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OGE ENERGY CORP. - 10-K - Management's Discussion and Analysis of Financial Condition and Results of Operations.
[February 27, 2013]

OGE ENERGY CORP. - 10-K - Management's Discussion and Analysis of Financial Condition and Results of Operations.

(Edgar Glimpses Via Acquire Media NewsEdge) Introduction The Company is 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. The Company conducts these activities through three business segments: (i) electric utility, (ii) natural gas transportation and storage and (iii) natural gas gathering and processing.

The electric utility segment generates, transmits, distributes and sells electric energy in Oklahoma and western Arkansas. Its operations are conducted through OG&E and 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.

Enogex is a provider of integrated natural gas midstream services. Enogex is engaged in the business of gathering, processing, transporting and storing natural gas. Most of Enogex's natural gas gathering, processing, transportation and storage assets are strategically located in the Arkoma and Anadarko basins of Oklahoma and the Texas Panhandle. During the third quarter of 2012, the operations and activities of EER were fully integrated with those of Enogex through the creation of a new commodity management organization. This new organization is intended to facilitate the execution of Enogex's strategy through an enhanced focus on asset optimization and active management of its growing natural gas, NGLs and condensate positions. The operations of EER, including asset management activities, have been included in the natural gas transportation and storage segment and have been restated for all prior periods presented. Enogex's operations are now organized into two business segments: (i) natural gas transportation and storage and (ii) natural gas gathering and processing. At December 31, 2012, OGE Energy indirectly owns a 79.9 percent membership interest in Enogex Holdings, which in turn owns all of the membership interests in Enogex LLC.

Overview Company Strategy The Company'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. The Company'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.

Enogex's business plan entails growing its businesses and providing attractive financial returns through efficient operations and effective commercial management of its assets. Enogex also plans to capture growth opportunities through expansion projects, increased utilization of existing assets and through acquisitions (including joint ventures) in and around its footprint and attracting new customers. In addition, Enogex is seeking to geographically diversify its gathering, processing and transportation businesses principally by expanding into other areas that are complementary with the Company's capabilities. Enogex expects to accomplish this diversification by undertaking organic growth projects and through acquisitions.

Additionally, the Company wants to achieve a premium valuation of its businesses relative to its peers, grow earnings per share with a stable earnings pattern, create a high performance culture and achieve desired outcomes with target stakeholders.

43 -------------------------------------------------------------------------------- The Company's financial objectives include a long-term annual earnings growth rate of five to seven percent on a weather-normalized basis, maintaining a strong credit rating as well as increasing the dividend to meet the Company's dividend payout objectives. The Company's target payout ratio is to pay out dividends no more than 60 percent of its normalized earnings on an annual basis.

The target payout ratio has been determined after consideration of numerous factors, including the largely retail composition of the Company's shareholder base, the Company's financial position, the Company's growth targets, the composition of the Company's assets and investment opportunities. The Company believes it can accomplish these financial objectives by, among other things, pursuing multiple avenues to build its business, maintaining a diversified asset position, continuing to develop a wide range of skills to succeed with changes in its industries, providing products and services to customers efficiently, managing risks effectively and maintaining strong regulatory and legislative relationships.

Summary of Operating Results 2012 compared to 2011. Net income attributable to OGE Energy was $355.0 million, or $3.58 per diluted share, in 2012 as compared to $342.9 million, or $3.45 per diluted share, in 2011. The increase in net income attributable to OGE Energy of $12.1 million, or 3.5 percent, or $0.13 per diluted share, in 2012 as compared to 2011 was primarily due to: • an increase in net income at OG&E of $17.0 million, or 6.5 percent, or $0.18 per diluted share of the Company's common stock, 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; • a decrease in net income at Enogex of $8.1 million, or 9.9 percent, or $0.08 per diluted share of the Company's common stock, primarily due to higher other operation and maintenance expense, higher depreciation and amortization expense, lower other income primarily due to the recognition of a gain related to the sale of the Harrah processing plant and the associated Wellston and Davenport gathering assets in 2011, higher interest expense and OGE Energy's lower membership interest in Enogex Holdings. These decreases were partially offset by a higher gross margin related to (i) increased gathering rates and volumes associated with ongoing expansion projects and increased volumes from gas gathering assetsacquired in November 2011 and August 2012 and (ii) increased inlet volumes partially offset by lower average natural gas and NGLs prices. Also having a positive impact on net income was a higher gain on insurance proceeds in 2012 and an impairment related to the Atoka processing plant in 2011; and • an increase in net income at OGE Energy of $3.2 million, or $0.03 per diluted share of the Company's common stock, primarily due to higher other income due to a decrease in deferred compensation losses partially offset by higher interest expense and a lower income tax benefit in 2012.

Non-Recurring Items. During 2012, Enogex had an increase in net income of $4.6 million due to a gain on insurance proceeds related to the reimbursement of costs incurred to replace the damaged train at the Cox City natural gas processing plant partially offset by a decrease in net income of $2.1 million related to sales taxes on the assets acquired in the gas gathering acquisitions in August 2012, as discussed in Note 3 of Notes to Consolidated Financial Statements, which Enogex does not consider to be reflective of its ongoing performance. During 2011, Enogex had an increase in net income of $2.3 million relating to the sale of the Harrah processing plant and the associated Wellston and Davenport gathering assets in April 2011, which Enogex does not consider to be reflective of its ongoing performance.

2011 compared to 2010. Net income attributable to OGE Energy was $342.9 million, or $3.45 per diluted share, in 2011 as compared to $295.3 million, or $2.99 per diluted share, in 2010. Included in net income attributable to OGE Energy in 2010 was a one-time, non-cash charge of $11.4 million, or $0.11 per diluted share, related to the elimination of the tax deduction for the Medicare Part D subsidy (as previously reported in the Company's Form 10-Q for the quarter ended March 31, 2011). The increase in net income attributable to OGE Energy of $47.6 million, or 16.1 percent, or $0.46 per diluted share, in 2011 as compared to 2010 was primarily due to: • an increase in net income at OG&E of $47.6 million or 22.1 percent, or $0.47 per diluted share of the Company's common stock, 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 Medicare Part D subsidy discussed above; • a decrease in net income at Enogex of $8.9 million or 9.8 percent, or $0.09 per diluted share of the Company's common stock, primarily due to higher other operation and maintenance expense and OGE Energy's lower membership interest in Enogex Holdings partially offset by a higher gross margin primarily from higher NGLs 44-------------------------------------------------------------------------------- prices and increased gathered volumes associated with ongoing expansion projects, the recognition of a gain related to the sale of the Harrah processing plant and the associated Wellston and Davenport gathering assets, lower interest expense and lower income tax expense related to the Medicare Part D subsidy discussed above; and • an increase in the net income at OGE Energy of $8.9 million or 77.4 percent or $0.08 per diluted share of the Company's common stock, primarily due to lower other operation and maintenance expense, a decrease in charitable contributions in 2011 and a higher income tax benefit related to the Medicare Part D subsidy discussed above.

Non-Recurring Item. During 2011, Enogex had an increase in net income of $2.3 million relating to the sale of the Harrah processing plant and the associated Wellston and Davenport gathering assets in April 2011, which Enogex does not consider to be reflective of its ongoing performance.

Timing Item. Enogex's net income in 2011 was $82.2 million, which included a loss of $2.6 million resulting from recording Enogex's natural gas storage inventory at the lower of cost or market value. The offsetting gains from the sale of withdrawals from inventory were realized during the first quarter of 2012.

Recent Developments and Regulatory Matters OG&E 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.

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 17 of Notes to Consolidated 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.

OG&E 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) 45 -------------------------------------------------------------------------------- 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.

OG&E 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.

Texas Panhandle Gathering Divestiture On January 2, 2013, Enogex and one of its five largest customers entered into new agreements, effective January 1, 2013, relating to the customer's gathering and processing volumes on the Texas portion of Enogex's system. The effects of this new arrangement are (i) a fixed fee processing agreement replaces the previous keep-whole agreement, (ii) the acreage dedicated by the customer to Enogex for gathering and processing in Texas has been increased for an extended term and (iii) the sale by Enogex of certain gas gathering assets in the Texas Panhandle portion of Enogex's system to this customer for cash proceeds of approximately $35 million. The sale of these assets was approved by the Company's and Enogex's Board of Directors in November 2012, therefore these assets were classified as held for sale on the Company's Consolidated Balance Sheet at December 31, 2012. Enogex expects to recognize a pre-tax gain of approximately $10 million in the first quarter of 2013 in its natural gas gathering and processing segment from the sale of these assets.

Enogex Western Oklahoma / Texas Panhandle Natural Gas Gathering and Processing System Expansions In August 2012, Enogex completed construction of its cryogenic processing plant in Wheeler County, Texas, which added 200 MMcf/d of rich gas processing capacity to Enogex's system, and is supported by the installation of 9,400 horsepower of field compression, as well as 6,000 horsepower of inlet compression to facilitate additional flexibility in the operation of Enogex's "super-header" gathering system. The remainder of the inlet compression facilities is expected to be in service during the second quarter of 2013.

In support of significant long-term acreage dedications from its customers in the area, Enogex has expanded its gathering infrastructure in western Oklahoma and the Texas Panhandle. These expansions included the installation of 39,700 horsepower of low pressure compression and 235 miles of gathering pipe across the area, which was completed during the third quarter of 2012.

In support of significant long-term acreage dedications from its customers in the area, Enogex is expanding its gathering infrastructure in southern Oklahoma.

