGE Energy's Form 8-K filed July 9, 2012 (File No. 1-12579) and incorporated by reference herein) |
10.04 | Amended and Restated Facility Operating Agreement for the McClain Generating Facility dated as of July 9, 2004 between OG&E and the Oklahoma Municipal Power Authority. (Filed as Exhibit 10.03 to OGE Energy's Form 10-Q for the quarter ended June 30, 2004 (File No. 1-12579) and incorporated by reference herein) |
10.05 | Amended and Restated Ownership and Operation Agreement for the McClain Generating Facility dated as of July 9, 2004 between OG&E and the Oklahoma Municipal Power Authority. (Filed as Exhibit 10.04 to OGE Energy's Form 10-Q for the quarter ended June 30, 2004 (File No. 1-12579) and incorporated by reference herein) |
10.06 | Operating and Maintenance Agreement for the Transmission Assets of the McClain Generating Facility dated as of August 25, 2003 between OG&E and the Oklahoma Municipal Power Authority. (Filed as Exhibit 10.05 to OGE Energy's Form 10-Q for the quarter ended June 30, 2004 (File No. 1-12579) and incorporated by reference herein) |
10.07* | Amendment No. 1 to OGE Energy's 2003 Stock Incentive Plan. (Filed as Exhibit 10.23 to OGE Energy's Form 10-K for the year ended December 31, 2004 (File No. 1-12579) and incorporated by reference herein) |
10.08 | Intrastate Firm No-Notice, Load Following Transportation and Storage Services Agreement dated as of May 1, 2003 between OG&E and Enogex. [Confidential treatment has been requested for certain portions of this exhibit.] (Filed as Exhibit 10.24 to OGE Energy's Form 10-K for the year ended December 31, 2004 (File No. 1-12579) and incorporated by reference herein) |
10.09* | Form of Performance Unit Agreement under OGE Energy's 2008 Stock Incentive Plan. (Filed as Exhibit 10.01 to OGE Energy's Form 10-Q for the quarter ended March 31, 2012 (File No. 1-12579) and incorporated by reference herein) |
10.10* | Form of Split Dollar Agreement. (Filed as Exhibit 10.32 to OGE Energy's Form 10-K for the year ended December 31, 2004 (File No. 1-12579) and incorporated by reference herein) |
10.11 | Credit agreement dated as of December 13, 2011, by and between OG&E, the Lenders thereto, Wells Fargo Bank, National Association, as Administrative Agent, JPMorgan Chase Bank, N.A., as Syndication Agent, Mizuho Corporate Bank, Ltd., The Royal Bank of Scotland PLC, UBS Securities LLC and Union Bank, N.A., as Co-Documentation Agents. (Filed as Exhibit 99.02 to OGE Energy's Form 8-K filed December 19, 2011 (File No. 1-12579) and incorporated by reference herein) |
10.12* | Amendment No. 1 to OGE Energy's 1998 Stock Incentive Plan. (Filed as Exhibit 10.26 to OGE Energy's Form 10-K for the year ended December 31, 2006 (File No. 1-12579) and incorporated by reference herein) |
10.13* | Amendment No. 2 to OGE Energy's 2003 Stock Incentive Plan. (Filed as Exhibit 10.27 to OGE Energy's Form 10-K for the year ended December 31, 2006 (File No. 1-12579) and incorporated by reference herein) |
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10.14 | Ownership and Operating Agreement, dated as of January 21, 2008, entered into by and among OG&E, the Oklahoma Municipal Power Authority and the Grand River Dam Authority. (Filed as Exhibit 10.01 to OGE Energy's Form 8-K filed January 25, 2008 (File No. 1-12579) and incorporated by reference herein) |
10.15* | OGE Energy Supplemental Executive Retirement Plan, as amended and restated. (Filed as Exhibit 10.03 to OGE Energy's Form 10-Q for the quarter ended March 31, 2008 (File No. 1-12579) and incorporated by reference herein) |
10.16* | OGE Energy Restoration of Retirement Income Plan, as amended and restated. (Filed as Exhibit 10.04 to OGE Energy's Form 10-Q for the quarter ended March 31, 2008 (File No. 1-12579) and incorporated by reference herein) |
