	Page
FORWARD-LOOKING INFORMATION	1

Part I
Item 1. Business	2
The Company	2
General	3
Regulation and Rates	5
Rate Structures	7
Fuel Supply	7
Finance and Construction	9
Environmental Matters	10
Employees	10
Access to Securities and Exchange Commission Filings	10

Item 1A. Risk Factors	10

Item 1B. Unresolved Staff Comments	15

Item 2. Properties	16

Item 3. Legal Proceedings	17

Item 4. Submission of Matters to a Vote of Security Holders	18
Executive Officers of the Registrant	19

Part II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	22

Item 6. Selected Financial Data	22

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations	23

Item 7A. Quantitative and Qualitative Disclosures About Market Risk	39

Item 8. Financial Statements and Supplementary Data	42

Item 9. Changes In and Disagreements with Accountants on Accounting and Financial Disclosure	92

Item 9A. Controls and Procedures	92

Item 9B. Other Information	96

Part III
Item 10. Directors and Executive Officers of the Registrant	96

Item 11. Executive Compensation	96

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	96

Item 13. Certain Relationships and Related Transactions	96

Item 14. Principal Accounting Fees and Services	96

Part IV
Item 15. Exhibits, Financial Statement Schedules	97

Signatures	105

Except for the historical statements contained herein, the matters discussed in this Form 10-K, including those matters discussed in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations,” are forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements are intended to be identified in this document by the words “anticipate”, “believe”, “estimate”, “expect”, “intend”, “objective”, “plan”, “possible”, “potential”, “project” and similar expressions. Actual results may vary materially. In addition to the specific risk factors discussed in “Item 1A. Risk Factors” and “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations,” factors that could cause actual results to differ materially from the forward-looking statements include, but are not limited to:

The Company generates, transmits, distributes and sells electric energy in Oklahoma and western Arkansas. The Company is subject to regulation by the OCC, the APSC and the FERC. The Company is a wholly-owned subsidiary of Energy Corp. 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. The Company was incorporated in 1902 under the laws of the Oklahoma Territory. The Company is the largest electric utility in Oklahoma and its franchised service territory includes the Fort Smith, Arkansas area. The Company sold its retail gas business in 1928 and is no longer engaged in the gas distribution business. The Company’s principal executive offices are located at 321 North Harvey, P.O. Box 321, Oklahoma City, Oklahoma 73101-0321; telephone (405) 553-3000.

Energy Corp.’s vision is to be a regional utility-focused energy business recognized for operational excellence and strong financial performance. Energy Corp. intends to execute its vision by focusing on its regulated electric utility business and unregulated midstream gas business conducted by its wholly-owned natural gas pipeline subsidiary, Enogex Inc. and subsidiaries (“Enogex”). As explained below, Energy Corp. intends to maintain the majority of its assets in the regulated utility business complemented by its natural gas pipeline business. The Company’s long-term financial goals include earnings growth of four to five percent on a weather-normalized basis, an annual total return in the top third of its peer group, dividend growth, maintenance of a dividend payout ratio consistent with its peer group, maintenance of strong credit ratings and appropriate returns on invested capital. Energy Corp. believes it can accomplish these financial goals by, among other things, pursuing multiple avenues to build its business, maintaining a diversified asset position, continuing to develop a wide range of skills to succeed with changes in its industries, providing products and services to customers efficiently, managing risks effectively and maintaining strong regulatory and legislative relationships.

The Company has been focused on its Customer Savings and Reliability Plan, which provides for increased investment at the utility to improve reliability and meet load growth, replace infrastructure equipment, replace aging transmission and distribution system and deploy newer technology that improves operational, financial and environmental performance. As part of this plan, the Company purchased, for approximately $160 million, a 77 percent interest in the 520 megawatt (“MW”) natural gas-fired combined cycle NRG McClain Station (the “McClain Plant”) in July 2004. Capacity payment savings from reduced cogeneration payments and fuel savings from the McClain Plant will be utilized to help mitigate the price increases associated with this investment. Also, as part of this plan, on February 20, 2006, the Company entered into an agreement to engineer, procure and construct a wind generation energy system for a 120 MW wind farm (“Centennial”) in northwestern Oklahoma. The wind farm was fully in service in January 2007. Through December 31, 2006, the Company has spent approximately $171.1 million related to the Centennial wind farm. On January 17, 2007, the Company sent notice to the OCC to trigger the Centennial wind farm rider for the first billing cycle in February 2007. The Company has announced a six-year construction initiative that is estimated to include up to $3.3 billion in major projects designed to expand capacity, enhance reliability and improve environmental performance. The first part of this initiative involved the Company entering into an agreement for the proposed construction of a 950 MW coal unit at the Company’s existing Sooner plant location near Red Rock, Oklahoma. The Company expects construction to begin in 2007 and is targeting the completion of the power plant in the 2011/2012 timeframe. The Company’s share of the projected $1.8 billion construction cost for the plant will be about $759 million. The Company’s six-year construction initiative also includes strengthening and expanding the electric transmission, distribution and substation systems and replacing aging infrastructure. Other projects involve installing new emission-control equipment at existing Company power plants to help meet the Company’s commitment to meet environmental requirements. The Company also expects to incur a significant amount of capital and operating expenditures in the next several years to comply with current and future environmental laws and regulations. For additional information regarding the above items and other regulatory matters, see Note 14 of Notes to Financial Statements.

Energy Corp.’s business strategy is to continue maintaining the diversified asset position of the Company and Enogex so as to provide competitive energy products and services to customers primarily in the south central United States. Energy Corp. will continue to focus on those products and services with limited or manageable commodity exposure. In addition to the incremental growth opportunities that Enogex provides, Energy Corp. believes that many of the risk management practices, commercial skills and market information available from Enogex provide value to all of Energy

Corp.’s businesses. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Executive Overview” for a further discussion.

The Company furnishes retail electric service in 269 communities and their contiguous rural and suburban areas. During 2006, five other communities and two rural electric cooperatives in Oklahoma and western Arkansas purchased electricity from the Company for resale. The service area, with an estimated population of 2.0 million, covers approximately 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 269 communities that the Company serves, 243 are located in Oklahoma and 26 in Arkansas. The Company derived approximately 89 percent of its total electric operating revenues for the year ended December 31, 2006 from sales in Oklahoma and the remainder from sales in Arkansas.

The Company’s system control area peak demand as reported by the system dispatcher during 2006 was approximately 6,473 MW’s on August 10, 2006. The Company’s load responsibility peak demand was approximately 6,033 MW’s on August 10, 2006. As reflected in the table below and in the operating statistics on page 4, there were approximately 26.4 million megawatt-hour (“MWH”) sales to the Company’s customers (“system sales”) in 2006 as compared to approximately 26.0 million in 2005 and 24.7 million in 2004. System sales increased approximately 1.5 percent in 2006 primarily due to warmer weather during 2006. Variations in system sales for the three years are reflected in the following table:

The Company 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. In a citywide election in May 2006, Oklahoma City voters approved a 25-year franchise for the Company, which as noted above is the largest city in the Company’s service territory.

Besides competition from other suppliers or marketers of electricity, the Company 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. See Note 14 of Notes to Financial Statements for a discussion of the potential impact on competition from federal and state legislation.

OKLAHOMA GAS AND ELECTRIC COMPANY
CERTAIN OPERATING STATISTICS

Year ended December 31 (In millions)		2006		2005		2004

ELECTRIC ENERGY (Millions of MWH)
Generation (exclusive of station use)		24.6		24.8		22.6
Purchased		3.9		3.3		4.2
Total generated and purchased		28.5		28.1		26.8
Company use, free service and losses		(2.1)		(2.0)		(2.0)
Electric energy sold		26.4		26.1		24.8

ELECTRIC ENERGY SOLD (Millions of MWH)
Residential		8.7		8.5		7.9
Commercial		6.2		6.0		5.7
Industrial		7.1		7.2		7.0
Public authorities		2.9		2.8		2.7
Sales for resale		1.5		1.5		1.4
System sales		26.4		26.0		24.7
Off-system sales		---		0.1		0.1
Total sales		26.4		26.1		24.8

ELECTRIC OPERATING REVENUES (In millions)
Residential	$	698.8	$	663.6	$	611.4
Commercial		428.3		418.9		389.9
Industrial		345.0		355.6		326.7
Public authorities		171.0		173.1		158.5
Sales for resale		65.4		67.7		57.0
Provision for rate refund		(0.9)		(2.0)		(6.9)
System sales revenues		1,707.6		1,676.9		1,536.6
Off-system sales revenues		2.7		4.9		0.8
Other		35.4		38.9		40.7
Total Electric Operating Revenues	$	1,745.7	$	1,720.7	$	1,578.1

ACTUAL NUMBER OF ELECTRIC CUSTOMERS (At end of period)
Residential		647,548		639,733		630,736
Commercial		82,974		81,728		80,786
Industrial		9,505		9,472		9,420
Public authorities		14,769		14,515		14,022
Sales for resale		44		45		44
Total		754,840		745,493		735,008

AVERAGE RESIDENTIAL CUSTOMER SALES
Average annual revenue	$	1,084.31	$	1,043.60	$	975.08
Average annual use (kilowatt-hour (“KWH”))		13,526		13,455		12,630
Average price per KWH (cents)	$	8.02	$	7.76	$	7.72

The Company’s retail electric tariffs are regulated by the OCC in Oklahoma and by the APSC in Arkansas. The issuance of certain securities by the Company is also regulated by the OCC and the APSC. The Company’s wholesale electric tariffs, short-term borrowing authorization and accounting practices are subject to the jurisdiction of the FERC. The Secretary of the Department of Energy has jurisdiction over some of the Company’s facilities and operations. For the year ended December 31, 2006, approximately 87 percent of the Company’s electric revenue was subject to the jurisdiction of the OCC, nine percent to the APSC and four percent to the FERC.

The OCC issued an order in 1996 authorizing the Company to reorganize into a subsidiary of Energy Corp. The order required that, among other things, (i) Energy Corp. permit the OCC access to the books and records of Energy Corp. and its affiliates relating to transactions with the Company; (ii) Energy Corp. employ accounting and other procedures and controls to protect against subsidization of non-utility activities by the Company’s customers; and (iii) Energy Corp. refrain from pledging Company 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 Energy Corp. and its affiliates as the FERC deems relevant to costs incurred by the Company or necessary or appropriate for the protection of utility customers with respect to the FERC jurisdictional rates.

The Company has been and will continue to be affected by competitive changes to the utility industry. Significant changes already have occurred and additional changes are being proposed to the wholesale electric market. Although it appears unlikely in the near future that changes will occur to retail regulation in the states served by the Company due to the significant problems faced by other states in their electric deregulation efforts and other factors, significant changes are possible, which could significantly change the manner in which the Company conducts its business. These developments at the federal and state levels are described in more detail in Note 14 of Notes to Financial Statements.

Wind Power Filing. On February 20, 2006, the Company entered into an agreement to engineer, procure and construct the 120 MW Centennial wind farm planned for construction in northwestern Oklahoma. The wind farm was fully in service in January 2007. Through December 31, 2006, the Company has spent approximately $171.1 million related to the Centennial wind farm. On April 28, 2006, the OCC approved a settlement agreement approving the wind power contract and a recovery rider for up to $205 million in construction costs and allowance for funds used during construction. The settlement also indicated that the Company shall file for a general rate review during 2009 that will permit the OCC to issue an order no later than December 31, 2009 placing the Centennial wind farm in the Company’s rate base. On January 17, 2007, the Company sent notice to the OCC to trigger the Centennial wind farm rider for the first billing cycle in February 2007. The recovery rider is designed to recover approximately $22.6 million in the first year of operations, which amount will decline over the life of the facility. Because the wind farm rider was implemented in February 2007, the Company expects to recover approximately $20.7 million under the rider during the remaining 11 months of 2007. The Company expects the recovery rider to remain in effect through late 2009. As explained below, the recent rate order from the APSC allows for the recovery of the portion of the Centennial wind farm allocable to the Company’s customers in Arkansas.

Arkansas Rate Case Filing. On July 28, 2006, the Company filed with the APSC an application for an annual rate increase of approximately $13.5 million to recover, among other things, its investment in, and the operating expenses of, the McClain Plant, the Centennial wind power project and the costs of electric system expansion and upgrades based on a return on equity of 11.75 percent. On November 29, 2006, the Company reached a settlement with the other parties in this case for an annual rate increase of approximately $5.4 million. In the settlement agreement, the parties also agreed that the Company would be allowed to recover the full Arkansas portion of the Centennial wind farm. On January 5, 2007, the APSC approved the settlement and issued a rate order that provides for a $5.4 million annual increase in the Company’s electric rates and a 10.0 percent return on equity. The new Arkansas rates became effective in February 2007.

Proposed Construction of Power Plant. On July 18, 2006, Energy Corp. announced plans for the Company to partner with American Electric Power’s subsidiary, Public Service Company of Oklahoma (“PSO”), and the Oklahoma Municipal Power Authority (“OMPA”) to build a new 950 MW coal unit at the Company’s existing Sooner plant location near Red Rock, Oklahoma. The estimated $1.8 billion project is the result of PSO’s December 2005 request for proposals in which it sought bids for up to 600 MW’s of new base load generation to be available to PSO. The unit, to be called Red Rock, is expected to be one of the cleanest of its size using coal from the Powder River Basin, which is located near Gillette, Wyoming. The Company will operate the facility and expects to spend approximately $759 million in construction costs related to its 42 percent ownership percentage in the project and approximately $30 million in transmission costs for the project. PSO will own 50 percent and the OMPA will own eight percent. On December 1, 2006, the Company submitted an application to the Oklahoma Department of Environmental Quality (“ODEQ”) for an air permit for the Red Rock plant. The Company is seeking to have the air permit approved by the ODEQ by August 1, 2007. The Company expects construction to begin in 2007 and is targeting the completion of the power plant in the 2011/2012 timeframe. The Company filed an application with the OCC on January 17, 2007 asking the OCC to find that its portion of the construction costs are prudent and that a recovery mechanism should be established to recover the Company’s overall cost of capital on the investment during the construction period. The OCC rules provide that the OCC has up to 240 days to issue an order determining the Company’s pre-approval request, however the Company’s application requested that the OCC issue an order by July 20, 2007. The project is contingent upon numerous factors, including the successful completion of contract negotiations and the necessary regulatory and environmental approvals. Under the construction, ownership and operating agreement between the Company, PSO and the OMPA, the parties could incur up to $60 million (of which approximately $25 million would be borne by the Company) prior to the receipt of acceptable regulatory approvals and permits. If such approvals and permits were not obtained and the Red Rock project was abandoned, the Company can provide no assurance that these expenditures incurred by the Company would be recoverable in future rates.

See Note 14 of Notes to Financial Statements for a discussion of certain regulatory matters including, among other things, the gas transportation and storage contract between the Company and Enogex, the Company’s 2005 Oklahoma rate case order, security enhancements, national energy legislation and state legislative initiatives.

The Company, as a regulated utility, is subject to the accounting principles prescribed by SFAS No. 71. SFAS No. 71 provides 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.

At December 31, 2006 and 2005, the Company had regulatory assets of approximately $319.2 million and $189.2 million, respectively, and regulatory liabilities of approximately $224.5 million and $118.1 million, respectively. See Note 1 of Notes to Financial Statements for a further discussion.

As discussed in Note 14 of Notes to Financial Statements, legislation was enacted in Oklahoma that was to restructure the electric utility industry in that state. The implementation of the Oklahoma restructuring legislation has been delayed and seems unlikely to proceed during the near future. Yet, if and when implemented, this legislation could deregulate the Company’s electric generation assets and cause the Company to discontinue the use of SFAS No. 71 with respect to its related regulatory balances. The previously-enacted Oklahoma legislation would not affect the Company’s electric transmission and distribution assets and the Company believes that the continued use of SFAS No. 71 with respect to the related regulatory balances is appropriate. Based on a current evaluation of the various factors and conditions that are expected to impact future cost recovery, management believes that its regulatory assets, including those related to generation, are probable of future recovery.

The Company has had several different customer programs and rate options. The Guaranteed Flat Bill (“GFB”) 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 GFB option. The GFB option received OCC approval for permanent rate status in the Company’s rate case completed in December 2005. A second tariff rate option provides a “renewable energy” resource to the Company’s Oklahoma retail customers. This renewable energy resource is a wind power purchase program and is available as a voluntary option to all of the Company’s Oklahoma retail customers. The Company’s ownership and access to wind resources makes the renewable wind power option a possible choice in meeting the renewable energy needs of our conservation-minded customers and provides the customers with a means to reduce their exposure to increased prices for natural gas used by the Company as boiler fuel. A third rate offering available to commercial and industrial customers is levelized demand billing. This program is beneficial for medium to large size customers with seasonally consistent demand levels who wish to reduce the variability of their monthly electric bills. Another program being offered to the Company’s commercial and industrial customers is a voluntary load curtailment program. This program provides customers with the opportunity to curtail on a voluntary basis when the Company’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.

The previously discussed rate options coupled with the Company’s other rate choices provide many tariff options for the Company’s Oklahoma retail customers. The Company’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 our customers for many years to come. The revenue impacts associated with these options are indeterminate in future years since customers may choose to remain on existing rate options instead of volunteering for the new rate option choices. There was no overall material impact in 2005 or 2006 associated with these rate options, but revenue variations may occur in the future based upon changes in customers’ usage characteristics if they choose these programs.

Energy efficiency hearings are also currently being held by the APSC for all Arkansas utilities. These hearings are expected to lead to various conservation options and programs in the near future and result in better use of energy resources.

During 2006, approximately 67 percent of the Company-generated energy was produced by coal-fired units and 33 percent by natural gas-fired units. Of the Company’s 6,079 total MW capability reflected in the table under Item 2. Properties, approximately 3,480 MW’s, or 57 percent, are from natural gas generation and approximately 2,599 MW’s, or 43 percent, are from coal generation. Though the Company 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. A slight decline in the percentage of coal generation in future years is expected to result from increased usage of natural gas generation required to meet growing energy needs. Over the last five years, the weighted average cost of fuel used, by type, per million British thermal unit (“MMBtu”) was as follows:

The decrease in the weighted average cost of fuel in 2006 as compared to 2005 was primarily due to decreased natural gas prices partially offset by increased amounts of natural gas being burned. The increase in the weighted average cost of fuel in 2005 and in 2004 was primarily due to increased natural gas prices and increased amounts of natural gas being burned. The increase in the weighted average cost of fuel in 2003 as compared to 2002 was primarily due to increased natural gas prices in 2003 partially offset by a lower amount of natural gas burned in 2003. A portion of these fuel costs is included in the base rates to customers and differs for each jurisdiction. The portion of these fuel costs that is not included in the base rates is recoverable through the Company’s regulatorily approved automatic fuel adjustment clauses.

All of the Company’s coal-fired units, with an aggregate capability of approximately 2,599 MW’s, are designed to burn low sulfur western coal. The Company purchases coal primarily under long-term contracts expiring in years 2010 and 2011. During 2006, the Company purchased approximately 10.1 million tons of coal from various Wyoming suppliers. The combination of all coal has a weighted average sulfur content of less than 0.3 percent and can be burned in these units under existing federal, state and local environmental standards (maximum of 1.20 lbs. of sulfur dioxide per MMBtu) without the addition of sulfur dioxide removal systems. Based upon the average sulfur content, the Company’s coal units have an approximate emission rate of 0.52 lbs. of sulfur dioxide per MMBtu, well within the limitations of the current provisions of the Federal Clean Air Act discussed in Note 13 of Notes to Financial Statements.

The Company has continued its efforts to maximize the utilization of its coal-fired units at its Sooner and Muskogee generating plants. See “Environmental Laws and Regulations” in Note 13 of Notes to Financial Statements for a discussion of environmental matters which may affect the Company in the future.

In July 2005, the Company received notification from Union Pacific Railroad (“Union Pacific”) that, in May 2005, Union Pacific and BNSF Railway (“BNSF”) experienced successive derailments on the jointly-owned rail line serving the Southern Powder River Basin coal producers. According to Union Pacific, these two derailments were caused by track that had become unstable from an accumulation of coal dust in the roadbed combined with unusually heavy rainfall. BNSF, which maintains and operates the line, concluded that a significant part of the line needed to be repaired before normal train operations could resume. While the repairs were taking place, Union Pacific was unable to operate at full capacity from the Powder River Basin. In November 2005, Union Pacific notified the Company that the South Powder River Basin joint line force majeure condition that was declared in May 2005 had ended. On December 2, 2005, BNSF completed the enhanced joint line maintenance program which opened the way for a return to normal operating conditions. It is expected that as rail traffic improves, the Company will be able to increase its level of coal inventories. At December 31, 2006, the Company had slightly more than 30 days of coal supply for each of its coal-fired units at its Sooner and Muskogee generating plants. Furthermore, if no other significant disruptions occur going forward, the Company now expects to replenish its coal inventory to pre-disruption levels by the end of 2008.

In October 2006, the Company issued and completed a request for proposal (“RFP”) for gas supply purchases for periods that began in November 2006 through March 2007, which accounted for approximately eight percent of its projected 2007 natural gas requirements. All of these contracts are tied to various gas price market indices and will expire in 2007. The Company’s remaining 2007 natural gas requirements will be met with additional RFP’s issued in early to mid-2007. The Company will meet additional natural gas requirements with monthly and daily purchases as required.

In 1993, the Company began utilizing a natural gas storage facility for storage services that allowed the Company to maximize the value of its generation assets. Storage services are now provided by Enogex as part of Enogex’s gas transportation and storage contract with the Company. At December 31, 2006, the Company had approximately 1.6 million MMBtu’s in natural gas storage that it acquired for approximately $5.9 million.

In October 2006, the Company issued an RFP for firm economy energy purchases during the summer of 2007 and expects to select a supplier in early 2007. Also, in early 2007, the Company expects to issue an RFP for capacity and/or firm energy purchases for the summer periods of 2008 through 2010 and expects to select a supplier by the early summer of 2007.

The Company’s primary needs for capital are related to acquiring or constructing new facilities and replacing or expanding existing facilities in its electric utility business. Other working capital requirements are primarily related to maturing debt, operating lease obligations, hedging activities, delays in recovering unconditional fuel purchase obligations and fuel clause under and over recoveries. The Company generally meets its cash needs through a combination of internally generated funds, short-term borrowings (through a combination of bank borrowings, commercial paper and borrowings from Energy Corp.) and permanent financings. See “Item 7. Management’s Discussion and Analysis of Financial Conditions and Results of Operations – Liquidity and Capital Requirements” for a discussion of the Company’s capital requirements.

The Company’s current 2007 to 2012 construction program includes continued investment in its distribution, generation and transmission system. The Company’s current estimates of capital expenditures for 2007 through 2012 are approximately $426.5 million, $689.6 million, $745.1 million, $589.9 million, $480.2 million and $366.0 million, respectively, which include capital expenditures of approximately $94.0 million, $278.8 million, $285.7 million, $97.7 million and $34.1 million, respectively, in 2007 through 2011 related to the construction of the proposed Red Rock power plant discussed below. The Company also has approximately 550 MW’s of contracts with qualified cogeneration facilities (“QF”) and small power production producers’ (“QF contracts”) to meet its current and future expected customer needs. The Company 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.

In July 2006, Energy Corp. announced plans for the Company to partner with PSO and the OMPA to build a new 950 MW coal unit at the Company’s existing Sooner plant location near Red Rock, Oklahoma. The estimated $1.8 billion project is the result of PSO’s December 2005 request for proposals in which it sought bids for up to 600 MW’s of new base load generation to be available to PSO. The unit, to be called Red Rock, is expected to be one of the cleanest of its size using coal from the Powder River Basin, which is located near Gillette, Wyoming. The Company will operate the facility and expects to spend approximately $759 million in construction costs related to its 42 percent ownership percentage in the project and approximately $30 million in transmission costs for the project. PSO will own 50 percent and the OMPA will own eight percent. For additional information regarding the proposed construction of this power plant, see Note 14 of Notes to Financial Statements.

During 2006 and 2005, Energy Corp. made contributions to its pension plan of approximately $90.0 million and $32.0 million, respectively, to ensure that the pension plan maintains an adequate funded status, of which approximately $69.4 million and $24.8 million, respectively, were allocated to the Company. During 2007, Energy Corp. may contribute up to $50 million to its pension plan, of which approximately $38.5 million is expected to be

allocated to the Company. See “Item 7. Management’s Discussion and Analysis of Financial Conditions and Results of Operations – Liquidity and Capital Requirements” for a discussion of Energy Corp.’s pension and postretirement benefit plans.

Management expects that internally generated funds, the issuance of long and short-term debt and funds received from Energy Corp. (from proceeds from the sales of its common stock to the public through Energy Corp.’s Automatic Dividend Reinvestment and Stock Purchase Plan or other offerings) will be adequate over the next three years to meet anticipated cash needs. Energy Corp. utilizes short-term borrowings (through a combination of bank borrowings and commercial paper) to satisfy temporary working capital needs and as an interim source of financing capital expenditures until permanent financing is arranged.

Short-term borrowings generally are used to meet working capital requirements. In December 2006, Energy Corp. and the Company increased their aggregate available borrowing capacity under their revolving credit agreements from $750.0 million to $1.0 billion, $600 million for Energy Corp. and $400 million for the Company. Also, the Company has the necessary regulatory approvals to incur up to $800 million in short-term borrowings at any time for a two-year period beginning January 1, 2007 and ending December 31, 2008. See Note 11 of Notes to Financial Statements for a discussion of Energy Corp.’s and the Company’s short-term debt activity.

Approximately $15.6 million and $96.0 million, respectively, of the Company’s capital expenditures budgeted for 2007 and 2008 are to comply with environmental laws and regulations. The Company’s management believes that all of its operations are in substantial compliance with present federal, state and local environmental standards. It is estimated that the Company’s total expenditures for capital, operating, maintenance and other costs to preserve and enhance environmental quality will be approximately $81.9 million during 2007 as compared to approximately $58.0 million in 2006. The Company continues to evaluate its environmental management systems to ensure compliance with existing and proposed environmental legislation and regulations and to better position itself in a competitive market. See Note 13 of Notes to Financial Statements for a discussion of environmental matters, including the impact of existing and proposed environmental legislation and regulations.

Energy Corp.’s web site address is www.oge.com. Through Energy Corp.’s web site under the heading “Investors”, “SEC Filings,” Energy Corp. makes available, free of charge, its 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 (“SEC”).

In addition to the other information in this 10-K and other documents filed by us with the SEC from time to time, the following factors should be carefully considered in evaluating the Company. Such factors could affect actual results and cause results to differ materially from those expressed in any forward-looking statements made by or on our behalf. Additional risks and uncertainties not currently known to us or that we currently view as immaterial may also impair our business operations.

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. As indicated in the settlement agreement with the OCC related to the Company’s Centennial wind farm, the Company is to file for a general rate review during 2009.

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 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 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 condition 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 mortality, 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.

We may incur additional costs or delays in power plant construction and may not be able to recover our investment.

Our business plan includes the construction of an estimated 950 MW coal-fired generating plant. We have not recently managed a construction program of this magnitude. There are risks in the completion of this project including, among other things, that actual costs may exceed budget estimates, negotiation of satisfactory engineering, procurement and construction agreements, delays may occur in obtaining permits and materials, construction delays, supplier and contractor performance shortfalls, shortages and inconsistent quality of equipment, materials and labor,

work stoppages, adverse weather conditions, environmental and geological conditions, and events beyond our control may occur that may materially affect the schedule, budget and performance of this project. These risks may increase the costs of this project, require us to purchase additional electricity to supply our retail customers until the project is completed, or both, and may materially affect our results of operations and financial position. In addition, construction delays and contractor performance shortfalls can result in the loss of revenues and may, in turn, adversely affect our net income and financial position. Furthermore, if the construction project is not completed according to specification, we may incur liabilities and suffer reduced plant efficiency, higher operating costs and reduced net income. If we are unable to complete the construction of the facility or decide to delay or cancel construction of the facility, we may not be able to recover our investment in that facility.

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 condition. 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 planned capital investment program coincides with a material increase in the historic prices of the fuels used to generate electricity. Many of our jurisdictions have fuel clauses that permit us to recover these increased 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 condition.

