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OKLAHOMA GAS & ELECTRIC CO - 10-K - Management's Discussion and Analysis of Financial Condition and Results of Operations.(Edgar Glimpses Via Acquire Media NewsEdge) Introduction OG&E generates, transmits, distributes and sells electric energy in Oklahoma and western Arkansas. Its operations are subject to regulation by the OCC, the APSC and the FERC. OG&E was incorporated in 1902 under the laws of the Oklahoma Territory. OG&E is the largest electric utility in Oklahoma and its franchised service territory includes the Fort Smith, Arkansas area. OG&E sold its retail natural gas business in 1928 and is no longer engaged in the natural gas distribution business. OG&E is a wholly-owned subsidiary of OGE Energy, an energy and energy services provider offering physical delivery and related services for both electricity and natural gas primarily in the south central United States. Overview OG&E Strategy OGE Energy's mission is to fulfill its critical role in the nation's electric utility and natural gas midstream pipeline infrastructure and meet individual customers' needs for energy and related services focusing on safety, efficiency, reliability, customer service and risk management. OGE Energy's corporate strategy is to continue to maintain its existing business mix and diversified asset position of its regulated electric utility business and unregulated natural gas midstream business while providing competitive energy products and services to customers primarily in the south central United States as well as seeking growth opportunities in both businesses. OG&E is focused on increased investment to preserve system reliability and meet load growth by adding and maintaining infrastructure equipment and replacing aging transmission and distribution systems. OG&E expects to maintain a diverse generation portfolio while remaining environmentally responsible. OG&E is focused on maintaining strong regulatory and legislative relationships for the long-term benefit of its customers. In an effort to encourage more efficient use of electricity, OG&E is also providing energy management solutions to its customers through the Smart Grid program that utilizes newer technology to improve operational and environmental performance as well as allow customers to monitor and manage their energy usage, which should help reduce demand during critical peak times, resulting in lower capacity requirements. If these initiatives are successful, OG&E believes it may be able to defer the construction or acquisition of any incremental fossil fuel generation capacity until 2020. The Smart Grid program also provides benefits to OG&E, including more efficient use of its resources and access to increased information about customer usage, which should enable OG&E to have better distribution system planning data, better response to customer usage questions and faster detection and restoration of system outages. As the Smart Grid platform matures, OG&E anticipates providing new products and services to its customers. In addition, OG&E is also pursuing additional transmission-related opportunities within the SPP. Summary of Operating Results 2013 compared to 2012. OG&E reported net income of $292.6 million and $280.3 million, respectively, in 2013 and 2012, an increase of $12.3 million, or 4.4 percent, driven by higher gross margin primarily related to increased wholesale transmission revenue and lower other operation and maintenance expense, partially offset by higher interest expense related to the issuance of debt in May 2013 2012 compared to 2011. OG&E reported net income of $280.3 million and $263.3 million, respectively, in 2012 and 2011, an increase of $17.0 million, or 6.5 percent, primarily due to a higher gross margin 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. 2014 Outlook OG&E projects to earn approximately $292 million to $303 million, in 2014 and is based on the following assumptions: • Normal weather patterns are experienced for the remainder of the year; • Gross margin on revenues of approximately $1.355 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; 24-------------------------------------------------------------------------------- • 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 includingapproximately $11 million of AEFUDC; and • An effective tax rate of approximately 28 percent. OG&E has significant seasonality in its earnings. OG&E typically shows minimal earnings in the first and fourth quarters with a majority of earnings in the third quarter due to the seasonal nature of air conditioning demand. Results of Operations The following discussion and analysis presents factors that affected OG&E's results of operations for the years ended December 31, 2013, 2012 and 2011 and OG&E's financial position at December 31, 2013 and 2012. The following information should be read in conjunction with the Financial Statements and Notes thereto. Known trends and contingencies of a material nature are discussed to the extent considered relevant. Year ended December 31 (In millions) 2013 2012 2011 Operating income $ 525.3 $ 489.4 $ 472.3 Net income $ 292.6 $ 280.3 $ 263.3 In reviewing its operating results, OG&E believes that it is appropriate to focus on operating income as reported in its Statements of Income as those measures indicate the ongoing profitability of OG&E excluding the cost of capital and income taxes. 25 -------------------------------------------------------------------------------- Year ended December 31 (Dollars in millions) 2013 2012 2011 Operating revenues $ 2,262.2 $ 2,141.2 $ 2,211.5 Cost of sales 965.9 879.1 1,013.5 Other operation and maintenance 438.8 446.3 436.0 Depreciation and amortization 248.4 248.7 216.1 Taxes other than income 83.8 77.7 73.6 Operating income 525.3 489.4 472.3 Allowance for equity funds used during construction 6.6 6.2 20.4 Other income 8.1 8.2 8.5 Other expense 4.6 4.3 8.4 Interest expense 129.3 124.6 111.6 Income tax expense 113.5 94.6 117.9 Net income $ 292.6 $ 280.3 $ 263.3 Operating revenues by classification Residential $ 901.4 $ 878.0 $ 943.5 Commercial 554.2 523.5 531.3 Industrial 220.6 206.8 216.0 Oilfield 176.4 163.4 165.1 Public authorities and street light 214.3 202.4 207.4 Sales for resale 59.4 54.9 65.3 System sales revenues 2,126.3 2,029.0 2,128.6 Off-system sales revenues 14.7 36.5 36.2 Other 121.2 75.7 46.7 Total operating revenues $ 2,262.2 $ 2,141.2 $ 2,211.5 Reconciliation of gross margin to revenue: Operating revenues 2,262.2 2,141.2 2,211.5 Cost of sales 965.9 879.1 1,013.5 Gross Margin 1,296.3 1,262.1 1,198.0 MWH sales by classification (In millions) Residential 9.4 9.1 9.9 Commercial 7.1 7.0 6.9 Industrial 3.9 4.0 3.9 Oilfield 3.4 3.3 3.2 Public authorities and street light 3.2 3.3 3.2 Sales for resale 1.2 1.3 1.4 System sales 28.2 28.0 28.5 Off-system sales 0.4 1.4 1.0 Total sales 28.6 29.4 29.5 Number of customers 806,940 798,110 789,146 Weighted-average cost of energy per kilowatt-hour - cents Natural gas 3.905 2.930 4.328 Coal 2.273 2.310 2.064 Total fuel 2.784 2.437 2.897 Total fuel and purchased power 3.178 2.806 3.215 Degree days (A) Heating - Actual 3,673 2,667 3,359 Heating - Normal 3,349 3,349 3,631 Cooling - Actual 2,106 2,561 2,776 Cooling - Normal 2,092 2,092 1,911 (A) Degree days are calculated as follows: The high and low degrees of a particular day are added together and then averaged. If the calculated average is above 65 degrees, then the difference between the calculated average and 65 is expressed as cooling degree days, with each degree of difference equaling one cooling degree day. If the calculated average is below 65 degrees, then the difference between the calculated average and 65 is expressed as heating degree days, with each degree of difference equaling one heating degree day. The daily calculations are then totaled for the particular reporting period. 26-------------------------------------------------------------------------------- 2013 compared to 2012. OG&E's operating income increased $35.9 million, or 7.3 percent, in 2013 as compared to 2012 primarily due to a higher gross margin, lower other operation and maintenance expense and lower depreciation and amortization expense partially offset by higher taxes other than income. Gross Margin Gross Margin is defined by OG&E as operating revenues less fuel, purchased power and transmission expenses. Gross margin is a non-GAAP financial measure because it excludes depreciation and amortization, and other operation and maintenance expenses. Expenses for fuel, purchased power and transmission expenses are recovered through fuel adjustment clauses and as a result changes in these expenses are offset in operating revenues with no impact on net income. OG&E believes gross margin provides a more meaningful basis for evaluating its operations across periods than operating revenues because gross margin excludes the revenue effect of fluctuations in these expenses. Gross margin is used internally to measure performance against budget and in reports for management and the Board of Directors. OG&E's definition of gross margin may be different from similar terms used by other companies. Operating revenues were $2,262.2 million in 2013 as compared to $2,141.2 million in 2012, an increase of $121.0 million, or 5.7 percent. Cost of sales were $965.9 million in 2013 as compared to $879.1 million in 2012, an increase of $86.8 million, or 9.9 percent. Gross margin was $1,296.3 million in 2013 as compared to $1,262.1 million in 2012, an increase of $34.2 million, or 2.7 percent The below factors contributed to the change in gross margin: $ Change (In millions) Wholesale transmission revenue (A) $ 44.9 New customer growth 10.9 Non-residential demand and related revenues 0.1 Other 1.8 Price variance (B) (17.1 ) Quantity variance (primarily weather) (6.4 ) Change in gross margin $ 34.2 (A) Increased primarily due to higher investments related to certain FERC approved transmission projects included in formula rates. (B) Decreased primarily due to sales and customer mix. Cost of sales for OG&E consists of fuel used in electric generation, purchased power and transmission related charges. Fuel expense was $672.7 million in 2013 as compared to $642.4 million in 2012, an increase of $30.3 million, or 4.7 percent, primarily due to higher natural gas prices. OG&E's electric generating capability is fairly evenly divided between coal and natural gas and provides for flexibility to use either fuel to the best economic advantage for OG&E and its customers. In 2013, OG&E's fuel mix was 53 percent coal, 40 percent natural gas and seven percent wind. In 2012, OG&E's fuel mix was 52 percent coal, 42 percent natural gas and six percent wind. Purchased power costs were $267.6 million in 2013 as compared to $223.0 million in 2012, an increase of $44.6 million, or 20.0 percent, primarily due to an increase in purchases in the energy imbalance service market and short-term power agreements. Transmission related charges were $25.6 million in 2013 as compared to $13.7 million in 2012, an increase of $11.9 million, or 86.9 percent, primarily due to higher SPP charges for the base plan projects of other utilities. Variances in the actual cost of fuel used in electric generation and certain purchased power costs, as compared to the fuel component included in the cost-of-service for ratemaking, are passed through to OG&E's customers through fuel adjustment clauses. The fuel adjustment clauses are subject to periodic review by the OCC, the APSC and the FERC. The OCC, the APSC and the FERC have authority to review the appropriateness of gas transportation charges or other fees OG&E pays to its affiliate, Enable. 