UNITED STATES |
SECURITIES AND EXCHANGE COMMISSION |
Washington, D.C. 20549 |
FORM 10-K |
(Mark One)
x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
| THE SECURITIES EXCHANGE ACT OF 1934 |
| For the fiscal year ended December 31, 2007 |
| OR |
o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
| THE SECURITIES EXCHANGE ACT OF 1934 |
| For the transition period from _____to_____ | Commission File Number: 1-1097 |
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 |
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o No x | ||
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Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act. Yes o No x | ||
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Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No o | ||
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Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. o | ||
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Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one): | ||
Large Accelerated Filer o | Accelerated Filer o | |
Non-Accelerated Filer x | Smaller reporting company o | |
(Do not check if a smaller reporting company) | ||
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Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No x | ||
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At June 29, 2007, the last business day of the registrant’s most recently completed second fiscal quarter, the aggregate market value of shares of common stock held by non-affiliates was $0. As of such date, 40,378,745 shares of common stock, par value $2.50 per share, were outstanding, all of which were held by OGE Energy Corp. | ||
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At January 31, 2008, 40,378,745 shares of common stock, par value $2.50 per share, were outstanding, all of which were held by OGE Energy Corp. There were no other shares of capital stock of the registrant outstanding at such date. | ||
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DOCUMENTS INCORPORATED BY REFERENCE | ||
None | ||
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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
FORM 10-K
FOR THE YEAR ENDED DECEMBER 31, 2007
TABLE OF CONTENTS
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Item 1. Business | 2 |
The Company | 2 |
3 | |
Regulation and Rates | 5 |
Rate Structures | 6 |
Fuel Supply and Generation | 7 |
Environmental Matters | 9 |
Finance and Construction | 11 |
12 | |
Access to Securities and Exchange Commission Filings | 12 |
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Item 1A. Risk Factors | 12 |
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Item 1B. Unresolved Staff Comments | 17 |
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Item 2. Properties | 18 |
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Item 3. Legal Proceedings | 19 |
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Item 4. Submission of Matters to a Vote of Security Holders | 21 |
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Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities |
25 |
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Item 6. Selected Financial Data | 25 |
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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations | 26 |
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Item 7A. Quantitative and Qualitative Disclosures About Market Risk | 44 |
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Item 8. Financial Statements and Supplementary Data | 46 |
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Item 9. Changes In and Disagreements with Accountants on Accounting and Financial Disclosure | 93 |
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Item 9A. Controls and Procedures | 93 |
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Item 9B. Other Information | 96 |
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Item 10. Directors, Executive Officers and Corporate Governance | 96 |
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Item 11. Executive Compensation | 96 |
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Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters |
96 |
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Item 13. Certain Relationships and Related Transactions, and Director Independence | 96 |
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Item 14. Principal Accounting Fees and Services | 96 |
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Item 15. Exhibits, Financial Statement Schedules | 97 |
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107 |
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Except for the historical statements contained herein, the matters discussed in this Annual Report on 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:
| • | general economic conditions, including the availability of credit, actions of rating agencies and their impact on capital expenditures; |
| • | Oklahoma Gas and Electric Company’s (the “Company”), a wholly-owned subsidiary of OGE Energy Corp. (“Energy Corp.”), and Energy Corp.’s ability to obtain financing on favorable terms; |
| • | prices and availability of electricity, coal and natural gas; |
| • | business conditions in the energy industry; |
| • | competitive factors including the extent and timing of the entry of additional competition in the markets served by the Company; |
| • | unusual weather; |
| • | availability and prices of raw materials for current and future construction projects; |
| • | federal or state legislation and regulatory decisions (including the approval of future regulatory filings related to the proposed acquisition of the Redbud power plant) and initiatives that affect cost and investment recovery, have an impact on rate structures or affect the speed and degree to which competition enters the Company’s markets; |
| • | environmental laws and regulations that may impact the Company’s operations; |
| • | changes in accounting standards, rules or guidelines; |
| • | the discontinuance of regulated accounting principles under Financial Accounting Standards Board Statement of Financial Accounting Standard (“SFAS”) No. 71, “Accounting for the Effects of Certain Types of Regulation”; |
| • | creditworthiness of suppliers, customers and other contractual parties; and |
| • | other risk factors listed in the reports filed by the Company with the Securities and Exchange Commission including those listed in “Item 1A. Risk Factors” and in Exhibit 99.01 to this Annual Report on Form 10-K. |
1
PART I
Introduction
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 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.
Company Strategy
Energy Corp.’s vision is to fulfill its critical role in the nation’s electric utility and natural gas midstream pipeline infrastructure and meet individual customers’ needs for energy and related services in a safe, reliable and efficient manner. 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”). Energy Corp. intends to maintain the majority of its assets in the regulated utility business complemented by its natural gas pipeline business. Energy Corp.’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 and maintenance of strong credit ratings. 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 increased investment at the utility to improve reliability and meet load growth, replace infrastructure equipment, replace aging transmission and distribution systems, provide new products and services and deploy newer technology that improves operational, financial and environmental performance. As part of this plan, the Company has taken, or has committed to take, the following actions:
| • | the Company purchased a 77 percent interest in the 520 megawatt (“MW”) natural gas-fired combined cycle NRG McClain Station (the “McClain Plant”) in July 2004; |
| • | the Company entered into an agreement in February 2006 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; |
| • | the Company announced in early 2007 a six-year construction initiative that is estimated to include up to $2.4 billion in major projects designed to expand capacity, enhance reliability and improve environmental performance. This six-year construction initiative also includes strengthening and expanding the electric transmission, distribution and substation systems and replacing aging infrastructure; |
| • | the Company announced in October 2007 its goal to increase its wind power generation over the next four years from its current 170 MWs to 770 MWs, and as part of this plan, the Company expects to issue a request for proposal (“RFP”) in the first quarter of 2008; |
| • | the Company announced in October 2007 its desire to begin building a high-capacity transmission line from Oklahoma City, Oklahoma to Woodward, Oklahoma in early to mid-2008 and then eventually to extend the line from Woodward to Guymon, Oklahoma in the Oklahoma Panhandle that would be used by the Company and others to deliver wind-generated power from western and northwestern Oklahoma to the rest of Oklahoma and other states; |
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| • | the Company has also previously committed to the Southwest Power Pool (“SPP”) to build the Oklahoma portion of the western half of the SPP “X-Plan” that includes transmission lines from Woodward to Tuco, Texas and from Woodward to Spearville, Kansas; |
| • | the Company entered into agreements in January 2008 to purchase a 51 percent ownership interest in the 1,230 MW Redbud power plant; and |
| • | with the previously announced six-year construction initiative discussed above, and including the acquisition of the Redbud power plant, the Company’s 2008 to 2013 capital expenditures are expected to be approximately $3.0 billion. |
The increase in wind power generation, the building of the transmission lines and the acquisition of the Redbud power plant are all subject to numerous regulatory and other approvals, including appropriate regulatory treatment from the OCC and, in the case of the transmission lines, the SPP. Other projects involve installing new emission-control and monitoring equipment at the Company’s existing power plants to help meet the Company’s commitment to comply with current and future environmental requirements. For additional information regarding the above items and other regulatory matters, see Note 13 of Notes to Financial Statements.
The Company furnishes retail electric service in 269 communities and their contiguous rural and suburban areas. During 2007, five other communities and two rural electric cooperatives in Oklahoma and western Arkansas purchased electricity from the Company for resale. The service area 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 88 percent of its total electric operating revenues for the year ended December 31, 2007 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 2007 was approximately 6,317 MWs on August 14, 2007. The Company’s load responsibility peak demand was approximately 6,031 MWs on August 14, 2007. As reflected in the table below and in the operating statistics that follow, there were approximately 26.4 million megawatt-hour (“MWH”) sales to the Company’s customers (“system sales”) in both 2007 and 2006 and 26.0 million MWH system sales in 2005. Variations in system sales for the three years are reflected in the following table:
| 2007 vs. 2006 |
| 2006 vs. 2005 |
| 2005 vs. 2004 | ||
Year ended December 31 (In millions) | 2007 | Increase | 2006 | Increase | 2005 | Increase | |
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System Sales (A) | 26.4 | ---% | 26.4 | 1.5% | 26.0 | 5.3% | |
(A) | Sales are in millions of MWHs. |
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.
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 13 of Notes to Financial Statements for a discussion of the potential impact on competition from federal and state legislation.
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OKLAHOMA GAS AND ELECTRIC COMPANY | |||||||||
CERTAIN OPERATING STATISTICS | |||||||||
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Year ended December 31 (In millions) |
| 2007 |
| 2006 |
| 2005 | |||
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ELECTRIC ENERGY (Millions of MWH) |
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Generation (exclusive of station use) |
| 23.8 |
| 24.6 |
| 24.8 | |||
Purchased |
| 5.2 |
| 3.9 |
| 3.3 | |||
Total generated and purchased |
| 29.0 |
| 28.5 |
| 28.1 | |||
Company use, free service and losses |
| (1.9) |
| (2.1) |
| (2.0) | |||
Electric energy sold |
| 27.1 |
| 26.4 |
| 26.1 | |||
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ELECTRIC ENERGY SOLD (Millions of MWH) |
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Residential |
| 8.7 |
| 8.7 |
| 8.5 | |||
Commercial |
| 6.3 |
| 6.2 |
| 6.0 | |||
Industrial |
| 4.2 |
| 4.4 |
| 4.5 | |||
Oilfield |
| 2.8 |
| 2.7 |
| 2.6 | |||
Street light |
| 0.1 |
| 0.1 |
| 0.1 | |||
Public authorities |
| 2.9 |
| 2.8 |
| 2.8 | |||
Sales for resale |
| 1.4 |
| 1.5 |
| 1.5 | |||
System sales |
| 26.4 |
| 26.4 |
| 26.0 | |||
Off-system sales |
| 0.7 |
| --- |
| 0.1 | |||
Total sales |
| 27.1 |
| 26.4 |
| 26.1 | |||
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ELECTRIC OPERATING REVENUES (In millions) |
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Residential | $ | 706.4 | $ | 698.8 | $ | 663.6 | |||
Commercial |
| 450.1 |
| 428.3 |
| 418.9 | |||
Industrial |
| 221.4 |
| 215.7 |
| 220.8 | |||
Oilfield |
| 140.9 |
| 129.3 |
| 134.8 | |||
Street light |
| 9.1 |
| 11.4 |
| 12.2 | |||
Public authorities |
| 172.3 |
| 159.6 |
| 160.9 | |||
Sales for resale |
| 68.8 |
| 65.4 |
| 67.7 | |||
Provision for rate refund |
| 0.1 |
| (0.9) |
| (2.0) | |||
System sales revenues |
| 1,769.1 |
| 1,707.6 |
| 1,676.9 | |||
Off-system sales revenues |
| 35.1 |
| 2.7 |
| 4.9 | |||
Other |
| 30.9 |
| 35.4 |
| 38.9 | |||
Total Electric Operating Revenues | $ | 1,835.1 | $ | 1,745.7 | $ | 1,720.7 | |||
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ACTUAL NUMBER OF ELECTRIC CUSTOMERS (At end of period) |
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Residential |
| 653,369 |
| 647,548 |
| 639,733 | |||
Commercial |
| 83,901 |
| 82,974 |
| 81,728 | |||
Industrial |
| 3,142 |
| 3,181 |
| 3,207 | |||
Oilfield |
| 6,324 |
| 6,324 |
| 6,265 | |||
Street light |
| 250 |
| 250 |
| 250 | |||
Public authorities |
| 15,196 |
| 14,519 |
| 14,265 | |||
Sales for resale |
| 52 |
| 44 |
| 45 | |||
Total |
| 762,234 |
| 754,840 |
| 745,493 | |||
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AVERAGE RESIDENTIAL CUSTOMER SALES |
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Average annual revenue | $ | 1,086.03 | $ | 1,084.31 | $ | 1,043.60 | |||
Average annual use (kilowatt-hour (“KWH”)) |
| 13,325 |
| 13,526 |
| 13,455 | |||
Average price per KWH (cents) | $ | 8.15 | $ | 8.02 | $ | 7.76 | |||
4
Regulation and Rates
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, 2007, 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 13 of Notes to Financial Statements.
Recent Regulatory Matters
Cancelled Red Rock Power Plant. On October 11, 2007, the OCC issued an order denying the Company and Public Service Company of Oklahoma’s (“PSO”) request for pre-approval of their proposed 950 MW Red Rock power plant project. The plant, which was to be built at the Company’s Sooner plant site, was to be 42 percent owned by the Company, 50 percent owned by PSO and eight percent owned by the Oklahoma Municipal Power Authority (“OMPA”). As a result, on October 11, 2007, the Company, PSO and the OMPA agreed to terminate agreements to build and operate the plant. At December 31, 2007, the Company had incurred approximately $17.5 million of capitalized costs associated with the Red Rock power plant project. In December 2007, the Company filed an application with the OCC requesting authorization to defer, and establish a method for recovery of, approximately $14.7 million of Oklahoma jurisdictional costs associated with the Red Rock power plant project that are currently reflected in Deferred Charges and Other Assets on the Company’s Balance Sheets. If the request for deferral is not approved, the deferred costs will be expensed. In February 2008, the OCC issued a procedural schedule with a hearing scheduled for May 7, 2008. The Company expects to receive an order from the OCC in this matter by the end of 2008.
