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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;

•	the timing and extent of changes in commodity prices, particularly natural gas and NGLs, the competitive effects of the available pipeline capacity in the regions Enable serves, and the effects of geographic and seasonal commodity price differentials, including the effects of these circumstances on re-contracting available capacity on Enable's interstate pipelines;

•	the timing and extent of changes in the supply of natural gas, particularly supplies available for gathering by Enable's gathering and processing business and transporting by Enable interstate pipelines, including the impact of natural gas and NGLs prices on the level of drilling and production activities in the regions Enable serves;

•	business conditions in the energy and natural gas midstream industries, including the demand for natural gas, NGLs, crude oil and midstream services;

•	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;

•	difficulty in making accurate assumptions and projections regarding future revenues and costs associated with the Company's equity investment in Enable that the Company does not control;

•	the risk that Enable may not be able to successfully integrate the operations of Enogex LLC and the businesses contributed by CenterPoint as discussed in Note 3; 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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(1)	Ark-La-Tex basin assets also include 14,500 Bbl/d of fractionation capacity and 6,300 Bbl/d of ethane pipeline capacity, which are not listed in the table.

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(1)	Except with respect to length, this information does not include amounts for Southeast Supply Header, LLC. Southeast Supply Header, LLC is a non- consolidated entity in which Enable own a 24.95% ownership interest.

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(A)	Approximately 30% of revenue requirement allocated to SPP members other than OG&E.

(B)	Approximately 85% of revenue requirement allocated to SPP members other than OG&E.

(D)	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. On July 19, 2013, the U.S. Court of Appeals for the Tenth Circuit by a 2 to 1 vote denied the petition for review and affirmed the EPA's issuance of the FIP. On January 2, 2014, the Tenth Circuit confirmed that the stay of the FIP has remained in place and continues until the Tenth Circuit issues the mandate. A Petition for Certiorari was filed by the State of Oklahoma, the Industrial Consumers and OG&E with the United States Supreme Court on January 29, 2014. The mandate from the Tenth Circuit has been stayed until the Supreme Court acts on the petition. If the Supreme Court elects not to hear the case, OG&E will have approximately 55 months from the effective date of the lifting of the stay to achieve compliance with the FIP.

•

Installation of control equipment (other than activated carbon injection) for compliance with MATS by a deadline of April 16, 2016, which includes a one-year extension which was granted by the Oklahoma Department of Environmental Quality. As noted above, OG&E is currently planning to utilize activated carbon injection for the removal of mercury at each of its five coal-fired units, the capital costs of which are estimated to be approximately $20 million over a three year period and are included in the capital expenditures table in "Future Capital Requirements and Financing Activities" above. OG&E continues to review whether additional controls such as dry sorbent injection are needed for compliance with MATS. Current capital costs for installing the necessary control equipment for dry sorbent injection are estimated to be approximately $45 million over a three year period, but due to the uncertainty as to whether or not dry sorbent injection is necessary, such costs are not included in the capital expenditures table in "Future Capital Requirements and Financing Activities" above.

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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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•	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.

•	the fees and gross margins realized with respect to the volume of natural gas and crude oil handled;

•	the prices of, levels of production of, and demand for natural gas and crude oil;

•	the volume of natural gas and crude oil gathered, compressed, treated, dehydrated, processed, fractionated, transported and stored;

•	the relationship among prices for natural gas, NGLs and crude oil;

•	cash calls and settlements of hedging positions;

•	margin requirements on open price risk management assets and liabilities;

•	the level of competition from other midstream energy companies;

•	adverse effects of governmental and environmental regulation;

•	the level of operation and maintenance expenses and general and administrative costs; and

•	prevailing economic conditions.

•	the level and timing of capital expenditures;

•	the cost of acquisitions;

•	debt service requirements and other liabilities;

•	fluctuations in working capital needs;

•	ability to borrow funds and access capital markets;

•	restrictions contained in debt agreements;

•	other business risks affecting its cash levels.

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•	the availability and cost of capital;

•	prevailing and projected commodity prices, including the prices of natural gas, NGLs and crude oil;

•	demand for natural gas, NGLs and crude oil;

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•	levels of reserves;

•	geological considerations;

•	environmental or other governmental regulations, including the availability of drilling permits and the regulation of hydraulic fracturing; and

•	the availability of drilling rigs and other costs of production and equipment.