The initial phase of these expansions include the installation of approximately 20,000 horsepower of compression and approximately 100 miles of gathering pipeline, which are expected to be in service by the end of the first quarter of 2013. The remainder of the expansion includes the installation of approximately 50,000 horsepower of compression and approximately 300 miles of gathering pipeline, which are expected to be in service by the end of 2013.

Enogex is constructing a cryogenic processing plant in Custer County, Oklahoma, which is expected add 200 MMcf/d of natural gas processing capacity to Enogex's system, and is expected to be supported by the installation of 6,000 horsepower of inlet compression and four miles of transmission pipeline. This plant will be connected to the Enogex "super-header" gathering system and is expected to be in service by the end of 2013.

The capital expenditures related to the above projects are presented in the summary of capital expenditures for known and committed projects in "Item 7.

Management's Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources - Future Capital Requirements and Financing Activities." 46 --------------------------------------------------------------------------------Gas Gathering Acquisitions On August 1, 2012, Enogex entered into agreements with Chesapeake Midstream Gas Services, L.L.C. and Mid-America Midstream Gas Services, L.L.C., wholly-owned subsidiaries of Access Midstream Partners, L.P. and Chesapeake Midstream Development, L.P., respectively, pursuant to which Enogex agreed to acquire approximately 235 miles of natural gas gathering pipelines, right-of-ways and certain other midstream assets that provide natural gas gathering services in the greater Granite Wash area. The transactions closed on August 31, 2012. The aggregate purchase price for these transactions was approximately $78.6 million including reimbursement for certain permitted capital expenditures incurred during the period beginning June 1, 2012 and ending August 31, 2012. Enogex utilized cash generated from operations and bank borrowings to fund the purchase. In addition, Enogex also incurred acquisition-related costs of $3.5 million for sales taxes on acquired assets, which are included in taxes other than income. Enogex expects the purchase price allocations to be completed by the end of the first quarter of 2013. The Company believes that the acquisition transactions will provide Enogex with key new opportunities in the greater Granite Wash area.

In connection with these agreements, Enogex entered into a gas gathering and processing agreement with Chesapeake effective September 1, 2012 pursuant to which Enogex began providing fee-based natural gas gathering, compression, processing and transportation services to Chesapeake with respect to certain acreage dedicated by Chesapeake.

The capital expenditures related to the above agreements are presented in the summary of capital expenditures for known and committed projects in "Item 7.

Management's Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources - Future Capital Requirements and Financing Activities." 2013 Outlook The Company's 2013 earnings guidance is between approximately $335 million and $360 million of net income, or $3.35 to $3.60 per average diluted share.

Key assumptions for 2013 include: Consolidated OGE • Approximately 100 million average diluted shares outstanding; • An effective tax rate of approximately 30 percent; and • A projected loss at the holding company between approximately $2 million and $4 million, or $0.02 to $0.04 per diluted share, primarily due to interest expense relating to long andshort-term debt borrowings partially offset by tax deductions.

OG&E The Company projects OG&E to earn approximately $280 million to $290 million or $2.80 to $2.90 per average diluted share 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; • 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 $135million 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 ofapproximately $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.

47 --------------------------------------------------------------------------------Enogex The Company projects Enogex to earn approximately $55 million to $75 million, or $0.55 to $0.75 per average diluted share and EBITDA between $213 million and $241 million, in 2013 net of noncontrolling interest, and is based on the following assumptions: • Total Enogex anticipated gross margin of between approximately $470 million and $500 million. The gross margin assumption includes: • Natural gas transportation and storage gross margincontribution of between approximately $130 million and $140 million, of which 83 percent is attributable to the transportation business; • Natural gas gathering and processing gross margincontribution of between approximately $340 million and $360 million, of which 51 percent is attributable to the processing business; • Key factors affecting the natural gas gathering andprocessing gross margin forecast are: • Assumed increase of approximately 10 to 15 percent in gathered volumes over 2012; • Assumed increase of approximately 10 to 15 percent in processable* volumes over 2012; • At the midpoint of Enogex's natural gas gathering and processing assumption Enogex has assumed: • An average processing contract mix of 48 percent fixed-fee, 23 percent percent-of-liquids, 19 percentpercent-of-proceeds and 10 percent keep-whole; • Average natural gas price of $3.38 per MMBtu in 2013; • Average NGLs price of $0.82 per gallon in 2013; • Average price per gallon of condensate of $2.13 in 2013; • Ethane is projected to be in rejection for 2013; • Approximately 50 percent of NGLs volumes are expected to flow to Mt. Belvieu; and • A 10 percent change in the average NGLs price for the entire year impacts net income approximately $5 million; • Enogex has assumed operating expenses of approximately $325 million to $335 million, with operation and maintenance expenses comprising 54 percent of the total; • A pre-tax gain of approximately $10 million associated with asset sales in the first quarter of 2013; • Interest expense of approximately $30 million to $35 million; • An effective tax rate of approximately 38 percent; and • ArcLight group will own approximately 22 percent of Enogex Holdings by the end of 2013.

2014 Volume projections for Enogex: • Assumed increase of approximately five to 10 percent in gathered volumes over 2013; and • Assumed increase of approximately 10 to 20 percent in processable* volumes over 2013.

* Processable volumes are the natural gas production that are on Enogex's gathering systems that are available to be processed, some of which is moved off of the system and is not processed under one of Enogex's processing agreements.

Processable volumes include condensate volumes which are captured in the gathering pipeline and therefore not included in plant inlet volumes.

EBITDA is a supplemental non-GAAP financial measure used by external users of the Company's financial statements such as investors, commercial banks and others; therefore, the Company has included the table below which provides a reconciliation of projected EBITDA to projected net income attributable to Enogex Holdings at the midpoint of Enogex Holdings' earnings assumptions for 2013, which does not include the effect of income taxes whereas OGE Energy's portion of Enogex Holdings' net income included in OGE Energy's earnings guidance does reflect the effect of income taxes. Enogex Holding's net income shown in the EBITDA table does not include the effect of income taxes because Enogex Holdings is a partnership and is not subject to income taxes. Each partner is responsible for paying their own income taxes. For a discussion of the reasons for the use of EBITDA, as well as its limitations as an analytical tool, see "Non-GAAP Financial Measure" below.

48 -------------------------------------------------------------------------------- Reconciliation of projected EBITDA to projected net income attributable to Enogex Holdings Twelve Months Ended December 31, 2013 (In millions) (A)(B) Net income attributable to Enogex Holdings $ 132 Add: Interest expense, net 33 Depreciation and amortization expense (C) 123 EBITDA $ 288 OGE Energy's portion $ 228 (A) Based on the midpoint of Enogex Holdings' earnings guidance for 2013.

(B) As of November 1, 2010, Enogex Holdings' earnings are no longer subject to tax (other than Texas state margin taxes) and are taxable at the individual partner level.

(C) Includes amortization of certain customer-based intangible assets associated with the acquisition from Cordillera in November 2011, which is included in gross margin for financial reporting purposes.

Results of Operations The following discussion and analysis presents factors that affected the Company's consolidated results of operations for the years ended December 31, 2012, 2011 and 2010 and the Company's consolidated financial position at December 31, 2012 and 2011. The following information should be read in conjunction with the Consolidated 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 except per share 2012 2011 2010 data) Operating income $ 676.9 $ 646.7 $ 593.9 Net income attributable to OGE Energy $ 355.0 $ 342.9 $ 295.3 Basic average common shares outstanding 98.6 97.9 97.3 Diluted average common shares outstanding 99.1 99.2 98.9 Basic earnings per average common share attributable to OGE Energy common shareholders $ 3.60 $ 3.50 $ 3.03 Diluted earnings per average common share attributable to OGE Energy common shareholders $ 3.58 $ 3.45 $ 2.99 Dividends declared per common share $ 1.5950 $ 1.5175 $ 1.4625 In reviewing its consolidated operating results, the Company believes that it is appropriate to focus on operating income as reported in its Consolidated Statements of Income as operating income indicates the ongoing profitability of the Company excluding the cost of capital and income taxes.

Operating Income (Loss) by Business Segment Year ended December 31 (In millions) 2012 2011 2010 OG&E (Electric Utility) $ 489.4 $ 472.3 $ 413.7 Enogex (Natural Gas Midstream Operations) Natural gas transportation and storage (A) 45.1 56.4 60.4 Natural gas gathering and processing 140.5 118.7 123.9 Other Operations (B) 1.9 (0.7 ) (4.1 ) Consolidated operating income $ 676.9 $ 646.7 $ 593.9 (A) During the third quarter of 2012, the operations and activities of EER were fully integrated with those of Enogex through the creation of a new commodity management organization. The operations of EER, including asset management activities, have been included in the natural gas transportation and storage segment and have been restated for all prior periods presented.

(B) Other Operations primarily includes the operations of the holding company and consolidating eliminations.

The following operating income analysis by business segment includes intercompany transactions that are eliminated in the Consolidated Financial Statements.

49 -------------------------------------------------------------------------------- OG&E (Electric Utility) 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.

50-------------------------------------------------------------------------------- 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.

51 --------------------------------------------------------------------------------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) $ 6.4Contract 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 renewable energy tax credits recognized associated with the Crossroads wind farm and lower pre-tax income in 2012 as compared to 2011.

52 --------------------------------------------------------------------------------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.

53 --------------------------------------------------------------------------------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 the Company's retiree medical plan adopted in January 2011 (see Note 14 of Notes to Consolidated Financial Statements) partially offset by a modification to OG&E's pension tracker and a decrease in worker's compensation accruals in 2011.