27 --------------------------------------------------------------------------------Operating Expenses Other operation and maintenance expenses were $438.8 million in 2013 as compared to $446.3 million in 2012, a decrease of $7.5 million, or 1.7 percent. The below factors contributed to the change in other operations and maintenance expense: $ Change (In millions) Employee benefits (A) $ (12.3 ) Total salaries and wages (B) (6.5 ) Temporary labor (2.3 ) Contract professional services (primarily smart grid) (C) (1.7 ) Other 0.6 Other marketing and sales expense (primarily lower demand-side management initiatives) (C) 1.2 Administrative and assessment fees (primarily SPP Administration Fees) 2.2 Software expense (primarily smart grid) (C) 2.7 Capitalized labor 8.6 Change in other operation and maintenance expense $ (7.5 ) (A) Decreased primarily due to lower recoverable amounts of pension expense and postretirement medical expense allowed in the August 2012 rate case, a decrease in medical expense, and a decrease in worker's compensation accruals. (B) Decreased primarily due to lower salaries and wages as a result of lower headcount in 2013 and a decrease in incentive pay, partially offset by annual salary increases and an increase in overtime wages related to 2013 storms. (C) Includes costs that are being recovered through a rider. Depreciation and amortization expense was $248.4 million in 2013 as compared to $248.7 million in 2012, a decrease of $0.3 million, primarily due to the amortization of the deferred pension credits regulatory liability and a decrease in the amortization of the storm regulatory asset (see Note 1). These decreases in depreciation and amortization expense were partially offset by: • increases in depreciation rates from the August 2012 rate case; and • additional assets being placed in service throughout 2013 and 2012, including the Sooner-Rose Hill and Sunnyside-Hugo transmission projects, which were fully in service in April 2012, the smart grid project which was completed in late 2012 and the Cleveland to Sooner transmission project which was fully in service in February 2013. Taxes other than income was $83.8 million in 2013 as compared to $77.7 million in 2012, an increase of $6.1 million, or 7.9 percent, primarily due to higher ad valorem taxes. Additional Information Interest Expense. Interest expense was $129.3 million in 2013 as compared to $124.6 million in 2012, an increase of $4.7 million, or 3.8 percent, primarily due to a $6.4 million increase in interest on long term debt related to a $250 million debt issuance that occurred in May 2013, partially offset by a $2.0 million decrease in interest related to tax matters. Income Tax Expense. Income tax expense was $113.5 million in 2013 as compared to $94.6 million in 2012, an increase of $18.9 million, or 20.0 percent. primarily due to higher pre-tax income and a reserve related to a portion of the Oklahoma investment tax credits generated in years prior to 2013 but not yet utilized. 2012 compared to 2011. OG&E's operating income increased $17.1 million, or 3.6 percent, in 2012 as compared to 2011 primarily due to a higher gross margin partially offset by higher other operation and maintenance expense and higher depreciation and amortization expense. 28 --------------------------------------------------------------------------------Gross Margin Operating revenues were $2,141.2 million in 2012 as compared to $2,211.5 million in 2011, a decrease of $70.3 million, or 3.2 percent. Fuel and purchased power was $879.1 million in 2012 as compared to $1,013.5 million in 2011, a decrease of $134.4 million, or 13.3 percent. Gross margin was $1,262.1 million in 2012 as compared to $1,198.0 million in 2011, an increase of $64.1 million, or 5.4 percent. The below factors contributed to the change in gross margin: $ Change (In millions) Price variance (A) $ 54.1 Wholesale transmission revenue (B) 28.5 New customer growth 11.5 Non-residential demand and related revenues 4.9 Enogex transportation credit (C) 3.3 Arkansas rate increase 2.8 Oklahoma rate increase 2.7 Renewal of wholesale contract with customer 1.3 Other 0.3 Quantity variance (primarily weather) (45.3 ) Change in gross margin $ 64.1 (A) Increased due to revenues from the recovery of investments, including the Crossroads wind farm and smart grid. (B) Increased primarily due to the inclusion of construction work in progress in transmission rates for specific FERC approved projects that previously accrued allowance for funds used during construction. (C) Increased due to a credit to OG&E's customers in 2011 related to the settlement of OG&E's 2009 fuel adjustment clause review. Fuel expense was $642.4 million in 2012 as compared to $775.0 million in 2011, a decrease of $132.6 million, or 17.1 percent, primarily due to lower natural gas prices. OG&E's electric generating capability is fairly evenly divided between coal and natural gas and provides for flexibility to use either fuel to the best economic advantage for OG&E and its customers. In 2012, OG&E's fuel mix was 52 percent coal, 42 percent natural gas and six percent wind. In 2011, OG&E's fuel mix was 58 percent coal, 39 percent natural gas and three percent wind. Purchased power costs were $223.0 million in 2012 as compared to $230.7 million in 2011, a decrease of $7.7 million, or 3.3 percent, primarily due to a decrease in cogeneration purchases and purchases in the energy imbalance service market due to milder weather partially offset by an increase in short-term power purchases. Transmission related charges were $13.7 million in 2012 as compared to $7.8 million in 2011, an increase of $5.9 million, or 75.6 percent, primarily due to higher SPP charges for the base plan projects of other utilities. 29 --------------------------------------------------------------------------------Operating Expenses Other operation and maintenance expenses were $446.3 million in 2012 as compared to $436.0 million in 2011, an increase of $10.3 million, or 2.4 percent. The below factors contributed to the change in other operations and maintenance expense: $ Change (In millions) Salaries and wages (A) $ 6.4Contract professional and technical services (related to smart grid) (B) 4.2 Employee benefits (C) 3.4 Administration and assessment fees (primarily SPP and North American Electric Reliability Corporation) 3.4 Wind farm lease expense (primarily Crossroads) (B) 3.0 Injuries and damages 1.9 Ongoing maintenance at power plants (B) 1.9 Software (primarily smart grid) (B) 1.8 Other 0.2 Temporary labor (1.7 ) Uncollectibles (2.4 ) Vegetation management (primarily system hardening) (B) (3.0 ) Allocations from holding company (primarily lower contract professional services and lower payroll and benefits) (3.1 ) Capitalized labor (5.7 ) Change in other operation and maintenance expense $ 10.3 (A) Increased primarily due to salary increases and an increase in incentive compensation expense partially offset by lower headcount in 2012 and a decrease in overtime expense. (B) Includes costs that are being recovered through a rider. (C) Increased primarily due to an increase in worker's compensation accruals, an increase in medical expense and an increase in postretirement medical expense partially offset by a decrease in pension expense. Depreciation and amortization expense was $248.7 million in 2012 as compared to $216.1 million in 2011, an increase of $32.6 million, or 15.1 percent, primarily due to additional assets being placed in service throughout 2011 and 2012, including the Crossroads wind farm, which was fully in service in January 2012, the Sooner-Rose Hill and Sunnyside-Hugo transmission projects, which were fully in service in April 2012, and the smart grid project which was completed in late 2012. Allowance for Equity Funds Used During Construction. Allowance for equity funds used during construction was $6.2 million in 2012 as compared to $20.4 million in 2011, a decrease of $14.2 million, or 69.6 percent, primarily due to higher levels of construction costs for the Crossroads wind farm in 2011. Other Income. Other income was $8.0 million in both 2012 and 2011. Factors affecting other income included an increased margin of $8.8 million recognized in the guaranteed flat bill program in 2012 as a result of milder weather offset by a decrease of $8.9 million related to the benefit associated with the tax gross-up of allowance for equity funds used during construction. Other Expense. Other expense was $4.3 million in 2012 as compared to $8.4 million in 2011, a decrease of $4.1 million, or 48.8 percent primarily due to a decrease in charitable contributions. Interest Expense. Interest expense was $124.6 million in 2012 as compared to $111.6 million in 2011, an increase of $13.0 million, or 11.6 percent, primarily due to a $6.9 million increase in interest expense related to lower allowance for borrowed funds used during construction costs for the Crossroads wind farm in 2011 and a $5.5 million increase in interest expense related to the issuance of long-term debt in May 2011. Income Tax Expense. Income tax expense was $94.6 million in 2012 as compared to $117.9 million in 2011, a decrease of $23.3 million, or 19.8 percent. The decrease in income tax expense was primarily due to an increase in the amount of Federal renewable energy tax credits recognized associated with the Crossroads wind farm and lower pre-tax income in 2012 as compared to 2011. 