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•	joint venture partners may share certain approval rights over major decisions;

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•	joint venture partners may not pay their share of the joint venture’s obligations, leaving Enable liable for their shares of joint venture liabilities;

•	it may be unable to control the amount of cash it will receive from the joint venture;

•	it may incur liabilities as a result of an action taken by its joint venture partners;

•	it may be required to devote significant management time to the requirements of and matters relating to the joint ventures;

•	its insurance policies may not fully cover loss or damage incurred by both them and its joint venture partners in certain circumstances;

•	its joint venture partners may be in a position to take actions contrary to its instructions or requests or contrary to its policies or objectives; and

•	disputes between them and its joint venture partners may result in delays, litigation or operational impasses.

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

•	inadvertent damage from construction, vehicles, farm and utility equipment;

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

•	ruptures, fires and explosions; and

•	other hazards that could also result in personal injury and loss of life, pollution and suspension of operations.

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•	acquired businesses or assets may not produce revenues, earnings or cash flow at anticipated levels;

•	acquired businesses or assets could have environmental, permitting or other problems for which contractual protections prove inadequate;

•	it may assume liabilities that were not disclosed to it, that exceed its estimates, or for which its rights to indemnification from the seller are limited;

•	it may be unable to integrate acquired businesses successfully and realize anticipated economic, operational and other benefits in a timely manner, which could result in substantial costs and delays or other operational, technical or financial problems; and

•	acquisitions, or the pursuit of acquisitions, could disrupt its ongoing businesses, distract management, divert resources and make it difficult to maintain its current business standards, controls and procedures.

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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, if at all;

•	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, future business opportunities and distributions;

•	the debt level will make Enable more vulnerable to competitive pressures or a downturn in the business or the economy generally; and

•	the debt level may limit flexibility in responding to changing business and economic conditions.

•	Enable's credit facilities contain customary covenants that, among other things, limit the ability to:

•	permit its subsidiaries to incur or guarantee additional debt;

•	incur or permit to exist certain liens on assets;

•	dispose of assets;

•	merge or consolidate with another company or engage in a change of control;

•	enter into transactions with affiliates on non-arm’s length terms; and

•	change the nature of its business.

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

•	identify and characterize applicable threats that could impact a high consequence area;

•	improve data collection, integration, and analysis;

•	repair and remediate pipelines as necessary; and

•	implement preventive and mitigating action.

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(A)	2013 Capacity Factor = 2013 Net Actual Generation / (2013 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.

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(A)	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 $12.3 million, or 4.4 percent, or $0.06 per diluted share of the Company's common stock, driven by higher gross margin primarily related to increased wholesale transmission revenue and lower other operation and maintenance expense, partially offset by higher interest expense related to the issuance of debt in May 2013;

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an increase in net income at OGE Holdings of $25.8 million, or 34.8 percent, or $0.13 per diluted share of the Company's common stock, due partially to the accretive effect to OGE Holdings of its investment in Enable since May 1, 2013 and a reduction in deferred state income taxes, associated with a remeasurement of the accumulated deferred taxes related to the formation of Enable. Also contributing to the increase was the performance of Enogex for the first four months of 2013. Compared to the same period of 2012, earnings were higher for Enogex due to increased gathering rates and volumes and inlet processing volumes associated with its expansion projects and gas gathering assets acquired in August 2012. These increases were partially offset by lower NGLs prices, lower keep-whole processing spreads and the contract conversion of the Texas production volumes of one of Enogex's five largest customers from keep-whole to fixed-fee; and

•	a decrease in net income at OGE Energy of $5.5 million, or $0.04 per diluted share of the Company's common stock, primarily due to transaction expenses related to the formation of Enable as discussed in Note 3 of Notes to Condensed Consolidated Financial Statements.

•

an increase in net income at OG&E of $17.0 million, or 6.5 percent, or $0.09 per diluted share of the Company's common stock, primarily due to a higher gross margin primarily due to increased recovery of investments and increased transmission revenue partially offset by milder weather in OG&E's service territory. The increase in gross margin was partially offset by higher depreciation and amortization expense related to additional assets being placed in service and lower allowance for equity funds used during construction related to higher levels of construction costs for the Crossroads wind farm in 2011;

•	an increase in net income of Enogex LLC of $0.7 million, which was offset by an $8.9 million increase in net income attributable to noncontrolling interests, resulting in a decrease in net income attributable to OGE Holdings

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•	an increase in net income at OGE Energy of $3.3 million, or $0.01 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.