OCC Order Confirming Savings / Acquisition of McClain Power Plant. The 2002 agreed-upon settlement of a Company rate case (“2002 Settlement Agreement”) required that, if the Company did not acquire electric generation of not less than 400 MW (“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. On July 9, 2004, the Company completed the acquisition of the McClain Plant that was intended to satisfy the requirement in the 2002 Settlement Agreement to acquire New Generation. On June 7, 2007, the Company filed an application with the OCC supporting its compliance with the 2002 Settlement Agreement. On November 21, 2007, the Company received an order from the OCC affirming that the acquisition of the McClain Plant provided savings to the Company’s Oklahoma customers in excess of the required $75 million over the three-year period from January 1, 2004 through December 31, 2006.
See Note 13 of Notes to Financial Statements for a discussion of certain regulatory matters including, among other things, security enhancements, review of the Company’s fuel adjustment clause, cogeneration credit rider, the Company FERC audit, national energy legislation and state legislative initiatives.
5
Regulatory Assets and Liabilities
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.
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.
At December 31, 2007 and 2006, the Company had regulatory assets of approximately $330.7 million and $319.2 million, respectively, and regulatory liabilities of approximately $148.2 million and $224.5 million, respectively. See Note 1 of Notes to Financial Statements for a further discussion.
As discussed in Note 13 of Notes to Financial Statements, legislation was enacted in the 1990’s for 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.
Rate Structures
Oklahoma
The Company’s standard tariff rates include a cost-of-service component (including an authorized return on capital) plus an automatic fuel adjustment clause mechanism that allows the Company to pass through to customers variances (either positive or negative) in the actual cost of fuel as compared to the fuel component in the Company’s most recently approved rate case.
The Company offers several alternate 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 usage 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,
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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 not determinable in future years because customers may choose to remain on existing rate options instead of volunteering for the alternative rate option choices. There was no overall material impact in 2006 associated with these rate options; however, there was an increase in other income from the GFB option in 2007. Revenue variations may occur in the future based upon changes in customers’ usage characteristics if they choose alternative rate options.
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.
Arkansas
During 2006, energy efficiency hearings were held by the APSC for all Arkansas utilities. These hearings led to new rules being approved for all Arkansas utilities in January 2007. The Company filed for seven new energy efficiency programs that were accepted and approved by the APSC in September 2007. Six of the seven programs were implemented in October 2007 and have attracted new customers, which management believes has resulted in an improved use of energy resources throughout the Company’s Arkansas jurisdiction. The revised compact fluorescent lamp and energy efficiency program is expected to be submitted in March 2008 seeking approval for immediate implementation in 2008.
Fuel Supply and Generation
During 2007, approximately 62 percent of the Company-generated energy was produced by coal-fired units, 36 percent by natural gas-fired units and two percent by wind-powered units. Of the Company’s 6,229 total MW capability reflected in the table under Item 2. Properties, approximately 3,514 MWs, or 56 percent, are from natural gas generation, approximately 2,595 MWs, or 42 percent, are from coal generation and approximately 120 MWs, or two percent, are from wind 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 and/or wind 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:
Year ended December 31 | 2007 | 2006 | 2005 | 2004 | 2003 |
Coal | $ 1.10 | $ 1.10 | $ 0.98 | $ 1.00 | $ 0.93 |
Natural Gas | $ 6.77 | $ 7.10 | $ 8.76 | $ 6.57 | $ 6.46 |
Weighted Average | $ 3.13 | $ 2.98 | $ 3.21 | $ 2.69 | $ 2.27 |
The increase in the weighted average cost of fuel in 2007 as compared to 2006 was primarily due to increased natural gas volumes. 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. 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 automatic fuel adjustment clauses that are approved by the OCC and the APSC.
Coal
All of the Company’s coal-fired units, with an aggregate capability of approximately 2,595 MWs, are designed to burn low sulfur western coal. The Company purchases coal primarily under contracts expiring in years 2010 and 2011. During 2007, the Company purchased approximately 9.6 million tons of coal from various Wyoming suppliers. The combination of all coal has a weighted average sulfur content of 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
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emission rate of 0.51 lbs. of sulfur dioxide per MMBtu, well within the limitations of the current provisions of the Federal Clean Air Act discussed in Note 12 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 12 of Notes to Financial Statements for a discussion of environmental matters which may affect the Company in the future.
Coal Shipment Disruption
In mid-2005, the Company experienced a coal shipment disruption due to successive derailments on the jointly-owned rail line serving the Southern Powder River Basin coal producers. As a result, the Company’s level of coal inventory significantly decreased. In late 2005, the rail lines were repaired and returned to normal operating conditions. At December 31, 2007, the Company had slightly more than 57 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 expects to maintain its coal inventory level at approximately 60 days.
Natural Gas
In August 2007, the Company issued an RFP for gas supply purchases for periods from November 2007 through March 2008, which accounted for approximately 15 percent of its projected 2008 natural gas requirements. The contracts resulting from this RFP are tied to various gas price market indices and will expire in 2008. Additional gas supplies to fulfill the Company’s remaining 2008 natural gas requirements will be acquired through additional RFPs in early to mid-2008, along with monthly and daily purchases, all of which are expected to be made at competitive market prices.
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, 2007, the Company had approximately 2.0 million MMBtu’s in natural gas storage that it acquired for approximately $8.6 million.
Purchased Power
In March 2007, the Company issued an RFP for capacity and/or firm energy purchases for the summer periods of 2008, 2009, and/or 2010. In November 2007, the Company signed a purchase contract with Redbud for purchases in the summer periods of 2008 and 2009. The Company submitted notice of the contract to the OCC on January 2 and 3, 2008. Interventions and protests were due within 15 days of submission of the notice. No interventions or protests were received in this matter and the Company considers this purchase contract to be final. The purchase contract will be terminated if the acquisition of Redbud by the Company, the OMPA and the GRDA is completed as discussed in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
Wind
In January 2007, the Company’s 120 MW Centennial wind farm was fully in service. The OCC authorized a recovery rider for up to $205 million in construction costs and allowance for funds used during construction. As indicated in the settlement agreement with the OCC related to the Company’s Centennial wind farm, the Company must file for a general rate review that will permit the OCC to issue an order no later than December 31, 2009. Also, during 2003, the Company entered into a 15-year contract with FPL Energy whereby the Company has access to up to 50 MWs of electricity generated at a wind farm near Woodward, Oklahoma.
On October 30, 2007, the Company announced its goal to increase its wind power generation over the next four years from its current 170 MWs to 770 MWs, and as part of this plan, the Company expects to issue an RFP in the first quarter of 2008. The Company also announced its desire to begin building a transmission line from Oklahoma City, Oklahoma to Woodward, Oklahoma in early to mid-2008 and then eventually to extend the line from Woodward to Guymon, Oklahoma in the Oklahoma Panhandle. This high-capacity transmission line would be used by the Company and others to deliver wind-generated power from western and northwestern Oklahoma to the rest of Oklahoma and other states. The increase in wind power generation would be subject to numerous regulatory and other approvals, including appropriate regulatory treatment from the OCC.
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Safety and Health Regulation
The Company is subject to a number of federal and state laws and regulations, including the federal Occupational Safety and Health Act of 1970 (“OSHA”) and comparable state statutes, whose purpose is to protect the safety and health of workers. In addition, the OSHA hazard communication standard, the U.S. Environmental Protection Agency (“EPA”) community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act and comparable state statutes require that information be maintained concerning hazardous materials used or produced in the Company’s operations and that this information be provided to employees, state and local government authorities and citizens. The Company believes that it is in material compliance with all applicable laws and regulations relating to worker safety and health.
ENVIRONMENTAL MATTERS
General
The activities of the Company are subject to stringent and complex federal, state and local laws and regulations governing environmental protection as well as the discharge of materials into the environment. These laws and regulations can restrict or impact the Company’s business activities in many ways, such as restricting the way it can handle or dispose of its wastes, requiring remedial action to mitigate pollution conditions that may be caused by its operations or that are attributable to former operators, regulating future construction activities to avoid endangered species or enjoining some or all of the operations of facilities deemed in noncompliance with permits issued pursuant to such environmental laws and regulations. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial requirements, and the issuance of orders enjoining future operations. Certain environmental statutes impose strict, joint and several liability for costs required to clean up and restore sites where substances or wastes have been disposed or otherwise released into the environment. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of substances or wastes into the environment.
The Company believes that their operations are in substantial compliance with applicable environmental laws and regulations and that compliance with existing federal, state and local environmental laws and regulations will not have a material adverse effect on their business, financial position or results of operations. Nevertheless, the trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment. As a result, there can be no assurance as to amount or timing of future expenditures for environmental compliance or remediation, and actual future expenditures may be different from the amounts currently anticipated. Moreover, the Company cannot assure that future events, such as changes in existing laws, the promulgation of new laws, or the development or discovery of new facts or conditions will not cause it to incur significant costs. Approximately $36.0 million and $120.5 million, respectively, of the Company’s capital expenditures budgeted for 2008 and 2009 are to comply with environmental laws and regulations. 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 $94.7 million during 2008 as compared to approximately $63.5 million in 2007. 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 12 of Notes to Financial Statements for a discussion of environmental matters, including the impact of existing and proposed environmental legislation and regulations.
Hazardous Waste
The Company generates hazardous wastes that are subject to the Federal Resource Conservation and Recovery Act of 1976 (“RCRA”) as well as comparable state laws, which impose detailed requirements for the handling, storage, treatment and disposal of hazardous waste. These laws impose strict “cradle to grave” requirements on generators regarding their treatment, storage and disposal of hazardous waste. The Company routinely generates small quantities of hazardous waste throughout its system that include, but are not limited to, waste paint, spent solvents, rechargeable batteries and mercury-containing lamps. These wastes are treated, stored and disposed off-site at facilities that are permitted to manage them. Occasionally, larger quantities of hazardous wastes are generated as a result of power generation-related activities and these larger quantities are managed either on-site or off-site. Nevertheless, through its waste minimization efforts, the majority of the Company’s facilities remain conditionally exempt small quantity generators of hazardous waste.
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Site Remediation
The Comprehensive Environmental Response, Compensation and Liability Act of 1980 (“CERCLA”) (also known as “Superfund”) and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons responsible for the release of hazardous substances into the environment. Such classes of persons include the current and past owners or operators of sites where a hazardous substance was released, and companies that disposed or arranged for disposal of hazardous substances at offsite locations such as landfills. CERCLA authorizes the EPA and, in some cases, third parties to take actions in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. Because the Company utilize various products and generate wastes that either are or otherwise contain CERCLA hazardous substances, the Company could be subject to joint and several, strict liability for the costs of cleaning up and restoring sites where those substances have been released to the environment, for damages to natural resources and for costs of certain health studies. At this time, it is not anticipated that any associated liability will cause any significant impact to the Company.
Air Emissions
The Company’s operations are subject to the federal Clean Air Act, as amended, and comparable state laws and regulations. These laws and regulations regulate emissions of air pollutants from various industrial sources, including electric generating units, and also impose various monitoring and reporting requirements. Such laws and regulations may require that the Company obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions or result in the increase of existing air emissions, obtain and strictly comply with air permits containing various emissions and operational limitations, or subject the Company to monetary penalties, injunctions, conditions or restrictions on operations, and potentially criminal enforcement actions. The Company likely will be required to incur certain capital expenditures in the future for air pollution control equipment and technology in connection with obtaining and maintaining operating permits and approvals for air emissions. The Company believes, however, that their operations will not be materially adversely affected by such requirements, and the requirements are not expected to be any more burdensome to the Company than to any other similarly situated companies. See Note 12 of Notes to Financial Statements for a discussion of environmental capital expenditures related to air emissions.
Water Discharges
The Company’s operations are subject to the Federal Water Pollution Control Act of 1972, as amended (“Clean Water Act”), and analogous state laws and regulations. These laws and regulations impose detailed requirements and strict controls regarding the discharge of pollutants into state and federal waters. The discharge of pollutants, including discharges resulting from a spill or leak incident, is prohibited unless authorized by a permit or other agency approval. The Clean Water Act and regulations implemented thereunder also prohibit discharges of dredged and fill material in wetlands and other waters of the United States unless authorized by an appropriately issued permit. Any unpermitted release of pollutants from the Company’s power plants, pipelines or facilities could result in administrative, civil and criminal penalties as well as significant remedial obligations.