30 -------------------------------------------------------------------------------- Off-Balance Sheet Arrangement Railcar Lease Agreement OG&E has a noncancellable operating lease with purchase options, covering 1,389 coal rotary gondola railcars to transport coal from Wyoming to OG&E's coal-fired generation units. Rental payments are charged to Fuel Expense and are recovered through OG&E's tariffs and fuel adjustment clauses. On December 15, 2010, OG&E renewed the lease agreement effective February 1, 2011. At the end of the new lease term, which is February 1, 2016, OG&E has the option to either purchase the railcars at a stipulated fair market value or renew the lease. If OG&E chooses not to purchase the railcars or renew the lease agreement and the actual fair value of the railcars is less than the stipulated fair market value, OG&E would be responsible for the difference in those values up to a maximum of $22.8 million. OG&E is also required to maintain all of the railcars it has under the operating lease and has entered into an agreement with a non-affiliated company to furnish this maintenance. On January 11, 2012, OG&E executed a five-year lease agreement for 135 railcars to replace railcars that have been taken out of service or destroyed. OG&E has a unilateral right to terminate this lease upon a 6-month notice effective April 2015 and April 2016. Liquidity and Capital Resources Working Capital Working capital is defined as the amount by which current assets exceed current liabilities. OG&E's working capital requirements are driven generally by changes in accounts receivable, accounts payable, commodity prices, credit extended to, and the timing of collections from, customers, the level and timing of spending for maintenance and expansion activity, inventory levels and fuel recoveries. The balance of Accounts Receivable, Net and Accrued Unbilled Revenues was $238.1 million and $218.9 million at December 31, 2013 and 2012, respectively, an increase of $19.2 million, or 8.8 percent, primarily due to higher transmission revenue, an increase in billings for reimbursable construction costs and an increase in billings to partners of jointly-owned power plants. The balance of Accounts Payable was $239.0 million and $187.4 million at December 31, 2013 and 2012, respectively, an increase of $51.6 million, or 27.5 percent, primarily due to the timing of vendor payments and an increase in accruals. Cash Flows 2013 vs. 2012 2012 vs. 2011 Year ended December 31 (In 2013 2012 % Change $ Change % Change millions) 2011 $ Change Net cash provided from operating $ 545.1 $ 737.4 $ 549.3 $ (192.3 ) (26.1 )% $ 188.1 34.2 % activities Net cash used in investing (796.8 ) (676.3 ) (794.3 ) (120.5 ) (17.8 )% 118.0 (14.9 )% activities Net cash provided from (used in) 251.7 (61.1 ) 245.0 312.8 * (306.1 ) * financing activities * Percentage is greater than 100 percent. Operating Activities The decrease of $192.3 million, or 26.1 percent, in net cash provided from operating activities in 2013 as compared to 2012 was primarily due to fuel refunds in 2013 as compared to higher fuel recoveries in 2012. The increase of $188.1 million, or 34.2 percent, in net cash provided from operating activities in 2012 as compared to 2011 was primarily due to: • higher fuel recoveries in 2012 as compared to 2011; and • an increase in cash received in 2012 from transmission revenue and the recovery of investments including the Crossroads wind farm and smart grid partially offset by milder weather in 2012. 31--------------------------------------------------------------------------------Investing Activities The increase of $120.5 million, or 17.8 percent, in net cash used in investing activities in 2013 as compared to 2012 was primarily due to increased capital expenditures in 2013 related to various transmission projects. The decrease of $118.0 million, or 14.9 percent, in net cash used in investing activities in 2012 as compared to 2011 primarily related to lower levels of capital expenditures in 2012 related to the Crossroads wind farm. Financing Activities The increase of $312.8 million in net cash provided from financing activities in 2013 as compared to 2012 was primarily due to: • proceeds received from the issuance of long-term debt in May 2013; and • an increase in net advances with OGE Energy 2013. These increases in net cash provided from financing activities were partially offset by dividends payments in 2013. The decrease of $306.1 million in net cash provided from financing activities in 2012 as compared to 2011 was primarily due to: • proceeds received from the issuance of long-term debt during 2011; and • dividend payments in 2012; and • a capital contribution from OGE Energy during 2011. These decrease in net cash provided from financing activities were partially offset by an increase in net advances with OGE Energy during 2012. Future Capital Requirements and Financing Activities OG&E's primary needs for capital are related to acquiring or constructing new facilities and replacing or expanding existing facilities. Other working capital requirements are expected to be primarily related to maturing debt, operating lease obligations, fuel clause under and over recoveries and other general corporate purposes. OG&E generally meets its cash needs through a combination of cash generated from operations, short-term borrowings (through a combination of bank borrowings, commercial paper and borrowings from OGE Energy) and permanent financings. 32--------------------------------------------------------------------------------Capital Expenditures OG&E's estimates of capital expenditures for the years 2014 through 2018 are shown in the following table. These capital expenditures represent the base maintenance capital expenditures (i.e., capital expenditures to maintain and operate OG&E's business) plus capital expenditures for known and committed projects. (In millions) 2014 2015 2016 2017 2018 Base Transmission $ 30 $ 30 $ 30 $ 30 $ 30 Base Distribution 175 175 175 175 175 Base Generation 140 75 75 75 75 Other 15 15 15 15 15 Total Base Transmission, Distribution, Generation and Other 360 295 295 295 295 Known and Committed Projects: Transmission Projects: Regionally Allocated Base Projects (A) 55 20 20 20 20 Balanced Portfolio 3E Projects (B)(C) 15 - - - - SPP Priority Projects (B)(C) 75 - - - - SPP Integrated Transmission Projects (B) (C) 15 25 30 25 10 Total Transmission Projects 160 45 50 45 30 Other Projects: Smart Grid Program 25 10 10 - - Environmental - low NOX burners 35 20 15 10 - Environmental - activated carbon injection 5 10 5 - - Total Other Projects 65 40 30 10 - Total Known and Committed Projects 225 85 80 55 30 Total (D) $ 585 $ 380 $ 375 $ 350 $ 325 (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. (C) Projected Estimated Cost In-Service Project Type Project Description (In millions) Date 96 miles of transmission line from OG&E's Woodward District Extra High Voltage substation to the Oklahoma /Texas Stateline to a companion Balance Portfolio transmission line to its Tuco 3E substation $110 Mid-2014 99 miles of transmission line from OG&E's Woodward District Extra High Voltage substation to the western Beaver County line to a companion transmission line to its Hitchland Priority Project substation $165 Mid-2014 77 miles of transmission line from OG&E's Woodward District Extra High Voltage substation to a companion transmission line at the Kansas Priority Project border $140 Late 2014 47 miles of transmission line from Integrated OG&E's Gracemont substation to an Transmission AEP companion transmission line to Project its Elk City substation $45 Early 2018 126 miles of transmission line from OG&E's Woodward District Extra High Voltage substation to OG&E's Integrated Cimarron substation; construction of Transmission the Mathewson substation on this Project transmission line $180 Early 2021 (D) The capital expenditures above exclude any environmental expenditures associated with: • Pollution control equipment related to controlling SO2 emissions under the regional haze requirements due to the uncertainty regarding the approach and timing for such pollution control equipment. The SO2 emissions standards in the EPA's FIP could require the installation of Dry Scrubbers or fuel switching. OG&E estimates that installing such Dry Scrubbers could cost more than $1.0 billion. The FIP is being challenged by OG&E and the state of Oklahoma. On June 22, 2012, OG&E was granted a stay of the FIP by the U.S. Court of Appeals for the Tenth Circuit. 