Additional Information 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 constructionprimarily 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: 54 -------------------------------------------------------------------------------- • the one-time, non-cash charge in 2010 for the elimination of the tax deduction for the Medicare Part D subsidy; • the write-off of previously recognized Oklahoma investment tax credits in 2010 primarily due to expenditures no longereligible 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.

Enogex (Natural Gas Midstream Operations) Natural Gas Transportation and Natural Gas Gathering 2012 Storage and Processing Eliminations Total (In millions) Operating revenues $ 639.5 $ 1,222.6 $ (253.5 ) $ 1,608.6 Cost of goods sold 504.9 868.7 (253.5 ) 1,120.1 Gross margin on revenues 134.6 353.9 - 488.5 Other operation and maintenance 49.8 123.1 - 172.9 Depreciation and amortization 24.0 84.8 - 108.8 Impairment of assets - 0.4 - 0.4 Gain on insurance proceeds - (7.5 ) - (7.5 ) Taxes other than income 15.7 12.6 - 28.3 Operating income $ 45.1 $ 140.5 $ - $ 185.6 Natural Gas Transportation and Natural Gas Gathering 2011 Storage and Processing Eliminations Total (In millions) Operating revenues $ 880.1 $ 1,167.1 $ (260.1 ) $ 1,787.1 Cost of goods sold 736.0 870.7 (260.1 ) 1,346.6 Gross margin on revenues 144.1 296.4 - 440.5 Other operation and maintenance 50.7 111.8 - 162.5 Depreciation and amortization 22.0 55.6 - 77.6 Impairment of assets - 6.3 - 6.3 Gain on insurance proceeds - (3.0 ) - (3.0 ) Taxes other than income 15.0 7.0 0.1 22.1 Operating income $ 56.4 $ 118.7 $ (0.1 ) $ 175.0 Natural Gas Natural Gas Transportation and Gathering and 2010 Storage Processing Eliminations Total (In millions) Operating revenues $ 984.8 $ 1,005.6 $ (282.7 ) $ 1,707.7 Cost of goods sold 834.5 733.3 (282.7 ) 1,285.1 Gross margin on revenues 150.3 272.3 - 422.6 Other operation and maintenance 53.8 91.5 - 145.3 Depreciation and amortization 21.2 50.1 - 71.3 Impairment of assets 0.7 0.4 - 1.1 Taxes other than income 14.2 6.4 - 20.6 Operating income $ 60.4 $ 123.9 $ - $ 184.3 55-------------------------------------------------------------------------------- Operating Data Year ended December 31 2012 2011 2010 Gathered volumes - TBtu/d 1.41 1.36 1.32 Incremental transportation volumes - TBtu/d (A) 0.67 0.58 0.40 Total throughput volumes - TBtu/d 2.08 1.94 1.72 Natural gas processed - TBtu/d 0.98 0.79 0.82 Condensate sold - million gallons 35 27 24 Average condensate sales price per gallon $ 1.95 $ 2.09 $ 1.81 NGLs sold (keep-whole) - million gallons 162 167 187 NGLs sold (purchased for resale) - million gallons 667 487 470 NGLs sold (percent-of-liquids) - million gallons 24 25 26 NGLs sold (percent-of-proceeds) - million gallons 14 6 5 Total NGLs sold - million gallons 867 685 688 Average NGLs sales price per gallon $ 0.89 $ 1.16 $ 0.96 Average natural gas sales price per MMBtu $ 2.79 $ 4.08 $ 4.24 (A) Incremental transportation volumes consist of natural gas moved only on the transportation pipeline.

2012 compared to 2011. Enogex's operating income increased $10.6 million, or 6.1 percent, in 2012 as compared to 2011. This increase was primarily due to a higher gross margin, a higher gain on insurance proceeds related to the reimbursement of costs incurred to replace the damaged train at the Cox City natural gas processing plant discussed below and lower impairment of assets partially offset by higher other operation and maintenance expense, higher depreciation and amortization expense and higher taxes other than income. The higher gross margin related to (i) increased gathering rates and volumes associated with ongoing expansion projects and increased volumes from gas gathering assets acquired in November 2011 and August 2012 and (ii) increased inlet volumes resulting from the return to full service of the Cox City natural gas processing plant in September 2011, the South Canadian natural gas processing plant, which was placed in service in December 2011, and the Wheeler natural gas processing plant, which was placed in service in August 2012. These increases in gross margin were partially offset by lower average natural gas and NGLs prices. In 2012, imbalance volume changes and realized margin on physical gas long/short positions decreased the gross margin by $7.5 million, net of corresponding imbalance and fuel tracker balances and the impact of the recovery of prior years' under-recovered fuel positions during 2012.

Other operation and maintenance expense increased $10.4 million, or 6.4 percent, primarily due to: • increased payroll and benefits costs due to increased headcount to support business growth; and • increased rental expense on compression due to leases acquired in the August 2012 gas gathering acquisition partially offset by the reduction of rental payments on the Atoka plant, which was taken out of service in August 2011.

These increases in other operation and maintenance expense were partially offset by: • decreased costs for soil remediation projects; and • lower contract technical and professional services expense and materials and supplies expense due to a decrease in non-capital projects during 2012.

Depreciation and amortization expense increased $31.2 million, or 40.2 percent, primarily due to additional assets placed in service throughout 2011 and 2012, including the gas gathering assets acquired in November 2011 and August 2012.

Impairment of assets decreased $5.9 million, or 93.7 percent, primarily due to an impairment of $5.0 million related to a management decision in August 2011 to use third-party processing exclusively for gathered volumes dedicated to the Atoka processing plant and, therefore, to take the processing plant out of service and return it to the lessor in accordance with the rental agreement. The noncontrolling interest portion of the impairment was $2.5 million which was included in Net Income Attributable to Noncontrolling Interests in the Company's Consolidated Statement of Income.

Gain on insurance proceeds increased $4.5 million related to the reimbursement of costs incurred to replace the damaged train at the Cox City natural gas processing plant.

56 -------------------------------------------------------------------------------- Taxes other than income increased $6.2 million, or 28.1 percent, primarily due to: • sales tax of $3.5 million related to the acquisition of certain gas gathering assets in September 2012 as discussed in Note 3 of Notes to Consolidated Financial Statements; and • increased ad valorem taxes resulting from additional assets placed in service throughout 2011 and 2012.

Natural Gas Transportation and Storage The natural gas transportation and storage business contributed $134.6 million of Enogex's consolidated gross margin during 2012 as compared to $144.1 million during 2011, a decrease of $9.5 million or 6.6 percent. The transportation operations contributed $110.1 million of Enogex's consolidated gross margin during 2012 as compared to $118.8 million during 2011. The storage operations contributed $24.5 million of Enogex's consolidated gross margin during 2012 as compared to $25.3 million during 2011. Gross margin decreased primarily due to: • lower volumes and realized margin on sales of physical natural gas long positions associated with transportation operations, which decreased the gross margin by $6.4 million, net of imbalances and fuel tracker balances; • lower storage fees due to terminated contracts andrenegotiated contracts with less favorable terms, which decreased the gross margin by $2.5 million; • lower gains on storage sales during 2012, which decreased the gross margin by $1.9 million; • lower crosshaul revenues in 2012 resulting from the reversal of a previously recognized reserve of $3.0 million associated with the settlement of Enogex's 2009 FERC Section 311 rate case during 2011 partially offset by increased utilization of $1.3 million during 2012, which decreased the gross margin by $1.7 million; and • lower transportation fees due to unbundling oftransportation and gathering fees as contracts are renegotiated, which decreased the gross margin by $1.4 million.

These decreases in the natural gas transportation and storage gross margin were partially offset by: • higher realized margin on hedging activity associated with natural gas storage inventory from storage, which increased the gross margin by $4.4 million; and • higher transportation demand fees as a result of new contracts, which increased the gross margin by $2.3 million.

Other operation and maintenance expense for the natural gas transportation and storage business was $0.9 million, or 1.8 percent, lower during 2012 as compared to 2011 primarily due to lower contract technical and professional services expense and materials and supplies expense due to a decrease in non-capital projects during 2012 partially offset by increased payroll and benefits costs due to increased headcount to support business growth.

Natural Gas Gathering and Processing The natural gas gathering and processing business contributed $353.9 million of Enogex's consolidated gross margin during 2012 as compared to $296.4 million during 2011, an increase of $57.5 million, or 19.4 percent. The gathering operations contributed $145.9 million of Enogex's consolidated gross margin during 2012 as compared to $125.2 million during 2011. The processing operations contributed $208.0 million of Enogex's consolidated gross margin during 2012 as compared to $171.2 million during 2011.

During 2012, Enogex realized a higher gross margin in its natural gas gathering and processing operations related to (i) increased gathering rates and volumes associated with ongoing expansion projects, primarily in the Granite Wash play, which has added richer natural gas to Enogex's system, and increased volumes from gas gathering assets acquired in November 2011 and August 2012, (ii) increased inlet volumes resulting from the return to full service of the Cox City natural gas processing plant in September 2011, the South Canadian natural gas processing plant, which was placed in service in December 2011, and the Wheeler natural gas processing plant, which was placed in service in August 2012, and (iii) contract conversion of one of Enogex's five largest customer's Oklahoma production volumes to fixed fee effective July 1, 2011. These increases in the gathering and processing gross margin were partially offset by lower average natural gas and NGLs prices.