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 facilities as part of a vertically integrated utility. We are a member of the Southwest Power Pool (“SPP”) regional transmission organization (“RTO”) and have transferred operational authority (but not ownership) of our transmission facilities to the SPP RTO. The SPP RTO implemented a regional energy imbalance service market on February 1, 2007. Without significant actual operating experience in this market, we cannot fully assess the impact this market will have on our business. Our revenues, expenses, assets and liabilities may be adversely affected by changes in the organization, operation and regulation by the FERC or the SPP RTO.

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 an impairment 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.

Recent 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 condition and access to capital.

As a result of the volatility of natural gas prices in North America, accounting irregularities at public companies in general, and energy companies in particular, and investigations by governmental authorities into energy trading activities, companies 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 corporations 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 condition 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 and liabilities. These changes in accounting standards could lead to negative impacts on reported earnings or increases in liabilities that could, in turn, affect our reported results of operations.

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.

The Energy Policy Act of 2005 gave the FERC authority to establish mandatory electric reliability rules enforceable with monetary penalties. The FERC has approved the North American Electric Reliability Corporation (“NERC”) as the Electric Reliability Organization for North America and delegated to it the development and enforcement of electric transmission reliability rules. It is the Company’s intent to comply with all applicable reliability rules and expediently correct a violation should it occur. The Company is subject to periodic NERC compliance audits and cannot predict the outcome of those audits.

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. In addition, as agreements with our suppliers expire, we may not be able to enter into new agreements for coal delivery on equivalent terms.

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, similar to the August 14,

2003 black-out in portions of the eastern U.S. and Canada. 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 condition and results of operations.

Weather conditions such as tornadoes, thunderstorms, ice storms, wind storms, as well as seasonal temperature variations may adversely affect our results of operations and financial position.

Weather conditions directly influence the demand for electric power. In our 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.

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.

We have defined benefit retirement and postretirement plans that cover substantially all of our employees. Assumptions related to future costs, returns on investments, interest rates and other actuarial assumptions have a significant impact on our earnings and funding requirements. Based on our assumptions at December 31, 2006, we expect to continue to make future contributions to maintain required funding levels. It is our 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.

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.

All employees hired prior to February 1, 2000 participate in defined benefit and 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.

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, approximately 28% 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 agreements 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 now face may intensify.

Any reductions in our credit ratings could increase our financing costs and the cost of maintaining certain contractual relationships.

We cannot assure that any of our current 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 in the future so warrant. Any future downgrade could increase the cost of short-term borrowings but would not result in any defaults or accelerations as a result of the rating changes.

We are exposed to commodity price risk in the operations of our business. To minimize the risk of commodity prices, we may enter into physical or financial derivative instrument contracts to hedge purchase and sale commitments, fuel requirements and inventories of natural gas, distillate fuel oil, electricity, coal and emission allowances. However, financial derivative instrument contracts do not eliminate the risk. Specifically, such risks include commodity price changes and market supply shortages. The impact of these variables could result in our inability to fulfill contractual obligations and significantly higher energy or fuel costs relative to corresponding sales contracts. However, exposure to commodity price risk related to our retail customers is partially mitigated by our fuel adjustment clause, although we cannot assure that all increases in our commodity prices, including fuel costs, will be completely recovered, or that any such recovery will be timely.

We are exposed to credit risks in our generation and retail distribution operations. Credit risk includes the risk that counterparties that owe us money or energy will breach their obligations. If the counterparties 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.

At December 31, 2006, the Company owns and operates an interconnected electric generation, transmission and distribution system, located in Oklahoma and western Arkansas, which includes eight generating stations with an aggregate capability of approximately 6,079 MW’s. The following table sets forth information with respect to the Company’s electric generating facilities, all of which are located in Oklahoma. Also, in January 2007, the Company’s 120 MW Centennial wind farm was fully in service.

						2006		Unit	Station
Station &		Year		Fuel	Unit	Capacity		Capability	Capability
Unit		Installed	Unit Design Type	Capability	Run Type	Factor (A)		(MW)	(MW)
Muskogee	3	1956	Steam-Turbine	Gas	Base Load	8.6%		156.5
	4	1977	Steam-Turbine	Coal	Base Load	76.3%		510.5
	5	1978	Steam-Turbine	Coal	Base Load	78.9%		521.6
	6	1984	Steam-Turbine	Coal	Base Load	70.5%		515.0	1,703.6

Seminole	1	1971	Steam-Turbine	Gas	Base Load	18.4%		506.0
	1GT	1971	Combustion-Turbine	Gas	Peaking	0.1%	(B)	17.0
	2	1973	Steam-Turbine	Gas	Base Load	23.5%		500.5
	3	1975	Steam-Turbine	Gas/Oil	Base Load	27.4%		519.0	1,542.5

Sooner	1	1979	Steam-Turbine	Coal	Base Load	69.5%		540.0
	2	1980	Steam-Turbine	Coal	Base Load	69.9%		512.0	1,052.0

Horseshoe	6	1958	Steam-Turbine	Gas/Oil	Base Load	16.5%		171.7
Lake	7	1963	Combined Cycle	Gas/Oil	Base Load	10.3%		234.0
	8	1969	Steam-Turbine	Gas	Base Load	9.5%		387.0
	9	2000	Combustion-Turbine	Gas	Peaking	5.9%	(B)	45.5
	10	2000	Combustion-Turbine	Gas	Peaking	5.3%	(B)	45.5	883.7

McClain (C)	1	2001	Combined Cycle	Gas	Base Load	83.2%		363.2	363.2

Mustang	1	1950	Steam-Turbine	Gas	Peaking	1.1%	(B)	54.0
	2	1951	Steam-Turbine	Gas	Peaking	0.7%	(B)	43.0
	3	1955	Steam-Turbine	Gas	Base Load	8.9%		117.5
	4	1959	Steam-Turbine	Gas	Base Load	21.0%		241.0
	5A	1971	Combustion-Turbine	Gas/Jet Fuel	Peaking	1.0%	(B)	34.0
	5B	1971	Combustion-Turbine	Gas/Jet Fuel	Peaking	1.1%	(B)	34.0	523.5

Woodward	1	1963	Combustion-Turbine	Gas	Peaking	0.2%	(B)	10.2	10.2

Enid	1	1965	Combustion-Turbine	Gas	Peaking	---	(D)	---
	2	1965	Combustion-Turbine	Gas	Peaking	---	(D)	---
	3	1965	Combustion-Turbine	Gas	Peaking	---	(D)	---
	4	1965	Combustion-Turbine	Gas	Peaking	---	(D)	---	---
Total Generating Capability (all stations)									6,078.7

At December 31, 2006, the Company’s transmission system included: (i) 28 substations with a total capacity of approximately 7.7 million kilo Volt-Amps (“kVA”) and approximately 4,026 structure miles of lines in Oklahoma; and (ii) two substations with a total capacity of approximately 1.9 million kVA and approximately 252 structure miles of lines in Arkansas. The Company’s distribution system included: (i) 347 substations with a total capacity of approximately 10.4 million kVA, 23,486 structure miles of overhead lines, 794 miles of underground conduit and 9,459 miles of underground conductors in Oklahoma; and (ii) 36 substations with a total capacity of

approximately 1.59 million kVA, 2,082 structure miles of overhead lines, 73 miles of underground conduit and 619 miles of underground conductors in Arkansas.

During the three years ended December 31, 2006, the Company’s gross property, plant and equipment (excluding construction work in progress) additions were approximately $935.3 million and gross retirements were approximately $180.8 million. These additions were provided by internally generated funds from operating cash flows, short-term borrowings (through a combination of bank borrowings, commercial paper and borrowings from Energy Corp.) and permanent financings. The additions during this three-year period amounted to approximately 18.8 percent of total property, plant and equipment at December 31, 2006.

In the normal course of business, the Company is confronted with issues or events that may result in a contingent liability. These generally relate to lawsuits, claims made by third parties, environmental actions or the action of various regulatory agencies and income tax related items. Management consults with legal counsel and other appropriate experts to assess the claim. If, in management’s opinion, the Company has incurred a probable loss as set forth by accounting principles generally accepted in the United States, an estimate is made of the loss and the appropriate accounting entries are reflected in the Company’s Financial Statements. Except as set forth below and in Notes 13 and 14 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 the Company’s financial position, results of operations or cash flows.

1. United States of America ex rel., Jack J. Grynberg v. Enogex Inc., Enogex Services Corporation and the Company. (United States District Court for the Western District of Oklahoma, Case No. CIV-97-1010-L.) United States of America ex rel., Jack J. Grynberg v. Transok Inc. et al. (United States District Court for the Eastern District of Louisiana, Case No. 97-2089; United States District Court for the Western District of Oklahoma, Case No. 97-1009M.). On June 15, 1999, the Company was served with Plaintiff’s complaint, which is a qui tam action under the False Claims Act. Plaintiff Jack J. Grynberg, as individual relator on behalf of the United States Government, alleges: (i) each of the named defendants have improperly or intentionally mismeasured gas (both volume and Btu content) purchased from federal and Indian lands which have resulted in the under-reporting and underpayment of gas royalties owed to the Federal Government; (ii) certain provisions generally found in gas purchase contracts are improper; (iii) transactions by affiliated companies are not arms-length; (iv) excess processing cost deduction; and (v) failure to account for production separated out as a result of gas processing. Grynberg seeks the following damages: (a) additional royalties which he claims should have been paid to the Federal Government, some percentage of which Grynberg, as relator, may be entitled to recover; (b) treble damages; (c) civil penalties; (d) an order requiring defendants to measure the way Grynberg contends is the better way to do so; and (e) interest, costs and attorneys’ fees.

In qui tam actions, the United States Government can intervene and take over such actions from the relator. The Department of Justice, on behalf of the United States Government, decided not to intervene in this action.

Plaintiff filed over 70 other cases naming over 300 other defendants in various Federal Courts across the country containing nearly identical allegations. The Multidistrict Litigation Panel entered its order in late 1999 transferring and consolidating for pretrial purposes approximately 76 other similar actions filed in nine other Federal Courts. The consolidated cases are now before the United States District Court for the District of Wyoming.

In October 2002, the Court granted the Department of Justice’s motion to dismiss certain of Plaintiff’s claims and issued an order dismissing Plaintiff’s valuation claims against all defendants. Various procedural motions have been filed. A hearing on the defendants’ motions to dismiss for lack of subject matter jurisdiction, including public disclosure, original source and voluntary disclosure requirements was held in 2005 and the special master ruled that the Company and all Enogex parties named in these proceedings should be dismissed. This ruling was appealed to the District Court of Wyoming.

2006 and Grynberg filed his notice of appeal with the District Court of Wyoming. The defendants filed motions for attorneys’ fees regarding issues of liability and Rule 11 motions on January 8, 2007. The defendants also filed for other legal costs on December 18, 2006. A hearing on these motions is currently scheduled for April 24, 2007. Grynberg has also filed appeals with the Tenth Circuit Court of Appeals. The Company intends to vigorously defend this action. At this time, the Company is unable to provide an evaluation of the likelihood of an unfavorable outcome and an estimate of the amount or range of potential loss to the Company.

2. Will Price (Price I) – On September 24, 1999, various subsidiaries of Energy Corp. were served with a class action petition filed in United States District Court, State of Kansas by Quinque Operating Company and other named plaintiffs, alleging mismeasurement of natural gas on non-federal lands. On April 10, 2003 the Court entered an order denying class certification. On May 12, 2003, 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 petition and the court granted the motion on July 28, 2003. In this amended petition, the Company and Enogex Inc. were omitted from the case. Two subsidiaries of Enogex remain as defendants. The Plaintiffs’ amended petition alleges that approximately 60 defendants, including two Enogex subsidiaries, have improperly measured natural gas. The amended petition reduces the claims to: (1) mismeasurement of volume only; (2) conspiracy, unjust enrichment and accounting; (3) a putative Plaintiffs’ class of only royalty owners; and (4) gas measured in three specific states. A hearing on class certification issues was held April 1, 2005. Energy Corp. intends to vigorously defend this action. At this time, Energy Corp. is unable to provide an evaluation of the likelihood of an unfavorable outcome and an estimate of the amount or range of potential loss to Energy Corp.

3. On June 19, 2006, two Company customers brought a putative class action, on behalf of all similarly situated customers, in the District Court of Creek County, Oklahoma, challenging certain charges on the Company’s electric bills. The plaintiffs claim that the Company improperly charged sales tax based on franchise fee charges paid by its customers. The plaintiffs also challenge certain franchise fee charges, contending that such fees are more than is allowed under Oklahoma law. The Company’s motion for summary judgment was denied by the trial judge. The Company has filed a writ of prohibition at the Oklahoma Supreme Court asking the court to direct the trial court to dismiss the class action suit. At the present time, the Company believes that this case is without merit and intends to continue vigorously defending this case.

Under the reduced disclosure format permitted by General Instruction I(2)(c) of Form 10-K, the information otherwise required by this item has been omitted.

The following persons were Executive Officers of the Registrant as of February 16, 2007:

Name	Age	Title

Steven E. Moore	60	Chairman of the Board and Chief Executive Officer

Peter B. Delaney	53	President and Chief Operating Officer

James R. Hatfield	49	Senior Vice President and Chief Financial Officer

Carla D. Brockman	47	Vice President - Administration / Corporate Secretary

Steven R. Gerdes	50	Vice President - Utility Operations

Gary D. Huneryager	56	Vice President - Internal Audits

Jesse B. Langston	44	Vice President - Utility Commercial Operations

Cary W. Martin	54	Vice President - Human Resources

Howard W. Motley	58	Vice President - Regulatory Affairs

Reid Nuttall	49	Vice President - Enterprise Information and Performance

Melvin H. Perkins, Jr.	58	Vice President - Transmission

Paul L. Renfrow	50	Vice President - Public Affairs

Deborah S. Fleming	51	Vice President - Treasurer

Scott Forbes	49	Controller and Chief Accounting Officer

Jerry A. Peace	44	Chief Risk and Compliance Officer

No family relationship exists between any of the Executive Officers of the Registrant. Messrs. Moore, Delaney, Hatfield, Huneryager, Martin, Nuttall, Renfrow, Forbes and Peace, Ms. Brockman and Ms. Fleming are also officers of Energy Corp. Each Officer is to hold office until the Board of Directors meeting following the next Annual Meeting of Stockholders, currently scheduled for May 17, 2007.

The business experience of each of the Executive Officers of the Registrant for the past five years is as follows:

Name		Business Experience

Steven E. Moore	2007 – Present:	Chairman of the Board and Chief Executive Officer of Energy
		Corp. and the Company
	2002 – 2007:	Chairman of the Board, President and Chief Executive Officer
		of Energy Corp. and the Company

Peter B. Delaney	2007 – Present:	President and Chief Operating Officer of Energy Corp. and the
		Company
	2004 – 2007:	Executive Vice President and Chief Operating Officer of
		Energy Corp. and the Company
	2002 – 2004:	Executive Vice President, Finance and Strategic Planning –
		Energy Corp. and Chief Executive Officer – Enogex Inc.
	2002:	Principal, PD Energy Advisors (consulting firm)

James R. Hatfield	2002 – Present:	Senior Vice President and Chief Financial Officer of Energy
		Corp. and the Company

Carla D. Brockman	2005 – Present:	Vice President – Administration / Corporate Secretary of
		Energy Corp. and the Company
	2002 – 2005:	Corporate Secretary of Energy Corp. and the Company
	2002:	Assistant Corporate Secretary of Energy Corp. and the
		Company
	2002:	Client Manager – Strategic Planning of Energy Corp. and the
		Company

Steven R. Gerdes	2003 – Present:	Vice President – Utility Operations of the Company
	2002 – 2003:	Vice President – Shared Services of Energy Corp. and the
		Company

Gary D. Huneryager	2005 – Present:	Vice President – Internal Audits of Energy Corp. and the
		Company
	2002 – 2005:	Internal Audit Officer of Energy Corp. and the Company
	2002:	Assistant Internal Audit Officer of Energy Corp. and the
		Company

Jesse B. Langston	2006 – Present:	Vice President – Utility Commercial Operations
	2005 – 2006:	Director – Utility Commercial Operations
	2004 – 2005:	Director – Corporate Planning
	2002 – 2003:	Manager – Corporate Planning

Cary W. Martin	2006 – Present:	Vice President – Human Resources
	2005 – 2006:	Vice President – Global Human Resources – SPX Corporation
	2004 – 2005:	Vice President – Human Resources, Technical and Industrial
		Systems – SPX Corporation
	2002 – 2004:	Vice President – Human Resources, Communication and
		Technology Systems – SPX Corporation (global industrial
		manufacturer)

Howard W. Motley	2006 – Present:	Vice President – Regulatory Affairs
	2004 – 2006:	Director – Regulatory Affairs and Strategy
	2003 – 2004:	Director – Regulatory Strategies and Utility Resources
	2002 – 2003:	Manager – Regulatory Strategies and Utility Resources
	2002:	Manager, Rate Strategies

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.

Currently, all of the Company’s outstanding common stock is held by Energy Corp. Therefore, there is no public trading market for the Company’s common stock.

During 2006, 2005 and 2004, the Company paid dividends of approximately $39.0 million, $74.0 million and $107.6 million to Energy Corp.

Year ended December 31		2006 (A)	2005	2004	2003	2002
SELECTED FINANCIAL DATA
(In millions)

Operating revenues		$ 1,745.7	$ 1,720.7	$ 1,578.1	$ 1,517.1	$ 1,388.0
Cost of goods sold		950.0	994.2	914.2	837.3	695.7
Gross margin on revenues		795.7	726.5	663.9	679.8	692.3
Other operating expenses		501.8	494.3	471.6	463.5	453.1
Operating income		293.9	232.2	192.3	216.3	239.2
Interest income		1.9	2.6	2.7	0.7	1.2
Allowance for equity funds used during
construction		4.1	---	0.9	---	---
Other income (loss)		4.0	(2.8)	4.5	0.4	0.6
Other expense		9.7	2.5	2.3	3.0	3.1
Interest expense		60.1	47.2	37.5	38.8	40.2
Income tax expense		84.8	52.6	53.0	60.2	71.6
Net income		$ 149.3	$ 129.7	$ 107.6	$ 115.4	$ 126.1

Long-term debt		$ 843.3	$ 844.0	$ 847.2	$ 707.2	$ 710.5
Total assets		$ 3,589.7	$ 3,255.0	$ 3,057.7	$ 2,737.5	$ 2,659.9

CAPITALIZATION RATIOS (B)
Stockholder’s equity		61.05%	56.94%	55.64%	56.54%	56.00%
Long-term debt		38.95%	43.06%	44.36%	43.46%	44.00%

RATIO OF EARNINGS TO
FIXED CHARGES (C)
Ratio of earnings to fixed charges		4.43	4.44	4.76	5.11	5.41
	(A) The Company adopted Statement of Financial Accounting Standard No. 123 (Revised), “Share-Based Payment,” using the modified prospective transition method, effective January 1, 2006, which required the Company to measure and recognize the cost of employee services received in exchange for an award of equity instruments based on the grant date fair value of the award.
	(B) Capitalization ratios = [Stockholder’s equity / (Stockholder’s equity + Long-term debt + Long-term debt due within one year)] and [(Long-term debt + Long-term debt due within one year) / (Stockholder’s equity + Long-term debt + Long-term debt due within one year)].
	(C) For purposes of computing the ratio of earnings to fixed charges, (1) earnings consist of pre-tax income plus fixed charges, less allowance for borrowed funds used during construction; and (2) 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. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Oklahoma Gas and Electric Company (the “Company”) generates, transmits, distributes and sells electric energy in Oklahoma and western Arkansas. The Company is subject to regulation by the Oklahoma Corporation Commission (“OCC”), the Arkansas Public Service Commission (“APSC”) and the Federal Energy Regulatory Commission (“FERC”). The Company is a wholly-owned subsidiary of OGE Energy Corp. (“Energy Corp.”) 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. The Company was incorporated in 1902 under the laws of the Oklahoma Territory. The Company is the largest electric utility in Oklahoma and its franchised service territory includes the Fort Smith, Arkansas area. The Company sold its retail gas business in 1928 and is no longer engaged in the gas distribution business.

United States. Energy Corp. will continue to focus on those products and services with limited or manageable commodity exposure. In addition to the incremental growth opportunities that Enogex provides, Energy Corp. believes that many of the risk management practices, commercial skills and market information available from Enogex provide value to all of Energy Corp.’s businesses.

In December 2006, Energy Corp. and the Company increased their aggregate available borrowing capacity under their revolving credit agreements from $750.0 million to $1.0 billion, $600 million for Energy Corp. and $400 million for the Company. Each of the credit facilities has a five-year term with an option to extend the term for two additional one-year periods. Also, each of these credit facilities has an additional option at the end of the two renewal options to convert the outstanding balance to a one-year term loan. These revolving credit agreements will provide sufficient liquidity to meet the Company’s daily operational needs and capital improvements.

2006 compared to 2005. The Company reported net income of approximately $149.3 million and $129.7 million for the years ended December 31, 2006 and 2005, respectively. The increase was primarily due to rate increases authorized in the OCC order in December 2005, customer growth and increased usage in the Company’ss service territory partially offset by increased operating and maintenance expenses and increased interest expense.

2005 compared to 2004. The Company reported net income of approximately $129.7 million and $107.6 million for the years ended December 31, 2005 and 2004, respectively. The increase in net income was primarily due to warmer weather, customer growth and increased usage in the Company’ss service territory partially offset by increased operating and maintenance expenses, depreciation expense, interest expense and ad valorem taxes due to the acquisition of the McClain Plant, which ceased being recorded as a regulatory asset on July 8, 2005.

As discussed above, in January 2007, the Centennial wind farm in northwestern Oklahoma was fully in service. Through December 31, 2006, the Company has spent approximately $171.1 million related to the Centennial wind farm. The OCC previously had approved a settlement agreement approving the Centennial wind power contract and a recovery rider for up to $205 million in construction costs and allowance for funds used during construction. The settlement also indicated that the Company shall file for a general rate review during 2009 that will permit the OCC to issue an order no later than December 31, 2009 placing the Centennial wind farm in the Company’s rate base. On January 17, 2007, the Company sent notice to the OCC to trigger the Centennial wind farm rider for the first billing cycle in February 2007. The recovery rider is designed to recover approximately $22.6 million in the first year of operations, which amount will decline over the life of the facility. Because the wind farm rider was implemented in February 2007, the Company expects to recover approximately $20.7 million under the rider during the remaining 11 months of 2007. The Company expects the recovery rider to remain in effect through late 2009. As explained below, the recent rate order from the APSC allows for the recovery of the portion of the Centennial wind farm allocable to the Company’s customers in Arkansas.

On July 28, 2006, the Company filed with the APSC an application for an annual rate increase of approximately $13.5 million to recover, among other things, its investment in, and the operating expenses of, the McClain Plant, the Centennial wind power project and the costs of electric system expansion and upgrades based on a return on equity of 11.75 percent. On November 29, 2006, the Company reached a settlement with the other parties in this case for an annual rate increase of approximately $5.4 million. In the settlement agreement, the parties also agreed that the Company would be allowed to recover the full Arkansas portion of the Centennial wind farm. On January 5, 2007, the APSC approved the settlement and issued a rate order that provides for a $5.4 million annual increase in the Company’s electric rates and a 10.0 percent return on equity. The new Arkansas rates became effective in February 2007.

As discussed above, the Company has entered into a contract with American Electric Power’s subsidiary, Public Service Company of Oklahoma (“PSO”), and the Oklahoma Municipal Power Authority (“OMPA”) to build a new 950 MW coal unit at the Company’s existing Sooner plant location near Red Rock, Oklahoma. The estimated $1.8 billion project is the result of PSO’s December 2005 request for proposals in which it sought bids for up to 600 MW’s of new base load generation to be available to PSO. The unit, to be called Red Rock, is expected to be one of the cleanest of its size using coal from the Powder River Basin, which is located near Gillette, Wyoming. The Company will operate the facility and expects to spend approximately $759 million in construction costs related to its 42 percent ownership percentage in the project and approximately $30 million in transmission costs for the project. PSO will own 50 percent and the OMPA will own eight percent. On December 1, 2006, the Company submitted an application to the Oklahoma Department of Environmental Quality (“ODEQ”) for an air permit for the Red Rock plant. The Company is seeking to have the air permit approved by the ODEQ by August 1, 2007. The Company expects construction to begin in 2007 and is targeting the completion of the power plant in the 2011/2012 timeframe. The Company filed an application with the OCC on January 17, 2007 asking the OCC to find that its portion of the construction costs are prudent and that a recovery mechanism should be established to recover the Company’s overall cost of capital on the investment during the construction period. The OCC rules provide that the OCC has up to 240 days to issue an order determining the Company’s pre-approval request, however the Company’s application requested that the OCC issue an order by July 20, 2007. The project is contingent upon numerous factors, including the successful completion of contract negotiations and the necessary regulatory and environmental approvals. Under the construction, ownership and operating agreement between the Company, PSO and the OMPA, the parties could incur up to $60 million (of which approximately $25 million would be borne by the Company) prior to the receipt of acceptable regulatory approvals and permits. If such approvals and permits were not obtained and the Red Rock project was abandoned, the Company can provide no assurance that these expenditures incurred by the Company would be recoverable in future rates.

In July 2006, the Boards of Directors of Bridgestone Firestone North American Tire and its parent company, Bridgestone Americas Holding Inc., approved the closing of the Oklahoma City Dayton tire plant, which closed in December 2006. The closing of this plant is expected to reduce net income by approximately $1.1 million in 2007.

Energy Corp. previously disclosed in its Form 10-Q for the quarter ended September, 2006 that its 2007 earnings guidance was $213 million to $231 million of income from continuing operations, or $2.30 to $2.50 per diluted share. Energy Corp. has reaffirmed the 2007 earnings guidance, which excludes any gains on asset sales and assumes approximately 92.5 million average diluted shares outstanding and an effective tax rate of 32.6 percent. Energy Corp. is currently projecting earnings toward the lower half of the guidance due to refinements of its prior estimates based on its 2006 audited financial results and numerous other factors. At the utility, these factors include reduced tariffs for fuel-related costs, the slight delay in implementing the Centennial wind farm rider and increased depreciation expense, offset in part by higher anticipated margin growth. Projected cash flow from operations of between $371 million and $389 million for 2007 has been lowered to $336 million to $354 million primarily due to the collection by the Company during 2006 under approved tariffs of approximately $26.7 million of additional fuel-related revenues that was not intended by the OCC rate order in December 2005. The $26.7 million, plus interest, will be credited to the Company’s Oklahoma customers in 2007 and 2008 through the Company’s automatic fuel adjustment clause and reduced tariffs were filed, effective December 31, 2006, that will cease the continued recovery of these additional fuel-related revenues. See “Financial Condition” below.

The Company’s earnings guidance has been reaffirmed at $154 million to $162 million. Key factors and assumptions underlying this guidance include:

The Company has significant seasonality in its earnings. The Company typically shows minimal earnings or slight losses in the first and fourth quarters with a majority of earnings in the third quarter due to the seasonal nature of air conditioning demand.

The following discussion and analysis presents factors that affected the Company’s results of operations for the years ended December 31, 2006, 2005 and 2004 and the Company’s financial position at December 31, 2006 and 2005. 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, the Company 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 the Company excluding unusual or infrequent items, the cost of capital and income taxes.