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 33 -------------------------------------------------------------------------------- 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. OG&E is currently evaluating options to comply with environmental requirements. For further information, see "Environmental Laws and Regulations" below. Additional capital expenditures beyond those identified in the table above, including additional incremental growth opportunities in electric transmission assets, will be evaluated based upon their impact upon achieving OG&E's financial objectives. Contractual Obligations The following table summarizes OG&E's contractual obligations at December 31, 2013. See OG&E's Statements of Capitalization and Note 12 of Notes to Financial Statements for additional information. (In millions) 2014 2015-2016 2017-2018 After 2018 Total Maturities of long-term debt (A) $ 0.2 $ 110.4 $ 375.2 $ 1,819.9 $ 2,305.7 Operating lease obligations Railcars 3.8 30.4 - - 34.2 Wind farm land leases 2.1 4.2 4.8 48.8 59.9 Total operating lease obligations 5.9 34.6 4.8 48.8 94.1 Other purchase obligations and commitments Cogeneration capacity and fixed operation and maintenance payments 85.1 164.6 156.6 235.2 641.5 Expected cogeneration energy payments 61.1 136.6 168.9 352.5 719.1 Minimum fuel purchase commitments 451.8 820.3 385.1 - 1,657.2 Expected wind purchase commitments 58.0 118.7 120.3 368.9 665.9 Long-term service agreement commitments 70.5 5.3 21.7 187.9 285.4 Total other purchase obligations and 726.5 1,245.5 852.6 1,144.5 3,969.1 commitments Total contractual obligations 732.6 1,390.5 1,232.6 3,013.2 6,368.9 Amounts recoverable through fuel adjustment (574.7 ) (1,106.0 ) (674.3 ) (721.4 ) (3,076.4 ) clause (B) Total contractual obligations, net $ 157.9 $ 284.5 $ 558.3 $ 2,291.8 $ 3,292.5 (A) Maturities of OG&E's long-term debt during the next five years consist of $0.2 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. OG&E also has 440 MWs of QF contracts to meet its current and future expected customer needs. OG&E will continue reviewing all of the supply alternatives to these QF contracts that minimize the total cost of generation to its customers, including exercising its options (if applicable) to extend these QF contracts at pre-determined rates. The actual cost of fuel used in electric generation (which includes the operating lease obligations for OG&E's railcar leases shown above) and certain purchased power costs are passed through to OG&E's customers through fuel adjustment clauses. Accordingly, while the cost of fuel related to operating leases and the vast majority of minimum fuel purchase commitments 34 -------------------------------------------------------------------------------- of OG&E noted above may increase capital requirements, such costs are recoverable through fuel adjustment clauses and have little, if any, impact on net capital requirements and future contractual obligations. The fuel adjustment clauses are subject to periodic review by the OCC, the APSC and the FERC. Pension and Postretirement Benefit Plans At December 31, 2013, 40.6 percent of the Pension Plan investments were in listed common stocks with the balance primarily invested in U.S Government securities, bonds, debentures and notes, a commingled fund and a common collective trust as presented in Note 11 of Notes to Financial Statements. In 2013, asset returns on the Pension Plan were 12.5 percent due to the gains in fixed income and equity investments. During the same time, corporate bond yields, which are used in determining the discount rate for future pension obligations, increased. During both 2013 and 2012, OGE Energy made contributions to its Pension Plan of $35 million of which none in 2013 and $33 million in 2012 was OG&E's portion, to help ensure that the Pension Plan maintains an adequate funded status. The level of funding is dependent on returns on plan assets and future discount rates. During 2014, OGE Energy expects to contribute up to $26 million to its Pension Plan, of which $1 million is expected to be OG&E's portion. OGE Energy could be required to make additional contributions if the value of its pension trust and postretirement benefit plan trust assets are adversely impacted by a major market disruption in the future. The following table presents the status of OG&E's portion of OGE Energy's Pension Plan, the Restoration of Retirement Income Plan and the postretirement benefit plans at December 31, 2013 and 2012. These amounts have been recorded in Accrued Benefit Obligations with the offset recorded as a regulatory asset in OG&E's Balance Sheet as discussed in Note 1 of Notes to Financial Statements. The regulatory asset represents a net periodic benefit cost to be recognized in the Statements of Income in future periods. Restoration of Retirement Postretirement Pension Plan Income Plan Benefit Plans December 31 (In millions) 2013 2012 2013 2012 2013 2012 Benefit obligations $ (503.6 ) $ (574.6 ) $ (2.1 ) $ (2.2 ) $ (202.4 ) $ (236.4 ) Fair value of plan assets 516.5 519.0 - - 56.7 55.5 Funded status at end of year $ 12.9 $ (55.6 ) $ (2.1 ) $ (2.2 ) $ (145.7 ) $ (180.9 ) In accordance with ASC Topic 715, "Compensation - Retirement Benefits," a one-time settlement charge is required to be recorded by an organization when lump sum payments or other settlements that relieve the organization from the responsibility for the pension benefit obligation during a plan year exceed the service cost and interest cost components of the organization's net periodic pension cost. During 2013, OG&E experienced an increase in both the number of employees electing to retire and the amount of lump sum payments to be paid to such employees upon retirement. As a result, and based in part on OG&E's historical experience regarding eligible employees who elect to retire in the last quarter of a particular year, OG&E recorded pension settlement charges of $17.6 million in the fourth quarter of 2013, of which $17.0 million related to OG&E's Oklahoma jurisdiction and has been included in the pension tracker. The pension settlement charge did not require a cash outlay by OG&E and did not increase OG&E's total pension expense over time, as the charges were an acceleration of costs that otherwise would be recognized as pension expense in future periods. Security Ratings Moody's Standard & Investors Poor's Ratings Services Services Fitch Ratings Senior Notes A1 A- A+ Access to reasonably priced capital is dependent in part on credit and security ratings. Generally, lower ratings lead to higher financing costs. Pricing grids associated with OGE Energy's and OG&E's credit facilities could cause annual fees and borrowing rates to increase if an adverse rating impact occurs. The impact of any future downgrade could include an increase in the costs of OGE Energy's and OG&E's short-term borrowings, but a reduction in OGE Energy's and OG&E's credit ratings would not result in any defaults or accelerations. Any future downgrade of OGE Energy or OG&E could also lead to higher long-term borrowing costs and, if below investment grade, would require OG&E to post collateral or letters of credit. On May 2, 2013, Standard & Poor's Ratings Services upgraded the long-term senior unsecured rating of OG&E to A-. 35 -------------------------------------------------------------------------------- On November 8, 2013, Moody's Investors Services placed the credit ratings of OG&E on review for possible upgrade. On January 31, 2014, Moody's upgraded the long-term senior unsecured rating of OG&E to A1 primarily due to their more favorable view of the relative credit supportiveness of the U.S. regulatory environment. A security rating is not a recommendation to buy, sell or hold securities. Such rating may be subject to revision or withdrawal at any time by the credit rating agency and each rating should be evaluated independently of any other rating. Future financing requirements may be dependent, to varying degrees, upon numerous factors such as general economic conditions, abnormal weather, load growth, commodity prices, acquisitions of other businesses and/or development of projects, actions by rating agencies, inflation, changes in environmental laws or regulations, rate increases or decreases allowed by regulatory agencies, new legislation and market entry of competing electric power generators. 2013 Capital Requirements, Sources of Financing and Financing Activities Total capital requirements, consisting of capital expenditures and maturities of long-term debt, were $797.7 million and contractual obligations, net of recoveries through fuel adjustment clauses, were $89.2 million resulting in total net capital requirements and contractual obligations of $886.9 million in 2013, of which $42.0 million was to comply with environmental regulations. This compares to net capital requirements of $677.0 million and net contractual obligations of $91.3 million totaling $768.3 million in 2012, of which $12.4 million was to comply with environmental regulations. In 2013, OG&E's sources of capital were cash generated from operations and proceeds from the issuance of short-term debt. Changes in working capital reflect the seasonal nature of OG&E's business, the revenue lag between billing and collection from customers and fuel inventories. See "Working Capital" for a discussion of significant changes in net working capital requirements as it pertains to operating cash flow and liquidity. Issuance of Long-Term Debt On May 8, 2013, OG&E issued $250 million of 3.9% senior notes due May 1, 2043. The proceeds from the issuance were added to OG&E's general funds and were used to repay short-term debt, to fund capital expenditures, to pay general corporate expenses and for working capital purposes. Potential Collateral Requirements Derivative instruments are utilized in managing OG&E's commodity price exposures. On July 21, 2010, President Obama signed into law the Dodd-Frank Act. Among other things, the Dodd-Frank Act provides for a new regulatory regime for derivatives, including mandatory clearing of certain swaps and margin requirements. The Dodd-Frank Act contains provisions that should exempt certain derivatives end-users such as OG&E from much of the clearing requirements. The regulations require that the decision on whether to use the end-user exception from mandatory clearing for derivative transactions be reviewed and approved by an "appropriate committee" of the Board of Directors. The scope of the margin requirements and their potential direct impact on OG&E remain unclear because final rules have not been issued. Further, even if OG&E qualifies for the end-user exception to clearing and margin requirements are not imposed on end-users, its derivative counterparties may be subject to new capital, margin and business conduct requirements as a result of the new regulations, which may increase OG&E's transaction costs or make it more difficult to enter into derivative transactions on favorable terms. OG&E's inability to enter into derivative transactions on favorable terms, or at all, could increase operating expenses and put OG&E at increased exposure to risks of adverse changes in commodities prices. The impact of the provisions of the Dodd-Frank Act on OG&E cannot be fully determined at this time due to uncertainty over forthcoming regulations and potential changes to the derivatives markets arising from new regulatory requirements. Future Sources of Financing Management expects that cash generated from operations, proceeds from the issuance of long and short-term debt and funds received from OGE Energy (from proceeds from the sales of its common stock to the public through OGE Energy's Automatic Dividend Reinvestment and Stock Purchase Plan or other offerings) will be adequate over the next three years to meet anticipated cash needs and to fund future growth opportunities. OG&E utilizes short-term borrowings (through a combination of bank borrowings, commercial paper and borrowings from OGE Energy) to satisfy temporary working capital needs and as an interim source of financing capital expenditures until permanent financing is arranged. 