Other Laws and Regulations
Recent scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases” and including carbon dioxide and methane, may be contributing to warming of the Earth’s atmosphere. In response to such studies, the U.S. Congress is actively considering legislation to reduce emissions of greenhouse gases. In addition, several states have declined to wait on Congress to develop and implement climate control legislation and have already taken legal measures to reduce emissions of greenhouse gases. For instance, at least nine states in the Northeast (Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New Jersey, New York and Vermont) and five states in the West (Arizona, California, New Mexico, Oregon and Washington) have passed laws, adopted regulations or undertaken regulatory initiatives to reduce the emission of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. Also, as a result of the U.S. Supreme Court’s decision on April 2, 2007 in Massachusetts, et al. v. EPA, the EPA may be required to regulate greenhouse gas emissions from mobile sources (such as cars and trucks) even if Congress does not adopt new legislation specifically addressing emissions of greenhouse gases. Other nations have already agreed to regulate emissions of greenhouse gases pursuant to the United Nations Framework Convention on Climate Change, also known as the “Kyoto Protocol,” an international treaty pursuant to which participating countries (not including the United States) have agreed to reduce their
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emissions of greenhouse gases to below 1990 levels by 2012. Passage of climate control legislation or other regulatory initiatives by Congress or various states of the U.S. as well as by foreign governmental authorities outside of the U.S., or the adoption of regulations by the EPA and analogous state or foreign governmental agencies that restrict emissions of greenhouse gases in areas in which the Company conducts business could have an adverse effect on its operations and demand for their services or products.
FINANCE AND CONSTRUCTION
Future Capital Requirements
Capital Requirements
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 cash generated from operations, 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.
Capital Expenditures
The Company’s current 2008 to 2013 construction program includes continued investment in its distribution, generation and transmission system. The Company’s current estimates of capital expenditures are approximately: 2008 - $788.5 million (approximately $434.5 million are related to the proposed acquisition of the Redbud power plant), 2009 - $393.9 million, 2010 - $449.0 million, 2011 - $438.6 million, 2012 - $455.6 million and 2013 - $438.6 million. The Company also has approximately 430 MWs 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.
On October 30, 2007, the Company announced its goal to increase its wind power generation over the next four years from its current 170 MWs to 770 MWs, and as part of this plan, the Company expects to issue an RFP in the first quarter of 2008. The Company also announced its desire to begin building a high-capacity transmission line from Oklahoma City, Oklahoma to Woodward, Oklahoma in early to mid-2008 and then eventually to extend the line from Woodward to Guymon, Oklahoma in the Oklahoma Panhandle that would be used by the Company and others to deliver wind-generated power from western and northwestern Oklahoma to the rest of Oklahoma and other states. The Company has also previously committed to the SPP to build the Oklahoma portion of the western half of the SPP “X-Plan”. The western half of the X-Plan includes transmission lines from Woodward to Tuco, Texas and from Woodward to Spearville, Kansas. The increase in wind power generation and the building of the transmission lines would be subject to numerous regulatory and other approvals, including appropriate regulatory treatment from the OCC and, in the case of the transmission lines, the SPP.
Pension and Postretirement Benefit Plans
During 2007 and 2006, Energy Corp. made contributions to its pension plan of approximately $50.0 million and $90.0 million, respectively, to help ensure that the pension plan maintains an adequate funded status, of which approximately $38.3 million and $69.4 million, respectively, were the Company’s portion. During 2008, Energy Corp. may contribute up to $50.0 million to its pension plan, of which approximately $42.6 million is expected to be the Company’s portion. 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.
Future Sources of Financing
Management expects that cash generated from operations and proceeds from 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
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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.
Issuance of New Long-Term Debt
In January 2008, the Company issued $200.0 million of 6.45% senior notes due February 1, 2038. The proceeds from the issuance were used to repay commercial paper borrowings.
Short-Term Debt
Short-term borrowings generally are used to meet working capital requirements. At December 31, 2007, the Company had no outstanding commercial paper borrowings. 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.
In December 2006, Energy Corp. and the Company amended and restated their revolving credit agreements to total in the aggregate $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. In November 2007, Energy Corp. and the Company utilized one of these one-year extensions to extend the maturity of their credit agreements to December 6, 2012. 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. See Note 10 of Notes to Financial Statements for a discussion of Energy Corp.’s and the Company’s short-term debt activity.
EMPLOYEES
The Company had 1,987 employees at December 31, 2007.
ACCESS TO SECURITIES AND EXCHANGE COMMISSION FILINGS
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, Energy Corp.’s and the Company’s annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act as soon as reasonably practicable after such material is electronically filed with or furnished to the Securities and Exchange Commission (“SEC”).
Item 1A. Risk Factors.
In the discussion of risk factors set forth below, unless the context otherwise requires, the terms “we”, “our” and “us” refer to Oklahoma Gas and Electric Company and “Energy Corp.” refers to OGE Energy Corp. In addition to the other information in this Annual Report on Form 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.
REGULATORY RISKS
Our profitability depends to a large extent on our ability to fully recover our costs from our customers and there may be changes in the regulatory environment that impair our ability to recover costs from our customers.
We are subject to comprehensive regulation by several federal and state utility regulatory agencies, which significantly influences our operating environment and our ability to fully recover our costs from utility customers. With rising fuel costs, recoverability of under recovered amounts from our customers is a significant risk. The utility commissions in the states where we operate regulate many aspects of our utility operations including siting and construction of facilities, customer service and the rates that we can charge customers. The profitability of our utility operations is
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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 our Centennial wind farm, we must file for a general rate review that will permit the OCC to issue an order no later than December 31, 2009. Also, during 2007, we incurred storm-related expenses of approximately $35.9 million for which we intend to seek recovery from our customers in our next rate case.
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 position and results of operations.
Costs of compliance with environmental laws and regulations are significant and the cost of compliance with future environmental laws and regulations may adversely affect our results of operations, financial position, or liquidity.
We are subject to extensive federal, state and local environmental statutes, rules and regulations relating to air quality, water quality, waste management, wildlife 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.
There is inherent risk of the incurrence of environmental costs and liabilities in our operations due to our handling of natural gas, air emissions related to our operations and historical industry operations and waste disposal practices. For example, an accidental release from one of our facilities could subject us to substantial liabilities arising from environmental cleanup and restoration costs, claims made by neighboring landowners and other third parties for personal injury and property damage and fines or penalties for related violations of environmental laws or regulations. We may be able to recover these costs from insurance. Moreover, the possibility exists that stricter laws, regulations or enforcement policies could significantly increase compliance costs and the cost of any remediation that may become necessary.
There also is growing concern nationally and internationally about global climate change and the contribution of emissions of greenhouse gases including, most significantly, carbon dioxide. This concern has led to increased interest in legislation at the federal level, actions at the state level, as well as litigation relating to greenhouse gas emissions, including a recent U.S. Supreme Court decision holding that the EPA has the authority to regulate carbon dioxide emissions from motor vehicles under the Clean Air Act. Increased pressure for carbon dioxide emissions reduction also is coming from investor organizations and the international community.
Oklahoma and Arkansas have not, at this time, established any mandatory programs to regulate carbon dioxide and other greenhouse gases. However, government officials in these states have declared support for state and federal action on climate change issues. We report quarterly our carbon dioxide emissions from our generating stations under the EPA’s acid
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rain program and are continuing to evaluate various options for reducing, avoiding, off-setting or sequestering our carbon dioxide emissions. If legislation or regulations are passed at the federal or state levels in the future requiring mandatory reductions of carbon dioxide and other greenhouse gases on generation facilities to address climate change, this could result in significant additional compliance costs that would affect our future financial position, results of operations and cash flows if such costs are not recovered through regulated rates. See Note 12 of Notes to Financial Statements for a further discussion.
We have incurred costs in connection with the Red Rock power plant project that has been terminated and we may not be able to fully recover those costs.
On September 10, 2007, the OCC denied our and PSO’s request for pre-approval of their proposed 950 MW Red Rock power plant project. The plant, which was to be built at our Sooner plant site, was to be 42 percent owned by us, 50 percent owned by PSO and eight percent owned by the OMPA. As a result of the denial for pre-approval, we, PSO and the OMPA agreed to terminate agreements to build and operate the plant. We filed an application with the OCC in December 2007 requesting authorization to defer, and establish a method for recovery of, approximately $14.7 million of Oklahoma jurisdictional costs associated with the Red Rock power plant project. If the request for deferral is not approved, the deferred costs will be expensed.
We may not be able to recover the costs of our substantial planned investment in capital improvements and additions.
Our business plan calls for extensive investment in capital improvements and additions, including the installation of environmental upgrades and retrofits and modernizing existing infrastructure as well as other initiatives. Significant portions of our facilities were constructed many years ago. Older generation equipment, even if maintained in accordance with good engineering practices, may require significant capital expenditures to maintain efficiency, to comply with changing environmental requirements or to provide reliable operations. We currently provide service at rates approved by one or more regulatory commissions. If these regulatory commissions do not approve adjustments to the rates we charge, we would not be able to recover the costs associated with our planned extensive investment. This could adversely affect our results of operations and financial position. While we may seek to limit the impact of any denied recovery by attempting to reduce the scope of our capital investment, there can no assurance as to the effectiveness of any such mitigation efforts, particularly with respect to previously incurred costs and commitments.
Our 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 position.
The regional power market in which we operate has changing transmission regulatory structures, which may affect the transmission assets and related revenues and expenses.
We currently own and operate transmission and generation facilities as part of a vertically integrated utility. We are a member of the SPP regional transmission organization (“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. We have participated, and continue to participate, in the SPP energy imbalance service market to aid in the optimization of our physical assets to serve our customers. We have not participated in the SPP energy imbalance service market for any speculative trading activities. The SPP purchases and sales are not allocated to individual customers. We record the hourly sales to the SPP at market rates in Operating Revenues and the hourly purchases from the SPP at market rates in Cost of Goods Sold in our Financial Statements. Our revenues, expenses, assets and liabilities may be adversely affected by changes in the organization, operation and regulation by the FERC or the SPP 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
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of assets, a loss of retail customers, lower profit margins and/or increased costs of capital. Any such restructuring could have a significant impact on our financial position, results of operations and cash flows. We cannot predict when we will be subject to changes in legislation or regulation, nor can we predict the impact of these changes on our financial position, results of operations or cash flows.
Events that are beyond our control have increased the level of public and regulatory scrutiny of our industry. Governmental and market reactions to these events may have negative impacts on our business, financial position and access to capital.
As a result of accounting irregularities at public companies in general, and energy companies in particular, and investigations by governmental authorities into energy trading activities, public companies, including those in the regulated and unregulated utility business, have been under an increased amount of public and regulatory scrutiny and suspicion. The accounting irregularities have caused regulators and legislators to review current accounting practices, financial disclosures and relationships between companies and their independent auditors. The capital markets and rating agencies also have increased their level of scrutiny. We believe that we are complying with all applicable laws and accounting standards, but it is difficult or impossible to predict or control what effect these types of events may have on our business, financial position, cash flows or access to the capital markets. It is unclear what additional laws or regulations may develop, and we cannot predict the ultimate impact of any future changes in accounting regulations or practices in general with respect to public companies, the energy industry or our operations specifically. Any new accounting standards could affect the way we are required to record revenues, expenses, assets, liabilities and equity. These changes in accounting standards could lead to negative impacts on reported earnings or decreases in assets or increases in liabilities that could, in turn, affect our results of operations and cash flows.
We are subject to substantial utility and energy regulation by governmental agencies. Compliance with current and future utility and energy regulatory requirements and procurement of necessary approvals, permits and certifications may result in significant costs to us.
We are subject to substantial regulation from federal, state and local regulatory agencies. We are required to comply with numerous laws and regulations and to obtain numerous permits, approvals and certificates from the governmental agencies that regulate various aspects of our businesses, including customer rates, service regulations, retail service territories, sales of securities, asset acquisitions and sales, accounting policies and practices and the operation of generating facilities. We believe the necessary permits, approvals and certificates have been obtained for our existing operations and that our business is conducted in accordance with applicable laws; however, we are unable to predict the impact on our operating results from future regulatory activities of these agencies.
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 our intent to comply with all applicable reliability rules and expediently correct a violation should it occur. We are subject to a NERC readiness evaluation and compliance audit every three years and cannot predict the outcome of those audits.
OPERATIONAL RISKS
Our results of operations may be impacted by disruptions beyond our control.
We are exposed to risks related to performance of contractual obligations by our suppliers. We are dependent on coal for much of our electric generating capacity. We rely on suppliers to deliver coal in accordance with short and long-term contracts. We have certain coal supply contracts in place; however, there can be no assurance that the counterparties to these agreements will fulfill their obligations to supply coal to us. The suppliers under these agreements may experience financial or technical problems that inhibit their ability to fulfill their obligations to us. In addition, the suppliers under these agreements may not be required to supply coal to us under certain circumstances, such as in the event of a natural disaster. Coal delivery may be subject to short-term interruptions or reductions due to various factors, including transportation problems, weather and availability of equipment. Failure or delay by our suppliers of coal deliveries could disrupt our ability to deliver electricity and require us to incur additional expenses to meet the needs of our customers. In addition, as agreements with our suppliers expire, we may not be able to enter into new agreements for coal delivery on equivalent terms.