Year ended December 31 (Dollars in millions)	2006	2005	2004
Operating revenues	$ 1,745.7	$ 1,720.7	$ 1,578.1
Cost of goods sold	950.0	994.2	914.2
Gross margin on revenues	795.7	726.5	663.9
Other operation and maintenance	316.5	309.2	301.9
Depreciation	132.2	134.4	122.7
Taxes other than income	53.1	50.7	47.0
Operating income	293.9	232.2	192.3
Interest income	1.9	2.6	2.7
Allowance for equity funds used during construction	4.1	---	0.9
Other income (loss)	4.0	(2.8)	4.5
Other expense	9.7	2.5	2.3
Interest expense	60.1	47.2	37.5
Income tax expense	84.8	52.6	53.0
Net income	$ 149.3	$ 129.7	$ 107.6
Operating revenues by classification
Residential	$ 698.8	$ 663.6	$ 611.4
Commercial	428.3	418.9	389.9
Industrial	345.0	355.6	326.7
Public authorities	171.0	173.1	158.5
Sales for resale	65.4	67.7	57.0
Provision for rate refund	(0.9)	(2.0)	(6.9)
System sales revenues	1,707.6	1,676.9	1,536.6
Off-system sales revenues	2.7	4.9	0.8
Other	35.4	38.9	40.7
Total operating revenues	$ 1,745.7	$ 1,720.7	$ 1,578.1
MWH (A) sales by classification (in millions)
Residential	8.7	8.5	7.9
Commercial	6.2	6.0	5.7
Industrial	7.1	7.2	7.0
Public authorities	2.9	2.8	2.7
Sales for resale	1.5	1.5	1.4
System sales	26.4	26.0	24.7
Off-system sales	---	0.1	0.1
Total sales	26.4	26.1	24.8
Number of customers	754,840	745,493	735,008
Average cost of energy per KWH (B) - cents
Fuel	3.040	3.011	2.887
Fuel and purchased power	3.398	3.300	3.436
Degree days (C)
Heating
Actual	2,746	3,159	3,114
Normal	3,631	3,631	3,650
Cooling
Actual	2,485	2,163	1,839
Normal	1,911	1,911	1,911

2006 compared to 2005. The Company’s operating income increased approximately $61.7 million or 26.7 percent in 2006 as compared to 2005 primarily due to higher gross margins partially offset by higher operating expenses.

Gross margin, which is operating revenues less cost of goods sold, was approximately $795.7 million in 2006 as compared to approximately $726.5 million in 2005, an increase of approximately $69.2 million, or 9.5 percent. The gross margin increased primarily due to:

Cost of goods sold for the Company consists of fuel used in electric generation and purchased power. Fuel expense was approximately $730.3 million in 2006 as compared to approximately $795.4 million in 2005, a decrease of approximately $65.1 million or 8.2 percent due to lower natural gas prices. The Company’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 the Company and its customers. In 2006 and 2005, respectively, the Company’s fuel mix was 67 percent coal and 33 percent natural gas and 70 percent coal and 30 percent natural gas. Though the Company has a higher installed capability of generation from natural gas units of 57 percent, it has been more economical to generate electricity for our customers with lower priced coal. Purchased power costs were approximately $219.7 million in 2006 as compared to approximately $198.8 million in 2005, an increase of approximately $20.9 million or 10.5 percent. This increase was primarily due to a power purchase contract that allowed the Company to make economic purchases during peak demand summer months.

Other operating and maintenance expenses were approximately $316.5 million in 2006 as compared to approximately $309.2 million in 2005, an increase of approximately $7.3 million or 2.4 percent. The increase in other operating and maintenance expenses was primarily due to:

The other operating and maintenance expense variance includes other operating and maintenance expenses associated with the acquisition of the McClain Plant, which expenses ceased being recorded as a regulatory asset on July 8, 2005.

Depreciation expense was approximately $132.2 million in 2006 as compared to approximately $134.4 million in 2005, a decrease of approximately $2.2 million or 1.6 percent. The decrease in depreciation expense was primarily due to:

These decreases in depreciation expense were partially offset by a full year of depreciation expense in 2006 associated with the acquisition of the McClain Plant.

Taxes other than income were approximately $53.1 million in 2006 as compared to approximately $50.7 million in 2005, an increase of approximately $2.4 million or 4.7 percent, primarily due to increased ad valorem taxes. This variance includes ad valorem taxes associated with the acquisition of the McClain Plant, which expenses ceased being recorded as a regulatory asset on July 8, 2005.

Allowance for equity funds used during construction was approximately $4.1 million in 2006 due to construction costs associated with the Company’s Centennial wind farm that exceeded the average daily short-term borrowings in 2006. There was no allowance for equity funds used during construction in 2005.

Other income includes, among other things, contract work performed, non-operating rental income and miscellaneous non-operating income. Other income was approximately $4.0 million in 2006 as compared to a reduction in other income of approximately $2.8 million in 2005, an increase in other income of approximately $6.8 million. The increase in other income was primarily due to:

Other expense includes, among other things, expenses from losses on the sale and retirement of assets, miscellaneous charitable donations, expenditures for certain civic, political and related activities and miscellaneous deductions and expenses. Other expense was approximately $9.7 million in 2006 as compared to approximately $2.5 million in 2005, an increase of approximately $7.2 million primarily due to a loss on the retirement of fixed assets of approximately $6.0 million.

Interest expense was approximately $60.1 million in 2006 as compared to approximately $47.2 million in 2005, an increase of approximately $12.9 million or 27.3 percent. The increase in interest expense was primarily due to:

Income tax expense was approximately $84.8 million in 2006 as compared to approximately $52.6 million in 2005, an increase of approximately $32.2 million or 61.2 percent. The increase in income tax expense was primarily due to:

2005 compared to 2004. The Company’s operating income increased approximately $39.9 million or 20.7 percent in 2005 as compared to 2004 primarily attributable to higher gross margins partially offset by higher operating expenses.

Gross margin was approximately $726.5 million in 2005 as compared to approximately $663.9 million in 2004, an increase of approximately $62.6 million or 9.4 percent. The gross margin increased primarily due to:

Fuel expense was approximately $795.4 million in 2005 as compared to approximately $645.1 million in 2004, an increase of approximately $150.3 million or 23.3 percent. The increase was primarily due to increased generation and a higher average cost of fuel per kwh. The Company’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 the Company and its customers. In 2005 and 2004, the Company’s fuel mix was 70 percent coal and 30 percent natural gas. Though the Company has a higher installed capability of generation from natural gas units of 58 percent, it has been more economical to generate electricity for our customers with lower priced coal. Purchased power costs were approximately $198.8 million in 2005 as compared to approximately $269.1 million in 2004, a decrease of approximately $70.3 million or 26.1 percent. The decrease was primarily due to the Company’s completion of the acquisition of the McClain Plant in 2004, the termination of a power purchase contract in August 2004 which was replaced with a new contract in September 2004 and the scheduled decrease in cogeneration capacity payments for another power purchase contract, which became effective in January 2005.

Other operating and maintenance expenses were approximately $309.2 million in 2005 as compared to approximately $301.9 million in 2004, an increase of approximately $7.3 million or 2.4 percent. The increase in other operating and maintenance expenses was primarily due to:

These increases in other operating and maintenance expenses were partially offset by lower allocations from the holding company of approximately $6.9 million primarily due to lower miscellaneous corporate expenses. This variance includes other operating and maintenance expenses associated with the acquisition of the McClain Plant, which ceased being recorded as a regulatory asset on July 8, 2005.

Depreciation expense was approximately $134.4 million in 2005 as compared to approximately $122.7 million in 2004, an increase of approximately $11.7 million or 9.5 percent, primarily due to a higher level of depreciable plant in addition to depreciation expense associated with the acquisition of the McClain Plant, which ceased being recorded as a regulatory asset on July 8, 2005.

Taxes other than income were approximately $50.7 million in 2005 as compared to approximately $47.0 million in 2004, an increase of approximately $3.7 million or 7.9 percent, primarily due to increased ad valorem taxes. This variance includes ad valorem taxes associated with the acquisition of the McClain Plant, which ceased being recorded as a regulatory asset on July 8, 2005.

There was a reduction in other income of approximately $2.8 million in 2005 as compared to income of approximately $4.5 million in 2004, a decrease of approximately $7.3 million. The decrease in other income was primarily due to gains recognized in 2004 of approximately $3.5 million from the sale of the Company’s interests in its natural gas producing properties and the sale of land near the Company’s principal executive offices which gains were reversed in 2005 and reclassified to Other Deferred Credits and Other Liabilities in the Balance Sheet as a regulatory liability. Also contributing to the decrease in other income was a gain in 2004 of approximately $0.6 million from the repurchase of outstanding heat pump loans.

Interest expense was approximately $47.2 million in 2005 as compared to approximately $37.5 million in 2004, an increase of approximately $9.7 million or 25.9 percent. The increase in interest expense was primarily due to:

Income tax expense was approximately $52.6 million in 2005 as compared to approximately $53.0 million in 2004, a decrease of approximately $0.4 million or 0.8 percent. The decrease in income tax expense was primarily due to:

The balance of Accounts Receivable, Net was approximately $138.2 million and $154.3 million at December 31, 2006 and 2005, respectively, a decrease of approximately $16.1 million or 10.4 percent, primarily due to a decrease in the Company’s billings to its customers reflecting lower fuel costs in December 2006 as compared to December 2005 and payments received from other utilities for the Company’s assistance with hurricanes Katrina and Rita.

The balance of Construction Work in Progress was approximately $177.2 million and $80.8 million at December 31, 2006 and 2005, respectively, an increase of approximately $96.4 million, primarily due to construction expenditures related to the Company’s Centennial wind farm.

The balance of Regulatory Asset – SFAS 158 was approximately $231.1 million at December 31, 2006 with no comparable balance at December 31, 2005. The balance of Intangible Asset – Unamortized Prior Service Cost was approximately $26.5 million at December 31, 2005 with no comparable balance at December 31, 2006. The

balance of Prepaid Benefit Obligation was approximately $65.4 million at December 31, 2005 with no comparable balance at December 31, 2006. The change in these balances is due to the accounting change required upon adoption of SFAS No. 158, effective December 31, 2006, which required the Company to record the funded status of its pension and postretirement benefit plans on the Balance Sheet (see Notes 1 and 2 of Notes to Financial Statements for a further discussion).

The balance of Deferred Charges – Other was approximately $17.5 million and $1.1 million at December 31, 2006 and 2005, respectively, an increase of approximately $16.4 million, primarily due to the creation of a regulatory asset of approximately $14.7 million for the excess pension expense over the amount granted in rates by the OCC in the Company’s last Oklahoma rate case (see Note 1 of Notes to Financial Statements for a further discussion).

The balance of Accounts Payable – Other was approximately $95.2 million and $113.1 million at December 31, 2006 and 2005, respectively, an increase of approximately $17.9 million or 15.8 percent, primarily due to lower natural gas prices in December 2006 as compared to December 2005 and the timing of outstanding checks clearing the bank.

The balance of Fuel Clause Over Recoveries was approximately $96.3 million at December 31, 2006. The balance of Fuel Clause Under Recoveries was approximately $101.1 million at December 31, 2005. The increase in fuel clause over recoveries was due to the amount billed to the Company’s customers during 2006 exceeding the Company’s cost of fuel due to lower than expected natural gas prices and amounts recovered under approved tariffs exceeding the amounts intended by the December 2005 OCC rate order. The Company’s fuel recovery clauses are designed to smooth the impact of fuel price volatility on customers’ bills. As a result, the Company typically under recovers fuel cost in periods of rising prices above the baseline charge for fuel and over recovers fuel cost when prices decline below the baseline charge for fuel. Provisions in the fuel clauses are intended to allow the Company to amortize under or over recovery. As described in more detail in Note 14 of Notes to Financial Statements, the OCC, in its order dated December 12, 2005, granted the Company a $42.3 million annual increase in the rates charged by the Company to its retail customers in Oklahoma. These increased rates became effective in January 2006 pursuant to approved tariffs filed with the OCC. In January 2007, the Company determined that the approved tariffs had inadvertently authorized the Company to collect, and the Company had collected, approximately $26.7 million of additional fuel-related revenues during 2006 that was not intended by the December 12, 2005 order. As a result, the Company filed with the OCC in January 2007 amendments to its previously-authorized tariffs, in order to cease recovery of the fuel-related revenues not intended by the December 12, 2005 order. The $26.7 million, plus $1.2 million of interest, was recorded as a liability under Fuel Clause Over Recoveries on the Balance Sheet in the fourth quarter of 2006, and such amounts, along with other Fuel Clause Over Recoveries, will be credited to the Company’s Oklahoma customers in 2007 and 2008 through the Company’s automatic fuel adjustment clause. In addition, the Company recorded a reduction in operating revenues of approximately $26.7 million and an increase in interest expense of approximately $0.5 million, which resulted in an after tax reduction in net income of approximately $16.7 million in the fourth quarter of 2006. Because the rate increase authorized in the December 2005 order was not implemented until January 2006 and the tariffs were corrected effective December 31, 2006, the $26.7 million had no impact on net income for the year ended December 31, 2006. See additional discussion in “Supplementary Data – Interim Financial Information (Unaudited).”

The balance of Current Liabilities – Other was approximately $14.0 million and $30.7 million at December 31, 2006 and 2005, respectively, a decrease of approximately $16.7 million or 54.4 percent, primarily due to the settlement of the Kaiser-Francis lawsuit and the refund to customers for transportation and storage costs.

Off-balance sheet arrangements include any transactions, agreements or other contractual arrangements to which an unconsolidated entity is a party and under which the Company has: (i) any obligation under a guarantee contract having specific characteristics as defined in Financial Accounting Standards Board (“FASB”) Interpretation No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others”; (ii) a retained or contingent interest in assets transferred to an unconsolidated entity or similar arrangement that serves as credit, liquidity or market risk support to such entity for such assets; (iii) any obligation, including a contingent obligation, under a contract that would be accounted for as a derivative instrument

but is indexed to the Company’s own stock and is classified in stockholder’s equity in the Company’s balance sheet; or (iv) any obligation, including a contingent obligation, arising out of a variable interest as defined in FASB Interpretation No. 46, “Consolidation of Variable Interest Entities, an interpretation of Accounting Research Bulletin No. 51,” in an unconsolidated entity that is held by, and material to, the Company, where such entity provides financing, liquidity, market risk or credit risk support to, or engages in leasing, hedging or research and development services with, the Company. The Company has the following material off-balance sheet arrangements.

The Company leases more than 1,400 railcars used to deliver coal to the Company’s coal-fired generation units. See Note 13 of Notes to Financial Statements for a discussion of the Company’s railcar lease agreement.

Capital requirements and future contractual obligations estimated for the next five years and beyond are as follows:

		Less than			More than
(In millions)	Total	1 year	1 - 3 years	3 - 5 years	5 years
Capital expenditures including AFUDC (A)	$ 3,297.3	$ 426.5	$ 1,434.7	$ 1,070.1	$ 366.0
Maturities of long-term debt	845.4	---	---	---	845.4
Interest payments on long-term debt	972.6	48.8	97.7	97.7	728.4
Pension funding obligations	96.3	38.5	33.8	24.0	N/A
Total capital requirements	5,211.6	513.8	1,566.2	1,191.8	1,939.8

Operating lease obligations
Railcars	52.0	4.0	7.7	40.3	---

Other purchase obligations and commitments
Cogeneration capacity payments	471.3	97.6	190.5	183.2	N/A
Fuel minimum purchase commitments	614.5	198.0	220.0	173.1	23.4
Total other purchase obligations and commitments	1,085.8	295.6	410.5	356.3	23.4

Total capital requirements, operating lease obligations
and other purchase obligations and commitments	6,349.4	813.4	1,984.4	1,588.4	1,963.2
Amounts recoverable through automatic fuel
adjustment clause (B)	(1,137.8)	(299.6)	(418.2)	(396.6)	(23.4)
Total, net	$ 5,211.6	$ 513.8	$ 1,566.2	$ 1,191.8	$ 1,939.8

(A) Under current environmental laws and regulations, the Company may be required to spend approximately $600 million in capital expenditures on its coal-fired plants. These expenditures are expected to begin in 2007 and would continue over the next five years.

(B) Includes expected recoveries of costs incurred for the Company’s railcar operating lease obligations and the Company’s unconditional fuel purchase obligations.

Variances in the actual cost of fuel used in electric generation (which includes the operating lease obligations for the Company’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 the Company’s customers through automatic fuel adjustment clauses. Accordingly, while the cost of fuel related to operating leases and the

vast majority of unconditional fuel purchase obligations of the Company noted above may increase capital requirements, such costs are recoverable through automatic fuel adjustment clauses and have little, if any, impact on net capital requirements and future contractual obligations. The automatic fuel adjustment clauses are subject to periodic review by the OCC, the APSC and the FERC. See Note 14 of Notes to Financial Statements for a discussion of the completed proceedings at the OCC regarding the Company’s gas transportation and storage contract with Enogex.

Total capital requirements, consisting of capital expenditures, maturities of long-term debt, interest payments on long-term debt and pension funding obligations, were approximately $528.4 million in 2006. There were no contractual obligations, net of recoveries through automatic fuel adjustment clauses in 2006. Approximately $17.0 million of the 2006 capital requirements were to comply with environmental regulations. This compares to net capital requirements of approximately $321.0 million in 2005. There were no contractual obligations, net of recoveries through automatic fuel adjustment clauses in 2005. Approximately $16.7 million of the 2005 capital requirements were to comply with environmental regulations. During 2006, the Company’s sources of capital were internally generated funds from operating cash flows, short-term borrowings from Energy Corp. (through a combination of bank borrowings and commercial paper) and proceeds from the sale of assets. Energy Corp. uses its commercial paper to fund changes in working capital and as an interim source of financing capital expenditures until permanent financing is arranged. Changes in working capital reflect the seasonal nature of the Company’s business, the revenue lag between billing and collection from customers and fuel inventories. See “Financial Condition” for a discussion of significant changes in net working capital requirements as it pertains to operating cash flow and liquidity.

There are no maturities of the Company’s long-term debt during the next five years.

The Company’s current 2007 to 2012 construction program includes continued investment in its distribution, generation and transmission system. The Company’s current estimates of capital expenditures for 2007 through 2012 are approximately $426.5 million, $689.6 million, $745.1 million, $589.9 million, $480.2 million and $366.0 million, respectively, which include capital expenditures of approximately $94.0 million, $278.8 million, $285.7 million, $97.7 million and $34.1 million, respectively, in 2007 through 2011 related to the construction of the proposed Red Rock power plant. The Company also has approximately 550 MW’s of contracts with qualified cogeneration facilities (“QF”) and small power production producers’ (“QF contracts”) to meet its current and future expected customer needs. The Company 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.

During 2006, actual asset returns for Energy Corp.’s defined benefit pension plan were positively affected by growth in the equity markets. At December 31, 2006, approximately 64 percent of the pension plan assets are invested in listed common stocks with the balance invested in corporate debt and U.S. Government securities. In 2006, asset returns on the pension plan were approximately 14.5 percent as compared to approximately 6.2 percent in 2005. During the same time, corporate bond yields, which are used in determining the discount rate for future pension obligations, have continued to decline.

Energy Corp.’s contributions to the pension plan increased from approximately $32.0 million in 2005 to approximately $90.0 million in 2006. This increase in pension plan contributions in 2006 was to maintain an adequate funded status. The level of funding is dependent on returns on plan assets and future discount rates. Higher returns on plan assets and increases in discount rates will reduce funding requirements to the plan. In August 2006,

legislation was passed that changed the funding requirement for single- and multi-employer defined benefit pension plans as discussed below. During 2007, Energy Corp. may contribute up to $50 million to its pension plan, of which approximately $38.5 million is expected to be allocated to the Company.

In accordance with Statement of Financial Accounting Standard (“SFAS”) No. 88, “Employer’s Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits,” a one-time settlement charge is required to be recorded by an organization when lump sum payments or other settlements that relieve the organization from the responsibility for the pension benefit obligation during a plan year exceed the service cost and interest cost components of the organization’s net periodic pension cost. During 2006, the Company experienced an increase in both the number of employees electing to retire and the amount of lump sum payments to be paid to such employees upon retirement in 2006. As a result, Energy Corp. recorded a pension settlement charge for 2006 of approximately $17.1 million in the fourth quarter of 2006, of which approximately $13.3 million was allocated to the Company. The pension settlement charge did not require a cash outlay by the Company and did not increase the Company’s total pension expense over time, as the charge was an acceleration of costs that otherwise would have been recognized as pension expense in future periods. The Company’s Oklahoma jurisdictional portion of this charge was recorded as a regulatory asset (see Note 1 of Notes to Financial Statements for a further discussion).

As discussed in Note 12 of Notes to Financial Statements, in 2000 Energy Corp. made several changes to its pension plan, including the adoption of a cash balance benefit feature for employees hired after January 31, 2000. The cash balance plan may provide lower post-employment pension benefits to employees, which could result in less pension expense being recorded. Over the near term, Energy Corp.’s cash requirements for the plan are not expected to be materially different than the requirements existing prior to the plan changes. However, as the population of employees included in the cash balance plan feature increases, Energy Corp.’s cash requirements should decrease and will be much less sensitive to changes in discount rates.

At December 31, 2006, the projected benefit obligation and fair value of assets of the Company’s portion of Energy Corp.’s pension plan and restoration of retirement income plan was approximately $465.6 million and $410.1 million, respectively, for an underfunded status of approximately $55.5 million. Also, at December 31, 2006, the accumulated postretirement benefit obligation and fair value of assets of the Company’s portion of Energy Corp.’s postretirement benefit plans was approximately $188.0 million and $71.7 million, respectively, for an underfunded status of approximately $116.3 million. The above amounts have been recorded in Accrued Pension and Benefit Obligations with the offset recorded as a regulatory asset in the Company’s Balance Sheet as discussed in Note 1 of Notes to Financial Statements. The entry did not impact the results of operations in 2006 and did not require a usage of cash and is therefore excluded from the Statement of Cash Flows. The amount recorded as a regulatory asset represents a net periodic pension cost to be recognized in the Statements of Income in future periods.

During 2005, Energy Corp. made contributions to the pension plan that exceeded amounts previously recognized as net periodic pension expense and recorded a net prepaid benefit obligation at December 31, 2005 of approximately $88.9 million, of which approximately $66.0 million was allocated to the Company. At December 31, 2005, Energy Corp.’s projected pension benefit obligation exceeded the fair value of the pension plan assets by approximately $154.6 million, of which approximately $127.6 million was allocated to the Company. As a result of recording a prepaid benefit obligation and having a funded status where the projected benefit obligations exceeded the fair value of plan assets, provisions of SFAS No. 87 required the recognition of an additional minimum liability in the amount of approximately $181.4 million for Energy Corp., of which approximately $157.3 million was allocated to the Company at December 31, 2005. The offset of this entry was an intangible asset and Accumulated Other Comprehensive Income, net of a deferred tax asset; therefore, this adjustment did not impact the results of operations in 2005 and did not require a usage of cash and is therefore excluded from the Statement of Cash Flows. The amount recorded as an intangible asset equaled the unrecognized prior service cost with the remainder recorded in Accumulated Other Comprehensive Income. The amount in Accumulated Other Comprehensive Income represents a net periodic pension cost to be recognized in the Statements of Income in future periods.

Among other things, it introduces a new funding requirement for single- and multi-employer defined benefit pension plans, provides legal certainty on a prospective basis for cash balance and other hybrid plans and addresses contributions to defined contribution plans, deduction limits for contributions to retirement plans and investment advice provided to plan participants. The Company is currently analyzing the impact of the Pension Protection Act on its pension plans.

The Company’s $125.0 million principal amount 6.65 percent Senior Notes (“Senior Notes”) due July 15, 2027, are repayable on July 15, 2007, at the option of the holders, at 100 percent of the principal amount, together with accrued and unpaid interest to July 15, 2007. Only holders who submit requests for repayment between May 15, 2007 and June 15, 2007 are entitled to such repayments. In accordance with SFAS No. 6, “Classification of Short-Term Obligations Expected to Be Refinanced,” the Company reclassified the Senior Notes from long-term debt due within one year to long-term debt at December 31, 2006 due to the Company having sufficient long-term liquidity in place as a result of increasing its revolving credit agreement to $400.0 million in December 2006. Also, based on where the Senior Notes have recently traded, the Company does not believe it is probable that this option will be exercised by the note holders.

On October 31, 2006, the Company submitted a commercial letter of credit to the Southwest Power Pool for approximately $2.9 million related to the costs of upgrades required for the Company to obtain transmission service from its new Centennial wind farm. This commercial letter of credit is not recorded as a liability on the Company’s Balance Sheet.

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, 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.

Management expects that internally generated funds, the issuance of long and short-term debt and funds received from Energy Corp. (from proceeds from the sales of its common stock to the public through Energy Corp.’s Automatic Dividend Reinvestment and Stock Purchase Plan or other offerings) will be adequate over the next three years to meet anticipated cash needs. The Company utilizes short-term borrowings (through a combination of bank borrowings, commercial paper and borrowings from Energy Corp.) to satisfy temporary working capital needs and as an interim source of financing capital expenditures until permanent financing is arranged.

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 affect on the Company’s Financial Statements particularly as they relate to pension expense. However, the Company believes it has taken reasonable, but conservative, positions where assumptions and estimates are used in order to minimize the negative financial impact to the Company that could result if actual results vary from the assumptions and estimates. In management’s opinion, the areas of the Company where the most significant judgment is exercised is in the valuation of pension plan assumptions, contingency reserves, asset retirement obligations, fair value and cash flow hedges, regulatory assets and liabilities, unbilled revenues and the allowance for uncollectible accounts receivable. The selection, application and disclosure of the following critical accounting estimates have been discussed with Energy Corp.’s Audit Committee.

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 12 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.

In accordance with FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations,” an entity was required to recognize a liability for the fair value of an asset retirement obligation (“ARO”) that was conditional on a future event if the liability’s fair value could be reasonably estimated. The fair value of a liability for the conditional ARO was recognized when incurred. Uncertainty surrounding the timing and method of settlement of a conditional ARO was factored into the measurement of the liability when sufficient information existed. However, in some cases, there is insufficient information to estimate the fair value of an ARO. In these cases, the liability was initially recognized in the period in which sufficient information was available for an entity to make a reasonable estimate of the liability’s fair value. In the fourth quarter of 2006, the Company recorded

an ARO for approximately $0.9 million related to its Centennial wind farm. Beginning January 1, 2007, the Company will amortize the remaining value of the related ARO asset over the remaining estimated life of 99 years.

The Company engages in cash flow and fair value hedge transactions to modify the rate composition of the debt portfolio. During 2004, the Company entered into an interest rate swap agreement and, during 2005 and 2006, the Company entered into treasury lock agreements relating to managing interest rate exposure on the debt portfolio or anticipated debt issuances to modify the interest rate exposure on fixed rate debt issues. These interest rate swaps and treasury lock agreements qualified as fair value or cash flow hedges under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities.” The objective of the interest rate swap was to achieve a lower cost of debt and to raise the percentage of total corporate long-term floating rate debt to reflect a level more in line with industry standards. The objective of the treasury lock agreements in late 2005 was to protect against the variability of future payments of interest expense of debt that was issued by the Company in January 2006 and the objective of the treasury lock agreement in November 2006 is to protect against the variability of future interest payments of long-term debt that is expected to be issued during the first half of 2007.

The Company, as a regulated utility, is subject to the accounting principles prescribed by SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation.” SFAS No. 71 provides 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.

The Company 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 Company adopted certain provisions of SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106 and 132R,” effective December 31, 2006, which requires the Company to separately disclose the items that have not yet been recognized as components of net periodic pension cost including, net loss, prior service cost and net transition obligation at December 31, 2006. For companies not subject to SFAS No. 71, SFAS No. 158 required this information to be included in Accumulated Other Comprehensive Income. However, for companies subject to SFAS No. 71, this information is allowed to be recorded as a regulatory asset if: (i) the utility has historically recovered and currently recovers pension and postretirement benefit plan expense in its electric rates; and (ii) there is no negative evidence that the existing regulatory treatment will change. Therefore, the Company has recorded the net loss, prior service cost and net transition obligation as a regulatory asset as these expenses are probable of future recovery. If, in the future, the regulatory bodies indicated a change in policy related to the recovery of pension and postretirement benefit plan expenses, this could cause the SFAS No. 158 regulatory asset balance to be reclassified to Accumulated Other Comprehensive Income.

The Company 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, 2006, 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 approximately $0.2 million. At December 31, 2006 and 2005, Accrued Unbilled Revenues were approximately $39.7 million and $41.8 million, respectively. The estimates that management uses in this calculation could vary from the actual amounts to be paid by customers.

Customer balances are generally written off if not collected within six months after the final billing date. The allowance for uncollectible accounts receivable 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. At December 31, 2006, if the provision rate were to increase or decrease by 10 percent, this would cause a change in the uncollectible expense recognized of approximately $0.3 million. The allowance for uncollectible accounts receivable is a reduction to Accounts Receivable, Net 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 approximately $3.3 million and $2.5 million at December 31, 2006 and 2005, respectively.

