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•	general economic conditions, including the availability of credit, access to existing lines of credit, access to the commercial paper markets, actions of rating agencies and their impact on capital expenditures;

•	the ability of the Company and its subsidiaries to access the capital markets and obtain financing on favorable terms as well as inflation rates and monetary fluctuations;

•	prices and availability of electricity, coal, natural gas and NGLs, each on a stand-alone basis and in relation to each other as well as the processing contract mix between percent-of-liquids, percent-of-proceeds, keep-whole and fixed-fee;

•	business conditions in the energy and natural gas midstream industries;

•	competitive factors including the extent and timing of the entry of additional competition in the markets served by the Company;

•	unusual weather;

•	availability and prices of raw materials for current and future construction projects;

•	Federal or state legislation and regulatory decisions and initiatives that affect cost and investment recovery, have an impact on rate structures or affect the speed and degree to which competition enters the Company's markets;

•	environmental laws and regulations that may impact the Company's operations;

•	changes in accounting standards, rules or guidelines;

•	the discontinuance of accounting principles for certain types of rate-regulated activities;

•	the cost of protecting assets against, or damage due to, terrorism or cyber attacks and other catastrophic events;

•	advances in technology;

•	creditworthiness of suppliers, customers and other contractual parties;

•	the higher degree of risk associated with the Company's nonregulated business compared with the Company's regulated utility business; and

•	other risk factors listed in the reports filed by the Company with the Securities and Exchange Commission including those listed in "Item 1A. Risk Factors" and in Exhibit 99.01 to this Form 10-K.

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Fee-based arrangements.  Under these arrangements, Enogex generally is paid a fixed fee for performing the gathering and processing service. This fee is directly related to the volume of natural gas that flows through Enogex's system and is not directly dependent on commodity prices. However, a sustained decline in commodity prices could result in a decline in volumes and, thus, a decrease in Enogex's fee revenues. These arrangements provide stable cash flows, but minimal, if any, upside in higher commodity price environments. At December 31, 2012, these arrangements accounted for 35 percent of Enogex's natural gas processed volumes.

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Percent-of-proceeds and percent-of-liquids arrangements.  Under these arrangements, Enogex generally gathers raw natural gas from producers at the wellhead, transports the gas through its gathering system, processes the gas and sells the processed gas and/or NGLs at prices based on published index prices. These arrangements provide upside in high commodity price environments, but result in lower margins in low commodity price environments. The price paid to producers is based on an agreed percentage of the proceeds of the sale of processed natural gas, NGLs or both or the expected proceeds based on an index price. We refer to contracts in which Enogex shares in specified percentages of the proceeds from the sale of natural gas and NGLs as percent-of-proceeds arrangements and in which Enogex receives proceeds from the sale of NGLs or the NGLs themselves as compensation for its processing services as percent-of-liquids arrangements. Under percent-of-proceeds arrangements, Enogex's margin correlates directly with the prices of natural gas and NGLs. Under percent-of-liquids arrangements, Enogex's margin correlates directly with the prices of NGLs. At December 31, 2012, Enogex's percent-of-proceeds and percent-of-liquids processing arrangements accounted for 16 percent and 28 percent, respectively, of Enogex's natural gas processed volumes.

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Keep-whole arrangements.  Enogex processes raw natural gas to extract NGLs and returns to the producer the full gas equivalent British thermal unit value of raw natural gas received from the producer in the form of either processed gas or its cash equivalent. Enogex is entitled to retain the processed NGLs and to sell them for its own account. Accordingly, Enogex's margin is a function of the difference between the value of the NGLs produced and the cost of the processed gas used to replace the thermal equivalent of those NGLs. These arrangements can provide large profit margins in favorable commodity price environments, but also can be subject to losses if the cost of natural gas exceeds the value of its thermal equivalent of NGLs. Many of Enogex's keep-whole contracts include provisions that reduce its commodity price exposure, including conditioning floors (such as the default processing fee described below) that allow the keep-whole contract to be charged a fee if the NGLs have a lower value than their gas equivalent British thermal unit value in natural gas.  At December 31, 2012, these arrangements accounted for 21 percent of Enogex's natural gas processed volumes.

