Item 1. Business.
Introduction
OG&E generates, transmits, distributes and sells electric energy in Oklahoma and western Arkansas. Its operations are conducted through OG&E and are subject to regulation by the OCC, the APSC and the FERC. OG&E is a wholly-owned subsidiary of OGE Energy which is an energy and energy services provider offering physical delivery and related services for both electricity and natural gas primarily in the south central United States. 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's principal executive offices are located at 321 North Harvey, P.O. Box 321, Oklahoma City, Oklahoma 73101-0321; telephone 405-553-3000.
OG&E Strategy
OGE Energy's mission is to fulfill its critical role in the nation's electric utility and natural gas midstream pipeline infrastructure and meet individual customers' needs for energy and related services in a safe, reliable and efficient manner. 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 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 and promote demand-side management programs. 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. 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. OG&E is customer focused and strives to provide excellent customer service.
General
The electric utility segment generates, transmits, distributes and sells electric energy in Oklahoma and western Arkansas. Its operations are conducted through OG&E. OG&E furnishes retail electric service in 268 communities and their contiguous rural and suburban areas. At December 31, 2011, two other communities and two rural electric cooperatives in Oklahoma and western Arkansas purchased electricity from OG&E for resale. The service area covers 30,000 square miles in Oklahoma and western Arkansas, including Oklahoma City, the largest city in Oklahoma, and Fort Smith, Arkansas, the second largest city in that state. Of the 268 communities that OG&E serves, 242 are located in Oklahoma and 26 in Arkansas. OG&E derived 90 percent of its total electric operating revenues in 2011 from sales in Oklahoma and the remainder from sales in Arkansas.
OG&E's system control area peak demand in 2011 was 7,057 MWs on August 3, 2011. OG&E's load responsibility peak demand was 6,513 MWs on August 3, 2011. As reflected in the table below and in the operating statistics that follow, there were 28.5 million MWH system sales in 2011, 27.6 million MWH system sales in 2010 and 25.9 million MWH system sales in 2009. Variations in system sales for the three years are reflected in the following table:
OG&E is subject to competition in various degrees from government-owned electric systems, municipally-owned electric systems, rural electric cooperatives and, in certain respects, from other private utilities, power marketers and cogenerators. Oklahoma law forbids the granting of an exclusive franchise to a utility for providing electricity.
Besides competition from other suppliers or marketers of electricity, OG&E competes with suppliers of other forms of energy. The degree of competition between suppliers may vary depending on relative costs and supplies of other forms of energy.
Regulation and Rates
OG&E's retail electric tariffs are regulated by the OCC in Oklahoma and by the APSC in Arkansas. The issuance of certain securities by OG&E is also regulated by the OCC and the APSC. OG&E's wholesale electric tariffs, transmission activities, short-term borrowing authorization and accounting practices are subject to the jurisdiction of the FERC. The Secretary of the U.S. Department of Energy has jurisdiction over some of OG&E's facilities and operations. In 2011, 89 percent of OG&E's electric revenue was subject to the jurisdiction of the OCC, eight percent to the APSC and three percent to the FERC.
The OCC issued an order in 1996 authorizing OG&E to reorganize into a subsidiary of OGE Energy. The order required that, among other things, (i) OGE Energy permit the OCC access to the books and records of OGE Energy and its affiliates relating to transactions with OG&E, (ii) OGE Energy employ accounting and other procedures and controls to protect against subsidization of non-utility activities by OG&E's customers and (iii) OGE Energy refrain from pledging OG&E assets or income for affiliate transactions. In addition, the Energy Policy Act of 2005 enacted the Public Utility Holding Company Act of 2005, which in turn granted to the FERC access to the books and records of OGE Energy and its affiliates as the FERC deems relevant to costs incurred by OG&E or necessary or appropriate for the protection of utility customers with respect to the FERC jurisdictional rates.
Completed Regulatory Matters
Wholesale Agreement
On May 28, 2009, OG&E sent a termination notice to the Arkansas Valley Electric Cooperative that OG&E would terminate its wholesale power agreement to all points of delivery where OG&E sells or has sold power to the Arkansas Valley Electric Cooperative, effective November 30, 2011. In December 2010, OG&E and the Arkansas Valley Electric Cooperative entered into a new wholesale power agreement whereby OG&E will supply wholesale power to the Arkansas Valley Electric Cooperative through June 2015. On January 3, 2011, OG&E submitted this agreement to the FERC for approval. The FERC approved the new wholesale power agreement on March 2, 2011 and the new contract was effective May 1, 2011.
Crossroads Wind Farm
On July 29, 2010, OG&E received an order from the OCC authorizing OG&E to recover from Oklahoma customers the cost to construct Crossroads, with the rider being implemented as the individual turbines are placed in service. The Crossroads wind farm was fully in service in January 2012. As part of this project, on June 16, 2011, OG&E entered into an interconnection agreement with the SPP for Crossroads which allowed Crossroads to interconnect at 227.5 MWs.
2010 Arkansas Rate Case Filing
On September 28, 2010, OG&E filed a rate case with the APSC requesting an annual rate increase of $17.7 million, to recover the cost of significant electric system expansions and upgrades, including high-voltage transmission lines, that have been completed since the last rate filing in August 2008, as well as increased operating costs. OG&E also sought recovery, through a rider, of the Arkansas jurisdictional portion of (i) costs associated with transmission upgrades and facilities that have been approved by the SPP in its regional planning processes and constructed by other non-OG&E transmission owners throughout the SPP that have been allocated to OG&E through the FERC-approved transmission rates and (ii) SPP administrative fees. On June 17, 2011, the APSC approved a settlement agreement among all parties to the case and OG&E implemented new electric rates effective June 20, 2011. Key items of the APSC order include: (i) the recovery of and a return on significant electric system expansions and upgrades, including high-voltage transmission lines, as well as increased operating costs, totaling $8.8 million annually; (ii) authorization for OG&E to recover the actual cost of third-party transmission charges and SPP administrative fees through a rider mechanism which will remain in effect until new rates are implemented after OG&E's next general rate case (the Arkansas jurisdictional portion of the combined costs was $1.0 million in 2011); and (iii) the deferral of certain expenses associated with a customer education program in an amount not to exceed $0.3 million per year for a maximum of two years.
SPP Cost Tracker
On October 7, 2010, OG&E filed an application with the OCC seeking recovery of the Oklahoma jurisdictional portion of (i) costs associated with transmission upgrades and facilities that have been approved by the SPP in its regional planning processes and constructed by other non-OG&E transmission owners throughout the SPP that have been allocated to OG&E through the FERC-approved transmission rates and (ii) SPP administrative fees. OG&E requested authorization to implement a cost tracker in order to recover from its retail customers the third-party project costs discussed above and to collect its administrative SPP cost assessment levied under Schedule 1A of the SPP open access transmission tariff, which is currently recovered in base rates. OG&E also requested authorization to establish a regulatory asset effective January 1, 2011 in order to give OG&E the opportunity to
recover such costs that will be paid but not recovered until the cost tracker is made effective. On February 8, 2011, all parties signed a settlement agreement in this matter which would allow OG&E to recover the costs discussed in (i) above through a recovery rider effective January 1, 2011. OG&E recovered $5.1 million of incremental revenues in 2011 through the rider. Rather than including the costs of the SPP administrative fee assessment in the recovery rider, the stipulating parties agreed to allow OG&E to include the projected 2012 level of the SPP administrative fee assessment in its next Oklahoma rate case which was filed in August 2011. Pursuant to the settlement agreement in OG&E's 2011 Oklahoma general rate case filing, OG&E proposed that recovery in base rates for the costs of transmission projects it constructs and owns and that are authorized by the SPP in its regional planning processes should be limited to the Oklahoma retail jurisdictional share of the costs for such projects allocated to OG&E by the SPP. On March 28, 2011, the OCC issued an order in this matter approving the settlement agreement.
Fuel Adjustment Clause Review for Calendar Year 2009
On October 29, 2010, the OCC Staff filed an application for a public hearing to review and monitor OG&E's application of the 2009 fuel adjustment clause. On December 28, 2010, OG&E responded by filing the necessary information and documents to satisfy the OCC's minimum filing requirement rules. An intervenor representing a group of OG&E's industrial customers filed testimony on March 11, 2011 seeking a $15.5 million refund related to (i) a purported failure by OG&E to maximize the use of its coal-fired power plants and (ii) an inappropriate extension of the existing gas transportation and storage contract between OG&E and Enogex. OG&E filed rebuttal testimony on April 4, 2011 in opposition to the claims of the intervenor. On August 11, 2011, all parties to this case signed a settlement agreement in this matter, stating that (i) OG&E was prudent in its operations during 2009; (ii) a third party expert should be hired to evaluate OG&E's future gas transportation and storage needs and that OG&E should file a plan for meeting its future gas transportation and storage needs by mid-2012; and (iii) with respect to the existing gas transportation and storage contract with Enogex, OG&E will return $8.4 million to its customers in settlement for all periods under the contract through April 30, 2013. In August 2011, OG&E credited $4.9 million to its customers and will credit the remaining amount on a monthly basis through April 30, 2013. The OCC issued an order approving the settlement agreement on August 29, 2011.
Smart Grid Project
On December 17, 2010, OG&E filed an application with the APSC requesting pre-approval for system-wide deployment of smart grid technology and a recovery rider, including a credit for the Smart Grid grant awarded by the U.S. Department of Energy under the American Recovery and Reinvestment Act of 2009. On June 22, 2011, OG&E reached a settlement agreement with all the parties in this matter. OG&E and the other parties in this matter agreed to ask the APSC to approve the settlement agreement including the following: (i) pre-approval of system-wide deployment of smart grid technology in Arkansas and authorization for OG&E to begin recovering the prudently incurred costs of the Arkansas system-wide deployment of smart grid technology through a rider mechanism that will become effective in accordance with the order approving the settlement agreement; (ii) cost recovery through the rider would commence when all of the smart meters to be deployed in Arkansas are in service; (iii) OG&E guarantees that customers will receive certain operations and maintenance cost reductions resulting from the smart grid deployment as a credit to the recovery rider; and (iv) the stranded costs associated with OG&E's existing meters which are being replaced by smart meters will be accumulated in a regulatory asset and recovered in base rates beginning after an order is issued in OG&E's next general rate case. OG&E currently expects to spend $14 million, net of funds from the U.S. Department of Energy grant, in capital expenditures to implement smart grid in Arkansas pursuant to the settlement agreement. On August 3, 2011, the APSC issued an order in this matter approving the settlement agreement.
FERC Transmission Rate Incentive Filing
On February 18, 2011, OG&E submitted to the FERC a request seeking limited transmission rate incentives for five transmission projects. OG&E requested recovery of 100 percent of all prudently incurred construction work in progress in rate base for five 345 kilovolt Extra High Voltage transmission projects to be constructed and owned by OG&E within the SPP's region. OG&E also requested to recover 100 percent of all prudently incurred development and construction costs if the transmission projects are abandoned or cancelled, in whole or in part, for reasons beyond OG&E's control. On April 19, 2011, the FERC granted these incentives for the Sooner-Rose Hill, Sunnyside-Hugo and Balanced Portfolio 3E transmission projects discussed below.
Pension Tracker Modification Filing
On February 22, 2011, OG&E filed an application with the OCC requesting that OG&E's pension tracker be modified to include the difference between the level of retiree medical costs authorized in OG&E's last rate case and the current level of these expenses as a regulatory liability, effective January 1, 2011. On June 23, 2011, a settlement agreement was filed by parties in the case stating that the pension tracker should be modified as proposed by OG&E and that the level of retiree medical costs included in base rates will be reviewed and determined in OG&E's next rate case. On September 27, 2011, the OCC issued an
order in this matter approving the settlement agreement.
Demand and Energy Efficiency Program Filing
To build on the success of its earlier programs and further promote energy efficiency and conservation for each class of OG&E customers, on March 15, 2011, OG&E filed an application with the APSC seeking approval of several programs, ranging from residential weatherization to commercial lighting. In seeking approval of these programs, OG&E also sought recovery of the program and related costs through a rider that would be added to customers' electric bills. On June 30, 2011, the APSC issued an order approving OG&E's energy efficiency plan for 2011 and approving OG&E's energy efficiency cost recovery rider for 2011. In Arkansas, OG&E's program is expected to cost $7.0 million over a three-year period and is expected to increase the average residential electric bill by $1.47 per month.
FERC Order No. 1000, Final Rule on Transmission Planning and Cost Allocation
On July 21, 2011, the FERC issued Order No. 1000, which revised the FERC's existing regulations governing the process for planning enhancements and expansions of the electric transmission grid in a particular region, along with the corresponding process for allocating the costs of such expansions. Order No. 1000 applies only to "new transmission facilities," which are described as those subject to evaluation or reevaluation (under the applicable local or regional transmission planning process) subsequent to the effective date of the regulatory compliance filings required by the rule, which are expected to be filed during the third quarter of 2012. Order No. 1000 leaves to individual regions to determine whether a previously-approved project is subject to reevaluation and is therefore governed by the new rule.
Order No. 1000 requires, among other things, public utility transmission providers, such as the SPP, to participate in a process that produces a regional transmission plan satisfying certain standards, and requires that each such regional process consider transmission needs driven by public policy requirements (such as state or Federal policies favoring increased use of renewable energy resources). Order No. 1000 also directs public utility transmission providers to coordinate with neighboring transmission planning regions. In addition, Order No. 1000 establishes specific regional cost allocation principles and directs public utility transmission providers to participate in regional and interregional transmission planning processes that satisfy these principles.
On the issue of determining how entities are to be selected to develop and construct the specific transmission projects, Order No. 1000 directs public utility transmission providers to remove from the FERC-jurisdictional tariffs and agreements provisions that establish any federal "right of first refusal" for the incumbent transmission owner (such as OG&E) regarding transmission facilities selected in a regional transmission planning process, subject to certain limitations. However, Order No. 1000 is not intended to affect the right of an incumbent transmission owner (such as OG&E) to build, own and recover costs for upgrades to its own transmission facilities, and Order No. 1000 does not alter an incumbent transmission owner's use and control of existing rights of way. Order No. 1000 also clarifies that incumbent transmission owners may rely on regional transmission facilities to meet their reliability needs or service obligations. The SPP currently has a "right of first refusal" for incumbent transmission owners and this provision has played a role in OG&E being selected by the SPP to build various transmission projects in Oklahoma.
OGE Energy is continuing to evaluate Order No. 1000 and cannot at this time determine its precise impact on OG&E. Nevertheless, at the present time, OGE Energy has no reason to believe that the implementation of Order No. 1000 will impact OG&E's transmission projects currently under development and construction for which OG&E has received a notice to proceed from the SPP.
Pending Regulatory Matters
2011 Oklahoma Rate Case Filing
As part of the Joint Stipulation and Settlement Agreement reached in OG&E's 2009 Oklahoma rate case filing, the parties agreed that OG&E would file a rate case on or before June 30, 2011. On May 27, 2011, OG&E requested an extension until the end of July 2011 for filing the Oklahoma rate case. On July 28, 2011, OG&E filed its application with the OCC requesting an annual rate increase of $73.3 million, or a 4.3 percent increase in its rates. OG&E is requesting a return on equity of 11.00 percent based on a common equity percentage of 53 percent. Each 0.10 percent change in the requested return on equity affects the requested rate increase by $3.0 million. In its application, OG&E seeks to recover increases in its operating costs and to begin earning on approximately $500 million of new capital investments made on behalf of its Oklahoma customers during the previous two and one-half years. On November 9, 2011, the OCC Staff recommended a $6.2 million annual rate decrease based on a return on equity of 9.81 percent and a common equity percentage of 53 percent. The staff of the Oklahoma Attorney General recommended a return on equity of 9.818 percent and a common equity percentage of 49.5 percent. The staff of the Oklahoma Attorney General
did not recommend a specific revenue requirement, but OG&E believes that adoption of the staff of the Oklahoma Attorney General's recommendations would result in a rate decrease. The Oklahoma Industrial Electric Consumers recommended a $56 million annual rate decrease based on a return on equity of 9.5 percent and a common equity percentage of 48 percent. OG&E filed rebuttal testimony on November 29, 2011 on the revenue requirement testimony filed by the parties on November 9, 2011. On November 16, 2011, the parties filed cost-of-service and rate design testimony and OG&E filed rebuttal testimony in those areas on December 2, 2011. The hearing in this matter began on December 13, 2011. OG&E expects to receive an order from the OCC in the first quarter of 2012.
Fuel Adjustment Clause Review for Calendar Year 2010
On August 19, 2011, the OCC Staff filed an application for a public hearing to review and monitor OG&E's application of the 2010 fuel adjustment clause. On October 18, 2011, OG&E responded by filing the necessary information and documents to satisfy the OCC's minimum filing requirement rules. A procedural schedule has not yet been established in this matter.
Contract and Wind Energy Purchase Agreement Filing
On December 1, 2011, OG&E filed an application with the OCC requesting approval of a 20-year agreement that is intended to provide wind power to help meet the current and future power generation needs of Oklahoma State University. The project calls for OG&E to contract with NextEra Energy to build a 60 MW wind farm near Blackwell, Oklahoma, to support the Oklahoma State University project in which NextEra will build, own and operate the wind farm and OG&E will purchase the electric output. A procedural schedule has not yet been established in this matter. OG&E expects to receive a decision from the OCC in the first quarter of 2012.
SPP Transmission/Substation Projects
The SPP is a regional transmission organization under the jurisdiction of the FERC that was created to ensure reliable supplies of power, adequate transmission infrastructure and competitive wholesale prices of electricity. The SPP does not build transmission though the SPP's tariff contains rules that govern the transmission construction process. Transmission owners complete the construction and then own, operate and maintain transmission assets within the SPP region. When the SPP Board of Directors approves a project, the transmission provider in the area where the project is needed currently has the first obligation to build; however, the process for deciding which entity constructs and owns a project may change as a result of FERC Order. No. 1000 discussed above.
There are several studies currently under review at the SPP including a 20-year plan to address issues of regional and interregional importance. The 20-year plan suggests overlaying the SPP footprint with a 345 kilovolt transmission system and integrating it with neighboring regional entities. In 2009, the SPP Board of Directors approved a new report that recommended restructuring the SPP's regional planning processes to focus on the construction of a robust transmission system, large enough in both scale and geography, to provide flexibility to meet the SPP's future needs. OG&E expects to actively participate in the ongoing study, development and transmission growth that may result from the SPP's plans.
In 2007, the SPP notified OG&E to construct 44 miles of a new 345 kilovolt transmission line which will originate at OG&E's existing Sooner 345 kilovolt substation and proceed generally in a northerly direction to the Oklahoma/Kansas Stateline (referred to as the Sooner-Rose Hill project). At the Oklahoma/Kansas Stateline, the line will connect to the companion line being constructed in Kansas by Westar Energy. Construction of the line began in early 2011 and the line is estimated to be in service by mid-2012 at an estimated cost of $45 million for OG&E.
In January 2009, OG&E received notification from the SPP to begin construction on 50 miles of a new 345 kilovolt transmission line and substation upgrades at OG&E's Sunnyside substation, among other projects. In April 2009, Western Farmers Electric Cooperative assigned to OG&E the construction of 50 miles of line designated by the SPP to be built by Western Farmers Electric Cooperative. The new line will extend from OG&E's Sunnyside substation near Ardmore, Oklahoma, 123.5 miles to the Hugo substation owned by Western Farmers Electric Cooperative near Hugo, Oklahoma. The project cost is estimated at $155 million for OG&E. OG&E began preliminary line routing and acquisition of rights-of-way in June 2009. Construction began in January 2011. When construction is completed, which is expected in mid-2012, the SPP will allocate a portion of the annual revenue requirement to OG&E customers according to the regional cost allocation mechanism as provided in the SPP tariff for application to such improvements.
On April 28, 2009, the SPP approved the Balanced Portfolio 3E projects. Balanced Portfolio 3E includes four projects to be built by OG&E and includes: (i) construction of 135 miles of transmission line from OG&E's Seminole substation in a northeastern direction to OG&E's Muskogee substation at an estimated cost of $160 million for OG&E, which is expected to be
in service by late 2013, (ii) construction of 96 miles of transmission line from OG&E's Woodward District Extra High Voltage substation in a southwestern direction to the Oklahoma/Texas Stateline to a companion transmission line to be built by Southwestern Public Service to its Tuco substation at an estimated cost of $145 million for OG&E, which is expected to be in service by mid-2014, (iii) construction of 39 miles of transmission line from OG&E's Sooner substation in an eastern direction to the Grand River Dam Authority Cleveland substation at an estimated cost of $60 million for OG&E, which is expected to be in service by late 2012 and (iv) construction of a new substation near Anadarko which consisted of a 345/138 kilovolt transformer and substation breakers and was built in OG&E's portion of the Cimarron-Lawton East Side 345 kilovolt line at an estimated cost of $15 million for OG&E, which was placed in service in December 2011. On June 19, 2009, OG&E received a notice to construct the Balanced Portfolio 3E projects from the SPP. On July 23, 2009, OG&E responded to the SPP that OG&E will construct the Balanced Portfolio 3E projects discussed above beginning in early 2011.
On April 27, 2010, the SPP approved, contingent upon approval by the FERC of a regional cost allocation methodology filed with the FERC by the SPP, a set of transmission projects titled "Priority Projects." The Priority Projects consist of several transmission projects, two of which have been assigned to OG&E. The 345 kilovolt projects include: (i) construction of 99 miles of transmission line from OG&E's Woodward District Extra High Voltage substation to a companion transmission line to be built by Southwestern Public Service to its Hitchland substation in the Texas Panhandle at an estimated cost of $185 million for OG&E, which is expected to be in service by mid-2014 and (ii) construction of 77 miles of transmission line from OG&E's Woodward District Extra High Voltage substation to a companion transmission line at the Kansas border to be built by either Mid-Kansas Electric Company or another company assigned by Mid-Kansas Electric Company at an estimated cost of $150 million to OG&E, which is expected to be in service by late 2014. On June 17, 2010, the FERC approved the cost allocation filed by the SPP and notices to construct these Priority Projects were issued by the SPP on June 30, 2010. On September 27, 2010, OG&E responded to the SPP that OG&E will construct the Priority Projects discussed above beginning in June 2012. The scope of the Woodward District Extra High Voltage substation/Kansas border Priority Project was subsequently revised and the SPP Board of Directors approved this revision in October 2010. The SPP issued a revised notice to construct for this Priority Project on November 22, 2010. On February 4, 2011, OG&E responded to the SPP that OG&E will construct the revised Priority Project.
The capital expenditures related to the Sooner-Rose Hill, Sunnyside-Hugo, Balanced Portfolio 3E and Priority Projects are presented in the summary of capital expenditures for known and committed projects in "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources - Future Capital Requirements and Financing Activities."
Regulatory Assets and Liabilities
OG&E, as a regulated utility, is subject to accounting principles for certain types of rate-regulated activities, which provide that certain actual or anticipated costs that would otherwise be charged to expense can be deferred as regulatory assets, based on the expected recovery from customers in future rates. Likewise, certain actual or anticipated credits that would otherwise reduce expense can be deferred as regulatory liabilities, based on the expected flowback to customers in future rates. Management's expected recovery of deferred costs and flowback of deferred credits generally results from specific decisions by regulators granting such ratemaking treatment.
OG&E records certain actual or anticipated costs and obligations as regulatory assets or liabilities if it is probable, based on regulatory orders or other available evidence, that the cost or obligation will be included in amounts allowable for recovery or refund in future rates.
At December 31, 2011 and 2010, OG&E had regulatory assets of $523.9 million and $495.3 million, respectively, and regulatory liabilities of $276.4 million and $243.9 million, respectively. See Note 1 of Notes to Financial Statements for a further discussion.
Management continuously monitors the future recoverability of regulatory assets. When in management's judgment future recovery becomes impaired, the amount of the regulatory asset is adjusted, as appropriate. If OG&E were required to discontinue the application of accounting principles for certain types of rate-regulated activities for some or all of its operations, it could result in writing off the related regulatory assets, which could have significant financial effects.
Rate Structures
Oklahoma
OG&E's standard tariff rates include a cost-of-service component (including an authorized return on capital) plus a fuel adjustment clause mechanism that allows OG&E to pass through to customers variances (either positive or negative) in the actual cost of fuel as compared to the fuel component in OG&E's most recently approved rate case.
OG&E offers several alternate customer programs and rate options. The guaranteed flat bill option for residential and small general service accounts allows qualifying customers the opportunity to purchase their electricity needs at a set price for an entire year. Budget-minded customers that desire a fixed monthly bill may benefit from the guaranteed flat bill option. A second tariff rate option provides a "renewable energy" resource to OG&E's Oklahoma retail customers. This renewable energy resource is a Renewable Energy Credit purchase program and is available as a voluntary option to all of OG&E's Oklahoma retail customers. OG&E's ownership and access to wind resources makes the renewable option a possible choice in meeting the renewable energy needs of our conservation-minded customers. Another program being offered to OG&E's commercial and industrial customers is a voluntary load curtailment program called Load Reduction. This program provides customers with the opportunity to curtail usage on a voluntary basis when OG&E's system conditions merit curtailment action. Customers that curtail their usage will receive payment for their curtailment response. This voluntary curtailment program seeks customers that can curtail on most curtailment event days, but may not be able to curtail every time that a curtailment event is required. OG&E also offers certain qualifying customers a "day-ahead price" rate option which allows participating customers to adjust their electricity consumption based on a price signal received from OG&E. The day-ahead price is based on OG&E's projected next day hourly operating costs.
OG&E also has two rate classes, Public Schools-Demand and Public Schools Non-Demand, that will provide OG&E with flexibility to provide targeted programs for load management to public schools and their unique usage patterns. OG&E also created service level fuel differentiation that allows customers to pay fuel costs that better reflect operational energy losses related to a specific service level. Lastly, OG&E implemented a military base rider that demonstrates Oklahoma's continued commitment to our military partners.
The previously discussed rate options, coupled with OG&E's other rate choices, provide many tariff options for OG&E's Oklahoma retail customers. The revenue impacts associated with these options are not determinable in future years because customers may choose to remain on existing rate options instead of volunteering for the alternative rate option choices. Revenue variations may occur in the future based upon changes in customers' usage characteristics if they choose alternative rate options. OG&E's rate choices, reduction in cogeneration rates, acquisition of additional generation resources and overall low costs of production and deliverability are expected to provide valuable benefits for OG&E's customers for many years to come.
Arkansas
OG&E's standard tariff rates include a cost-of service component (including an authorized return on capital) plus an energy cost recovery mechanism that allows OG&E to pass through to customers the actual cost of fuel. OG&E offers several alternate customer programs and rate options. The "time-of-use" and "variable peak pricing" tariffs allow participating customers to save on their electricity bills by shifting some of the electricity consumption to times when demand for electricity is lowest. A second tariff rate option provides a "renewable energy" resource to OG&E's Arkansas retail customers. This renewable energy resource is a Renewable Energy Credit purchase program and is available as a voluntary option to all of OG&E's Arkansas retail customers. OG&E's ownership and access to wind resources makes the renewable option a possible choice in meeting the renewable energy needs of our conservation-minded customers. OG&E offers its commercial and industrial customers a voluntary load curtailment program called Load Reduction. This program provides customers with the opportunity to curtail usage on a voluntary basis and receive a billing credit when OG&E's system conditions merit curtailment action. OG&E offers certain qualifying customers a "day-ahead price" rate option which allows participating customers to adjust their electricity consumption based on a price signal received from OG&E. The day-ahead price is based on OG&E's projected next day hourly operating costs.
Fuel Supply and Generation
In 2011, 57.9 percent of the OG&E-generated energy was produced by coal-fired units, 39.2 percent by natural gas-fired units and 2.9 percent by wind-powered units. Of OG&E's 6,790 total MW capability reflected in the table under Item 2. Properties, 3,825 MWs, or 56.3 percent, are from natural gas generation, 2,548 MWs, or 37.5 percent, are from coal generation and 417 MWs, or 6.2 percent, are from wind generation. Though OG&E has a higher installed capability of generation from natural gas units, it has been more economical to generate electricity for our customers using lower priced coal. Over the last five years, the weighted average cost of fuel used, by type, was as follows:
The decrease in the weighted average cost of fuel in 2011 as compared to 2010 was primarily due to lower natural gas prices and lower natural gas generation. The increase in the weighted average cost of fuel in 2010 as compared to 2009 was primarily due to higher natural gas prices and increased natural gas generation. The decrease in the weighted average cost of fuel
in 2009 as compared to 2008 was primarily due to decreased natural gas prices partially offset by increased coal transportation rates in 2009. The increase in the weighted average cost of fuel in 2008 as compared to 2007 was primarily due to increased natural gas prices partially offset by decreased amounts of natural gas being burned. A portion of these fuel costs is included in the base rates to customers and differs for each jurisdiction. The portion of recoverable fuel costs that is not included in the base rates is recovered through OG&E's fuel adjustment clauses that are approved by the OCC, the APSC and the FERC.