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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 position and results of operations.
Terrorist attacks, and the threat of terrorist attacks, have resulted in increased costs to our business. Continued hostilities in the Middle East or other sustained military campaigns may adversely impact our financial position, results of operations and cash flows.
The long-term impact of terrorist attacks, such as the attacks that occurred on September 11, 2001, and the magnitude of the threat of future terrorist attacks on the electric utility industry in general, and on us in particular, cannot be known. Increased security measures taken by us as a precaution against possible terrorist attacks have resulted in increased costs to our business. Uncertainty surrounding continued hostilities in the Middle East or other sustained military campaigns may affect our operations in unpredictable ways, including disruptions of supplies and markets for our products, and the possibility that our infrastructure facilities could be direct targets of, or indirect casualties of, an act of terror. Changes in the insurance markets attributable to terrorist attacks may make certain types of insurance more difficult for us to obtain. Moreover, the insurance that may be available to us may be significantly more expensive than existing insurance coverage.
Weather conditions such as tornadoes, thunderstorms, ice storms, wind storms, as well as seasonal temperature variations may adversely affect our financial position, results of operations and cash flows.
Weather conditions directly influence the demand for electric power. In 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. During 2007, we incurred storm-related expenses of approximately $35.9 million for which we intend to seek recovery from our customers in our next rate case.
FINANCIAL RISKS
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 with respect to the defined benefit retirement and postretirement plans have a significant impact on our earnings and funding requirements. Based on our assumptions at December 31, 2007, 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.
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. Those assumptions are outside of our control.
In addition to the costs of our retirement plans, the costs of providing health care benefits to our employees and retirees have increased substantially in recent years. We believe that our employee benefit costs, including costs related to
16
health care plans for our employees and former employees, will continue to rise. The increasing costs and funding requirements with our defined benefit retirement plan, health care plans and other employee benefits may adversely affect our results of operations, financial position, or liquidity.
We face certain human resource risks associated with the availability of trained and qualified labor to meet our future staffing requirements.
Workforce demographic issues challenge employers nationwide and are of particular concern to the electric utility industry. The median age of utility workers is significantly higher than the national average. Over the next three years, approximately 35 percent of our current employees will be eligible to retire with full pension benefits. Failure to hire and adequately train replacement employees, including the transfer of significant internal historical knowledge and expertise to the new employees, may adversely affect our ability to manage and operate our business.
We may be able to incur substantially more indebtedness, which may increase the risks created by our indebtedness.
The terms of the indentures governing our debt securities do not fully prohibit us from incurring additional indebtedness. If we are in compliance with the financial covenants set forth in our revolving credit 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 and they now face may intensify.
Any reductions in our credit ratings could increase our financing costs and the cost of maintaining certain contractual relationships or limit our ability to obtain financing on favorable terms.
We cannot assure 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 so warrant. Our ability to access the commercial paper market could be adversely impacted by a credit ratings downgrade or major market disruption as experienced with the market turmoil in August 2007. 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 downgrade 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. Any future downgrade would also lead to higher long-term borrowing costs and, if below investment grade, would require us to post cash collateral or letters of credit.
We are exposed to the credit risk of our key customers and counterparties, and any material nonpayment or nonperformance by our key customers and counterparties could adversely affect our financial position, results of operations and cash flows.
We are exposed to credit risks in our generation and retail distribution operations. Credit risk includes the risk that customers and counterparties that owe us money or energy will breach their obligations. If such parties to these arrangements fail to perform, we may be forced to enter into alternative arrangements. In that event, our financial results could be adversely affected, and we could incur losses.
Item 1B. Unresolved Staff Comments.
| None. |
17
Item 2. Properties.
The Company owns and operates an interconnected electric generation, transmission and distribution system, located in Oklahoma and western Arkansas, which included nine generating stations with an aggregate capability of approximately 6,229 MWs at December 31, 2007. The following table sets forth information with respect to the Company’s electric generating facilities, all of which are located in Oklahoma.
|
|
|
|
|
| 2007 |
| 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 | 18.9% |
| 170.5 |
|
| 4 | 1977 | Steam-Turbine | Coal | Base Load | 62.0% |
| 510.5 |
|
| 5 | 1978 | Steam-Turbine | Coal | Base Load | 47.6% |
| 517.3 |
|
| 6 | 1984 | Steam-Turbine | Coal | Base Load | 72.6% |
| 515.0 | 1,713.3 |
|
|
|
|
|
|
|
|
|
|
Seminole | 1 | 1971 | Steam-Turbine | Gas | Base Load | 23.2% |
| 506.0 |
|
| 1GT | 1971 | Combustion-Turbine | Gas | Peaking | 0.1% | (B) | 17.0 |
|
| 2 | 1973 | Steam-Turbine | Gas | Base Load | 23.8% |
| 500.5 |
|
| 3 | 1975 | Steam-Turbine | Gas/Oil | Base Load | 31.9% |
| 519.0 | 1,542.5 |
|
|
|
|
|
|
|
|
|
|
Sooner | 1 | 1979 | Steam-Turbine | Coal | Base Load | 78.4% |
| 540.0 |
|
| 2 | 1980 | Steam-Turbine | Coal | Base Load | 59.1% |
| 512.0 | 1,052.0 |
|
|
|
|
|
|
|
|
|
|
Horseshoe | 6 | 1958 | Steam-Turbine | Gas/Oil | Base Load | 15.3% |
| 171.7 |
|
Lake | 7 | 1963 | Combined Cycle | Gas/Oil | Base Load | 16.4% |
| 209.0 |
|
| 8 | 1969 | Steam-Turbine | Gas | Base Load | 14.6% |
| 387.0 |
|
| 9 | 2000 | Combustion-Turbine | Gas | Peaking | 3.3% | (B) | 45.5 |
|
| 10 | 2000 | Combustion-Turbine | Gas | Peaking | 3.2% | (B) | 45.5 | 858.7 |
|
|
|
|
|
|
|
|
|
|
Mustang | 1 | 1950 | Steam-Turbine | Gas | Peaking | 2.1% | (B) | 54.0 |
|
| 2 | 1951 | Steam-Turbine | Gas | Peaking | 2.1% | (B) | 50.0 |
|
| 3 | 1955 | Steam-Turbine | Gas | Base Load | 19.8% |
| 113.4 |
|
| 4 | 1959 | Steam-Turbine | Gas | Base Load | 31.7% |
| 241.0 |
|
| 5A | 1971 | Combustion-Turbine | Gas/Jet Fuel | Peaking | 0.7% | (B) | 34.0 |
|
| 5B | 1971 | Combustion-Turbine | Gas/Jet Fuel | Peaking | 1.0% | (B) | 34.0 | 526.4 |
|
|
|
|
|
|
|
|
|
|
McClain (C) | 1 | 2001 | Combined Cycle | Gas | Base Load | 83.0% |
| 363.2 | 363.2 |
|
|
|
|
|
|
|
|
|
|
Woodward | 1 | 1963 | Combustion-Turbine | Gas | Peaking | 0.2% | (B) | 9.5 | 9.5 |
|
|
|
|
|
|
|
|
|
|
Enid | 1 | 1965 | Combustion-Turbine | Gas | Peaking | 0.8% |
| 11.1 |
|
| 2 | 1965 | Combustion-Turbine | Gas | Peaking | 0.3% |
| 10.5 |
|
| 3 | 1965 | Combustion-Turbine | Gas | Peaking | ---% |
| 11.5 |
|
| 4 | 1965 | Combustion-Turbine | Gas | Peaking | 0.5% |
| 10.5 | 43.6 |
Total Generating Capability (all stations, excluding winds station) | 6,109.2 |
|
|
|
|
| 2007 |
| Unit | Station |
| Year |
| Number of | Fuel | Capacity |
| Capability | Capability |
Station | Installed | Location | units | Capability | Factor (A) |
| (MW) | (MW) |
Centennial | 2007 | Woodward, OK | 80 | Wind | 33.7% |
| 1.5 | 120.0 |
Total Generating Capability (wind station) | 120.0 |
(A) 2007 Capacity Factor = 2007 Net Actual Generation / (2007 Net Maximum Capacity (Nameplate Rating in MWs) x Period Hours (8,760 Hours)).
(B) Peaking units, which are used when additional capacity is required, are also necessary to meet the SPP reserve margins.
(C) Represents the Company’s 77 percent ownership interest in the McClain Plant.
At December 31, 2007, the Company’s transmission system included: (i) 48 substations with a total capacity of approximately 9.5 million kilo Volt-Amps (“kVA”) and approximately 4,025 structure miles of lines in Oklahoma; and (ii) seven substations with a total capacity of approximately 2.5 million kVA and approximately 259 structure miles of lines in
18
Arkansas. The Company reclassified some substation assets as transmission assets that historically have been distribution assets. This was done in order to comply with the SPP’s FERC-approved transmission definition, which resulted in an increase in transmission substations and transformer capacity, as compared to 2006. The Company’s distribution system included: (i) 342 substations with a total capacity of approximately 8.6 million kVA, 23,854 structure miles of overhead lines, 1,833 miles of underground conduit and 9,756 miles of underground conductors in Oklahoma; and (ii) 36 substations with a total capacity of approximately 1.0 million kVA, 1,906 structure miles of overhead lines, 178 miles of underground conduit and 647 miles of underground conductors in Arkansas.
The Company owns approximately 140,133 square feet of office space at its executive offices at 321 North Harvey, Oklahoma City, Oklahoma 73101. In addition to its executive offices, the Company owns numerous facilities throughout its service territory that support its operations. These facilities include, but are not limited to, district offices, fleet and equipment service facilities, operation support and other properties.
During the three years ended December 31, 2007, the Company’s gross property, plant and equipment (excluding construction work in progress) additions were approximately $1.0 billion and gross retirements were approximately $187.5 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 19.0 percent of total property, plant and equipment at December 31, 2007.
Item 3. Legal Proceedings.
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. 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 12 and 13 of Notes to Financial Statements, management, after consultation with legal counsel, does not currently anticipate that liabilities arising out of these pending or threatened lawsuits, claims and contingencies will have a material adverse effect on 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. (U.S. 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. (U.S. District Court for the Eastern District of Louisiana, Case No. 97-2089; U.S. District Court for the Western District of Oklahoma, Case No. 97-1009M.). On June 15, 1999, the Company was served with the 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 Federal government, alleges: (a) 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; (b) certain provisions generally found in gas purchase contracts are improper; (c) transactions by affiliated companies are not arms-length; (d) excess processing cost deduction; and (e) 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 Federal government can intervene and take over such actions from the relator. The Department of Justice, on behalf of the Federal government, decided not to intervene in this action.
The 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 (“MDL”) 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 U.S. District Court for the District of Wyoming.
In October 2002, the court granted the Department of Justice’s motion to dismiss certain of the plaintiff’s claims and issued an order dismissing the plaintiff’s valuation claims against all defendants. Various procedural motions have been
19
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.
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 on various bases on January 8, 2007. The defendants also filed for other legal costs on December 18, 2006. A hearing on these motions was held on April 24, 2007, at which time the judge took these motions under advisement. Grynberg has also filed appeals with the Tenth Circuit Court of Appeals. In compliance with the Tenth Circuit’s June 19, 2007 scheduling order, Grynberg filed appellants’ opening brief on July 31, 2007 and the appellees’ consolidated response briefs were filed on November 21, 2007. Also, on December 5, 2007, Energy Corp. filed a notice of its intent to file a separate response brief, which Energy Corp. filed on January 11, 2008. At this time, oral arguments are preliminarily scheduled for the week of September 22, 2008. 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, et al. v. El Paso Natural Gas Co., et al. (Price I). On September 24, 1999, various subsidiaries of Energy Corp. were served with a class action petition filed in the District Court of Stevens County, Kansas by Quinque Operating Company and other named plaintiffs alleging the mismeasurement of natural gas on non-federal lands. On April 10, 2003, the court entered an order denying class certification. On May 12, 2003, the plaintiffs (now Will Price, Stixon Petroleum, Inc., Thomas F. Boles and the Cooper Clark Foundation, on behalf of themselves and other royalty interest owners) filed a motion seeking to file an amended class action petition, and the court granted the motion on July 28, 2003. In its amended petition (the “Fourth Amended Petition”), the Company and Enogex Inc. were omitted from the case but two of Energy Corp.’s subsidiary entities remained as defendants. The plaintiffs’ Fourth Amended Petition seeks class certification and alleges that approximately 60 defendants, including two of Energy Corp.s’ subsidiary entities, have improperly measured the volume of natural gas. The Fourth Amended Petition asserts theories of civil conspiracy, aiding and abetting, accounting and unjust enrichment. In their briefing on class certification, the plaintiffs seek to also allege a claim for conversion. The plaintiffs seek unspecified actual damages, attorneys’ fees, costs and pre-judgment and post-judgment interest. The plaintiffs also reserved the right to seek punitive damages.