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(A)

Balanced Portfolio 3E includes three projects to be built by OG&E and includes: (i) construction of 135 miles of transmission line from OG&E's Seminole substation in a northeastern direction to OG&E's Muskogee substation at an estimated cost of $175 million for OG&E, which is expected to be in service by late 2013, (ii) construction of 96 miles of transmission line from OG&E's Woodward District Extra High Voltage substation in a southwestern direction to the Oklahoma/Texas Stateline to a companion transmission line to be built by Southwestern Public Service to its Tuco substation at an estimated cost of $115 million for OG&E, which is expected to be in service by mid-2014 and (iii) construction of 39 miles of transmission

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(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:

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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.

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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.

(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.

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•	identify potential threats to the public or environment, including "high consequence areas" on covered pipeline segments where a leak or rupture could do the most harm;

•	develop a baseline plan to prioritize the assessment of a covered pipeline segment;

•	gather data and identify and characterize applicable threats that could impact a covered pipeline segment;

•	discover, evaluate and remediate problems in accordance with the program requirements;

•	continuously improve all elements of the integrity program;

•	continuously perform preventative and mitigation actions;

•	maintain a quality assurance process and management-of-change process; and

•	establish a communication plan that addresses safety concerns raised by the U.S. Department of Transportation and state agencies, including the periodic submission of performance documents to the U.S. Department of Transportation.

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•	increased prices for fuel and fuel transportation as existing contracts expire;

•	facility shutdowns due to a breakdown or failure of equipment or processes or interruptions in fuel supply;

•	operator error or safety related stoppages;

•	disruptions in the delivery of electricity; and

•	catastrophic events such as fires, explosions, floods or other similar occurrences.

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•	damage to pipelines and plants, related equipment and surrounding properties caused by tornadoes, floods, earthquakes, fires and other natural disasters and acts of terrorism;

•	inadvertent damage from third parties, including construction, farm and utility equipment;

•	leaks of natural gas, NGLs and other hydrocarbons or losses of natural gas or NGLs as a result of the malfunction of equipment or facilities; and

•	fires and explosions.

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•	the ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or the financing may not be available on favorable terms;

•	a portion of cash flows will be required to make interest payments on the debt, reducing the funds that would otherwise be available for operations and future business opportunities; and

•	our debt levels may limit our flexibility in responding to changing business and economic conditions.

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(A)	2012 Capacity Factor = 2012 Net Actual Generation / (2012 Net Maximum Capacity (Nameplate Rating in MWs) x Period Hours (8,760 Hours)).

(B)	Peaking units are used when additional short-term capacity is required.

(C)	Represents OG&E's 51 percent ownership interest in the Redbud Plant.

(D)	Represents OG&E's 77 percent ownership interest in the McClain Plant.

(E)	In December 2012, the Enid and Woodward generating stations were retired.

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(A)	These processing plants are located on property that Enogex owns in fee.

(B)	This processing plant will be used when additional capacity is required.

(C)	This processing plant was placed into service in August 2012.

(D)	These processing plants are located on easements or leased property as described above.

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(A)	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.

(B)	These shares of restricted stock were returned to the Company to satisfy tax liabilities.

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(A)	Capitalization ratios = [Total stockholders' equity / (Total stockholders' equity + Long-term debt + Long-term debt due within one year)] and [(Long-term debt + Long-term debt due within one year) / (Total stockholders' equity + Long-term debt + Long-term debt due within one year)].

(B)	For purposes of computing the ratio of earnings to fixed charges, (i) earnings consist of pre-tax income plus fixed charges, less allowance for borrowed funds used during construction and other capitalized interest and (ii) fixed charges consist of interest on long-term debt, related amortization, interest on short-term borrowings and a calculated portion of rents considered to be interest.

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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;

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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 assets acquired 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.

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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

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•	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.

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•	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 and short-term debt borrowings partially offset by tax deductions.

•	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 $135 million which assumes a $3 million allowance for borrowed funds used during construction reduction to interest expense and $250 million of long-term debt issued in the first half of 2013;

•	Allowance for equity funds used during construction of approximately $10 million; and

•	An effective tax rate of approximately 28 percent.