See Notes 2 and 3 of Notes to Financial Statements for a discussion of recent accounting pronouncements that are applicable to the Company.

The Company has been and will continue to be affected by competitive changes to the utility and energy industries. Significant changes already have occurred and additional changes are being 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 the Company due to an impairment of assets, a loss of retail customers, lower profit margins and/or increased costs of capital. Any such restructuring also could have a significant impact on the Company’s financial position, results of operations and cash flows. The Company cannot predict when it will be subject to changes in legislation or regulation, nor can it predict the impact of these changes on the Company’s financial position, results of operations or cash flows. The Company believes that the prices for electricity and the quality and reliability of the Company’s service currently place us in a position to compete effectively in the energy market. These developments at the federal and state levels are described in more detail in Note 14 of Notes to Financial Statements. The Company is also subject to competition in various degrees from state-owned electric systems, municipally-owned electric systems, rural electric cooperatives and, in certain respects, from other private utilities, power marketers and cogenerators. The Company has a franchise to serve in more than 270 towns and cities throughout its service territory. In a citywide election in May 2006, Oklahoma City voters approved a 25-year franchise for the Company which is the largest city in the Company’s service territory.

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 the Company’s financial position, results of operations or cash flows. See Notes 13 and 14 of Notes to Financial Statements and Item 3 of Part I in this Form 10-K for a discussion of the Company’s commitments and contingencies.

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. The Company’s exposure to changes in interest rates relates primarily to short-term variable-rate debt, interest rate swap agreements, treasury lock agreements and commercial paper. The Company also engages in price risk management activities.

The Company monitors market risks using a risk committee structure. Energy Corp.’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 risk management activities of the Company. This committee’s emphasis is a holistic perspective of risk measurement and policies targeting the Company’s overall financial performance. The Risk Oversight Committee is authorized by, and reports quarterly to, the Audit Committee of the Board of Directors of Energy Corp.

The Company also has a Corporate Risk Management Department led by our Chief Risk and Compliance Officer. This group, in conjunction with the aforementioned committees, is responsible for establishing and enforcing the Company’s risk policies.

The Company utilizes risk policies to control the amount of market risk exposure. These policies, which include value-at-risk limits, position limits, tenor limits and stop loss limits, are designed to provide the Audit Committee of the Board of Directors of Energy Corp. and senior executives of the Company with confidence that the risks taken on by the Company’s business activities are in accordance with their expectations for financial returns and that the approved policies and controls related to risk management are being followed.

The Company’s exposure to changes in interest rates relates primarily to short-term debt, interest rate swap agreements, treasury lock agreements and commercial paper. The Company manages its interest rate exposure by limiting its variable-rate debt to a certain percentage of total capitalization and by monitoring the effects of market changes in interest rates. The Company utilizes interest rate derivatives to alter interest rate exposure in an attempt to reduce interest expense related to existing debt issues. Interest rate derivatives are used solely to modify interest rate exposure and not to modify the overall leverage of the debt portfolio.

The Company entered into a treasury lock agreement, effective November 17, 2006, to hedge interest payments on the first $50.0 million of long-term debt that is expected to be issued during the first half of 2007. This treasury lock expires March 29, 2007.

The fair value of the Company’s long-term debt is based on quoted market prices. At December 31, 2006, the Company had no outstanding interest rate swap agreements. The following table shows the Company’s long-term debt maturities and the weighted-average interest rates by maturity date.

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

(B) A hypothetical change of 100 basis points in the underlying variable interest rate would change interest expense by approximately $1.4 million annually.

The Company may designate certain derivative instruments for the purchase or sale of electric power and fuel procurement as normal purchases and normal sales contracts under the provisions of SFAS No. 133. Normal purchases and normal sales contracts are not recorded in Price Risk Management assets or liabilities in the Balance Sheets and earnings recognition is recorded in the period in which physical delivery of the commodity occurs. The

Company applies normal purchases and normal sales to electric power contracts by the Company and for fuel procurement by the Company.

Credit risk includes the risk that counterparties that owe us money or energy will breach their obligations. If the counterparties 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.

For the Company, new business customers are required to provide a security deposit in the form of cash, a 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 after 12 months of good payment history based on the applicable utility regulation. 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.

Year ended December 31 (In millions)	2006	2005	2004

OPERATING REVENUES	$ 1,745.7	$ 1,720.7	$ 1,578.1

COST OF GOODS SOLD (exclusive of depreciation shown below)*	950.0	994.2	914.2
Gross margin on revenues	795.7	726.5	663.9
Other operation and maintenance	316.5	309.2	301.9
Depreciation	132.2	134.4	122.7
Taxes other than income	53.1	50.7	47.0

OPERATING INCOME	293.9	232.2	192.3

OTHER INCOME (EXPENSE)
Interest income	1.9	2.6	2.7
Allowance for equity funds used during construction	4.1	---	0.9
Other income (loss)	4.0	(2.8)	4.5
Other expense	(9.7)	(2.5)	(2.3)
Net other income (expense)	0.3	(2.7)	5.8

INTEREST EXPENSE
Interest on long-term debt	50.3	42.1	36.9
Allowance for borrowed funds used during construction	(4.5)	(2.2)	(1.7)
Interest on short-term debt and other interest charges	14.3	7.3	2.3
Interest expense	60.1	47.2	37.5

INCOME BEFORE TAXES	234.1	182.3	160.6

INCOME TAX EXPENSE	84.8	52.6	53.0

NET INCOME	$ 149.3	$ 129.7	$ 107.6

* Before intercompany eliminations with affiliates that are eliminated in the preparation of Energy Corp.’s
consolidated financial statements.

December 31 (In millions)	2006	2005

ASSETS
CURRENT ASSETS
Cash and cash equivalents	$ ---	$ ---
Accounts receivable, net	138.2	154.3
Accrued unbilled revenues	39.7	41.8
Fuel inventories, at LIFO cost	29.7	27.9
Materials and supplies, at average cost	54.9	52.6
Price risk management	0.9	0.1
Accumulated deferred tax assets	9.0	11.2
Fuel clause under recoveries	---	101.1
Prepayments	4.3	4.9
Other	5.2	10.2
Total current assets	281.9	404.1

OTHER PROPERTY AND INVESTMENTS, at cost	3.3	3.7

PROPERTY, PLANT AND EQUIPMENT
In service	4,977.2	4,747.1
Construction work in progress	177.2	80.8
Total property, plant and equipment	5,154.4	4,827.9
Less accumulated depreciation	2,175.3	2,157.7
Net property, plant and equipment	2,979.1	2,670.2

DEFERRED CHARGES AND OTHER ASSETS
Income taxes recoverable from customers, net	31.1	32.8
Regulatory asset - SFAS 158	231.1	---
Intangible asset - unamortized prior service cost	---	26.5
Prepaid benefit obligation	---	65.4
McClain Plant deferred expenses	18.7	24.9
Unamortized loss on reacquired debt	20.1	21.3
Unamortized debt issuance costs	6.9	5.0
Other	17.5	1.1
Total deferred charges and other assets	325.4	177.0

TOTAL ASSETS	$ 3,589.7	$ 3,255.0

December 31 (In millions)	2006	2005

LIABILITIES AND STOCKHOLDER’S EQUITY
CURRENT LIABILITIES
Accounts payable - affiliates	$ 5.2	$ 10.7
Accounts payable - other	95.2	113.1
Advances from parent	102.1	108.3
Customers’ deposits	50.9	46.3
Accrued taxes	24.1	22.9
Accrued interest	22.1	16.3
Accrued compensation	24.2	20.1
Price risk management	---	0.1
Gas imbalances	---	0.2
Fuel clause over recoveries	96.3	---
Other	14.0	30.7
Total current liabilities	434.1	368.7

LONG-TERM DEBT	843.3	844.0

COMMITMENTS AND CONTINGENCIES (NOTE 13)

DEFERRED CREDITS AND OTHER LIABILITIES
Accrued pension and benefit obligations	173.1	183.5
Accumulated deferred income taxes	644.0	584.0
Accumulated deferred investment tax credits	26.8	31.7
Accrued removal obligations, net	125.5	114.3
Other	20.9	12.8
Total deferred credits and other liabilities	990.3	926.3

STOCKHOLDER’S EQUITY
Common stockholder’s equity	665.4	665.4
Retained earnings	656.0	530.7
Accumulated other comprehensive income (loss), net of tax	0.6	(80.1)
Total stockholder’s equity	1,322.0	1,116.0

TOTAL LIABILITIES AND STOCKHOLDER’S EQUITY	$ 3,589.7	$ 3,255.0

December 31 (In millions)			2006	2005

STOCKHOLDER’S EQUITY
Common stock, par value $2.50 per share; authorized 100.0 shares;
and outstanding 40.4 shares			$ 100.9	$ 100.9
Premium on capital stock			564.5	564.5
Retained earnings			656.0	530.7
Accumulated other comprehensive income (loss), net of tax			0.6	(80.1)
Total stockholder’s equity			1,322.0	1,116.0

LONG-TERM DEBT
SERIES	DATE DUE
Senior Notes
5.15 %	Senior Notes, Series Due January 15, 2016		110.0		---
6.50 %	Senior Notes, Series Due July 15, 2017		125.0		125.0
6.65 %	Senior Notes, Series Due July 15, 2027		125.0		125.0
6.50 %	Senior Notes, Series Due April 15, 2028		100.0		100.0
6.50 %		Senior Notes, Series Due August 1, 2034	140.0		140.0
5.75 %	Senior Notes, Series Due January 15, 2036		110.0		---
Other Bonds
3.11% - 4.05% Garfield Industrial Authority, January 1, 2025			47.0	47.0
3.20% - 4.13% Muskogee Industrial Authority, January 1, 2025			32.4	32.4
3.03% - 4.06% Muskogee Industrial Authority, June 1, 2027			56.0	56.0

Other long-term debt (NOTE 11)			---	220.0

Unamortized discount			(2.1)	(1.4)
Total long-term debt			843.3	844.0

Total Capitalization			$ 2,165.3	$ 1,960.0

The accompanying Notes to Financial Statements are an integral part hereof .

Year ended December 31 (In millions)	2006	2005	2004

CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$ 149.3	$ 129.7	$ 107.6
Adjustments to reconcile net income to net cash provided from operating activities
Depreciation	132.2	134.4	122.7
Deferred income taxes and investment tax credits, net	11.3	11.5	35.6
Allowance for equity funds used during construction	(4.1)	---	(0.9)
Gain on sale of assets	---	---	(3.2)
Loss on retirement of fixed assets	6.0	---	---
Price risk management assets	(0.8)	(0.1)	---
Price risk management liabilities	(0.1)	(0.1)	0.1
Other assets	(56.4)	(4.9)	(32.0)
Other liabilities	12.9	(7.9)	(0.6)
Change in certain current assets and liabilities
Accounts receivable, net	16.1	(48.9)	27.6
Accrued unbilled revenues	2.1	3.7	(7.5)
Fuel, materials and supplies inventories	(4.1)	12.0	(4.8)
Fuel clause under recoveries	101.1	(46.8)	(50.3)
Other current assets	5.6	7.8	4.3
Accounts payable	(17.9)	20.1	35.3
Accounts payable - affiliates	(5.5)	2.0	5.5
Income taxes payable - affiliates	12.3	(3.5)	(4.4)
Customers’ deposits	4.6	0.7	9.8
Accrued taxes	1.2	2.5	(0.2)
Accrued interest	5.8	(0.1)	3.6
Accrued compensation	4.1	(1.0)	(0.4)
Gas imbalance liability	(0.2)	0.1	0.1
Fuel clause over recoveries	96.3	---	(32.4)
Other current liabilities	(16.7)	(5.5)	5.7
Net Cash Provided from Operating Activities	455.1	205.7	221.2

CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures (less allowance for equity funds used during
construction)	(411.1)	(249.1)	(391.2)
Proceeds from sale of assets	1.0	1.8	3.3
Net Cash Used in Investing Activities	(410.1)	(247.3)	(387.9)

CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from long-term debt	217.5	---	138.6
Retirement of long-term debt	---	(220.0)	---
(Decrease) increase in short-term debt, net	(223.5)	335.6	131.7
Dividends paid on common stock	(39.0)	(74.0)	(107.6)
Net Cash (Used in) Provided from Financing Activities	(45.0)	41.6	162.7

NET CHANGE IN CASH AND CASH EQUIVALENTS	---	---	(4.0)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	---	---	4.0
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$ ---	$ ---	$ ---

The accounting records of the Company are maintained in accordance with the Uniform System of Accounts prescribed by the FERC and adopted by the OCC and the APSC. Additionally, the Company, as a regulated utility, is subject to the accounting principles prescribed by the Financial Accounting Standards Board (“FASB”) Statement of Financial Accounting Standards (“SFAS”) No. 71, “Accounting for the Effects of Certain Types of Regulation.” SFAS No. 71 provides 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.

The Company adopted SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106 and 132R,” effective December 31, 2006, which requires the Company to separately disclose the items that have not yet been recognized as components of net periodic pension cost including, net loss, prior service cost and net transition obligation at December 31, 2006. For companies not subject to SFAS No. 71, SFAS No. 158 required this information to be included in Accumulated Other Comprehensive Income. However, for companies subject to SFAS No. 71, this information is allowed to be recorded as a regulatory asset if: (i) the utility has historically recovered and currently recovers pension and postretirement benefit plan expense in its electric rates; and (ii) there is no negative evidence that the existing regulatory treatment will change. Therefore, the Company has recorded the net loss, prior service cost and net transition obligation as a regulatory asset as these expenses are probable of future recovery. If, in the future, the regulatory bodies indicated a change in policy related to the recovery of pension and postretirement benefit plan expenses, this could cause the SFAS No. 158 regulatory asset balance to be reclassified to Accumulated Other Comprehensive Income.

The following amounts in the SFAS No. 158 regulatory asset at December 31, 2006 are expected to be recognized as components of net periodic benefit cost in 2007:

Income taxes recoverable from customers represent income tax benefits previously used to reduce the Company’s revenues. These amounts are being recovered in rates as the temporary differences that generated the income tax benefit turn around. The provisions of SFAS No. 71 allowed the Company to treat these amounts as regulatory assets and liabilities and they are being amortized over the estimated remaining life of the assets to which they relate. The income tax related regulatory assets and liabilities are netted on the Company’s Balance Sheets in the line item, “Income Taxes Recoverable from Customers, Net.” The OCC authorized approximately $30.1 million of the $32.8 million regulatory asset balance at December 31, 2005 to be included in the Company’s rate base for purposes of earning a return.

Unamortized loss on reacquired debt is comprised of unamortized debt issuance costs related to the early retirement of the Company’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 the Company’s rate base and does not otherwise earn a rate of return.

As a result of the acquisition of a 77 percent interest in the 520 megawatt (“MW”) natural gas-fired combined cycle NRG McClain Station (the “McClain Plant”) completed on July 9, 2004, and consistent with the

2002 agreed-upon settlement of a Company rate case (the “2002 Settlement Agreement”) with the OCC, the Company had the right to accrue a regulatory asset, for a period not to exceed 12 months subsequent to the acquisition and operation of the McClain Plant, consisting of the non-fuel operation and maintenance expenses, depreciation, cost of debt associated with the investment and ad valorem taxes. At December 31, 2005, the McClain Plant regulatory asset was approximately $24.9 million which is being recovered over a four-year time period as authorized in the OCC rate order which began in January 2006. The OCC authorized approximately $15.5 million of the $24.9 million regulatory asset balance at December 31, 2005 to be included in the Company’s rate base for purposes of earning a return.

In accordance with the OCC order received by the Company in December 2005 in its Oklahoma rate case, the Company was allowed to recover a certain amount of pension plan expenses. At December 31, 2006, there was approximately $14.7 million of expenses exceeding this level primarily related to a pension settlement charge recorded by the Company during the fourth quarter of 2006 (see Note 12 for a further discussion). These excess amounts have been recorded as a regulatory asset as the Company believes these expenses are probable of future recovery.

In January 2005, a cogeneration credit rider was implemented at the Company as part of the Oklahoma retail customer electric rates in order to return purchase power capacity payment reductions and any change in operating and maintenance expense related to cogeneration previously included in base rates to the Company’s customers. The balance of the cogeneration credit rider under recovery was approximately $3.1 million and $3.7 million, respectively, at December 31, 2006 and 2005. The Company’s cogeneration credit rider has been updated and approved by the OCC in December of each year through December 2006 and any over/under recovery of the cogeneration credit rider in the current year and prior periods has been automatically included in the next year’s rider. The Company’s current cogeneration credit rider expired December 31, 2006. The 2007 cogeneration credit rider is approximately $80.7 million and the total under recovery through 2006 was approximately $3.1 million. The Company expects to file an application with the OCC in late 2007 to request a cogeneration credit for years after 2007. The cogeneration credit rider under recovery was not included in the Company’s rate base and did not otherwise earn a rate of return. The cogeneration credit rider under recovery is included in Other Current Assets on the Company’s Balance Sheets.

Fuel clause under recoveries are generated from under recoveries from the Company’s customers when the Company’s cost of fuel exceeds the amount billed to its customers. Fuel clause over recoveries are generated from over recoveries from the Company’s customers when the amount billed to its customers exceeds the Company’s cost of fuel. The Company’s fuel recovery clauses are designed to smooth the impact of fuel price volatility on customers’ bills. As a result, the Company typically under recovers fuel cost in periods of rising prices above the baseline charge for fuel and over recovers fuel cost when prices decline below the baseline charge for fuel. Provisions in the fuel clauses allow the Company to amortize under or over recovery. In accordance with the OCC order received by the Company in December 2005 in its rate case, beginning in January 2006, the Company’s mechanism for the recovery of over or under recovered fuel costs from its customers was modified to allow interest to be applied to the over or under recovery. As described in more detail in Note 14, the OCC, in its order dated December 12, 2005, granted the Company a $42.3 million annual increase in the rates charged by the Company to its retail customers in Oklahoma. These increased rates became effective in January 2006 pursuant to approved tariffs filed with the OCC. In January 2007, the Company determined that the approved tariffs had inadvertently authorized the Company to collect, and the Company had collected, approximately $26.7 million of additional fuel-related revenues during 2006 that was not intended by the December 12, 2005 order. As a result, the Company filed with the OCC in January 2007 amendments to its previously-authorized tariffs, in order to cease recovery of the fuel-related revenues not intended by the December 12, 2005 order. The $26.7 million, plus $1.2 million of interest, was recorded as a liability under Fuel Clause Over Recoveries on the Balance Sheet in the fourth quarter of 2006, and such amounts, along with other Fuel Clause Over Recoveries, will be credited to the Company’s Oklahoma customers in 2007 and 2008 through the Company’s automatic fuel adjustment clause. In addition, the Company recorded a reduction in operating revenues of approximately $26.7 million and an increase in interest expense of approximately $0.5 million, which resulted in an after tax reduction in net income of approximately $16.7 million in the fourth quarter of 2006. Because the rate increase authorized in the December 2005 order was not implemented until January 2006 and the tariffs were corrected effective December 31, 2006, the $26.7 million had no impact on

net income for the year ended December 31, 2006. See additional discussion in “Supplementary Data – Interim Financial Information (Unaudited).”

Accrued removal obligations represent asset retirement costs previously recovered from ratepayers for other than legal obligations. In accordance with SFAS No. 143, “Accounting for Asset Retirement Obligations,” the Company was required to reclassify its accrued removal obligations, which had previously been recorded as a liability in Accumulated Depreciation, to a regulatory liability.

During 2004, the Company sold assets including its interest in certain natural gas producing properties and the sale of land near the Company’s principal executive offices for a gain of approximately $3.5 million. During 2005, the Company sold certain assets for a gain of approximately $0.3 million. In December 2005, the OCC order in the Company’s Oklahoma rate case required that any previously recognized gain in 2004 related to the sale of assets should be returned to customers through electric rates at a rate of approximately $1.3 million annually. During 2005, the Company reversed these gains and reclassified them to Other Deferred Credits and Other Liabilities as a regulatory liability. The Company recorded gains from the sale of assets in 2005 and 2006 in a similar manner and expects to continue that treatment for future gains from the sale of assets.

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 reduced or written off, as appropriate. If the Company were required to discontinue the application of SFAS No. 71 for some or all of its operations, it could result in writing off the related regulatory assets; the financial effects of which could be significant.

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 affect on the Company’s Financial Statements particularly as they relate to pension expense. However, the Company believes it has taken reasonable, but conservative, positions where assumptions and estimates are used in order to minimize the negative financial impact to the Company that could result if actual results vary from the assumptions and estimates. In management’s opinion, the areas of the Company where the most significant judgment is exercised is in the valuation of pension plan assumptions, contingency reserves, asset retirement obligations, fair value and cash flow hedges, regulatory assets and liabilities, unbilled revenues and the allowance for uncollectible accounts receivable.

For purposes of the Financial Statements, the Company 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.

Under the Company’s cash management arrangement with Energy Corp., the Company remits all excess cash to Energy Corp. who then funds the Company’s controlled disbursement accounts as amounts are presented for payment. Outstanding checks in excess of cash balances were approximately $24.3 million and $32.0 million at December 31, 2006 and 2005, respectively, and are classified as Accounts Payable in the Balance Sheets. Sufficient funds were available to fund these outstanding checks when they were presented for payment.

effect on the amount of uncollectible expense recognized. The allowance for uncollectible accounts receivable was approximately $3.3 million and $2.5 million at December 31, 2006 and 2005, 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 after 12 months of good payment history based on the applicable utility regulation. 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 for the generation of electricity consist of coal, natural gas and oil. These inventories are accounted for under the last-in, first-out (“LIFO”) cost method. The estimated replacement cost of fuel inventories was higher than the stated LIFO cost by approximately $13.7 million and $19.1 million for 2006 and 2005, respectively, based on the average cost of fuel purchased. The amount of fuel inventory was approximately $29.7 million and $27.9 million at December 31, 2006 and 2005, respectively.

All property, plant and equipment are 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 (“AFUDC”). 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 less net salvage 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 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 Company owns a 77 percent in the McClain Plant and, as disclosed below, only the Company’s 77 percent interest is reflected in the balances in the table below. The owner of the remaining 23 percent interest in the McClain Plant is the Oklahoma Municipal Power Authority (“OMPA”). The Company and the OMPA are responsible for providing their own financing of capital expenditures. Also, only the Company’s proportionate interest of any direct expenses of the McClain Plant such as fuel, maintenance expense and other operating expenses is included in the applicable financial statements captions in the Statements of Income. The balance of the Company’s interest in the McClain Plant asset is approximately $176.2 million and $174.0 million, respectively, at December 31, 2006 and 2005. The accumulated depreciation associated with the Company’s interest in the McClain Plant is approximately $24.9 million and $14.3 million, respectively, at December 31, 2006 and 2005.

The Company’s property, plant and equipment are divided into the following major classes at December 31, 2006 and 2005, respectively.

The provision for depreciation, which was approximately 2.7 percent and 3.0 percent, respectively, of the average depreciable utility plant for 2006 and 2005, 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 2007, the provision for depreciation is projected to be approximately 2.7 percent of the average depreciable utility plant. Amortization of intangibles other than debt costs is computed using the straight-line method. Approximately 81 percent of the amortizable intangible plant balance at December 31, 2006 will be amortized over three years with the remaining intangible plant being amortized over their respective lives ranging up to 25 years.

AFUDC is calculated according to the FERC pronouncements for the imputed cost of equity and borrowed funds. AFUDC, a non-cash item, is reflected as a credit in the Statements of Income and as a charge to Construction Work in Progress in the Balance Sheets. AFUDC rates, compounded semi-annually, were 7.79 percent, 3.78 percent and 4.99 percent for the years 2006, 2005 and 2004, respectively. The increase in the AFUDC rates in 2006 was primarily due to increased equity funds in the AFUDC calculation that resulted from a higher level of construction costs partially offset by a lower level of short-term borrowings in 2006.

The Company 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. An amount is accrued as a receivable for this unbilled revenue 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.

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 the Company’s customers through automatic fuel adjustment clauses, which are subject to periodic review by the OCC, the APSC and the FERC.

The Company adopted SFAS No. 123 (Revised), “Share-Based Payment,” using the modified prospective transition method effective January 1, 2006, which required the Company to measure and recognize the cost of employee services received in exchange for an award of equity instruments based on the grant date fair value of the award. See Note 3 for a further discussion related to the Company’s stock-based compensation. Pursuant to the provisions of SFAS No. 123, “Accounting for Stock-Based Compensation,” the Company had elected to continue using the intrinsic value method of accounting for stock options granted under Energy Corp.’s employee compensation plans in accordance with Accounting Principles Board (“APB”) Opinion No. 25, “Accounting for Stock Issued to Employees.” Accordingly, prior to January 1, 2006, the Company did not recognize compensation expense for stock options. The Company would have recognized less than $0.1 million in 2005 had it elected to adopt the fair value recognition provisions of SFAS No. 123. For purposes of this pro forma calculation, the value of the options was determined using a Black-Scholes option pricing formula and amortized to expense over the options’ vesting periods. Pro forma information is not included for 2006 as all share-based payments have been accounted for under SFAS No. 123(R).

The Company accrues vacation pay by establishing a liability for vacation earned during the current year, but not payable until the following year.

The components of accumulated other comprehensive income (loss) at December 31, 2006 and 2005 are as follows:

Accumulated other comprehensive loss included an after tax loss of approximately $80.1 million ($130.7 million pre-tax) at December 31, 2005 related to a minimum pension liability adjustment based on a review of the funded status of Energy Corp.’s pension plan by the Energy Corp.’s actuarial consultants as of December 31, 2005.

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 the Company has been designated as one of several potentially responsible parties, the amount accrued represents the Company’s estimated share of the cost.

Energy Corp. allocated operating costs to the Company of approximately $88.0 million, $86.2 million and $89.6 million during 2006, 2005 and 2004, respectively. Energy Corp. allocates operating costs to its affiliates based on several factors. Operating costs directly related to specific affiliates are assigned to those affiliates. Where more than one affiliate benefits from certain expenditures, the costs are shared between those affiliates receiving the benefits. Operating costs incurred for the benefit of all affiliates are allocated among the affiliates, based primarily upon head-count, occupancy, usage or 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. Energy Corp. adopted the Distrigas method in January 1996 as a result of a recommendation by the OCC Staff. Energy Corp. believes this method provides a reasonable basis for allocating common expenses.

In 2006, 2005 and 2004, the Company paid Enogex Inc. and its subsidiaries (“Enogex”) approximately $34.9 million, $34.9 million and $34.3 million, respectively, for transporting gas to the Company’s natural gas-fired generating facilities. In 2006, 2005 and 2004, the Company paid Enogex approximately $12.7 million, $12.7 million and $15.3 million, respectively, for natural gas storage services. In 2006, 2005 and 2004, the Company also recorded natural gas purchases from Enogex of approximately $60.4 million, $94.6 million and $45.2 million, respectively. Approximately $5.4 million and approximately $11.2 million were recorded at December 31, 2006 and 2005, respectively, and are included in Accounts Payable – Affiliates in the Balance Sheet for these activities. See Note 14 for a discussion of the gas transportation and storage contract between the Company and Enogex.

In 2006, 2005 and 2004, the Company recorded interest income of approximately $0.3 million, $0.3 million and $0.7 million, respectively, from Energy Corp. for advances made by the Company to Energy Corp.

In 2006, 2005 and 2004, the Company recorded interest expense of approximately $2.6 million, $1.0 million and $0.4 million, respectively, to Energy Corp. for advances made by Energy Corp. to the Company. The interest rate charged on advances to the Company from Energy Corp. approximates Energy Corp.’s commercial paper rate.

In 2006, 2005 and 2004, the Company paid approximately $39.0 million, $74.0 million and $107.6 million, respectively, in dividends to Energy Corp.

Certain prior year amounts have been reclassified on the Financial Statements to conform to the 2006 presentation.