Discovery was conducted on the class certification issues, and the parties fully briefed these same issues. A hearing on class certification issues was held April 1, 2005. In May 2006, the court heard oral argument on a motion to intervene filed by Colorado Consumers Legal Foundation, which is claiming entitlement to participate in the putative class action. The court has not yet ruled on the motion to intervene.
On July 2, 2007, the court ordered the plaintiffs and defendants to file proposed findings of facts and conclusions of law on class certification by July 31, 2007. On July 31, 2007, the two subsidiary entities of Energy Corp. filed their proposed findings of fact and conclusions of law regarding conflict of law issues and the coordinated defendants filed their proposed findings of facts and conclusions of law on class certification.
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. Franchise Fee Lawsuit. 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. In January 2007, the Oklahoma Supreme Court “arrested” the District Court action until, and if, the propriety of the complaint of billing practices is determined by the OCC. The plaintiffs have not filed any action with the OCC to date. The Company believes that this case is without merit.
20
4. Patent Infringement Lawsuit. In Ronald A. Katz Technology Licensing, L.P. v. OGE Energy Corp., et al. (U.S. District Court for the Western District of Oklahoma, (Civil Action No. 5:07-CV-00650-C)), Ronald A. Katz Technology Licensing, L.P. (“RAKTL”) sued Energy Corp. and the Company on June 7, 2007 for patent infringement. RAKTL alleges that the Company, by operating automated telephone systems that allow the Company’s customers to access account information, sign-up for new service, transfer service, arrange for an installment payment plan, make a payment on an account, request a duplicate bill, report an electricity outage, and perform various other functions, has infringed 13 of RAKTL’s patents and continues to infringe four of RAKTL’s patents. RAKTL seeks unspecified damages resulting from the Company’s alleged infringement, including treble damages, as well as a permanent injunction enjoining the Company from continuing the alleged infringement. RAKTL has previously filed similar actions against numerous companies and these previously filed cases have been consolidated pursuant to MDL proceedings in the U.S. District Court for the Central District of California. The Judicial Panel on MDL issued a conditional transfer order on June 20, 2007, consolidating this case with the currently pending MDL proceedings, In re Katz Interactive Call Processing Patent Litigation Case No. MDL-1816. On September 12, 2007, RAKTL filed its reply to the counterclaims of the Company defendants in the Central District of California. An initial conference was held on October 30, 2007. While the Company cannot predict the outcome of this lawsuit at this time, the Company intends to vigorously defend this case and believes that its ultimate resolution will not be material to the Company’s financial position or results of operations.
Item 4. Submission of Matters to a Vote of Security Holders.
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.
21
Executive Officers of the Registrant.
The following persons were Executive Officers of the Registrant as of February 28, 2008:
Name |
| Age |
| Title |
|
|
|
|
|
Peter B. Delaney |
| 54 |
| Chairman of the Board, President and Chief Executive Officer |
|
|
|
|
|
Danny P. Harris |
| 52 |
| Senior Vice President and Chief Operating Officer |
|
|
|
|
|
James R. Hatfield |
| 50 |
| Senior Vice President and Chief Financial Officer |
|
|
|
|
|
Carla D. Brockman |
| 48 |
| Vice President - Administration / Corporate Secretary |
|
|
|
|
|
Gary D. Huneryager |
| 57 |
| Vice President - Internal Audits |
|
|
|
|
|
S. Craig Johnston |
| 47 |
| Vice President - Strategic Planning and Marketing |
|
|
|
|
|
Jesse B. Langston |
| 45 |
| Vice President - Utility Commercial Operations |
|
|
|
|
|
Cary W. Martin |
| 55 |
| Vice President - Human Resources |
|
|
|
|
|
Howard W. Motley |
| 59 |
| Vice President - Regulatory Affairs |
|
|
|
|
|
Reid V. Nuttall |
| 50 |
| Vice President - Enterprise Information and Performance |
|
|
|
|
|
Melvin H. Perkins, Jr. |
| 59 |
| Vice President - Power Delivery |
|
|
|
|
|
Paul L. Renfrow |
| 51 |
| Vice President - Public Affairs |
|
|
|
|
|
John Wendling Jr. |
| 51 |
| Vice President - Power Supply |
|
|
|
|
|
Deborah S. Fleming |
| 52 |
| Vice President - Treasurer |
|
|
|
|
|
Scott Forbes |
| 50 |
| Controller and Chief Accounting Officer |
|
|
|
|
|
Jerry A. Peace |
| 45 |
| Chief Risk Officer |
|
|
|
|
|
John D. Rhea |
| 39 |
| Assistant Corporate Secretary and Corporate Compliance Officer |
No family relationship exists between any of the Executive Officers of the Registrant. Messrs. Delaney, Harris, Hatfield, Huneryager, Johnston, Martin, Nuttall, Renfrow, Forbes, Peace and Rhea and 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 of Energy Corp., currently scheduled for May 22, 2008.
22
The business experience of each of the Executive Officers of the Registrant for the past five years is as follows:
Name |
| Business Experience | ||
|
|
|
|
|
Peter B. Delaney |
| 2007 – Present: |
| Chairman of the Board, President and Chief Executive Officer |
|
|
|
| of Energy Corp. and the Company |
|
| 2007: |
| 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 |
|
| 2003 – 2004: |
| Executive Vice President, Finance and Strategic Planning – |
|
|
|
| Energy Corp. and Chief Executive Officer – Enogex Inc. |
|
| 2003 – Present: |
| Chief Executive Officer – Enogex Inc. |
|
| 2003 – 2005: |
| President – Enogex Inc. |
|
|
|
|
|
Danny P. Harris |
| 2007 – Present: |
| Senior Vice President and Chief Operating Officer of Energy |
|
|
|
| Corp. and the Company and President – Enogex Inc. |
|
| 2005 – 2007: |
| Senior Vice President – Energy Corp. and President and |
|
|
|
| Chief Operating Officer – Enogex Inc. |
|
| 2003 – 2005: |
| Vice President and Chief Operating Officer – Enogex Inc. |
|
|
|
|
|
James R. Hatfield |
| 2003 – 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 |
|
| 2003 – 2005: |
| Corporate Secretary of Energy Corp. and the Company |
|
|
|
|
|
Gary D. Huneryager |
| 2005 – Present: |
| Vice President – Internal Audits of Energy Corp. and the |
|
|
|
| Company |
|
| 2003 – 2005: |
| Internal Audit Officer of Energy Corp. and the Company |
|
|
|
|
|
S. Craig Johnston |
| 2007 – Present: |
| Vice President – Strategic Planning and Marketing of Energy |
|
|
|
| Corp. and the Company |
|
| 2004 – 2007: |
| Senior Vice President – Worldwide Oil & Gas Markets – Air |
|
|
|
| Liquide (industrial gases company) |
|
| 2003 – 2004: |
| Manager – Strategy & Business Optimization – ConocoPhillips |
|
|
|
| (international oil company) |
|
|
|
|
|
Jesse B. Langston |
| 2006 – Present: |
| Vice President – Utility Commercial Operations of the Company |
|
| 2005 – 2006: |
| Director – Utility Commercial Operations of the Company |
|
| 2004 – 2005: |
| Director – Corporate Planning of the Company |
|
| 2003: |
| Manager – Corporate Planning of the Company |
|
|
|
|
|
Cary W. Martin |
| 2006 – Present: |
| Vice President – Human Resources of Energy Corp. and the |
|
|
|
| Company |
|
| 2005 – 2006: |
| Vice President – Global Human Resources – SPX Corporation |
|
| 2004 – 2005: |
| Vice President – Human Resources, Technical and Industrial |
|
|
|
| Systems – SPX Corporation |
|
| 2003 – 2004: |
| Vice President – Human Resources, Communication and |
|
|
|
| Technology Systems – SPX Corporation (global industrial |
|
|
|
| manufacturer) |
|
|
|
|
|
Howard W. Motley |
| 2006 – Present: |
| Vice President – Regulatory Affairs of the Company |
|
| 2004 – 2006: |
| Director – Regulatory Affairs and Strategy of the Company |
|
| 2003 – 2004: |
| Director – Regulatory Strategies and Utility Resources of the |
|
|
|
| Company |
|
| 2002 – 2003: |
| Manager – Regulatory Strategies and Utility Resources of the |
|
|
|
| Company |
23
Name |
| Business Experience | ||
|
|
|
|
|
Reid V. Nuttall |
| 2006 – Present: |
| Vice President – Enterprise Information and Performance of |
|
|
|
| Energy Corp. and the Company |
|
| 2005 – 2006: |
| Vice President – Enterprise Architecture – National Oilwell |
|
|
|
| Varco (oil and gas equipment company) |
|
| 2003 – 2005: |
| Chief Information Officer, Vice President – Information |
|
|
|
| Technology – Varco International (oil and gas equipment |
|
|
|
| company) |
|
|
|
|
|
Melvin H. Perkins, Jr. |
| 2007 – Present: |
| Vice President – Power Delivery of the Company |
|
| 2004 – 2007: |
| Vice President – Transmission of the Company |
|
| 2003: |
| Director – Transmission Policy of the Company |
|
|
|
|
|
Paul L. Renfrow |
| 2005 – Present: |
| Vice President – Public Affairs of Energy Corp. and the Company |
|
| 2003 – 2005: |
| Director – Public Affairs of Energy Corp. and the Company |
|
|
|
|
|
John Wendling, Jr. |
| 2007 – Present: |
| Vice President – Power Supply of the Company |
|
| 2005 – 2007: |
| Director, Power Plant Operations of the Company |
|
| 2004 – 2005: |
| Plant Manager, Sooner Power Plant of the Company |
|
| 2003 – 2004: |
| Plant Manager, Horseshoe Lake/Mustang Power Plants of the |
|
|
|
| Company |
|
|
|
|
|
Deborah S. Fleming |
| 2005 – Present: |
| Vice President – Treasurer of the Company |
|
| 2003 – Present: |
| Treasurer of Energy Corp. and the Company |
|
| 2003: |
| Assistant Treasurer – Williams Cos. Inc. (energy company) |
|
|
|
|
|
Scott Forbes |
| 2005 – Present: |
| Controller and Chief Accounting Officer of Energy Corp. and |
|
|
|
| the Company |
|
| 2003 – 2005: |
| Chief Financial Officer – First Choice Power (retail electric |
|
|
|
| provider) |
|
| 2003 – 2005: |
| Senior Vice President and Chief Financial Officer – Texas |
|
|
|
| New Mexico Power Company (electric utility) |
|
|
|
|
|
Jerry A. Peace |
| 2008 – Present: |
| Chief Risk Officer of Energy Corp. and the Company |
|
| 2004 – 2008: |
| Chief Risk Officer and Compliance Officer of Energy |
|
|
|
| Corp. and the Company |
|
| 2003 – 2004: |
| Chief Risk Officer of Energy Corp. and the Company |
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John D. Rhea |
| 2007 – Present: |
| Assistant Corporate Secretary and Corporate Compliance Officer |
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| of Energy Corp. and the Company |
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| 2006 – 2007: |
| Assistant General Counsel and Director of Corporate Compliance – |
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| El Paso Electric Company |
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| 2005 – 2006: |
| Assistant General Counsel and Director of Corporate Compliance – |
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| and Risk Management – El Paso Electric Company |
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| 2003 – 2005: |
| Assistant General Counsel and Director of Corporate Compliance – |
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| El Paso Electric Company (electric utility) |
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PART II
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 2007, 2006 and 2005, the Company declared dividends of approximately $56.0 million, $24.0 million and $60.0 million, respectively, to Energy Corp.
Item 6. Selected Financial Data.