The above factors contributed to the increase in the natural gas gathering and processing gross margin as follows: • an increased gross margin on keep-whole processing of $28.4 million; • an increase in gathering fees associated with ongoing expansion projects and increased volumes from gas gathering assets, which increased the gross margin by $16.8 million; 57-------------------------------------------------------------------------------- • an increase in condensate revenues associated with higher condensate margins and volumes, which increased the gross margin by $14.2 million; and • an increased gross margin on fixed-fee contracts of $8.4 million.

These increases in the natural gas gathering and processing gross margin were partially offset by: • an increase in the utilization of third-party processing as a result of (i) the Atoka processing plant being taken out of service in August 2011 and (ii) increased activity from western Oklahoma and Texas Panhandle expansion projects currently processed by third parties, which together decreased the gross margin by $6.2 million; • a decrease in percent-of-liquids and percent-of-proceeds margins of $4.4 million; and • lower volumes and realized margin on sales of physical natural gas long positions associated with gathering operations, which decreased the gross margin by $1.1 million, net of imbalances and fuel tracker obligations.

Other operation and maintenance expense for the natural gas gathering and processing business was $11.3 million, or 10.1 percent, higher during 2012 as compared to 2011 primarily due to: • increased payroll and benefits costs due to increased headcount to support business growth; and • increased rental expense on compression due to leases acquired in the August 2012 gas gathering acquisition partially offset by the reduction of rental payments on the Atoka plant, which was taken out of service in August 2011.

These increases in other operation and maintenance expense were partially offset by decreased costs for soil remediation projects.

Enogex Consolidated Information Other Income. Enogex's consolidated other income was $1.0 million during 2012 as compared to $3.9 million during 2011, a decrease of $2.9 million, or 74.4 percent, due to the recognition in April 2011 of a gain related to the sale of the Harrah processing plant and the associated Wellston and Davenport gathering assets.

Other Expense. Enogex's consolidated other expense was $4.5 million during 2012 as compared to $1.3 million during 2011, an increase of $3.2 million due to higher non-cash losses on retirements of equipment during 2012.

Interest Expense. Enogex's consolidated interest expense was $32.6 million during 2012 as compared to $22.9 million during 2011, an increase of $9.7 million, or 42.4 percent, primarily due to: • a decrease in capitalized interest during 2012 due to the completion of several large capital projects as compared to 2011; • higher borrowings partially offset by repayments under Enogex's revolving credit agreement during 2012 as compared to 2011; and • borrowings under Enogex's term loan during 2012 with nocomparable item during 2011.

Income Tax Expense. Enogex's consolidated income tax expense was $45.7 million during 2012 as compared to $51.7 million during 2011, a decrease of $6.0 million, or 11.6 percent, primarily due to lower pre-tax income (net of noncontrolling interest) during 2012 as compared to 2011.

Noncontrolling Interest. Enogex's net income attributable to noncontrolling interest was $29.7 million during 2012 as compared to $20.8 million during 2011, an increase of $8.9 million or 42.8 percent, due to higher net income, the ArcLight group's increased ownership in Enogex Holdings as a result of the ArcLight group funding capital contributions at a disproportionate percentage to OGE Holdings throughout 2011 and an impairment recorded in August 2011 related to the Atoka processing plant.

Non-Recurring Items. During 2012, Enogex had an increase in net income of $4.6 million due to a gain on insurance proceeds related to the reimbursement of costs incurred to replace the damaged train at the Cox City natural gas processing plant partially offset by a decrease in net income of $2.1 million related to sales taxes on the assets acquired in the gas gathering acquisitions in August 2012, as discussed in Note 3 of Notes to Consolidated Financial Statements, which Enogex does not consider to be reflective of its ongoing performance. During 2011, Enogex had an increase in net income of $2.3 million relating to the sale of the Harrah processing plant and the associated Wellston and Davenport gathering assets in April 2011, which Enogex does not consider to be reflective of its ongoing performance.

58 -------------------------------------------------------------------------------- 2011 compared to 2010. Enogex's operating income decreased $9.3 million, or 5.0 percent, in 2011 as compared to 2010. This decrease was primarily due to higher other operation and maintenance expense, higher depreciation and amortization expense, lower average natural gas prices and a slight decrease in inlet processing volumes related to the 120 MMcf/d Cox City natural gas processing plant being out of service due to the fire from December 2010 until September 2011 and the sale of the Harrah processing plant and the associated Wellston and Davenport gathering assets in April 2011. These decreases were partially offset by higher NGLs prices and increased gathered volumes associated with ongoing expansion projects. In 2011, imbalance volume changes and realized margin on physical gas long/short positions decreased the gross margin by $14.8 million, net of corresponding imbalance and fuel tracker balances and the impact of the recovery of prior years' under-recovered fuel positions during 2010.

Other operation and maintenance expense increased $17.2 million, or 11.8 percent, primarily due to: • increased payroll and benefits costs due to increased headcount to support business growth; • increased contract technical and professional services expense and materials and supplies expense due to an increase in non-capital projects in 2011; • increased property insurance costs; • increased rental expense due to growing demand for compression as Enogex's business expands; and • increased costs due to soil remediation projects.

Depreciation and amortization expense increased $6.3 million, or 8.8 percent, primarily due to additional assets placed in service throughout 2010 and 2011.

Impairment of assets increased $5.2 million in 2011 primarily due to an impairment of $5.0 million related to a management decision in August 2011 to use third-party processing exclusively for gathered volumes dedicated to the Atoka processing plant and, therefore, to take the processing plant out of service and return it to the lessor in accordance with the rental agreement. The noncontrolling interest portion of the impairment was $2.5 million which was included in Net Income Attributable to Noncontrolling Interests in the Company's Consolidated Statement of Income.

Gain on insurance proceeds was $3.0 million in 2011 with no comparable item in 2010. The gain on insurance proceeds was for reimbursement related to the damaged train at the Cox City natural gas processing plant being replaced and the facility being returned to full service in September 2011.

Natural Gas Transportation and Storage The natural gas transportation and storage business contributed $144.1 million of Enogex's gross margin in 2011 as compared to $150.3 million in 2010, a decrease of $6.2 million, or 4.1 percent. The transportation operations contributed $118.8 million of Enogex's consolidated gross margin in 2011 as compared to $116.9 million in 2010. The storage operations contributed $25.3 million of Enogex's consolidated gross margin in 2011 as compared to $33.4 million in 2010. Gross margin decreased primarily due to: • lower volumes and realized margin on sales of physical natural gas long positions associated with transportation operations in 2011.

Gross margin in 2011 included the under recovery of fuel positions as compared to 2010 that included the recovery of prior year's under-recovered fuel positions, which reduced the gross margin in 2011 by $12.1 million, net of imbalance and fuel tracker obligations; • lower of cost or market adjustments on the natural gas storage inventory reflective of higher inventory volumes in 2011, which decreased the gross margin by $4.4 million; and • lower realized margin on sale of natural gas inventory from storage due to a reduction in the realized natural gas market spreads, which decreased the gross margin by $2.8 million.

These decreases in the natural gas transportation and storage gross margin were partially offset by: • higher capacity lease services under the MEP and Gulf Crossing capacity leases in 2011 as a result of pipeline integrity work on an Enogex pipeline in 2010, which increased the gross margin by $7.1 million; • higher firm 311 services due to new contracts with more favorable rates in 2011, which increased the gross margin by $5.4 million; • more favorable results from Enogex's customer-focused risk management services, natural gas marketing activities and trading activities and the expiration of an unfavorable transportation contract, which increased the gross margin by $2.2 million; 59-------------------------------------------------------------------------------- • higher interruptible transportation fees due to new contracts with more favorable rates in 2011, which increased the gross margin by $1.6 million; and • higher crosshaul revenues in 2011 resulting from thereversal of a previously recognized reserve of $3.0 million associated with the settlement of Enogex's 2009 FERC Section 311 rate case partially offset by decreased utilization of $2.5 million in 2011 due to shippers utilizing crosshaul service in 2010 as a result of pipeline integrity work, which increased the 2011 gross margin by $0.5 million.

Other operation and maintenance expense for the natural gas transportation and storage business was $3.1 million, or 5.8 percent, lower in 2011 as compared to 2010 primarily due to decreased contract technical and professional services expense and materials and supplies expense due to a decrease in non-capital projects in 2011 partially offset by an increase in payroll and benefits costs due to increased headcount to support business growth.

Natural Gas Gathering and Processing The natural gas gathering and processing business contributed $296.4 million of Enogex's consolidated gross margin in 2011 as compared to $272.3 million in 2010, an increase of $24.1 million, or 8.9 percent. The gathering operations contributed $125.2 million of Enogex's consolidated gross margin in 2011 as compared to $117.6 million in 2010. The processing operations contributed $171.2 million of Enogex's consolidated gross margin in 2011 as compared to $154.7 million in 2010.

In 2011, Enogex realized a higher gross margin in its natural gas gathering and processing operations primarily as the result of continued growth in gathered volumes from ongoing expansion projects, primarily in the Granite Wash play and Cana/Woodford Shale play, which has added richer natural gas to Enogex's system and higher NGLs prices. Although gathered volumes increased over 2010, gathering and processing volumes grew at a slower pace during the fourth quarter of 2011 than Enogex had anticipated. The increased gathering volumes were partially offset by the contract conversion of one of Enogex's five largest customer's Oklahoma production volumes to fixed fee effective July 1, 2011, a slight decrease in inlet processing volumes related to the 120 MMcf/d Cox City natural gas processing plant being out of service due to the fire from December 2010 until September 2011, the sale of the Harrah processing plant and the associated Wellston and Davenport gathering assets in April 2011 and lower average natural gas prices.