•	Approximately 200 million average diluted shares outstanding;

•	An effective tax rate of approximately 30 percent; and

•	A projected loss at the holding company of $2 million or $0.01 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 $1.355 billion to $1.345 billion based on sales growth of approximately 1.2 percent on a weather-adjusted basis;

•	Approximately $115 million of gross margin is primarily attributed to regionally allocated transmission projects;

•	Operating expenses of approximately $805 million to $815 million, with operation and maintenance expenses comprising 56 percent of the total;

•	Interest expense of approximately $141 million which assumes a $4 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 2014;

•	Other income of approximately $14 million including approximately $11 million of AEFUDC; and

•	An effective tax rate of approximately 28 percent.

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(A)	The former natural gas transportation and storage segment and natural gas gathering and processing segment have been combined into the natural gas midstream operations 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 primarily due to higher investments related to certain FERC approved transmission projects included in formula rates.

(B)	Decreased primarily due to sales and customer mix.

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(A)	Decreased primarily due to lower recoverable amounts of pension expense and postretirement medical expense allowed in the August 2012 rate case, a decrease in medical expense, and a decrease in worker's compensation accruals.

(B)	Decreased primarily due to lower salaries and wages as a result of lower headcount in 2013 and a decrease in incentive pay, partially offset by annual salary increases and an increase in overtime wages related to 2013 storms.

(C)	Includes costs that are being recovered through a rider.

•	increases in depreciation rates from the August 2012 rate case; and

•	additional assets being placed in service throughout 2013 and 2012, including the Sooner-Rose Hill and Sunnyside-Hugo transmission projects, which were fully in service in April 2012, the smart grid project which was completed in late 2012 and the Cleveland to Sooner transmission project which was fully in service in February 2013.

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

(A)	Excludes volumes billed under throughput agreements.

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•	increased gathering rates and volumes associated with ongoing expansion projects and increased volumes from as gathering assets acquired in November 2011 and August 2012;

•	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;

•	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 as discussed below; and

•	lower impairment of assets as discussed below.

•	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.

•	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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•	fuel refunds at OG&E in 2013 as compared to higher fuel recoveries in 2012;

•	the deconsolidation of Enogex Holdings on May 1, 2013.

•	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 LLC during 2012 as compared to 2011 partially offset by lower natural gas and NGLs prices in 2012 as compared to 2011.

•	a decrease in repayments of lines of credit in 2013 as compared to 2012;

•	payments on advances from unconsolidated affiliates due to the deconsolidation of Enogex Holdings on May 1, 2013; and

•	and higher contributions from the Arclight group related to the closing of the transaction to form Enable.

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•	lower contributions from the ArcLight group during 2012 as compared to 2011;higher borrowings under Enogex LLC's revolving credit agreement during 2011; and

•	repayments of Enogex's line of credit during 2012.

(A)	Approximately 30% of revenue requirement allocated to SPP members other than OG&E.

(B)	Approximately 85% of revenue requirement allocated to SPP members other than OG&E.

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(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. On July 19, 2013, the U.S. Court of Appeals for the Tenth Circuit by a 2 to 1 vote denied the petition for review and affirmed the EPA's issuance of the FIP. On January 2, 2014, the Tenth Circuit confirmed that the stay of the FIP has remained in place and continues until the Tenth Circuit issues the mandate. A Petition for Certiorari was filed by the State of Oklahoma, the Industrial Consumers and OG&E with the United States Supreme Court on January 29, 2014. The mandate from the Tenth Circuit has been stayed until the Supreme Court acts on the petition. If the Supreme Court elects not to hear the case, OG&E will have approximately 55 months from the effective date of the lifting of the stay to achieve compliance with the FIP.

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Installation of control equipment (other than activated carbon injection) for compliance with MATS by a deadline of April 16, 2016, which includes a one-year extension which was granted by the Oklahoma Department of Environmental Quality. As noted above, OG&E is currently planning to utilize activated carbon injection for the removal of mercury at each of its five coal-fired units, the capital costs of which are estimated to be approximately $20 million over a three year period and are included in the capital expenditures table in "Future Capital Requirements and Financing Activities" above. OG&E continues to review whether additional controls such as dry sorbent injection are needed for compliance with MATS. Current capital costs for installing the necessary control equipment for dry sorbent injection are estimated to be approximately $45 million over a three year period, but due to the uncertainty as to whether or not dry sorbent injection is necessary, such costs are not included in the capital expenditures table in "Future Capital Requirements and Financing Activities" above.

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(A)	Maturities of the Company's long-term debt during the next five years consist of $100.2 million, $0.2 million, $110.2 million$125.1 million and $250.1 million in years 2014, 2015, 2016, 2017 and 2018, 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 $1.4 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)	Construction work in progress was $0.1 million and $39.5 million for the McClain and Redbud Plants, respectively.