Coal
All of OG&E's coal-fired units, with an aggregate capability of 2,548 MWs, are designed to burn low sulfur western sub-bituminous coal. OG&E purchases coal primarily under contracts expiring in years 2012 and 2015. In 2011, OG&E purchased 7.5 million tons of coal from various Wyoming suppliers. The combination of all coal has a weighted average sulfur content of 0.26 percent. Based upon the average sulfur content and EPA certified emission data, OG&E's coal units have an approximate emission rate of 0.5 lbs. of SO2 per MMBtu. As discussed, in "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Environmental Laws and Regulations," emission limits are expected to become more stringent.
See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Environmental Laws and Regulations" for a discussion of environmental matters which may affect OG&E in the future, including its utilization of coal.
Natural Gas
OG&E has natural gas contracts for purchases from January 2012 through March 2012 that account for 26 percent of OG&E's projected 2012 natural gas requirements. Additional gas supplies to fulfill OG&E's remaining 2012 natural gas requirements will be acquired through additional requests for proposal in early to mid-2012, along with monthly and daily purchases, all of which are expected to be made at market prices.
OG&E utilizes a natural gas storage facility for storage services that allows OG&E to maximize the value of its generation assets. Storage services are provided by Enogex as part of Enogex's gas transportation and storage contract with OG&E. At December 31, 2011, OG&E had 2.9 million MMBtu's in natural gas storage valued at $10.7 million.
Wind
OG&E's current wind power portfolio includes: (i) the Centennial wind farm, (ii) the OU Spirit wind farm, (iii) the Crossroads wind farm, (iv) access to up to 50 MWs of electricity generated at a wind farm near Woodward, Oklahoma from a 15-year contract OG&E entered into with FPL Energy that expires in 2018, (v) access to up to 150 MWs of electricity generated at a wind farm in Woodward County, Oklahoma from a 20-year contract OG&E entered into with CPV Keenan that expires in 2030 and (vi) access to up to 130 MWs of electricity generated at a wind farm in Woodward County, Oklahoma from a 20-year contract OG&E entered into with Edison Mission Energy that expires in 2030.
Safety and Health Regulation
OG&E is subject to a number of Federal and state laws and regulations, including OSHA and comparable state statutes, whose purpose is to protect the safety and health of workers. In addition, the OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of the Federal Superfund Amendment and Reauthorization Act and comparable state statutes require that information be maintained concerning hazardous materials used or produced in OG&E's operations and that this information be provided to employees, state and local government authorities and citizens. OG&E believes that it is in material compliance with all applicable laws and regulations relating to worker safety and health.
ENVIRONMENTAL MATTERS
General
The activities of OG&E are subject to stringent and complex Federal, state and local laws and regulations governing environmental protection including the discharge of materials into the environment. These laws and regulations can restrict or impact OG&E's business activities in many ways, such as restricting the way it can handle or dispose of its wastes, requiring remedial action to mitigate pollution conditions that may be caused by its operations or that are attributable to former operators, regulating future construction activities to mitigate harm to threatened or endangered species and requiring the installation and operation of pollution control equipment. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial requirements and the issuance of orders enjoining future
operations. OG&E believes that its operations are in substantial compliance with current Federal, state and local environmental standards.
The trend in environmental regulation, however, is to place more restrictions and limitations on activities that may affect the environment. OG&E cannot assure that future events, such as changes in existing laws, the promulgation of new laws or regulations, or the development or discovery of new facts or conditions will not cause it to incur significant costs. Management continues to evaluate its compliance with existing and proposed environmental legislation and regulations and implement appropriate environmental programs in a competitive market.
Of OG&E's capital expenditures budgeted for 2012 and 2013, $33.7 million and $35.3 million, respectively, are to comply with environmental laws and regulations. OG&E's management believes that all of its operations are in substantial compliance with current Federal, state and local environmental standards. It is estimated that OG&E's total expenditures for capital, operating, maintenance and other costs associated with environmental quality will be $51.6 million in 2012 as compared to $24.0 million in 2011. Management continues to evaluate its compliance with existing and proposed environmental legislation and regulations and implement appropriate environmental programs in a competitive market.
For a further discussion of environmental matters that may affect OG&E, see "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Environmental Laws and Regulations."
FINANCE AND CONSTRUCTION
Future Capital Requirements and Financing Activities
Capital Requirements
OG&E's primary needs for capital are related to acquiring or constructing new facilities and replacing or expanding existing facilities. Other working capital requirements are expected to be primarily related to maturing debt, operating lease obligations, hedging activities, fuel clause under and over recoveries and other general corporate purposes. OG&E generally meets its cash needs through a combination of cash generated from operations, short-term borrowings (through a combination of bank borrowings, commercial paper and borrowings from OGE Energy) and permanent financings. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources" for a discussion of OG&E's capital requirements.
Capital Expenditures
OG&E's estimates of capital expenditures for the years 2012 through 2016 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.
(A)
These capital expenditures are net of the $130 million Smart Grid grant approved by the U.S. Department of Energy.
(B)
The capital expenditures above exclude any environmental expenditures associated with pollution control equipment related to regional haze requirements due to the uncertainty regarding the timing and costs for such pollution control equipment. OG&E has committed to install low NOX burners at the affected generating units at a cost preliminarily estimated between $70 million and $130 million, but the timing of the installation of such burners is uncertain. The SO2 emissions standards in the EPA's Federal implementation plan 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 Federal implementation plan is being challenged by OG&E and the state of Oklahoma. Neither the outcome of the challenge to the Federal implementation plan nor the timing and amount of any required capital expenditures can be predicted with any certainty at this time, but such capital expenditures could be significant. For further information, see "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Environmental Laws and Regulations" below.
Additional capital expenditures beyond those identified in the table above, including additional incremental growth opportunities in electric transmission assets, will be evaluated based upon their impact upon achieving OG&E's financial objectives.
Pension and Postretirement Benefit Plans
During each of 2011 and 2010, OGE Energy made contributions to its Pension Plan of $50 million, of which $47 million in each of 2011 and 2010 was OG&E's portion, to help ensure that the Pension Plan maintains an adequate funded status. During 2012, OGE Energy may contribute up to $35 million to its Pension Plan, of which $33 million is expected to be OG&E's portion. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources - Future Capital Requirements and Financing Activities" for a discussion of OGE Energy's pension and postretirement benefit plans.
Future Sources of Financing
Management expects that cash generated from operations, proceeds from the issuance of long and short-term debt and funds received from OGE Energy (from proceeds from the sales of its common stock to the public through OGE Energy's Automatic Dividend Reinvestment and Stock Purchase Plan or other offerings) will be adequate over the next three years to meet anticipated cash needs and to fund future growth opportunities. OG&E utilizes short-term borrowings (through a combination of bank borrowings, commercial paper and borrowings from OGE Energy) to satisfy temporary working capital needs and as an interim source of financing capital expenditures until permanent financing is arranged.
Short-Term Debt and Credit Facility
At December 31, 2011 and 2010, there were $97.2 million and $68.9 million, respectively, in net outstanding advances to OGE Energy. OG&E has an intercompany borrowing agreement with OGE Energy whereby OG&E has access to up to $250
million of OGE Energy's revolving credit amount. This agreement has a termination date of January 9, 2013. At December 31, 2011, there were no intercompany borrowings under this agreement. In December 2011, OG&E entered into a new $400 million unsecured five-year revolving credit facility which is available to back up OG&E's commercial paper borrowings and to provide revolving credit borrowings. This bank facility can also be used as a letter of credit facility. At December 31, 2011, there was $2.2 million supporting letters of credit at a weighted-average interest rate of 0.53 percent. There were no outstanding borrowings under this revolving credit agreement and no outstanding commercial paper borrowings at December 31, 2011. At December 31, 2011, OG&E had $397.8 million of net available liquidity under its revolving credit agreement. OG&E has the necessary regulatory approvals to incur up to $800 million in short-term borrowings at any one time for a two-year period beginning January 1, 2011 and ending December 31, 2012. At December 31, 2011, OG&E had less than $0.1 million in cash and cash equivalents. See Note 10 of Notes to Financial Statements for a discussion of OG&E's short-term debt activity.
Expected Issuance of Long-Term Debt
OG&E expects to issue approximately $250 million of long-term debt in late 2012, depending on market conditions, to fund capital expenditures, repay short-term borrowings and for general corporate purposes.
EMPLOYEES
OG&E had 2,108 employees at December 31, 2011.
EXECUTIVE OFFICERS
The following persons were Executive Officers of the Registrant as of February 16, 2012:
No family relationship exists between any of the Executive Officers of the Registrant. Messrs. Delaney, Trauschke, Bullard, Forbes, Huneryager, Myers, Nuttall, Peace, Renfrow and Ms. Horn and Ms. McQuistion are also officers of OGE Energy. Messrs. Delaney, Trauschke, Myers and Ms. Horn are also officers of Enogex Holdings and/or its subsidiaries. Each Executive Officer is to hold office until the Board of Directors meeting following the next Annual Meeting of Shareowners of OGE Energy, currently scheduled for May 17, 2012.
The business experience of each of the Executive Officers of the Registrant for the past five years is as follows:
ACCESS TO SECURITIES AND EXCHANGE COMMISSION FILINGS
OGE Energy's web site address is www.oge.com. Through OGE Energy's website under the heading "Investor Relations," "SEC Filings," OGE Energy makes available, free of charge, OGE Energy's and OG&E's annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act as soon as reasonably practicable after such material is electronically filed with or furnished to the Securities and Exchange Commission. Our Internet website and the information contained therein or connected thereto are not intended to be incorporated into this Form 10-K and should not be considered a part of this Form 10-K.
Item 1A.
Item 1A. Risk Factors.
In the discussion of risk factors set forth below, unless the context otherwise requires, the terms "we," "our" and "us" refer to Oklahoma Gas and Electric Company. In addition to the other information in this Form 10-K and other documents filed by us with the Securities and Exchange Commission from time to time, the following factors should be carefully considered in evaluating OG&E. Such factors could affect actual results and cause results to differ materially from those expressed in any forward-looking statements made by or on behalf of us. Additional risks and uncertainties not currently known to us or that we currently view as immaterial may also impair our business operations.
REGULATORY RISKS
Our profitability depends to a large extent on our ability to fully recover our costs from our customers and there may be changes in the regulatory environment that impair our ability to recover costs from our customers.
We are subject to comprehensive regulation by several Federal and state utility regulatory agencies, which significantly influences our operating environment and our ability to fully recover our costs from utility customers. With rising fuel costs, recoverability of under recovered amounts from our customers is a significant risk. The utility commissions in the states where we operate regulate many aspects of our utility operations including siting and construction of facilities, customer service and the rates that we can charge customers. The profitability of our utility operations is dependent on our ability to fully recover costs related to providing energy and utility services to our customers.
In recent years, the regulatory environments in which we operate have received an increased amount of public attention. It is possible that there could be changes in the regulatory environment that would impair our ability to fully recover costs historically absorbed by our customers. State utility commissions generally possess broad powers to ensure that the needs of the utility customers are being met. We cannot assure that the OCC, APSC and the FERC will grant us rate increases in the future or in the amounts we request, and they could instead lower our rates.
We are unable to predict the impact on our operating results from the future regulatory activities of any of the agencies that regulate us. Changes in regulations or the imposition of additional regulations could have an adverse impact on our results of operations.
Our rates are subject to rate regulation by the states of Oklahoma and Arkansas, as well as by a Federal agency, whose regulatory paradigms and goals may not be consistent.
We are currently a vertically integrated electric utility and most of our revenue results from the sale of electricity to retail customers subject to bundled rates that are approved by the applicable state utility commission and from the sale of electricity to wholesale customers subject to rates and other matters approved by the FERC.
We operate in Oklahoma and western Arkansas and are subject to rate regulation by the OCC and the APSC, in addition to the FERC. Exposure to inconsistent state and Federal regulatory standards may limit our ability to operate profitably. Further alteration of the regulatory landscape in which we operate may harm our financial position and results of operations.
Costs of compliance with environmental laws and regulations are significant and the cost of compliance with future environmental laws and regulations may adversely affect our results of operations, financial position, or liquidity.
We are subject to extensive Federal, state and local environmental statutes, rules and regulations relating to air quality, water quality, waste management, wildlife conservation, natural resources and health and safety that could, among other things, restrict or limit the output of certain facilities or the use of certain fuels required for the production of electricity and/or require additional pollution control equipment and otherwise increase costs. There are significant capital, operating and other costs associated with compliance with these environmental statutes, rules and regulations and those costs may be even more significant in the future. For example, the EPA rules could require significant capital and operating expenditures to achieve reductions in emissions of SO2 and NOX over the next five years.
In response to public concern about global climate change, emissions of greenhouse gases including, most significantly, carbon dioxide could be restricted in the future as a result of Federal or state legal requirements or litigation relating to greenhouse gas emissions. If mandatory reductions of carbon dioxide and other greenhouse gases are required in the future, this could result in significant additional compliance costs that would affect our future financial position, results of operations and cash flows if such costs are not recovered through regulated rates.
There is inherent risk of the incurrence of environmental costs and liabilities in our operations due to our handling of natural gas, air emissions related to our operations and historical industry operations and waste disposal practices. For example, an accidental release from one of our facilities could subject us to substantial liabilities arising from environmental cleanup and restoration costs, claims made by neighboring landowners and other third parties for personal injury and property damage and fines or penalties for related violations of environmental laws or regulations. We may be unable to recover these costs from insurance. Moreover, the possibility exists that stricter laws, regulations or enforcement policies could significantly increase compliance costs and the cost of any remediation that may become necessary.
For a further discussion of environmental matters that may affect OG&E, see "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Environmental Laws and Regulations".
We are subject to physical and financial risks associated with climate change.
Climate change creates physical and financial risk. Physical risks from climate change could include an increase in sea level and changes in weather conditions, such as an increase in changes in precipitation and extreme weather events. OG&E's operations are not sensitive to potential future sea-level rise as it does not operate in coastal areas. However, OG&E's power delivery systems are vulnerable to damage from extreme weather events, such as ice storms, tornadoes and severe thunderstorms. These types of extreme weather events are common on OG&E's system, so OG&E includes storm restoration in its budgeting process as a normal business expense. To the extent the frequency of extreme weather events increases, this could increase OG&E's cost of providing service. OG&E's electric generating facilities are designed to withstand the effects of extreme weather events, however, extreme weather conditions increase the stress placed on such systems. If climate change results in temperature increases in OG&E's service territory, OG&E could expect increased electricity demand due to the increase in temperature and longer warm seasons. While this increase in demand could lead to increased energy consumption, it could also create a physical strain on OG&E's generating resources. At the same time, OG&E could face restrictions on the ability to meet that demand if, due to drought severity, there is a lack of sufficient water for use in cooling during the electricity generating process.
In addition to the above cited risks, to the extent that any climate change adversely affects the national or regional economic health through increased rates caused by the inclusion of additional regulatory imposed costs (carbon dioxide taxes or costs associated with additional regulatory requirements), OG&E may be adversely impacted. A declining economy could adversely impact the overall financial health of OG&E because of lack of load growth and decreased sales opportunities.
To the extent financial markets view climate change and emissions of greenhouse gases as a financial risk, this could negatively affect our ability to access capital markets or cause us to receive less than ideal terms and conditions.
We may not be able to recover the costs of our substantial planned investment in capital improvements and additions.
Our business plan calls for extensive investment in capital improvements and additions, including the installation of environmental upgrades and retrofits and modernizing existing infrastructure as well as other initiatives. Significant portions of our facilities were constructed many years ago. Older generation equipment, even if maintained in accordance with good engineering practices, may require significant capital expenditures to maintain efficiency, to comply with changing environmental requirements or to provide reliable operations. We currently provide service at rates approved by one or more regulatory
commissions. If these regulatory commissions do not approve adjustments to the rates we charge, we would not be able to recover the costs associated with our planned extensive investment. This could adversely affect our results of operations and financial position. While we may seek to limit the impact of any denied recovery by attempting to reduce the scope of our capital investment, there can no assurance as to the effectiveness of any such mitigation efforts, particularly with respect to previously incurred costs and commitments.
Our jurisdictions have fuel clauses that permit us to recover fuel costs through rates without a general rate case. While prudent capital investment and variable fuel costs each generally warrant recovery, in practical terms our regulators could limit the amount or timing of increased costs that we would recover through higher rates. Any such limitation could adversely affect our results of operations and financial position.
OG&E may not realize the expected benefits of its Smart Grid metering system, the Smart Grid metering system may not perform as intended or OG&E may incur costs to deploy the Smart Grid metering system that are not recoverable in rates which could adversely affect our results of operations, financial position and cash flows.
In 2010, OG&E began implementing its Smart Grid metering infrastructure project for residential and commercial customers. This project, which is expected to be completed by the end of 2012, involves the installation of approximately 792,000 Smart Grid meters throughout OG&E's service territory. Smart Grid meters will allow customer usage data to be transmitted through a communication network to a central collection point, where the data will be stored and used for customer billing and other commercial purposes.
The costs recoverable from Oklahoma customers for system-wide deployment of smart grid technology and implementing the smart grid pilot program are capped at $366.4 million, (inclusive of the U.S. Department of Energy grant award amount) subject to an offset for any recovery of those costs from Arkansas customers and are currently being recovered through a rider which will remain in effect until the Smart Grid project costs are included in base rates beginning in 2014. To the extent that OG&E's total expenditure for system-wide deployment of smart grid technology during the eligible period exceeds the Smart Grid project cost, OG&E shall be entitled to offer evidence and seek to establish that the excess above the Smart Grid project cost was prudently incurred and any such contention may be addressed in OG&E's next rate case.
If OG&E does not recognize the expected benefits of its Smart Grid metering system, if OG&E incurs additional Smart Grid metering costs that the OCC does not find reasonable or are unrecoverable or if OG&E cannot integrate the Smart Grid metering system with its customer billing and other computer information systems, this may adversely affect our results of operations, financial position and cash flows.
The regional power market in which we operate has changing transmission regulatory structures, which may affect the transmission assets and related revenues and expenses.
We currently own and operate transmission and generation facilities as part of a vertically integrated utility. We are a member of the SPP regional transmission organization and have transferred operational authority (but not ownership) of our transmission facilities to the SPP. The SPP implemented a regional energy imbalance service market on February 1, 2007. We participate in the SPP energy imbalance service market to aid in the optimization of its physical assets to serve our customers. We have not participated in the SPP energy imbalance service market for any speculative trading activities. The SPP purchases and sales are not allocated to individual customers. We record the hourly sales to the SPP at market rates in Operating Revenues and the hourly purchases from the SPP at market rates in Cost of Goods Sold in our Financial Statements. Our revenues, expenses, assets and liabilities may be adversely affected by changes in the organization, operation and regulation by the FERC or the SPP.
Increased competition resulting from restructuring efforts could have a significant financial impact on us and consequently decrease our revenue.
We have been and will continue to be affected by competitive changes to the utility and energy industries. Significant changes already have occurred and additional changes have been proposed to the wholesale electric market. Although retail restructuring efforts in Oklahoma and Arkansas have been postponed for the time being, if such efforts were renewed, retail competition and the unbundling of regulated energy service could have a significant financial impact on us due to possible impairments of assets, a loss of retail customers, lower profit margins and/or increased costs of capital. Any such restructuring could have a significant impact on our financial position, results of operations and cash flows. We cannot predict when we will be subject to changes in legislation or regulation, nor can we predict the impact of these changes on our financial position, results of operations or cash flows.
Events that are beyond our control have increased the level of public and regulatory scrutiny of our industry. Governmental and market reactions to these events may have negative impacts on our business, financial position, cash flows and access to capital.
As a result of accounting irregularities at public companies in general, and energy companies in particular, and investigations by governmental authorities into energy trading activities, public companies, including those in the regulated and unregulated utility business, have been under an increased amount of public and regulatory scrutiny and suspicion. The accounting irregularities have caused regulators and legislators to review current accounting practices, financial disclosures and relationships between companies and their independent auditors. The capital markets and rating agencies also have increased their level of scrutiny. We believe that we are complying with all applicable laws and accounting standards, but it is difficult or impossible to predict or control what effect these types of events may have on our business, financial position, cash flows or access to the capital markets. It is unclear what additional laws or regulations may develop, and we cannot predict the ultimate impact of any future changes in accounting regulations or practices in general with respect to public companies, the energy industry or our operations specifically. Any new accounting standards could affect the way we are required to record revenues, expenses, assets, liabilities and equity. These changes in accounting standards could lead to negative impacts on reported earnings or decreases in assets or increases in liabilities that could, in turn, affect our results of operations and cash flows.
We are subject to substantial utility and energy regulation by governmental agencies. Compliance with current and future utility and energy regulatory requirements and procurement of necessary approvals, permits and certifications may result in significant costs to us.
We are subject to substantial regulation from Federal, state and local regulatory agencies. We are required to comply with numerous laws and regulations and to obtain numerous permits, approvals and certificates from the governmental agencies that regulate various aspects of our businesses, including customer rates, service regulations, retail service territories, sales of securities, asset acquisitions and sales, accounting policies and practices and the operation of generating facilities. We believe the necessary permits, approvals and certificates have been obtained for our existing operations and that our business is conducted in accordance with applicable laws; however, we are unable to predict the impact on our operating results from future regulatory activities of these agencies.
In compliance with the Energy Policy Act of 2005, the FERC approved the North American Electric Reliability Corporation as the national energy reliability organization. The North American Electric Reliability Corporation is responsible for the development and enforcement of mandatory reliability and cyber security standards for the wholesale electric power system. OG&E's plan is to comply with all applicable standards and to expediently correct a violation should it occur. The North American Electric Reliability Corporation has authority to assess penalties up to $1 million per day per violation for noncompliance. OG&E is subject to a North American Electric Reliability Corporation compliance audit every three years as well as periodic spot check audits and cannot predict the outcome of those audits.
OPERATIONAL RISKS
Our results of operations may be impacted by disruptions beyond our control.
We are exposed to risks related to performance of contractual obligations by our suppliers. We are dependent on coal for much of our electric generating capacity. We rely on suppliers to deliver coal in accordance with short and long-term contracts. We have certain coal supply contracts in place; however, there can be no assurance that the counterparties to these agreements will fulfill their obligations to supply coal to us. The suppliers under these agreements may experience financial or technical problems that inhibit their ability to fulfill their obligations to us. In addition, the suppliers under these agreements may not be required to supply coal to us under certain circumstances, such as in the event of a natural disaster. Coal delivery may be subject to short-term interruptions or reductions due to various factors, including transportation problems, weather and availability of equipment. Failure or delay by our suppliers of coal deliveries could disrupt our ability to deliver electricity and require us to incur additional expenses to meet the needs of our customers.
Also, because our generation and transmission systems are part of an interconnected regional grid, we face the risk of possible loss of business due to a disruption or black-out caused by an event (severe storm, generator or transmission facility outage) on a neighboring system or the actions of a neighboring utility. Any such disruption could result in a significant decrease in revenues and significant additional costs to repair assets, which could have a material adverse impact on our financial position and results of operations.
OG&E's electric generating facilities are subject to operational risks that could result in unscheduled plant outages, unanticipated operation and maintenance expenses and increased power purchase costs.
OG&E owns and operates coal-fired, natural gas-fired and wind-powered generating facilities. Operation of electric generating facilities involves risks that can adversely affect energy output and efficiency levels. Included among these risks are:
•
Increased prices for fuel and fuel transportation as existing contracts expire;
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Facility shutdowns due to a breakdown or failure of equipment or processes or interruptions in fuel supply;
•
Operator error or safety related stoppages;
•
Disruptions in the delivery of electricity; and
•
Catastrophic events such as fires, explosions, floods or other similar occurrences.
Economic conditions could negatively impact our business and our results of operations.
Our operations are affected by local, national and worldwide economic conditions. The consequences of a prolonged recession could include a lower level of economic activity and uncertainty regarding energy prices and the capital and commodity markets. A lower level of economic activity could result in a decline in energy consumption, which could adversely affect our revenues and future growth. Instability in the financial markets, as a result of recession or otherwise, also could affect the cost of capital and our ability to raise capital.
Current economic conditions may be exacerbated by insufficient financial sector liquidity leading to potential increased unemployment, which could impact the ability of our customers to pay timely, increase customer bankruptcies, and could lead to increased bad debt. If such circumstances occur, we expect that commercial and industrial customers would be impacted first, with residential customers following.
In addition, economic conditions, particularly budget shortfalls, could lead to increased pressure on Federal, state and local governments to raise additional funds, including through increased corporate taxes and/or through delaying, reducing or eliminating tax credits, grants or other incentives, which could have a material adverse impact on our results of operations.
We are subject to cyber security risks.
In the regular course of our businesses, we handle a range of sensitive security and customer information. We are subject to laws and rules issued by different agencies concerning safeguarding and maintaining the confidentiality of this information. A security breach of our information systems such as theft or inappropriate release of certain types of information, including confidential customer information or system operating information, could have a material adverse impact on the operations and financial condition of OG&E.
OG&E operates in a highly regulated industry that requires the continued operation of sophisticated information technology systems and network infrastructure. Despite implementation of security measures, the technology systems are vulnerable to disability, failures or unauthorized access. Such failures or breaches of the systems could impact the reliability of OG&E's generation, transmission and distribution systems and also subjects OG&E to financial harm. The implementation of OG&E's Smart Grid program further increases potential risks associated with cyber security attacks. If the technology systems were to fail or be breached and not recovered in a timely way, critical business functions could be impaired and sensitive confidential data could be compromised, which could have a material adverse impact on the operations and financial condition of OG&E.
Terrorist attacks, and the threat of terrorist attacks, have resulted in increased costs to our business. Continued hostilities in the Middle East or other sustained military campaigns may adversely impact our financial position, results of operations and cash flows.
The long-term impact of terrorist attacks and the magnitude of the threat of future terrorist attacks on the electric utility industry in general, and on us in particular, cannot be known. Increased security measures taken by us as a precaution against possible terrorist attacks have resulted in increased costs to our business. Uncertainty surrounding continued hostilities in the Middle East or other sustained military campaigns may affect our operations in unpredictable ways, including disruptions of supplies and markets for our products, and the possibility that our infrastructure facilities could be direct targets of, or indirect casualties of, an act of terror. Changes in the insurance markets attributable to terrorist attacks may make certain types of insurance more difficult for us to obtain. Moreover, the insurance that may be available to us may be significantly more expensive than existing insurance coverage.
Weather conditions such as tornadoes, thunderstorms, ice storms, wind storms, as well as seasonal temperature variations may adversely affect our financial position, results of operations and cash flows.
Weather conditions directly influence the demand for electric power. In OG&E's service area, demand for power peaks during the hot summer months, with market prices also typically peaking at that time. As a result, overall operating results may fluctuate on a seasonal and quarterly basis. In addition, we have historically sold less power, and consequently received less revenue, when weather conditions are milder. Unusually mild weather in the future could reduce our revenues, net income, available cash and borrowing ability. Severe weather, such as tornadoes, thunderstorms, ice storms and wind storms, may cause outages and property damage which may require us to incur additional costs that are generally not insured and that may not be recoverable from customers. The effect of the failure of our facilities to operate as planned, as described above, would be particularly burdensome during a peak demand period.
We engage in commodity hedging activities to minimize the impact of commodity price risk, which may have a volatile effect on our earnings and cash flows.
We are exposed to changes in commodity prices in our operations. We occasionally use commodity price swap contracts to manage our commodity price risk exposures. Natural gas swaps are used to manage OG&E's natural gas exposure associated with a wholesale power sales contract.
From time to time, OG&E has instituted a hedging program that was intended to reduce the commodity price risk associated with OG&E's wholesale power sales contract. Management will continue to evaluate whether to enter into any new hedging arrangements and there can be no assurance that OG&E will enter into any new hedging arrangements. To the extent OG&E hedges its commodity price and interest rate exposures, OG&E may forego the benefits that otherwise would be experienced if commodity prices or interest rates were to change in OG&E's favor. In addition, even though management monitors OG&E's hedging activities, these activities can result in substantial losses. Such losses could occur under various circumstances, including if a counterparty does not perform its obligations under the applicable hedging arrangement, the hedging arrangement is imperfect or ineffective, or the hedging policies and procedures are not followed or do not work as planned.
FINANCIAL RISKS
Market performance, increased retirements, changes in retirement plan regulations and increasing costs associated with our defined benefit retirement plans, health care plans and other employee-related benefits may adversely affect our results of operations, financial position or liquidity.
OGE Energy has a Pension Plan that covers substantially all of our employees hired before December 1, 2009. OGE Energy also has defined benefit postretirement plans that cover substantially all of our employees hired prior to February 1, 2000. Assumptions related to future costs, returns on investments, interest rates and other actuarial assumptions with respect to the defined benefit retirement and postretirement plans have a significant impact on our earnings and funding requirements. Based on our assumptions at December 31, 2011, OGE Energy expects to continue to make future contributions to maintain required funding levels. It is OGE Energy's practice to also make voluntary contributions to maintain more prudent funding levels than minimally required. These amounts are estimates and may change based on actual stock market performance, changes in interest rates and any changes in governmental regulations.