HISTORICAL DATA
Year ended December 31 | 2007 | 2006 (A) | 2005 | 2004 | 2003 |
SELECTED FINANCIAL DATA |
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(In millions) |
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Results of Operations Data: |
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Operating revenues | $ 1,835.1 | $ 1,745.7 | $ 1,720.7 | $ 1,578.1 | $ 1,517.1 |
Cost of goods sold | 1,025.1 | 950.0 | 994.2 | 914.2 | 837.3 |
Gross margin on revenues | 810.0 | 795.7 | 726.5 | 663.9 | 679.8 |
Other operating expenses | 518.0 | 501.8 | 494.3 | 471.6 | 463.5 |
Operating income | 292.0 | 293.9 | 232.2 | 192.3 | 216.3 |
Interest income | --- | 1.9 | 2.6 | 2.7 | 0.7 |
Allowance for equity funds used during |
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construction | --- | 4.1 | --- | 0.9 | --- |
Other income (loss) | 5.0 | 4.0 | (2.8) | 4.5 | 0.4 |
Other expense | 7.2 | 9.7 | 2.5 | 2.3 | 3.0 |
Interest expense | 54.9 | 60.1 | 47.2 | 37.5 | 38.8 |
Income tax expense | 73.2 | 84.8 | 52.6 | 53.0 | 60.2 |
Net income | $ 161.7 | $ 149.3 | $ 129.7 | $ 107.6 | $ 115.4 |
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Balance Sheet Data (at period end): |
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Property, plant, and equipment, net | $ 3,233.6 | $ 2,979.1 | $ 2,670.2 | $ 2,548.6 | $ 2,264.1 |
Total assets | $ 3,874.9 | $ 3,589.7 | $ 3,255.0 | $ 3,057.7 | $ 2,737.5 |
Long-term debt | $ 843.4 | $ 843.3 | $ 844.0 | $ 847.2 | $ 707.2 |
Total stockholder’s equity | $ 1,423.3 | $ 1,322.0 | $ 1,116.0 | $ 1,062.3 | $ 919.9 |
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CAPITALIZATION RATIOS (B) |
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Stockholder’s equity | 62.8% | 61.1% | 56.9% | 55.6% | 56.5% |
Long-term debt | 37.2% | 38.9% | 43.1% | 44.4% | 43.5% |
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RATIO OF EARNINGS TO |
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FIXED CHARGES (C) |
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Ratio of earnings to fixed charges | 4.78 | 4.43 | 4.44 | 4.76 | 5.11 |
(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 (excluding interest related to Financial Accounting Standards Board Interpretation No. 48 liabilities) plus fixed charges, less
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allowance for borrowed funds used during construction; and (2) fixed charges consist of interest on long-term debt (excluding interest related to FIN 48 liabilities), 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.
Introduction
Oklahoma Gas and Electric Company (the “Company”) generates, transmits, distributes and sells electric energy in Oklahoma and western Arkansas. The Company’s operations are 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.
Executive Overview
Strategy
Energy Corp.’s vision is to fulfill its critical role in the nation’s electric utility and natural gas midstream pipeline infrastructure and meet individual customers’ needs for energy and related services in a safe, reliable and efficient manner. 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”). Energy Corp. intends to maintain the majority of its assets in the regulated utility business complemented by its natural gas pipeline business. Energy Corp.’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 and maintenance of strong credit ratings. 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 increased investment at the utility to improve reliability and meet load growth, replace infrastructure equipment, replace aging transmission and distribution systems, provide new products and services and deploy newer technology that improves operational, financial and environmental performance. As part of this plan, the Company has taken, or has committed to take, the following actions:
| • | the Company purchased a 77 percent interest in the 520 megawatt (“MW”) natural gas-fired combined cycle NRG McClain Station (the “McClain Plant”) in July 2004; |
| • | the Company entered into an agreement in February 2006 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; |
| • | the Company announced in early 2007 a six-year construction initiative that is estimated to include up to $2.4 billion in major projects designed to expand capacity, enhance reliability and improve environmental performance. This six-year construction initiative also includes strengthening and expanding the electric transmission, distribution and substation systems and replacing aging infrastructure; |
| • | the Company announced in October 2007 its goal to increase its wind power generation over the next four years from its current 170 MWs to 770 MWs, and as part of this plan, the Company expects to issue a request for proposal in the first quarter of 2008; |
| • | the Company announced in October 2007 its desire to begin building a high-capacity transmission line from Oklahoma City, Oklahoma to Woodward, Oklahoma in early to mid-2008 and then eventually to extend the line from Woodward to Guymon, Oklahoma in the Oklahoma Panhandle that would be used by the Company and others to deliver wind-generated power from western and northwestern Oklahoma to the rest of Oklahoma and other states; |
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| • | the Company has also previously committed to the Southwest Power Pool (“SPP”) to build the Oklahoma portion of the western half of the SPP “X-Plan” that includes transmission lines from Woodward to Tuco, Texas and from Woodward to Spearville, Kansas; |
| • | the Company entered into agreements in January 2008 to purchase a 51 percent ownership interest in the 1,230 MW Redbud power plant; and |
| • | with the previously announced six-year construction initiative discussed above, and including the acquisition of the Redbud power plant, the Company’s 2008 to 2013 capital expenditures are expected to be approximately $3.0 billion. |
The increase in wind power generation, the building of the transmission lines and the acquisition of the Redbud power plant are all subject to numerous regulatory and other approvals, including appropriate regulatory treatment from the OCC and, in the case of the transmission lines, the SPP. Other projects involve installing new emission-control and monitoring equipment at the Company’s existing power plants to help meet the Company’s commitment to comply with current and future environmental requirements. For additional information regarding the above items and other regulatory matters, see Note 13 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. Also, Energy Corp. believes that many of the risk management practices, commercial skills and market information available from OGE Energy Resources, Inc. (“OERI”) provide value to all of Energy Corp.’s businesses.
Summary of Operating Results
2007 compared to 2006. The Company reported net income of approximately $161.7 million and $149.3 million, respectively, for the years ended December 31, 2007 and 2006, an increase of approximately $12.4 million. The increase was primarily due to a higher gross margin from higher rates from the Centennial wind farm rider, security rider and Arkansas rate case, increased peak demand and related revenues by non-residential customers in the Company’s service territory and new customer growth in the Company’s service territory partially offset by cooler weather in the Company’s service territory. Also contributing to the increase in net income was lower interest expense and lower income tax expense partially offset by higher depreciation expense.
2006 compared to 2005. The Company reported net income of approximately $149.3 million and $129.7 million, respectively, for the years ended December 31, 2006 and 2005, an increase of approximately $19.6 million. The increase was primarily from a price variance primarily due to rate increases and new customer growth and increased usage in the Company’s service territory. These increases were partially offset by higher operation and maintenance expenses, higher interest expense and higher income tax expense.
Recent Developments and Regulatory Matters
Proposed Acquisition of Power Plant
On January 21, 2008, the Company entered into a Purchase and Sale Agreement (“Purchase and Sale Agreement”) with Redbud Energy I, LLC, Redbud Energy II, LLC and Redbud Energy III, LLC (“Redbud Sellers”), which are indirectly owned by Kelson Holdings LLC, a subsidiary of Harbinger Capital Partners Master Fund I, Ltd. and Harbinger Capital Partners Special Situations Fund, L.P. Pursuant to the Purchase and Sale Agreement, the Company agreed to acquire from the Redbud Sellers the entire partnership interest in Redbud Energy LP which currently owns a 1,230 MW natural gas-fired, combined-cycle power generation facility in Luther, Oklahoma (“Redbud Facility”), for approximately $852 million, subject to working capital and inventory adjustments in accordance with the terms of the Purchase and Sale Agreement.
In connection with the Purchase and Sale Agreement, the Company also entered into (i) an Asset Purchase Agreement (“Asset Purchase Agreement”) with the Oklahoma Municipal Power Authority (“OMPA”) and the Grand River Dam Authority (“GRDA”), pursuant to which the Company agreed that it would, after the closing of the transaction contemplated by the Purchase and Sale Agreement, dissolve Redbud Energy LP and sell a 13 percent undivided interest in the Redbud Facility to the OMPA and sell a 36 percent undivided interest in the Redbud Facility to the GRDA, and (ii) an Ownership and Operating Agreement (“Ownership and Operating Agreement”) with the OMPA and the GRDA, pursuant to
27
which the Company, the OMPA and the GRDA, following the completion of the transaction contemplated by the Asset Purchase Agreement, would jointly own the Redbud Facility and the Company will act as the operations manager and perform the day-to-day operation and maintenance of the Redbud Facility. Under the Ownership and Operating Agreement, each of the parties would be entitled to its pro rata share, which is equal to its respective ownership interest, of all output of the Redbud Facility and would pay its pro rata share of all costs of operating and maintaining the Redbud Facility, including its pro rata share of the operations manager’s general and administrative overhead allocated to the Redbud Facility.
The transactions described above are subject to the expiration or termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act, an order from the FERC authorizing the contemplated transactions, an order from the OCC approving the prudence of the transactions and an appropriate reasonable recovery mechanism, and other customary conditions. The Company will not be obligated to complete the transactions if the orders from the FERC and the OCC contain any conditions or restrictions which are materially more burdensome than those proposed in the Company’s applications. Either the Company or the Redbud Sellers may terminate the Purchase and Sale Agreement if the closing has not occurred on or prior to November 16, 2008; provided that the Redbud Sellers have the option to extend such deadline for up to an additional 180 days if the sole reason the closing has not occurred is because the governmental and regulatory approvals have not been obtained. There can be no assurances that the transactions will be completed or as to its ultimate timing. The Company expects to file an application with the OCC in March 2008 asking the OCC to approve the prudency of the transactions and an appropriate reasonable recovery mechanism. The OCC rules provide that the OCC has up to 240 days to issue an order determining the Company’s pre-approval request. Absent a settlement, the earliest the Company expects an order from the OCC is November 2008.
Cancelled Red Rock Power Plant
On October 11, 2007, the OCC issued an order denying the Company and Public Service Company of Oklahoma’s (“PSO”) request for pre-approval of their proposed 950 MW Red Rock power plant project. The plant, which was to be built at the Company’s Sooner plant site, was to be 42 percent owned by the Company, 50 percent owned by PSO and eight percent owned by the OMPA. As a result, on October 11, 2007, the Company, PSO and the OMPA agreed to terminate agreements to build and operate the plant. At December 31, 2007, the Company had incurred approximately $17.5 million of capitalized costs associated with the Red Rock power plant project. In December 2007, the Company filed an application with the OCC requesting authorization to defer, and establish a method for recovery of, approximately $14.7 million of, Oklahoma jurisdictional costs associated with the Red Rock power plant project that are currently reflected in Deferred Charges and Other Assets on the Company’s Balance Sheets. If the request for deferral is not approved, the deferred costs will be expensed. In February 2008, the OCC issued a procedural schedule with a hearing scheduled for May 7, 2008. The Company expects to receive an order from the OCC in this matter by the end of 2008.
OCC Order Confirming Savings / Acquisition of McClain Power Plant
The 2002 agreed-upon settlement of a Company rate case (“2002 Settlement Agreement”) required that, if the Company did not acquire electric generation of not less than 400 MW (“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. On July 9, 2004, the Company completed the acquisition of the McClain Plant that was intended to satisfy the requirement in the 2002 Settlement Agreement to acquire New Generation. On June 7, 2007, the Company filed an application with the OCC supporting its compliance with the 2002 Settlement Agreement. On November 21, 2007, the Company received an order from the OCC affirming that the acquisition of the McClain Plant provided savings to the Company’s Oklahoma customers in excess of the required $75 million over the three-year period from January 1, 2004 through December 31, 2006.
2008 Outlook
Energy Corp.’s earnings guidance for 2008 is between $223 million and $242 million of net income or $2.40 to $2.60 per diluted share assuming approximately 93.1 million average diluted shares outstanding, cash flow from operations of between $483 million and $502 million and an effective tax rate of 33.5 percent.
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Key assumptions for 2008 are:
As shown above, the Company’s earnings guidance for 2008 is between $145 million to $155 million. Key factors and assumptions underlying this guidance include:
| • | Normal weather patterns are experienced for the remainder of the year; |
| • | Gross margin on weather-adjusted, retail electric sales increases approximately two percent; |
| • | Operating expenses of approximately $536 million; |
| • | Interest costs of approximately $77 million; |
| • | An effective tax rate of approximately 31.1 percent; and |
| • | Capital expenditures for investment in the Company’s generation, transmission and distribution system of approximately $789 million in 2008, which includes capital expenditures in the amount of approximately $435 million associated with the Company’s planned acquisition of the Redbud generating plant. |
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.
Results of Operations
The following discussion and analysis presents factors that affected the Company’s results of operations for the years ended December 31, 2007, 2006 and 2005 and the Company’s financial position at December 31, 2007 and 2006. The following information should be read in conjunction with the Financial Statements and Notes thereto. Known trends and contingencies of a material nature are discussed to the extent considered relevant.
Year ended December 31 (In millions) | 2007 | 2006 | 2005 |
Operating income | $ 292.0 | $ 293.9 | $ 232.2 |
Net income | $ 161.7 | $ 149.3 | $ 129.7 |
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 the cost of capital and income taxes.