36 --------------------------------------------------------------------------------Short-Term Debt and Credit Facility At December 31, 2013 , there were $87.2 million in net outstanding advances from OGE Energy as compared to $90.3 million in net outstanding advances from OGE Energy at December 31, 2012. OG&E has an intercompany borrowing agreement with OGE Energy whereby OG&E has access to up to $400 million of OGE Energy's revolving credit amount. This agreement has a termination date of December 13, 2017. At December 31, 2013, there were no intercompany borrowings under this agreement. OG&E has a $400 million revolving credit facility which is available to back up OG&E's commercial paper borrowings and to provide revolving credit borrowings. This bank facility can also be used as a letter of credit facility. At December 31, 2013, there was $2.1 million supporting letters of credit at a weighted-average interest rate of 0.53 percent. There were no outstanding borrowings under this revolving credit agreement and no outstanding commercial paper borrowings at December 31, 2013. At December 31, 2013, OG&E had $397.9 million of net available liquidity under its revolving credit agreement. OG&E has the necessary regulatory approvals to incur up to $800 million in short-term borrowings at any one time for a two-year period beginning January 1, 2013 and ending December 31, 2014. At December 31, 2013, OG&E had less than $0.1 million in cash and cash equivalents. See Note 10 of Notes to Financial Statements for a discussion of OG&E's short-term debt activity. In December 2011, OG&E entered into an unsecured five-year revolving credit agreement for $400.0 million. This credit facility contains 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, OG&E utilized one of these one-year extensions, and received consent from all of the lenders, to extend the maturity of its credit agreements to December 13, 2017. Expected Issuance of Long-Term Debt OG&E expects to issue up to $250 million of long-term debt during 2014, depending on market conditions, to fund capital expenditures, to repay short or long-term borrowings and for general corporate purposes. Critical Accounting Policies and Estimates The Financial Statements and Notes to Financial Statements contain information that is pertinent to Management's Discussion and Analysis. In preparing the Financial Statements, management is required to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and contingent liabilities at the date of the Financial Statements and the reported amounts of revenues and expenses during the reporting period. Changes to these assumptions and estimates could have a material effect on OG&E's Financial Statements. However, OG&E believes it has taken reasonable positions where assumptions and estimates are used in order to minimize the negative financial impact to OG&E that could result if actual results vary from the assumptions and estimates. In management's opinion, the areas of OG&E where the most significant judgment is exercised includes the determination of Pension Plan assumptions, impairment estimates of long-lived assets (including intangible assets), income taxes, contingency reserves, asset retirement obligations, assets and depreciable lives of property, plant and equipment, the existence of regulatory assets and liabilities and unbilled revenues. The selection, application and disclosure of the following critical accounting estimates have been discussed with OGE Energy's Audit Committee. OG&E discusses its significant accounting policies, including those that do not require management to make difficult, subjective, or complex judgments or estimates, in Note 1 of Notes to Financial Statements. 37 --------------------------------------------------------------------------------Pension and Postretirement Benefit Plans OGE Energy has a Pension Plan that covers a significant amount of OG&E's employees hired before December 1, 2009. Also, effective December 1, 2009, OGE Energy's Pension Plan is no longer being offered to employees hired on or after December 1, 2009. OGE Energy also has defined benefit postretirement plans that cover a significant amount of its employees. Pension and other postretirement plan expenses and liabilities are determined on an actuarial basis and are affected by the market value of plan assets, estimates of the expected return on plan assets, assumed discount rates and the level of funding. Actual changes in the fair market value of plan assets and differences between the actual return on plan assets and the expected return on plan assets could have a material effect on the amount of pension expense ultimately recognized. The pension plan rate assumptions are shown in Note 11 of Notes to Financial Statements. The assumed return on plan assets is based on management's expectation of the long-term return on the plan assets portfolio. The discount rate used to compute the present value of plan liabilities is based generally on rates of high-grade corporate bonds with maturities similar to the average period over which benefits will be paid. The level of funding is dependent on returns on plan assets and future discount rates. Higher returns on plan assets and an increase in discount rates will reduce funding requirements to the Pension Plan. The following table indicates the sensitivity of the Pension Plan funded status to these variables. Change Impact on Funded Status Actual plan asset returns +/- 1 percent +/- $6.5 million Discount rate +/- 0.25 percent +/- $18.3 million Contributions +/- $10 million +/- $10 million Income Taxes OG&E uses the asset and liability method of accounting for income taxes. Under this method, a deferred tax asset or liability is recognized for the estimated future tax effects attributable to temporary differences between the financial statement basis and the tax basis of assets and liabilities as well as tax credit carry forwards and net operating loss carry forwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in the period of the change. The application of income tax law is complex. Laws and regulations in this area are voluminous and often ambiguous. Interpretations and guidance surrounding income tax laws and regulations change over time. Accordingly, it is necessary to make judgments regarding income tax exposure. As a result, changes in these judgments can materially affect amounts OG&E recognized in its financial statements. Tax positions taken by OG&E on its income tax returns that are recognized in the financial statements must satisfy a more likely than not recognition threshold, assuming that the position will be examined by taxing authorities with full knowledge of all relevant information. Commitments and Contingencies In the normal course of business, OG&E is confronted with issues or events that may result in a contingent liability. These generally relate to lawsuits or claims made by third parties, including governmental agencies. When appropriate, management consults with legal counsel and other appropriate experts to assess the claim. If, in management's opinion, OG&E has incurred a probable loss as set forth by GAAP, an estimate is made of the loss and the appropriate accounting entries are reflected in OG&E's Financial Statements. Except as disclosed otherwise in this Form 10-K, OG&E believes that any reasonably possible losses in excess of accrued amounts arising out of pending or threatened lawsuits or claims would not be quantitatively material to its financial statements and would not have a material adverse effect on OG&E's financial position, results of operations or cash flows. See Notes 12 and 13 of Notes to Financial Statements and Item 3 of Part I in this Form 10-K for a discussion of OG&E's commitments and contingencies. Asset Retirement Obligations OG&E has previously recorded asset retirement obligations that are being amortized over their respective lives ranging from 20 to 74 years. The inputs used in the valuation of asset retirement obligations include the assumed life of the asset placed into service, the average inflation rate, market risk premium, the credit-adjusted risk free interest rate and the timing of incurring costs related to the retirement of the asset. 38 --------------------------------------------------------------------------------Hedging Policies From time to time, OG&E may engage in cash flow and fair value hedge transactions to modify interest rate exposure and not to modify the overall leverage of the debt portfolio. Hedges are evaluated prior to execution with respect to the impact on the volatility of forecasted earnings and are evaluated at least quarterly after execution for the impact on earnings. Regulatory Assets and Liabilities OG&E, as a regulated utility, is subject to accounting principles for certain types of rate-regulated activities, which provide that certain actual or anticipated costs that would otherwise be charged to expense can be deferred as regulatory assets, based on the expected recovery from customers in future rates. Likewise, certain actual or anticipated credits that would otherwise reduce expense can be deferred as regulatory liabilities, based on the expected flowback to customers in future rates. Management's expected recovery of deferred costs and flowback of deferred credits generally results from specific decisions by regulators granting such ratemaking treatment. OG&E records certain actual or anticipated costs and obligations as regulatory assets or liabilities if it is probable, based on regulatory orders or other available evidence, that the cost or obligation will be included in amounts allowable for recovery or refund in future rates. The benefit obligations regulatory asset is comprised of expenses recorded which are probable of future recovery and that have not yet been recognized as components of net periodic benefit cost, including net loss, prior service cost and net transition obligation. Unbilled Revenues