All employees hired prior to February 1, 2000 participate in defined benefit postretirement plans. If these employees retire when they become eligible for retirement over the next several years, or if our plan experiences adverse market returns on its investments, or if interest rates materially fall, our pension expense and contributions to the plans could rise substantially over historical levels. The timing and number of employees retiring and selecting the lump-sum payment option could result in pension settlement charges that could materially affect our results of operations if we are unable to recover these costs through our electric rates. In addition, assumptions related to future costs, returns on investments, interest rates and other actuarial assumptions, including projected retirements, have a significant impact on our results of operations and financial position. Those factors are outside of our control.
In addition to the costs of our retirement plans, the costs of providing health care benefits to our employees and retirees have increased substantially in recent years. We believe that our employee benefit costs, including costs related to health care plans for our employees and former employees, will continue to rise. The increasing costs and funding requirements with our defined benefit retirement plan, health care plans and other employee benefits may adversely affect our results of operations, financial position, or liquidity.
We face certain human resource risks associated with the availability of trained and qualified labor to meet our future staffing requirements.
Workforce demographic issues challenge employers nationwide and are of particular concern to the electric utility industry. The median age of utility workers is significantly higher than the national average. Over the next three years, 37 percent of our current employees will be eligible to retire with full pension benefits. Failure to hire and adequately train replacement employees, including the transfer of significant internal historical knowledge and expertise to the new employees, may adversely affect our ability to manage and operate our business.
We may be able to incur substantially more indebtedness, which may increase the risks created by our indebtedness.
The terms of the indentures governing our debt securities do not fully prohibit us from incurring additional indebtedness. If we are in compliance with the financial covenants set forth in our revolving credit agreement and the indentures governing our debt securities, we may be able to incur substantial additional indebtedness. If we incur additional indebtedness, the related risks that we and they now face may intensify.
Any reductions in our credit ratings could increase our financing costs and the cost of maintaining certain contractual relationships or limit our ability to obtain financing on favorable terms.
We cannot assure you that any of our current credit ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances so warrant. Our ability to access the commercial paper market could be adversely impacted by a credit ratings downgrade or major market disruptions. Pricing grids associated with our credit facility could cause annual fees and borrowing rates to increase if an adverse rating impact occurs. The impact of any future downgrade would include an increase in the costs of our short-term borrowings, but a reduction in our credit ratings would not result in any defaults or accelerations. Any future downgrade would also lead to higher long-term borrowing costs and, if below investment grade, could require us to post collateral or letters of credit.
Our debt levels may limit our flexibility in obtaining additional financing and in pursuing other business opportunities.
We have a revolving credit agreement for working capital, capital expenditures, including acquisitions, and other corporate purposes. The levels of our debt could have important consequences, including the following:
•
the ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or the financing may not be available on favorable terms;
•
a portion of cash flows will be required to make interest payments on the debt, reducing the funds that would otherwise be available for operations and future business opportunities; and
•
our debt levels may limit our flexibility in responding to changing business and economic conditions.
We are exposed to the credit risk of our key customers and counterparties, and any material nonpayment or nonperformance by our key customers and counterparties could adversely affect our financial position, results of operations and cash flows.
We are exposed to credit risks in our generation and retail distribution operations. Credit risk includes the risk that customers and counterparties that owe us money or energy will breach their obligations. If such parties to these arrangements fail to perform, we may be forced to enter into alternative arrangements. In that event, our financial results could be adversely affected, and we could incur losses.
Item 1B.
Item 1B. Unresolved Staff Comments.
None.
Item 2.
Item 2. Properties.
OG&E owns and operates an interconnected electric generation, transmission and distribution system, located in Oklahoma and western Arkansas, which included 12 generating stations with an aggregate capability of 6,790 MWs at December 31, 2011. The following tables set forth information with respect to OG&E's electric generating facilities, all of which are located in Oklahoma.
(A) 2011 Capacity Factor = 2011 Net Actual Generation / (2011 Net Maximum Capacity (Nameplate Rating in MWs) x Period Hours (8,760 Hours)).
(B) Peaking units are used when additional short-term capacity is required.
(C) Represents OG&E's 51 percent ownership interest in the Redbud Plant.
(D) Represents OG&E's 77 percent ownership interest in the McClain Plant.
(E) This unit did not demonstrate summer capability in 2011 as prescribed by the SPP criteria.
(F) The Crossroads wind farm was fully in service in January 2012, which increased station capability to 227.5 MWs.
At December 31, 2011, OG&E's transmission system included: (i) 51 substations with a total capacity of 11.5 million kilovolt-amps and 4,258 structure miles of lines in Oklahoma and (ii) seven substations with a total capacity of 2.4 million kilovolt-amps and 279 structure miles of lines in Arkansas. OG&E's distribution system included: (i) 353 substations with a total capacity of 9.1 million kilovolt-amps, 27,854 structure miles of overhead lines, 1,895 miles of underground conduit and 10,120 miles of underground conductors in Oklahoma and (ii) 37 substations with a total capacity of 1.0 million kilovolt-amps, 2,250 structure miles of overhead lines, 212 miles of underground conduit and 572 miles of underground conductors in Arkansas.
OG&E owns 140,133 square feet of office space at its executive offices at 321 North Harvey, Oklahoma City, Oklahoma 73102. In addition to its executive offices, OG&E owns numerous facilities throughout its service territory that support its operations. These facilities include, but are not limited to, district offices, fleet and equipment service facilities, operation support and other properties.
During the three years ended December 31, 2011, OG&E's gross property, plant and equipment (excluding construction work in progress) additions were $2.0 billion and gross retirements were $241.3 million. These additions were provided by cash generated from operations, short-term borrowings (through a combination of bank borrowings, commercial paper and borrowings from OGE Energy), long-term borrowings and permanent financings. The additions during this three-year period amounted to 25.2 percent of gross property, plant and equipment (excluding construction work in progress) at December 31, 2011.
Item 3.
Item 3. Legal Proceedings.
In the normal course of business, OG&E is confronted with issues or events that may result in a contingent liability. These generally relate to lawsuits, claims made by third parties, environmental actions or the action of various regulatory 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 set forth below and in Notes 12 and 13 of Notes to Financial Statements, management, after consultation with legal counsel, does not currently anticipate that liabilities arising out of these pending or threatened lawsuits, claims and contingencies will have a material adverse effect on OG&E's financial position, results of operations or cash flows.
1. Will Price, et al. v. El Paso Natural Gas Co., et al. (Price I). On September 24, 1999, various subsidiaries of OGE Energy were served with a class action petition filed in the District Court of Stevens County, Kansas by Quinque Operating Company and other named plaintiffs alleging the mismeasurement of natural gas on non-Federal lands. On April 10, 2003, the court entered an order denying class certification. On May 12, 2003, the plaintiffs (now Will Price, Stixon Petroleum, Inc., Thomas F. Boles and the Cooper Clark Foundation, on behalf of themselves and other royalty interest owners) filed a motion seeking to file an amended class action petition, and the court granted the motion on July 28, 2003. In its amended petition, OG&E and Enogex Inc. were omitted from the case but two of OGE Energy's other subsidiary entities remained as defendants. The plaintiffs' amended petition seeks class certification and alleges that 60 defendants, including two of OGE Energy's subsidiary entities, have improperly measured the volume of natural gas. The amended petition asserts theories of civil conspiracy, aiding and abetting, accounting and unjust enrichment. In their briefing on class certification, the plaintiffs seek to also allege a claim for conversion. The plaintiffs seek unspecified actual damages, attorneys' fees, costs and pre-judgment and post-judgment interest. The plaintiffs also reserved the right to seek punitive damages.
On September 18, 2009, the court entered its order denying class certification. On October 2, 2009, the plaintiffs filed for a rehearing of the court's denial of class certification. On March 31, 2010, the court denied the plaintiffs' request for rehearing. On July 20, 2011, Enogex LLC and OER filed motions for summary judgment. On January 25, 2012, the court denied portions of the motions for summary judgment related to the legal issue of the plaintiffs' claims regarding civil conspiracy. In an order dated January 23, 2012, the court granted the plaintiffs additional time to perform discovery prior to the consideration of the motions for summary judgment as they relate to the plaintiffs' other claims.
OGE Energy intends to vigorously defend this action. At this time, OGE Energy does not believe the outcome will have a material impact on its financial position.
2. Opacity Notice. On May 17, 2011, OG&E entered into a Consent Order with the ODEQ related to alleged violations of Federal and state opacity standards from 2005 to May 2011 at OG&E's Muskogee and Sooner generating stations. The Consent Order requires OG&E to reach certain milestones with regard to the overall amount of time when opacity exceeds certain amounts. Beginning January 1, 2015, the Consent Order requires each unit at OG&E's Muskogee and Sooner generating stations to have a rolling annual average of the time that opacity emissions are in excess of 20 percent to a level equal to or below one percent of the total time in a measurement period. OG&E agreed to implement two specific projects and other measures as necessary to achieve the milestones established in the Consent Order. These projects and other measures are not expected to involve
significant capital or ongoing operating expenses. OG&E also agreed to pay a stipulated cash penalty of $150,000 and agreed to contribute another $150,000 to an ODEQ environmental fund for assisting small Oklahoma communities with their drinking water and wastewater treatment systems. OG&E entered into the Consent Order without admitting or denying the allegations made by the ODEQ. In order to facilitate the court approval of the Consent Order, the ODEQ initiated the necessary legal action against OG&E in state court on May 17, 2011. On June 2, 2011, the Consent Order was approved and entered by the District Court of Oklahoma County, Oklahoma. Subject to the ongoing compliance obligations described above pursuant to the Consent Order, OG&E considers this matter closed.
As previously reported, on March 18, 2011, the Gulf Coast Environmental Labor Coalition gave notice pursuant to the citizen suit provision of the Federal Clean Air Act that it intended to file a lawsuit against OG&E seeking both injunctive relief to enjoin excess opacity emissions from OG&E's Muskogee and Sooner generating stations and the assessment of civil penalties for alleged past violations of the applicable opacity limits. Because the Consent Order addresses the same alleged violations, the legal action by the ODEQ will prevent the Gulf Coast Environmental Labor Coalition from filing the lawsuit against OG&E. Neither the ODEQ action against OG&E in state court nor the Consent Order preclude the EPA from seeking additional relief in connection with the allegations of opacity emissions not in accordance with applicable new source performance standards that are contained in the previously disclosed notice of violation issued to OG&E on April 26, 2011.
3. Patent Infringement Case. On September 16, 2011, TransData, Inc., a Texas corporation, sued OG&E in the Western District of Oklahoma, accusing OG&E of infringing three of their U.S. patents by using OG&E's General Electric "smart" meters with Silver Spring Networks wireless modules. The complaint seeks a judgment of infringement, unspecified damages, a permanent injunction, costs and attorneys fees. OG&E was served with the complaint on September 21, 2011 and has notified both General Electric and Silver Springs Network of the lawsuit and its intent to seek indemnity from those companies for any damages that it may incur from this lawsuit. TransData, Inc. sought to consolidate its OG&E lawsuit with similar lawsuits in the Eastern District of Texas, however, on December 13, 2011, the TransData, Inc. cases were consolidated in the Western District of Oklahoma. OG&E has filed a motion for extension of time to answer the complaint. On December 30, 2011 OG&E and General Electric agreed to terms for General Electric to provide OG&E with an unqualified defense in the matter and to indemnify OG&E for costs, expenses and damages awarded against OG&E subject to a reservation of rights. While OG&E cannot predict the outcome of this lawsuit at this time, OG&E intends to vigorously defend this action and believes that its ultimate resolution will not be material to OG&E's financial position or results of operations.
Item 4.
Item 4. Mine Safety Disclosures.
Not Applicable.
PART II
Item 5.
Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.
Currently, all of OG&E's outstanding common stock is held by OGE Energy. Therefore, there is no public trading market for OG&E's common stock.
In 2010, OG&E declared dividends to OGE Energy of $60.2 million. In 2011 and 2009, OG&E declared no dividends to OGE Energy.
Item 6.
Item 6. Selected Financial Data
HISTORICAL DATA
(A) Capitalization ratios = [Total stockholder's equity / (Total stockholder's equity + Long-term debt + Long-term debt due within one year)] and [(Long-term debt + Long-term debt due within one year) / (Total stockholder's equity + Long-term debt + Long-term debt due within one year)].
(B) For purposes of computing the ratio of earnings to fixed charges, (i) earnings consist of pre-tax income plus fixed charges, less allowance for borrowed funds used during construction and (ii) fixed charges consist of interest on long-term debt, related amortization, interest on short-term borrowings and a calculated portion of rents considered to be interest.
Item 7.
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations.
Introduction
OG&E generates, transmits, distributes and sells electric energy in Oklahoma and western Arkansas. Its operations are conducted through OG&E and are subject to regulation by the OCC, the APSC and the FERC. OG&E is a wholly-owned subsidiary of OGE Energy which is an energy and energy services provider offering physical delivery and related services for both electricity and natural gas primarily in the south central United States. 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.
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 in a safe, reliable and efficient manner. 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 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 and promote demand-side management programs. 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. 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. OG&E is customer focused and strives to provide excellent customer service.
Summary of Operating Results
2011 compared to 2010. OG&E reported net income of $263.3 million and $215.7 million, respectively, in 2011 and 2010, an increase of $47.6 million, or 22.1 percent, primarily due to a higher gross margin primarily from warmer weather in OG&E's service territory partially offset by higher other operation and maintenance expense, higher interest expense and higher income tax expense. Income tax expense was higher due to higher pre-tax income which more than offset the effects of the one-time, non-cash charge in 2010 of $7.0 million related to the elimination of the tax deduction for the Medicare Part D subsidy (as previously reported in OG&E's 2010 Form 10-K).
2010 compared to 2009. OG&E reported net income of $215.7 million and $200.4 million in 2010 and 2009, respectively, an increase of $15.3 million, or 7.6 percent, due to a higher gross margin primarily due to rate increases and riders and warmer weather in OG&E's service territory partially offset by higher other operation and maintenance expense, higher depreciation and amortization expense and higher income tax expense mainly attributable to higher pre-tax income and the elimination of the tax deduction for the Medicare Part D subsidy discussed above.
Recent Developments and Regulatory Matters
Global Climate Change, Environmental Concerns and Related Opportunities
It is uncertain at this time whether, and in what form, Congress will adopt legislation to restrict greenhouse gas emissions. In the absence of such legislation, the EPA has taken steps to regulate greenhouse gas emissions. Future legislation or rules could require reductions of carbon dioxide and other greenhouse gas emissions from generation facilities. This 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. The OG&E service territory is in central Oklahoma and borders one of the nation's best wind resource areas. Uncertainty surrounding global climate change and environmental concerns related to new coal-fired generation development is changing the mix of the potential sources of new generation in the region. Adoption of renewable portfolio standards would be expected to increase the region's reliance on wind generation and other renewables. OG&E has leveraged its advantageous geographic position to develop renewable energy resources and transmission to deliver the renewable energy. In January 2012, the Crossroads wind farm was placed in service and added to OG&E's wind power portfolio, which now includes potential wind generation of up to of 780 MWs (including wind power purchase agreements). In addition, the SPP regional transmission organization has begun to address the relative lack 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 constraints.
OG&E Crossroads Wind Farm
On July 29, 2010, OG&E received an order from the OCC authorizing OG&E to recover from Oklahoma customers the cost to construct Crossroads, with the rider being implemented as the individual turbines are placed in service. The Crossroads wind farm was fully in service in January 2012. As part of this project, on June 16, 2011, OG&E entered into an interconnection agreement with the SPP for Crossroads which allowed Crossroads to interconnect at 227.5 MWs.
2011 Oklahoma Rate Case Filing
As part of the Joint Stipulation and Settlement Agreement reached in OG&E's 2009 Oklahoma rate case filing, the parties agreed that OG&E would file a rate case on or before June 30, 2011. On May 27, 2011, OG&E requested an extension until the end of July 2011 for filing the Oklahoma rate case. On July 28, 2011, OG&E filed its application with the OCC requesting an annual rate increase of $73.3 million, or a 4.3 percent increase in its rates. OG&E is requesting a return on equity of 11.00 percent based on a common equity percentage of 53 percent. Each 0.10 percent change in the requested return on equity affects the requested rate increase by $3.0 million. In its application, OG&E seeks to recover increases in its operating costs and to begin earning on approximately $500 million of new capital investments made on behalf of its Oklahoma customers during the previous two and one-half years. On November 9, 2011, the OCC Staff recommended a $6.2 million annual rate decrease based on a return on equity of 9.81 percent and a common equity percentage of 53 percent. The staff of the Oklahoma Attorney General recommended a return on equity of 9.818 percent and a common equity percentage of 49.5 percent. The staff of the Oklahoma Attorney General did not recommend a specific revenue requirement, but OG&E believes that adoption of the staff of the Oklahoma Attorney General's recommendations would result in a rate decrease. The Oklahoma Industrial Electric Consumers recommended a $56 million annual rate decrease based on a return on equity of 9.5 percent and a common equity percentage of 48 percent. OG&E filed rebuttal testimony on November 29, 2011 on the revenue requirement testimony filed by the parties on November 9, 2011. On November 16, 2011, the parties filed cost-of-service and rate design testimony and OG&E filed rebuttal testimony in those areas on December 2, 2011. The hearing in this matter began on December 13, 2011. OG&E expects to receive an order from the OCC in the first quarter of 2012.
Contract and Wind Energy Purchase Agreement Filing
On December 1, 2011, OG&E filed an application with the OCC requesting approval of a 20-year agreement that is intended to provide wind power to help meet the current and future power generation needs of Oklahoma State University. The project calls for OG&E to contract with NextEra Energy to build a 60 MW wind farm near Blackwell, Oklahoma, to support the Oklahoma State University project in which NextEra will build, own and operate the wind farm and OG&E will purchase the electric output. A procedural schedule has not yet been established in this matter. OG&E expects to receive a decision from the OCC in the first quarter of 2012.
2012 Outlook
OG&E's 2012 earnings guidance will be provided following a final order in the Oklahoma general rate case. OG&E anticipates the final order during March 2012.
Results of Operations
The following discussion and analysis presents factors that affected OG&E's results of operations for the years ended December 31, 2011, 2010 and 2009 and OG&E's financial position at December 31, 2011 and 2010. 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.
In reviewing its operating results, OG&E believes that it is appropriate to focus on operating income as reported in its Statements of Income as operating income indicates the ongoing profitability of OG&E excluding the cost of capital and income taxes.
(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.
2011 compared to 2010. OG&E's operating income increased $58.6 million, or 14.2 percent, in 2011 as compared to 2010 primarily due to a higher gross margin partially offset by higher other operation and maintenance expense.
Gross Margin
Gross margin was $1,198.0 million in 2011 as compared to $1,109.7 million in 2010, an increase of $88.3 million, or 8.0 percent. The gross margin increased primarily due to:
•
warmer weather in OG&E's service territory, which increased the gross margin by $27.4 million;
•
increased price variance, which included revenues from various rate riders, including the Windspeed transmission line rider, the Oklahoma demand program rider, the Smart Grid rider, the system hardening rider, the Oklahoma storm recovery rider, the Crossroads rider and the OU Spirit rider, and higher revenues from sales and customer mix, which increased the gross margin by $23.9 million;
•
higher transmission revenue 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, which increased the gross margin by $15.3 million;
•
new customer growth in OG&E's service territory, which increased the gross margin by $13.1 million;
•
revenues from the Arkansas rate increase, which increased the gross margin by $6.0 million;
•
higher demand and related revenues by non-residential customers in OG&E's service territory, which increased the gross margin by $5.0 million; and
•
higher revenues related to the renewal of the Arkansas Valley Electric Cooperative contract (see Note 13 of Notes to Financial Statements), which increased the gross margin by $3.1 million.
These increases in the gross margin were partially offset by a credit to customers related to the settlement of OG&E's 2009 fuel adjustment clause review (see Note 13 of Notes to Financial Statements), which decreased the gross margin by $5.7 million.
Cost of goods sold for OG&E consists of fuel used in electric generation, purchased power and transmission related charges. Fuel expense was $775.0 million in 2011 as compared to $771.0 million in 2010, an increase of $4.0 million, or 0.5 percent, primarily due to higher generation primarily due to warmer weather in OG&E's service territory. OG&E's electric generating capability is fairly evenly divided between coal and natural gas and provides for flexibility to use either fuel to the best economic advantage for OG&E and its customers. In 2011, OG&E's fuel mix was 58 percent coal, 39 percent natural gas and three percent wind. In 2010, OG&E's fuel mix was 55 percent coal, 42 percent natural gas and three percent wind. Purchased power costs were $230.7 million in 2011 as compared to $226.5 million in 2010, an increase of $4.2 million, or 1.9 percent, primarily due to an increase in short-term power purchases partially offset by a decrease in purchases in the energy imbalance service market and a decrease in cogeneration cost.
Variances in the actual cost of fuel used in electric generation and certain purchased power costs, as compared to the fuel component included in the cost-of-service for ratemaking, are passed through to OG&E's customers through fuel adjustment clauses. The fuel adjustment clauses are subject to periodic review by the OCC, the APSC and the FERC. The OCC, the APSC and the FERC have authority to review the appropriateness of gas transportation charges or other fees OG&E pays to Enogex.
Operating Expenses
Other operation and maintenance expenses were $436.0 million in 2011 as compared to $418.1 million in 2010, an increase of $17.9 million, or 4.3 percent. The increase in other operation and maintenance expenses was primarily due to:
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an increase of $15.5 million allocated from the holding company primarily related to payroll and benefits expense, contract technical and construction services and contract professional services;
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an increase of $12.1 million in salaries and wages expense primarily due to salary increases in 2011, increased incentive compensation expense and increased overtime expense primarily due to storms in April and August 2011;
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an increase of $4.6 million in other marketing and sales expense related to demand-side management initiatives, which expenses are being recovered through a rider;
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an increase of $3.1 million in uncollectible expense;
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an increase of $1.6 million in fleet transportation expense primarily due to higher fuel costs in 2011;
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an increase of $1.3 million in temporary labor expense; and
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an increase of $1.2 million in SPP administration fees.
These increases in other operation and maintenance expenses were partially offset by:
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a decrease of $9.8 million in employee benefits expense primarily due to a decrease in postretirement benefits expense related to amendments to OGE Energy's retiree medical plan adopted in January 2011 (see Note 11 of Notes to Financial Statements) partially offset by a modification to OG&E's pension tracker and a decrease in worker's compensation accruals in 2011;
•
a decrease of $5.0 million in injuries and damages expense primarily due to higher reserves on claims in 2010; and
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a decrease of $2.9 million related to decreased spending on vegetation management partially related to system hardening, which expenses are being recovered through a rider.
Additional Information
Allowance for Equity Funds Used During Construction. Allowance for equity funds used during construction was $20.4 million in 2011 as compared to $11.4 million in 2010, an increase of $9.0 million, or 78.9 percent, primarily due to higher levels of construction costs for Crossroads.
Other Income. Other income was $8.0 million in 2011 as compared to $6.5 million in 2010, an increase of $1.5 million, or 23.1 percent. The increase in other income was primarily due to a benefit of $5.6 million associated with the tax gross-up of allowance for equity funds used during construction partially offset by increased losses of $4.2 million recognized in the guaranteed flat bill program in 2011 from higher than expected usage resulting from warmer weather.
Other Expense. Other expense was $8.4 million in 2011 as compared to $1.6 million in 2010, an increase of $6.8 million, primarily due to an increase in charitable contributions of $6.4 million as the holding company made the charitable contributions in 2010.
Interest Expense. Interest expense was $111.6 million in 2011 as compared to $103.4 million in 2010, an increase of $8.2 million, or 7.9 percent, primarily due to a $14.0 million increase related to the issuance of long-term debt in June 2010 and May 2011. This increase in interest expense was partially offset by:
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a $4.9 million decrease in interest expense due to a higher allowance for borrowed funds used during construction primarily due to construction costs for Crossroads; and
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a $1.4 million decrease in interest expense in 2011 due to interest to customers related to the fuel over recovery balance in 2010.
Income Tax Expense. Income tax expense was $117.9 million in 2011 as compared to $111.0 million in 2010, an increase of $6.9 million, or 6.2 percent. The increase in income tax expense was primarily due to higher pre-tax income in 2011 as compared to 2010. This increase in income tax expense was partially offset by:
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the one-time, non-cash charge in 2010 for the elimination of the tax deduction for the Medicare Part D subsidy;
•
the write-off of previously recognized Oklahoma investment tax credits in 2010 primarily due to expenditures no longer eligible for the Oklahoma investment tax credit related to the change in the tax method of accounting for capitalization of repair expenditures; and
•
higher Oklahoma investment tax credits in 2011 as compared to 2010.
2010 compared to 2009. OG&E's operating income increased $59.6 million, or 16.8 percent, in 2010 as compared to 2009 primarily due to a higher gross margin partially offset by higher other operation and maintenance expense and higher depreciation and amortization expense.
Gross Margin
Gross margin was $1,109.7 million in 2010 as compared to $954.9 million in 2009, an increase of $154.8 million, or 16.2 percent. The gross margin increased primarily due to:
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increased price variance, which included revenues from various rate riders, including the Windspeed rider, the OU Spirit rider, the Oklahoma demand program rider and the Smart Grid rider, and higher revenues from the sales and customer mix, which increased the gross margin by $74.5 million;
•
warmer weather in OG&E's service territory resulting in a 25 percent increase in cooling degree days, which increased the gross margin by $46.8 million;
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revenue from the full year effect of the August 2009 Oklahoma rate increase, which increased the gross margin by $24.1 million;
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higher demand and related revenues by non-residential customers in OG&E's service territory, which increased the gross margin by $6.9 million;
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new customer growth in OG&E's service territory, which increased the gross margin by $6.7 million; and
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revenues from the full year effect of the June 2009 Arkansas rate increase, which increased the gross margin by $3.5 million.
These increases in the gross margin were partially offset by lower other revenues due to fewer transmission requests from others on OG&E's system, which decreased the gross margin by $7.7 million.
Fuel expense was $771.0 million in 2010 as compared to $618.5 million in 2009, an increase of $152.5 million, or 24.7 percent, primarily due to higher natural gas prices and increased natural gas generation due to ongoing maintenance at some of OG&E's coal-fired power plants. 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 2010, OG&E's fuel mix was 55 percent coal, 42 percent natural gas and three percent wind. In 2009, OG&E's fuel mix was 60 percent coal, 38 percent natural gas and two percent wind. Purchased power costs were $226.5 million in 2010 as compared to $176.6 million in 2009, an increase of $49.9 million, or 28.3 percent, primarily due to an increase in purchases in the energy imbalance service market to meet OG&E's generation load requirements and an increase in short-term power agreements resulting in short-term spot market purchases.
Operating Expenses
Other operation and maintenance expenses were $418.1 million in 2010 as compared to $348.0 million in 2009, an increase of $70.1 million, or 20.1 percent. The increase in other operation and maintenance expenses was primarily due to:
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an increase of $16.2 million in contract technical and construction services and an increase of $5.2 million in materials and supplies expense primarily attributable to increased spending for ongoing maintenance at some of OG&E's power plants in 2010 as compared to 2009;
•
an increase of $16.2 million in employee benefits expense primarily due to an increase in postretirement benefits due to an increase in medical costs and changes in actuarial assumptions in 2010, a reclassification in May 2009 of 2006 and 2007 pension settlement costs to a regulatory asset, as prescribed in the Arkansas rate case settlement, and an increase in pension expense due to an increase in the amount deferred as a pension regulatory liability in OG&E's Oklahoma jurisdiction resulting from OG&E's 2009 Oklahoma rate case;
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an increase of $9.7 million in allocations from the holding company primarily due to higher contract professional services expense, materials and supplies expense and communication and media services expense;
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an increase of $9.1 million in other marketing and sales expense related to demand-side management initiatives, which expenses are being recovered through a rider;
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an increase of $7.5 million in salaries and wages expense primarily due to salary increases in 2010;
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an increase of $4.8 million due to increased spending on vegetation management related to system hardening, which expenses are being recovered through a rider;
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an increase of $3.4 million in injuries and damages expense primarily due to increased reserves on claims in 2010;
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an increase of $2.1 million in overtime expense due to the storms in January and May 2010; and
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an increase of $1.7 million in temporary labor expense.
These increases in other operation and maintenance expenses were partially offset by a decrease of $3.9 million in incentive compensation expense primarily due to lower accruals in 2010.
Depreciation and amortization expense was $208.7 million in 2010 as compared to $187.7 million in 2009, an increase of $21.0 million, or 11.2 percent, primarily due to additional assets being placed in service, including OU Spirit that was placed in service in November and December 2009 and Windspeed that was placed in service on March 31, 2010.
Additional Information
Allowance for Equity Funds Used During Construction. Allowance for equity funds used during construction was $11.4 million in 2010 as compared to $15.1 million in 2009, a decrease of $3.7 million, or 24.5 percent, primarily due to the completion of OU Spirit in November and December 2009 and Windspeed on March 31, 2010.
Other Income. Other income was $6.5 million in 2010 as compared to $20.4 million in 2009, a decrease of $13.9 million, or 68.1 percent. The decrease in other income was primarily due to:
•
a decrease of $10.0 million due to a decreased level of gains recognized in the guaranteed flat bill program in 2010 from higher than expected usage resulting from warmer weather in addition to more customers participating in the guaranteed flat bill program in 2010; and
•
a decrease of $2.6 million related to the benefit associated with the tax gross-up of allowance for equity funds used during construction.