The above factors contributed to the increase in the natural gas gathering and processing gross margin as follows: • an increase in condensate revenues associated with higher condensate prices and volumes, which increased the gross margin by $11.1 million; • an increase in gathering fees associated with ongoing expansion projects, which increased the gross margin by $10.7 million; • an increased gross margin on keep-whole processing of $4.8 million; • an increased gross margin on percent-of-liquids and percent-of-proceeds contracts of $2.6 million; and • an increased gross margin on fixed-fee contract of $1.3 million.

These increases in the natural gas gathering and processing gross margin were partially offset by: • an increase in the utilization of third-party processing as a result of the reduced capacity related to the Cox City processing plant being out of service until September 2011 and the Atoka processing plant being taken out of service in August 2011, whichdecreased the gross margin by $3.4 million; and • lower volumes and realized margin on sales of physical natural gas long positions associated with gathering operations, which decreased the gross margin in 2011 by $2.7 million, net of imbalance and fuel tracker obligations.

Other operation and maintenance expense for the natural gas gathering and processing business was $20.3 million, or 22.2 percent, higher in 2011 as compared to 2010 primarily due to: • increased payroll and benefits costs due to increased headcount to support business growth; • increased contract technical and professional services expense and materials and supplies expense due to an increase in non-capital projects in 2011; • increased rental expense due to growing demand for compression as Enogex's business expands; and • increased costs due to soil remediation projects.

60 -------------------------------------------------------------------------------- Enogex Consolidated Information Other Income. Enogex's consolidated other income was $3.9 million in 2011 as compared to $0.2 million in 2010, an increase of $3.7 million, primarily due to the recognition of a gain related to the sale of the Harrah processing plant and the associated Wellston and Davenport gathering assets in April 2011.

Interest Expense. Enogex's consolidated interest expense was $22.9 million in 2011 as compared to $30.4 million in 2010, a decrease of $7.5 million, or 24.7 percent, primarily due to: • an increase of $6.1 million in capitalized interest related to increased construction activity in 2011; and • a decrease of $1.0 million in interest expense in 2011 due to the retirement of long-term debt in January 2010.

Income Tax Expense. Enogex's consolidated income tax expense was $51.7 million in 2011 as compared to $57.7 million in 2010, a decrease of $6.0 million, or 10.4 percent, primarily due to: • lower pre-tax income in 2011 as compared to 2010; and • the one-time, non-cash charge in 2010 for the elimination of the tax deduction for the Medicare Part D subsidy.

Noncontrolling Interest. Enogex's net income attributable to noncontrolling interest was $20.8 million in 2011 as compared to $5.1 million in 2010, an increase of $15.7 million, due to the equity sale of a membership interest in Enogex Holdings to the ArcLight group partially offset by an impairment recorded in August 2011 related to the Atoka processing plant.

Non-Recurring Item. During 2011, Enogex had an increase in net income of $2.3 million relating to the sale of the Harrah processing plant and the associated Wellston and Davenport gathering assets in April 2011, which Enogex does not consider to be reflective of its ongoing performance.

Timing Item. Enogex's net income in 2011 was $82.2 million, which included a loss of $2.6 million resulting from recording Enogex's natural gas storage inventory at the lower of cost or market value. The offsetting gains from the sale of withdrawals from inventory were realized during the first quarter of 2012.

Non-GAAP Financial Measure Enogex has included in this Form 10-K the non-GAAP financial measure EBITDA.

EBITDA is a supplemental non-GAAP financial measure used by external users of the Company's financial statements such as investors, commercial banks and others, to assess: • the financial performance of Enogex's assets without regard to financing methods, capital structure or historical cost basis; • Enogex's operating performance and return on capital ascompared to other companies in the midstream energy sector, without regard to financing or capital structure; and • the viability of acquisitions and capital expenditureprojects and the overall rates of return on alternative investmentopportunities.

Enogex provides a reconciliation of EBITDA to net income attributable to Enogex Holdings, which Enogex considers to be its most directly comparable financial measure as calculated and presented in accordance with GAAP. The non-GAAP financial measure of EBITDA should not be considered as an alternative to GAAP net income attributable to Enogex Holdings. EBITDA is not a presentation made in accordance with GAAP and has important limitations as an analytical tool. EBITDA should not be considered in isolation or as a substitute for analysis of Enogex's results as reported under GAAP. Because EBITDA excludes some, but not all, items that affect net income and is defined differently by different companies in Enogex's industry, Enogex's definition of EBITDA may not be comparable to a similarly titled measure of other companies.

To compensate for the limitations of EBITDA as an analytical tool, Enogex believes it is important to review the comparable GAAP measure and understand the differences between the measures.

61 --------------------------------------------------------------------------------Reconciliation of EBITDA to net income attributable to Enogex Holdings (In millions) 2012 2011 2010 Net income attributable to Enogex Holdings $ 147.8 $ 155.9 $ 476.1 Add: Interest expense, net 32.6 22.9 30.3 Income tax expense (A) 0.2 0.2 (325.0 ) Depreciation and amortization expense (B) 111.6 77.2 70.2 EBITDA $ 292.2 $ 256.2 $ 251.6 OGE Energy's portion $ 236.6 $ 222.9 $ 248.8 (A) As of November 1, 2010, Enogex Holdings' earnings are no longer subject to tax (other than Texas state margin taxes) and are taxable at the individual partner level.

(B) Includes amortization of certain customer-based intangible assets associated with the acquisition from Cordillera in November 2011, which is included in gross margin for financial reporting purposes.

Off-Balance Sheet Arrangement OG&E 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. The Company'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 $352.7 million and $381.8 million at December 31, 2012 and 2011, respectively, a decrease of $29.1 million, or 7.6 percent, primarily due to a decrease in billings to OG&E's customers in 2012 due to milder weather in 2012, a decrease at Enogex due to lower natural gas sales volumes and prices and the timing of customer payments received partially offset by higher transmission revenue and increased rates at OG&E.

The balance of Accounts Payable was $396.7 million and $388.0 million at December 31, 2012 and 2011, respectively, an increase of $8.7 million, or 2.2 percent, primarily due to increased NGLs volumes at Enogex partially offset by lower NGLs prices at Enogex, a decrease in accruals and the timing of ad valorem payments.

62--------------------------------------------------------------------------------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 $ 1,046.1 $ 833.9 $ 782.5 $ 212.2 25.4 % $ 51.4 6.6 % activities Net cash used in investing (1,192.6 ) (1,395.8 ) (846.1 ) 203.2 (14.6 )% (549.7 ) 65.0 % activities Net cash provided from financing 143.7 564.2 7.8 (420.5 ) (74.5 )% 556.4 * activities * Percentage is greater than 100 percent.

Operating Activities The increase of $212.2 million, or 25.4 percent, in net cash provided from operating activities in 2012 as compared to 2011 was primarily due to: • higher fuel recoveries at OG&E in 2012 as compared to 2011; • 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; and • an increase in gathered volumes and NGLs volumes at Enogex during 2012 as compared to 2011 partially offset by lower natural gas and NGLs prices in 2012 as compared to 2011.

The increase of $51.4 million, or 6.6 percent, in net cash provided from operating activities in 2011 as compared to 2010 was primarily due to: • lower fuel refunds at OG&E 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 $203.2 million, or 14.6 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 at OG&E and lower levels of capital expenditures related to gathering and processing expansion projects at Enogex.

The increase of $549.7 million, or 65.0 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 at OG&E and gathering and processing expansion projects at Enogex.

Financing Activities The decrease of $420.5 million, or 74.5 percent, in net cash provided from financing activities in 2012 as compared to 2011 was primarily due to: • lower contributions from the ArcLight group during 2012 as compared to 2011; • higher borrowings under Enogex's revolving credit agreement during 2011; and • repayments of Enogex's line of credit during 2012.

These decreases in net cash provided from financing activities were partially offset by an increase in short-term debt borrowings during 2012 as compared to 2011.

The increase of $556.4 million in net cash provided from financing activities in 2011 as compared to 2010 was primarily due to: • repayment in 2010 of the remaining balance of Enogex LLC's $400 million 8.125% senior notes which matured on January 15, 2010; 63--------------------------------------------------------------------------------• an increase in short-term debt borrowings in 2011 as compared to 2010; • contributions from the noncontrolling interest partners in 2011; • higher borrowings under Enogex LLC's revolving credit agreement in 2011; and • a decrease in repayments of borrowings under Enogex LLC's revolving credit agreement in 2011 as compared to 2010.

Future Capital Requirements and Financing Activities The Company's primary needs for capital are related to acquiring or constructing new facilities and replacing or expanding existing facilities at OG&E and Enogex. 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. The Company generally meets its cash needs through a combination of cash generated from operations, short-term borrowings (through a combination of bank borrowings and commercial paper) and permanent financings.

Capital Expenditures The Company's consolidated 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 the Company's businesses) plus capital expenditures for known and committed projects.

(In millions) 2013 2014 2015 2016 2017 OG&E Base Transmission $ 65 $ 50 $ 50 $ 50 $ 50 OG&E Base Distribution 175 175 175 175 175 OG&E Base Generation 80 75 75 75 75 OG&E Other 15 15 15 15 15 Total OG&E Base Transmission, Distribution, Generation and Other 335 315 315 315 315 OG&E 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 OG&E Known and Committed Projects 445 185 35 70 40 Total OG&E (D) 780 500 350 385 355 Enogex LLC Base Maintenance 50 55 55 55 55 Enogex LLC Known and Committed Projects: Western Oklahoma / Texas Panhandle Gathering Expansion 380 180 140 80 65 Other Gathering Expansion 25 15 10 10 10 Total Enogex LLC Known and Committed Projects 405 195 150 90 75 Total Enogex LLC (E) 455 250 205 145 130 OGE Energy 10 10 10 10 10 Total capital expenditures $ 1,245 $ 760 $ 565 $ 540 $ 495 (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 64-------------------------------------------------------------------------------- $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 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.