10.17* | OGE Energy Deferred Compensation Plan, as amended and restated. (Filed as Exhibit 10.05 to OGE Energy's Form 10-Q for the quarter ended March 31, 2008 (File No. 1-12579) and incorporated by reference herein) |
10.18* | Amendment No. 3 to OGE Energy's 2003 Stock Incentive Plan. (Filed as Exhibit 10.06 to OGE Energy's Form 10-Q for the quarter ended March 31, 2008 (File No. 1-12579) and incorporated by reference herein) |
10.19* | Amendment No. 2 to OGE Energy's 1998 Stock Incentive Plan. (Filed as Exhibit 10.07 to OGE Energy's Form 10-Q for the quarter ended March 31, 2008 (File No. 1-12579) and incorporated by reference herein) |
10.20* | OGE Energy's 2008 Stock Incentive Plan. (Filed as Annex A to OGE Energy's Proxy Statement for the 2008 Annual Meeting of Shareowners (File No. 1-12579) and incorporated by reference herein) |
10.21* | OGE Energy's 2008 Annual Incentive Compensation Plan. (Filed as Annex B to OGE Energy's Proxy Statement for the 2008 Annual Meeting of Shareowners (File No. 1-12579) and incorporated by reference herein) |
10.22 | Form of Employment Agreement for all existing and future officers of OG&E relating to change of control. (Filed as Exhibit 10.28 to OGE Energy's Form 10-K for the year ended December 31, 2011 (File No. 1-12579) and incorporated by reference herein) |
10.23* | Form of Restricted Stock Agreement under OGE Energy's 2008 Stock Incentive Plan. (Filed as Exhibit 10.01 to OGE Energy's Form 10-Q for the quarter ended September 30, 2008 (File No. 1-12579) and incorporated by reference herein) |
10.24 | Agreement, dated February 17, 2010, between OG&E and Oklahoma Department of Environmental Quality. (Filed as Exhibit 99.01 to OGE Energy's Form 8-K filed February 23, 2010 (File No. 1-12579) and incorporated by reference herein) |
10.25* | Amendment No. 1 to OGE Energy's Restoration of Retirement Income Plan. (Filed as Exhibit 10.40 to OGE Energy's Form 10-K for the year ended December 31, 2009 (File No. 1-12579) and incorporated by reference herein) |
10.26* | Amendment No. 1 to OGE Energy's Deferred Compensation Plan. (Filed as Exhibit 10.33 to OGE Energy's Form 10-K for the year ended December 31, 2011 (File No. 1-12579) and incorporated by reference herein) |
10.27 | Copy of Settlement Agreement with Oklahoma Corporation Commission Staff, the Oklahoma Attorney General and others relating to OG&E's Smart Grid application. (Filed as Exhibit 99.02 to OGE Energy's Form 8-K filed June 1, 2010 (File No. 1-12579) and incorporated by reference herein) |
10.28 | Copy of Settlement Agreement with Oklahoma Corporation Commission Staff, the Oklahoma Attorney General and others relating to OG&E's Crossroads wind farm application. (Filed as Exhibit 99.01 to OGE Energy's Form 8-K filed July 1, 2010 (File No. 1-12579) and incorporated by reference herein) |
10.29 | Copy of Settlement Agreement with Arkansas Public Service Commission Staff, the Arkansas Attorney General and others relating to OG&E's rate case. (Filed as Exhibit 99.01 to OGE Energy's Form 8-K filed May 19, 2011 (File No. 1-12579) and incorporated by reference herein) |
10.30 | Copy of Settlement Agreement with Arkansas Public Service Commission Staff, the Arkansas Attorney General and others relating to OG&E's Smart Grid application. (Filed as Exhibit 99.01 to OGE Energy's Form 8-K filed June 28, 2011 (File No. 1-12579) and incorporated by reference herein) |
10.31* | Amendment No. 2 to OGE Energy's Deferred Compensation Plan. (Filed as Exhibit 10.41 to OGE Energy's Form 10-K for the year ended December 31, 2009 (File No. 1-12579) and incorporated by reference herein) |
10.32* | Amendment No. 3 to OGE Energy's Deferred Compensation Plan. (Filed as Exhibit 10.39 to OGE Energy's Form 10-K for the year ended December 31, 2011 (File No. 1-12579) and incorporated by reference herein) |