Other Expense. Other expense was $1.6 million in 2010 as compared to $6.7 million in 2009, a decrease of $5.1 million or 76.1 percent, primarily due to a decrease in charitable contributions in 2010 as the holding company made the charitable contributions in 2010.
Interest Expense. Interest expense was $103.4 million in 2010 as compared to $93.6 million in 2009, an increase of $9.8 million, or 10.5 percent. The increase in interest expense was primarily due to:
•
an $8.2 million increase related to the issuance of $250 million of long-term debt in June 2010; and
•
a $2.8 million increase due to a lower allowance for borrowed funds used during construction in 2010 as compared to 2009.
Income Tax Expense. Income tax expense was $111.0 million in 2010 as compared to $90.0 million in 2009, an increase of $21.0 million, or 23.3 percent, primarily due to:
•
higher pre-tax income in 2010 as compared to 2009;
•
an adjustment for the elimination of the tax deduction for the Medicare Part D subsidy; and
•
the write-off of previously recognized Oklahoma investment tax credits primarily due to expenditures no longer eligible for the Oklahoma investment tax credit related to the change in the tax method of accounting for capitalization of repair expenditures.
These increases in income tax expense were partially offset by an increase in Federal renewable energy credits in 2010 as compared to 2009.
Financial Condition
The balance of Accounts Receivable, Net was $182.4 million and $142.3 million at December 31, 2011 and 2010, respectively, an increase of $40.1 million, or 28.2 percent, primarily due to an increase in billings to OG&E's customers in 2011 while customers received a refund in 2010 for the over collection of fuel
The balance of Advances to Parent was $97.2 million and $68.9 million at December 31, 2011 and 2010, respectively, an increase of $28.3 million, or 41.1 percent, primarily due to proceeds received from issuance of long-term debt in May 2011 partially offset by payments for various transmission projects and Crossroads, bond interest and other operational needs.
The balance of Fuel Inventories was $76.9 million and $134.9 million at December 31, 2011 and 2010, respectively, a decrease of $58.0 million, or 43.0 percent, primarily due to lower coal inventory balances at OG&E from higher coal generation.
The balance of Property, Plant and Equipment in Service was $7,808.8 million and $7,043.6 million at December 31, 2011 and 2010, respectively, an increase of $765.2 million, or 10.9 percent, primarily due to assets placed in service in 2011, including the Crossroads wind farm, distribution and transmission projects and Smart Grid assets.
The balance of Accounts Payable was $193.4 million and $144.1 million at December 31, 2011 and 2010, respectively, an increase of $49.3 million, or 34.2 percent, primarily due to the timing of outstanding checks clearing the bank and an increase in accruals related to Crossroads and Smart Grid projects.
The balance of Fuel Clause Over Recoveries was $7.7 million and $29.9 million at December 31, 2011 and 2010, respectively, a decrease of $22.2 million, or 74.2 percent, primarily due to the fact that the amount billed to retail customers was lower than OG&E's cost of fuel. OG&E's fuel recovery clauses are designed to smooth the impact of fuel price volatility on customers' bills. As a result, OG&E under recovers fuel costs in periods of rising fuel prices above the baseline charge for fuel and over recovers fuel costs when prices decline below the baseline charge for fuel. Provisions in the fuel clauses are intended to allow OG&E to amortize under and over recovery balances.
The balance of Other Current Liabilities was $56.5 million and $40.3 million at December 31, 2011 and 2010, respectively, an increase of $16.2 million, or 40.2 percent, primarily due to the over recovery of various rate riders, primarily the Smart Grid rider.
The balance of Long-Term Debt was $2,039.2 million and $1,790.4 million at December 31, 2011 and 2010, respectively, an increase of $248.8 million, or 13.9 percent, due to the issuance of $250 million of long-term debt in May 2011.
The balance of Accrued Benefit Obligations was $230.8 million and $259.8 million at December 31, 2011 and 2010, respectively, a decrease of $29.0 million, or 11.2 percent, primarily due to amendments to OGE Energy's retiree medical plan adopted in January 2011 (see Note 11 of Notes to Financial Statements) and Pension Plan contributions in 2011 partially offset by net losses for OGE Energy's Pension Plan, restoration of retirement income plan and postretirement benefit plans.
The balance of Deferred Income Taxes was $1,146.0 million and $1,055.3 million at December 31, 2011 and 2010, respectively, an increase of $90.7 million, or 8.6 percent, primarily due to accelerated bonus tax depreciation partially offset by OG&E being in a tax net operating loss position in 2011.
The balance of Regulatory Liabilities was $230.7 million and $193.1 million at December 31, 2011 and 2010, respectively, an increase of $37.6 million, or 19.5 percent, primarily due to increases related to removal obligations for OG&E distribution, transmission and generation assets and Oklahoma pension regulatory liabilities.
Off-Balance Sheet Arrangement
Railcar Lease Agreement
OG&E has a noncancellable operating lease with purchase options, covering 1,392 coal hopper railcars to transport coal from Wyoming to OG&E's coal-fired generation units. Rental payments are charged to Fuel Expense and are recovered through OG&E's tariffs and fuel adjustment clauses. On December 15, 2010, OG&E renewed the lease agreement effective February 1, 2011. At the end of the new lease term, which is February 1, 2016, OG&E has the option to either purchase the railcars at a stipulated fair market value or renew the lease. If OG&E chooses not to purchase the railcars or renew the lease agreement and the actual fair value of the railcars is less than the stipulated fair market value, OG&E would be responsible for the difference in those values up to a maximum of $22.8 million.
OG&E is also required to maintain all of the railcars it has under lease to transport coal from Wyoming and has entered into agreements with Progress Rail Services and WATCO, both of which are non-affiliated companies, to furnish this maintenance.
Liquidity and Capital Resources
Cash Flows
Operating Activities
The increase of $83.6 million, or 18.0 percent, in net cash provided from operating activities in 2011 as compared to 2010 was primarily due to lower fuel refunds at OG&E in 2011 as compared to 2010 and cash received in 2011 from an increase in billings to OG&E's customers due to warmer weather in OG&E's service territory in 2011 partially offset by income tax refunds received in 2010 related to a carry back of the 2008 tax loss resulting from a change in tax method of accounting for capitalization of repair expenditures and accelerated tax bonus depreciation.
The decrease of $114.5 million, or 19.7 percent, in net cash provided from operating activities in 2010 as compared to 2009 was primarily due to higher fuel refunds at OG&E in 2010 as compared to 2009. This decrease in net cash provided from operating activities was partially offset by:
•
income tax refunds received in 2010 related to a carry back of the 2008 tax loss resulting from a change in tax method of accounting for capitalization of repair expenditures and accelerated tax bonus depreciation; and
•
cash received in 2010 from the implementation of rate increases and riders at OG&E.
Investing Activities
The increase of $192.2 million, or 31.9 percent, in net cash used in investing activities in 2011 as compared to 2010 primarily related to higher levels of capital expenditures in 2011 related to various transmission projects and Crossroads. There was an increase of $2.6 million in net cash used in investing activities in 2010 as compared to 2009.
Financing Activities
The increase of $108.6 million, or 79.6 percent, in net cash provided from financing activities in 2011 as compared to 2010 was primarily due to a capital contribution from OGE Energy and a decrease in dividends paid.
The increase of $167.8 million in net cash provided from financing activities in 2010 as compared to 2009 was primarily due to OG&E using the proceeds received from the issuance of $250 million of long-term debt in June 2010 to make payments to OGE Energy partially offset by dividends paid in 2010.
Future Capital Requirements and Financing Activities
OG&E's primary needs for capital are related to acquiring or constructing new facilities and replacing or expanding existing facilities. Other working capital requirements are expected to be primarily related to maturing debt, operating lease obligations, hedging activities, fuel clause under and over recoveries and other general corporate purposes. OG&E generally meets its cash needs through a combination of cash generated from operations, short-term borrowings (through a combination of bank borrowings, commercial paper and borrowings from OGE Energy) and permanent financings.
Capital Expenditures
OG&E's estimates of capital expenditures for the years 2012 through 2016 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.
(A)
These capital expenditures are net of the $130 million Smart Grid grant approved by the U.S. Department of Energy.
(B)
The capital expenditures above exclude any environmental expenditures associated with pollution control equipment related to regional haze requirements due to the uncertainty regarding the timing and costs for such pollution control equipment. OG&E has committed to install low NOX burners at the affected generating units at a cost preliminarily estimated between $70 million and $130 million, but the timing of the installation of such burners is uncertain. The SO2 emissions standards in the EPA's Federal implementation plan 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 Federal implementation plan is being challenged by OG&E and the state of Oklahoma. Neither the outcome of the challenge to the Federal implementation plan nor the timing
and amount of any required capital expenditures can be predicted with any certainty at this time, but such capital expenditures could be significant. For further information, see "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Environmental Laws and Regulations" below.
Additional capital expenditures beyond those identified in the table above, including additional incremental growth opportunities in electric transmission assets, will be evaluated based upon their impact upon achieving OG&E's financial objectives.
Contractual Obligations
The following table summarizes OG&E's contractual obligations at December 31, 2011. See OG&E's Statements of Capitalization and Note 12 of Notes to Financial Statements for additional information.
(A)
Maturities of OG&E's long-term debt during the next five years consist of $110 million in 2016. There are no maturities of OG&E's long-term debt in years 2012, 2013, 2014 or 2015.
(B)
Includes expected recoveries of costs incurred for OG&E's railcar operating lease obligations, OG&E's cogeneration expected energy payments, OG&E's minimum fuel purchase commitments and OG&E's expected wind purchase commitments.
OG&E also has 720 MWs of QF contracts to meet its current and future expected customer needs. OG&E will continue reviewing all of the supply alternatives to these QF contracts that minimize the total cost of generation to its customers, including exercising its options (if applicable) to extend these QF contracts at pre-determined rates.
Variances in the actual cost of fuel used in electric generation (which includes the operating lease obligations for OG&E's railcar leases shown above) and certain purchased power costs, as compared to the fuel component included in the cost-of-service for ratemaking, are passed through to OG&E's customers through fuel adjustment clauses. Accordingly, while the cost of fuel related to operating leases and the vast majority of minimum fuel purchase commitments of OG&E noted above may increase capital requirements, such costs are recoverable through fuel adjustment clauses and have little, if any, impact on net capital requirements and future contractual obligations. The fuel adjustment clauses are subject to periodic review by the OCC, the APSC and the FERC.
Pension and Postretirement Benefit Plans
At December 31, 2011, 38.6 percent of the Pension Plan investments were in listed common stocks with the balance primarily invested in bonds, debentures and notes, U.S. Government securities, a commingled fund and a common collective trust as presented in Note 11 of Notes to Financial Statements. In 2011, asset returns on the Pension Plan were 1.4 percent due to the gains in fixed income investments partially offset by losses in equity investments in 2011. During the same time, corporate bond yields, which are used in determining the discount rate for future pension obligations, have continued to decline. During each of 2011 and 2010, OGE Energy made contributions to its Pension Plan of$50 million, of which $47 million in each of 2011 and 2010 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 2012, OGE Energy may contribute up to $35 million to its Pension Plan, of which $33 million is expected to be OG&E's portion. OGE Energy could be required to make additional contributions if the value of its pension trust and postretirement benefit plan trust assets are adversely impacted by a major market disruption
in the future.
The following table presents the status of OG&E's portion of OGE Energy's Pension Plan, the Restoration of Retirement Income Plan and the postretirement benefit plans at December 31, 2011 and 2010. 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.
Security Ratings
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 ratings 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 OG&E could also lead to higher long-term borrowing costs and, if below investment grade, would require OG&E to post cash collateral or letters of credit.
A security rating is not a recommendation to buy, sell or hold securities. Such rating may be subject to revision or withdrawal at any time by the credit rating agency and each rating should be evaluated independently of any other rating.
Future financing requirements may be dependent, to varying degrees, upon numerous factors such as general economic conditions, abnormal weather, load growth, commodity prices, acquisitions of other businesses and/or development of projects, 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.
2011 Capital Requirements, Sources of Financing and Financing Activities
Total capital requirements, consisting of capital expenditures and maturities of long-term debt, were $794.8 million and contractual obligations, net of recoveries through fuel adjustment clauses, were $90.1 million resulting in total net capital requirements and contractual obligations of $884.9 million in 2011, of which $6.4 million was to comply with environmental regulations. This compares to net capital requirements of $603.4 million and net contractual obligations of $92.7 million totaling $696.1 million in 2010, of which $2.1 million was to comply with environmental regulations.
In 2011, OG&E's sources of capital were cash generated from operations and proceeds from the issuance of long and 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 "Financial Condition" for a discussion of significant changes in net working capital requirements as it pertains to operating cash flow and liquidity.
OG&E Issuance of Long-Term Debt
On May 24, 2011, OG&E issued $250 million of 5.25% senior notes due May 15, 2041. The proceeds from the issuance were added to OGE Energy's general funds and were used to repay short-term debt. OG&E expects to issue additional long-term debt from time to time when market conditions are favorable and when the need arises.
Potential Collateral Requirements
On July 21, 2010, President Obama signed into law the Dodd-Frank Act. While the Dodd-Frank Act is focused primarily on the regulation and oversight of financial institutions, it also provides for a new regulatory regime for derivatives, including mandatory clearing of certain swaps, exchange trading, margin requirements and other transparency requirements. The Dodd-Frank Act contains provisions that should exempt certain derivatives end-users from much of the clearing requirements. It is unclear whether end-users will be exempt from the margin requirements. The scope of the margin requirements and the end user exemption is uncertain and will be further defined through rulemaking proceedings at the Commodity Futures Trading Commission and the Securities and Exchange Commission. Further, although OG&E may qualify for certain exemptions, its derivative counterparties may be subject to new capital, margin and business conduct requirements imposed as a result of the new legislation, which may increase OG&E's transaction costs or make it more difficult to enter into hedging transactions on favorable terms. OG&E's inability to enter into hedging 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. If, as a result of the rulemaking associated with the Dodd-Frank Act, OG&E does not qualify for any exemptions related to clearing requirements and/or are subject to margin requirements, OG&E would be subject to higher costs and increased collateral requirements. The impact of the provisions of the Dodd-Frank Act on OG&E cannot be determined pending issuance of the final implementing regulations.
Future Sources of Financing
Management expects that cash generated from operations, proceeds from the issuance of long and short-term debt and funds received from OGE Energy (from proceeds from the sales of its common stock to the public through OGE Energy's Automatic Dividend Reinvestment and Stock Purchase Plan or other offerings) will be adequate over the next three years to meet anticipated cash needs and to fund future growth opportunities. OG&E utilizes short-term borrowings (through a combination of bank borrowings, commercial paper and borrowings from OGE Energy) to satisfy temporary working capital needs and as an interim source of financing capital expenditures until permanent financing is arranged.
Short-Term Debt and Credit Facility
At December 31, 2011 and 2010, there were $97.2 million and $68.9 million, respectively, in net outstanding advances to OGE Energy. OG&E has an intercompany borrowing agreement with OGE Energy whereby OG&E has access to up to $250 million of OGE Energy's revolving credit amount. This agreement has a termination date of January 9, 2013. At December 31, 2011, there were no intercompany borrowings under this agreement. In December 2011, OG&E entered into a new $400 million unsecured five-year revolving credit facility which is available to back up OG&E's commercial paper borrowings and to provide revolving credit borrowings. This bank facility can also be used as a letter of credit facility. At December 31, 2011, there was $2.2 million supporting letters of credit at a weighted-average interest rate of 0.53 percent. There were no outstanding borrowings under this revolving credit agreement and no outstanding commercial paper borrowings at December 31, 2011. At December 31, 2011, OG&E had $397.8 million of net available liquidity under its revolving credit agreement. OG&E has the necessary regulatory approvals to incur up to $800 million in short-term borrowings at any one time for a two-year period beginning January 1, 2011 and ending December 31, 2012. At December 31, 2011, OG&E had less than $0.1 million in cash and cash equivalents. See Note 10 of Notes to Financial Statements for a discussion of OG&E's short-term debt activity.
Expected Issuance of Long-Term Debt
OG&E expects to issue approximately $250 million of long-term debt in late 2012, depending on market conditions, to fund capital expenditures, repay short-term borrowings and for general corporate purposes.
Critical Accounting Policies and Estimates
The Financial Statements and Notes to Financial Statements contain information that is pertinent to Management's Discussion and Analysis. In preparing the Financial Statements, management is required to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and contingent liabilities at the date of the Financial Statements and the reported amounts of revenues and expenses during the reporting period. Changes to these assumptions and estimates could have a material effect on OG&E's Financial Statements. However, OG&E believes it has taken reasonable, but conservative, positions where assumptions and estimates are used in order to minimize the negative financial impact to OG&E that could result if actual results vary from the assumptions and estimates. In management's opinion, the areas of OG&E where the most significant judgment is exercised includes the valuation of Pension Plan assumptions, income taxes, contingency reserves, asset retirement obligations, fair value and cash flow hedges, the allowance for uncollectible accounts receivable, the valuation of regulatory assets and liabilities and unbilled revenues. The selection, application and disclosure of the following critical accounting estimates have been discussed with OGE Energy's Audit Committee. OG&E discusses its significant accounting
policies, including those that do not require management to make difficult, subjective, or complex judgments or estimates, in Note 1 of Notes to Financial Statements.
Pension and Postretirement Benefit Plans
OGE Energy has a Pension Plan that covers substantially all 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 substantially all 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.
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, claims made by third parties, environmental actions or the action of various regulatory 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, management, after consultation with legal counsel, does not currently anticipate that liabilities arising out of these pending or threatened lawsuits, claims and contingencies will 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 99 years. In the fourth quarter of 2011, OG&E recorded an asset retirement obligation for $13.0 million related to its Crossroads wind farm. Beginning December 1, 2011, OG&E began to amortize the value of the related asset retirement obligation
asset over the estimated remaining life of 50 years. OG&E also has certain asset retirement obligations that have not been recorded because OG&E determined that these assets, primarily related to OG&E's power plant sites, have indefinite lives.
Hedging Policies
OG&E designates as cash flow hedges derivatives used to manage commodity price risk exposure for its natural gas exposure associated with a wholesale power sales contract that expires in 2013. Hedges are evaluated prior to execution with respect to the impact on the volatility of forecasted earnings and are evaluated at least quarterly after execution for the impact on earnings.
From time to time, OG&E may engage in cash flow and fair value hedge transactions to modify interest rate exposure and not to modify the overall leverage of the debt portfolio.
Regulatory Assets and Liabilities
OG&E, as a regulated utility, is subject to accounting principles for certain types of rate-regulated activities, which provide that certain actual or anticipated costs that would otherwise be charged to expense can be deferred as regulatory assets, based on the expected recovery from customers in future rates. Likewise, certain actual or anticipated credits that would otherwise reduce expense can be deferred as regulatory liabilities, based on the expected flowback to customers in future rates. Management's expected recovery of deferred costs and flowback of deferred credits generally results from specific decisions by regulators granting such ratemaking treatment.
OG&E records certain actual or anticipated costs and obligations as regulatory assets or liabilities if it is probable, based on regulatory orders or other available evidence, that the cost or obligation will be included in amounts allowable for recovery or refund in future rates. The benefit obligations regulatory asset is comprised of expenses recorded which are probable of future recovery and that have not yet been recognized as components of net periodic benefit cost, including net loss, prior service cost and net transition obligation.
Unbilled Revenues
OG&E reads its customers' meters and sends bills to its customers throughout each month. As a result, there is a significant amount of customers' electricity consumption that has not been billed at the end of each month. Unbilled revenue is presented in Accrued Unbilled Revenues on the Balance Sheets and in Operating Revenues on the Statements of Income based on estimates of usage and prices during the period. At December 31, 2011, 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, 2011 and 2010, Accrued Unbilled Revenues were $59.3 million and $56.8 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. Beginning in August 2009 and going forward, there was a change in the provision calculation as a result of the Oklahoma rate case whereby the portion of the uncollectible provision related to fuel is being recovered through the fuel adjustment clause. Due to the extremely hot weather in OG&E's service territory in 2011, OG&E recorded an additional amount of uncollectible expense anticipating higher customer defaults. At December 31, 2011, 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 $3.7 million and $1.6 million at December 31, 2011 and 2010, respectively.
Accounting Pronouncement
See Note 2 of Notes to Financial Statements for a discussion of a recently issued accounting pronouncement that is applicable to OG&E.
Commitments and Contingencies
Except as disclosed otherwise in this Form 10-K, management, after consultation with legal counsel, does not currently anticipate that liabilities arising out of these pending or threatened lawsuits, claims and contingencies will 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 of this Form 10-K for a discussion of OG&E's commitments and contingencies.
Environmental Laws and Regulations
The activities of OG&E are subject to stringent and complex Federal, state and local laws and regulations governing environmental protection including the discharge of materials into the environment. These laws and regulations can restrict or impact OG&E's business activities in many ways, such as restricting the way it can handle or dispose of its wastes, requiring remedial action to mitigate pollution conditions that may be caused by its operations or that are attributable to former operators, regulating future construction activities to mitigate harm to threatened or endangered species and requiring the installation and operation of pollution control equipment. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial requirements and the issuance of orders enjoining future operations. OG&E believes that its operations are in substantial compliance with current Federal, state and local environmental standards.
Environmental regulation can increase the cost of planning, design, initial installation and operation of OG&E's facilities. Historically, OG&E's total expenditures for environmental control facilities and for remediation have not been significant in relation to its financial position or results of operations. OG&E believes, however, that it is reasonably likely that the trend in environmental legislation and regulations will continue towards more restrictive standards. Compliance with these standards is expected to increase the cost of conducting business.
OG&E expects that environmental expenditures necessary to comply with the environmental laws and regulations discussed below will qualify as part of a pre-approval plan to handle state and Federally mandated environmental upgrades which will be recoverable in Oklahoma from OG&E's retail customers under House Bill 1910, which was enacted into law in May 2005.
Of OG&E's capital expenditures budgeted for 2012 and 2013, $33.7 million and $35.3 million, respectively, are to comply with environmental laws and regulations. OG&E's management believes that all of its operations are in substantial compliance with current Federal, state and local environmental standards. It is estimated that OG&E's total expenditures for capital, operating, maintenance and other costs associated with environmental quality will be $51.6 million in 2012 as compared to $24.0 million in 2011. Management continues to evaluate its compliance with existing and proposed environmental legislation and regulations and implement appropriate environmental programs in a competitive market.
Air
Federal Clean Air Act Overview
OG&E’s 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. These regulations are intended to protect visibility in certain national parks and wilderness areas throughout the United States. In Oklahoma, the Wichita Mountains are the only area covered under the regulation. However, Oklahoma's impact on parks in other states must also be evaluated.
As required by the Federal regional haze rule, the state of Oklahoma evaluated the installation of BART to reduce emissions that cause or contribute to regional haze from certain sources within the state that were built between 1962 and 1977. Certain of
OG&E’s units at the Horseshoe Lake, Seminole, Muskogee and Sooner generating stations were evaluated for BART. On February 18, 2010, Oklahoma submitted its SIP to the EPA, which set forth the state's plan for compliance with the Federal regional haze rule. The SIP was subject to the EPA's review and approval.
The Oklahoma SIP included requirements for reducing emissions of NOX and SO2 from OG&E's seven BART-eligible units at the Seminole, Muskogee and Sooner generating stations. The SIP also included a waiver from BART requirements for all eligible units at the Horseshoe Lake generating station based on air modeling that showed no significant impact on visibility in nearby national parks and wilderness areas. The SIP concluded that BART for reducing NOX emissions at all of the subject units should be the installation of low NOX burners (overfire air and 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 cost of installing and operating these NOX controls on all covered units, based on recent industry experience and past projects, will be between $70 million and $130 million. With respect to SO2 emissions, the SIP included an agreement between the ODEQ and OG&E that established BART for SO2 control at four 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 rejected portions of the Oklahoma SIP and issued a Federal implementation plan. While the EPA accepted Oklahoma's BART determination for NOX in the SIP, it rejected the SO2 BART determination with respect to the four coal-fired units at the Sooner and Muskogee generating stations. In its place, the EPA is 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 cost OG&E more than $1.0 billion. OG&E and the state of Oklahoma expect to file an administrative stay request with the EPA. OG&E and the state of Oklahoma have also announced that they intend to petition for review of this determination in the U.S. Court of Appeals for the Tenth Circuit. Neither the outcome of the appeal nor the timing and amount of any required expenditures for pollution control equipment can be predicted with any certainty at this time.
Cross-State Air Pollution Rule
On July 7, 2011, the EPA finalized its Cross-State Air Pollution Rule to replace the former Clean Air Interstate Rule that was remanded by a Federal court as a result of legal challenges. The final rule requires 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 makes 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 is required to reduce ozone-season NOX emissions from its electrical generating units within the state beginning in 2012. The Cross-State Air Pollution Rule is currently being 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 and requested proposals for accelerated briefing to allow the merits of the case to be heard by April 2012. On February 6, 2012, the EPA issued a notice indicating that the supplemental rule is also included in the stay discussed above. OG&E cannot predict the outcome of such challenges and is evaluating what emission controls would be necessary to meet the standards, its ability to comply with the standards in the timeframe proposed by the EPA and the associated costs, which could be significant.
Hazardous Air Pollutants Emission Standards
On December 16, 2011, the EPA signed the Maximum Achievable Control Technology regulations governing emissions of certain hazardous air pollutants from electric generating units. The final rule includes numerical standards for particulate matter (as a surrogate for toxic metals), hydrogen chloride and mercury emissions from coal-fired boilers. In addition, the regulations include work practice standards for dioxins and furans. Compliance is required within three years after the effective date of the rule with a possibility of a one year extension. The effective date of the rule has not been established, but it is expected to be during the second quarter of 2012. The final rule could be appealed after it is published. OG&E cannot predict the outcome of any such appeals and is evaluating the regulations and what emission controls would be necessary to meet the standards and the associated costs, which could be significant.
Notice of Violation
In July 2008, OG&E received a request for information from the EPA regarding Federal Clean Air Act compliance at OG&E's Muskogee and Sooner generating plants. In recent years, the EPA has issued similar requests to numerous other electric utilities seeking to determine whether various maintenance, repair and replacement projects should have required permits under the Federal Clean Air Act's new source review process. In January 2012, OG&E received a supplemental request for an update
of the previously provided information and for some additional information not previously requested. OG&E believes it has acted in full compliance with the Federal Clean Air Act and new source review process and is cooperating with the EPA. On April 26, 2011, the EPA issued a notice of violation alleging that 13 projects that 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 (See Part I, Item 3 - Legal Proceedings - Opacity Notice for a related discussion). OG&E has met with the EPA regarding the notice but cannot predict at this time what, if any, further actions may be necessary as a result of the notice. The EPA could seek to require OG&E to install additional pollution control equipment and pay fines and significant penalties as a result of the allegations in the notice of violation. Section 113 of the Federal Clean Air Act (along with the Federal Civil Penalties Inflation Adjustment Act of 1996) provides for civil penalties as much as $37,500 per day for each violation.
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. On June 2, 2010, the EPA released its final rule strengthening its NAAQS for SO2. The final rule revokes the existing 24-hour and annual standards and establishes a new lower one-hour standard at a level of 75 parts per billion. The EPA intends to complete attainment designations within two years of promulgation of the revised SO2 standard, which is expected by June 2012. States with areas designated nonattainment in 2012 would need to submit a SIP to the EPA by early 2014 outlining actions that those states will take to meet the EPA's revised standards on or before August 2017. OG&E will continue to monitor the EPA's attainment designation activities.
On January 25, 2010, the EPA released a rule strengthening the NAAQS for oxides of nitrogen as measured by nitrogen dioxide which became effective March 26, 2011. The rule establishes a new one-hour standard and monitoring requirements, as well as an approach for implementing the new standard. Oklahoma is currently in attainment with the new standard and it is anticipated that Oklahoma will be designated "unclassifiable" in 2012 because the new monitoring requirements will not yet be fully implemented. After the new monitoring network is deployed and has collected three years of air quality data, the EPA will re-designate areas in 2016 or 2017 based on the new data. It is currently anticipated that Oklahoma will be designated "attainment" at that time.
On September 21, 2006, the EPA lowered the 24-hour fine particulate NAAQS while retaining the annual NAAQS at its existing level and promulgated a new standard for inhalable coarse particulates. Based on past monitoring data, it appears that Oklahoma may be able to remain in attainment with these standards. However if parts of Oklahoma do become "non-attainment", reductions in emissions from OG&E's coal-fired boilers could be required which may result in significant capital and operating expenditures.
The EPA has designated Oklahoma as being "in attainment" with the current NAAQS for ozone. In March 2008, the EPA issued a final rule lowering the ambient primary and secondary ozone standards NAAQS from current levels. Before Oklahoma's designations of areas as attaining or not attaining the 2008 ozone standards were complete, the EPA announced an intent to reconsider these standards and issue even lower ozone NAAQS. President Obama, however, requested that the EPA refrain from issuing revised standards until 2013. The EPA has indicated that it will comply with the President's request. As a result, it is expected that Oklahoma will proceed with the designation of areas as attaining or not attaining the ozone standards established in the 2008 rule. Neither the outcome nor timing of the ozone NAAQS attainment area designation process nor its impact on OG&E can be determined with any certainty at this time.