(E) These capital expenditures represent 100 percent of Enogex LLC's capital expenditures, of which a portion may be funded by the ArcLight group. Until the ArcLight group owns 50 percent of the equity of Enogex Holdings, the ArcLight group will fund capital contributions in an amount higher than its proportionate interest. If necessary, the ArcLight group will fund between 50 percent and 90 percent of required capital contributions during that period. The remainder of the required capital contributions (i.e., between 10 percent and 50 percent) will be funded by OGE Holdings.

Additional capital expenditures beyond those identified in the table above, including additional incremental growth opportunities in electric transmission assets and at Enogex LLC, will be evaluated based upon their impact upon achieving the Company's financial objectives. The capital expenditure projections related to Enogex LLC in the table above reflect base market conditions at February 27, 2013 and do not reflect the potential opportunity for a set of growth projects that could materialize. Also, if drilling activity declines in the future, this could reduce Enogex's capital expenditures in the table above.

65 --------------------------------------------------------------------------------Contractual Obligations The following table summarizes the Company's contractual obligations at December 31, 2012. See the Company's Consolidated Statements of Capitalization and Note 16 of Notes to Consolidated Financial Statements for additional information.

(In millions) 2013 2014-2015 2016-2017 After 2017 Total Maturities of long-term debt (A) $ 0.2 $ 550.4 $ 235.4 $ 2,070.1 $ 2,856.1 Operating lease obligations OG&E railcars 3.2 5.5 27.3 - 36.0 OG&E wind farm land leases 2.0 4.2 4.5 51.2 61.9 OGE Energy noncancellable operating lease 0.3 1.6 1.6 0.7 4.2 Enogex noncancellable operating leases 5.2 7.2 4.1 - 16.5 Total operating lease obligations 10.7 18.5 37.5 51.9 118.6 Other purchase obligations and commitments OG&E cogeneration capacity and fixed operation and maintenance payments 87.9 170.3 162.5 315.3 736.0 OG&E expected cogeneration energy payments 58.6 134.3 168.3 468.7 829.9 OG&E minimum fuel purchase commitments 405.0 519.8 - - 924.8 OG&E expected wind purchase commitments 57.5 116.9 120.6 838.0 1,133.0 OG&E long-term service agreement 8.0 34.5 12.6 53.0 108.1 commitments EER commitments 11.9 15.5 0.8 - 28.2 Total other purchase obligations and 628.9 991.3 464.8 1,675.0 3,760.0 commitments Total contractual obligations 639.8 1,560.2 737.7 3,797.0 6,734.7 Amounts recoverable through fuel adjustment (524.3 ) (776.5 ) (316.2 ) (1,306.7 ) (2,923.7 ) clause (B) Total contractual obligations, net $ 115.5 $ 783.7 $ 421.5 $ 2,490.3 $ 3,811.0 (A) Maturities of the Company's long-term debt during the next five years consist of $0.2 million, $300.2 million, $250.2 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.

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 14 of Notes to Consolidated 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, 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. OGE Energy could be required to make additional contributions 66 --------------------------------------------------------------------------------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 the Company'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 in Accumulated Other Comprehensive Loss (except OG&E's portion which is recorded as a regulatory asset as discussed in Note 1 of Notes to Consolidated Financial Statements) in the Company's Consolidated Balance Sheet. The amounts in Accumulated Other Comprehensive Loss and those recorded as a regulatory asset represent a net periodic benefit cost to be recognized in the Consolidated Statements of Income in future periods.

Restoration of Retirement Postretirement Pension Plan Income Plan Benefit Plans December 31 (In millions) 2012 2011 2012 2011 2012 2011 Benefit obligations $ (747.1 ) $ (697.7 ) $ (14.5 ) $ (13.3 ) $ (301.0 ) $ (280.6 ) Fair value of plan assets 626.0 589.8 - - 59.6 61.0 Funded status at end of year $ (121.1 ) $ (107.9 ) $ (14.5 ) $ (13.3 ) $ (241.4 ) $ (219.6 ) Common Stock Dividends The Company's dividend policy is reviewed by the Board of Directors at least annually and is based on numerous factors, including management's estimation of the long-term earnings power of its businesses. The Company's financial objective includes increasing the dividend to meet the Company's dividend payout objectives. The Company's target payout ratio is to pay out dividends no more than 60 percent of its normalized earnings on an annual basis. The target payout ratio has been determined after consideration of numerous factors, including the largely retail composition of the Company's shareholder base, the Company's financial position, the Company's growth targets, the composition of the Company's assets and investment opportunities. At the Company's November 2012 Board meeting, management, after considering estimates of future earnings and numerous other factors, recommended to the Board of Directors an increase in the current quarterly dividend rate to $0.4175 per share from $0.3925 per share effective with the Company's first quarter 2013 dividend.

Security Ratings Moody's Standard & Investors Poor's Ratings Services Services Fitch Ratings OG&E Senior Notes A2 BBB+ A+ Enogex LLC Notes Baa3 BBB- BBB OGE Energy Senior Notes Baa1 BBB A- OGE Energy Commercial Paper P2 A2 F2 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 the Company'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 the Company's short-term borrowings, but a reduction in the Company's credit ratings would not result in any defaults or accelerations. Any future downgrade could also lead to higher long-term borrowing costs and, if below investment grade, would require the Company to post collateral or letters of credit. In the event Moody's Investors Services or Standard & Poor's Ratings Services were to lower the Company's senior unsecured debt rating to a below investment grade rating, at December 31, 2012, the Company would have been required to post $0.2 million of cash collateral to satisfy its obligation under its financial and physical contracts relating to derivative instruments that are in a net liability position at December 31, 2012. In addition, the Company could be required to provide additional credit assurances in future dealings with third parties, which could include letters of credit or cash collateral.

On June 20, 2012, Fitch Ratings downgraded OGE Energy Corp.'s short-term debt rating from F1 to F2 and OGE Energy Corp.'s long-term debt issuer default rating from A to A-. All other ratings (by Fitch Ratings) at OG&E and Enogex remained unchanged and with a stable outlook. Fitch Ratings indicated that the downgrade at OGE Energy Corp. was primarily due to concerns related to the uncertainties associated with the environmental mandates at OG&E as well as Enogex's sensitivity to commodity prices and growth strategy with the ArcLight group.

67 -------------------------------------------------------------------------------- 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, levels of drilling activity, acquisitions of other businesses and/or development of projects, actions by rating agencies, inflation, changes in environmental laws or regulations, rate increases or decreases allowed by regulatory agencies, new legislation and market entry of competing electric power generators.

2012 Capital Requirements, Sources of Financing, Purchase of Treasury Stock and Financing Activities Total capital requirements, consisting of capital expenditures and maturities of long-term debt, were $1,351.8 million and contractual obligations, net of recoveries through fuel adjustment clauses, were $112.8 million resulting in total net capital requirements and contractual obligations of $1,464.6 million in 2012, of which $12.9 million was to comply with environmental regulations. This compares to net capital requirements of $1,446.2 million and net contractual obligations of $111.1 million totaling $1,557.3 million in 2011, of which $6.9 million was to comply with environmental regulations.

In 2012, the Company's sources of capital were cash generated from operations, proceeds from the issuance of short-term debt, proceeds from Enogex's term loan agreement, proceeds from the sales of common stock to the public through the Company's Automatic Dividend Reinvestment and Stock Purchase Plan, funding for growth opportunities at Enogex through the ArcLight group and quarterly distributions from Enogex Holdings. Changes in working capital reflect the seasonal nature of the Company'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.

Purchase of Treasury Stock In November 2012, the Company purchased 60,000 shares of its common stock at an average cost of $55.41 per share on the open market. These shares will be used to satisfy Enogex's portion of the Company's obligation to deliver shares of common stock related to long-term incentive payouts of earned performance units in 2013. The Company expects to purchase shares in the future to satisfy a portion of its obligation under its incentive plan.

Enogex Term Loan Agreement On August 2, 2012, Enogex entered into a $250 million, three-year term loan agreement with a maturity date of August 2, 2015. The loan was used to fund capital expenditures and for working capital purposes.

Potential Collateral Requirements Derivative instruments are utilized in managing the Company's commodity price exposures and in Enogex's asset management and hedging activities executed on behalf of the Company. Agreements governing the derivative instruments may require the Company to provide collateral in the form of cash or a letter of credit in the event mark-to-market exposures exceed contractual thresholds or the Company's credit ratings are lowered. Future collateral requirements are uncertain, and are subject to terms of the specific agreements and to fluctuations in natural gas and NGLs market prices.

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 the Company 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 the Company remain unclear because final rules have not been issued. Further, even if the Company 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 the Company's transaction costs or make it more difficult to enter into derivative transactions on favorable terms. The Company's inability to enter into derivative transactions on favorable terms, or at all, could increase operating expenses and put the Company at increased exposure to risks of adverse changes in commodities prices. The impact of the provisions of the Dodd-Frank Act on the Company 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.