OG&E reads its customers' meters and sends bills to its customers throughout each month. As a result, there is a significant amount of customers' electricity consumption that has not been billed at the end of each month. Unbilled revenue is presented in Accrued Unbilled Revenues on the Balance Sheets and in Operating Revenues on the Statements of Income based on estimates of usage and prices during the period. At December 31, 2013, if the estimated usage or price used in the unbilled revenue calculation were to increase or decrease by one percent, this would cause a change in the unbilled revenues recognized of $0.3 million. At December 31, 2013 and 2012, Accrued Unbilled Revenues were $58.7 million and $57.4 million, respectively. The estimates that management uses in this calculation could vary from the actual amounts to be paid by customers. Allowance for Uncollectible Accounts Receivable Customer balances are generally written off if not collected within six months after the final billing date. The allowance for uncollectible accounts receivable for OG&E is calculated by multiplying the last six months of electric revenue by the provision rate. The provision rate is based on a 12-month historical average of actual balances written off. To the extent the historical collection rates are not representative of future collections, there could be an effect on the amount of uncollectible expense recognized. Also, a portion of the uncollectible provision related to fuel within the Oklahoma jurisdiction is being recovered through the fuel adjustment clause. At December 31, 2013, if the provision rate were to increase or decrease by 10 percent, this would cause a change in the uncollectible expense recognized of $0.2 million. The allowance for uncollectible accounts receivable is a reduction to Accounts Receivable on the Balance Sheets and is included in Other Operation and Maintenance Expense on the Statements of Income. The allowance for uncollectible accounts receivable was $1.9 million and $2.6 million at December 31, 2013 and 2012, respectively. Accounting Pronouncements See Note 2 of Notes to Financial Statements for discussion of a current accounting pronouncements that is applicable to OG&E. Commitments and Contingencies In the normal course of business, OG&E is confronted with issues or events that may result in a contingent liability. These generally relate to lawsuits or claims made by third parties, including governmental agencies. When appropriate, management consults with legal counsel and other appropriate experts to assess the claim. If, in management's opinion, OG&E has incurred a probable loss as set forth by GAAP, an estimate is made of the loss and the appropriate accounting entries are reflected in OG&E's Financial Statements. At the present time, based on currently available information, except as disclosed otherwise in this Form 10-K, OG&E believes that any reasonably possible losses in excess of accrued amounts arising out of pending or threatened 39 -------------------------------------------------------------------------------- lawsuits or claims would not be quantitatively material to its financial statements and would not have a material adverse effect on OG&E's financial position, results of operations or cash flows. See Notes 12 and 13 of Notes to Financial Statements and Item 3 of Part I in this Form 10-K for a discussion of OG&E's commitments and contingencies. Environmental Laws and Regulations The activities of OG&E are subject to stringent and complex Federal, state and local laws and regulations governing environmental protection relating to air quality, water quality, waste management, wildlife conservation and natural resources. These laws and regulations can restrict or impact business activities in many ways, such as restricting the way it can handle or dispose of its wastes, requiring remedial action to mitigate environmental issues that may be caused by its operations or that are attributable to former operators, requiring changes in operations and requiring the installation and operation of pollution control equipment. Failure to comply with these laws and regulations could result in the assessment of administrative, civil and criminal penalties, the imposition of remedial requirements and the issuance of orders enjoining future operations. Environmental regulation can increase the cost of planning, design, initial installation and operation of OG&E's facilities. Historically, OG&E's total expenditures for environmental control facilities and for remediation have not been significant in relation to its financial position or results of operations. OG&E believes, however, that it is reasonably likely that the trend in environmental legislation and regulations will continue towards more restrictive standards. Compliance with these standards is expected to increase the cost of conducting business. Management continues to evaluate its compliance with existing and proposed environmental legislation and regulations and implement appropriate environmental programs in a competitive market. OG&E expects that environmental capital expenditures necessary to comply with the environmental laws and regulations discussed below will qualify as part of a regulatory plan to handle state and Federally mandated environmental upgrades which will be recoverable in Oklahoma from OG&E's retail customers under House Bill 1910, which was enacted into law in May 2005. It is estimated that OG&E's total expenditures to comply with environmental laws, regulations and requirements for 2014 will be $72.6 million, of which $55.0 million is for capital expenditures. It is estimated that OG&E's total expenditures to comply with environmental laws, regulations and requirements for 2015 will be $49.6 million, of which $31.3 million is for capital expenditures. The amounts above include capital expenditures for low NOX burners and activated carbon injection and exclude certain other capital expenditures as discussed in footnote D to the capital expenditures table in "Future Capital Requirements and Financing Activities" above. Air Federal Clean Air Act Overview OG&E's operations are subject to the Federal Clean Air Act, as amended, and comparable state laws and regulations. These laws and regulations regulate emissions of air pollutants from various industrial sources, including electric generating units, and also impose various monitoring and reporting requirements. Such laws and regulations may require that OG&E obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions or result in the increase of existing air emissions, obtain and strictly comply with air permits containing various emissions and operational limitations or install emission control equipment. OG&E likely will be required to incur certain capital expenditures in the future for air pollution control equipment and technology in connection with obtaining and maintaining operating permits and approvals for air emissions. Regional Haze Control Measures On June 15, 2005, the EPA issued final amendments to its 1999 regional haze rule. Regional haze is visibility impairment caused by the cumulative air pollutant emissions from numerous sources over a wide geographic area. As required by the Federal regional haze rule, the state of Oklahoma evaluated the installation of BART to reduce emissions that cause or contribute to regional haze from certain sources within the state that were built between 1962 and 1977. On February 18, 2010, Oklahoma submitted its SIP to the EPA, which set forth the state's plan for compliance with the Federal regional haze rule. The SIP was subject to the EPA's review and approval. The Oklahoma SIP included requirements for reducing emissions of NOX and SO2 from OG&E's seven BART-eligible units at the Seminole, Muskogee and Sooner generating stations. The SIP also included a waiver from BART requirements for all eligible units at the Horseshoe Lake generating station based on air modeling that showed no significant impact on visibility in nearby national parks and wilderness areas. The SIP concluded that BART for reducing NOX emissions at all of the subject 40 -------------------------------------------------------------------------------- units should be the installation of low NOX burners with overfire air (flue gas recirculation was also required on two of the units) and set forth associated NOX emission rates and limits. OG&E preliminarily estimates that the total capital cost of installing and operating these NOX controls on all covered units, based on recent industry experience and past projects, will be approximately $80 million. With respect to SO2 emissions, the SIP included an agreement between the Oklahoma Department of Environmental Quality and OG&E that established BART for SO2 control at the four affected coal-fired units located at OG&E's Sooner and Muskogee generating stations as the continued use of low sulfur coal (along with associated emission rates and limits). The SIP specifically rejected the installation and operation of Dry Scrubbers as BART for SO2 control from these units because the state determined that Dry Scrubbers were not cost effective on these units. On December 28, 2011, the EPA issued a final rule in which it rejected portions of the Oklahoma SIP and issued a FIP in their place. While the EPA accepted Oklahoma's BART determination for NOX in the final rule, it rejected Oklahoma's SO2 BART determination with respect to the four coal-fired units at the Sooner and Muskogee generating stations. The EPA is instead requiring that OG&E meet an SO2 emission rate of 0.06 pounds per MMBtu within five years. OG&E could meet the proposed standard by either installing and operating Dry Scrubbers or fuel switching at the four affected units. OG&E estimates that installing Dry Scrubbers on these units would include capital costs to OG&E of more than $1.0 billion. OG&E and the state of Oklahoma filed an administrative stay request with the EPA on February 24, 2012. The EPA has not yet responded to this request. OG&E and other parties also filed a petition for review of the FIP in the U.S. Court of Appeals for the Tenth Circuit on February 24, 2012 and a stay request on April 4, 2012. On June 22, 2012, the U.S. Court of Appeals for the Tenth Circuit granted the stay request. 