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•	Total Enogex anticipated gross margin of between approximately $470 million and $500 million. The gross margin assumption includes:

•	Natural gas transportation and storage gross margin contribution of between approximately $130 million and $140 million, of which 83 percent is attributable to the transportation business;

•	Natural gas gathering and processing gross margin contribution 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 and processing 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 percent percent-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.

•	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.

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(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.

(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.

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(A)

Degree days are calculated as follows:  The high and low degrees of a particular day are added together and then averaged.  If the calculated average is above 65 degrees, then the difference between the calculated average and 65 is expressed as cooling degree days, with each degree of difference equaling one cooling degree day.  If the calculated average is below 65 degrees, then the difference between the calculated average and 65 is expressed as heating degree days, with each degree of difference equaling one heating degree day.  The daily calculations are then totaled for the particular reporting period.

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(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.

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(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.

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(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.

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(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.

•	a $4.9 million decrease in interest expense due to a higher allowance for borrowed funds used during construction primarily due to construction costs for the Crossroads wind farm; and

•	a $1.4 million decrease in interest expense in 2011 due to interest to customers related to the fuel over recovery balance in 2010.

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•	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 longer eligible for the Oklahoma investment tax credit related to the change in the tax method of accounting for capitalization of repair expenditures; and

•	higher Oklahoma investment tax credits in 2011 as compared to 2010.

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(A)	Incremental transportation volumes consist of natural gas moved only on the transportation pipeline.

•	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.

•	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.

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•	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.

•	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 and renegotiated 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 of transportation and gathering fees as contracts are renegotiated, which decreased the gross margin by $1.4 million.

•	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.

•	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;

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•	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.

•	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.

•	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.

•	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 no comparable item during 2011.

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•	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.

•	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.

•	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;

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•	higher interruptible transportation fees due to new contracts with more favorable rates in 2011, which increased the gross margin by $1.6 million; and

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higher crosshaul revenues in 2011 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 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.

•	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.

•	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, which decreased 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.

•	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.

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•	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.

•	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.

•	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 as compared to other companies in the midstream energy sector, without regard to financing or capital structure; and

•	the viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities.

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(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.

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•	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.

•	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;

•	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.

•	repayment in 2010 of the remaining balance of Enogex LLC's $400 million 8.125% senior notes which matured on January 15, 2010;

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•	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.

(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

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(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:

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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.

(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.

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(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.

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(A)	Prior to or when these debt obligations mature, the Company may refinance all or a portion of such debt at then-existing market interest rates which may be more or less than the interest rates on the maturing debt.

(B)	A hypothetical change of 100 basis points in the underlying variable interest rate incurred by the Company would change interest expense by $3.9 million annually.

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1.	Summary of Significant Accounting Policies

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(A)	Included in Other Current Assets on the Consolidated Balance Sheets.

(B)	Included in Other Current Liabilities on the Consolidated Balance Sheets.

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(A)	This amount includes a plant acquisition adjustment of $148.3 million and accumulated amortization of $23.3 million.

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(A)	This amount includes a plant acquisition adjustment of $148.3 million and accumulated amortization of $23.3 million.

(B)	This amount includes a plant acquisition adjustment of $3.3 million and accumulated amortization of $0.3 million.

(A)	This amount includes a plant acquisition adjustment of $148.3 million and accumulated amortization of $17.9 million.

(B)	This amount includes a plant acquisition adjustment of $3.3 million and accumulated amortization of $0.2 million.

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(A)	Due to certain Enogex compression assets in 2012 and OG&E's Crossroads wind farm in 2011.

(B)	Due to changes to OG&E's asset retirement obligations related to its wind farms due to a change in the assumption related to the timing of removal used in the valuation of the asset retirement obligations.

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2.	Accounting Pronouncements

3.	Gas Gathering and Processing Acquisitions and Divestitures

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4.	Noncontrolling Interests

(A)	Effective October 1, 2012, OGE Energy and the ArcLight group made contributions to Enogex Holdings of $45.0 million each to fund a portion of Enogex LLC's 2012 capital requirements.