In July 2006, the FASB issued FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109,” which clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with SFAS No. 109, “Accounting for Income Taxes.” This interpretation prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. This interpretation also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. This interpretation is effective for fiscal years beginning after December 15, 2006. The Company adopted this new interpretation effective January 1, 2007. As prescribed in the interpretation, the cumulative effect of applying the provisions of FIN No. 48 shall be reflected as an adjustment to the opening balance of Stockholder’s Equity. The Company estimates that this cumulative effect will be between approximately $3 million and $5 million. The Company also anticipates additional interest expense will be incurred during 2007 related to the method of accounting used to capitalize costs for self-constructed assets (see Note 8 for a further discussion).

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements,” which defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles and expands disclosures about fair value measurements. SFAS No. 157 expands disclosures about the use of fair value to measure assets and liabilities in interim and annual periods subsequent to initial recognition. The guidance in SFAS No. 157 applies to derivatives and other financial instruments measured at fair value under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” at initial recognition and in all subsequent periods. Therefore, SFAS No. 157 nullifies the guidance in footnote 3 of Emerging Issues Task Force Issue No. 02-3, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities.” SFAS No. 157 also amends SFAS No. 133 to remove the guidance similar to that nullified in EITF 02-3. SFAS No. 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. The provisions of SFAS No. 157 should be applied prospectively as of the beginning of the fiscal year in which it is initially applied, except in certain conditions. The Company will adopt this new standard effective January 1, 2008. Management has not yet determined what the impact of this new standard will be on its financial position or results of operations.

In September 2006, the FASB issued SFAS No. 158 which requires an employer to: (i) recognize the overfunded or underfunded status of a defined benefit postretirement plan (other than a multiemployer plan) as an asset or liability in its statement of financial position and to recognize changes in that funded status in the year in which the changes occur through comprehensive income of a business entity; and (ii) to measure the fair value of the funded status of a plan as of the date of its year-end statement of financial position, with limited exceptions. The requirement to initially recognize the funded status of the defined benefit postretirement plan and the disclosure requirements are effective for the year ended December 31, 2006 for the Company. The requirement to measure plan assets and benefit obligations at fair value in accordance with SFAS No. 157 as of the date of the employer’s fiscal year-end statement of financial position is effective for fiscal years ending after December 15, 2008. The Company adopted provision (i) above of this new standard effective December 31, 2006. At December 31, 2006, the projected benefit obligation and fair value of assets of the Company’s portion of Energy Corp.’s pension plan and restoration of retirement income plan was approximately $465.6 million and $410.1 million, respectively, for an

underfunded status of approximately $55.5 million. Also, at December 31, 2006, the accumulated postretirement benefit obligation and fair value of assets of the Company’s portion of Energy Corp.’s postretirement benefit plans was approximately $188.0 million and $71.7 million, respectively, for an underfunded status of approximately $116.3 million. The above amounts have been recorded in Accrued Pension and Benefit Obligations with the offset recorded as a regulatory asset in the Company’s Balance Sheet as discussed in Note 1. The Company will adopt provision (ii) above of this new standard effective December 31, 2008. Management has not yet determined what the impact of provision (ii) of this new standard will be on its financial position or results of operations.

On January 21, 1998, Energy Corp. adopted a Stock Incentive Plan (the “1998 Plan”). In 2003, Energy Corp. adopted, and its shareowners approved, a new Stock Incentive Plan (the “2003 Plan” and together with the 1998 Plan, the “Plans”). The 2003 Plan replaced the 1998 Plan and no further awards will be granted under the 1998 Plan. As under the 1998 Plan, under the 2003 Plan, restricted stock, stock options, stock appreciation rights and performance units may be granted to officers, directors and other key employees. Energy Corp. has authorized the issuance of up to 2,700,000 shares under the 2003 Plan.

Prior to January 1, 2006, Energy Corp. accounted for the Plans under the recognition and measurement provisions of APB Opinion No. 25, as permitted by SFAS No. 123. Energy Corp. also previously adopted the disclosure provisions under SFAS No. 123 and SFAS No. 148, “Accounting for Stock-Based Compensation – Transition and Disclosure.” The Company recorded compensation expense of approximately $0.2 million pre-tax ($0.1 million after tax) and $0.5 million pre-tax ($0.3 million after tax) in 2005 and 2004, respectively, related to its performance units in Other Operation and Maintenance Expense in the Statements of Income. No compensation expense related to stock options was recognized in 2005 or 2004 as all options granted under those plans had an exercise price equal to the market value of Energy Corp.’s common stock on the grant date. Effective January 1, 2006, Energy Corp. adopted SFAS No. 123(R) using the modified prospective transition method. Under that transition method, compensation cost recognized in the first quarter of 2006 included: (i) compensation cost for all share-based payments granted prior to, but not yet vested as of January 1, 2006, based on the fair value calculated in accordance with the provisions of SFAS No. 123(R); and (ii) compensation cost for all share-based payments granted in the first quarter of 2006, based on the fair value calculated in accordance with the provisions of SFAS No. 123(R). Results for prior periods were not restated.

As a result of adopting SFAS No. 123(R) on January 1, 2006, the Company recorded a cumulative effect adjustment of approximately $0.3 million pre-tax ($0.2 million after tax) on January 1, 2006 for outstanding non-vested share-based compensation grants at December 31, 2005, which is not included in the amounts discussed below. The Company determined that the cumulative effect adjustment was immaterial for presentation purposes and is, therefore, included in Other Operation and Maintenance Expense in the Statement of Income. The Company recorded compensation expense of approximately $1.8 million pre-tax ($1.1 million after tax) in 2006 related to the Company’s share-based payments.

Prior to the adoption of SFAS No. 123(R), Energy Corp. presented all tax benefits of deductions resulting from the exercise of stock options or other share-based payments as operating cash flows in the Statements of Cash Flows. SFAS No. 123(R) requires cash flows resulting in tax benefits from tax deductions in excess of the compensation cost recognized for share-based payments (“excess tax benefits”) to be classified as financing cash flows. Energy Corp. recorded an excess tax benefit of approximately $2.8 million in 2006 related to Energy Corp.’s 2006 share-based payments, which amount will be presented as a financing cash inflow and realized when Energy Corp.’s 2006 income tax return is completed in 2007. Energy Corp. realized an excess tax benefit of approximately $1.4 million in 2006 related to Energy Corp.’s 2005 share-based payments, which amount was presented as a financing cash inflow and realized when Energy Corp.’s 2005 income tax return was filed in August 2006. Energy Corp. realized an excess tax benefit of approximately $0.8 million during 2005 related to Energy Corp.’s 2004 share-based payments. Energy Corp. did not realize an excess tax benefit during 2004 related to Energy Corp.’s 2003 share-based payments.

Under the Plans, Energy Corp. has issued performance units which represent the value of one share of Energy Corp.’s common stock. The performance units provide for accelerated vesting if there is a change in control (as defined in the Plans). Each performance unit is subject to forfeiture if the recipient terminates employment with Energy Corp. 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 three-year award cycle, further adjusted based on the achievement of the performance goals during the award cycle. The following table is a summary of the terms of Energy Corp.’s outstanding performance units awarded during 2004, 2005 and 2006.

The performance units granted based on total shareholder return (“TSR”) are contingently awarded and will be payable in cash or shares of Energy Corp.’s common stock (other than performance units awarded in 2006, which will be payable only in shares of 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 is dependent on Energy Corp.’s TSR ranking relative to a peer group of companies. The performance units granted based on earnings per share (“EPS”) are contingently awarded and will be payable in cash or shares of Energy Corp.’s common stock (other than performance units awarded in 2006, which will be payable only in shares of common stock) based on Energy Corp.’s EPS growth over a three-year award cycle compared to a target set at the time of the grant by the Compensation Committee of Energy Corp.’s Board of Directors. If there is no or only a partial payout for the performance units at the end of the three-year award cycle, the unearned performance units are cancelled. During 2006, 2005 and 2004, respectively, Energy Corp. awarded 239,856, 201,794 and 162,591 performance units to certain employees of Energy Corp. and its subsidiaries.

The Company recorded compensation expense of approximately $1.4 million pre-tax ($0.9 million after tax) in 2006 related to the performance units based on TSR. The Company recorded compensation expense of less than $0.1 million pre-tax and after tax and approximately $0.5 million pre-tax ($0.3 million after tax) in 2005 and 2004, respectively, related to the performance units based on TSR. The fair value of the performance units based on TSR 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 settled in stock 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. Compensation expense for the performance units settled in cash is based on the change in the fair value of the performance units for each reporting period. This liability for the performance units will be remeasured at each reporting date until the date of settlement. 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 Energy Corp.’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 three-year award cycle. There are no post-vesting restrictions related to Energy Corp.’s performance units based on TSR. The fair value of the performance units based on TSR was calculated based on the following assumptions at the grant date.

The fair value of the performance units based on TSR which are settled in cash was remeasured at December 31, 2006 based on the following assumptions:

A summary of the activity for Energy Corp.’s performance units applicable to the Company’s employees based on TSR at December 31, 2006 and changes during 2006 are summarized in the following table. Following the end of a three-year performance period, payout of the performance units based on TSR is determined by Energy Corp.’s TSR for such period compared to a peer group and payout requires the approval of the Compensation Committee of Energy Corp.’s Board of Directors. Payouts, if any, are made in two-thirds stock and one-third cash (other than payouts of performance units awarded in 2006, which will be made only in common stock) and are considered made when the payout is approved by the Compensation Committee.

(B) 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.

(D) These performance units awarded in 2004 became fully vested at December 31, 2006 and if certified by the Compensation Committee of Energy Corp.’s Board of Director’s will be converted in February 2007.

A summary of the activity for Energy Corp.’s non-vested performance units applicable to the Company’s employees based on TSR at December 31, 2006 and changes during 2006 are summarized 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) These performance units awarded in 2004 became fully vested at December 31, 2006 and if certified by the Compensation Committee of Energy Corp.’s Board of Director’s will be converted in February 2007.

(D) Of the 51,782 performance units not vested at December 31, 2006, 48,641 performance units are assumed to vest at the end of the applicable vesting period.

At December 31, 2006, there was approximately $0.5 million in unrecognized compensation cost related to non-vested performance units based on TSR which is expected to be recognized over a weighted-average period of 1.56 years.

The Company recorded compensation expense of approximately $0.4 million pre-tax ($0.2 million after tax) in 2006 related to the performance units based on EPS. The Company recorded compensation expense of less than $0.1 million pre-tax and after tax in 2005 related to the performance units based on EPS. No compensation expense related to performance units based on EPS was recognized in 2004 as the 2004 performance units did not have an EPS component. The fair value of the performance units based on EPS is based on grant date fair value which is equivalent to the price of one share of Energy Corp.’s common stock on the date of grant. The fair value of performance units based on EPS 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. Energy Corp. 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 Energy Corp.’s performance units based on EPS. The grant date fair value of the 2005 and 2006 performance units was $23.78 and $28.00, respectively.

A summary of the activity for Energy Corp.’s performance units applicable to the Company’s employees based on EPS at December 31, 2006 and changes during 2006 are summarized in the following table. Following the end of a three-year performance period, payout of the performance units based on EPS growth is determined by Energy Corp.’s growth in EPS for such period compared to a target set at the beginning of the three-year period by the Compensation Committee of Energy Corp.’s Board of Directors and payout requires the approval of the Compensation Committee. Payouts, if any, are made in two-thirds stock and one-third cash (other than payouts of performance units awarded in 2006, which will be made only in common stock) and are considered made when approved by the Compensation Committee.

(B) 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.

A summary of the activity for Energy Corp.’s non-vested performance units applicable to the Company’s employees based on EPS at December 31, 2006 and changes during 2006 are summarized in the following table:

(D) 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.

(E) Due to certain employees transferring between Energy Corp. and its subsidiaries.

(F) Of the 17,254 performance units not vested at December 31, 2006, 16,208 performance units are assumed to vest at the end of the applicable vesting period.

At December 31, 2006, there was approximately $0.4 million in unrecognized compensation cost related to non-vested performance units based on EPS which is expected to be recognized over a weighted-average period of 1.65 years.

The Company recorded compensation expense of less than $0.1 million pre-tax and after tax in 2006 related to stock options. During 2006 and 2005, no stock options were granted under the 2003 Plan. During 2004, 63,700 stock options were granted under the 2003 Plan. Compensation expense for the non-vested stock options at December 31, 2005 was a fixed amount determined at the grant date fair value and was recognized over the remaining vesting period during 2006. No compensation expense related to stock options was recognized in 2005 or 2004 as all options granted under those plans had an exercise price equal to the market value of Energy Corp.’s common stock on the grant date. Energy Corp. accounts for stock option grants as separate grants. The options granted under the Plans vest in one-third annual installments beginning one year from the date of grant and have a contractual life of 10 years. Each option is subject to forfeiture if the recipient terminates employment with Energy Corp. or a subsidiary for any reason other than death, disability or retirement. Dividends are not paid or accrued on unexercised options. The options provide for accelerated vesting if there is a change in control (as defined in the Plans). The fair value of each option grant under the Plans is estimated on the grant date using the Black-Scholes option pricing model that factors in information, including the expected dividend yield, expected price volatility and risk-free interest rate. The fair value was $2.05 at the grant date for the stock options that are not fully vested at December 31, 2006 and was calculated based on the following assumptions at the grant date.

A summary of the activity for Energy Corp.’s options applicable to the Company’s employees at December 31, 2006 and changes during 2006 are summarized in the following table:

A summary of the activity for Energy Corp.’s non-vested options applicable to the Company’s employees at December 31, 2006 and changes during 2006 are summarized in the following table:

(A) All of the 13,903 stock options not vested at December 31, 2006 vested in January 2007.

At December 31, 2006, there was no unrecognized compensation cost related to non-vested options, which became fully vested in January 2007.

Energy Corp. issues new shares to satisfy stock option exercises. Energy Corp. received approximately $14.5 million in 2006 related to exercised stock options. Energy Corp. recorded an excess tax benefit of approximately $2.8 million in 2006 related to Energy Corp.’s 2006 share-based payments, which amount will be presented as a financing cash inflow and realized when Energy Corp.’s 2006 income tax return is completed in 2007. Energy Corp. realized an excess tax benefit of approximately $1.4 million in 2006 related to Energy Corp.’s 2005 share-based payments, which amount was presented as a financing cash inflow and realized when Energy Corp.’s 2005 income tax return was filed in August 2006. Energy Corp. realized an excess tax benefit of approximately $0.8 million during 2005 related to Energy Corp.’s 2004 share-based payments. Energy Corp. did not realize an excess tax benefit during 2004 related to Energy Corp.’s 2003 share-based payments.

In accordance with SFAS No. 143 for periods subsequent to the initial measurement of an asset retirement obligations (“ARO”), an entity shall recognize period-to-period changes in the liability for an ARO resulting from: (i) the passage of time; and (ii) revisions to either the timing or the amount of the original estimate of undiscounted cash flows. During the second quarter of 2006, the Company reviewed its initial ARO valuations and determined that there were changes in the liability of the ARO related to power plant structure legal obligations resulting from revisions to the amount of the original estimate of undiscounted cash flows. As a result, an ARO of approximately $1.0 million was recognized as an increase in the carrying amount of the liability for an ARO and an increase in the related asset retirement cost capitalized as part of the carrying amount of the related long-lived asset with no effect on net income. There were no changes made to previously recorded ARO’s during the last six months of 2006.

Also, in the fourth quarter of 2006, the Company recorded an additional ARO for approximately $0.9 million related to its Centennial wind farm. Beginning January 1, 2007, the Company will amortize the remaining value of the related ARO asset over the estimated remaining life of 99 years.

The Company had a power supply contract with a large industrial customer which expired June 1, 2006. In conjunction with the expiration of this contract, the Company evaluated options to utilize the assets dedicated to that customer, which resulted in the decision to retire these assets as of June 30, 2006. The carrying amount of these assets at June 30, 2006 was approximately $6.8 million, which was recorded as a pre-tax loss during the second quarter of 2006. This loss was included in Other Expense in the Statement of Income. Also, as part of the settlement of the ARO for these assets, the Company recorded a reduction to the previously recorded ARO for these assets of approximately $0.9 million in 2006 due to an agreement with a third party to provide removal and remediation services. This reduction is included in Other Expense in the Statement of Income.

The Company periodically utilizes derivative contracts to reduce exposure to adverse interest rate fluctuations. During 2006 and 2005, the Company’s use of price risk management instruments involved the use of an interest rate swap agreement and treasury lock agreements. The interest rate swap agreement involved the exchange of fixed price or rate payments in exchange for floating price or rate payments over the life of the instrument without an exchange of the underlying principal amount. The treasury lock agreements in late 2005 protected against the variability of future interest payments of long-term debt that was issued by the Company in January 2006 and the treasury lock agreement in November 2006 is to protect against the variability of future interest payments of long-term debt that is expected to be issued during the first half of 2007.

In accordance with SFAS No. 133, the Company recognizes its non-exchange traded derivative instruments as Price Risk Management assets or liabilities in the Balance Sheets at fair value with such amounts classified as current or long-term based on their anticipated settlement. The accounting for changes in the fair value of a derivative depends on the intended use of the derivative and resulting designation. For derivative instruments that are designated and qualify as a fair value hedge, the gain or loss on the derivative instrument is recognized in current earnings on the same line item as the gain or loss recorded for the change in the fair value of the hedged item. 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 is recognized currently in earnings. Forecasted transactions designated as the hedged item 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. If the forecasted transactions are no longer reasonably possible of occurring, any associated amounts recorded in Accumulated Other Comprehensive Income will also be recognized directly in earnings.

At December 31, 2006 and 2005, the Company had no outstanding interest rate swap agreements. At December 31, 2006, the Company’s treasury lock agreement has been designated as a cash flow hedge under SFAS No. 133. At December 31, 2005, the Company had two separate treasury lock agreements designated as cash flow hedges under SFAS No. 133, which were terminated on January 6, 2006 after the Company issued long-term debt. The Company measures ineffectiveness of the cash flow hedges under the hypothetical derivative method prescribed by SFAS No. 133. Under the hypothetical derivative method, the Company has designated that the critical terms of

the hedging instrument are the same as the critical terms of the hypothetical derivative used to value the forecasted transaction, and, as a result, no ineffectiveness is expected.

The following table discloses information about investing and financing activities that affect recognized assets and liabilities but which do 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.

The Company is a member of an affiliated group that files consolidated income tax returns. Income taxes are allocated to each company in the affiliated group based on its separate taxable income or loss. Federal investment tax credits on electric utility property have been deferred and are being amortized to income over the life of the related property. The Company continues to amortize its federal investment tax credits on a ratable basis throughout the year. This ratable amortization results in a larger percentage reconciling item related to these credits during the first quarter when the Company historically experiences decreased book income. The following schedule reconciles the statutory federal tax rate to the effective income tax rate:

(A) During 2005, the Company performed a detailed analysis of all deferred tax assets and liabilities. In connection with this analysis, it was determined that an excess liability existed. The removal of this excess liability caused a permanent difference in the effective tax rate for 2005 of approximately 1.2 percent.

In connection with the filing in the third quarter of 2003 of Energy Corp.’s consolidated income tax returns for 2002, the Company elected to change its tax method of accounting related to the capitalization of costs for self-constructed assets to another method prescribed in the Income Tax regulations. The accounting method change was for income tax purposes only. For financial accounting purposes, the only change was recognition of the impact of the cash flow generated by accelerating income tax deductions. This was reflected in the financial statements as a switch from current income taxes payable to deferred income taxes payable. This tax accounting method change resulted in a one-time catch-up deduction for costs previously capitalized under the prior method, resulting in a consolidated tax net operating loss for 2002. This tax net operating loss eliminated Energy Corp.’s current federal and state income tax liability for 2002 and 2003 and all estimated payments made for 2002 were refunded. Energy Corp. received federal and state income tax refunds of approximately $50.8 million during 2003 related to this tax accounting method change.

During 2005, new guidelines were issued by the Internal Revenue Service (“IRS”) related to the change in the method of accounting used to capitalize costs for self-construction discussed above. Energy Corp.’s current IRS examination process, which was completed in the second quarter of 2006, identified this change in method of accounting as an issue under examination. As a result of their examination, the IRS disagreed with the change the Company made in 2002 and determined that the Company should change its tax method of accounting for the capitalization of costs for self-constructed assets to another method prescribed in the Income Tax regulations. Energy Corp. filed a formal protest with the IRS on July 21, 2006 and requested a hearing with the IRS to review the IRS’s determination that the tax accounting method the Company elected in 2002 was not appropriate. On August 17, 2006, Energy Corp. made a deposit with the IRS in anticipation that a portion of prior year deductions will be disallowed. The deposit enabled the Company to cease accruing interest effective August 17, 2006. The impact of this matter on future cash flows is uncertain but could be material. The Company cannot predict either the final outcome or the timing of the resolution of this matter. During 2005 and 2006, the Company recorded approximately $3.5 million in additional interest expense related to income taxes as a result of a potential adjustment. This amount is included in Interest on Short-Term Debt and Other Interest Charges in the Statements of Income.

The Company follows the provisions of SFAS No. 109 which uses an asset and liability approach to accounting for income taxes. Under SFAS No. 109, deferred tax assets or liabilities are computed based on the difference between the financial statement and income tax bases of assets and liabilities using the enacted marginal tax rate. Deferred income tax expenses or benefits are based on the changes in the asset or liability from period to period.

The deferred tax provisions, set forth above, are recognized as costs in the ratemaking process by the commissions having jurisdiction over the rates charged by the Company. The components of Accumulated Deferred Taxes at December 31, 2006 and 2005 respectively, are as follows:

The Company has an Oklahoma investment tax credit carryover of approximately $2.7 million. These Oklahoma credit carryover amounts will begin expiring in the year 2017. During 2006, additional Oklahoma tax credits of approximately $4.9 million were generated by the Company. The Company believes that, based on current projections, the entire $7.6 million of these state tax credit amounts will be fully utilized in 2006.

There were no new shares of common stock issued during 2006, 2005 or 2004. The Company’s Restated Certificate of Incorporation permits the issuance of a new series of preferred stock with dividends payable other than quarterly.

A summary of the Company’s long-term debt is included in the Statements of Capitalization. At December 31, 2006, the Company is in compliance with all of its debt agreements.

The Company has three series of variable-rate industrial authority bonds (the “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 (dollars in millions):

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, the Company is obligated to repurchase such unremarketed Bonds. The Company has sufficient long-term liquidity to meet these obligations.

There are no maturities of the Company’s long-term debt during the next five years.

The Company 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 – Other and 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.

At December 31, 2006 and 2005, the Company had approximately $102.1 million and $108.3 million, respectively, in outstanding advances from Energy Corp. In accordance with SFAS No. 6, $220.0 million of commercial paper was classified as long-term debt at December 31, 2005 as the Company planned to refinance this amount. Subsequently, the Company issued $220 million of long-term debt in January 2006 and repaid the outstanding commercial paper and bank borrowings. The following table shows Energy Corp.’s and the Company’s revolving credit agreements and available cash at December 31, 2006.

Energy Corp.’s and the Company’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 the back-up lines of credit could cause annual fees and borrowing rates to increase if an adverse ratings impact occurs. The impact of any future downgrades would result in an increase in the cost of short-term borrowings but would not result in any defaults or accelerations as a result of the rating changes.

Unlike Energy Corp., the Company must obtain regulatory approval from the FERC in order to borrow on a short-term basis. The Company 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, 2007 and ending December 31, 2008.

In September 2006, the FASB issued SFAS No. 158 which requires an employer to: (i) recognize the overfunded or underfunded status of a defined benefit postretirement plan (other than a multiemployer plan) as an asset or liability in its statement of financial position and to recognize changes in that funded status in the year in which the changes occur through comprehensive income of a business entity; and (ii) to measure the fair value of the funded status of a plan as of the date of its year-end statement of financial position, with limited exceptions. The requirement to initially recognize the funded status of the defined benefit postretirement plan and the disclosure requirements are effective for the year ended December 31, 2006 for the Company. The requirement to measure plan assets and benefit obligations at fair value in accordance with SFAS No. 157 as of the date of the employer’s fiscal year-end statement of financial position is effective for fiscal years ending after December 15, 2008. SFAS No. 158 also requires additional disclosures for defined benefit pension plans and other defined benefit postretirement plans.

All eligible employees of the Company are covered by a non-contributory defined benefit pension plan sponsored by Energy Corp. For employees hired on or after February 1, 2000, the pension plan is a cash balance plan, under which Energy Corp. annually will credit to the employee’s account an amount equal to five percent of the employee’s annual compensation plus accrued interest. Employees hired prior to February 1, 2000, will receive the greater of the cash balance benefit or a benefit based primarily on years of service and the average of the five highest consecutive years of compensation during an employee’s last 10 years prior to retirement, with reductions in benefits for each year prior to age 62 unless the employee’s age and years of credited service equal or exceed 80.

It is Energy Corp.’s policy to fund the plan on a current basis based on the net periodic SFAS No. 87, “Employers’ Accounting for Pensions,” pension expense as determined by the Company’s actuarial consultants. Additional amounts may be contributed from time to time to increase the funded status of the plan. During 2006 and 2005, Energy Corp. made contributions to its pension plan of approximately $90.0 million and $32.0 million, respectively, of which approximately $69.4 million and $24.8 million, respectively, were allocated to the Company, to 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. In August 2006, legislation was passed that changed the funding requirement for single- and multi-employer defined benefit pension plans as discussed below. During 2007, Energy Corp. may contribute up to $50 million to its pension plan, of which approximately $38.5 million is expected to be allocated to the Company. The expected contribution to the pension plan, anticipated to be in the form of cash, is a discretionary contribution and is not required to satisfy the minimum regulatory funding requirement specified by the Employee Retirement Income Security Act of 1974, as amended.

At December 31, 2006, the projected benefit obligation and fair value of assets of the Company’s portion of Energy Corp.’s pension plan and restoration of retirement income plan was approximately $465.6 million and $410.1 million, respectively, for an underfunded status of approximately $55.5 million. The above amounts have been recorded in Accrued Pension and Benefit Obligations with the offset recorded as a regulatory asset in the Company’s Balance Sheet as discussed in Note 1. The entry did not impact the results of operations in 2006 and did not require a usage of cash and is therefore excluded from the Statement of Cash Flows. The amount recorded as a regulatory asset represents a net periodic benefit cost to be recognized in the Statements of Income in future periods.

During 2005, Energy Corp. made contributions to the pension plan that exceeded amounts previously recognized as net periodic pension expense and recorded a net prepaid benefit obligation at December 31, 2005 of approximately $88.9 million, of which approximately $66.0 million was allocated to the Company. At December 31, 2005, Energy Corp.’s projected pension benefit obligation exceeded the fair value of the pension plan assets by approximately $154.6 million, of which approximately $127.6 million was allocated to the Company. As a result of recording a prepaid benefit obligation and having a funded status where the projected benefit obligations exceeded the fair value of plan assets, provisions of SFAS No. 87 required the recognition of an additional minimum liability in the amount of approximately $181.4 million for Energy Corp., of which approximately $157.3 million was allocated to the Company at December 31, 2005. The offset of this entry was an intangible asset and Accumulated Other Comprehensive Income, net of a deferred tax asset; therefore, this adjustment did not impact the results of operations in 2005 and did not require a usage of cash and is therefore excluded from the Statement of Cash Flows. The amount recorded as an intangible asset equaled the unrecognized prior service cost with the remainder recorded in Accumulated Other Comprehensive Income. The amount in Accumulated Other Comprehensive Income represents a net periodic benefit cost to be recognized in the Statements of Income in future periods.

In accordance with SFAS No. 88, “Employer’s Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits,” a one-time settlement charge is required to be recorded by an organization when lump sum payments or other settlements that relieve the organization from the responsibility for the pension benefit obligation during a plan year exceed the service cost and interest cost components of the organization’s net periodic pension cost. During 2006, the Company experienced an increase in both the number of employees electing to retire and the amount of lump sum payments to be paid to such employees upon retirement in 2006. As a result, Energy Corp. recorded a pension settlement charge for 2006 of approximately $17.1 million in the fourth quarter of 2006, of which approximately $13.3 million was allocated to the Company. The pension settlement charge did not require a cash outlay by the Company and did not increase the Company’s total pension expense over time, as the charge was an acceleration of costs that otherwise would have been recognized as pension expense in future periods. The Company’s Oklahoma jurisdictional portion of this charge was recorded as a regulatory asset (see Note 1 for a further discussion).