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. Cross-State Air Pollution Rule As previously reported, on July 7, 2011, the EPA finalized its Cross-State Air Pollution Rule to replace the former Clean Air Interstate Rule that was remanded by a Federal court as a result of legal challenges. The final rule would require 27 states to reduce power plant emissions that contribute to ozone and particulate matter pollution in other states. On December 27, 2011, the EPA published a supplemental rule, which would make six additional states, including Oklahoma, subject to the Cross-State Air Pollution Rule for NOX emissions during the ozone-season from May 1 through September 30. Under the rule, OG&E would have been required to reduce ozone-season NOX emissions from its electrical generating units within the state beginning in 2012. The Cross-State Air Pollution Rule was challenged in court by numerous states and power generators. On December 30, 2011, the U.S. Court of Appeals issued a stay of the rule, which includes the supplemental rule, pending a decision on the merits. By order dated August 21, 2012, the U.S. Court of Appeals vacated the Cross-State Air Pollution Rule and ordered the EPA to promulgate a replacement rule. On June 24, 2013, the U.S. Supreme Court agreed to review the decision by the U.S. Court of Appeals, with a decision expected during the first half of 2014. OG&E cannot predict the outcome of such challenges. Hazardous Air Pollutants Emission Standards On April 16, 2012, regulations governing emissions of certain hazardous air pollutants from electric generating units were published as the final MATS rule. This rule includes numerical standards for particulate matter (as a surrogate for toxic metals), hydrogen chloride and mercury emissions from coal-fired boilers. In addition, the regulations include work practice standards for dioxins and furans. Compliance with the MATS rule is required within three years after the effective date of the rule with the possibility of a one-year extension. OG&E requested and was granted a one-year extension by the Oklahoma Department of Environmental Quality resulting in a compliance date of April 16, 2016 for OG&E. To comply with this rule, OG&E is currently planning to utilize activated carbon injection for the removal of mercury at each of its five coal-fired units, the capital costs of which are estimated to be approximately $20 million over a three year period and are included in the capital expenditures table in "Future Capital Requirements and Financing Activities" above. 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. OG&E is evaluating the results of field testing to finalize its plans and cost estimates. The final MATS rule has been appealed by several parties. OG&E is not a party to the appeals and cannot predict the outcome of any such appeals. 41 -------------------------------------------------------------------------------- Federal Clean Air Act New Source Review Litigation As previously reported, in July 2008, OG&E received a request for information from the EPA regarding Federal Clean Air Act compliance at OG&E's Muskogee and Sooner generating plants. In recent years, the EPA has issued similar requests to numerous other electric utilities seeking to determine whether various maintenance, repair and replacement projects should have required permits under the Federal Clean Air Act's new source review process. In January 2012, OG&E received a supplemental request for an update of the previously provided information and for some additional information not previously requested. On May 1, 2012, OG&E responded to the EPA's supplemental request for information. On April 26, 2011, the EPA issued a notice of violation alleging that 13 projects occurred at OG&E's Muskogee and Sooner generating plants between 1993 and 2006 without the required new source review permits. The notice of violation also alleges that OG&E's visible emissions at its Muskogee and Sooner generating plants are not in accordance with applicable new source performance standards. In March 2013, the DOJ informed OG&E that it was prepared to initiate enforcement litigation concerning the matters identified in the notice of violation. OG&E subsequently met with EPA and DOJ representatives regarding the notice of violation and proposals for resolving the matter without litigation. On July 8, 2013, the United States, at the request of the EPA, filed a complaint for declaratory relief against OG&E in United States District Court for the Western District of Oklahoma (Case No. CIV-13-690-D) alleging that OG&E did not follow the Federal Clean Air Act procedures for projecting emission increases attributable to eight projects that occurred between 2003 and 2006. This complaint seeks to have OG&E submit a new assessment of whether the projects were likely to result in a significant emissions increase. The Sierra Club has intervened in this proceeding and has asserted claims for declaratory relief that are similar to those requested by the United States. OG&E expects to vigorously defend against these claims, but OG&E cannot predict the outcome of such litigation. On August 12, 2013, the Sierra Club filed a complaint against OG&E in the United States District Court for the Eastern District of Oklahoma (Case No. 13-CV-00356) alleging that OG&E modifications made at Unit 6 of the Muskogee generating plant in 2008 were made without obtaining a prevention of significant deterioration permit and that the plant has exceeded emissions limits for opacity and particulate matter. The Sierra Club seeks a permanent injunction preventing OG&E from operating the Muskogee generating plant. At this time, OG&E continues to believe that it has acted in compliance with the Federal Clean Air Act. If OG&E does not prevail in these proceedings and if a new assessment of the projects were to conclude that they caused a significant emissions increase, the EPA and the Sierra Club could seek to require OG&E to install additional pollution control equipment, including scrubbers, baghouses and selective catalytic reduction systems with capital costs in excess of $1.0 billion and pay fines and significant penalties as a result of the allegations in the notice of violation. Section 113 of the Federal Clean Air Act (along with the Federal Civil Penalties Inflation Adjustment Act of 1996) provides for civil penalties as much as $37,500 per day for each violation. The cost of any required pollution control equipment could also be significant. OG&E cannot predict at this time whether it will be legally required to incur any of these costs. National Ambient Air Quality Standards The EPA is required to set NAAQS for certain pollutants considered to be harmful to public health or the environment. The Clean Air Act requires the EPA to review each NAAQS every five years. As a result of these reviews, the EPA periodically has taken action to adopt more stringent NAAQS for those pollutants. If any areas of Oklahoma were to be designated as not attaining the NAAQS for a particular pollutant, OG&E could be required to install additional emission controls on its facilities to help the state achieve attainment with the NAAQS. As of the end of 2013, no areas of Oklahoma had been designated as non-attainment for pollutants that are likely to affect OG&E's operations. Several processes are under way to designate areas in Oklahoma as attaining or not attaining revised NAAQS. OG&E is monitoring those processes and their possible impact on its operations but, at this time, cannot determine with any certainty whether they will cause a material impact to OG&E's financial results. Acid Rain Program The Federal Clean Air Act includes an Acid Rain Program. The goal of the Acid Rain Program is to achieve environmental and public health benefits through reductions in SO2 and NOX emissions, which are the primary causes of acid rain. To achieve this goal, the program employs both traditional and market-based approaches for reducing emissions. The Acid Rain Program introduces an allowance trading system that uses the free market to reduce emissions. Under this system, affected utility units are allocated allowances based on their historic fuel consumption and a specific emissions rate. Each allowance permits a unit to emit one ton of SO2 during or after a specified year. For each ton of SO2 emitted in a given year, one allowance is retired, that is, it can no longer be used. Allowances may be bought, sold or banked. 42 -------------------------------------------------------------------------------- During Phase II of the program (now in effect), the Federal Clean Air Act set a permanent ceiling (or cap) of 8.95 million total annual allowances allocated to utilities. This cap firmly restricts emissions and ensures that environmental benefits will be achieved and maintained. Due to OG&E's earlier decision to burn low sulfur coal, these restrictions have had no significant financial impact. The Acid Rain Program also focuses on one set of sources that emit NOX, coal-fired electric utility boilers. As with the SO2 emission reduction requirements, the NOX program was implemented in two phases, beginning in 1996 and 2000. The NOX program embodies many of the same principles of the SO2 trading program. However, it does not cap NOX emissions as the SO2 program does, nor does it utilize an allowance trading system. Emission limitations for NOX focus on the emission rate to be achieved (expressed in pounds of NOX per MMBtu of heat input). In general, two options for compliance with the emission limitations are provided: compliance with an individual emission rate for a boiler; or averaging of emission rates over two or more units to meet an overall emission rate limitation. Since becoming subject to the Acid Rain Program, OG&E has met all obligations and limitations requirements. Climate Change and Greenhouse Gas Emissions There is continuing discussion and evaluation of possible global climate change in certain regulatory and legislative arenas. The focus is generally on emissions of greenhouse gases, including carbon dioxide, sulfur hexafluoride and methane, and whether these emissions are contributing to the warming of the Earth's atmosphere. There are various international agreements that restrict greenhouse gas emissions, but none of them have a binding effect on sources located in the United States. The