5.	Impairment of Assets

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6.	Fair Value Measurements

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(A)	The Company uses the market approach to fair value its gas imbalance assets and liabilities, using an average of the Inside FERC Gas Market Report for Panhandle Eastern Pipe Line Co. (Texas, Oklahoma Mainline), ONEOK (Oklahoma) and ANR Pipeline (Oklahoma) indices.

(B)	Gas imbalance assets exclude fuel reserves for under retained fuel due from shippers of $5.9 million at December 31, 2012 with no comparable item at December 31, 2011, which fuel reserves are based on the value of natural gas at the time the imbalance was created and which are not subject to revaluation at fair market value.

(C)	Gas imbalance liabilities exclude fuel reserves for over retained fuel due to shippers of $1.2 million and $2.0 million at December 31, 2012 and 2011, respectively, which fuel reserves are based on the value of natural gas at the time the imbalance was created and which are not subject to revaluation at fair market value.

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(A)

In September 2012, OG&E purchased the electric distribution system at Tinker Air Force Base for $10.7 million and began making installment payments over a 50-year term. The fair value of this debt was based on calculating the net present value of the monthly payments discounted by the Company's current borrowing rate. Since the debt was valued using unobservable inputs, it was classified as Level 3 in the fair value hierarchy. This was a non-cash investing and financing activity as discussed in Note 9.

7.	Derivative Instruments and Hedging Activities

•	NGLs put options and NGLs swaps are used to manage Enogex's NGLs exposure associated with its processing agreements;

•	natural gas swaps are used to manage Enogex's keep-whole natural gas exposure associated with its processing operations and Enogex's natural gas exposure associated with operating its gathering, transportation and storage assets; and

•	natural gas futures and swaps, natural gas options and natural gas commodity purchases and sales are used to manage Enogex's natural gas exposure associated with its storage and transportation contracts and asset management activities.

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(A)	Natural gas in MMBtu's.

(A)	Natural gas in MMBtu's.

(B)	95.1 percent of the natural gas contracts have durations of one year or less, 2.9 percent have durations of more than one year and less than two years and 2.0 percent have durations of more than two years.

(C)	Of the natural gas physical purchases and sales volumes not designated as hedges, the majority are priced based on a monthly or daily index and the fair value is subject to little or no market price risk.

(D)	Natural gas physical sales volumes exceed natural gas physical purchase volumes due to the marketing of natural gas volumes purchased via Enogex's processing contracts, which are not derivative instruments and are excluded from the table above.

(A)	See Note 6 for a reconciliation of the Company's total derivatives fair value to the Company's Consolidated Balance Sheet at December 31, 2012.

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(A)	See Note 6 for a reconciliation of the Company's total derivatives fair value to the Company's Consolidated Balance Sheet at December 31, 2011.

(A)	The estimated net amount of gains or losses included in Accumulated Other Comprehensive Income (Loss) at December 31, 2012 that is expected to be reclassified into income within the next 12 months is a loss of $0.2 million.

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8.	Stock-Based Compensation

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(A)	For performance units, this represents the target number of performance units granted.  Actual number of performance units earned, if any, is dependent upon performance and may range from 0 percent to 200 percent of the target.

(B)	These amounts represent performance units that vested at December 31, 2011 which were settled in February 2012.

(A)	For performance units, this represents the target number of performance units granted.  Actual number of performance units earned, if any, is dependent upon performance and may range from 0 percent to 200 percent of the target.

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(A)	The difference between the market value on the date of exercise and the option exercise price.

(B)	The Company did not realize an income tax benefit for the tax deductions from the exercised stock options in 2012 and 2011 due to the Company being in a tax net operating loss position in 2012 and 2011.

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9.	Supplemental Cash Flow Information

(A)	Net of interest capitalized of $8.0 million, $19.1 million and $8.0 million in 2012, 2011 and 2010, respectively.

10.	Income Taxes

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(A)	These are credits associated with the production from OG&E's wind farms.

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11.	Common Equity

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12.	Long-Term Debt

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13.	Short-Term Debt and Credit Facilities

(A)	Includes direct borrowings under the revolving credit agreements, commercial paper borrowings and letters of credit at December 31, 2012.