68 --------------------------------------------------------------------------------Future Sources of Financing Management expects that cash generated from operations, proceeds from the issuance of long and short-term debt and proceeds from the sales of common stock to the public through the Company'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. Additionally, the Company will have an additional source of funding for growth opportunities at Enogex through the ArcLight group and from quarterly distributions from Enogex Holdings. The Company utilizes short-term borrowings (through a combination of bank borrowings and commercial paper) 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 Facilities Short-term borrowings generally are used to meet working capital requirements. The Company borrows on a short-term basis, as necessary, by the issuance of commercial paper and by borrowings under its revolving credit agreements. The Company has revolving credit facilities totaling in the aggregate $1,550.0 million. These bank facilities can also be used as letter of credit facilities. The short-term debt balance was $430.9 million and $277.1 million at December 31, 2012 and 2011, respectively. The weighted-average interest rate on short-term debt at December 31, 2012 was 0.43 percent. The average balance of short-term debt in 2012 was $451.0 million at a weighted-average interest rate of 0.45 percent. The maximum month-end balance of short-term debt in 2012 was $608.2 million. At December 31, 2012, Enogex had no outstanding borrowings under its revolving credit agreement as compared to $150.0 million at December 31, 2011. As Enogex LLC's credit agreement matures on December 13, 2016, along with its intent in utilizing its credit agreement, borrowings thereunder are classified as long-term debt in the Company's Consolidated Balance Sheets. At December 31, 2012, the Company had $1,116.9 million of net available liquidity under its revolving credit agreements. 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, the Company had $1.8 million in cash and cash equivalents. See Note 13 of Notes to Consolidated Financial Statements for a discussion of the Company'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.

Common Stock The Company expects to issue between $12 million and $15 million of common stock in its Automatic Dividend Reinvestment and Stock Purchase Plan in 2013. See Note 11 of Notes to Consolidated Financial Statements for a discussion of the Company's common stock activity.

Minimum Quarterly Distributions by Enogex Holdings Pursuant to the Enogex Holdings LLC Agreement, Enogex Holdings will make minimum quarterly distributions equal to the amount of cash required to cover OGE Energy's anticipated tax liabilities plus $12.5 million, to be distributed in proportion to each member's percentage ownership interest.

Critical Accounting Policies and Estimates The Consolidated Financial Statements and Notes to Consolidated Financial Statements contain information that is pertinent to Management's Discussion and Analysis. In preparing the Consolidated 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 Consolidated 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 the Company's Consolidated Financial Statements. However, the Company believes it has taken reasonable, but conservative, positions where assumptions and estimates are used in order to minimize the negative financial impact to the Company that could result if actual results vary from the assumptions and estimates. In management's opinion, the areas of the Company where the most significant judgment is exercised for all Company segments 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 and the allowance for uncollectible accounts receivable. For the electric utility segment, the most significant judgment is also exercised in the valuation of regulatory assets and liabilities and unbilled revenues. For the natural gas transportation and storage segment and the natural gas gathering and processing segment, the most significant judgment is also exercised in the 69 -------------------------------------------------------------------------------- valuation of operating revenues, natural gas purchases, purchase and sale contracts, assets and depreciable lives of property, plant and equipment, amortization methodologies related to intangible assets and impairment assessments of goodwill. The selection, application and disclosure of the following critical accounting estimates have been discussed with the Company's Audit Committee. The Company 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 Consolidated Financial Statements.

Consolidated (including all Company segments) Pension and Postretirement Benefit Plans The Company has a Pension Plan that covers a significant amount of the Company's employees hired before December 1, 2009. Also, effective December 1, 2009, the Company's Pension Plan is no longer being offered to employees hired on or after December 1, 2009. The Company 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 14 of Notes to Consolidated 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 Assessing Impairment of Long-Lived Assets (Including Intangible Assets) and Goodwill The Company assesses its long-lived assets, including intangible assets with finite useful lives, for impairment when there is evidence that events or changes in circumstances require an analysis of the recoverability of an asset's carrying amount. Estimates of future cash flows used to test the recoverability of long-lived assets and intangible assets shall include only the future cash flows (cash inflows less associated cash outflows) that are directly associated with and that are expected to arise as a direct result of the use and eventual disposition of the asset. The fair value of these assets is based on third-party evaluations, prices for similar assets, historical data and projected cash flows. An impairment loss is recognized when the sum of the expected future net cash flows is less than the carrying amount of the asset. The amount of any recognized impairment is based on the estimated fair value of the asset subject to impairment compared to the carrying amount of such asset. In 2011, the Company recorded a pre-tax impairment loss of $5.0 million, of which $2.5 million was the noncontrolling interest portion (see Note 5 of Notes to Consolidated Financial Statements), related to the Atoka processing plant. The Company recorded no other material impairments in 2012, 2011 or 2010.

As a result of the gas gathering acquisitions in November 2011, Enogex recorded goodwill of $39.4 million. Enogex assesses its goodwill for impairment at least annually as of October 1 by comparing the fair value of the reporting unit with its book value, including goodwill. Enogex utilizes the income approach (generally accepted valuation approach) to estimate the fair value of the reporting unit, also giving consideration to alternative methods such as the market and cost approaches. Under the income approach, anticipated cash flows over a period of years plus a terminal value are discounted to present value using appropriate discount rates. Enogex performs its goodwill impairment testing at the natural gas gathering and processing segment reporting unit level. Enogex recorded no impairments of goodwill in 2012.

Income Taxes The Company 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 70 -------------------------------------------------------------------------------- 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 the Company recognized in its consolidated financial statements. Tax positions taken by the Company 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.

Commitments and Contingencies In the normal course of business, the Company 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, the Company 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 the Company's Consolidated Financial Statements.

Except as disclosed otherwise in this Form 10-K, the Company 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 the Company's consolidated financial position, results of operations or cash flows.

See Notes 16 and 17 of Notes to Consolidated Financial Statements and Item 3 of Part I in this Form 10-K for a discussion of the Company's commitments and contingencies.

Asset Retirement Obligations The Company has previously recorded asset retirement obligations that are being amortized over their respective lives ranging from three months to 74 years. The Company also has certain asset retirement obligations primarily related to Enogex's processing plants and compression sites that have not been recorded because the Company cannot determine when these obligations will be incurred.

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 The Company designates as cash flow hedges derivatives used to manage commodity price risk exposure for Enogex's NGLs volumes and corresponding keep-whole natural gas resulting from its natural gas processing contracts (processing hedges) and natural gas positions resulting from its natural gas gathering and processing operations and natural gas transportation and storage operations (operational gas hedges). The Company also designates as cash flow hedges certain derivatives used to manage natural gas commodity exposure for certain natural gas storage inventory positions. 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.

Enogex's cash flow hedges at December 31, 2012 mature by the end of the first quarter of 2013.

From time to time, OG&E and Enogex 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.

Electric Utility Segment 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 71 -------------------------------------------------------------------------------- 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 Consolidated Balance Sheets and in Operating Revenues on the Consolidated 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.

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 Consolidated Balance Sheets and is included in Other Operation and Maintenance Expense on the Consolidated Statements of Income. The allowance for uncollectible accounts receivable was $2.6 million and $3.7 million at December 31, 2012 and 2011, respectively.

Natural Gas Transportation and Storage and Natural Gas Gathering and Processing Segments Operating Revenues Operating revenues for gathering, processing, transportation and storage services for Enogex are recorded each month based on the current month's estimated volumes, contracted prices (considering current commodity prices), historical seasonal fluctuations and any known adjustments. The estimates are reversed in the following month and customers are billed on actual volumes and contracted prices. Gas sales are calculated on current-month nominations and contracted prices. Operating revenues associated with the production of NGLs are estimated based on current-month estimated production and contracted prices. These amounts are reversed in the following month and the customers are billed on actual production and contracted prices. Estimated operating revenues are reflected in Accounts Receivable on the Consolidated Balance Sheets and in Operating Revenues on the Consolidated Statements of Income.

Enogex recognizes revenue from natural gas gathering, processing, transportation and storage services to third parties as services are provided. Revenue associated with NGLs is recognized when the production is sold.

Enogex records deferred revenue when it receives consideration from a third party before achieving certain criteria that must be met for revenue to be recognized in accordance with GAAP. In August 2010, Enogex completed construction of transportation and compression facilities necessary to provide gas delivery service to a new natural gas-fired electric generation facility near Pryor, Oklahoma. Aid in Construction payments of $36.4 million received in excess of construction costs were recognized as Deferred Revenues on the Company's Consolidated Balance Sheet and are being amortized on a straight-line basis of $1.2 million per year over the life of the related firm transportation service agreement under which service commenced in June 2011. Also, in August 2011, Enogex and one of its five largest customers entered into new agreements, effective July 1, 2011, relating to the customer's natural gas gathering and processing volumes on the Oklahoma portion of Enogex's system. As a result, Enogex has recorded $7.1 million in Deferred Revenues on the Company's Consolidated Balance Sheet at December 31, 2012, which are expected to be recognized based on the estimated average fee per MMBtu processed by the end of 2014. Enogex has also recorded $1.5 million in Deferred Revenues on the Company's Consolidated Balance Sheet at December 31, 2012 in connection with other gathering and processing agreements.

Enogex engages in asset management and hedging activities related to the purchase and sale of natural gas and NGLs. Contracts utilized in these activities generally include purchases and sales for physical delivery, over-the-counter forward swap and options contracts and exchange traded futures and options. Enogex's transactions that qualify as derivatives are reflected at 72 -------------------------------------------------------------------------------- fair value with the resulting unrealized gains and losses recorded as PRM Assets or Liabilities in the Consolidated Balance Sheets, classified as current or long-term based on their anticipated settlement, or against the brokerage deposits in Other Current Assets. The offsetting unrealized gains and losses from changes in the market value of open contracts are included in Operating Revenues in the Consolidated Statements of Income or in Other Comprehensive Income for derivatives designated and qualifying as cash flow hedges. Contracts resulting in delivery of a commodity are included as sales or purchases in the Consolidated Statements of Income as Operating Revenues or Cost of Goods Sold depending on whether the contract relates to the sale or purchase of the commodity.