Acid Rain Program
The Federal Clean Air Act includes an Acid Rain Program. The goal of the Acid Rain Program is to achieve environmental and public health benefits through reductions in SO2 and NOX emissions, which are the primary causes of acid rain. To achieve this goal, the program employs both traditional and market-based approaches for controlling air pollution.
The Acid Rain Program introduces an allowance trading system that uses the free market to reduce pollution. Under this system, affected utility units are allocated allowances based on their historic fuel consumption and a specific emissions rate. Each allowance permits a unit to emit one ton of SO2 from the chimney during or after a specified year. For each ton of SO2 emitted in a given year, one allowance is retired, that is, it can no longer be used. Allowances may be bought, sold or banked.
During Phase II of the program (now in effect), the Federal Clean Air Act set a permanent ceiling (or cap) of 8.95 million total annual allowances allocated to utilities. This cap firmly restricts emissions and ensures that environmental benefits will be achieved and maintained. Due to OG&E's earlier decision to burn low sulfur coal, these restrictions have had no significant financial impact.
The Acid Rain Program also focuses on one set of sources that emit NOX, coal-fired electric utility boilers. As with the SO2 emission reduction requirements, the NOX program was implemented in two phases, beginning in 1996 and 2000. The NOX program embodies many of the same principles of the SO2 trading program. However, it does not cap NOX emissions as the SO2 program does, nor does it utilize an allowance trading system.
Emission limitations for NOX focus on the emission rate to be achieved (expressed in pounds of NOX per MMBtu of heat input). In general, two options for compliance with the emission limitations are provided: compliance with an individual emission rate for a boiler; or averaging of emission rates over two or more units to meet an overall emission rate limitation.
Since becoming subject to the Acid Rain Program, OG&E has met all obligations and limitations requirements.
Climate Change and Greenhouse Gas Emissions
Emissions of greenhouse gases, including carbon dioxide, sulfur hexafluoride and methane, may be contributing to 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. 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.
In the absence of new Federal legislation, the EPA is regulating greenhouse gas emissions from stationary sources using its existing legal authority. On September 22, 2009, the EPA announced the adoption of the first 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. Pursuant to the rule, OG&E began collecting data on January 1, 2010 and submitted its first annual report to the EPA by the September 30, 2011 deadline. OG&E already reports quarterly its carbon dioxide emissions from generating units subject to the Federal Acid Rain Program.
On June 3, 2010, the EPA issued a final rule that makes certain sources subject to permitting requirements for greenhouse gas emissions. This rule now 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 may have to install best available control technology to control greenhouse gas emissions pursuant to this rule. Also, in December 2010, the EPA entered into an agreement to settle litigation brought by states and environmental groups whereby the EPA agreed to issue New Source Performance Standards for greenhouse gas emissions from certain new and modified electric generating units and emissions guidelines for existing units over the next two years. Pursuant to this settlement agreement, the EPA agreed to issue proposed rules during the fourth quarter of 2011 and final rules by mid-2012. The EPA has not yet issued proposed rules and has sought to extend the deadlines for issuing the rules.
Another impetus for addressing climate change is litigation relating to greenhouse gas emissions and pressure for greenhouse gas emission reductions from investor organizations and the international community. In at least three Federal court cases, nuisance-type claims have been asserted against emitters of carbon dioxide, including several utility companies, alleging that such emissions contribute to global warming. On June 20, 2011, the U.S. Supreme Court issued a decision that bars state and private parties from bringing Federal common law nuisance actions against electrical utility companies based on their alleged contribution to climate change. The Supreme Court's decision, which did not address state law claims, is expected to affect other pending Federal climate change litigation. Although OG&E is not a defendant in any of these proceedings, additional litigation in Federal and state courts over climate change issues is continuing.
OG&E is continuing to evaluate various options for reducing, avoiding, offsetting or sequestering its carbon dioxide emissions. OG&E is a partner in the EPA Sulfur Hexafluoride Voluntary Reduction Program.
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 facilities to address climate change, 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.
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, such as the lesser prairie chicken, become subject to protection, OG&E’s operations and development projects, particularly transmission projects, wind projects or pipeline operations, could be restricted or delayed, or OG&E could be required to implement expensive mitigation measures.
Waste
OG&E's operations generate hazardous wastes that are subject to the Federal Resource Conservation and Recovery Act of 1976 as well as comparable state laws which impose detailed requirements for the handling, storage, treatment and disposal of hazardous waste.
For OG&E, these laws impose strict "cradle to grave" requirements on generators regarding their treatment, storage and disposal of hazardous waste. OG&E routinely generates small quantities of hazardous waste throughout its system and occasional larger quantities from periodic power generation related activities. These wastes are treated, stored and disposed at facilities that are permitted to manage them.
In June 2010, the EPA proposed new rules under Federal Resource Conservation and Recovery Act of 1976 that could alter the classification of OG&E's coal-fired power plants as conditionally exempt hazardous waste generators and make the management of coal ash more costly. The extent to which the EPA intends to regulate coal ash is uncertain due to the fact that the new rules propose to regulate coal ash as a hazardous waste or as a nonhazardous solid waste. In November 2010, OG&E submitted written comments opposing the regulation of coal ash as a hazardous waste while supporting its regulation as a nonhazardous waste. The EPA continues to consider numerous comments received on the proposal and has stated that it plans to issue a final rule regarding the regulation of coal ash in late 2012.
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 2011, OG&E obtained refunds of $5.2 million from the recycling of scrap metal, salvaged transformers and used transformer oil. This figure does not include the additional savings gained through the reduction and/or avoidance of disposal costs and the reduction in material purchases due to the reuse of existing materials. Similar savings are anticipated in future years.
Water
OG&E's operations are subject to the Federal Clean Water Act, and analogous state laws and regulations. These laws and regulations impose detailed requirements and strict controls regarding the discharge of pollutants into state and Federal waters. The discharge of pollutants, including discharges resulting from a spill or leak, is prohibited unless authorized by a permit or other agency approval. The Federal Clean Water Act and regulations implemented thereunder also prohibit discharges of dredged and fill material in wetlands and other waters of the United States unless authorized by an appropriately issued permit. Existing cooling water intake structures are regulated under the Federal Clean Water Act to minimize their impact on the environment.
With respect to cooling water intake structures, Section 316(b) of the Federal Clean Water Act requires that their location, design, construction and capacity reflect the "best available technology" for minimizing their adverse environmental impact via the impingement and entrainment of aquatic organisms. In March 2011, the EPA proposed rules to implement Section 316(b). On August 18, 2011, OG&E filed comments with the EPA on the proposed rules. OG&E anticipates that the proposed rules will be finalized in mid-2012. In the interim, the state of Oklahoma requires OG&E to implement best management practices related to the operation and maintenance of its existing cooling water intake structures as a condition of renewing its discharge permits. Once the EPA promulgates the final rules, OG&E may incur additional capital and/or operating costs to comply with them. The costs of complying with the final water intake standards are not currently determinable, but could be significant.
Site Remediation
The Comprehensive Environmental Response, Compensation and Liability Act of 1980 and comparable state laws impose liability, without regard to the legality of the original conduct, on certain classes of persons responsible for the release of hazardous substances into the environment. Because OG&E utilizes various products and generate wastes that are considered hazardous substances for purposes of the Comprehensive Environmental Response, Compensation and Liability Act of 1980, OG&E could
be subject to liability for the costs of cleaning up and restoring sites where those substances have been released to the environment. At this time, it is not anticipated that any associated liability will cause a significant impact to OG&E.
For a further discussion regarding contingencies relating to environmental laws and regulations, see Note 12 of Notes to Financial Statements.
Item 7A.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk.
Market risks are, in most cases, risks that are actively traded in a marketplace and have been well studied in regards to quantification. Market risks include, but are not limited to, changes in interest rates and commodity prices. OG&E's exposure to changes in interest rates relates primarily to short-term variable-rate debt and commercial paper. OG&E is exposed to commodity prices in its operations.
Risk Committee and Oversight
Management monitors market risks using a risk committee structure. OGE Energy's Risk Oversight Committee, which consists primarily of corporate officers, is responsible for the overall development, implementation and enforcement of strategies and policies for all market risk management activities of OG&E. This committee's emphasis is a holistic perspective of risk measurement and policies targeting OG&E's overall financial performance. The Risk Oversight Committee is authorized by, and reports quarterly to, the Audit Committee of OGE Energy's Board of Directors.
OG&E also has a Corporate Risk Management Department led by OGE Energy's Chief Risk Officer. This group, in conjunction with the aforementioned committees, is responsible for establishing and enforcing OG&E's risk policies.
Risk Policies
Management utilizes risk policies to control the amount of market risk exposure. These policies are designed to provide the Audit Committee of OGE Energy's Board of Directors and senior executives of OG&E with confidence that the risks taken on by OG&E's business activities are in accordance with their expectations for financial returns and that the approved policies and controls related to market risk management are being followed. Some of the measures in these policies include value-at-risk limits, position limits, tenor limits and stop loss limits.
Interest Rate Risk
OG&E's exposure to changes in interest rates primarily relates to short-term variable-rate debt and commercial paper. OG&E manages its interest rate exposure by monitoring and limiting the effects of market changes in interest rates. OG&E utilizes interest rate derivatives to alter interest rate exposure in an attempt to reduce the effects of these changes. Interest rate derivatives are used solely to modify interest rate exposure and not to modify the overall leverage of the debt portfolio.
The fair value of OG&E's long-term debt is based on quoted market prices and estimates of current rates available for similar issues with similar maturities. The following table shows OG&E's long-term debt maturities and the weighted-average interest rates by maturity date.
(A) Prior to or when these debt obligations mature, OG&E may refinance all or a portion of such debt at then-existing market interest rates which may be more or less than the interest rates on the maturing debt.
(B) A hypothetical change of 100 basis points in the underlying variable interest rate incurred by OG&E would change interest expense by $1.4 million annually.
Commodity Price Risk
OG&E occasionally uses commodity price swap contracts to manage OG&E's commodity price risk exposures. Natural gas swaps are used to manage OG&E's natural gas exposure associated with a wholesale power sales contract as discussed in Note 4 of Notes to Financial Statements.
Item 8.
Item 8. Financial Statements.
OKLAHOMA GAS AND ELECTRIC COMPANY
STATEMENTS OF INCOME
The accompanying Notes to Financial Statements are an integral part hereof.
OKLAHOMA GAS AND ELECTRIC COMPANY
STATEMENTS OF COMPREHENSIVE INCOME
The accompanying Notes to Financial Statements are an integral part hereof.
OKLAHOMA GAS AND ELECTRIC COMPANY
STATEMENTS OF CASH FLOWS
The accompanying Notes to Financial Statements are an integral part hereof.
OKLAHOMA GAS AND ELECTRIC COMPANY
BALANCE SHEETS
The accompanying Notes to Financial Statements are an integral part hereof.
OKLAHOMA GAS AND ELECTRIC COMPANY
BALANCE SHEETS (Continued)
The accompanying Notes to Financial Statements are an integral part hereof.
OKLAHOMA GAS AND ELECTRIC COMPANY
STATEMENTS OF CAPITALIZATION
The accompanying Notes to Financial Statements are an integral part hereof.
OKLAHOMA GAS AND ELECTRIC COMPANY
STATEMENTS OF CHANGES IN STOCKHOLDER'S EQUITY
The accompanying Notes to Financial Statements are an integral part hereof.
OKLAHOMA GAS AND ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
1.
Summary of Significant Accounting Policies
Organization
OG&E generates, transmits, distributes and sells electric energy in Oklahoma and western Arkansas. Its operations are conducted through OG&E and are subject to regulation by the OCC, the APSC and the FERC.OG&E is a wholly-owned subsidiary of OGE Energy which is an energy and energy services provider offering physical delivery and related services for both electricity and natural gas primarily in the south central United States. 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.
Basis of Presentation
In the opinion of management, all adjustments necessary to fairly present the financial position of OG&E at December 31, 2011 and 2010 and the results of its operations and cash flows for the years ended December 31, 2011, 2010 and 2009, have been included and are of a normal recurring nature except as otherwise disclosed.
Accounting Records
The accounting records of OG&E are maintained in accordance with the Uniform System of Accounts prescribed by the FERC and adopted by the OCC and the APSC. Additionally, OG&E, as a regulated utility, is subject to accounting principles for certain types of rate-regulated activities, which provide that certain actual or anticipated costs that would otherwise be charged to expense can be deferred as regulatory assets, based on the expected recovery from customers in future rates. Likewise, certain actual or anticipated credits that would otherwise reduce expense can be deferred as regulatory liabilities, based on the expected flowback to customers in future rates. Management's expected recovery of deferred costs and flowback of deferred credits generally results from specific decisions by regulators granting such ratemaking treatment.
OG&E records certain actual or anticipated costs and obligations as regulatory assets or liabilities if it is probable, based on regulatory orders or other available evidence, that the cost or obligation will be included in amounts allowable for recovery or refund in future rates.
The following table is a summary of OG&E's regulatory assets and liabilities at:
(A)
Included in Other Current Assets on the Balance Sheets.
(B)
Included in Other Current Liabilities on the Balance Sheets.
Fuel clause under recoveries are generated from under recoveries from OG&E's customers when OG&E's cost of fuel exceeds the amount billed to its customers. Fuel clause over recoveries are generated from over recoveries from OG&E's customers when the amount billed to its customers exceeds OG&E's cost of fuel. OG&E's fuel recovery clauses are designed to smooth the impact of fuel price volatility on customers' bills. As a result, OG&E under recovers fuel costs in periods of rising fuel prices above the baseline charge for fuel and over recovers fuel costs when prices decline below the baseline charge for fuel. Provisions in the fuel clauses are intended to allow OG&E to amortize under and over recovery balances.
The benefit obligations regulatory asset is comprised of expenses recorded which are probable of future recovery and that have not yet been recognized as components of net periodic benefit cost, including net loss, prior service cost and net transition obligation. These expenses were allowed to be recorded as a regulatory asset as OG&E had historically recovered and currently recovers pension and postretirement benefit plan expense in its electric rates and there was no negative evidence that the existing regulatory treatment would change. If, in the future, the regulatory bodies indicate a change in policy related to the recovery of pension and postretirement benefit plan expenses, this could cause the benefit obligations regulatory asset balance to be reclassified to Accumulated Other Comprehensive Income.
The following table is a summary of the components of the benefit obligations regulatory asset at:
The following amounts in the benefit obligations regulatory asset at December 31, 2011 are expected to be recognized as components of net periodic benefit cost in 2012:
Income taxes recoverable from customers, which represents income tax benefits previously used to reduce OG&E's revenues, are treated as regulatory assets and liabilities and are being amortized over the estimated remaining life of the assets to which they relate. These amounts are being recovered in rates as the temporary differences that generated the income tax benefit turn around. The income tax related regulatory assets and liabilities are netted in Income Taxes Recoverable from Customers, Net in the regulatory assets and liabilities table above.
In accordance with the OCC order received by OG&E in July 2010 related to its Smart Grid project, OG&E established a regulatory asset which includes the cost of system-wide deployment of smart grid technology and implementing the smart grid pilot program, the incremental costs for web portal access, education and providing home energy reports and stranded costs associated with OG&E's existing meters. The costs recoverable from Oklahoma customers for system-wide deployment of smart grid technology and implementing the smart grid pilot program are capped at $366.4 million (inclusive of the U.S. Department of Energy grant award amount) subject to an offset for any recovery of those costs from Arkansas customers and are currently being recovered through a rider which will remain in effect until the Smart Grid project costs are included in base rates beginning in 2014. The incremental costs for web portal access, education and home energy reports are capped at $6.9 million and will be recovered in base rates beginning in 2014. The stranded costs associated with OG&E's existing meters which are being replaced by smart meters will accumulate during the Smart Grid deployment and recovery of the stranded costs will be included in future rate cases. OG&E received an order from the APSC in August 2011 related to its Arkansas Smart Grid project. OG&E will recover estimated capital costs of $14 million and associated operation and maintenance costs for deployment of smart grid technology, along with incremental costs for web portal access and education of $0.8 million, through a rider. The rider will become effective when the smart meters are fully deployed in Arkansas, which is expected during the second quarter of 2012, and will remain in effect until new base rates are implemented subsequent to OG&E's next rate case. The APSC also authorized OG&E to record a regulatory asset for stranded costs associated with OG&E's existing meters and to recover the stranded meter regulatory asset in base rates subsequent to OG&E's next rate case.
In accordance with the September 2008 OCC rate order, OG&E was allowed to defer the Oklahoma storm-related operation and maintenance expenses in excess of $2.7 million and will reserve for any Oklahoma storm-related operation and maintenance expenses less than $2.7 million. OG&E will recover the deferred amounts over a five-year period ending in August 2013.
Unamortized loss on reacquired debt is comprised of unamortized debt issuance costs related to the early retirement of OG&E's long-term debt. These amounts are being amortized over the term of the long-term debt which replaced the previous long-term debt. The unamortized loss on reacquired debt is not included in OG&E's rate base and does not otherwise earn a rate of return.
In accordance with the OCC order received by OG&E in December 2005 in its Oklahoma rate case, OG&E was allowed to recover a certain amount of pension plan expenses. These deferred amounts have been recorded as a regulatory asset as OG&E received an order in July 2009 allowing it to begin recovery of $16.8 million of these costs over a four-year period. In accordance with the APSC order received by OG&E in May 2009 in its Arkansas rate case, OG&E was allowed recovery of its 2006 and 2007 pension settlement costs. During the second quarter of 2009, OG&E reduced its pension expense and recorded a regulatory asset for $3.2 million, which is being amortized over a 10-year period, as allowed in the Arkansas rate order. Both the Oklahoma and Arkansas pension plan expenses are reflected in Deferred Pension expenses asset in the regulatory assets and liabilities table above. Also, in accordance with the OCC order received by OG&E in August 2009 in its Oklahoma rate case, OG&E was allowed to recover a certain amount of pension plan expenses. In accordance with the OCC order received by OG&E in September 2011 in its pension tracker modification filing, OG&E was allowed to include postretirement medical expense in its pension tracker. At December 31, 2011, OG&E had $22.5 million of expenses under this level, which have been recorded as Pension tracker regulatory liability in the regulatory assets and liabilities table above.
Accrued removal obligations represent asset retirement costs previously recovered from ratepayers for other than legal obligations.
Management continuously monitors the future recoverability of regulatory assets. When in management's judgment future recovery becomes impaired, the amount of the regulatory asset is adjusted, as appropriate. If OG&E were required to discontinue the application of accounting principles for certain types of rate-regulated activities for some or all of its operations, it could result in writing off the related regulatory assets, which could have significant financial effects.
Use of Estimates
In preparing the Financial Statements, management is required to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and contingent liabilities at the date of the Financial Statements and the reported amounts of revenues and expenses during the reporting period. Changes to these assumptions and estimates could have a material effect on OG&E's Financial Statements. However, OG&E believes it has taken reasonable, but conservative, positions where assumptions and estimates are used in order to minimize the negative financial impact to OG&E that could result if actual results vary from the assumptions and estimates. In management's opinion, the areas of OG&E where the most significant judgment is exercised includes the valuation of Pension Plan assumptions, income taxes, contingency reserves, asset retirement obligations, fair value and cash flow hedges, the allowance for uncollectible accounts receivable, the valuation of regulatory assets and liabilities and unbilled revenues.
Cash and Cash Equivalents
For purposes of the Financial Statements, OG&E considers all highly liquid debt instruments purchased with an original maturity of three months or less to be cash equivalents. These investments are carried at cost, which approximates fair value.
Allowance for Uncollectible Accounts Receivable
Customer balances are generally written off if not collected within six months after the final billing date. The allowance for uncollectible accounts receivable for OG&E is calculated by multiplying the last six months of electric revenue by the provision rate. The provision rate is based on a 12-month historical average of actual balances written off. To the extent the historical collection rates are not representative of future collections, there could be an effect on the amount of uncollectible expense recognized. Beginning in August 2009 and going forward, there was a change in the provision calculation as a result of the Oklahoma rate case whereby the portion of the uncollectible provision related to fuel is being recovered through the fuel adjustment clause. Due to the extremely hot weather in OG&E's service territory in 2011, OG&E recorded an additional amount of uncollectible expense anticipating higher customer defaults. The allowance for uncollectible accounts receivable was $3.7 million and $1.6 million at December 31, 2011 and 2010, respectively.
New business customers are required to provide a security deposit in the form of cash, bond or irrevocable letter of credit that is refunded when the account is closed. New residential customers, whose outside credit scores indicate risk, are required to provide a security deposit that is refunded based on customer protection rules defined by the OCC and the APSC. The payment behavior of all existing customers is continuously monitored and, if the payment behavior indicates sufficient risk within the
meaning of the applicable utility regulation, customers will be required to provide a security deposit.
Fuel Inventories
Fuel inventories for the generation of electricity consist of coal, natural gas and oil. OG&E uses the weighted-average cost method of accounting for inventory that is physically added to or withdrawn from storage or stockpiles. The amount of fuel inventory was $76.9 million and $134.9 million at December 31, 2011 and 2010, respectively.
Property, Plant and Equipment
All property, plant and equipment is recorded at cost. Newly constructed plant is added to plant balances at cost which includes contracted services, direct labor, materials, overhead, transportation costs and the allowance for funds used during construction. Replacements of units of property are capitalized as plant. For assets that belong to a common plant account, the replaced plant is removed from plant balances and the cost of such property is charged to Accumulated Depreciation. For assets that do not belong to a common plant account, the replaced plant is removed from plant balances with the related accumulated depreciation and the remaining balance net of any salvage proceeds is recorded as a loss in the Statements of Income as Other Expense. Repair and replacement of minor items of property are included in the Statements of Income as Other Operation and Maintenance Expense.
The table below presents OG&E's ownership interest in the jointly-owned McClain Plant and the jointly-owned Redbud Plant, and, as disclosed below, only OG&E's ownership interest is reflected in the property, plant and equipment and accumulated depreciation balances in these tables. The owners of the remaining interests in the McClain Plant and the Redbud Plant are responsible for providing their own financing of capital expenditures. Also, only OG&E's proportionate interests of any direct expenses of the McClain Plant and the Redbud Plant such as fuel, maintenance expense and other operating expenses are included in the applicable financial statement captions in the Statement of Income.
(A) This amount includes a plant acquisition adjustment of $148.3 million.
(B) This amount includes accumulated amortization of the plant acquisition adjustment of $17.9 million.
OG&E's property, plant and equipment and related accumulated depreciation are divided into the following major classes at:
Depreciation and Amortization
The provision for depreciation, which was 2.9 percent and 3.0 percent, respectively, of the average depreciable utility plant for 2011 and 2010, is provided on a straight-line method over the estimated service life of the utility assets. Depreciation is provided at the unit level for production plant and at the account or sub-account level for all other plant, and is based on the average life group method. In 2012, the provision for depreciation is projected to be 2.9 percent of the average depreciable utility plant. Amortization of intangible assets is computed using the straight-line method. Of the remaining amortizable intangible plant balance at December 31, 2011, 48.3 percent will be amortized over three years with 51.7 percent of the remaining amortizable intangible plant balance at December 31, 2011 being amortized over their respective lives ranging from four to 25 years. Amortization of plant acquisition adjustments is provided on a straight-line basis over the estimated remaining service life of the acquired asset. Plant acquisition adjustments include $148.3 million for the Redbud Plant, which are being amortized over a 27-year life and $3.3 million for certain substation facilities in OG&E's service territory, which are being amortized over a 26 to 59-year period.
Asset Retirement Obligations
OG&E has previously recorded asset retirement obligations that are being amortized over their respective lives ranging from 20 to 99 years. In the fourth quarter of 2011, OG&E recorded an asset retirement obligation for $13.0 million related to its Crossroads wind farm. Beginning December 1, 2011, OG&E began to amortize the value of the related asset retirement obligation asset over the estimated remaining life of 50 years. OG&E also has certain asset retirement obligations that have not been recorded because OG&E determined that these assets, primarily related to OG&E's power plant sites, have indefinite lives.
Allowance for Funds Used During Construction
For OG&E, allowance for funds used during construction is calculated according to the FERC pronouncements for the imputed cost of equity and borrowed funds. Allowance for funds used during construction, a non-cash item, is reflected as a reduction to interest expense in the Statements of Income and as an increase to Construction Work in Progress in the Balance Sheets. Allowance for funds used during construction rates, compounded semi-annually, were 8.71 percent, 8.89 percent and 7.99 percent for the years ended December 31, 2011, 2010 and 2009, respectively. The decrease in the allowance for funds used during construction rates in 2011 was primarily due to the issuance of long-term debt which changed the cost of capital weighting to shift towards debt which has a lower effective rate than equity.
Collection of Sales Tax
In the course of its operations, OG&E collects sales tax from its customers. OG&E records a current liability for sales taxes when it bills its customers and eliminates this liability when the taxes are remitted to the appropriate governmental authorities. OG&E excludes the sales tax collected from its operating revenues.
Revenue Recognition
General
OG&E reads its customers' meters and sends bills to its customers throughout each month. As a result, there is a significant amount of customers' electricity consumption that has not been billed at the end of each month. Unbilled revenue is presented in Accrued Unbilled Revenues on the Balance Sheets and in Operating Revenues on the Statements of Income based on estimates of usage and prices during the period. The estimates that management uses in this calculation could vary from the actual amounts to be paid by customers.
SPP Purchases and Sales
OG&E participates in the SPP energy imbalance service market in a dual role as a load serving entity and as a generation owner. The energy imbalance service market requires cash settlements for over or under schedules of generation and load. Market participants, including OG&E, are required to submit resource plans and can submit offer curves for each resource available for dispatch. A function of interchange accounting is to match participants' MWH entitlements (generation plus scheduled bilateral purchases) against their MWH obligations (load plus scheduled bilateral sales) during every hour of every day. If the net result during any given hour is an entitlement, the participant is credited with a spot-market sale to the SPP at the respective market price for that hour; if the net result is an obligation, the participant is charged with a spot-market purchase from the SPP at the respective
market price for that hour. The SPP purchases and sales are not allocated to individual customers. OG&E records the hourly sales to the SPP at market rates in Operating Revenues and the hourly purchases from the SPP at market rates in Cost of Goods Sold in its Financial Statements.
Fuel Adjustment Clauses
Variances in the actual cost of fuel used in electric generation and certain purchased power costs, as compared to the fuel component in the cost-of-service for ratemaking, are passed through to OG&E's customers through fuel adjustment clauses, which are subject to periodic review by the OCC, the APSC and the FERC.
Income Taxes
OG&E is a member of an affiliated group that files consolidated income tax returns in the U.S. Federal jurisdiction and various state jurisdictions. Income taxes are generally allocated to each company in the affiliated group based on its stand-alone taxable income or loss. Federal investment tax credits previously claimed on electric utility property have been deferred and are being amortized to income over the life of the related property. OG&E uses the asset and liability method of accounting for income taxes. Under this method, a deferred tax asset or liability is recognized for the estimated future tax effects attributable to temporary differences between the financial statement basis and the tax basis of assets and liabilities as well as tax credit carry forwards and net operating loss carry forwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in the period of the change. OG&E recognizes interest related to unrecognized tax benefits in interest expense and recognizes penalties in other expense.
Accrued Vacation
OG&E accrues vacation pay monthly by establishing a liability for vacation earned. Vacation may be taken as earned and is charged against the liability. At the end of each year, the liability represents the amount of vacation earned, but not taken.
Accumulated Other Comprehensive Loss
The balance of Accumulated Other Comprehensive Loss was $2.5 million and $2.1 million at December 31, 2011 and 2010, respectively, related to deferred commodity contracts hedging activity.
Environmental Costs
Accruals for environmental costs are recognized when it is probable that a liability has been incurred and the amount of the liability can be reasonably estimated. Costs are charged to expense or deferred as a regulatory asset based on expected recovery from customers in future rates, if they relate to the remediation of conditions caused by past operations or if they are not expected to mitigate or prevent contamination from future operations. Where environmental expenditures relate to facilities currently in use, such as pollution control equipment, the costs may be capitalized and depreciated over the future service periods. Estimated remediation costs are recorded at undiscounted amounts, independent of any insurance or rate recovery, based on prior experience, assessments and current technology. Accrued obligations are regularly adjusted as environmental assessments and estimates are revised, and remediation efforts proceed. For sites where OG&E has been designated as one of several potentially responsible parties, the amount accrued represents OG&E's estimated share of the cost. OG&E has less than $0.1 million in accrued environmental liabilities at both December 31, 2011 and 2010.