10.33* | Amendment No. 1 to OGE Energy's 2008 Stock Incentive Plan. (Filed as Exhibit 10.40 to OGE Energy's Form 10-K for the year ended December 31, 2011 (File No. 1-12579) and incorporated by reference herein) |
10.34* | Director Compensation. (Filed as Exhibit 10.38 to OGE Energy's Form 10-K for the year ended December 31, 2012 (File No. 1-12579) and incorporated by reference herein) |
10.35* | Executive Officer Compensation. (Filed as Exhibit 10.39 to OGE Energy's Form 10-K for the year ended December 31, 2012 (File No. 1-12579) and incorporated by reference herein) |
12.01 | Calculation of Ratio of Earnings to Fixed Charges. |
23.01 | Consent of Ernst & Young LLP. |
24.01 | Power of Attorney. |
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31.01 | Certifications Pursuant to Rule 13a-14(a)/15d-14(a) As Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
32.01 | Certification Pursuant to 18 U.S.C. Section 1350 As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
99.01 | Cautionary Statement for Purposes of the "Safe Harbor" Provisions of the Private Securities Litigation Reform Act of 1995. |
99.02 | Copy of APSC order with Arkansas Public Service Commission Staff, the Arkansas Attorney General and others relating to OG&E's rate case. (Filed as Exhibit 99.02 to OGE Energy's Form 8-K filed June 22, 2011 (File No. 1-12579) and incorporated by reference herein) |
99.03 | Copy of OCC Order with Oklahoma Corporation Commission Staff, the Oklahoma Attorney General and others relating to OG&E's Smart Grid application. (Filed as Exhibit 99.02 to OGE Energy's Form 8-K filed July 7, 2010 (File No. 1-12579) and incorporated by reference herein) |
99.04 | Copy of OCC Order with Oklahoma Corporation Commission Staff, the Oklahoma Attorney General and others relating to OG&E's Crossroads wind farm application. (Filed as Exhibit 99.04 to OGE Energy's Form 10-Q for the quarter ended June 30, 2010 (File No. 1-12579) and incorporated by reference herein) |
101.INS | XBRL Instance Document. |
101.SCH | XBRL Taxonomy Schema Document. |
101.PRE | XBRL Taxonomy Presentation Linkbase Document. |
101.LAB | XBRL Taxonomy Label Linkbase Document. |
101.CAL | XBRL Taxonomy Calculation Linkbase Document. |
101.DEF | XBRL Definition Linkbase Document. |
* Represents executive compensation plans and arrangements. |
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OKLAHOMA GAS AND ELECTRIC COMPANY
SCHEDULE II - Valuation and Qualifying Accounts
Additions | ||||||||||||
Description | Balance at Beginning of Period | Charged to Costs and Expenses | Deductions (A) | Balance at End of Period | ||||||||
(In millions) | ||||||||||||
Balance at December 31, 2010 | ||||||||||||
Reserve for Uncollectible Accounts | $ | 1.7 | $ | 2.7 | $ | 2.8 | $ | 1.6 | ||||
Balance at December 31, 2011 | ||||||||||||
Reserve for Uncollectible Accounts | $ | 1.6 | $ | 5.8 | $ | 3.7 | $ | 3.7 | ||||
Balance at December 31, 2012 | ||||||||||||
Reserve for Uncollectible Accounts | $ | 3.7 | $ | 3.3 | $ | 4.4 | $ | 2.6 |
(A) | Uncollectible accounts receivable written off, net of recoveries. |
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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 27th day of February, 2013.
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 27, 2013 | ||
/s/ Sean Trauschke | |||
Sean Trauschke | Principal Financial Officer; and | February 27, 2013 | |
/s/ Scott Forbes | |||
Scott Forbes | Principal Accounting Officer. | February 27, 2013 | |
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; and | ||
Leroy C. Richie | Director. |
/s/ Peter B. Delaney | |||
By Peter B. Delaney (attorney-in-fact) | February 27, 2013 |
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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.
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