(B)	This amount includes a plant acquisition adjustment of $148.3 million and accumulated amortization of $28.8 million.

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(A)	Construction work in progress was $0.1 million and $0.3 million for the McClain and Redbud Plants, respectively.

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

(A)	This amount includes a plant acquisition adjustment of $148.3 million and accumulated amortization of $28.8 million.

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

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

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

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(A)	As a result of the formation of Enable on May 1, 2013, the Company has no obligations at December 31, 2013 under OGE Holdings' asset retirement obligations previously disclosed in the Company's 2012 10-K.

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

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(A)	Includes $3.0 million of pension settlement charges.

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(A)	These accumulated other comprehensive income (loss) components are included in the computation of net periodic benefit cost (see Note 13 for additional information).

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2.	Accounting Pronouncements

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3.	Investment in Unconsolidated Affiliates and Related Party Transactions

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4.	Impairment of Assets

5.	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, 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 at December 31, 2012, 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.

(A)	As a result of the formation of Enable on May 1, 2013 and the Company's deconsolidation of Enogex Holdings, the Company's consolidated financial statements do not include any obligations for the Enogex LLC Senior Notes and Enogex LLC Term Loan as of May 1, 2013.

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6.	Derivative Instruments and Hedging 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 5 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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7.	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 the performance unit grants previously based on earnings before interest, taxes, depreciation and amortization that were converted to performance units based on total shareholder return or earnings per share as a result of the formation of Enable.

(C)	These amounts represent performance units that vested at December 31, 2012 which were settled in February 2013.

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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 the performance unit grants previously based on earnings before interest, taxes, depreciation and amortization that were converted to performance units based on total shareholder return or earnings per share as a result of the formation of Enable.

(C)	The intrinsic value of the performance units based on total shareholder return and earnings per share is $28.3 million and $5.6 million, respectively.

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

8.	Supplemental Cash Flow Information

(A)	Net of interest capitalized of $5.4 million, $8.0 million and $19.1 million in 2013, 2012 and 2011, respectively.

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9.	Income Taxes

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

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10.	Common Equity

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11.	Long-Term Debt

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12.	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, 2013.

(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.

(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.

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

(E)

In December 2011, the Company and OG&E entered into unsecured five-year revolving credit agreements to total in the aggregate $1,150.0 million ($750.0 million for the Company and $400.0 million for OG&E). Each of the credit facilities contain an option, which may be exercised up to two times, to extend the term for an additional year, subject to consent of a specified percentage of the lenders. Effective July 29, 2013, the Company and OG&E utilized one of these one-year extensions, and received consent from all of the lenders, to extend the maturity of their credit agreements to December 13, 2017.

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13.	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.

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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 $60.0 million, $51.4 million and $45.1 million and of net periodic benefit cost recognized in 2013, 2012 and 2011, respectively, the Company recognized the following:

•	an increase in pension expense in 2013, 2012 and 2011 of $5.8 million, $8.3 million and $10.8 million, respectively, to maintain the allowable amount to be recovered for pension expense in the Oklahoma jurisdiction, which are included in the Pension tracker regulatory asset or liability (see Note 1); and

•	an increase in postretirement medical expense in 2013, 2012 and 2011 of $0.6 million, $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 asset or liability (see Note 1);

•	a deferral of pension expense in 2013 of $17.0 million related to the pension settlement charge of $22.4 million, in accordance with the Oklahoma pension tracker.

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14.	Report of Business Segments

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15.	Commitments and Contingencies

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16.	Rate Matters and Regulation

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17.	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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(i)	The following Consolidated Financial Statements are included in Part II, Item 8 of this Annual Report:

•	Consolidated Statements of Income for the years ended December 31, 2013, 2012 and 2011

•	Consolidated Statements of Comprehensive Income for the years ended December 31, 2013, 2012 and 2011

•	Consolidated Statements of Cash Flows for the years ended December 31, 2013, 2012 and 2011

•	Consolidated Balance Sheets at December 31, 2013 and 2012

•	Consolidated Statements of Capitalization at December 31, 2013 and 2012

•	Consolidated Statements of Changes in Stockholders' Equity for the years ended December 31, 2013, 2012 and 2011

•	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)

(ii)	The financial statements of Enable Midstream Partners, LP, required pursuant to Rule 3-09 of Regulation S-X are filed as Exhibit 99.06

•	Schedule II - Valuation and Qualifying Accounts

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

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