Related Party Transactions
OGE Energy charged operating costs to OG&E of $129.7 million, $106.9 million and $92.6 million in 2011, 2010 and 2009, respectively. OGE Energy charges operating costs to its subsidiaries based on several factors. Operating costs directly related to specific subsidiaries are assigned to those subsidiaries. Where more than one subsidiary benefits from certain expenditures, the costs are shared between those subsidiaries receiving the benefits. Operating costs incurred for the benefit of all subsidiaries are allocated among the subsidiaries, either as overhead based primarily on labor costs or using the "Distrigas" method. The Distrigas method is a three-factor formula that uses an equal weighting of payroll, net operating revenues and gross property, plant and equipment. OGE Energy adopted the Distrigas method in January 1996 as a result of a recommendation by the OCC Staff. OGE Energy believes this method provides a reasonable basis for allocating common expenses.
In each of 2011, 2010 and 2009, OG&E recorded an expense from its affiliate, Enogex, of $34.8 million for transporting gas to OG&E's natural gas-fired generating facilities. In each of 2011, 2010 and 2009, OG&E recorded an expense from Enogex
of $12.7 million for natural gas storage services. In 2011, 2010 and 2009, OG&E also recorded natural gas purchases from Enogex, through its subsidiary, OER, of $34.7 million, $50.3 million and $38.5 million, respectively. There are $1.7 million and $4.3 million of natural gas purchases recorded at December 31, 2011 and 2010, respectively, which are included in Accounts Payable - Affiliates in the Balance Sheets for these activities.
On July 1, 2009, OG&E, Enogex and OER entered into hedging transactions to offset natural gas long positions at Enogex with short natural gas exposures at OG&E resulting from the cost of generation associated with a wholesale power sales contract with the Oklahoma Municipal Power Authority. Enogex sold physical natural gas to OER, and OG&E entered into an offsetting natural gas swap with OER. These transactions are for 50,000 million British thermal units per month from August 2009 to December 2013 (see Note 4).
In 2010, OG&E declared dividends to OGE Energy of $60.2 million. In 2011 and 2009, OG&E declared no dividends to OGE Energy.
In June 2011, OGE Energy made a capital contribution to OG&E for $50.0 million.
Reclassifications
Certain prior year amounts have been reclassified on the Statements of Income for impairment of assets to conform to the 2011 presentation.
2.
Accounting Pronouncement
In December 2011, the Financial Accounting Standards Board issued "Comprehensive Income: Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in Accounting Standards Update No. 2011-05." The new standard defers the effective date of changes from previous accounting guidance that related to the presentation of reclassification adjustments. The new standard is applicable for all entities that have other comprehensive income. The new standard is effective for interim and annual reporting periods for fiscal years beginning after December 15, 2011. OG&E adopted this new standard effective January 1, 2012.
3.
Fair Value Measurements
The classification of OG&E's fair value measurements requires judgment regarding the degree to which market data are observable or corroborated by observable market data. GAAP establishes a fair value hierarchy that prioritizes the inputs used to measure fair value based on observable and unobservable data. The hierarchy categorizes the inputs into three levels, with the highest priority given to quoted prices in active markets for identical unrestricted assets or liabilities (Level 1) and the lowest priority given to unobservable inputs (Level 3). Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The three levels defined in the fair value hierarchy are as follows:
Level 1 inputs are quoted prices in active markets for identical unrestricted assets or liabilities that are accessible at the measurement date.
Level 2 inputs are inputs other than quoted prices in active markets included within Level 1 that are either directly or indirectly observable at the reporting date for the asset or liability for substantially the full term of the asset or liability. Level 2 inputs include quoted prices for similar assets or liabilities in active markets and quoted prices for identical or similar assets or liabilities in markets that are not active. Instruments classified as Level 2 include hedging transactions to offset natural gas long positions at Enogex with short natural gas exposures at OG&E resulting from the cost of generation associated with a wholesale power sales contract with the Oklahoma Municipal Power Authority.
Level 3 inputs are prices or valuation techniques for the asset or liability that require inputs that are both significant to the fair value measurement and unobservable (i.e., supported by little or no market activity). Unobservable inputs reflect the reporting entity's own assumptions about the assumptions that market participants would use in pricing the asset or liability (including assumptions about risk).
OG&E utilizes the market approach in determining the fair value of its derivative positions by using either NYMEX published market prices, independent broker pricing data or broker/dealer valuations. Over-the-counter derivatives with NYMEX based prices are considered Level 2 due to the impact of counterparty credit risk.
The impact to the fair value of derivatives due to credit risk is calculated using the probability of default based on Standard & Poor's Ratings Services and/or internally generated ratings. The fair value of derivative assets is adjusted for credit risk. The fair value of derivative liabilities is adjusted for credit risk only if the impact is deemed material.
At December 31, 2011 and 2010, OG&E had no gross derivative assets measured at fair value on a recurring basis. At December 31, 2011 and 2010, OG&E had $4.0 million and $3.5 million, respectively, of gross derivative liabilities measured at fair value on a recurring basis which are considered level 2 in the fair value hierarchy.
The following table summarizes the fair value and carrying amount of OG&E's financial instruments, including derivative contracts related to OG&E's PRM activities, at:
The carrying value of the financial instruments on the Balance Sheets not otherwise discussed above approximates fair value except for long-term debt which is valued at the carrying amount. The valuation of OG&E's energy derivative contracts was determined generally based on quoted market prices. The valuation of instruments also considers the credit risk of the counterparties. The fair value of OG&E's long-term debt is based on quoted market prices and estimates of current rates available for similar issues with similar maturities.
4.
Derivative Instruments and Hedging Activities
OG&E is exposed to certain risks relating to its ongoing business operations. The primary risks managed using derivatives instruments are commodity price risk and interest rate risk. OG&E is also exposed to credit risk in its business operations.
Commodity Price Risk
OG&E occasionally uses commodity price swap contracts to manage OG&E's commodity price risk exposures. Natural gas swaps are used to manage OG&E's natural gas exposure associated with a wholesale power sales contract.
On July 1, 2009, OG&E, Enogex and OER entered into hedging transactions to offset natural gas long positions at Enogex with short natural gas exposures at OG&E resulting from the cost of generation associated with a wholesale power sales contract with the Oklahoma Municipal Power Authority. Enogex sold physical natural gas to OER, and OG&E entered into an offsetting natural gas swap with OER. These transactions are for 50,000 million British thermal units per month from August 2009 to December 2013.
Normal purchases and normal sales contracts are not recorded in PRM Assets or Liabilities in the Balance Sheets and earnings recognition is recorded in the period in which physical delivery of the commodity occurs. Management applies normal purchases and normal sales treatment to: (i) electric power contracts by OG&E and (ii) fuel procurement by OG&E.
OG&E recognizes its non-exchange traded derivative instruments as PRM Assets or Liabilities in the Balance Sheets at fair value with such amounts classified as current or long-term based on their anticipated settlement.
Interest Rate Risk
OG&E's exposure to changes in interest rates primarily relates to short-term variable-rate debt and commercial paper. OG&E manages its interest rate exposure by monitoring and limiting the effects of market changes in interest rates. OG&E utilizes interest rate derivatives to alter interest rate exposure in an attempt to reduce the effects of these changes. Interest rate derivatives are used solely to modify interest rate exposure and not to modify the overall leverage of the debt portfolio.
Credit Risk
OG&E is exposed to certain credit risks relating to its ongoing business operations. Credit risk includes the risk that counterparties that owe OG&E money or energy will breach their obligations. If the counterparties to these arrangements fail to perform, OG&E may be forced to enter into alternative arrangements. In that event, OG&E's financial results could be adversely affected and OG&E could incur losses.
Cash Flow Hedges
For derivatives that are designated and qualify as a cash flow hedge, the effective portion of the change in fair value of the derivative instrument is reported as a component of Accumulated Other Comprehensive Income and recognized into earnings in the same period during which the hedged transaction affects earnings. The ineffective portion of a derivative's change in fair value or hedge components excluded from the assessment of effectiveness is recognized currently in earnings. Forecasted transactions, which are designated as the hedged transaction in a cash flow hedge, are regularly evaluated to assess whether they continue to be probable of occurring. If the forecasted transactions are no longer probable of occurring, hedge accounting will cease on a prospective basis and all future changes in the fair value of the derivative will be recognized directly in earnings.
At December 31, 2011 and 2010, the only derivative instruments that were designated as cash flow hedges were the related party natural gas swaps with OER discussed above.
Fair Value Hedges
For derivative instruments that are designated and qualify as a fair value hedge, the gain or loss on the derivative as well as the offsetting loss or gain on the hedged item attributable to the hedge risk are recognized currently in earnings. OG&E includes the gain or loss on the hedged items in Operating Revenues as the offsetting loss or gain on the related hedging derivative.
At December 31, 2011 and 2010, OG&E had no derivative instruments that were designated as fair value hedges.
Derivatives Not Designated As Hedging Instruments
For derivative instruments not designated as hedging instruments, the gain or loss on the derivative is recognized currently in earnings.
At December 31, 2011 and 2010, OG&E had no material derivative instruments that were not designated as hedging instruments.
Credit-Risk Related Contingent Features in Derivative Instruments
At December 31, 2011, OG&E had no derivative instruments that contain credit-risk related contingent features.
5.
Stock-Based Compensation
In 2008, OGE Energy adopted, and its shareowners approved, the 2008 Stock Incentive Plan. Under the 2008 Stock Incentive Plan, restricted stock, stock options, stock appreciation rights and performance units may be granted to officers, directors and other key employees of OGE Energy and its subsidiaries. OGE Energy has authorized the issuance of up to 2,750,000 shares under the 2008 Stock Incentive Plan.
The following table summarizes OG&E's pre-tax compensation expense and related income tax benefit for the years ended December 31, 2011, 2010 and 2009 related to performance units and restricted stock for OG&E employees.
OGE Energy has issued new shares to satisfy stock option exercises, restricted stock grants and payouts of earned performance units. In 2011, 2010 and 2009, there were 56,801 shares, 53,582 shares and 57,439 shares, respectively, of new common stock issued to OG&E's employees pursuant to OGE Energy's stock incentive plans related to exercised stock options, restricted stock grants and payouts of earned performance units. In 2011, there were 6,793 shares of restricted stock returned to OGE Energy to satisfy tax liabilities.
Performance Units
Under the 2008 Stock Incentive Plan, OGE Energy has issued performance units which represent the value of one share of OGE Energy's common stock. The performance units provide for accelerated vesting if there is a change in control (as defined in the 2008 Stock Incentive Plan). Each performance unit is subject to forfeiture if the recipient terminates employment with OGE Energy or a subsidiary prior to the end of the three-year award cycle for any reason other than death, disability or retirement. In the event of death, disability or retirement, a participant will receive a prorated payment based on such participant's number of full months of service during the award cycle, further adjusted based on the achievement of the performance goals during the award cycle.
The performance units granted based on total shareholder return are contingently awarded and will be payable in shares of OGE Energy's common stock subject to the condition that the number of performance units, if any, earned by the employees upon the expiration of a three-year award cycle (i.e., three-year cliff vesting period) is dependent on OGE Energy's total shareholder return ranking relative to a peer group of companies. The performance units granted based on earnings per share are contingently awarded and will be payable in shares of OGE Energy's common stock based on OGE Energy's earnings per share growth over a three-year award cycle (i.e., three-year cliff vesting period) compared to a target set at the time of the grant by the Compensation Committee of OGE Energy's Board of Directors. All of OG&E's performance units are classified as equity in OGE Energy's Consolidated Balance Sheet. If there is no or only a partial payout for the performance units at the end of the award cycle, the unearned performance units are cancelled. Payout requires approval of the Compensation Committee of OGE Energy's Board of Directors. Payouts, if any, are all made in OGE Energy's common stock and are considered made when the payout is approved by the Compensation Committee.
Performance Units - Total Shareholder Return
The fair value of the performance units based on total shareholder return was estimated on the grant date using a lattice-based valuation model that factors in information, including the expected dividend yield, expected price volatility, risk-free interest rate and the probable outcome of the market condition, over the expected life of the performance units. Compensation expense for the performance units is a fixed amount determined at the grant date fair value and is recognized over the three-year award cycle regardless of whether performance units are awarded at the end of the award cycle. Dividends are not accrued or paid during the performance period and, therefore, are not included in the fair value calculation. Expected price volatility is based on the historical volatility of OGE Energy's common stock for the past three years and was simulated using the Geometric Brownian Motion process. The risk-free interest rate for the performance unit grants is based on the three-year U.S. Treasury yield curve in effect at the time of the grant. The expected life of the units is based on the non-vested period since inception of the award cycle. There are no post-vesting restrictions related to OGE Energy's performance units based on total shareholder return. The number of performance units granted based on total shareholder return and the assumptions used to calculate the grant date fair value of the performance units based on total shareholder return are shown in the following table.
Performance Units - Earnings Per Share
The fair value of the performance units based on earnings per share is based on grant date fair value which is equivalent to the price of one share of OGE Energy's common stock on the date of grant. The fair value of performance units based on earnings per share varies as the number of performance units that will vest is based on the grant date fair value of the units and the probable outcome of the performance condition. OGE Energy reassesses at each reporting date whether achievement of the performance condition is probable and accrues compensation expense if and when achievement of the performance condition is probable. As a result, the compensation expense recognized for these performance units can vary from period to period. There are no post-vesting restrictions related to OGE Energy's performance units based on earnings per share. The number of performance units granted based on earnings per share and the grant date fair value are shown in the following table.
Restricted Stock
Under the 2008 Stock Incentive Plan and beginning in 2008, OGE Energy issued restricted stock to certain existing non-officer employees as well as other executives upon hire to attract and retain individuals to be competitive in the marketplace. The restricted stock vests in one-third annual increments. Prior to vesting, each share of restricted stock is subject to forfeiture if the recipient ceases to render substantial services to OGE Energy or a subsidiary for any reason other than death, disability or retirement. These shares may not be sold, assigned, transferred or pledged and are subject to a risk of forfeiture.
The fair value of the restricted stock was based on the closing market price of OGE Energy's common stock on the grant date. Compensation expense for the restricted stock is a fixed amount determined at the grant date fair value and is recognized as services are rendered by employees over a three-year vesting period. Also, OG&E treats its restricted stock as multiple separate awards by recording compensation expense separately for each tranche whereby a substantial portion of the expense is recognized in the earlier years in the requisite service period. Dividends are accrued and paid during the vesting period and, therefore, are included in the fair value calculation. The expected life of the restricted stock is based on the non-vested period since inception of the three-year award cycle. There are no post-vesting restrictions related to OGE Energy's restricted stock. The number of shares of restricted stock granted related to OG&E's employees and the grant date fair value are shown in the following table.
A summary of the activity for OGE Energy's non-vested performance units and restricted stock applicable to OG&E's employees at December 31, 2011 and changes in 2011 are shown in the following table.
(A) Represents target number of units granted. Actual number of units earned, if any, is dependent upon performance and may range from 0 percent to 200 percent of the target.
(B) Due to certain employees transferring between OG&E and its affiliates.
Fair Value of Vested Performance Units and Restricted Stock
A summary of OG&E's fair value for its vested performance units and restricted stock is shown in the following table.
Unrecognized Compensation Cost
A summary of OG&E's unrecognized compensation cost for its non-vested performance units and restricted stock and the weighted-average periods over which the compensation cost is expected to be recognized are shown in the following table.
Stock Options
OGE Energy last issued stock options in 2004 and as of December 31, 2006, all stock options were fully vested and expensed. All stock options have a contractual life of 10 years. A summary of the activity for OGE Energy's stock options applicable to OG&E's employees at December 31, 2011 and changes in 2011 are shown in the following table.
A summary of the activity for OG&E's exercised stock options in 2011, 2010 and 2009 are shown in the following table.
(A)
The difference between the market value on the date of exercise and the option exercise price.
6.
Supplemental Cash Flow Information
The following table discloses information about investing and financing activities that affected recognized assets and liabilities but which did not result in cash receipts or payments. Also disclosed in the table is cash paid for interest, net of interest capitalized, and cash paid for income taxes, net of income tax refunds.
(A) Net of interest capitalized of $10.4 million, $5.5 million and $8.3 million in 2011, 2010 and 2009, respectively.
7.
Income Taxes
The items comprising income tax expense are as follows:
OG&E is a member of an affiliated group that files consolidated income tax returns in the U.S. Federal jurisdiction and various state jurisdictions. With few exceptions, OG&E is no longer subject to U.S. Federal tax examinations by tax authorities for years prior to 2007 or state and local tax examinations by tax authorities for years prior to 2002. Income taxes are generally allocated to each company in the affiliated group based on its stand-alone taxable income or loss. Federal investment tax credits previously claimed on electric utility property have been deferred and are being amortized to income over the life of the related property. OG&E earns both Federal and Oklahoma state tax credits associated with the production from its wind farms as well
as earning Oklahoma state tax credits associated with its investments in electric generating facilities which further reduce OG&E's effective tax rate. The following schedule reconciles the statutory Federal tax rate to the effective income tax rate:
(A) These are credits associated with the production from OG&E's wind farms.
At December 31, 2011 and 2010, OG&E had no material unrecognized tax benefits related to uncertain tax positions.
The deferred tax provisions are recognized as costs in the ratemaking process by the commissions having jurisdiction over the rates charged by OG&E. The components of Deferred Income Taxes at December 31, 2011 and 2010, respectively, were as follows:
During 2010 and 2011, OG&E had a Federal tax operating loss primarily caused by the accelerated tax "bonus" depreciation provision contained within the Tax Relief, Unemployment Insurance Reauthorization and Job Creation Act of 2010 which allows OG&E to record a current income tax deduction for 100 percent of the cost of certain property placed into service from September 8, 2010 to December 31, 2011. In addition, the new law also allows OG&E to record a current income tax deduction for 50 percent of the cost of certain property placed into service from January 1, 2012 to December 31, 2012. For financial accounting purposes,
OG&E recorded an increase in its Non-Current Deferred Income Taxes Liability at December 31, 2011 and 2010 on OG&E's Balance Sheet to recognize the financial statement impact of this new law.
In June 2010, new legislation was passed in Oklahoma that created a moratorium, from July 1, 2010 through June 30, 2012, on 30 income tax credits. For income tax purposes, credits affected by the moratorium may not be claimed for any event, transaction, investment, expenditure or other act for which the credits would otherwise be allowable. During this two-year period, affected credits generated by OG&E are being deferred and will be utilized at a time after the moratorium expires. For financial accounting purposes, OG&E will receive the benefits in the future as most of these credits do not expire if they are not utilized in the period they are generated.
Medicare Part D Subsidy
On March 23, 2010, the Patient Protection and Affordable Care Act of 2009 was signed into law, and, on March 30, 2010, the Health Care and Education Reconciliation Act of 2010, which makes various amendments to certain aspects of the Patient Protection and Affordable Care Act of 2009, was signed into law. These Acts effectively change the tax treatment of Federal subsidies paid to sponsors of retiree health benefit plans that provide prescription drug benefits that are at least actuarially equivalent to the corresponding benefits provided under Medicare Part D.
The Federal subsidy paid to employers was introduced as part of the Medicare Prescription Drug, Improvement, and Modernization Act of 2003. OGE Energy has been recognizing the Federal subsidy since 2005 related to certain retiree prescription drug plans that were determined to be actuarially equivalent to the benefit provided under Medicare Part D. Under the Medicare Prescription Drug, Improvement, and Modernization Act of 2003, the Federal subsidy does not reduce an employer's income tax deduction for the costs of providing such prescription drug plans nor is it subject to income tax individually.
During 2011, OGE Energy modified its retiree health benefit plan in such a manner that it is no longer actuarially equivalent to the corresponding benefits provided under Medicare Part D. As a result, OGE Energy is no longer eligible to receive Medicare Part D reimbursements. See Note 11 for a further discussion.
Other
OG&E sustained Federal and state tax operating losses in 2010 and 2011 caused primarily by bonus depreciation and other book verses tax temporary differences. As a result, OG&E accrued Federal and state income tax benefits in 2010 and 2011. OG&E can no longer carry these losses back to prior periods, therefore, these losses are being carried forward. In addition to the operating losses, OG&E was unable to utilize the various tax credits that were generating during these years. These tax losses and credits are being carried as deferred tax assets and will be utilized in future periods. OG&E anticipates future taxable income will be sufficient to utilize all of the losses and credits before they begin to expire, accordingly no valuation allowance is considered necessary. The following table summarizes these carry forwards:
(A) Oklahoma capital investment board credits may not be exercisable after July 1, 2015. OG&E anticipates the credits will be monetized or the expiration date of these credits will be extended.
8. Common Stock and Cumulative Preferred Stock
There were no new shares of common stock issued in 2011, 2010 or 2009. OG&E's Restated Certificate of Incorporation permits the issuance of a new series of preferred stock with dividends payable other than quarterly.
9.
Long-Term Debt
A summary of OG&E's long-term debt is included in the Statements of Capitalization. At December 31, 2011, OG&E was in compliance with all of its debt agreements.
OG&E has tax-exempt pollution control bonds with optional redemption provisions that allow the holders to request repayment of the bonds at various dates prior to the maturity. The bonds, which can be tendered at the option of the holder during the next 12 months, are as follows:
All of these bonds are subject to an optional tender at the request of the holders, at 100 percent of the principal amount, together with accrued and unpaid interest to the date of purchase. The bond holders, on any business day, can request repayment of the bond by delivering an irrevocable notice to the tender agent stating the principal amount of the bond, payment instructions for the purchase price and the business day the bond is to be purchased. The repayment option may only be exercised by the holder of a bond for the principal amount. When a tender notice has been received by the trustee, a third party remarketing agent for the bonds will attempt to remarket any bonds tendered for purchase. This process occurs once per week. Since the original issuance of these series of bonds in 1995 and 1997, the remarketing agent has successfully remarketed all tendered bonds. If the remarketing agent is unable to remarket any such bonds, OG&E is obligated to repurchase such unremarketed bonds. As OG&E has both the intent and ability to refinance the bonds on a long-term basis and such ability is supported by an ability to consummate the refinancing, the bonds are classified as long-term debt in OG&E's Financial Statements. OG&E believes that it has sufficient liquidity to meet these obligations.
Long-Term Debt Maturities
Maturities of OG&E's long-term debt during the next five years consist of $110 million in 2016. There are no maturities of OG&E's long-term debt in years 2012, 2013, 2014 or 2015.
OG&E has previously incurred costs related to debt refinancings. Unamortized debt expense and unamortized loss on reacquired debt are classified as Deferred Charges and Other Assets and the unamortized premium and discount on long-term debt is classified as Long-Term Debt, respectively, in the Balance Sheets and are being amortized over the life of the respective debt.
OG&E Issuance of Long-Term Debt
On May 24, 2011, OG&E issued $250 million of 5.25% senior notes due May 15, 2041. The proceeds from the issuance were added to OGE Energy's general funds and were used to repay short-term debt. OG&E expects to issue additional long-term debt from time to time when market conditions are favorable and when the need arises.
10.
Short-Term Debt and Credit Facility
At December 31, 2011 and 2010, there were $97.2 million and $68.9 million, respectively, in net outstanding advances to OGE Energy. OG&E has an intercompany borrowing agreement with OGE Energy whereby OG&E has access to up to $250 million of OGE Energy's revolving credit amount. This agreement has a termination date of January 9, 2013. At December 31, 2011, there were no intercompany borrowings under this agreement. In December 2011, OG&E entered into a new $400 million unsecured five-year revolving credit facility which is available to back up OG&E's commercial paper borrowings and to provide revolving credit borrowings. This bank facility can also be used as a letter of credit facility. At December 31, 2011, there was $2.2 million supporting letters of credit at a weighted-average interest rate of 0.53 percent. There were no outstanding borrowings under this revolving credit agreement and no outstanding commercial paper borrowings at December 31, 2011. At December 31, 2011, OG&E had less than $0.1 million in cash and cash equivalents.
OGE Energy's and OG&E's ability to access the commercial paper market could be adversely impacted by a credit ratings downgrade or major market disruptions. Pricing grids associated with OGE Energy's and OG&E's credit facilities could cause
annual fees and borrowing rates to increase if an adverse ratings 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 OG&E could also lead to higher long-term borrowing costs and, if below investment grade, would require OG&E to post cash collateral or letters of credit.
OG&E must obtain regulatory approval from the FERC in order to borrow on a short-term basis. OG&E has the necessary regulatory approvals to incur up to $800 million in short-term borrowings at any one time for a two-year period beginning January 1, 2011 and ending December 31, 2012.
11.
Retirement Plans and Postretirement Benefit Plans
Pension Plan and Restoration of Retirement Income Plan
OG&E's employees participate in OGE Energy's Pension Plan and Restoration of Retirement Income Plan. In October 2009, OGE Energy's Pension Plan and OGE Energy's 401(k) Plan were amended, effective January 1, 2010 to provide eligible employees a choice to select a future retirement benefit combination from OGE Energy's Pension Plan and OGE Energy's 401(k) Plan.
Employees hired or rehired on or after December 1, 2009 do not participate in the Pension Plan but are eligible to participate in the 401(k) Plan where, for each pay period, OGE Energy contributes to the 401(k) Plan, on behalf of each participant, 200 percent of the participant's contributions up to five percent of compensation.
It is OGE Energy's policy to fund the Pension Plan on a current basis based on the net periodic pension expense as determined by OGE Energy's actuarial consultants. During each of 2011 and 2010, OGE Energy made contributions to its Pension Plan of $50 million, of which $47 million in each of 2011 and 2010 was OG&E's portion, to help ensure that the Pension Plan maintains an adequate funded status. Such contributions are intended to provide not only for benefits attributed to service to date, but also for those expected to be earned in the future. During 2012, OGE Energy may contribute up to $35 million to its Pension Plan, of which $33 million is expected to be OG&E's portion. The expected contribution to the Pension Plan during 2012 would be a discretionary contribution, anticipated to be in the form of cash, and is not required to satisfy the minimum regulatory funding requirement specified by the Employee Retirement Income Security Act of 1974, as amended. OGE Energy could be required to make additional contributions if the value of its pension trust and postretirement benefit plan trust assets are adversely impacted by a major market disruption in the future.
OGE Energy provides a Restoration of Retirement Income Plan to those participants in OGE Energy's Pension Plan whose benefits are subject to certain limitations under the Code. The benefits payable under this Restoration of Retirement Income Plan are equivalent to the amounts that would have been payable under the Pension Plan but for these limitations. The Restoration of Retirement Income Plan is intended to be an unfunded plan.
The following table presents the status of OG&E's portion of OGE Energy's Pension Plan and Restoration of Retirement Income Plan at December 31, 2011 and 2010. These amounts have been recorded in Accrued Benefit Obligations with the offset recorded as a regulatory asset in OG&E's Balance Sheet as discussed in Note 1. The regulatory asset represents a net periodic benefit cost to be recognized in the Statements of Income in future periods.
The following table summarizes the benefit payments OG&E expects to pay related to its Pension Plan and Restoration of Retirement Income Plan. These expected benefits are based on the same assumptions used to measure OGE Energy's benefit obligation at the end of the year and include benefits attributable to estimated future employee service.
Plan Investments, Policies and Strategies
The Pension Plan assets are held in a trust which follows an investment policy and strategy designed to reduce the funded status volatility of the Plan by utilizing liability driven investing. The purpose of liability driven investing is to structure the asset portfolio to more closely resemble the pension liability and thereby more effectively hedge against changes in the liability. The investment policy follows a glide path approach that shifts a higher portfolio weighting to fixed income as the Plan's funded status increases. The table below sets forth the targeted fixed income and equity allocations at different funded status levels.
Within the portfolio's overall allocation to equities, the funds are allocated according to the guidelines in the table below.
OGE Energy has retained an investment consultant responsible for the general investment oversight, analysis, monitoring investment guideline compliance and providing quarterly reports to certain of OG&E's members and OGE Energy's Investment Committee. The various investment managers used by the trust operate within the general operating objectives as established in the investment policy and within the specific guidelines established for each investment manager's respective portfolio.
The portfolio is rebalanced on an annual basis to bring the asset allocations of various managers in line with the target asset allocation listed above. More frequent rebalancing may occur if there are dramatic price movements in the financial markets which may cause the trust's exposure to any asset class to exceed or fall below the established allowable guidelines.
To evaluate the progress of the portfolio, investment performance is reviewed quarterly. It is, however, expected that performance goals will be met over a full market cycle, normally defined as a three to five year period. Analysis of performance is within the context of the prevailing investment environment and the advisors' investment style. The goal of the trust is to provide a rate of return consistently from three percent to five percent over the rate of inflation (as measured by the national Consumer Price Index) on a fee adjusted basis over a typical market cycle of no less than three years and no more than five years. Each investment manager is expected to outperform its respective benchmark. Below is a list of each asset class utilized with appropriate comparative benchmark(s) each manager is evaluated against:
The fixed income manager is expected to use discretion over the asset mix of the trust assets in its efforts to maximize risk-adjusted performance. Exposure to any single issuer, other than the U.S. government, its agencies, or its instrumentalities (which have no limits) is limited to five percent of the fixed income portfolio as measured by market value. At least 75 percent of the invested assets must possess an investment grade rating at or above Baa3 or BBB- by Moody's Investors Services, Standard & Poor's Ratings Services or Fitch Ratings. The portfolio may invest up to 10 percent of the portfolio's market value in convertible bonds as long as the securities purchased meet the quality guidelines. The purchase of any of OGE Energy's equity, debt or other securities is prohibited.