On August 17, 2006, President Bush signed The Pension Protection Act of 2006 (the “Pension Protection Act”) into law. The Pension Protection Act makes changes to important aspects of qualified retirement plans. Among other things, it introduces a new funding requirement for single- and multi-employer defined benefit pension plans, provides legal certainty on a prospective basis for cash balance and other hybrid plans and addresses contributions to defined contribution plans, deduction limits for contributions to retirement plans and investment advice provided to plan participants. The Company is currently analyzing the impact of the Pension Protection Act on its pension plans.

The pension plan’s assets consist primarily of investments in mutual funds, U.S. Government securities, listed common stocks and corporate debt. The following table shows, by major category, the percentage of the fair value of the plan assets held at December 31, 2006 and 2005:

The pension plan assets are held in a trust which follows an investment policy and strategy designed to maximize the long-term investment returns of the trust at prudent risk levels. Common stocks are used as a hedge against moderate inflationary conditions, as well as for participation in normal economic times. Fixed income investments are utilized for high current income and as a hedge against deflation. Energy Corp. has retained an

investment consultant responsible for the general investment oversight, analysis, monitoring investment guideline compliance and providing quarterly reports to certain of Energy Corp.’s members and Energy Corp.’s Employee Benefit Funds Management Committee (the “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 their respective portfolio. The table below shows the target asset allocation percentages for each major category of plan assets:

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 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 Service (“Moody’s”), Standard & Poor’s Ratings Services (“Standard & Poor’s”) or Fitch Ratings (“Fitch”). 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 Energy Corp.’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 S&P 400 Midcap Index, small dividend yield, return on equity at or near the S&P 400 Midcap Index and earnings per share growth rate at or near the S&P 400 Midcap Index. The domestic small-capitalization equity manager will purchase shares of companies with market capitalizations lower that 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 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 Europe, Australia and the Far East Index (“EAFE”) is the benchmark for comparative performance purposes. The EAFE Index is a market value weighted index comprised of over 1,000 companies traded on the stock markets of Europe, Australia, New Zealand and the Far East. 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. A minimum of 95 percent of the total assets of an equity manager’s portfolio must be allocated to the equity markets. Options or financial futures may not be purchased unless prior approval of the 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 Energy Corp.’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.

Energy Corp. provides a restoration of retirement income plan to those participants in Energy Corp.’s pension plan whose benefits are subject to certain limitations under the Internal Revenue Code (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.

In addition to providing pension benefits, Energy Corp. provides certain medical and life insurance benefits for eligible retired members (“postretirement benefits”). 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 age 55 with 10 years of vesting service at the time of retirement are entitled to these postretirement benefits. Employees hired on or after February 1, 2000, are not entitled to postretirement medical benefits but are entitled to postretirement life insurance benefits. Eligible retirees must contribute such amount as Energy Corp. 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. The Company charges to expense the SFAS No. 106, “Employers’ Accounting for Postretirement Benefits other than Pensions,” costs and includes an annual amount as a component of the cost-of-service in future ratemaking proceedings.

At December 31, 2006, the accumulated postretirement benefit obligation and fair value of assets of the Company’s portion of Energy Corp.’s postretirement benefit plans was approximately $188.0 million and $71.7

million, respectively, for an underfunded status of approximately $116.3 million. The above amounts have been recorded in Accrued Pension and Benefit Obligations with the offset recorded as a regulatory asset in the Company’s Balance Sheet as discussed in Note 1. The entry did not impact the results of operations in 2006 and did not require a usage of cash and is therefore excluded from the Statement of Cash Flows. The amount recorded as a regulatory asset represents a net periodic benefit cost to be recognized in the Statements of Income in future periods.

The details of the funded status of the pension plan (including the restoration of retirement income plan) and the postretirement benefit plans and the amounts included in the Balance Sheets are as follows:

	Pension Plan and
	Restoration of Retirement			Postretirement
	Income Plan			Benefit Plans
December 31 (In millions)	2006		2005	2006	2005

Change in Benefit Obligation
Beginning obligations	$ (478.2)		$ (447.1)	$ (175.8)	$ (164.8)
Service cost	(13.4)		(12.7)	(2.6)	(2.3)
Interest cost	(24.7)		(24.6)	(10.0)	(8.9)
Participants’ contributions	---		---	(4.2)	(3.3)
Actuarial losses	(10.6)		(29.1)	(9.1)	(8.6)
Benefits paid	61.3		35.3	13.7	12.1
Ending obligations	(465.6)		(478.2)	(188.0)	(175.8)

Change in Plans’ Assets
Beginning fair value		350.6	341.2	65.1		62.0
Actual return on plans’ assets		51.3	19.1	8.1		4.4
Employer contributions		69.5	25.6	8.0		7.5
Participants’ contributions		---	---	4.2		3.3
Benefits paid		(61.3)	(35.3)	(13.7)		(12.1)
Ending fair value		410.1	350.6	71.7		65.1
Funded status at end of year		$ (55.5)	$ (127.6)	$ (116.3)		$ (110.7)

Incremental Effect of Applying SFAS No. 158 on Individual Line Items in the Balance Sheet at December 31, 2006

	Pension Plan and
	Restoration of Retirement			Postretirement
	Income Plan			Benefit Plans
Year ended December 31 (In millions)	2006	2005	2004	2006	2005	2004
Service cost	$ 13.4	$ 12.7	$ 11.3	$ 2.6	$ 2.3	$ 2.1
Interest cost	24.7	24.6	24.4	10.0	8.9	9.6
Return on plan assets	(30.4)	(27.4)	(25.5)	(5.5)	(5.2)	(5.3)
Amortization of transition obligation	---	---	---	2.5	2.5	2.5
Amortization of net loss	13.4	11.7	9.6	7.6	4.5	4.6
Amortization of recognized prior service cost	4.7	5.2	5.2	1.5	1.5	1.5
Settlement (A)	13.3	---	---	---	---	---
Net periodic benefit cost (B)	$ 39.1	$ 26.8	$ 25.0	$ 18.7	$ 14.5	$ 15.0

(A) Approximately $11.6 million of Energy Corp.’s settlement charge related to the Company’s Oklahoma jurisdiction has been recorded as a regulatory asset (see Note 1 for a further discussion).

(B) The capitalized portion of the net periodic pension benefit cost was approximately $7.2 million, $8.3 million and $7.8 million at December 31, 2006, 2005 and 2004, respectively. The capitalized portion of the net periodic postretirement benefit cost was approximately $5.6 million, $4.7 million and $4.7 million at December 31, 2006, 2005 and 2004, respectively.

The overall expected rate of return on plan assets assumption remained 8.50 percent in 2005 and 2006 in determining net periodic benefit cost. 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.

The Company expects to pay benefits related to its pension plan and restoration of retirement income plan of approximately $50.8 million in 2007, $52.3 million in 2008, $53.4 million in 2009, $52.0 million in 2010, $52.3 million in 2011 and an aggregate of $243.5 million in years 2012 to 2016. These expected benefits were based on the same assumptions used to measure the Company’s benefit obligation at the end of the year and include benefits attributable to estimated future employee service.

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 eight percent in 2007 with the rates decreasing in subsequent years by one percentage point per year through 2010. A one-percentage point change in the assumed health care cost trend rate would have the following effects:

On December 8, 2003, President Bush signed into law the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the “Medicare Act”). The Medicare Act expanded Medicare to include, for the first time, coverage for prescription drugs. In May 2004, the FASB issued FASB Staff Position No. FAS 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003.” FAS 106-2 provided guidance on the accounting for the effects of the Medicare Act for employers that sponsor postretirement heath care plans that provide prescription drug benefits. FAS 106-2 also required those employers to provide certain disclosures regarding the effect of the federal subsidy provided by the Medicare Act. Energy Corp. adopted this new standard effective July 1, 2004 with retroactive application to the date of the Medicare Act’s enactment. Management expects that the accumulated plan benefit obligation (“APBO”) for Energy Corp. with respect to its postretirement medical plan will be reduced by approximately $39.7 million as a result of savings to Energy Corp. with respect to its postretirement medical plan resulting from the Medicare Act provided subsidy, which will reduce Energy Corp.’s costs for its postretirement medical plan by approximately $6.5 million annually, of which approximately $5.5 million is expected to be allocated to the Company. The $5.5 million in annual savings is comprised of a reduction of approximately $3.3 million from amortization of the $33.8 million gain due to the reduction of the APBO, a reduction in the interest cost on the APBO of approximately $1.8 million and a reduction in the service cost due to the subsidy of approximately $0.4 million.

The Company expects to pay gross benefits payments related to its postretirement benefit plans, including prescription drug benefits, of approximately $10.7 million in 2007, $11.1 million in 2008, $11.9 million in 2009, $12.7 million in 2010, $13.5 million in 2011 and an aggregate of $75.8 million in years 2012 to 2016. The Company expects to receive federal subsidy receipts provided by the Medicare Act of approximately $1.0 million in 2007, $1.2 million in 2008, $1.3 million in 2009, $1.4 million in 2010, $1.5 million in 2011 and an aggregate of $9.0 million in years 2012 to 2016. The Company did not receive any federal subsidy receipts in 2006.

Energy Corp. provides a defined contribution savings plan. Each regular full-time employee of Energy Corp. or a participating affiliate is eligible to participate in the plan immediately. All other employees of Energy

Corp. or a participating affiliate are eligible to become participants in the plan after completing one year of service as defined in the plan. Participants may contribute each pay period any whole percentage between two percent and 19 percent of their compensation, as defined in the plan, for that pay period. Contributions of the first six percent of compensation are called “Regular Contributions” and any contributions over six percent of compensation are called “Supplemental Contributions.” 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. Energy Corp. contributes to the Plan each pay period on behalf of each participant an amount equal to 50 percent of the participant’s Regular Contributions for participants whose employment or re-employment date, as defined in the plan, occurred before February 1, 2000 and who have less than 20 years of service, as defined in the plan, and an amount equal to 75 percent of the participant’s Regular Contributions for participants whose employment or re-employment date occurred before February 1, 2000 and who have 20 or more years of service. For participants whose employment or re-employment date occurred on or after February 1, 2000, Energy Corp. shall contribute 100 percent of the Regular Contributions deposited during such pay period by such participant. No Energy Corp. contributions are made with respect to a participant’s Supplemental Contributions, Catch-Up Contributions, or with respect to a participant’s Regular 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. Energy Corp.’s contribution which is initially allocated for investment to the Energy Corp. Common Stock Fund may be made in shares of Energy Corp.’s common stock or in cash which is used to invest in Energy Corp.’s common stock. Once made, Energy Corp.’s contribution may be reallocated, at any time, by participants to other available investment options. The Company contributed approximately $4.2 million, $4.2 million and $3.9 million during 2006, 2005 and 2004, respectively, to the defined contribution plan.

Energy Corp. provides a deferred compensation 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 Energy Corp. and to supplement such employees’ defined contribution 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 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 defined contribution plan with such deferrals to start when maximum deferrals to the qualified defined contribution 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. Energy Corp. matches employee (but not non-employee director) deferrals to provide for the match that would have been made under the defined contribution plan had such deferrals been made under that plan without regard to the statutory limitations on elective deferrals and matching contributions applicable to the defined contribution plan. In addition, the Benefits Committee may award discretionary employer contribution credits to a participant under the plan. Energy Corp. accounts for the contributions related to the Company’s executive officers in this plan as Accrued Pension and Benefit Obligations and the Company accounts for the contributions related to the Company’s directors in this plan as Other Deferred Credits and Other Liabilities in the Balance Sheets. The investment associated with these contributions is accounted for as Other Property and Investments in Energy Corp.’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 Energy Corp.’s Consolidated Statements of Income.

Energy Corp. provides a supplemental executive retirement plan in order to attract and retain lateral hires or other executives designated by the Compensation Committee of Energy Corp.’s Board of Directors who may not otherwise qualify for a sufficient level of benefits under Energy Corp.’s pension plan. The supplemental executive retirement plan is intended to be an unfunded plan and not subject to the benefit limits imposed by the Code.

The Company’s capital expenditures are estimated at approximately: 2007 – $426.5 million, 2008 – $689.6 million, 2009 – $745.1 million, 2010 – $589.9 million, 2011 – $480.2 million and 2012 – $366.0 million. These amounts include capital expenditures of approximately $94.0 million, $278.8 million, $285.7 million, $97.7 million and $34.1 million, respectively, in 2007 through 2011 related to the construction of the proposed Red Rock power plant as discussed in Note 14.

Future minimum payments for the noncancellable operating lease for railcars are as follows:

Payments for operating lease obligations were approximately $4.2 million, $5.4 million and $5.4 million in 2006, 2005 and 2004, respectively.

At December 31, 2006, the Company had a noncancellable operating lease with purchase options, covering 1,464 coal hopper railcars to transport coal from Wyoming to the Company’s coal-fired generation units. Rental payments are charged to Fuel Expense and are recovered through the Company’s tariffs and automatic fuel adjustment clauses. On December 29, 2005, the Company entered into a new lease agreement for railcars effective February 1, 2006 with a new lessor as described below. At the end of the new lease term which is January 31, 2011, the Company has the option to either purchase the railcars at a stipulated fair market value or renew the lease. If the Company chooses not to purchase the railcars or renew the lease agreement and the actual value of the railcars is less than the stipulated fair market value, the Company would be responsible for the difference in those values up to a maximum of approximately $29.9 million. The Company is also required to maintain 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.

The Company has entered into agreements with three qualifying cogeneration facilities having initial terms of three to 32 years. These contracts were entered into pursuant to the Public Utility Regulatory Policy Act of 1978 (“PURPA”). Stated generally, PURPA and the regulations thereunder promulgated by the FERC require the Company to purchase power generated in a manufacturing process from a qualified cogeneration facility (“QF”). The rate for such power to be paid by the Company was approved by the OCC. The rate generally consists of two components: one is a rate for actual electricity purchased from the QF by the Company; the other is a capacity charge, which the Company must pay the QF for having the capacity available. However, if no electrical power is made available to the Company for a period of time (generally three months), the Company’s obligation to pay the capacity charge is suspended. The total cost of cogeneration payments is recoverable in rates from customers. The Company has approximately 430 MW’s of QF contracts that will expire at the end of 2007, unless extended by the Company. For one of these QF contracts, the Company purchases 100 percent of electricity generated by the QF. For the other QF contract, the Company can purchase up to 17 percent of electricity generated by the QF. In addition, effective September 1, 2004, the Company entered into a new 15-year power purchase agreement for 120 MW’s with Powersmith Cogeneration Project, L.P. (“PowerSmith”) in which the Company purchases 100 percent of electricity generated by PowerSmith.

During 2006, 2005 and 2004, the Company made total payments to cogenerators of approximately $162.6 million, $183.8 million and $203.5 million, respectively, of which approximately $94.9 million, $95.5 million and $155.3 million, respectively, represented capacity payments. All payments for purchased power, including cogeneration, are included in the Statements of Income as Cost of Goods Sold. The future minimum capacity payments under the contracts are approximately: 2007 – $97.6 million, 2008 – $96.1 million, 2009 – $94.4 million, 2010 – $92.6 million and 2011 – $90.6 million. The minimum capacity payment amounts for 2008 through 2011 assume the Company elects to extend certain cogeneration contracts, which otherwise expire at the end of 2007.

The Company purchased necessary fuel supplies of coal and natural gas for its generating units of approximately $195.1 million, $163.5 million and $166.5 million for the years ended December 31, 2006, 2005 and 2004, respectively. The Company has entered into purchase commitments of necessary fuel supplies of approximately: 2007 – $198.0 million, 2008 – $114.1 million, 2009 – $105.9 million, 2010 – $107.7 million, 2011 - $65.4 million and 2012 and Beyond – $23.4 million.

In October 2006, the Company issued and completed a request for proposal (“RFP”) for gas supply purchases for periods that began in November 2006 through March 2007, which accounted for approximately eight percent of its projected 2007 natural gas requirements. All of these contracts are tied to various gas price market indices and will expire in 2007. The Company’s remaining 2007 natural gas requirements will be met with additional RFP’s in early to mid-2007. The Company will meet additional natural gas requirements with monthly and daily purchases as required.

United States of America ex rel., Jack J. Grynberg v. Enogex Inc., Enogex Services Corporation and the Company. (United States District Court for the Western District of Oklahoma, Case No. CIV-97-1010-L.) United States of America ex rel., Jack J. Grynberg v. Transok Inc. et al. (United States District Court for the Eastern District of Louisiana, Case No. 97-2089; United States District Court for the Western District of Oklahoma, Case No. 97-1009M.). On June 15, 1999, the Company was served with Plaintiff’s complaint, which is a qui tam action under the False Claims Act. Plaintiff Jack J. Grynberg, as individual relator on behalf of the United States Government, alleges: (i) each of the named defendants have improperly or intentionally mismeasured gas (both volume and British thermal unit (“Btu”) content) purchased from federal and Indian lands which have resulted in the under-reporting and underpayment of gas royalties owed to the Federal Government; (ii) certain provisions generally found in gas purchase contracts are improper; (iii) transactions by affiliated companies are not arms-length; (iv) excess processing cost deduction; and (v) failure to account for production separated out as a result of gas processing. Grynberg seeks the following damages: (a) additional royalties which he claims should have been paid to the Federal Government, some percentage of which Grynberg, as relator, may be entitled to recover; (b) treble damages; (c) civil penalties; (d) an order requiring defendants to measure the way Grynberg contends is the better way to do so; and (e) interest, costs and attorneys’ fees.

transferring and consolidating for pretrial purposes approximately 76 other similar actions filed in nine other Federal Courts. The consolidated cases are now before the United States District Court for the District of Wyoming.

On October 20, 2006, the District Court of Wyoming ruled on Grynberg’s appeal, following and confirming the recommendation of the special master dismissing all claims against Enogex Inc., Enogex Services Corp., Transok, Inc. and the Company, for lack of subject matter jurisdiction. Judgment was entered on November 17, 2006 and Grynberg filed his notice of appeal with the District Court of Wyoming. The defendants filed motions for attorneys’ fees regarding issues of liability and Rule 11 motions on January 8, 2007. The defendants also filed for other legal costs on December 18, 2006. A hearing on these motions is currently scheduled for April 24, 2007. Grynberg has also filed appeals with the Tenth Circuit Court of Appeals. The Company intends to vigorously defend this action. At this time, the Company is unable to provide an evaluation of the likelihood of an unfavorable outcome and an estimate of the amount or range of potential loss to the Company.

Will Price (Price I) – On September 24, 1999, various subsidiaries of Energy Corp. were served with a class action petition filed in United States District Court, State of Kansas by Quinque Operating Company and other named plaintiffs, alleging mismeasurement of natural gas on non-federal lands. On April 10, 2003 the Court entered an order denying class certification. On May 12, 2003, 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 petition and the court granted the motion on July 28, 2003. In this amended petition, the Company and Enogex Inc. were omitted from the case. Two subsidiaries of Enogex remain as defendants. The Plaintiffs’ amended petition alleges that approximately 60 defendants, including two Enogex subsidiaries, have improperly measured natural gas. The amended petition reduces the claims to: (1) mismeasurement of volume only; (2) conspiracy, unjust enrichment and accounting; (3) a putative Plaintiffs’ class of only royalty owners; and (4) gas measured in three specific states. A hearing on class certification issues was held April 1, 2005. Energy Corp. intends to vigorously defend this action. At this time, Energy Corp. is unable to provide an evaluation of the likelihood of an unfavorable outcome and an estimate of the amount or range of potential loss to Energy Corp.

On June 19, 2006, two Company customers brought a putative class action, on behalf of all similarly situated customers, in the District Court of Creek County, Oklahoma, challenging certain charges on the Company’s electric bills. The plaintiffs claim that the Company improperly charged sales tax based on franchise fee charges paid by its customers. The plaintiffs also challenge certain franchise fee charges, contending that such fees are more than is allowed under Oklahoma law. The Company’s motion for summary judgment was denied by the trial judge. The Company has filed a writ of prohibition at the Oklahoma Supreme Court asking the court to direct the trial court to dismiss the class action suit. At the present time, the Company believes that this case is without merit and intends to continue vigorously defending this case.

Calpine Corporation, Calpine Energy Services, L.P., and several other affiliates (collectively “Calpine”) voluntarily filed for Chapter 11 bankruptcy protection from creditors on December 20, 2005 (Case No. 05-60200 (BRL)) United States Bankruptcy Court, S.D. of New York. A Calpine-owned power generation plant in Oklahoma is contractually obligated to provide capacity and energy to the Company. The Calpine plant also pays, through the Southwest Power Pool (“SPP”), for transmission services provided to the Company. The Company expects both arrangements to remain in effect; however, whether Calpine in its bankruptcy proceedings will ultimately reject these agreements with the Company is unknown.

Approximately $15.6 million and $96.0 million, respectively of the Company’s capital expenditures budgeted for 2007 and 2008 are to comply with environmental laws and regulations. The Company’s management believes that all of its operations are in substantial compliance with present federal, state and local environmental standards. It is estimated that the Company’s total expenditures for capital, operating, maintenance and other costs to preserve and enhance environmental quality will be approximately $81.9 million during 2007 as compared to approximately $58.0 million in 2006. The Company continues to evaluate its environmental management systems to ensure compliance with existing and proposed environmental legislation and regulations and to better position itself in a competitive market.

On March 15, 2005, the Environmental Protection Agency (“EPA”) issued the Clean Air Mercury Rule (“CAMR”) to limit mercury emissions from coal-fired boilers. On May 31, 2006, the EPA issued a ruling which amended and clarified minor portions of the CAMR. The CAMR is currently subject to legal challenges. The CAMR requires reductions in mercury in two phases, Phase I beginning in 2010 and Phase II in 2018. The CAMR is based on the cap and trade program that will allow utilities to purchase mercury allowances (if available) rather than reduce emissions. It is anticipated that the Company will need to obtain allowances or reduce its mercury emissions in Phase II by approximately 70 percent. The CAMR requires each state to adopt the requirements of the federal rule into a state implementation plan. However, the CAMR does not preclude states from developing more stringent mercury reduction requirements. The state of Oklahoma has proposed to incorporate the EPA’s CAMR, along with the proposed mercury allowance allocations, into the state implementation program. The Company is currently participating in the state rulemaking process and anticipates the rulemaking to be completed by the end of 2007. Because rulemaking is in progress, the cost to install any mercury controls is uncertain at this time but is expected to be significant to meet Phase II requirements in 2018. The state implementation plan will also require continuous monitoring of mercury emissions from the Company’s coal-fired boilers beginning in 2009. The cost of the monitoring equipment is estimated at approximately $7.9 million which is expected to be incurred during the years 2007 and 2008. However, the cost to comply with the CAMR monitoring requirements will be in addition to the cost of other emissions monitoring that is already in place pursuant to Title IV of the Clean Air Act Amendments of 1990.

On June 15, 2005, the EPA issued final amendments to its 1999 regional haze rule. These regulations are intended to protect visibility in national parks and wilderness areas (“Class I 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. Sulfates and nitrate aerosols (both emitted from coal-fired boilers) can lead to the degradation of visibility. The state of Oklahoma has joined with eight other central states and has begun to finalize the process of determining what, if any, impact emission sources in Oklahoma have on national parks and wilderness areas.

In September 2005, the Oklahoma Department of Environmental Quality (“ODEQ”) informally notified affected utilities that they would be required to perform a study to determine their impact on visibility in Federal Class I areas. Affected utilities are those which have “Best Available Retrofit Technology (“BART”) eligible sources” (sources built between 1962 and 1977). For the Company these include various generating units at various generating stations. Regulations, however, allow an owner or operator of a BART-eligible source to request and obtain a waiver from BART if modeling shows no significant impact on visibility in nearby Class I areas. Therefore, the Company initiated a preliminary modeling study that was completed in July 2006. Because the preliminary results indicated a significant impact from the Company’s Sooner, Muskogee, Seminole and Horseshoe Lake generating stations on visibility in Class I areas in both Oklahoma and Arkansas, more detailed modeling is being performed. Based on results of modeling for the Seminole and Horseshoe Lake generating stations, the Company submitted an application for waiver to the ODEQ on December 1, 2006. The ODEQ and the EPA approvals are required for any waiver; it is not known at this time whether approval will be granted. The ODEQ made a preliminary determination to accept the application for Horseshoe Lake and reject the application for Seminole. The Company is continuing to discuss the Seminole application with the ODEQ.

The Company is currently evaluating various control strategies for its generating units. Proposed compliance determinations for affected units must be submitted to the ODEQ by March 30, 2007. The ODEQ will then incorporate the Company’s, as well as other industry’s compliance plans, into the state implementation plan which will then be submitted to the EPA. Once the EPA approves the plan, the Company will have five years to institute any required reductions. The Company is in the process of determining the extent of pollution control equipment needed to comply with the regulations. The Company plans to spend approximately $5.4 million during 2007 related to the regional haze project. The Company currently estimates that it could be required to spend approximately $600 million over a five-year period to install certain equipment such as scrubbers and low nitrogen oxide (“NOX”) burners at its generating stations. However, this amount could increase or decrease substantially based on the interpretation of the requirements by the ODEQ and the EPA, the availability of alternative control measures to achieve more cost effective visibility improvements, the availability of materials, labor force and the specific design criteria for the Company’s generating units. The Company expects that any necessary environmental expenditures will qualify as part of a pre-approval plan to handle state and federally mandated environmental upgrades which will be recoverable in Oklahoma from the Company’s retail customers under House Bill 1910, which was enacted into law in May 2005.

Currently, the EPA has designated Oklahoma “in attainment” with the ambient standard for ozone. However, future elevated readings could lead to redesignation of these areas as non-attainment. Both Tulsa and Oklahoma City have entered into an “Early Action Compact” with the EPA whereby voluntary measures will be enacted to reduce ozone. This compact expires in December 2007. However, the EPA has proposed continuation through a similar program called Ozone Flex, which both Oklahoma City and Tulsa expect to participate. If either Tulsa or Oklahoma City became non-attainment, reductions in nitrogen oxides emissions from the Company’s generating facilities may be required.

On April 25, 2005, the EPA published a finding that all 50 states failed to submit the interstate pollution transport plans required by the Clean Air Act as a result of the adoption of the revised ambient ozone and fine particle standards. Failure to submit these implementation plans began a two-year timeframe, starting on May 25, 2005, during which states must submit a demonstration to the EPA that they do not affect air quality in downwind states. Earlier in 2005 it was unclear whether this could be accomplished by the state of Oklahoma and it was previously reported that there may be future significant expenditures required by the Company if Oklahoma was determined to impact the air quality in downwind states. However, recent communications with the state of Oklahoma have affirmed that they have completed the demonstration that they do not affect air quality in downwind states and are on target to submit it to the EPA by the May 25, 2007 deadline. Therefore, there should be no significant impact to the Company as a result of the April 25, 2005 finding.

On September 21, 2006, the EPA lowered the 24-hour fine particulate ambient standard while retaining the annual standard at its current 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 the Company’s coal-fired boilers could be required which may result in significant capital and operating expenditures.

The 1990 Clean Air Act includes an acid rain program to reduce sulfur dioxide (“SO2”) emissions. Reductions were obtained through a program of emission (release) allowances issued by the EPA to power plants covered by the acid rain program. Each allowance is worth one ton of SO2 released from the smokestack. Plants may only release as much SO2 as they have allowances. Allowances may be banked and traded or sold nationwide. Beginning in 2000, the Company became subject to more stringent SO2 emission requirements in Phase II of the acid rain program. These lower limits had no significant financial impact due to the Company’s earlier decision to burn low sulfur coal. In 2006, the Company’s SO2 emissions were well below the allowable limits.

The EPA allocated SO2 allowances to the Company starting in 2000 and the Company started banking allowances in 2001. In February 2006, the Company sold 6,312 allowances for approximately $8.9 million. See Note 14 for a discussion of the SO2 allowance joint filing made in February 2006 which discusses how the proceeds from the sale of SO2 allowances will be shared between the Company and its customers for any sales after December 31, 2005.