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Year ended December 31 (Dollars in millions) | 2007 | 2006 | 2005 |
Operating revenues | $ 1,835.1 | $ 1,745.7 | $ 1,720.7 |
Cost of goods sold | 1,025.1 | 950.0 | 994.2 |
Gross margin on revenues | 810.0 | 795.7 | 726.5 |
Other operation and maintenance | 320.7 | 316.5 | 309.2 |
Depreciation | 141.3 | 132.2 | 134.4 |
Taxes other than income | 56.0 | 53.1 | 50.7 |
Operating income | 292.0 | 293.9 | 232.2 |
Interest income | --- | 1.9 | 2.6 |
Allowance for equity funds used during construction | --- | 4.1 | --- |
Other income (loss) | 5.0 | 4.0 | (2.8) |
Other expense | 7.2 | 9.7 | 2.5 |
Interest expense | 54.9 | 60.1 | 47.2 |
Income tax expense | 73.2 | 84.8 | 52.6 |
Net income | $ 161.7 | $ 149.3 | $ 129.7 |
Operating revenues by classification |
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Residential | $ 706.4 | $ 698.8 | $ 663.6 |
Commercial | 450.1 | 428.3 | 418.9 |
Industrial | 221.4 | 215.7 | 220.8 |
Oilfield | 140.9 | 129.3 | 134.8 |
Street light | 9.1 | 11.4 | 12.2 |
Public authorities | 172.3 | 159.6 | 160.9 |
Sales for resale | 68.8 | 65.4 | 67.7 |
Provision for rate refund | 0.1 | (0.9) | (2.0) |
System sales revenues | 1,769.1 | 1,707.6 | 1,676.9 |
Off-system sales revenues | 35.1 | 2.7 | 4.9 |
Other | 30.9 | 35.4 | 38.9 |
Total operating revenues | $ 1,835.1 | $ 1,745.7 | $ 1,720.7 |
MWH (A) sales by classification (in millions) |
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Residential | 8.7 | 8.7 | 8.5 |
Commercial | 6.3 | 6.2 | 6.0 |
Industrial | 4.2 | 4.4 | 4.5 |
Oilfield | 2.8 | 2.7 | 2.6 |
Street light | 0.1 | 0.1 | 0.1 |
Public authorities | 2.9 | 2.8 | 2.8 |
Sales for resale | 1.4 | 1.5 | 1.5 |
System sales | 26.4 | 26.4 | 26.0 |
Off-system sales | 0.7 | --- | 0.1 |
Total sales | 27.1 | 26.4 | 26.1 |
Number of customers | 762,234 | 754,840 | 745,493 |
Average cost of energy per KWH (B) - cents |
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Natural gas | 6.872 | 6.829 | 8.378 |
Coal | 1.143 | 1.114 | 1.004 |
Total fuel | 3.173 | 3.003 | 3.234 |
Total fuel and purchased power | 3.523 | 3.366 | 3.557 |
Degree days (C) |
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Heating - Actual | 3,175 | 2,746 | 3,159 |
Heating - Normal | 3,631 | 3,631 | 3,631 |
Cooling - Actual | 2,221 | 2,485 | 2,163 |
Cooling - Normal | 1,911 | 1,911 | 1,911 |
(A) Megawatt-hour. (B) Kilowatt-hour. (C) Degree days are calculated as follows: The high and low degrees of a particular day are added together and then averaged. If the calculated average is above 65 degrees, then the difference between the calculated average and 65 is expressed as cooling degree days, with each degree of difference equaling one cooling degree day. If the calculated average is below 65 degrees, then the difference between the calculated average and 65 is expressed as heating degree days, with each degree of difference equaling one heating degree day. The daily calculations are then totaled for the particular reporting period. |
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2007 compared to 2006. The Company’s operating income decreased approximately $1.9 million, or 0.7 percent, in 2007 as compared to 2006 primarily due to higher depreciation expense, higher taxes other than income and higher operation and maintenance expenses partially offset by a higher gross margin.
Gross Margin
Gross margin was approximately $810.0 million in 2007 as compared to approximately $795.7 million in 2006, an increase of approximately $14.3 million, or 1.8 percent. The gross margin increased primarily due to:
| • | higher rates from the Centennial wind farm rider, security rider and Arkansas rate case, which increased the gross margin by approximately $25.1 million; |
| • | increased peak demand and related revenues by non-residential customers in the Company’s service territory, which increased the gross margin by approximately $9.4 million; and |
| • | new customer growth in the Company’s service territory, which increased the gross margin by approximately $9.1 million. |
These increases in the gross margin were partially offset by:
| • | cooler weather in the Company’s service territory resulting in an approximate 11 percent decrease in cooling degree days compared to 2006, which decreased the gross margin by approximately $16.3 million; and |
| • | price variance due to sales and customer mix, which decreased the gross margin by approximately $13.6 million. |
Cost of goods sold for the Company consists of fuel used in electric generation, purchased power and transmission related charges. Fuel expense was approximately $756.1 million in 2007 as compared to approximately $730.3 million in 2006, an increase of approximately $25.8 million, or 3.5 percent, primarily due to increased natural gas generation in 2007 and a gain recognized from the sale of sulfur dioxide allowances of approximately $8.9 million in 2006. 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 2007, the Company’s fuel mix was 62 percent coal, 36 percent natural gas and two percent wind. In 2006, the Company’s fuel mix was 67 percent coal and 33 percent natural gas. Purchased power costs were approximately $268.6 million in 2007 as compared to approximately $219.7 million in 2006, an increase of approximately $48.9 million, or 22.3 percent. This increase was primarily due to the Company’s entrance into the energy imbalance service market on February 1, 2007 (see Note 13 of Notes to Financial Statements for a further discussion).
Variances in the actual cost of fuel used in electric generation and certain purchased power costs, as compared to the fuel component included in the cost-of-service for ratemaking, are passed through to the Company’s customers through automatic fuel adjustment clauses. The automatic fuel adjustment clauses are subject to periodic review by the OCC, the APSC and the FERC. The OCC, the APSC and the FERC have authority to review the appropriateness of gas transportation charges or other fees the Company pays to Enogex.
Operating Income
Other operation and maintenance expenses were approximately $320.7 million in 2007 as compared to approximately $316.5 million in 2006, an increase of approximately $4.2 million, or 1.3 percent. The increase in other operation and maintenance expenses was primarily due to:
| • | an increase in outside services expense of approximately $12.9 million primarily due to planned overhaul expenses at the power plants; |
| • | higher salaries, wages and other employee benefits expense of approximately $6.7 million; and |
| • | an increase in fees and permits expense of approximately $2.2 million due to additional fees to the SPP. |
These increases in other operation and maintenance expenses were partially offset by:
| • | an increase of capitalized work of approximately $17.7 million primarily related to storm costs that were deferred as a regulatory asset in 2007; and |
| • | a decrease of approximately $2.2 million of an additional accrual due to a settlement of a claim in 2006. |
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Depreciation expense was approximately $141.3 million in 2007 as compared to approximately $132.2 million in 2006, an increase of approximately $9.1 million, or 6.9 percent, primarily due to the Centennial wind farm being placed in service during January 2007.
Taxes other than income were approximately $56.0 million in 2007 as compared to approximately $53.1 million in 2006, an increase of approximately $2.9 million, or 5.5 percent, primarily due to increased ad valorem tax accruals and increased payroll tax expenses.
Additional Information
Interest Income. There was no interest income in 2007 as compared to approximately $1.9 million in 2006. The decrease was primarily due to interest income earned on fuel under recoveries in 2006 while there was a fuel over recovery balance in 2007.
Allowance for Equity Funds Used During Construction. There was no allowance for equity funds used during construction in 2007 as compared to approximately $4.1 million in 2006, a decrease of approximately $4.1 million primarily due to construction costs for the Centennial wind farm that exceeded the average daily short-term borrowings in 2006.
Other Income. Other income includes, among other things, contract work performed, non-operating rental income and miscellaneous non-operating income. Other income was approximately $5.0 million in 2007 as compared to approximately $4.0 million in 2006, an increase of approximately $1.0 million or 25.0 percent. The increase in other income was primarily due to an increase of approximately $3.6 million related to the guaranteed flat bill tariff resulting from more customers participating in this plan, along with milder weather in 2007. This was partially offset by a decrease of approximately $2.6 million associated with the tax gross up of allowance for equity funds used during construction in 2006 with no comparable item recorded in 2007.
Other Expense. 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 $7.2 million in 2007 as compared to approximately $9.7 million in 2006, a decrease of approximately $2.5 million, or 25.8 percent, primarily due to a loss on the retirement of fixed assets of approximately $5.2 million in 2006 partially offset by the write-off of non-recoverable Red Rock expenses of approximately $3.1 million for Arkansas and the FERC jurisdictions in 2007.
Interest Expense. Interest expense was approximately $54.9 million in 2007 as compared to $60.1 million in 2006, a decrease of approximately $5.2 million, or 8.7 percent. The decrease in interest expense was primarily due to:
| • | a settlement with the Internal Revenue Service (“IRS”) resulting in a reversal of interest expense of approximately $7.2 million in 2007; and |
| • | a decrease of approximately $7.0 million associated with the interest from a water storage facility in 2006. |
These decreases in interest expense were partially offset by:
| • | an increase of approximately $3.5 million in interest to Energy Corp.; |
| • | an increase of approximately $1.7 million associated with the carrying charges in the over recovery on fuel from customers; and |
| • | an increase of approximately $1.7 million due to interest expense recorded on treasury lock agreements the Company entered into related to the issuance of long-term debt by the Company in January 2008. |
Income Tax Expense. Income tax expense was approximately $73.2 million in 2007 as compared to approximately $84.8 million in 2006, a decrease of approximately $11.6 million, or 13.7 percent, primarily due to renewable energy tax credits for which the Company became eligible in 2007 on the wind power production from the Company’s Centennial wind farm partially offset by higher pre-tax income.
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.
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| Gross Margin |
Gross margin 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:
| • | price variance primarily due to rate increases authorized in the OCC order in December 2005, which increased the gross margin by approximately $47.6 million; |
| • | new customer growth in the Company’s service territory, which increased the gross margin by approximately $10.9 million; |
| • | increased peak demand and related revenues by non-residential customers in the Company’s service territory, which increased the gross margin by approximately $6.7 million; and |
| • | warmer weather in the Company’s service territory, which increased the gross margin by approximately $6.2 million. |
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.
Operating Income
Other operation 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 operation and maintenance expenses was primarily due to:
| • | higher salaries, wages and other employee benefits of approximately $12.5 million; |
| • | higher allocations from Energy Corp. of approximately $3.9 million primarily due to an increase in incentive compensation; |
| • | higher bad debt expense of approximately $3.5 million; and |
| • | an additional accrual of approximately $2.2 million for the settlement of a claim. |
| These increases in other operation and maintenance expenses were partially offset by: |
| • | a decrease in outside services expense of approximately $9.3 million; and |
| • | an increase in capitalized work of approximately $6.4 million primarily due to increased labor and transportation expenses related to more capital projects in 2006. |
The other operation and maintenance expense variance includes other operation 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:
| • | a decrease in depreciation rates that was implemented January 1, 2006 as approved by the OCC in December 2005; and |
| • | a decrease due to the retirement of assets at June 30, 2006 related to a power supply contract with a large industrial customer that expired June 1, 2006. |
33
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.
Additional Information
Allowance for Equity Funds Used During Construction. 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 (Loss). Other income was approximately $4.0 million in 2006 as compared to a loss of approximately $2.8 million in 2005, an increase of approximately $6.8 million. The increase in other income was primarily due to:
| • | a gain of approximately $3.5 million from the sale of miscellaneous assets that were recorded in 2004 and were reclassified to a regulatory liability in 2005; and |
| • | the benefit associated with the tax gross-up of approximately $4.1 million of allowance for equity funds used during construction. |
Other Expense. 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 in 2006.
Interest Expense. 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:
| • | increased interest of approximately $7.7 million due to the one-time recognition of interest expense associated with a water storage agreement; |
| • | increased interest of approximately $4.8 million on debt associated with the McClain Plant acquisition, which the Company ceased recording as a regulatory asset on July 8, 2005; |
| • | increased interest of approximately $3.0 million due to the termination of an interest rate swap in 2005; and |
| • | increased interest of approximately $1.5 million due to increased borrowings from Energy Corp. to cover increased construction costs. |
These increases in interest expense were partially offset by:
| • | a decrease in interest expense due to an increase in the allowance for borrowed funds used during construction of approximately $2.3 million; and |
| • | a decrease in interest expense of approximately $1.9 million related to Energy Corp. making a deposit with the IRS in August 2006 in anticipation that a portion of prior year deductions will be disallowed, which enabled the Company to cease accruing interest in August 2006. |
Income Tax Expense. 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:
| • | higher pre-tax income; |
| • | the ESOP dividend deduction at Energy Corp. in 2006 which was previously recorded at the Company in 2005 of approximately $7.4 million; and |
| • | a decrease in state tax credits in 2006 of approximately $3.8 million. |
34
Financial Condition
The balance of Fuel Inventories was approximately $44.3 million and $29.7 million at December 31, 2007 and 2006, respectively, an increase of approximately $14.6 million, or 49.2 percent, primarily due to outages at the Company’s Sooner and Muskogee power plants during the third and fourth quarters of 2007, resulting in a higher coal inventory balance at December 31, 2007.
The balance of Fuel Clause Under Recoveries was approximately $27.3 million at December 31, 2007 with no balance at December 31, 2006. This increase was due to the fact the amount billed to Oklahoma retail customers in 2007 was lower than 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 under recovers fuel costs in periods of rising fuel 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 and over recovery balances.