The domestic value equity managers focus on stocks that the manager believes are undervalued in price and earn an average or less than average return on assets, and often pays out higher than average dividend payments. The domestic growth equity manager will invest primarily in growth companies which consistently experience above average growth in earnings and sales, earn a high return on assets, and reinvest cash flow into existing business. The domestic mid-cap equity portfolio manager focuses on companies with market capitalizations lower than the average company traded on the public exchanges with the following characteristics: price/earnings ratio at or near the Russell Midcap Index, small dividend yield, return on equity at or near the Russell Midcap Index and an earnings per share growth rate at or near the Russell Midcap Index. The domestic small-cap equity manager will purchase shares of companies with market capitalizations lower than the average company traded on the public exchanges with the following characteristics: price/earnings ratio at or near the Russell 2000, small dividend yield, return on equity at or near the Russell 2000 and an earnings per share growth rate at or near the Russell 2000. The international global equity manager invests primarily in non-dollar denominated equity securities. Investing internationally diversifies the overall trust across the global equity markets. The manager is required to operate under certain restrictions including: regional constraints, diversification requirements and percentage of U.S. securities. The Morgan Stanley Capital International All Country World ex-US Index is the benchmark for comparative performance purposes. The Morgan Stanley Capital International All Country World ex-US Index is a market value weighted index designed to measure the combined equity market performance of developed and emerging markets countries, excluding the United States. All of the equities which are purchased for the international portfolio are thoroughly researched. Only companies with a market capitalization in excess of $100 million are allowable. No more than five percent of the portfolio can be invested in any one stock at the time of purchase. All securities are freely traded on a recognized stock exchange and there are no 144-A securities and no over-the-counter derivatives. The following investment categories are excluded: options (other than traded currency options), commodities, futures (other than currency futures or currency hedging), short sales/margin purchases, private placements, unlisted securities and real estate (but not real estate shares).
For all domestic equity investment managers, no more than eight percent (five percent for mid-cap and small-cap equity managers) can be invested in any one stock at the time of purchase and no more than 16 percent (10 percent for mid-cap and small-cap equity managers) after accounting for price appreciation. Options or financial futures may not be purchased unless prior approval of OGE Energy's Investment Committee is received. The purchase of securities on margin is prohibited as is securities lending. Private placement or venture capital may not be purchased. All interest and dividend payments must be swept on a daily basis into a short-term money market fund for re-deployment. The purchase of any of OGE Energy's equity, debt or other securities is prohibited. The purchase of equity or debt issues of the portfolio manager's organization is also prohibited. The aggregate positions in any company may not exceed one percent of the fair market value of its outstanding stock.
Plan Investments
The following tables summarize OGE Energy's Pension Plan's investments that are measured at fair value on a recurring basis at December 31, 2011 and 2010. There were no Level 3 investments held by the Pension Plan at December 31, 2011 and
2010.
(A) 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.
(B) 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.
(C) This category represents units of participation in a commingled fund that primarily invest in stocks and bonds of U.S. companies.
(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.
The three levels defined in the fair value hierarchy and examples of each are as follows:
Level 1 inputs are quoted prices in active markets for identical unrestricted assets or liabilities that are accessible by the Pension Plan at the measurement date. Instruments classified as Level 1 include investments in common and preferred stocks, U.S. treasury notes and bonds, mutual funds and interest-bearing cash.
Level 2 inputs are inputs other than quoted prices in active markets included within Level 1 that are either directly or indirectly observable at the reporting date for the asset or liability for substantially the full term of the asset or liability. Level 2 inputs include quoted prices for similar assets or liabilities in active markets and quoted prices for identical or similar assets or liabilities in markets that are not active. Instruments classified as Level 2 include corporate fixed income and other securities, mortgage-backed securities, other U.S. Government obligations, commingled fund, a common/collective trust, U.S. municipal bonds, foreign government bonds, a repurchase agreement, money market fund and forward contracts.
Level 3 inputs are prices or valuation techniques for the asset or liability that require inputs that are both significant to the fair value measurement and unobservable (i.e., supported by little or no market activity). Unobservable inputs reflect the Plan's own assumptions about the assumptions that market participants would use in pricing the asset or liability (including assumptions about risk).
Postretirement Benefit Plans
In addition to providing pension benefits, OGE Energy provides certain medical and life insurance benefits for eligible retired members. Regular, full-time, active employees hired prior to February 1, 2000 whose age and years of credited service total or exceed 80 or have attained at least age 55 with 10 or more years of service at the time of retirement are entitled to postretirement medical benefits while employees hired on or after February 1, 2000 are not entitled to postretirement medical benefits. Effective January 1, 2010, the age for dependents to participate in OGE Energy's Medical Plan was increased to age 21 and if the dependent is a full-time student to age 26. Effective July 1, 2010, the age for dependents to participate in OGE Energy's Medical Plan was increased to age 26 without regard to their full-time student status. All regular, full-time, active employees whose age and years of credited service total or exceed 80 or have attained at least age 55 with three or more years of service at the time of retirement are entitled to postretirement life insurance benefits. Eligible retirees must contribute such amount as OG&E specifies from time to time toward the cost of coverage for postretirement benefits. The benefits are subject to deductibles, co-payment provisions and other limitations. OG&E charges to expense the postretirement benefit costs and includes an annual amount as a component of the cost-of-service in future ratemaking proceedings.
In January 2011, OGE Energy adopted several amendments to its retiree medical plan. Effective January 1, 2012, medical costs for pre-65 aged eligible retirees are fixed at the 2011 level and OGE Energy covers future annual medical inflationary cost increases up to five percent. Increases in excess of five percent annually are covered by the pre-65 aged retiree in the form of premium increases. Also, effective January 1, 2012, OGE Energy supplements Medicare coverage for Medicare-eligible retirees, providing them a fixed stipend based on OGE Energy's expected average 2011 premium for medical and drug coverage, and allows those Medicare-eligible retirees to acquire coverage from an OGE Energy-provided third-party administrator. The effect of these plan amendments was reflected in OGE Energy's 2011 Consolidated Balance Sheet as a reduction to the accumulated postretirement benefit obligation of $91.3 million, an increase in other comprehensive income of $16.9 million and a reduction to OG&E's benefit obligations regulatory asset of $74.4 million.
Plan Investments
The following tables summarize the postretirement benefit plans investments that are measured at fair value on a recurring basis at December 31, 2011 and 2010. There were no Level 2 investments held by the postretirement benefit plans at December 31, 2011 and 2010.
(A) This category represents a group retiree medical insurance contract which invests in a pool of common stocks, bonds and money market accounts, of which a significant portion is comprised of mortgage-backed securities.
The postretirement benefit plans Level 3 investment includes an investment in a group retiree medical insurance contract. The unobservable input included in the valuation of the contract includes the approach for determining the allocation of the postretirement benefit plans pro-rata share of the total assets in the contract.
The following table summarizes the postretirement benefit plans investments that are measured at fair value on a recurring basis using significant unobservable inputs (Level 3).
The following table presents the status of OG&E's portion of OGE Energy's postretirement benefit plans at December 31, 2011 and 2010. These amounts have been recorded in Accrued Benefit Obligations with the offset recorded as a regulatory asset in OG&E's Balance Sheet as discussed in Note 1. The regulatory asset represents a net periodic benefit cost to be recognized in the Statements of Income in future periods.
The assumed health care cost trend rates have a significant effect on the amounts reported for postretirement medical benefit plans. Future health care cost trend rates are assumed to be 8.75 percent in 2012 with the rates trending downward to 4.48
percent by 2028. A one-percentage point change in the assumed health care cost trend rate would have the following effects:
Medicare Prescription Drug, Improvement and Modernization Act of 2003
On December 8, 2003, President Bush signed into law the Medicare Prescription Drug, Improvement and Modernization Act of 2003, which expanded Medicare to include, for the first time, coverage for prescription drugs. The following table summarizes the gross benefit payments OG&E expects to pay related to its postretirement benefit plans, including prescription drug benefits. OGE Energy received $1.3 million in Federal subsidy receipts in 2011. Due to amendments in OGE Energy's retiree medical plan discussed above, OGE Energy does not expect to receive any additional Federal subsidies in the future.
Early Retiree Reinsurance Program
The Patient Protection and Affordable Care Act of 2010 authorized a temporary reinsurance program to pay certain employment-based group health plans up to 80 percent of each early retiree's annual claims cost between $15,000 and $90,000. The program will end by the earlier of January 1, 2014 or when the limited $5 billion in funding runs out. OGE Energy received $0.7 million in Federal subsidy receipts in 2011. OGE Energy's reimbursement proceeds are excluded from gross income and were used to reduce the health benefit costs for the plan and to reduce premium contributions for the plan participants. OGE Energy does not expect to receive any additional benefits provided by this program.
Obligations and Funded Status
The following table presents the status of OG&E's portion of OGE Energy's Pension Plan, the Restoration of Retirement Income Plan and the postretirement benefit plans for 2011 and 2010. OG&E's portion of the benefit obligation for OGE Energy's Pension Plan and the Restoration of Retirement Income Plan represents the projected benefit obligation, while the benefit obligation for the postretirement benefit plans represents the accumulated postretirement benefit obligation. The accumulated postretirement benefit obligation for OGE Energy's Pension Plan and Restoration of Retirement Income Plan differs from the projected benefit obligation in that the former includes no assumption about future compensation levels. The accumulated postretirement benefit obligation for the Pension Plan and the Restoration of Retirement Income Plan at December 31, 2011 was $521.5 million and $2.1 million, respectively. The accumulated postretirement benefit obligation for the Pension Plan and the Restoration of Retirement Income Plan at December 31, 2010 was $485.5 million and $1.7 million, respectively. The details of the funded status of the Pension Plan, the Restoration of Retirement Income Plan and the postretirement benefit plans and the amounts included in the Balance Sheets are as follows:
Net Periodic Benefit Cost
(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 $30.2 million, $44.5 million and $44.5 million of net periodic benefit cost recognized in 2011, 2010 and 2009, respectively, OG&E recognized the following:
•
an increase in pension expense in 2011 and 2010 of $10.8 million and $8.1 million, respectively, and a reduction in pension expense in 2009 of $2.2 million to maintain the allowable amount to be recovered for pension expense in the Oklahoma jurisdiction which are included in the Pension tracker regulatory liability (see Note 1);
•
a reduction in pension expense in 2009 of $3.2 million in the Arkansas jurisdiction to reflect the approval of recovery of OG&E's 2006 and 2007 pension settlement costs in the May 2009 Arkansas rate order which are included in the Pension tracker regulatory liability) (see Note 1); and
•
an increase in postretirement medical expense in 2011 of $3.5 million to maintain the allowable amount to be recovered for postretirement medical expense in the Oklahoma jurisdiction which are included in the Pension tracker regulatory liability (see Note 1).
The capitalized portion of the net periodic pension benefit cost was $5.3 million, $5.7 million and $7.5 million at December 31, 2011, 2010 and 2009, respectively. The capitalized portion of the net periodic postretirement benefit cost was $3.3 million, $5.8 million and $3.6 million at December 31, 2011, 2010 and 2009, respectively.
Rate Assumptions
N/A - not applicable
The overall expected rate of return on plan assets assumption decreased from 8.50 percent in 2010 to 8.00 percent in 2011 in determining net periodic benefit cost due to recent returns on OGE Energy's long-term investment portfolio. The rate of return on plan assets assumption is the average long-term rate of earnings expected on the funds currently invested and to be invested for the purpose of providing benefits specified by the Pension Plan or postretirement benefit plans. This assumption is reexamined at least annually and updated as necessary. The rate of return on plan assets assumption reflects a combination of historical return analysis, forward-looking return expectations and the plans' current and expected asset allocation.
Post-Employment Benefit Plan
Disabled employees receiving benefits from OGE Energy's Group Long-Term Disability Plan are entitled to continue participating in OGE Energy's Medical Plan along with their dependents. The post-employment benefit obligation represents the actuarial present value of estimated future medical benefits that are attributed to employee service rendered prior to the date as of which such information is presented. The obligation also includes future medical benefits expected to be paid to current employees participating in OGE Energy's Group Long-Term Disability Plan and their dependents, as defined in OGE Energy's Medical Plan.
The post-employment benefit obligation is determined by an actuary on a basis similar to the accumulated postretirement benefit obligation. The estimated future medical benefits are projected to grow with expected future medical cost trend rates and are discounted for interest at the discount rate and for the probability that the participant will discontinue receiving benefits from OGE Energy's Group Long-Term Disability Plan due to death, recovery from disability, or eligibility for retiree medical benefits. OG&E's post-employment benefit obligation was $1.8 million and $1.6 million at December 31, 2011 and 2010, respectively.
401(k) Plan
OGE Energy provides a 401(k) Plan. Each regular full-time employee of OGE Energy or a participating affiliate is eligible to participate in the 401(k) Plan immediately. All other employees of OGE Energy or a participating affiliate are eligible to become participants in the 401(k) Plan after completing one year of service as defined in the 401(k) Plan. Participants may contribute each pay period any whole percentage between two percent and 19 percent of their compensation, as defined in the 401(k) Plan, for that pay period. Participants who have attained age 50 before the close of a year are allowed to make additional contributions referred to as "Catch-Up Contributions," subject to the limitations of the Code. The 401(k) Plan also allows an eligible automatic contribution arrangement and provides for a qualified default investment alternative consistent with the U.S. Department of Labor regulations. Participants may elect, in accordance with the 401(k) Plan procedures, to have his or her salary deferral rate to be made in the future automatically increased annually on a date and in an amount as specified by the participant in such election. The 401(k) Plan was amended in October 2009, as discussed previously, whereby employees were offered a choice to either stay in the 401(k) Plan (prior to it being amended) where OGE Energy matching contributions are discussed below or select an option whereby, effective January 1, 2010, OGE Energy contributes on behalf of each participant, depending on the option selected, 200 percent of the participant's contributions up to five percent of compensation or 100 percent of the participant's contributions up to six percent of compensation. In the 401(k) Plan (prior to it being amended), OGE Energy contributes to the
401(k) Plan each pay period, on behalf of each participant, an amount equal to 50 percent of the participant's contributions up to six percent of compensation for participants whose employment or re-employment date occurred before February 1, 2000 and who have less than 20 years of service, as defined in the 401(k) Plan, and an amount equal to 75 percent of the participant's contributions up to six percent of compensation for participants whose employment or re-employment date occurred before February 1, 2000 and who have 20 or more years of service, as defined in the 401(k) Plan. For participants whose employment or re-employment date occurred on or after February 1, 2000 and before December 1, 2009, under the 401(k) Plan (prior to it being amended), OGE Energy contributes 100 percent of the participant's contributions up to six percent of compensation. For participants hired on or after December 1, 2009, OGE Energy contributes, effective January 1, 2010, 200 percent of the participant's contributions up to five percent of compensation. No OGE Energy contributions are made with respect to a participant's Catch-Up Contributions, rollover contributions, or with respect to a participant's contributions based on overtime payments, pay-in-lieu of overtime for exempt personnel, special lump-sum recognition awards and lump-sum merit awards included in compensation for determining the amount of participant contributions. Prior to January 1, 2010, OGE Energy's contribution, which was initially allocated for investment to the OGE Energy Corp. Common Stock Fund, was made in shares of OGE Energy's common stock or in cash which was used to invest in OGE Energy's common stock. Once made, OGE Energy's contribution could be reallocated, on any business day, by participants to other available investment options. The 401(k) Plan was amended effective January 1, 2010, whereby OGE Energy's contribution may be directed to any available investment option in the 401(k) Plan. OGE Energy match contributions vest over a three-year period. After two years of service, participants become 20 percent vested in their OGE Energy contribution account and become fully vested on completing three years of service. In addition, participants fully vest when they are eligible for normal or early retirement under Pension Plan, in the event of their termination due to death or permanent disability or upon attainment of age 65 while employed by OGE Energy or its affiliates. OG&E contributed $7.0 million, $6.9 million and $5.6 million in 2011, 2010 and 2009, respectively, to the 401(k) Plan.
Deferred Compensation Plan
OGE Energy provides a nonqualified deferred compensation plan which is intended to be an unfunded plan. The plan's primary purpose is to provide a tax-deferred capital accumulation vehicle for a select group of management, highly compensated employees and non-employee members of the Board of Directors of OGE Energy and to supplement such employees' 401(k) Plan contributions as well as offering this plan to be competitive in the marketplace.
Eligible employees who enroll in the plan have the following deferral options: (i) eligible employees may elect to defer up to a maximum of 70 percent of base salary and 100 percent of annual bonus awards or (ii) eligible employees may elect a deferral percentage of base salary and bonus awards based on the deferral percentage elected for a year under the 401(k) Plan with such deferrals to start when maximum deferrals to the qualified 401(k) Plan have been made because of limitations in that plan. Eligible directors who enroll in the plan may elect to defer up to a maximum of 100 percent of directors' meeting fees and annual retainers. OGE Energy matches employee (but not non-employee director) deferrals to make up for any match lost in the 401(k) Plan because of deferrals to the deferred compensation plan, and to allow for a match that would have been made under the 401(k) Plan on that portion of either the first six percent of total compensation or the first five percent of total compensation, depending on the option the participant elected under the choice provided to eligible employees discussed above, deferred that exceeds the limits allowed in the 401(k) Plan. Matching credits vest based on years of service, with full vesting after six years or, if earlier, on retirement, disability, death, a change in control of OGE Energy or termination of the plan. The deferred compensation plan was amended, effective January 1, 2012, to provide for full vesting after three years. In addition, the Benefits Committee may award discretionary employer contribution credits to a participant under the plan. OGE Energy accounts for the contributions related to OG&E's executive officers in this plan as Accrued Benefit Obligations and OGE Energy accounts for the contributions related to OG&E's directors in this plan as Other Deferred Credits and Other Liabilities in the Consolidated Balance Sheets. The investment associated with these contributions is accounted for as Other Property and Investments in OGE Energy's Consolidated Balance Sheets. The appreciation of these investments is accounted for as Other Income and the increase in the liability under the plan is accounted for as Other Expense in OGE Energy's Consolidated Statements of Income.
Supplemental Executive Retirement Plan
OGE Energy provides a supplemental executive retirement plan in order to attract and retain lateral hires or other executives designated by the Compensation Committee of OGE Energy's Board of Directors who may not otherwise qualify for a sufficient level of benefits under OGE Energy's Pension Plan and Restoration of Retirement Income Plan. The supplemental executive retirement plan is intended to be an unfunded plan and not subject to the benefit limits imposed by the Code.
12.
Commitments and Contingencies
Operating Lease Obligations
Future minimum payments for noncancellable operating lease for railcars are as follows:
Payments for operating lease obligations were $3.3 million, $4.6 million and $5.0 million for the years ended December 31, 2011, 2010 and 2009, respectively.
Railcar Lease Agreement
OG&E has a noncancellable operating lease with purchase options, covering 1,392 coal hopper railcars to transport coal from Wyoming to OG&E's coal-fired generation units. Rental payments are charged to Fuel Expense and are recovered through OG&E's tariffs and fuel adjustment clauses. On December 15, 2010, OG&E renewed the lease agreement effective February 1, 2011. At the end of the new lease term, which is February 1, 2016, OG&E has the option to either purchase the railcars at a stipulated fair market value or renew the lease. If OG&E chooses not to purchase the railcars or renew the lease agreement and the actual fair value of the railcars is less than the stipulated fair market value, OG&E would be responsible for the difference in those values up to a maximum of $22.8 million.
OG&E is also required to maintain all of the railcars it has under lease to transport coal from Wyoming and has entered into agreements with Progress Rail Services and WATCO, both of which are non-affiliated companies, to furnish this maintenance.
Other Purchase Obligations and Commitments
OG&E's other future purchase obligations and commitments estimated for the next five years are as follows:
Public Utility Regulatory Policy Act of 1978
At December 31, 2011, OG&E has QF contracts having terms of 15 to 32 years. These contracts were entered into pursuant to the Public Utility Regulatory Policy Act of 1978. Stated generally, the Public Utility Regulatory Policy Act of 1978 and the regulations thereunder promulgated by the FERC require OG&E to purchase power generated in a manufacturing process from a QF. The rate for such power to be paid by OG&E was approved by the OCC. The rate generally consists of two components: one is a rate for actual electricity purchased from the QF by OG&E; the other is a capacity charge, which OG&E must pay the QF for having the capacity available. However, if no electrical power is made available to OG&E for a period of time (generally three months), OG&E's obligation to pay the capacity charge is suspended. The total cost of cogeneration payments is recoverable in rates from customers. For the 320 MW AES-Shady Point, Inc. QF contract and the 120 MW PowerSmith Cogeneration Project, L.P. QF contract, OG&E purchases 100 percent of the electricity generated by the QFs.
For the years ended December 31, 2011, 2010 and 2009, OG&E made total payments to cogenerators of $140.7 million, $147.3 million and $139.8 million, respectively, of which $78.0 million, $80.7 million and $83.1 million, respectively, represented capacity payments. All payments for purchased power, including cogeneration, are included in the Statements of Income as Cost of Goods Sold.
Minimum Fuel Purchase Commitments
OG&E purchased necessary fuel supplies of coal and natural gas for its generating units of $729.8 million, $819.3 million and $674.4 million for the years ended December 31, 2011, 2010 and 2009, respectively. OG&E has coal contracts for purchases from January 2012 through December 2015. OG&E has natural gas contracts for purchases from January 2012 through March 2012 that account for 26 percent of OG&E's projected 2012 natural gas requirements. Additional gas supplies to fulfill OG&E's remaining 2012 natural gas requirements will be acquired through additional requests for proposal in early to mid-2012, along with monthly and daily purchases, all of which are expected to be made at market prices.
Wind Purchase Commitments
OG&E's current wind power portfolio includes: (i) the Centennial wind farm, (ii) the OU Spirit wind farm, (iii) the Crossroads wind farm, (iv) access to up to 50 MWs of electricity generated at a wind farm near Woodward, Oklahoma from a 15-year contract OG&E entered into with FPL Energy that expires in 2018, (v) access to up to 150 MWs of electricity generated at a wind farm in Woodward County, Oklahoma from a 20-year contract OG&E entered into with CPV Keenan that expires in 2030 and (vi) access to up to 130 MWs of electricity generated at a wind farm in Woodward County, Oklahoma from a 20-year contract OG&E entered into with Edison Mission Energy that expires in 2030.
The following table summarizes OG&E's wind power purchases for the years ended December 31, 2011, 2010 and 2009.
Long-Term Service Agreement Commitments
In July 2004, OG&E acquired a 77 percent interest in the McClain Plant. As part of that acquisition, OG&E became subject to an existing long-term parts and service maintenance contract for the upkeep of the natural gas-fired combined cycle generation facility. The contract was initiated in December 1999, and runs for the earlier of 96,000 factored-fired hours or 4,800 factored-fired starts. Based on historical usage and current expectations for future usage, this contract is expected to run until 2015. The contract requires payments based on both a fixed and variable cost component, depending on how much the McClain Plant is used.
In September 2008, OG&E acquired a 51 percent interest in the Redbud Plant. As part of that acquisition, OG&E became subject to an existing long-term parts and service maintenance contract for the upkeep of the natural gas-fired combined cycle generation facility. The contract was initiated in January 2001, and runs for the earlier of 120,000 factored-fired hours or 4,500 factored-fired starts. Based on historical usage and current expectations for future usage, this contract is expected to run until 2028. The contract requires payments based on both a fixed and variable cost component, depending on how much the Redbud Plant is used.
Natural Gas Measurement Case
Will Price, et al. v. El Paso Natural Gas Co., et al. (Price I). On September 24, 1999, various subsidiaries of OGE Energy were served with a class action petition filed in the District Court of Stevens County, Kansas by Quinque Operating Company and other named plaintiffs alleging the mismeasurement of natural gas on non-Federal lands. On April 10, 2003, the court entered an order denying class certification. On May 12, 2003, the plaintiffs (now Will Price, Stixon Petroleum, Inc., Thomas F. Boles and the Cooper Clark Foundation, on behalf of themselves and other royalty interest owners) filed a motion seeking to file an amended class action petition, and the court granted the motion on July 28, 2003. In its amended petition, OG&E and Enogex Inc. were omitted from the case but two of OGE Energy's other subsidiary entities remained as defendants. The plaintiffs' amended petition seeks class certification and alleges that 60 defendants, including two of OGE Energy's subsidiary entities, have improperly measured the volume of natural gas. The amended petition asserts theories of civil conspiracy, aiding and abetting, accounting and unjust enrichment. In their briefing on class certification, the plaintiffs seek to also allege a claim for conversion. The plaintiffs seek unspecified actual damages, attorneys' fees, costs and pre-judgment and post-judgment interest. The plaintiffs also reserved the right to seek punitive damages.
On September 18, 2009, the court entered its order denying class certification. On October 2, 2009, the plaintiffs filed for a rehearing of the court's denial of class certification. On March 31, 2010, the court denied the plaintiffs' request for rehearing. On July 20, 2011, Enogex LLC and OER filed motions for summary judgment. On January 25, 2012, the court denied portions of the motions for summary judgment related to the legal issue of the plaintiffs' claims regarding civil conspiracy. In an order dated January 23, 2012, the court granted the plaintiffs additional time to perform discovery prior to the consideration of the motions for summary judgment as they relate to the plaintiffs' other claims.
OGE Energy intends to vigorously defend this action. At this time, OGE Energy does not believe the outcome will have a material impact on its financial position.
Environmental Laws and Regulations
The activities of OG&E are subject to stringent and complex Federal, state and local laws and regulations governing environmental protection including the discharge of materials into the environment. These laws and regulations can restrict or impact OG&E's business activities in many ways, such as restricting the way it can handle or dispose of its wastes, requiring remedial action to mitigate pollution conditions that may be caused by its operations or that are attributable to former operators, regulating future construction activities to mitigate harm to threatened or endangered species and requiring the installation and operation of pollution control equipment. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial requirements and the issuance of orders enjoining future operations. OG&E believes that its operations are in substantial compliance with current Federal, state and local environmental standards.
Environmental regulation can increase the cost of planning, design, initial installation and operation of OG&E's facilities. Historically, OG&E's total expenditures for environmental control facilities and for remediation have not been significant in relation to its financial position or results of operations. OG&E believes, however, that it is reasonably likely that the trend in environmental legislation and regulations will continue towards more restrictive standards. Compliance with these standards is expected to increase the cost of conducting business.
On May 17, 2011, OG&E entered into a Consent Order with the ODEQ related to alleged violations of Federal and state opacity standards from 2005 to May 2011 at OG&E's Muskogee and Sooner generating stations. The Consent Order requires OG&E to reach certain milestones with regard to the overall amount of time when opacity exceeds certain amounts. Beginning January 1, 2015, the Consent Order requires each unit at OG&E's Muskogee and Sooner generating stations to have a rolling annual average of the time that opacity emissions are in excess of 20 percent to a level equal to or below one percent of the total time in a measurement period. OG&E agreed to implement two specific projects and other measures as necessary to achieve the milestones established in the Consent Order. These projects and other measures are not expected to involve significant capital or ongoing operating expenses. OG&E also agreed to pay a stipulated cash penalty of $150,000 and agreed to contribute another $150,000 to an ODEQ environmental fund for assisting small Oklahoma communities with their drinking water and wastewater treatment systems. OG&E entered into the Consent Order without admitting or denying the allegations made by the ODEQ. In order to facilitate the court approval of the Consent Order, the ODEQ initiated the necessary legal action against OG&E in state court on May 17, 2011. On June 2, 2011, the Consent Order was approved and entered by the District Court of Oklahoma County, Oklahoma. Subject to the ongoing compliance obligations described above pursuant to the Consent Order, OG&E considers this matter closed.
OG&E is managing several significant uncertainties about the scope and timing for the acquisition, installation and operation of additional pollution control equipment and compliance costs for a variety of the EPA rules that are being challenged in court. OG&E is unable to predict the financial impact of these matters with certainty at this time. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Environmental Laws and Regulations" for a discussion of OG&E's environmental matters.
Other
In the normal course of business, OG&E is confronted with issues or events that may result in a contingent liability. These generally relate to lawsuits, claims made by third parties, environmental actions or the action of various regulatory 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 otherwise stated above, in Note 13 below and in Item 3 of this Form 10-K, management, after consultation with legal counsel, does not currently anticipate that liabilities arising out of these pending or threatened lawsuits, claims and contingencies will have a material adverse effect on OG&E's financial position, results of operations or cash flows.
13.
Rate Matters and Regulation
Regulation and Rates
OG&E's retail electric tariffs are regulated by the OCC in Oklahoma and by the APSC in Arkansas. The issuance of certain securities by OG&E is also regulated by the OCC and the APSC. OG&E's wholesale electric tariffs, transmission activities, short-term borrowing authorization and accounting practices are subject to the jurisdiction of the FERC. The Secretary of the U.S. Department of Energy has jurisdiction over some of OG&E's facilities and operations. In 2011, 89 percent of OG&E's electric revenue was subject to the jurisdiction of the OCC, eight percent to the APSC and three percent to the FERC.