With respect to the NOX regulations of the acid rain program, the Company committed to meeting a 0.45 lbs/million British thermal unit (“MMBtu”) NOX emission level in 1997 on all coal-fired boilers. As a result, the Company was eligible to exercise its option to extend the effective date of the lower emission requirements from the year 2000 until 2008. The Company’s average NOX emissions from its coal-fired boilers for 2006 were approximately 0.33 lbs/MMBtu. The regulations require that the Company achieve a NOX emission level of 0.40 lbs/MMBtu for these boilers beginning in 2008. Further reductions in NOX emissions could be required if the ODEQ determines that such NOX emissions are contributing to regional haze or that the Company’s facilities impact the air quality of the Tulsa or Oklahoma City metropolitan areas, or if Oklahoma becomes non-attainment with the fine particulate standard. Any of these scenarios would require significant capital and operating expenditures.

The ODEQ Clean Air Act Amendment Title V permitting program was approved by the EPA in March 1996. By March of 1997, the Company had submitted all required permit applications. As of December 31, 2006, the Company had received Title V permits for all of its generating stations. Since these permits require renewal every five years, the Company has begun the renewal process for some of its generating stations. Air permit fees for generating stations were approximately $0.6 million in 2006. The fees for 2007 are estimated to be approximately the same as in 2006.

There have been a variety of unsuccessful legislative and litigation efforts to force mandatory control of utility emissions that allegedly contribute to climate change. If legislation is passed in the future requiring mandatory carbon dioxide emission reductions to address climate change, this could have a tremendous impact on all coal-fired electric utilities, including the Company’s operations by requiring the Company to significantly reduce the use of coal as a fuel source.

The Company has sought and will continue to seek, new pollution prevention opportunities and to evaluate the effectiveness of its waste reduction, reuse and recycling efforts. In 2006, the Company obtained refunds of approximately $2.0 million from its recycling efforts. 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.

The Company had one Oklahoma Pollutant Discharge Elimination System (“OPDES”) permit approved during 2006 and has one other OPDES permit renewal pending. The Company expects that this permit will be issued during the first or second quarter of 2007. The Company expects that this permit, when issued, will continue to be reasonable in its requirements, allow operational flexibility and provide reductions in operating costs. Additionally, the Company filed an application with the state of Oklahoma during 2006 for a new wastewater discharge permit for one of its facilities. The Company expects that the wastewater discharge permit for this facility will be issued in the first or second quarter of 2007.

Section 316(b) of the Clean Water Act requires that the location, design, construction and capacity of any cooling water intake structure reflect the “best available technology” for minimizing environmental impacts. The EPA 316(b) rules for existing facilities became effective July 23, 2004. The Company has engaged a consultant who has developed the required documentation for four Company facilities. These documents were submitted to the state agency on December 7, 2005 for review and approval. The Company has also provided the state of Oklahoma with information and requests that, if approved by the state, may reduce the impact of the 316(b) rules on the Company because if the Company’s position is approved, three of the four Company facilities would not be required to comply with the 316(b) rules. Depending on the ultimate analysis and final determinations regarding the 316(b) rules, capital and/or operating costs may increase at any affected Company generating facility. On January 25, 2007, a federal court reversed and remanded portions of the 316(b) rules to the EPA. The existing rules remain in effect while the EPA is considering how to respond to the court decision. It is not clear what changes, if any, the EPA will make to the rules or how those changes may affect the Company.

In the normal course of business, the Company is confronted with issues or events that may result in a contingent liability. These generally relate to lawsuits, claims made by third parties, environmental actions or the action of various regulatory agencies and income tax related items. Management consults with legal counsel and other appropriate experts to assess the claim. If, in management’s opinion, the Company has incurred a probable loss as set forth by accounting principles generally accepted in the United States, an estimate is made of the loss and the appropriate accounting entries are reflected in the Company’s Financial Statements. Except as otherwise stated above, in Note 14 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 the Company’s financial position, results of operations or cash flows.

On November 22, 2002, the OCC signed a rate order containing the provisions of the 2002 Settlement Agreement. The 2002 Settlement Agreement provided for, among other items: (i) a $25.0 million annual reduction in the electric rates of the Company’s Oklahoma customers which went into effect January 6, 2003; (ii) recovery by the Company, through rate base, of the capital expenditures associated with the January 2002 ice storm; (iii) the Company to acquire electric generation of not less than 400 MW (“New Generation”) to be integrated into the Company’s generation system; and (iv) recovery by the Company, over three years, of the $5.4 million in deferred operating costs, associated with the January 2002 ice storm, through the Company’s rider for sales to other utilities and power marketers (“off-system sales”). Previously, the Company had a 50/50 sharing mechanism in Oklahoma for any off-system sales. The 2002 Settlement Agreement provided that the first $1.8 million in annual net profits from the Company’s off-system sales will go to the Company, the next $3.6 million in annual net profits from off-system sales will go to the Company’s Oklahoma customers and any net profits from off-system sales in excess of these amounts will be credited in each sales year with 80 percent to the Company’s Oklahoma customers and the remaining 20 percent to the Company. During 2005, the Company recovered approximately $1.8 million in annual net profits from off-system sales. Including this amount, the Company has recovered a total of $5.4 million related to the regulatory asset since December 31, 2002, which is in accordance with the 2002 Settlement Agreement. During 2005, the Company also credited as required approximately $3.6 million in annual net profits from off-system sales to the Company’s Oklahoma customers and the net profits from off-system sales that exceeded the $5.4 million were shared with 80 percent to the Company’s Oklahoma customers and the remaining 20 percent to the

Company. Beginning January 1, 2006, the annual net profits from off-system sales were shared with 80 percent to the Company’s Oklahoma customers and 20 percent to the Company.

The 2002 Settlement Agreement required that, if the Company did not acquire the New Generation by December 31, 2003, the Company must credit $25.0 million annually (at a rate of 1/12 of $25.0 million per month for each month that the New Generation is not in place) to its Oklahoma customers beginning January 1, 2004 and continuing through December 31, 2006. As discussed in more detail below, in August 2003 the Company signed an agreement to purchase a 77 percent interest in the McClain Plant, but due to a delay at the FERC, the acquisition was not completed by December 31, 2003. In the interim, the Company entered into a power purchase agreement with the McClain Plant that delivered the savings guaranteed to the Company’s customers. The Company requested that the OCC confirm that the steps it had taken, including the power purchase agreement, were satisfying the customer savings obligation under the 2002 Settlement Agreement and that the Company would not be required to begin crediting its customers. On April 28, 2004, the OCC issued an order confirming that the Company was delivering savings to its customers as required under the 2002 Settlement Agreement. The order removed any uncertainty over whether the OCC believed the Company had to reduce its rates, effective January 1, 2004, while it awaited action by the FERC on its application to purchase the McClain Plant. A party to the OCC proceeding appealed the OCC’s order to the Oklahoma Supreme Court. The appeal was denied and the OCC order is considered final. The Company has filed reports with the OCC for the months of January 2004 through December 2006 supporting the savings from the McClain Plant. The Company expects to file an application with the OCC in the second quarter of 2007 supporting its compliance with the 2002 Settlement Agreement. The Company expects the OCC to issue an order by the end of 2007 in this matter.

On July 9, 2004, the Company completed the acquisition of a 77 percent interest in the McClain Plant. This transaction was intended to satisfy the requirement in the 2002 Settlement Agreement to acquire electric generation of not less than 400 MW’s.

The closing of the purchase of the McClain Plant was subject to approval from the FERC. The FERC’s July 2, 2004 approval was based on an offer of settlement in which the Company agreed to undertake the following mitigation measures: (i) install certain transmission facilities designed to result in up to 600 MW’s of available transfer capability (“ATC”) from the Redbud Energy LP (“Redbud”) facility to the Company control area; (ii) pending completion of these transmission upgrades, provide up to 600 MW’s of ATC into the Company’s control area from the Redbud plant through changes to the dispatch of the Company’s generating units; and (iii) hire an independent market monitor to oversee the Company’s activity in its control area until the SPP implements a market monitor for the SPP regional transmission organization (“RTO”). The Company completed the installation of the capital improvements and notified the FERC in writing on May 31, 2005 that these were completed. The Company’s obligation to redispatch its system to make 600 MW’s of ATC available to the Redbud power plant terminated upon completion of the transmission upgrades. On June 20, 2006, the FERC issued an order that the Company had fully satisfied all of the transmission upgrade requirements associated with the McClain Plant acquisition. Parties in this matter had 30 days to request a rehearing. No request for rehearing was filed with the FERC and the Company believes the order is final. According to both the Company’s market monitoring plan and the applicable FERC orders, the Company’s market monitoring plan was set to terminate when the SPP installed its own market monitor. Given the implementation of the SPP’s external market monitor effective December 1, 2006, the Company’s market monitoring plan effectively ended and the Company’s market monitor was dismissed on December 1, 2006. Also, on December 1, 2006, the Company notified the FERC that based on the status of the SPP’s internal and external market monitors, the McClain settlement’s market monitoring requirements had been fulfilled. On January 16, 2007, the Company’s market monitor submitted its final report addressing the period from September 30, 2006 to November 30, 2006.

The Company expects the addition of the McClain Plant, including the effects of an interim power purchase agreement the Company had with NRG McClain LLC while the Company was awaiting regulatory approval to complete the acquisition, will provide savings, over a three-year period (January 1, 2004 through December 31,

2006), in excess of $75.0 million to its Oklahoma customers. In the event the Company is unable to demonstrate at least $75.0 million in savings to its customers during this 36-month period, the Company will be required to credit its Oklahoma customers any unrealized savings below $75.0 million as determined subsequent to the end of the 36-month period. At this time, the Company believes that it achieved at least $75.0 million in savings during this period. The Company has filed reports with the OCC for the months of January 2004 through December 2006 supporting the savings from the McClain Plant. The Company expects to file an application with the OCC in the second quarter of 2007 supporting its compliance with the 2002 Settlement Agreement. The Company expects the OCC to issue an order by the end of 2007 in this matter.

On May 20, 2005, the Company filed with the OCC an application for an annual rate increase of approximately $89.1 million to recover, among other things, its investment in, and the operating expenses of, the McClain Plant. The application also included, among other things, implementation of enhanced reliability programs in the Company’s system, increased fuel oil inventory, the establishment of a separate recovery mechanism for major storm expense, the establishment of new rate classes for public schools and related facilities, the establishment of a military base rider, the establishment of a new low income assistance tariff and the proposal to make the guaranteed flat bill pilot tariff permanent for residential and small business customers.

On September 12, 2005, several parties filed responsive testimony reflecting various positions on the issues related to this case. In particular, the testimony of the OCC Staff recommended that the Company be entitled a rate increase of approximately $13.0 million, one-seventh the amount requested by the Company in its May 20, 2005 application. The recommendations in the testimony of the Attorney General’s office and the OIEC recommended a rate decrease of approximately $24 million and $31 million, respectively. Hearings in the rate case began on October 10, 2005 and concluded on October 24, 2005. On November 3, 2005, the Referee appointed by the OCC for this proceeding issued a report recommending an estimated rate increase of approximately $42 million for the Company. On December 12, 2005, the OCC issued an order providing for a $42.3 million increase in rates and a 10.75 percent return on equity, based on a capital structure consisting of 55.7 percent equity and 44.3 percent debt. The new rates became effective in January 2006 pursuant to approved tariffs filed with the OCC. Also included in the order, among other things, are new depreciation rates effective January 2006 and a provision which modified the Company’s mechanism for the recovery of over or under recovered fuel costs from its customers to allow interest to be applied to the over or under recovery. See Note 1 for a discussion of amendments to the tariffs related to Fuel Clause Over Recoveries.

As part of the rate order issued by the OCC in December 2005, the Company received OCC approval for the creation of two new rate classes, Public Schools-Demand and Public Schools Non-Demand. These two classes of service will provide the Company flexibility to provide targeted programs for load management to public schools and their unique usage patterns. Another item approved in the order was the creation of service level fuel differentiation that allows customers to pay fuel costs that better reflect operational energy losses related to a specific service level. The OCC order also approved a military base rider that demonstrates Oklahoma’s continued commitment to our military partners. The Company’s highly successful wind program was authorized to lower its cost on a per kilowatt-hour basis, which provides subscribing customers the increased incentive to hedge against future natural gas prices. The order specific also enables the Company’s low-income qualified customers to receive relief on their summer electric bills by waiving the customer charge on their monthly bills from June to September of each year. Also included in the Company’s rate case application, but not approved, was the establishment of a separate recovery mechanism for major storm expense.

As provided in the 2002 Settlement Agreement, the Company had the right to accrue a regulatory asset, for a period not to exceed 12 months subsequent to the completion of the acquisition and operation of the McClain Plant, consisting of the non-fuel operation and maintenance expenses, depreciation, cost of debt associated with the investment and ad valorem taxes. The Company completed its acquisition of the McClain Plant on July 9, 2004. Accordingly, the Company ceased accruing various operating and related costs associated with the McClain Plant as a regulatory asset on July 8, 2005. At December 31, 2005, the actual incurred expenses included in the McClain Plant regulatory asset were approximately $24.9 million. Such costs will be recovered over a four-year time period

as authorized in the OCC rate order beginning in January 2006. The OCC authorized approximately $15.5 million of the $24.9 million regulatory asset to be included in the Company’s rate base for purposes of earning a return.

As part of the 2002 Settlement Agreement, the Company also agreed to consider competitive bidding as a basis to select its provider for gas transportation service to its natural gas-fired generation facilities pursuant to the terms set forth in the 2002 Settlement Agreement. Because the required integrated service was not available in the marketplace from parties other than Enogex, the Company advised the OCC that, after careful consideration, competitive bidding for gas transportation was rejected in favor of a new intrastate integrated, firm no-notice load following gas transportation and storage services agreement with Enogex. This seven-year agreement provides for gas transportation and storage services for each of the Company’s natural gas-fired generation facilities. The Company will pay Enogex annual demand fees of approximately $46.8 million for the right to transport specified maximum daily quantities (“MDQ”) and maximum hourly quantities (“MHQ”) of gas at various minimum gas delivery pressures depending on the operational needs of the individual generating facility. In addition, the Company supplies system fuel in-kind for its pro-rata share of actual fuel and lost and unaccounted for gas on the transportation system. To the extent the Company transports gas in quantities exceeding the prescribed MDQ’s or MHQ’s, it pays an overrun service charge. During the years ended December 31, 2006, 2005 and 2004, the Company paid Enogex approximately $47.5 million, $47.6 million and $49.6 million, respectively, for gas transportation and storage services.

On July 14, 2005, the OCC issued an order in this case approving a $41.9 million annual recovery. The OCC order disallowed the recovery by the Company of the amount that Enogex charges the Company for the cost of fuel used, or otherwise unaccounted for, in providing natural gas transportation and storage service to the Company. Over the last three years, this amount has ranged from $1.0 million to $3.4 million annually. This amount was approximately $1.0 million in 2006 and is projected to be approximately $1.1 million in 2007. The OCC’s order required the Company to refund to its Oklahoma customers the difference between the amounts collected from such customers in the past based on an annual rate of $46.8 million for gas transportation and storage services and the $41.9 million annual rate authorized by the OCC’s order. Based on the order, the Company’s refund obligation was approximately $8.8 million. The Company began refunding this obligation in September 2005 through its automatic fuel adjustment clause. The obligation was fully refunded at September 30, 2006.

In connection with the Enogex gas transportation and storage agreement, the Company also recorded a refund obligation in Arkansas of approximately $1.1 million at December 31, 2005. The Company provided to the APSC the OCC evidence and above findings showing that the Arkansas refund was calculated consistently with the Oklahoma refund. The Company applied the refund obligation to its fuel clause under recoveries balance in April and customers began receiving this refund in April 2006 and will continue through March 2007.

On April 8, 2002, the Company filed a joint application with the OCC Staff requesting approval for security investments and a rider to recover these costs from the ratepayers. On October 28, 2004, all parties signed a joint stipulation that contains the OCC Staff’s recommendations and authorizes up to a $5 million annual recovery from the Company’s customers for security enhancement. On December 21, 2004, the OCC issued an order approving the stipulation which included a security rider. The Company implemented the security rider with the first billing period in July 2006 and began charging the Company’s Oklahoma customers approximately $2.4 million annually. In compliance with the OCC order, in October 2006, the Company filed a report regarding the recovery of the security costs through the authorized recovery rider for the period from July 1, 2006 to September 30, 2006. The OCC authorized tariff provides that the security rider may be updated quarterly. In December 2006, the Company updated the security rider to recover approximately $2.9 million annually beginning with the first billing cycle in January 2007. The Company also filed an application with the OCC on December 15, 2006 to amend its security plan to seek approval of approximately $7.6 million of cost increases related to the expanded scope of previously authorized projects and approximately $10.9 million for new security projects. The annual revenue requirement associated with the $18.5 million of capital expenditures is approximately $2.7 million. A procedural schedule was issued in

February 2007 in this matter with hearings scheduled to begin on May 30, 2007. The Company expects the OCC to issue an order in the third quarter of 2007 in this matter.

Competitive Bidding, Prudence Reviews and Other Rules for Electric Utility Providers

On March 10, 2005, the OCC filed Cause No. PUD 200500129 regarding “Inquiry of the Oklahoma Corporation Commission into Guidelines for Establishing Rules for Competitive Bidding and Prudence Reviews for Electric Utility Providers.” On June 10, 2005, the OCC voted to close this notice of inquiry and directed the OCC Staff to open a rulemaking to address the competitive bidding issue for electric utilities and other matters. Rules were adopted by the OCC on January 18, 2006 and became effective on April 3, 2006. The new rules: (i) establish a competitive procurement process for purchase of long-term electric generation and long-term fuel supplies; (ii) clarify existing law by requiring that a prudence review of utility fuel and generation procurement be conducted no less frequently than every two years; (iii) require a utility to submit an integrated resource plan to the OCC every three years; and (iv) establish a process in accordance with House Bill 1910 whereby a utility may seek pre-approval for recovery of costs associated with transmission upgrades, generation facility modifications caused by environmental requirements and the purchase or construction of generation facilities. The Company does not expect these rules to have a significant impact on its operations.

On February 10, 2006, the Company, the OCC Staff and AES Shady Point (“AES”) filed a joint application with the OCC to determine the treatment of proceeds received from the Company’s sale of SO2 allowances and how these proceeds will be shared between the Company and its customers for any sales after December 31, 2005. In the application, the parties proposed that AES be held harmless from any reduction in the Company’s coal costs caused by the sale of SO2 allowances and that the proceeds of such sales be shared 80 percent with the Company’s Oklahoma customers and the remaining 20 percent to the Company. A credit rider was requested to pass the proceeds from the sale of the SO2 allowances to Oklahoma customers. Any proceeds from the sale of SO2 allowances in the Arkansas and the FERC jurisdictions will flow through the Company’s automatic fuel adjustment clause. On June 5, 2006, the parties signed a settlement agreement providing that the proceeds of such sales after December 31, 2005 are to be shared 90 percent with the Company’s Oklahoma customers and the remaining 10 percent to the Company. On June 26, 2006, the OCC approved the settlement agreement, including the 90/10 sharing mechanism. During 2006, the Company recorded approximately $0.8 million in SO2 sales proceeds from sales in 2006 that are included as an increase in Operating Revenues in the Statement of Income.

Review of the Company’s Fuel Adjustment Clause for Calendar Years 2003 and 2004

The OCC routinely audits activity in the Company’s fuel adjustment clause for each calendar year. On March 18, 2005, the OCC Staff filed Cause No. PUD 200500140 regarding “Application of the Public Utility Division Director for Public Hearing to Review and Monitor the Company’s Fuel Adjustment Clause for Calendar Year 2003.” On August 25, 2005, the OCC Staff filed Cause No. PUD 200500327 regarding “Application of the Public Utility Division Director for Public Hearing to Review and Monitor the Company’s Fuel Adjustment Clause for Calendar Year 2004.” On September 27, 2005, the OCC consolidated these two proceedings into one proceeding. Oklahoma Industrial Energy Consumers, AES, Redbud and PowerSmith Cogeneration Project, L.P intervened in this proceeding. On September 21, 2006, the Company reached a settlement with the other parties in this case that required no refunds. On October 16, 2006, the OCC issued an order that approved the settlement concluding that the Company’s 2003 fuel costs were prudent and the Company’s 2004 fuel costs were appropriately calculated. Also, as part of the settlement, the Company agreed to develop minimum filing requirements for future fuel adjustment clause reviews.

On September 17, 2004, the Company filed an application and testimony with the OCC requesting a cogeneration credit rider. The requested rider reduces cogeneration charges to customers because of decreasing cogeneration payments made by the Company beginning January 2005. The cogeneration credit rider is necessary because amounts currently recovered from customers in base rates include historically higher cogeneration payments.

The Company’s cogeneration credit rider has been updated and approved by the OCC in December of each year through December 2006 and any over/under recovery of the cogeneration credit rider in the current year and prior periods has been automatically included in the next year’s rider. The Company’s current cogeneration credit rider expired December 31, 2006. The 2007 cogeneration credit rider is approximately $80.7 million and the total under recovery through 2006 was approximately $3.1 million. The Company expects to file an application with the OCC in late 2007 to request a cogeneration credit for years after 2007.

In January 2007, the Centennial wind farm in northwestern Oklahoma was fully in service. Through December 31, 2006, the Company has spent approximately $171.1 million related to the Centennial wind farm. The OCC previously had approved a settlement agreement approving the Centennial wind power contract and a recovery rider for up to $205 million in construction costs and allowance for funds used during construction. The settlement also indicated that the Company shall file for a general rate review during 2009 that will permit the OCC to issue an order no later than December 31, 2009 placing the Centennial wind farm in the Company’s rate base. On January 17, 2007, the Company sent notice to the OCC to trigger the Centennial wind farm rider for the first billing cycle in February 2007. The recovery rider is designed to recover approximately $22.6 million in the first year of operations, which amount will decline over the life of the facility. Because the wind farm rider was implemented in February 2007, the Company expects to recover approximately $20.7 million under the rider during the remaining 11 months of 2007. The Company expects the recovery rider to remain in effect through late 2009. As explained below, the recent rate order from the APSC allows for the recovery of the portion of the Centennial wind farm allocable to the Company’s customers in Arkansas.

On July 18, 2006, Energy Corp. announced plans for the Company to partner with American Electric Power’s subsidiary, Public Service Company of Oklahoma (“PSO”), and the OMPA to build a new 950 MW coal unit at the Company’s existing Sooner plant location near Red Rock, Oklahoma. The estimated $1.8 billion project is the result of PSO’s December 2005 request for proposals in which it sought bids for up to 600 MW’s of new base load generation to be available to PSO. The unit, to be called Red Rock, is expected to be one of the cleanest of its size using coal from the Powder River Basin, which is located near Gillette, Wyoming. The Company will operate the facility and expects to spend approximately $759 million in construction costs related to its 42 percent ownership percentage in the project and approximately $30 million in transmission costs for the project. PSO will own 50 percent and the OMPA will own eight percent. On December 1, 2006, the Company submitted an application to the ODEQ for an air permit for the Red Rock plant. The Company is seeking to have the air permit approved by the ODEQ by August 1, 2007. The Company expects construction to begin in 2007 and is targeting the completion of the power plant in the 2011/2012 timeframe. The Company filed an application with the OCC on January 17, 2007 asking the OCC to find that its portion of the construction costs are prudent and that a recovery mechanism should be established to recover the Company’s overall cost of capital on the investment during the construction period. The OCC rules provide that the OCC has up to 240 days to issue an order determining the Company’s pre-approval request, however the Company’s application requested that the OCC issue an order by July 20, 2007. The project is

contingent upon numerous factors, including the successful completion of contract negotiations and the necessary regulatory and environmental approvals. Under the construction, ownership and operating agreement between the Company, PSO and the OMPA, the parties could incur up to $60 million (of which approximately $25 million would be borne by the Company) prior to the receipt of acceptable regulatory approvals and permits. If such approvals and permits were not obtained and the Red Rock project was abandoned, the Company can provide no assurance that these expenditures incurred by the Company would be recoverable in future rates.

On May 29, 2006, the FERC notified the Company that it was commencing an audit to determine whether and how the Company is complying with: (i) its Open Access Transmission Tariff; (ii) requirements of its market-based rate authorization; (iii) Standards of Conduct and Open Access Same-Time Information System; and (iv) wholesale fuel adjustment clause tariff and other requirements contained in the FERC regulations. Over the past several years, the FERC has conducted numerous audits of utilities across the country to ensure regulatory compliance. The Company is currently in the process of providing information to the FERC. The Company cannot predict either the final outcome or the timing of the completion of this audit.

On January 23, 2006, the Director of the Public Utility Division of the OCC filed Cause No. PUD 200600012 regarding an application to review the OCC’s regulation of the automatic rate adjustment clauses of all public energy utilities operating in Oklahoma and subject to the OCC’s jurisdiction. A technical conference for electric utilities was held on March 17, 2006. At this time, the Company does not believe the outcome of this proceeding will significantly impact the Company.

The Company is a member of the SPP, the regional reliability organization for all or parts of Oklahoma, Arkansas, Kansas, Louisiana, New Mexico, Mississippi, Missouri and Texas. The Company participated with the SPP in the development of regional transmission tariffs and executed a Membership Agreement with the SPP to facilitate interstate transmission operations within this region in 1998. In October 2003, the SPP filed an application with the FERC seeking authority to form an RTO. In a FERC order dated October 1, 2004, the SPP was granted RTO status, subject to the SPP submitting a further compliance filing. On January 25, 2005, the FERC issued an order on compliance filing stating that the November 1, 2004 SPP compliance filing satisfied the October 1 FERC order. The approval of the SPP RTO application is not expected to significantly impact the Company’s financial results.

The regional state committee, which is comprised of commissioners of the applicable state regulatory commissions, finished its process of formulating a methodology for funding transmission expansion in the SPP control area by allocating costs of transmission expansion to the SPP members who benefit. The SPP Board of Directors adopted this plan and filed it with the FERC on February 28, 2005, Docket No. ER05-652. The FERC conditionally accepted the plan on April 21, 2005 with an effective date of May 5, 2005. The SPP made a second compliance filing on October 20, 2005 on various minor issues associated with the plan. On January 11, 2006, the FERC conditionally accepted the compliance filing, but required the SPP to make minor wording changes within 30 days. The SPP filed these minor wording changes on February 10, 2006.

The SPP filed on June 15, 2005, Docket No. ER05-1118, to create a real-time, offer-based energy imbalance service market that will require cash settlements for over or under generation. Market participants, including the Company, will be required to submit resource plans and can submit offer curves for each resource available for dispatch. In addition, the SPP may order certain dispatching of generating units and has implemented a market monitoring plan that provides a clear set of rules, the potential consequences if the rules are violated and the areas in which an independent market monitor will examine and report. On March 20, 2006, the FERC issued an order that conditionally accepted a portion of the filing and suspended and rejected other portions of the filing. After several delays, the SPP Board of Directors voted to implement the energy imbalance service market no earlier than February 1, 2007. The SPP filed a certification of readiness to the FERC on January 18, 2007 that addressed issues

raised by intervenors to the proceeding. The SPP energy imbalance service market began operations on February 1, 2007. As one condition to participation in the energy imbalance service market, the Company, as well as other balancing authorities in the SPP, were required to submit open access tariff schedules setting forth the rates, terms and conditions for the provision of emergency energy service. The Company submitted the required schedule on September 13, 2006, in Docket No. ER06-1488-000. On January 31, 2007, the FERC issued an order conditionally accepting the Company’s proposed emergency energy schedule, subject to the Company submitting, within 30 days, a compliance filing making certain revisions required by the FERC.

On August 8, 2005, the SPP filed with the FERC for approval, Docket No. ER05-1285, tariff provisions which contained, among other items, a standard definition of “transmission” to be used in the SPP RTO. The definition provides a uniform basis for application of formula rates, exercise of functional control of the transmission system, planning and expansion of the transmission system, compensation of new transmission owners and provides for a three-year period for petitioning for deviations from the bright line definition. The basic definition of transmission facilities is similar to definitions accepted for other RTO’s. On September 30, 2005, the FERC accepted the definition, with minor modification. On November 29, 2005, the SPP submitted a compliance filing consistent with the September 30 FERC directions for modification.