Natural Gas Purchases Estimates for gas purchases are based on estimated volumes and contracted purchase prices. Estimated gas purchases are included in Accounts Payable on the Consolidated Balance Sheets and in Cost of Goods Sold on the Consolidated Statements of Income.

Purchase and Sale Contracts Enogex utilizes purchases and sales for physical delivery, over-the-counter forward swap and options contracts and exchange traded futures and options.

These activities either qualify as derivatives and are recorded at fair market value or qualify for normal purchase normal sale treatment. Enogex's portfolio is marked to estimated fair market value on a daily basis. When available, actual market prices are utilized in determining the value of natural gas and related derivative commodity instruments. For longer-term positions, which are limited to a maximum of 60 months and certain short-term positions for which market prices are not available, models based on forward price curves are utilized. These models incorporate estimates and assumptions as to a variety of factors such as pricing relationships between various energy commodities and geographic location. Actual experience can vary significantly from these estimates and assumptions.

In nearly all cases, independent market prices are obtained and compared to the values used in determining the fair value. The recorded value of the energy contracts may change significantly in the future as the market price for the commodity changes, but the value of transactions not designated as cash flow hedges is subject to mark-to-market risk loss limitations provided under the Company's risk policies. Management utilizes models to estimate the fair value of the Company's energy contracts including derivatives that do not have an independent market price. At December 31, 2012, unrealized mark-to-market losses were $0.2 million, none of which were calculated utilizing models. At December 31, 2012, a price movement of one percent for prices verified by independent parties would result in unrealized mark-to-market gains or losses of less than $0.1 million and a price movement of five percent on model-based prices would result in unrealized mark-to-market gains or losses of less than $0.1 million.

Valuation of Assets The application of business combination and impairment accounting requires Enogex to use significant estimates and assumptions in determining the fair value of assets and liabilities. The acquisition method of accounting for business combinations requires Enogex to estimate the fair value of assets acquired and liabilities assumed to allocate the proper amount of the purchase price consideration between goodwill and the assets that are depreciated and amortized. Enogex records intangible assets separately from goodwill and amortizes intangible assets with finite lives over their estimated useful life as determined by management. Enogex does not amortize goodwill but instead annually assesses goodwill for impairment.

In 2011 and 2012, Enogex completed gas gathering acquisitions accounted for as business combinations as discussed in Note 3 of Notes to Consolidated Financial Statements. As part of these acquisitions, Enogex has engaged the services of a third-party valuation expert to assist it in determining the fair value of the acquired assets and liabilities, including goodwill; however, the ultimate determination of those values is the responsibility of Enogex's management.

Enogex bases its estimates on assumptions believed to be reasonable, but which are inherently uncertain. These valuations require the use of management's assumptions, which would not reflect unanticipated events and circumstances that may occur.

Depreciable Lives of Property, Plant and Equipment and Amortization Methodologies Related to Intangible Assets The computation of depreciation expense requires judgment regarding the estimated useful lives and salvage value of assets at the time the assets are placed in service. As circumstances warrant, useful lives are adjusted when changes in planned use, changes in estimated production lives of affiliated natural gas basins or other factors indicate that a different life would be more appropriate. Such changes could materially impact future depreciation expense.

Changes in useful lives that do not result in the impairment of an asset are recognized prospectively. The computation of amortization expense on intangible assets requires 73 -------------------------------------------------------------------------------- judgment regarding the amortization method used. Intangible assets are amortized on a straight-line basis over their useful lives using a method of amortization that reflects the pattern in which the economic benefits of the intangible asset are consumed.

Natural Gas Inventory Natural gas inventory is held by Enogex, through its transportation and storage business, to provide operational support for its pipeline deliveries and to manage its leased storage capacity. In an effort to mitigate market price exposures, Enogex may enter into contracts or hedging instruments to protect the cash flows associated with its inventory. All natural gas inventory held by Enogex is valued using moving average cost and is recorded at the lower of cost or market. As part of its asset management activity, Enogex injects and withdraws natural gas into and out of inventory under the terms of its storage capacity contracts. During the years ended December 31, 2012, 2011 and 2010, Enogex recorded write-downs to market value related to natural gas storage inventory of $5.5 million, $4.8 million and $0.3 million, respectively. The amount of Enogex's natural gas inventory was $16.5 million and $23.7 million at December 31, 2012 and 2011, respectively. The cost of gas associated with sales of natural gas storage inventory is presented in Cost of Goods Sold on the Consolidated Statements of Income.

Allowance for Uncollectible Accounts Receivable The allowance for uncollectible accounts receivable for Enogex is calculated based on outstanding accounts receivable balances over 180 days old. In addition, other outstanding accounts receivable balances less than 180 days old are reserved on a case-by-case basis when Enogex believes the collection of specific amounts owed is unlikely to occur. The allowance for uncollectible accounts receivable is a reduction to Accounts Receivable on the Consolidated Balance Sheets and is included in Other Operation and Maintenance Expense on the Consolidated Statements of Income. The aggregate allowance for uncollectible accounts receivable for Enogex's natural gas transportation and storage and natural gas gathering and processing segments was less than $0.1 million at December 31, 2012 and 2011.

Accounting Pronouncements See Note 2 of Notes to Consolidated Financial Statements for discussion of current accounting pronouncements that are applicable to the Company.

Commitments and Contingencies In the normal course of business, the Company 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, the Company 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 the Company's Consolidated Financial Statements. At the present time, based on currently available information, except as disclosed otherwise in this Form 10-K, the Company 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 the Company's consolidated financial position, results of operations or cash flows. See Notes 16 and 17 of Notes to Consolidated Financial Statements and Item 3 of Part I in this Form 10-K for a discussion of the Company's commitments and contingencies.

Environmental Laws and Regulations The activities of OG&E and Enogex 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 and Enogex's business activities in many ways, such as restricting the way it can handle or dispose of their wastes, requiring remedial action to mitigate pollution conditions that may be caused by their 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 and Enogex believe that their 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 or Enogex's facilities. Historically, OG&E's and Enogex's total expenditures for environmental control facilities and for remediation have not been significant in relation to its consolidated financial position or results of operations. The Company believes, however, 74 -------------------------------------------------------------------------------- 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 and Enogex's total expenditures to comply with environmental laws, regulations and requirements for 2013 will be $63.0 million and $6.4 million, respectively, of which $45.3 million and $0.7 million, respectively, are for capital expenditures. It is estimated that OG&E's and Enogex's total expenditures to comply for environmental laws, regulations and requirements for 2014 will be $37.7 million and $6.3 million, respectively, of which $19.2 million and $0.5 million, respectively, are for capital expenditures. The amounts for OG&E 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. The Company'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.

Air Federal Clean Air Act Overview OG&E's and Enogex'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, natural gas processing plants and compressor stations, and also impose various monitoring and reporting requirements. Such laws and regulations may require that OG&E and Enogex 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 and Enogex 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.

75 -------------------------------------------------------------------------------- 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 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.

76--------------------------------------------------------------------------------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, the Company 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 the Company's operations. Several processes are under way to designate areas in Oklahoma as attaining or not attaining revised NAAQS. The Company 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 the Company'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.

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, Arkansas and Texas 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 the Company's facilities, this could result in significant additional compliance costs that would affect the Company'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 77 --------------------------------------------------------------------------------on the Company's existing facilities, they ultimately could result in significant changes to the Company's operations, significant capital expenditures by the Company and a significant increase in the Company'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 and Enogex facilities. OG&E also reports quarterly its carbon dioxide emissions from generating units subject to the Federal Acid Rain Program. OG&E and Enogex have submitted the reports required by the applicable reporting rules.

The Company 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. Enogex is a partner in the EPA Natural Gas STAR Program, a voluntary program to reduce methane emissions.

The Company 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. The Company 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 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 the Company conducts operations, or if additional species in those areas become subject to protection, the Company's operations and development projects, particularly transmission, wind or pipeline projects, could be restricted or delayed, or the Company 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 the Company, the impact of a final decision to list this species as threatened cannot be determined at this time.

Waste OG&E's and Enogex'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.

The Company 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, the Company obtained refunds of $6.4 million from the recycling of scrap metal, salvaged transformers and used transformer oil. This figure does not include the additional savings gained through the reduction and/or avoidance of disposal costs and the reduction in material purchases due to the reuse of existing materials. Similar savings are anticipated in future years.

78 -------------------------------------------------------------------------------- For Enogex, the Federal Resource Conservation and Recovery Act of 1976 currently exempts many natural gas gathering and field processing wastes from classification as hazardous waste. However, these oil and gas exploration and production wastes may still be regulated under state law or the less stringent solid waste requirements of the Federal Resource Conservation and Recovery Act of 1976. The transportation of natural gas in pipelines may also generate some hazardous wastes that are subject to the Federal Resource Conservation and Recovery Act of 1976 or comparable state law requirements.

Water OG&E's and Enogex'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 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 and Enogex utilize 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 and Enogex 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 or Enogex.

For a further discussion regarding contingencies relating to environmental laws and regulations, see Note 16 of Notes to Consolidated Financial Statements.

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