The OCC issued an order in 1996 authorizing OG&E to reorganize into a subsidiary of OGE Energy. The order required that, among other things, (i) OGE Energy permit the OCC access to the books and records of OGE Energy and its affiliates relating to transactions with OG&E, (ii) OGE Energy employ accounting and other procedures and controls to protect against subsidization of non-utility activities by OG&E's customers and (iii) OGE Energy refrain from pledging OG&E assets or income for affiliate transactions. In addition, the Energy Policy Act of 2005 enacted the Public Utility Holding Company Act of 2005, which in turn granted to the FERC access to the books and records of OGE Energy and its affiliates as the FERC deems relevant to costs incurred by OG&E or necessary or appropriate for the protection of utility customers with respect to the FERC jurisdictional rates.
Completed Regulatory Matters
Wholesale Agreement
On May 28, 2009, OG&E sent a termination notice to the Arkansas Valley Electric Cooperative that OG&E would terminate its wholesale power agreement to all points of delivery where OG&E sells or has sold power to the Arkansas Valley Electric Cooperative, effective November 30, 2011. In December 2010, OG&E and the Arkansas Valley Electric Cooperative entered into a new wholesale power agreement whereby OG&E will supply wholesale power to the Arkansas Valley Electric Cooperative through June 2015. On January 3, 2011, OG&E submitted this agreement to the FERC for approval. The FERC approved the new wholesale power agreement on March 2, 2011 and the new contract was effective May 1, 2011.
Crossroads Wind Farm
On July 29, 2010, OG&E received an order from the OCC authorizing OG&E to recover from Oklahoma customers the cost to construct Crossroads, with the rider being implemented as the individual turbines are placed in service. The Crossroads wind farm was fully in service in January 2012. As part of this project, on June 16, 2011, OG&E entered into an interconnection agreement with the SPP for Crossroads which allowed Crossroads to interconnect at 227.5 MWs.
2010 Arkansas Rate Case Filing
On September 28, 2010, OG&E filed a rate case with the APSC requesting an annual rate increase of $17.7 million, to recover the cost of significant electric system expansions and upgrades, including high-voltage transmission lines, that have been completed since the last rate filing in August 2008, as well as increased operating costs. OG&E also sought recovery, through a rider, of the Arkansas jurisdictional portion of (i) costs associated with transmission upgrades and facilities that have been approved by the SPP in its regional planning processes and constructed by other non-OG&E transmission owners throughout the SPP that have been allocated to OG&E through the FERC-approved transmission rates and (ii) SPP administrative fees. On June 17, 2011, the APSC approved a settlement agreement among all parties to the case and OG&E implemented new electric rates effective June 20, 2011. Key items of the APSC order include: (i) the recovery of and a return on significant electric system expansions and upgrades, including high-voltage transmission lines, as well as increased operating costs, totaling $8.8 million annually; (ii) authorization for OG&E to recover the actual cost of third-party transmission charges and SPP administrative fees through a rider mechanism which will remain in effect until new rates are implemented after OG&E's next general rate case (the Arkansas jurisdictional portion of the combined costs was $1.0 million in 2011); and (iii) the deferral of certain expenses associated with a customer education program in an amount not to exceed $0.3 million per year for a maximum of two years.
SPP Cost Tracker
On October 7, 2010, OG&E filed an application with the OCC seeking recovery of the Oklahoma jurisdictional portion of (i) costs associated with transmission upgrades and facilities that have been approved by the SPP in its regional planning processes and constructed by other non-OG&E transmission owners throughout the SPP that have been allocated to OG&E through the FERC-approved transmission rates and (ii) SPP administrative fees. OG&E requested authorization to implement a cost tracker
in order to recover from its retail customers the third-party project costs discussed above and to collect its administrative SPP cost assessment levied under Schedule 1A of the SPP open access transmission tariff, which is currently recovered in base rates. OG&E also requested authorization to establish a regulatory asset effective January 1, 2011 in order to give OG&E the opportunity to recover such costs that will be paid but not recovered until the cost tracker is made effective. On February 8, 2011, all parties signed a settlement agreement in this matter which would allow OG&E to recover the costs discussed in (i) above through a recovery rider effective January 1, 2011. OG&E recovered $5.1 million of incremental revenues in 2011 through the rider. Rather than including the costs of the SPP administrative fee assessment in the recovery rider, the stipulating parties agreed to allow OG&E to include the projected 2012 level of the SPP administrative fee assessment in its next Oklahoma rate case which was filed in August 2011. Pursuant to the settlement agreement in OG&E's 2011 Oklahoma general rate case filing, OG&E proposed that recovery in base rates for the costs of transmission projects it constructs and owns and that are authorized by the SPP in its regional planning processes should be limited to the Oklahoma retail jurisdictional share of the costs for such projects allocated to OG&E by the SPP. On March 28, 2011, the OCC issued an order in this matter approving the settlement agreement.
Fuel Adjustment Clause Review for Calendar Year 2009
On October 29, 2010, the OCC Staff filed an application for a public hearing to review and monitor OG&E's application of the 2009 fuel adjustment clause. On December 28, 2010, OG&E responded by filing the necessary information and documents to satisfy the OCC's minimum filing requirement rules. An intervenor representing a group of OG&E's industrial customers filed testimony on March 11, 2011 seeking a $15.5 million refund related to (i) a purported failure by OG&E to maximize the use of its coal-fired power plants and (ii) an inappropriate extension of the existing gas transportation and storage contract between OG&E and Enogex. OG&E filed rebuttal testimony on April 4, 2011 in opposition to the claims of the intervenor. On August 11, 2011, all parties to this case signed a settlement agreement in this matter, stating that (i) OG&E was prudent in its operations during 2009; (ii) a third party expert should be hired to evaluate OG&E's future gas transportation and storage needs and that OG&E should file a plan for meeting its future gas transportation and storage needs by mid-2012; and (iii) with respect to the existing gas transportation and storage contract with Enogex, OG&E will return $8.4 million to its customers in settlement for all periods under the contract through April 30, 2013. In August 2011, OG&E credited $4.9 million to its customers and will credit the remaining amount on a monthly basis through April 30, 2013. The OCC issued an order approving the settlement agreement on August 29, 2011.
Smart Grid Project
On December 17, 2010, OG&E filed an application with the APSC requesting pre-approval for system-wide deployment of smart grid technology and a recovery rider, including a credit for the Smart Grid grant awarded by the U.S. Department of Energy under the American Recovery and Reinvestment Act of 2009. On June 22, 2011, OG&E reached a settlement agreement with all the parties in this matter. OG&E and the other parties in this matter agreed to ask the APSC to approve the settlement agreement including the following: (i) pre-approval of system-wide deployment of smart grid technology in Arkansas and authorization for OG&E to begin recovering the prudently incurred costs of the Arkansas system-wide deployment of smart grid technology through a rider mechanism that will become effective in accordance with the order approving the settlement agreement; (ii) cost recovery through the rider would commence when all of the smart meters to be deployed in Arkansas are in service; (iii) OG&E guarantees that customers will receive certain operations and maintenance cost reductions resulting from the smart grid deployment as a credit to the recovery rider; and (iv) the stranded costs associated with OG&E's existing meters which are being replaced by smart meters will be accumulated in a regulatory asset and recovered in base rates beginning after an order is issued in OG&E's next general rate case. OG&E currently expects to spend $14 million, net of funds from the U.S. Department of Energy grant, in capital expenditures to implement smart grid in Arkansas pursuant to the settlement agreement. On August 3, 2011, the APSC issued an order in this matter approving the settlement agreement.
FERC Transmission Rate Incentive Filing
On February 18, 2011, OG&E submitted to the FERC a request seeking limited transmission rate incentives for five transmission projects. OG&E requested recovery of 100 percent of all prudently incurred construction work in progress in rate base for five 345 kilovolt Extra High Voltage transmission projects to be constructed and owned by OG&E within the SPP's region. OG&E also requested to recover 100 percent of all prudently incurred development and construction costs if the transmission projects are abandoned or cancelled, in whole or in part, for reasons beyond OG&E's control. On April 19, 2011, the FERC granted these incentives for the Sooner-Rose Hill, Sunnyside-Hugo and Balanced Portfolio 3E transmission projects discussed below.
Pension Tracker Modification Filing
On February 22, 2011, OG&E filed an application with the OCC requesting that OG&E's pension tracker be modified to include the difference between the level of retiree medical costs authorized in OG&E's last rate case and the current level of
these expenses as a regulatory liability, effective January 1, 2011. On June 23, 2011, a settlement agreement was filed by parties in the case stating that the pension tracker should be modified as proposed by OG&E and that the level of retiree medical costs included in base rates will be reviewed and determined in OG&E's next rate case. On September 27, 2011, the OCC issued an order in this matter approving the settlement agreement.
Demand and Energy Efficiency Program Filing
To build on the success of its earlier programs and further promote energy efficiency and conservation for each class of OG&E customers, on March 15, 2011, OG&E filed an application with the APSC seeking approval of several programs, ranging from residential weatherization to commercial lighting. In seeking approval of these programs, OG&E also sought recovery of the program and related costs through a rider that would be added to customers' electric bills. On June 30, 2011, the APSC issued an order approving OG&E's energy efficiency plan for 2011 and approving OG&E's energy efficiency cost recovery rider for 2011. In Arkansas, OG&E's program is expected to cost $7.0 million over a three-year period and is expected to increase the average residential electric bill by $1.47 per month.
FERC Order No. 1000, Final Rule on Transmission Planning and Cost Allocation
On July 21, 2011, the FERC issued Order No. 1000, which revised the FERC's existing regulations governing the process for planning enhancements and expansions of the electric transmission grid in a particular region, along with the corresponding process for allocating the costs of such expansions. Order No. 1000 applies only to "new transmission facilities," which are described as those subject to evaluation or reevaluation (under the applicable local or regional transmission planning process) subsequent to the effective date of the regulatory compliance filings required by the rule, which are expected to be filed during the third quarter of 2012. Order No. 1000 leaves to individual regions to determine whether a previously-approved project is subject to reevaluation and is therefore governed by the new rule.
Order No. 1000 requires, among other things, public utility transmission providers, such as the SPP, to participate in a process that produces a regional transmission plan satisfying certain standards, and requires that each such regional process consider transmission needs driven by public policy requirements (such as state or Federal policies favoring increased use of renewable energy resources). Order No. 1000 also directs public utility transmission providers to coordinate with neighboring transmission planning regions. In addition, Order No. 1000 establishes specific regional cost allocation principles and directs public utility transmission providers to participate in regional and interregional transmission planning processes that satisfy these principles.
On the issue of determining how entities are to be selected to develop and construct the specific transmission projects, Order No. 1000 directs public utility transmission providers to remove from the FERC-jurisdictional tariffs and agreements provisions that establish any federal "right of first refusal" for the incumbent transmission owner (such as OG&E) regarding transmission facilities selected in a regional transmission planning process, subject to certain limitations. However, Order No. 1000 is not intended to affect the right of an incumbent transmission owner (such as OG&E) to build, own and recover costs for upgrades to its own transmission facilities, and Order No. 1000 does not alter an incumbent transmission owner's use and control of existing rights of way. Order No. 1000 also clarifies that incumbent transmission owners may rely on regional transmission facilities to meet their reliability needs or service obligations. The SPP currently has a "right of first refusal" for incumbent transmission owners and this provision has played a role in OG&E being selected by the SPP to build various transmission projects in Oklahoma.
OGE Energy is continuing to evaluate Order No. 1000 and cannot at this time determine its precise impact on OG&E. Nevertheless, at the present time, OGE Energy has no reason to believe that the implementation of Order No. 1000 will impact OG&E's transmission projects currently under development and construction for which OG&E has received a notice to proceed from the SPP.
Pending Regulatory Matters
2011 Oklahoma Rate Case Filing
As part of the Joint Stipulation and Settlement Agreement reached in OG&E's 2009 Oklahoma rate case filing, the parties agreed that OG&E would file a rate case on or before June 30, 2011. On May 27, 2011, OG&E requested an extension until the end of July 2011 for filing the Oklahoma rate case. On July 28, 2011, OG&E filed its application with the OCC requesting an annual rate increase of $73.3 million, or a 4.3 percent increase in its rates. OG&E is requesting a return on equity of 11.00 percent based on a common equity percentage of 53 percent. Each 0.10 percent change in the requested return on equity affects the requested rate increase by $3.0 million. In its application, OG&E seeks to recover increases in its operating costs and to begin earning on approximately $500 million of new capital investments made on behalf of its Oklahoma customers during the previous
two and one-half years. On November 9, 2011, the OCC Staff recommended a $6.2 million annual rate decrease based on a return on equity of 9.81 percent and a common equity percentage of 53 percent. The staff of the Oklahoma Attorney General recommended a return on equity of 9.818 percent and a common equity percentage of 49.5 percent. The staff of the Oklahoma Attorney General did not recommend a specific revenue requirement, but OG&E believes that adoption of the staff of the Oklahoma Attorney General's recommendations would result in a rate decrease. The Oklahoma Industrial Electric Consumers recommended a $56 million annual rate decrease based on a return on equity of 9.5 percent and a common equity percentage of 48 percent. OG&E filed rebuttal testimony on November 29, 2011 on the revenue requirement testimony filed by the parties on November 9, 2011. On November 16, 2011, the parties filed cost-of-service and rate design testimony and OG&E filed rebuttal testimony in those areas on December 2, 2011. The hearing in this matter began on December 13, 2011. OG&E expects to receive an order from the OCC in the first quarter of 2012.
Fuel Adjustment Clause Review for Calendar Year 2010
On August 19, 2011, the OCC Staff filed an application for a public hearing to review and monitor OG&E's application of the 2010 fuel adjustment clause. On October 18, 2011, OG&E responded by filing the necessary information and documents to satisfy the OCC's minimum filing requirement rules. A procedural schedule has not yet been established in this matter.
Contract and Wind Energy Purchase Agreement Filing
On December 1, 2011, OG&E filed an application with the OCC requesting approval of a 20-year agreement that is intended to provide wind power to help meet the current and future power generation needs of Oklahoma State University. The project calls for OG&E to contract with NextEra Energy to build a 60 MW wind farm near Blackwell, Oklahoma, to support the Oklahoma State University project in which NextEra will build, own and operate the wind farm and OG&E will purchase the electric output. A procedural schedule has not yet been established in this matter. OG&E expects to receive a decision from the OCC in the first quarter of 2012.
SPP Transmission/Substation Projects
The SPP is a regional transmission organization under the jurisdiction of the FERC that was created to ensure reliable supplies of power, adequate transmission infrastructure and competitive wholesale prices of electricity. The SPP does not build transmission though the SPP's tariff contains rules that govern the transmission construction process. Transmission owners complete the construction and then own, operate and maintain transmission assets within the SPP region. When the SPP Board of Directors approves a project, the transmission provider in the area where the project is needed currently has the first obligation to build; however, the process for deciding which entity constructs and owns a project may change as a result of FERC Order. No. 1000 discussed above.
There are several studies currently under review at the SPP including a 20-year plan to address issues of regional and interregional importance. The 20-year plan suggests overlaying the SPP footprint with a 345 kilovolt transmission system and integrating it with neighboring regional entities. In 2009, the SPP Board of Directors approved a new report that recommended restructuring the SPP's regional planning processes to focus on the construction of a robust transmission system, large enough in both scale and geography, to provide flexibility to meet the SPP's future needs. OG&E expects to actively participate in the ongoing study, development and transmission growth that may result from the SPP's plans.
In 2007, the SPP notified OG&E to construct 44 miles of a new 345 kilovolt transmission line which will originate at OG&E's existing Sooner 345 kilovolt substation and proceed generally in a northerly direction to the Oklahoma/Kansas Stateline (referred to as the Sooner-Rose Hill project). At the Oklahoma/Kansas Stateline, the line will connect to the companion line being constructed in Kansas by Westar Energy. Construction of the line began in early 2011 and the line is estimated to be in service by mid-2012 at an estimated cost of $45 million for OG&E.
In January 2009, OG&E received notification from the SPP to begin construction on 50 miles of a new 345 kilovolt transmission line and substation upgrades at OG&E's Sunnyside substation, among other projects. In April 2009, Western Farmers Electric Cooperative assigned to OG&E the construction of 50 miles of line designated by the SPP to be built by Western Farmers Electric Cooperative. The new line will extend from OG&E's Sunnyside substation near Ardmore, Oklahoma, 123.5 miles to the Hugo substation owned by Western Farmers Electric Cooperative near Hugo, Oklahoma. The project cost is estimated at $155 million for OG&E. OG&E began preliminary line routing and acquisition of rights-of-way in June 2009. Construction began in January 2011. When construction is completed, which is expected in mid-2012, the SPP will allocate a portion of the annual revenue requirement to OG&E customers according to the regional cost allocation mechanism as provided in the SPP tariff for application to such improvements.
On April 28, 2009, the SPP approved the Balanced Portfolio 3E projects. Balanced Portfolio 3E includes four projects to be built by OG&E and includes: (i) construction of 135 miles of transmission line from OG&E's Seminole substation in a northeastern direction to OG&E's Muskogee substation at an estimated cost of $160 million for OG&E, which is expected to be in service by late 2013, (ii) construction of 96 miles of transmission line from OG&E's Woodward District Extra High Voltage substation in a southwestern direction to the Oklahoma/Texas Stateline to a companion transmission line to be built by Southwestern Public Service to its Tuco substation at an estimated cost of $145 million for OG&E, which is expected to be in service by mid-2014, (iii) construction of 39 miles of transmission line from OG&E's Sooner substation in an eastern direction to the Grand River Dam Authority Cleveland substation at an estimated cost of $60 million for OG&E, which is expected to be in service by late 2012 and (iv) construction of a new substation near Anadarko which consisted of a 345/138 kilovolt transformer and substation breakers and was built in OG&E's portion of the Cimarron-Lawton East Side 345 kilovolt line at an estimated cost of $15 million for OG&E, which was placed in service in December 2011. On June 19, 2009, OG&E received a notice to construct the Balanced Portfolio 3E projects from the SPP. On July 23, 2009, OG&E responded to the SPP that OG&E will construct the Balanced Portfolio 3E projects discussed above beginning in early 2011.
On April 27, 2010, the SPP approved, contingent upon approval by the FERC of a regional cost allocation methodology filed with the FERC by the SPP, a set of transmission projects titled "Priority Projects." The Priority Projects consist of several transmission projects, two of which have been assigned to OG&E. The 345 kilovolt projects include: (i) construction of 99 miles of transmission line from OG&E's Woodward District Extra High Voltage substation to a companion transmission line to be built by Southwestern Public Service to its Hitchland substation in the Texas Panhandle at an estimated cost of $185 million for OG&E, which is expected to be in service by mid-2014 and (ii) construction of 77 miles of transmission line from OG&E's Woodward District Extra High Voltage substation to a companion transmission line at the Kansas border to be built by either Mid-Kansas Electric Company or another company assigned by Mid-Kansas Electric Company at an estimated cost of $150 million to OG&E, which is expected to be in service by late 2014. On June 17, 2010, the FERC approved the cost allocation filed by the SPP and notices to construct these Priority Projects were issued by the SPP on June 30, 2010. On September 27, 2010, OG&E responded to the SPP that OG&E will construct the Priority Projects discussed above beginning in June 2012. The scope of the Woodward District Extra High Voltage substation/Kansas border Priority Project was subsequently revised and the SPP Board of Directors approved this revision in October 2010. The SPP issued a revised notice to construct for this Priority Project on November 22, 2010. On February 4, 2011, OG&E responded to the SPP that OG&E will construct the revised Priority Project.
The capital expenditures related to the Sooner-Rose Hill, Sunnyside-Hugo, Balanced Portfolio 3E and Priority Projects are presented in the summary of capital expenditures for known and committed projects in "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources - Future Capital Requirements and Financing Activities."
14.
Quarterly Financial Data (Unaudited)
Due to the seasonal fluctuations and other factors of OG&E's business, the operating results for interim periods are not necessarily indicative of the results that may be expected for the year. In OG&E's opinion, the following quarterly financial data includes all adjustments, consisting of normal recurring adjustments, necessary to fairly present such amounts. Summarized quarterly unaudited financial data is as follows:
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Stockholder
Oklahoma Gas and Electric Company
We have audited the accompanying balance sheets and statements of capitalization of Oklahoma Gas and Electric Company as of December 31, 2011 and 2010, and the related statements of income, changes in stockholder's equity, comprehensive income and cash flows for each of the three years in the period ended December 31, 2011. Our audits also included the financial statement schedule listed in the Index at Item 15(a). These financial statements and schedule are the responsibility of the company's management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Oklahoma Gas and Electric Company at December 31, 2011 and 2010, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2011, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Oklahoma Gas and Electric Company's internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 16, 2012 expressed an unqualified opinion thereon.
Oklahoma City, Oklahoma
February 16, 2012
Item 9.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.
None.
Item 9A.
Item 9A. Controls and Procedures.
OG&E maintains a set of disclosure controls and procedures designed to ensure that information required to be disclosed by OG&E in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission rules and forms. In addition, the disclosure controls and procedures ensure that information required to be disclosed is accumulated and communicated to management, including the chief executive officer and chief financial officer, allowing timely decisions regarding required disclosure. As of the end of the period covered by this report, based on an evaluation carried out under the supervision and with the participation of OG&E's management, including the chief executive officer and chief financial officer, of the effectiveness of OG&E's disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15(d)-15(e) under the Securities Exchange Act of 1934), the chief executive officer and chief financial officer have concluded that OG&E's disclosure controls and procedures are effective.
No change in OG&E's internal control over financial reporting has occurred during OG&E's most recently completed fiscal quarter that has materially affected, or is reasonably likely to materially affect, OG&E's internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934).
Management's Report on Internal Control Over Financial Reporting
The management of OG&E is responsible for establishing and maintaining adequate internal control over financial reporting. OG&E's internal control system was designed to provide reasonable assurance to OG&E's management and Board of Directors regarding the preparation and fair presentation of published financial statements. All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.
OG&E management assessed the effectiveness of OG&E's internal control over financial reporting as of December 31, 2011. In making this assessment, it used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control-Integrated Framework. Based on our assessment, we believe that, as of December 31, 2011,OG&E's internal control over financial reporting is effective based on those criteria.
OG&E's independent auditors have issued an attestation report on OG&E's internal control over financial reporting. This report appears on the following page.
/s/ Peter B. Delaney
/s/ Scott Forbes
Peter B. Delaney, Chairman of the Board, President
Scott Forbes, Controller
and Chief Executive Officer
and Chief Accounting Officer
/s/ Sean Trauschke
Sean Trauschke, Vice President
and Chief Financial Officer
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Stockholder
Oklahoma Gas and Electric Company
We have audited Oklahoma Gas and Electric Company's internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Oklahoma Gas and Electric Company's management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management's Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the company's internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, Oklahoma Gas and Electric Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2011, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the balance sheets and statements of capitalization of Oklahoma Gas and Electric Company as of December 31, 2011 and 2010, and the related statements of income, changes in stockholder's equity, comprehensive income and cash flows for each of the three years in the period ended December 31, 2011 of Oklahoma Gas and Electric Company and our report dated February 16, 2012 expressed an unqualified opinion thereon.
Oklahoma City, Oklahoma
February 16, 2012
Item 9B.
Item 9B. Other Information.
None.
PART III
Item 10.
Item 10. Directors, Executive Officers and Corporate Governance.
Code of Ethics Policy
OGE Energy maintains a code of ethics for our chief executive officer and senior financial officers, including the chief financial officer and chief accounting officer, which is available for public viewing on OGE Energy's web site address www.oge.com under the heading "Investor Relations", "Corporate Governance." The code of ethics will be provided, free of charge, upon request. OGE Energy intends to satisfy the disclosure requirements under Section 5, Item 5.05 of Form 8-K regarding an amendment to, or waiver from, a provision of the code of ethics by posting such information on its web site at the location specified above. OGE Energy will also include in its proxy statement information regarding the Audit Committee financial experts.
Under the reduced disclosure format permitted by General Instruction I(2)(c) of Form 10-K, the information otherwise required by Item 10 has been omitted.
Item 11.
Item 11. Executive Compensation.
Under the reduced disclosure format permitted by General Instruction I(2)(c) of Form 10-K, the information required by Item 11 has been omitted.
Item 12.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.
Under the reduced disclosure format permitted by General Instruction I(2)(c) of Form 10-K, the information required by Item 12 has been omitted.
Item 13.
Item 13. Certain Relationships and Related Transactions, and Director Independence.
Under the reduced disclosure format permitted by General Instruction I(2)(c) of Form 10-K, the information otherwise required by Item 13 has been omitted.
Item 14.
Item 14. Principal Accounting Fees and Services.
The following discussion relates to the audit fees paid by OGE Energy to its independent auditors for the services provided to OGE Energy and its subsidiaries, including OG&E
Fees for Independent Auditors
(A) Includes reviews of the financial statements included in OGE Energy's and OG&E's Quarterly Reports on Form 10-Q, audits
of OGE Energy's subsidiaries, preparation for Audit Committee meetings and fees for consulting with OGE Energy's and OG&E's executives regarding accounting issues.
(B) The aggregate audit fees include fees billed for the audit of OGE Energy's and OG&E's annual financial statements and for the reviews of the financial statements included in OGE Energy's and OG&E's Quarterly Reports on Form 10-Q. For 2011, this amount includes estimated billings for the completion of the 2011 audit, which services were rendered after year-end.
(C) Includes the U.S. Department of Energy Smart Grid grant audits.
All Other Fees
There were no other fees billed by the independent auditors to OGE Energy in 2011 and 2010 for other services.
Audit Committee Pre-Approval Procedures
Rules adopted by the Securities and Exchange Commission in order to implement requirements of the Sarbanes-Oxley Act of 2002 require public company audit committees to pre-approve audit and non-audit services. OGE Energy's Audit Committee follows procedures pursuant to which audit, audit-related and tax services, and all permissible non-audit services are pre-approved by category of service. The fees are budgeted, and actual fees versus the budget are monitored throughout the year. During the year, circumstances may arise when it may become necessary to engage the independent public accountants for additional services not contemplated in the original pre-approval. In those instances, OGE Energy will obtain the specific pre-approval of the Audit Committee before engaging the independent public accountants. The procedures require the Audit Committee to be informed of each service, and the procedures do not include any delegation of the Audit Committee's responsibilities to management. The Audit Committee may delegate pre-approval authority to one or more of its members. The member to whom such authority is delegated will report any pre-approval decisions to the Audit Committee at its next scheduled meeting.
For 2011, 100 percent of the audit fees, audit-related fees, tax fees and all other fees were pre-approved by the Audit Committee or the Chairman of the Audit Committee pursuant to delegated authority.
PART IV
Item 15.
Item 15. Exhibits and Financial Statement Schedules.
(a) 1. Financial Statements
The following Financial Statements are included in Part II, Item 8 of this Annual Report:
•
Statements of Income for the years ended December 31, 2011, 2010 and 2009
•
Statements of Comprehensive Income for the years ended December 31, 2011, 2010 and 2009
•
Statements of Cash Flows for the years ended December 31, 2011, 2010 and 2009
•
Balance Sheets at December 31, 2011 and 2010
•
Statements of Capitalization at December 31, 2011 and 2010
•
Statements of Changes in Stockholder's Equity for the years ended December 31, 2011, 2010 and 2009
•
Notes to Financial Statements
•
Report of Independent Registered Public Accounting Firm (Audit of Financial Statements)
•
Management's Report on Internal Control Over Financial Reporting
•
Report of Independent Registered Public Accounting Firm (Audit of Internal Control)
2. Financial Statement Schedule (included in Part IV)
•
Schedule II - Valuation and Qualifying Accounts
All other schedules have been omitted since the required information is not applicable or is not material, or because the information required is included in the respective Financial Statements or Notes thereto.
3. Exhibits
OKLAHOMA GAS AND ELECTRIC COMPANY
SCHEDULE II - Valuation and Qualifying Accounts
(A) Uncollectible accounts receivable written off, net of recoveries.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, as amended, the Registrant has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Oklahoma City, and State of Oklahoma on the 16th day of February, 2012.
OKLAHOMA GAS AND ELECTRIC COMPANY
(Registrant)
By /s/
Peter B. Delaney
Peter B. Delaney
Chairman of the Board, President
and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, as amended, this Report has been signed below by the following persons on behalf of the Registrant in the capacities and on the dates indicated.
Signature
Title
Date
/s/ Peter B. Delaney
Peter B. Delaney
Principal Executive
Officer and Director;
February 16, 2012
/s/ Sean Trauschke
Sean Trauschke
Principal Financial Officer; and
February 16, 2012
/s/ Scott Forbes
Scott Forbes
Principal Accounting Officer.
February 16, 2012
James H. Brandi
Director;
Wayne H. Brunetti
Director;
Luke R. Corbett
Director;
John D. Groendyke
Director;
Kirk Humphreys
Director;
Robert Kelley
Director;
Linda P. Lambert
Director;
Robert O. Lorenz
Director;
Judy R. McReynolds
Director; and
Leroy C. Richie
Director.
Supplemental Information to Be Furnished With Reports Filed Pursuant to Section 15(d) of the Act by Registrants Which Have Not Registered Securities Pursuant to Section 12 of the Act.
The Registrant has not sent, and does not expect to send, an annual report or proxy statement to its security holders.