On August 5, 2004, the Company filed with the APSC in Docket 04-111-U an application for approval of its participation in the SPP RTO. The application was filed pursuant to the provisions of the Arkansas code, which require that no public utility shall sell, lease, rent or otherwise transfer, in any manner, control of electric transmission facilities in this state without the approval of the APSC, provided that the approval is required only to the extent the transaction is not subject to the exclusive jurisdiction of the FERC or any other federal agency. On October 12, 2004, the SPP filed with the APSC in Docket 04-137-U an application for a Certificate of Public Convenience and Necessity for the limited purpose of managing and coordinating the use of certain transmission facilities located within the state of Arkansas. The APSC consolidated these two dockets, among others, and a public hearing was held on April 4, 2006. On August 10, 2006, the APSC issued an order granting the Company, subject to certain conditions, permission to transfer functional control of its transmission facilities to the SPP. Also, in a separate order, the APSC granted the application of the SPP for a certificate of public convenience and necessity to transact business as a public utility in Arkansas due to asserting functional control of certain transmission facilities in Arkansas. The APSC, however, denied the SPP’s request for a waiver of the applicability of various provisions of state law. Also, on December 1, 2006, the APSC issued an order closing the combined dockets described above.

On December 22, 2003, the Company and OGE Energy Resources, Inc. (“OERI”) filed a triennial market power update based on the supply margin assessment test. On May 13, 2004, the FERC directed all utilities with pending three year market-based reviews to revise the generation market power portion of their three year review to address the new interim tests. The Company and OERI submitted a compliance filing to the FERC on February 7, 2005 that applied the interim tests to the Company and OERI. In the compliance filing, the Company and OERI passed the pivotal supplier screen but did not pass the market share screen in the Company control area. The Company and OERI provided an explanation as to why their failure of the market share screen in the Company control area should not be viewed as an indication that they can exercise generation market power.

On June 7, 2005, the FERC issued an order on the Company’s and OERI’s market-based rate filing. Because the Company and OERI failed the market share screen for the Company’s control area, the FERC established hearing procedures to investigate whether the Company and OERI may continue to sell power at market-based rates in the Company’s control area. The order established a rebuttable presumption that the Company and OERI have the ability to exercise market power in the Company control area. The Company and OERI were requested to provide additional information that demonstrates to the FERC that they cannot exercise market power in the first-tier markets as well. However, the order conditionally allows the Company and OERI to sell power in first-tier markets subject to the Company and OERI providing additional information that clearly shows that they pass the market share screen for the first-tier markets. The Company and OERI provided that additional information on July 7, 2005. On August 8, 2005, the Company and OERI informed the FERC that they will: (i) adopt the FERC default rate mechanism for sales of one week or less to loads that sink in the Company’s control area; and (ii) commit not to enter into any sales with a duration of between one week and one year to loads that sink in the Company’s control

area. The Company and OERI also informed the FERC that any new agreements for long-term sales (one year or longer in duration) to loads that sink in the Company’s control area will be filed with the FERC and that the Company and OERI will not make such sales under their respective market based rate tariffs. On January 20, 2006, the FERC issued a Notice of Institution of Proceeding and Refund Effective Date for the purpose of establishing the date from which any subsequent market-based sales would be subject to refund in the event the FERC concludes after investigation that the rates for such sales are not just and reasonable. The refund effective date was March 27, 2006.

On March 21, 2006, the FERC issued an order conditionally accepting the Company’s and OERI’s proposal to mitigate the presumption of market power in the Company control area. First, the FERC accepted the additional information related to first-tier markets submitted by the Company and OERI, and concluded that the Company and OERI satisfy the FERC’s generation market power standard for directly interconnected first-tier control areas. Second, the FERC directed the Company to make certain revisions to its mitigation proposal and file a cost-based rate tariff for short-term sales (one week or less) made within the Company control area. The FERC also expanded the scope of the proposed mitigation to all sales made within the Company control area (instead of only to sales sinking to load within the Company control area). On April 20, 2006, the Company submitted: (i) a compliance filing containing the specified revisions to the Company’s market-based rate tariffs and the new cost-based rate tariff; and (ii) a request for rehearing asking the FERC to reconsider its expanded mitigation directive contained in the March 21, 2006 order. On May 22, 2006, the FERC issued a tolling order that effectively provided the FERC additional time to consider the April 20, 2006 rehearing request. On July 25, 2006 and August 25, 2006, pursuant to a FERC March 20, 2006 order, the Company and OERI filed revisions to their market-based rate tariffs to allow them to sell energy imbalance service into the wholesale markets administered by the SPP at market-based rates. The FERC has not yet acted on the Company’s April 20, 2006, July 25, 2006 or August 25, 2006 filings. On February 6, 2007, the Company and OERI submitted to the FERC a change in status report notifying the FERC that the Company has placed into service its Centennial wind farm, a wind farm with a nameplate capacity rating of 120 MW. The Company and OERI explained that adding this capacity was not material to the FERC’s grant of market-based rate status to the Company and OERI. The FERC has not yet acted on this change in status filing.

On April 5, 2004, the U.S. Department of Energy issued its final report regarding the August 14, 2003 electric blackout in the eastern United States, which did not have an adverse affect on the Company’s electric system. The report recommends a number of specific changes to current statutes, rules or practices in order to improve the reliability of the infrastructure used to transmit electric power. The recommendations include the establishment of mandatory reliability standards and financial penalties for noncompliance. On April 14, 2004, the FERC issued a policy statement requiring electric utilities, including the Company, to submit a report on vegetation management practices and indicating the FERC’s intent to make North American Electric Reliability Council reliability standards mandatory. On June 17, 2004, the Company filed its report on vegetation management practices with the FERC. During 2004, the Company spent less than $0.2 million related to the implementation of blackout report recommendations. Implementation of the blackout report recommendations and the FERC policy statement could increase future transmission costs, but the extent of the increased costs is not known at this time.

In late 2006, the FERC issued final regulations, pursuant to the 2005 Energy Policy Act, governing the elimination of mandatory purchase obligations by utilities from qualified facilities under PURPA. Those regulations offer the potential for the Company as a member of the SPP to avoid new mandatory purchase obligations under certain conditions. In addition, in December 2006, Congress enacted and the President signed into law legislation extending through 2008 several energy tax credits, including the tax credit for renewable energy sources such as wind power, that otherwise would have expired in 2007. Looking ahead to 2007, Congress will likely consider several issues of interest to the Company, including proposals to create a federal mandate for utilities to generate a specified percentage of their power from renewable sources, as well as proposals to impose mandatory global climate emission controls that might limit emissions of carbon dioxide and other so-called greenhouse gases from coal based electric generation facilities.

The 2006 legislative session concluded on May 26, 2006, with no legislation being passed that had a material impact on the Company. One bill, House Bill 1386 was introduced in the 2005 session and was carried over into the 2006 session. That bill, if passed, could have an impact on the Company’s ability to compete with other utility providers. The bill proposed that utilities be able to continue to serve and expand, if so desired, in service territories in which they currently serve but which a municipality annexes. The Company believes current case law authorizes utilities to serve and expand in an area described above. House Bill 1386 would codify the Company’s belief. The bill failed to be heard in the Senate in 2006.

As discussed above, legislation was enacted in Oklahoma in the 1990’s that was to restructure the electric utility industry in that state. The implementation of the Oklahoma restructuring legislation was delayed and seems unlikely to proceed anytime in the near future. Yet, if ultimately enacted, this legislation could deregulate the Company’s electric generation assets and cause the Company to discontinue the use of SFAS No. 71 with respect to its related regulatory balances. The previously-enacted Oklahoma legislation would not affect the Company’s electric transmission and distribution assets and the Company believes that the continued use of SFAS No. 71 with respect to the related regulatory balances is appropriate. Based on a current evaluation of the various factors and conditions that are expected to impact future cost recovery, management believes that its regulatory assets, including those related to generation, are probable of future recovery.

The Energy Act, the actions of the FERC, the restructuring legislation in Oklahoma and other factors are intended to increase competition in the electric industry. The Company has taken steps in the past and intends to take appropriate steps in the future to remain a competitive supplier of electricity. While the Company is supportive of competition, it believes that all electric suppliers must be required to compete on a fair and equitable basis and the Company is advocating this position vigorously.

The following information is provided regarding the estimated fair value of the Company’s financial instruments, including derivative contracts related to the Company’s price risk management activities, as of December 31:

	2006		2005
	Carrying	Fair	Carrying	Fair
December 31 (In millions)	Amount	Value	Amount	Value
Price Risk Management Assets
Interest Rate Swap	$ 0.9	$ 0.9	$ 0.1	$ 0.1

Price Risk Management Liabilities
Interest Rate Swap	$ ---	$ ---	$ 0.1	$ 0.1

Long-Term Debt
Senior Notes	$ 707.9	$ 725.0	$ 488.6	$ 511.7
Industrial Authority Bonds	135.4	135.4	135.4	135.4
Other	---	---	220.0	220.0

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 the Company’s interest rate swap was determined primarily based on quoted market prices. The fair value of the Company’s long-term debt is based on quoted market prices.

We have audited the accompanying balance sheets and statements of capitalization of Oklahoma Gas and Electric Company as of December 31, 2006 and 2005, and the related statements of income, retained earnings, comprehensive income and cash flows for each of the three years in the period ended December 31, 2006. Our audits also included the financial statement schedule listed in the Index at Item 15. 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, 2006 and 2005, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2006, 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 herein.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of Oklahoma Gas and Electric Company’s internal control over financial reporting as of December 31, 2006, 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 14, 2007 expressed an unqualified opinion thereon.

As discussed in Notes 2, 3 and 12 to the financial statements, in 2006 the Company adopted Statement of Financial Accounting Standards No. 123 (Revised), “Share-Based Payment,” and Statement of Financial Accounting Standards No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans.”

In the opinion of the Company, the following quarterly information includes all adjustments, consisting of normal recurring adjustments, necessary to fairly present the Company’s results of operations for such periods:

Quarter ended (In millions)			Mar 31		Jun 30		Sep 30		Dec 31		Total

Operating revenues (A)	2006	$	374.0	$	444.7	$	608.7	$	318.3	$	1,745.7
	2005		301.0		394.1		612.9		412.7		1,720.7

Operating income (loss) (A)	2006	$	9.8	$	88.8	$	195.5	$	(0.2)	$	293.9
	2005		2.8		55.0		164.0		10.4		232.2

Net income (loss) (A)	2006	$	(1.1)	$	44.0	$	107.4	$	(1.0)	$	149.3
	2005		(1.7)		29.7		99.4		2.3		129.7

(A) As described above in Note 14 of the Notes to Financial Statements, the OCC, in its order dated December 12, 2005, granted the Company a $42.3 million annual increase in the rates charged by the Company to its retail customers in Oklahoma. These increased rates became effective in January 2006 pursuant to approved tariffs filed with the OCC. In January 2007, the Company determined that the approved tariffs had inadvertently authorized the Company to collect, and the Company had collected, approximately $26.7 million of additional fuel-related revenues during 2006 that was not intended by the December 12, 2005 order. As a result, the Company filed with the OCC in January 2007 amendments to its previously-authorized tariffs, in order to cease recovery of the fuel-related revenues not intended by the December 12, 2005 order. The $26.7 million, plus $1.2 million of interest, was recorded as a liability under Fuel Clause Over Recoveries on the Balance Sheet in the fourth quarter of 2006, and such amounts, along with other Fuel Clause Over Recoveries, will be credited to the Company’s Oklahoma customers in 2007 and 2008 through the Company’s automatic fuel adjustment clause. In addition, the Company recorded a reduction in operating revenues of approximately $26.7 million and an increase in interest expense of approximately $0.5 million, which resulted in an after tax reduction in net income of approximately $16.7 million in the fourth quarter of 2006. On a quarterly basis, collections of such additional amounts under the previously-authorized tariffs represented approximately $7.8 million of operating revenues ($4.8 million of net income) for the quarter ended March 31, 2006, approximately $7.7 million of operating revenues ($4.7 million of net income) for the quarter ended June 30, 2006 and approximately $5.9 million of operating revenues ($3.6 million of net income) for the quarter ended September 30, 2006.

Item 9. Changes In and Disagreements with Accountants on Accounting and Financial Disclosure.

The Company maintains a set of disclosure controls and procedures designed to ensure that information required to be disclosed by the Company 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 (“SEC”) 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 (“CEO”) and chief financial officer (“CFO”), 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 the Company’s management, including the CEO and CFO, of the effectiveness of the Company’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 CEO and CFO have concluded that the Company’s disclosure controls and procedures are effective.

No change in the Company’s internal control over financial reporting has occurred during the Company’s most recently completed fiscal quarter that has materially affected, or is reasonably likely to materially affect, the Company’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).

The management of Oklahoma Gas and Electric Company (the “Company”) is responsible for establishing and maintaining adequate internal control over financial reporting. The Company’s internal control system was designed to provide reasonable assurance to the Company’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.

The Company’s management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2006. 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, 2006, the Company’s internal control over financial reporting is effective based on those criteria.

The Company’s independent auditors have issued an attestation report on management’s assessment of the Company’s internal control over financial reporting. This report appears on the following page.

We have audited management’s assessment, included in the accompanying Management’s Report on Internal Control Over Financial Reporting, that Oklahoma Gas and Electric Company maintained effective internal control over financial reporting as of December 31, 2006, 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. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of 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, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, 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, management’s assessment that Oklahoma Gas and Electric Company maintained effective internal control over financial reporting as of December 31, 2006, is fairly stated, in all material respects, based on the COSO criteria. Also, in our opinion, Oklahoma Gas and Electric Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2006, 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, 2006 and 2005, and the related statements of income, retained earnings, comprehensive income and cash flows for each of the three years in the period ended December 31, 2006 of Oklahoma Gas and Electric Company and our report dated February 14, 2007 expressed an unqualified opinion thereon.

The Company 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 Energy Corp.’s web site address www.oge.com under the heading “Investors”, “Corporate Governance.” The code of ethics will be provided, free of charge, upon request. The Company 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. Energy Corp. will also include in its proxy statement the Audit Committee financial expert.

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 otherwise required by Items 10, 11, 12 and 13 has been omitted.

The following discussion relates to the audit fees paid by Energy Corp. to its independent auditors for the services provided to Energy Corp. and its subsidiaries, including the Company.

Total audit fees for 2006 were $2,062,819 for Energy Corp.’s 2006 financial statement audit. These fees include $705,669 for the audit of internal control over financial reporting pursuant to the requirements of Sarbanes-Oxley section 404 and $15,750 for services in support of debt and stock offerings. Total audit fees for 2005 were $2,107,307 for Energy Corp.’s 2005 financial statement audit. These fees include $775,500 for the audit of internal control over financial reporting pursuant to the requirements of Sarbanes-Oxley section 404 and $37,321 for services in support of debt and stock offerings.

The aggregate audit fees include fees billed for the audit of Energy Corp.’s annual financial statements and for the reviews of the financial statements included in Energy Corp.’s Quarterly Reports on Form 10-Q. For 2006, this amount includes estimated billings for the completion of the 2006 audit, which were rendered after year-end.

The aggregate fees billed for audit-related services for the fiscal year ended December 31, 2006 were $89,575, of which $73,575 was for employee benefit plan audits and $16,000 for other audit-related services.

The aggregate fees billed for audit-related services for the fiscal year ended December 31, 2005 were $82,500, of which $67,500 was for employee benefit plan audits and $15,000 for other audit-related services.

The aggregate fees billed for tax services for the fiscal year ended December 31, 2006 were $331,499. These fees include $239,555 for tax preparation and compliance ($74,000 for the review of federal and state tax returns and $165,555 for assistance with examinations and other return issues) and $91,944 for other tax services.

The aggregate fees billed for tax services for the fiscal year ended December 31, 2005 were $292,096. These fees include $198,758 for tax preparation and compliance ($76,732 for the review of federal and state tax returns and $122,026 for assistance with examinations and other return issues) and $93,338 for other tax services.

Rules adopted by the SEC 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. Energy Corp.’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, we 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 2006, 100% of the 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.

The following financial statements and supplementary data are included in Part II, Item 8 of this Report:

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.

		Addition
	Balance at	Charged to	Charged to		Balance at
	Beginning	Costs and	Other		End of
Description	of Period	Expenses	Accounts	Deductions	Period

		(In millions)


Year Ended December 31, 2004


Reserve for Uncollectible Accounts	$ 2.6	$ 4.8	$ ---	$ 4.7 (A)	$ 2.7


Year Ended December 31, 2005


Reserve for Uncollectible Accounts	$ 2.7	$ 3.3	$ ---	$ 3.5 (A)	$ 2.5


Year Ended December 31, 2006


Reserve for Uncollectible Accounts	$ 2.5	$ 6.8	$ ---	$ 6.0 (A)	$ 3.3

Pursuant to the requirements 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 16^th day of February, 2007.

Pursuant to the requirements of the Securities Exchange Act of 1934, as amended, this Report has been signed below by the following persons in the capacities and on the dates indicated.

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.

Oklahoma Gas and Electric Company meets the conditions set forth in General Instruction I(1) (a) and (b) of Form 10-K and is therefore filing this form with the reduced disclosure format permitted by General Instruction I(2).
OKLAHOMA GAS AND ELECTRIC COMPANY
(Exact name of registrant as specified in its charter)
Oklahoma		73-0382390
(State or other jurisdiction of		(I.R.S. Employer
incorporation or organization)		Identification No.)
321 North Harvey
P.O. Box 321
Oklahoma City, Oklahoma 73101-0321
(Address of principal executive offices)
(Zip Code)
Registrant’s telephone number, including area code: 405-553-3000
Securities registered pursuant to Section 12(b) of the Act: None
Securities registered pursuant to Section 12(g) of the Act: None

Year ended December 31	2006	2005	2004	2003	2002
Coal	$ 1.10	$ 0.98	$ 1.00	$ 0.93	$ 0.93
Natural Gas	$ 7.10	$ 8.76	$ 6.57	$ 6.46	$ 3.78
Weighted Average	$ 2.98	$ 3.21	$ 2.69	$ 2.27	$ 1.77

	Moody’s	Standard & Poor’s	Fitch’s
Company Senior Notes	A2	BBB+	AA-

	Change	Impact on Funded Status
Actual plan asset returns	+/- 5 percent	+/- $26.0 million
Discount rate	+/-0.25 percent	+/- $19.5 million
Contributions	+ $10.0 million	+ $10.0 million
Expected long-term return on plan assets	+/- 1 percent	None

Year ended December 31				12/31/06
(Dollars in millions)	2007	Thereafter	Total	Fair Value
Fixed-rate debt (A)
Principal amount	$ ---	$ 710.0	$ 710.0	$ 725.0
Weighted-average
interest rate	---	6.2 %	6.2 %	---
Variable-rate debt (B)
Principal amount	---	$ 135.4	$ 135.4	$ 135.4
Weighted-average
interest rate	---	3.6%	3.6%	---

Year ended December 31 (In millions)	2006	Increase	2005	Increase	2004	Decrease

System Sales (A)	26.4	1.5%	26.0	5.3%	24.7	(1.2)%

Year ended December 31 (In millions)	2006	2005	2004

Net income	$ 149.3	$ 129.7	$ 107.6
Other comprehensive income (loss), net of tax:
Minimum pension liability adjustment [$130.7, ($26.1) and ($17.4) pre-tax, respectively]	80.1	(16.0)	(10.7)
Deferred hedging gain [$0.9 pre-tax]	0.6	---	---
Total other comprehensive income (loss), net of tax	80.7	(16.0)	(10.7)

Total comprehensive income	$ 230.0	$ 113.7	$ 96.9

December 31 (In millions)	2006
Defined benefit pension plan:
Net loss	$ 129.9
Prior service cost	21.9
Defined benefit postretirement plans:
Net loss	60.3
Net transition obligation	15.2
Prior service cost	3.8
Total	$ 231.1

Defined benefit pension plan:
Net loss	$ 8.1
Prior service cost	4.7
Defined benefit postretirement plans:
Net loss	5.4
Net transition obligation	2.5
Prior service cost	1.5
Total	$ 22.2

Condition	Settlement	Vesting Period	SFAS No. 123(R)
			Classification

Total Shareholder Return	2/3 – Stock (A)	3-year cliff	Equity
	1/3 – Cash	3-year cliff	Liability

Earnings Per Share	2/3 – Stock (A)	3-year cliff	Equity
	1/3 – Cash	3-year cliff	Liability

	2005
Expected dividend yield	4.0%
Expected price volatility	15.8%
Risk-free interest rate	4.96%
Expected life of units (in years)	1.00
Fair value of units at 12/31/06	$ 62.62

(dollars in millions)	Number of Units	Stock Conversion Ratio (A)	Aggregate Intrinsic Value
Units Outstanding at 12/31/05	60,982	1 : 1
Granted (B)	25,845	1 : 1
Converted	(18,485)	1 : 1	$ 0.7
Forfeited	(5,038)	1 : 1
Employee migration (C)	15,233	1 : 1
Units Outstanding at 12/31/06	78,537	1 : 1	$5.8
Units Fully Vested at 12/31/06 (D)	26,755	1 : 1	$1.9

	Number of Units	Weighted-Average Grant Date Fair Value
Units Non-Vested at 12/31/05	42,497	$ 20.80
Granted (A)	25,845	$ 22.93
Vested (B)	(26,755)	$ 20.10
Forfeited	(5,038)	$ 22.31
Employee migration (C)	15,233	$ 21.40
Units Non-Vested at 12/31/06 (D)	51,782	$ 22.26

	2004
Expected dividend yield	6.27%
Expected price volatility	18.58%
Risk-free interest rate	3.77%
Expected life of options (in years)	7
Weighted-average fair value of options granted	$ 2.05

(dollars in millions)	Number of Options	Weighted-Average Exercise Price	Aggregate Intrinsic Value	Weighted-Average Remaining Contractual Term
Options Outstanding at 12/31/05	441,467	$ 23.08
Exercised	(281,375)	$ 23.24	$ 3.0
Forfeited	(2,134)	$ 19.91
Options Outstanding at 12/31/06	157,958	$ 22.83	$ 2.7	4.20 years
Options Fully Vested and Exercisable at 12/31/06	144,055	$ 22.76	$ 2.5	4.02 years

	Number of Options	Weighted-Average Grant Date Fair Value
Options Non-Vested at 12/31/05	66,410	$ 1.95
Vested	(52,507)	$ 1.92
Options Non-Vested at 12/31/06 (A)	13,903	$ 2.05

SERIES	DATE DUE	AMOUNT
3.11% - 4.05% Garfield Industrial Authority, January 1, 2025		$ 47.0
3.20% - 4.13% Muskogee Industrial Authority, January 1, 2025		32.4
3.03% - 4.06% Muskogee Industrial Authority, June 1, 2027		56.0
Total (redeemable during next 12 months)		$ 135.4

Revolving Credit Agreements and Available Cash (In millions)
			Weighted-Average
Entity	Amount Available	Amount Outstanding	Interest Rate	Maturity
Energy Corp. (A)	$ 600.0	$ ---	---	December 6, 2011 (C)
The Company (B)	400.0	---	---	December 6, 2011 (C)
	1,000.0	---	---
Cash	---	N/A	N/A	N/A
Total	$ 1,000.0	$ ---	---

December 31	2006	2005
Equity securities	64 %	59 %
Debt securities	34 %	36 %
Other	2 %	5 %
Total	100 %	100 %

Asset Class	Target Allocation	Minimum	Maximum
Domestic Equity	30 %	--- %	60 %
Domestic Mid-Cap Equity	10 %	--- %	10 %
Domestic Small-Cap Equity	10 %	--- %	10 %
International Equity	10 %	--- %	10 %
Fixed Income Domestic	38 %	30 %	70 %
Cash	2 %	--- %	5 %

Asset Class	Comparative Benchmark(s)
Fixed Income	Lehman Aggregate Index
Equity Index	S&P 500 Index
Value Equity	Russell 1000 Value Index – Short-term
	S&P 500 Index – Long-term
Growth Equity	Russell 1000 Growth Index – Short-term
	S&P 500 Index – Long-term
Mid-Cap Equity	S&P 400 Midcap Index
Small-Cap Equity	Russell 2000 Index
International Equity	Morgan Stanley Capital International Europe, Australia and Far East Index

	Before Application		After Application
December 31 (In millions)	of SFAS No. 158	Adjustments	of SFAS No. 158
Regulatory asset – SFAS 158	$ ---	$ 231.1	$ 231.1
Intangible asset – unamortized prior service cost	0.7	(0.7)	---
Prepaid benefit obligation	95.9	(95.9)	---
Total deferred charges and other assets	190.9	134.5	325.4
Accrued pension and benefit obligations:
Defined pension plan	0.3	55.2	55.5
Defined postretirement benefit plans	37.0	79.3	116.3
Total deferred credits and other liabilities	855.8	134.5	990.3

				Postretirement
	Pension Plan			Benefit Plans
Year ended December 31	2006	2005	2004	2006	2005	2004
Discount rate	5.75%	5.50%	5.75%	5.75%	5.50%	5.75%
Rate of return on plans’ assets	8.50%	8.50%	8.75%	8.50%	8.50%	8.75%
Compensation increases	4.50%	4.50%	4.50%	4.50%	4.50%	4.50%
Assumed health care cost trend:
Initial trend	N/A	N/A	N/A	9.00%	9.00%	10.00%
Ultimate trend rate	N/A	N/A	N/A	4.50%	4.50%	4.50%
Ultimate trend year	N/A	N/A	N/A	2012	2011	2010

ONE-PERCENTAGE POINT INCREASE
Year ended December 31 (In millions)	2006	2005	2004
Effect on aggregate of the service and interest cost components	$ 1.7	$ 1.4	$ 1.5
Effect on accumulated postretirement benefit obligations	23.4	21.8	19.9

ONE-PERCENTAGE POINT DECREASE
Year ended December 31 (In millions)	2006	2005	2004
Effect on aggregate of the service and interest cost components	$ 1.4	$ 1.1	$ 1.2
Effect on accumulated postretirement benefit obligations	19.3	18.0	16.4

						2012 and
Year ended December 31 (In millions)	2007	2008	2009	2010	2011	Beyond

Railcars	$ 4.0	$ 3.9	$ 3.8	$ 3.7	$ 36.6	$ ---

/s/ Steven E. Moore		/s/ Peter B. Delaney
Steven E. Moore, Chairman of the Board		Peter B. Delaney, President
and Chief Executive Officer		and Chief Operating Officer

/s/ James R. Hatfield		/s/ Scott Forbes
James R. Hatfield, Senior Vice President		Scott Forbes, Controller and
and Chief Financial Officer		Chief Accounting Officer

/s/ Steven E. Moore
Steven E. Moore
Chairman of the Board and
Chief Executive Officer

/s/ James R. Hatfield
James R. Hatfield
Senior Vice President and
Chief Financial Officer

	Year Ended	Year Ended	Year Ended	Year Ended	Year Ended
	Dec 31, 2002	Dec 31, 2003	Dec 31, 2004	Dec 31, 2005	Dec 31, 2006

Earnings:
Pre-tax income	$ 197,572,191	$ 175,604,686	$ 160,634,550	$ 182,280,019	$ 234,092,939

Add Fixed Charges	44,577,061	42,582,265	42,234,286	52,379,698	66,973,329

Subtotal	242,149,252	218,186,951	202,868,836	234,659,717	301,066,268


Subtract:
Allowance for borrowed funds used during construction	905,189	538,624	1,661,732	2,232,715	4,486,530

Total Earnings	241,244,063	217,648,327	201,207,104	232,427,002	296,579,738

Fixed Charges:
Interest on long-term debt	38,171,798	36,899,911	36,890,073	42,117,662	50,300,510
Interest on short-term debt and other interest charges	3,044,837	2,443,702	2,246,574	7,314,465	14,300,066
Calculated interest on leased property	3,360,426	3,238,652	3,097,639	2,947,571	2,372,753

Total Fixed Charges	$ 44,577,061	$ 42,582,265	$ 42,234,286	$ 52,379,698	$ 66,973,329


Ratio of Earnings to Fixed Charges	5.41	5.11	4.76	4.44	4.43