(B)	This bank facility is available to back up OGE Energy's commercial paper borrowings and to provide revolving credit borrowings.  This bank facility can also be used as a letter of credit facility.  At December 31, 2012, there was $430.9 million in outstanding commercial paper borrowings.

(C)	This bank facility is available to back up OG&E's commercial paper borrowings and to provide revolving credit borrowings.  This bank facility can also be used as a letter of credit facility.  At December 31, 2012, there was $2.2 million supporting letters of credit.

(D)	This bank facility is available to provide revolving credit borrowings for Enogex LLC.  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.

(E)	Represents the weighted-average interest rate for the outstanding borrowings under the revolving credit agreements, commercial paper borrowings and letters of credit.

14.	Retirement Plans and Postretirement Benefit Plans

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(A)	This category represents U.S. treasury notes and bonds with a Moody's Investors Services rating of Aaa and Government Agency Bonds with a Moody's Investors Services rating of A1 or higher.

(B)	This category primarily represents U.S. corporate bonds with an investment grade rating at or above Baa3 or BBB- by Moody's Investors Services, Standard & Poor's Ratings Services or Fitch Ratings.

(C)	This category represents units of participation in a commingled fund that primarily invested in stocks of international companies and emerging markets.

(D)

This category represents units of participation in an investment pool which primarily invests in foreign or domestic bonds, debentures, mortgages, equipment or other trust certificates, notes, obligations issued or guaranteed by the U.S. Government or its agencies, bank certificates of deposit, bankers' acceptances and repurchase agreements, high grade commercial paper and other instruments with money market characteristics with a fixed or variable interest rate. There are no restrictions on redemptions in the common/collective trust.

(E)	This category represents units of participation in a commingled fund that primarily invest in stocks and bonds of U.S. companies.

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(A)	This category represents a group retiree medical insurance contract which invests in a pool of common stocks, bonds and money market accounts, of which a significant portion is comprised of mortgage-backed securities.

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(A)	Unamortized prior service cost is amortized on a straight-line basis over the average remaining service period to the first eligibility age of participants who are expected to receive a benefit and are active at the date of the plan amendment.

(B)	In addition to the $51.4 million, $45.1 million and $61.4 million and of net periodic benefit cost recognized in 2012, 2011 and 2010, respectively, the Company recognized the following:

•	an increase in pension expense in 2012, 2011 and 2010 of $8.3 million, $10.8 million and $8.1 million, respectively, to maintain the allowable amount to be recovered for pension expense in the Oklahoma jurisdiction which are included in the Pension tracker regulatory liability (see Note 1); and

•	an increase in postretirement medical expense in 2012 and 2011 of $0.8 million and $3.5 million, respectively, to maintain the allowable amount to be recovered for postretirement medical expense in the Oklahoma jurisdiction which are included in the Pension tracker regulatory liability (see Note 1).

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15.	Report of Business Segments

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(A)	Includes $78.6 million related to the acquisition of certain gas gathering assets as discussed in Note 3.

(A)	Includes $200.4 million related to the acquisition of certain gas gathering assets as discussed in Note 3.

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16.	Commitments and Contingencies

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17.	Rate Matters and Regulation

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18.	Quarterly Financial Data (Unaudited)

(A)	Due to the impact of dilution on the earnings per share calculation, quarterly earnings per share amounts may not add to the total.

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•	Consolidated Statements of Income for the years ended December 31, 2012, 2011 and 2010

•	Consolidated Statements of Comprehensive Income for the years ended December 31, 2012, 2011 and 2010

•	Consolidated Statements of Cash Flows for the years ended December 31, 2012, 2011 and 2010

•	Consolidated Balance Sheets at December 31, 2012 and 2011

•	Consolidated Statements of Capitalization at December 31, 2012 and 2011

•	Consolidated Statements of Changes in Stockholders' Equity for the years ended December 31, 2012, 2011 and 2010

•	Notes to Consolidated Financial Statements

•	Report of Independent Registered Public Accounting Firm (Audit of Financial Statements)

•	Management's Report on Internal Control Over Financial Reporting

•	Report of Independent Registered Public Accounting Firm (Audit of Internal Control)

•	Schedule II - Valuation and Qualifying Accounts

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(A)	Uncollectible accounts receivable written off, net of recoveries.

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