U.S. Congress has not passed legislation to reduce emissions of greenhouse gases and the future prospects for any such legislation are uncertain, but the EPA believes it has existing authority under the Clean Air Act to regulate greenhouse gas emissions from stationary sources. Several states have passed laws, adopted regulations or undertaken regulatory initiatives to reduce the emission of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. Oklahoma and Arkansas are not among them. If legislation or regulations are passed at the Federal or state levels in the future requiring mandatory reductions of carbon dioxide and other greenhouse gases on OG&E's facilities, this could result in significant additional compliance costs that would affect OG&E's future financial position, results of operations and cash flows if such costs are not recovered through regulated rates. In 2009, the EPA adopted a comprehensive national system for reporting emissions of carbon dioxide and other greenhouse gases produced by major sources in the United States. The reporting requirements apply to large direct emitters of greenhouse gases with emissions equal to or greater than a threshold of 25,000 metric tons per year, which includes certain OG&E facilities. OG&E also reports quarterly its carbon dioxide emissions from generating units subject to the Federal Acid Rain Program. OG&E has submitted the reports required by the applicable reporting rules. Following from the Supreme Court's interpretation of the Clean Air Act's applicability to greenhouse gases in Massachusetts v. EPA, the EPA has proposed regulations for new power plants. In 2010, the EPA also issued a final rule that makes certain existing sources subject to permitting requirements for greenhouse gas emissions. This rule requires sources that emit greater than 100,000 tons per year of greenhouse gases to obtain a permit for those emissions, even if they are not otherwise required to obtain a new or modified permit. Such sources that undergo construction or modification may have to install best available control technology to control greenhouse gas emissions. Although these rules currently do not have a material impact on OG&E's existing facilities, they ultimately could result in significant changes to OG&E's operations, significant capital expenditures by OG&E and a significant increase in OG&E's cost of conducting business. In October 2013, the U.S. Supreme Court granted certiorari to review EPA's greenhouse gas regulations, including the Tailoring Rule which limits the sources subject to greenhouse gas permitting requirements to the largest fossil-fueled power plants. It is conceivable that the Court could invalidate EPA's prevention of significant deterioration and Title V Tailoring Rule, but still leave power plants subject to anticipated new and existing source performance standards for greenhouse gas emissions described below. In January 2014, the EPA issued new proposed New Source Performance Standards that specify permissible levels of greenhouse gas emissions from newly-constructed fossil fuel-fired electric generating units. The proposed New Source Performance Standards sets separate standards for natural gas combined cycle units and coal-fired generating units. As directed by President Obama's June 25, 2013, Climate Action Plan, the EPA also announced plans to establish, pursuant to Section 111(d) of the Clean Air Act, carbon dioxide emissions standards for existing fossil fuel fired electric generating units. EPA plans to publish the proposed standards for existing units by June 1, 2014, and finalize those guidelines by June 1, 2015. States must then submit their individual plans for reducing power plants' greenhouse gas emissions to EPA by June 30, 2016. 43 --------------------------------------------------------------------------------OG&E is continuing to review and evaluate available options for reducing, avoiding, offsetting or sequestering its greenhouse gas emissions. OG&E also seeks to utilize renewable energy sources that do not emit greenhouse gases. OG&E's service territory is in central Oklahoma and borders one of the nation's best wind resource areas. OG&E has leveraged its advantageous geographic position to develop renewable energy resources and transmission to deliver the renewable energy. The SPP has begun to authorize the construction of transmission lines capable of bringing renewable energy out of the wind resource area in western Oklahoma, the Texas Panhandle and western Kansas to load centers by planning for more transmission to be built in the area. In addition to significantly increasing overall system reliability, these new transmission resources should provide greater access to additional wind resources that are currently constrained due to existing transmission delivery limitations. Endangered Species Certain Federal laws, including the Bald and Golden Eagle Protection Act, the Migratory Bird Treaty Act and the Endangered Species Act, provide special protection to certain designated species. These laws and any state equivalents provide for significant civil and criminal penalties for unpermitted activities that result in harm to or harassment of certain protected animals and plants, including damage to their habitats. If such species are located in an area in which OG&E conducts operations, or if additional species in those areas become subject to protection, OG&E's operations and development projects, particularly transmission or wind projects, could be restricted or delayed, or OG&E could be required to implement expensive mitigation measures. The U.S. Fish and Wildlife Service announced a proposed rule to list the lesser prairie chicken as threatened on November 30, 2012. A final decision regarding listing is anticipated to be completed by March 30, 2014. Although the lesser prairie chicken and its habitat are located in potential development areas of OG&E, the impact of a final decision to list this species as threatened cannot be determined at this time. Waste OG&E's operations generate wastes that are subject to the Federal Resource Conservation and Recovery Act of 1976 as well as comparable state laws which impose detailed requirements for the handling, storage, treatment and disposal of waste. For OG&E, these laws impose strict requirements on waste generators regarding their treatment, storage and disposal of waste. OG&E routinely generates small quantities of hazardous waste throughout its system. These wastes are treated, stored and disposed at facilities that are permitted to manage them. In June 2010, the EPA proposed new rules under Federal Resource Conservation and Recovery Act of 1976 that could make the management of coal ash more costly. The extent to which the EPA intends to regulate coal ash is uncertain. The EPA continues to consider numerous comments received on the proposal. On January 29, 2014, the EPA entered into a consent decree directing them, by December 19, 2014, to sign for publication in the Federal Register a notice taking final action on the EPA's proposed Subtitle D option for coal ash which set performance standards for waste management, to be administered by the states. OG&E has sought and will continue to seek pollution prevention opportunities and to evaluate the effectiveness of its waste reduction, reuse and recycling efforts. In 2013, OG&E obtained refunds of $3.5 million from the recycling of scrap metal, salvaged transformers and used transformer oil. This figure does not include the additional savings gained through the reduction and/or avoidance of disposal costs and the reduction in material purchases due to the reuse of existing materials. Similar savings are anticipated in future years. Water OG&E's operations are subject to the Federal Clean Water Act, and analogous state laws and regulations. These laws and regulations impose detailed requirements and strict controls regarding the discharge of pollutants into state and Federal waters. The discharge of pollutants, including discharges resulting from a spill or leak, is prohibited unless authorized by a permit or other agency approval. The Federal Clean Water Act and regulations implemented thereunder also prohibit discharges of dredged and fill material in wetlands and other waters of the United States unless authorized by an appropriately issued permit. Existing cooling water intake structures are regulated under the Federal Clean Water Act to minimize their impact on the environment. With respect to cooling water intake structures, Section 316(b) of the Federal Clean Water Act requires that their location, design, construction and capacity reflect the best available technology for minimizing their adverse environmental impact via the impingement and entrainment of aquatic organisms. In March 2011, the EPA proposed rules to implement Section 316(b). Recently, the EPA announced that it will issue a final rule by April 17, 2014. In the interim, the state of Oklahoma requires OG&E to implement best management practices related to the operation and maintenance of its existing cooling water intake structures as 44 -------------------------------------------------------------------------------- a condition of renewing its discharge permits. Once the EPA promulgates the final rules, OG&E may incur additional capital and/or operating costs to comply with them. The costs of complying with the final water intake standards are not currently determinable, but could be significant. Site Remediation The Comprehensive Environmental Response, Compensation and Liability Act of 1980 and comparable state laws impose liability, without regard to the legality of the original conduct, on certain classes of persons responsible for the release of hazardous substances into the environment. Because OG&E utilizes various products and generate wastes that are considered hazardous substances for purposes of the Comprehensive Environmental Response, Compensation and Liability Act of 1980, OG&E could be subject to liability for the costs of cleaning up and restoring sites where those substances have been released to the environment. At this time, it is not anticipated that any associated liability will cause a significant impact to OG&E. For a further discussion regarding contingencies relating to environmental laws and regulations, see Note 12 of Notes to Financial Statements. |