The balance of Construction Work in Progress was approximately $112.4 million and $177.2 million at December 31, 2007 and 2006, respectively, a decrease of approximately $64.8 million, or 36.5 percent, primarily due to the Company’s Centennial wind farm being placed in service during January 2007 partially offset by capital projects related to the December 2007 ice storm and various distribution and transmission projects.
The balance of Regulatory Asset - SFAS 158 was approximately $174.6 million and $231.1 million at December 31, 2007 and 2006, respectively, a decrease of approximately $56.5 million, or 24.4 percent, primarily due to pension plan and restoration retirement plan settlement charges and a reduction in the Company’s plan obligations due to a better than expected return on plan assets, Energy Corp.’s contribution to the pension plan and a higher discount rate.
The balance of Other Deferred Charges and Other Assets was approximately $76.9 million and $17.5 million at December 31, 2007 and 2006, respectively, an increase of approximately $59.4 million, primarily due to deferred costs associated with the cancelled Red Rock power plant, deferred costs for storm activities and plan settlement charges which resulted in excess pension expense over the amount granted in rates by the OCC in the Company’s most recent Oklahoma rate case.
The balance of Accounts Payable – Other was approximately $164.3 million and $95.2 million at December 31, 2007 and 2006, respectively, an increase of approximately $69.1 million, primarily due to accruals for the December 2007 ice storm and timing of outstanding checks clearing the bank.
The balance of Advances from Parent was approximately $348.0 million and $102.1 million at December 31, 2007 and 2006, respectively, an increase of approximately $245.9 million, primarily due to borrowings to fund dividend payments, pension plan funding, refunds to customers for fuel clause over recoveries along with under collections from customers for fuel clause under recoveries and daily operational needs of the Company.
The balance of Fuel Clause Over Recoveries was approximately $4.2 million and $96.3 million at December 31, 2007 and 2006, respectively, a decrease of approximately $92.1 million or 95.6 percent. The decrease was due to the fact that the amount billed to retail customers in Oklahoma and Arkansas in 2007 was lower than the Company’s cost of fuel. The $4.2 million balance at December 31, 2007 represents the Arkansas fuel clause over recoveries as the Oklahoma portion was in a fuel clause under recovery position at December 31, 2007. 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.
The balance of Accrued Benefit Obligations was approximately $118.1 million and $173.1 million at December 31, 2007 and 2006, respectively, a decrease of approximately $55.0 million, or 31.8 percent, primarily due to pension plan contributions during 2007 and plan changes for prior service cost and net loss for the pension, restoration retirement and postretirement plans.
35
Off-Balance Sheet Arrangements
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.
Heat Pump Loans
In December 2002, the Company sold approximately $8.5 million of its heat pump loans in a securitization transaction through OGE Consumer Loan 2002, LLC. In August 2007, the Company repurchased the outstanding heat pump loan balance of approximately $0.6 million. There was no gain or loss associated with the repurchase of the heat pump loans.
Railcar Lease Agreement
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.
Liquidity and Capital Requirements
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 cash generated from operations, short-term borrowings (through a combination of bank borrowings, commercial paper and borrowings from Energy Corp.) and permanent financings.
36
Capital requirements and future contractual obligations estimated for the next five years and beyond are as follows:
|
| Less than |
|
|
|
|
| 1 year | 1 - 3 years | 3 - 5 years | More than |
(In millions) | Total | (2008) | (2009-2010) | (2011-2012) | 5 years |
Capital expenditures including AFUDC (A)(B) | $ 3,808.8 | $ 788.5 | $ 842.9 | $ 894.2 | $ 1,283.2 |
Maturities of long-term debt | 845.4 | --- | --- | --- | 845.4 |
Interest payments on long-term debt | 945.0 | 49.0 | 98.1 | 98.1 | 699.8 |
Pension funding obligations | 80.0 | 47.0 | 17.0 | 16.0 | N/A |
Total capital requirements | 5,679.2 | 884.5 | 958.0 | 1,008.3 | 2,828.4 |
|
|
|
|
|
|
Operating lease obligations |
|
|
|
|
|
Railcars | 45.9 | 3.7 | 7.3 | 34.9 | --- |
|
|
|
|
|
|
Other purchase obligations and commitments |
|
|
|
|
|
Cogeneration capacity payments | 424.3 | 88.4 | 171.8 | 164.1 | N/A |
Fuel minimum purchase commitments | 428.5 | 115.1 | 224.5 | 69.3 | 19.6 |
Total other purchase obligations and commitments | 852.8 | 203.5 | 396.3 | 233.4 | 19.6 |
|
|
|
|
|
|
Total capital requirements, operating lease obligations |
|
|
|
|
|
and other purchase obligations and commitments | 6,577.9 | 1,091.7 | 1,361.6 | 1,276.6 | 2,848.0 |
Amounts recoverable through automatic fuel |
|
|
|
|
|
adjustment clause (C) | (898.7) | (207.2) | (403.6) | (268.3) | (19.6) |
Total, net | $ 5,679.2 | $ 884.5 | $ 958.0 | $ 1,008.3 | $ 2,828.4 |
(A) Under current environmental laws and regulations, the Company may be required to spend approximately $470 million in capital expenditures on its power plants related to regional haze projects. These expenditures are expected to begin in 2008 and would continue over the next five years.
(B) Approximately $434.5 million of the 2008 capital expenditures are related to the proposed acquisition of the Redbud power plant.
(C) Includes expected recoveries of costs incurred for the Company’s railcar operating lease obligations and the Company’s unconditional fuel purchase obligations.
N/A – not available
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.
2007 Capital Requirements and Financing Activities
Total capital requirements, consisting of capital expenditures, maturities of long-term debt, interest payments on long-term debt and pension funding obligations, were approximately $453.7 million in 2007. There were no contractual obligations, net of recoveries through automatic fuel adjustment clauses in 2007. Approximately $7.3 million of the 2007 capital requirements were to comply with environmental regulations. This compares to net capital requirements of approximately $528.4 million in 2006. There were no contractual obligations, net of recoveries through automatic fuel adjustment clauses in 2006. Approximately $2.0 million of the 2006 capital requirements were to comply with environmental regulations. During 2007, the Company’s sources of capital were internally generated funds from operating cash flows and short-term borrowings from Energy Corp. (through a combination of bank borrowings and commercial paper). 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.
37
Long-Term Debt Maturities
There are no maturities of the Company’s long-term debt during the next five years.
Cash Flows
Year Ended December 31 (In millions) | 2007 | 2006 | 2005 |
Net cash provided from operating activities | $ 230.1 | $ 455.1 | $ 205.7 |
Net cash used in investing activities | (376.4) | (410.1) | (247.3) |
Net cash provided from (used in) financing activities | 146.3 | (45.0) | 41.6 |
The reduction of approximately $225.0 million in net cash provided from operating activities in 2007 as compared to 2006 primarily related to lower fuel recoveries from Company customers partially offset by changes to other working capital. The increase of approximately $249.4 million in net cash provided from operating activities in 2006 as compared to 2005 primarily related to higher fuel recoveries from Company customers and a higher level of net income.
The decrease in net cash used in investing activities of approximately $33.7 million in 2007 as compared to 2006 related to lower levels of capital expenditures. The increase of approximately $162.8 million in net cash used investing activities in 2006 as compared to 2005 related to higher levels of capital expenditures.
The increase in net cash provided from financing activities of approximately $191.3 million in 2007 as compared to 2006 primarily related to higher levels of short-term debt partially offset by reduced amounts related to the issuance of long-term debt. The decrease of approximately $86.6 million in net cash used in financing activities in 2006 as compared to 2005 primarily related to proceeds from the issuance of long-term debt and maturities of long-term debt partially offset by lower levels of short-term debt.
Future Capital Requirements
Capital Expenditures
The Company’s current 2008 to 2013 construction program includes continued investment in its distribution, generation and transmission system. The Company’s current estimates of capital expenditures are approximately: 2008 - $788.5 million (approximately $434.5 million are related to the proposed acquisition of the Redbud power plant), 2009 - $393.9 million, 2010 - $449.0 million, 2011 - $438.6 million, 2012 - $455.6 million and 2013 - $438.6 million. The Company also has approximately 430 MWs 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.
Pension and Postretirement Benefit Plans
All eligible employees of the Company are covered by a non-contributory defined benefit pension plan. During 2007, actual asset returns for Energy Corp.’s defined benefit pension plan were positively affected by growth in the equity markets. At December 31, 2007, approximately 61 percent of the pension plan assets were invested in listed common stocks with the balance invested in corporate debt and U.S. Government securities. In 2007, asset returns on the pension plan were approximately 4.4 percent as compared to approximately 14.5 percent in 2006. 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 decreased from approximately $90.0 million in 2006 to approximately $50.0 million in 2007. 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 2008, Energy Corp. may contribute up to $50.0 million to its pension plan, of which approximately $42.6 million is expected to be the Company’s portion.
38
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 or the retirement restoration obligation during a plan year exceed the service cost and interest cost components of the organization’s net periodic pension cost or retirement restoration cost. During 2007 and 2006, Energy Corp. and 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 as well as the death of the Company’s Chairman and Chief Executive Officer in September 2007. As a result, Energy Corp. recorded pension settlement charges for 2007 and 2006 and a retirement restoration plan settlement charge in 2007. The pension settlement charges and retirement restoration plan 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 charges were an acceleration of costs that otherwise would have been recognized as pension expense or retirement restoration expense in future periods.
(In millions) | Energy Corp. | Company’s Portion (A) |
|
|
|
Pension Settlement Charges: |
|
|
2007 | $ 16.7 | $ 13.3 |
|
|
|
2006 | $ 17.1 | $ 13.3 |
|
|
|
Retirement Restoration Plan Settlement Charge: |
|
|
2007 | $ 2.3 | $ 0.1 |
(A) The Company’s Oklahoma jurisdictional portion of these changes were recorded as a regulatory asset (see Note 1 of Notes to Financial Statements for a further discussion).
As discussed in Note 11 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 on or after February 1, 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, 2007, 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 $414.4 million and $400.7 million, respectively, for an underfunded status of approximately $13.7 million. Also, at December 31, 2007, the accumulated postretirement benefit obligation and fair value of assets of the Company’s portion of Energy Corp.’s postretirement benefit plans was approximately $179.2 million and $76.0 million, respectively, for an underfunded status of approximately $103.2 million. The above amounts have been recorded in Accrued 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 amount recorded as a regulatory asset represents a net periodic pension cost to be recognized in the Statements of Income in future periods.
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 were recorded in Accrued 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.
39
Pension Plan Costs and Assumptions
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.
Many of the changes enacted as part of the Pension Protection Act are required to be implemented as of the first plan year beginning in 2008. While Energy Corp. generally has until the last day of the first plan year beginning in 2009 to reflect those changes as part of the plan document, plans must nevertheless comply in operation as of each provision’s effective date. Energy Corp. is taking steps now to ensure that its plans, as well as participants and outside administrators, are aware of the changes. In some instances, changes will necessitate notices to participants and/or changes in the plan’s administrative forms.
Optional Redemption of Long-Term Debt
The Company’s $125.0 million principal amount 6.65 percent Senior Notes (“Senior Notes”) due July 15, 2027, included a one-time option of the holders to redeem the notes on July 15, 2007, at 100 percent of the principal amount with accrued and unpaid interest. In July 2007, $50,000 of the Senior Notes were redeemed by the holders and retired.
Adoption of FIN No. 48
The Company adopted the provisions of FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes – an interpretation of FASB Statement No. 109,” on January 1, 2007. As a result of the implementation of FIN No. 48, the Company recognized an approximate $6.2 million increase in the accrued interest liability. The after-tax effect, of approximately $3.8 million, was accounted for as a reduction to the January 1, 2007 balance of retained earnings. The balance of uncertain tax positions at January 1, 2007 consisted of approximately $171.6 million of tax positions associated with the capitalization of self-constructed assets discussed in Note 7 of Notes to Financial Statements. On November 27, 2007, the Company reached a final settlement with the IRS related to the tax method of accounting, which resulted in the reversal of approximately $9.5 million of previously accrued interest expense related to this previously uncertain tax position.
Security Ratings
| Moody’s | Standard & Poor’s | Fitch’s |
Company Senior Notes | A2 | BBB+ | AA- |
A security rating is not a recommendation to buy, sell or hold securities. Such rating may be subject to revision or withdrawal at any time by the credit rating agency and each rating should be evaluated independently of any other rating.
Future financing requirements may be dependent, to varying degrees, upon numerous factors such as general economic conditions, abnormal weather, load growth, commodity prices, acquisitions of other businesses and/or development of projects, actions by rating agencies, inflation, changes in environmental laws or regulations, rate increases or decreases allowed by regulatory agencies, new legislation and market entry of competing electric power generators.
Future Sources of Financing
Management expects that cash generated from operations and proceeds from 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.
40
Issuance of New Long-Term Debt
In January 2008, the Company issued $200.0 million of 6.45% senior notes due February 1, 2038. The proceeds from the issuance were used to repay commercial paper borrowings.
Short-Term Debt
Short-term borrowings generally are used to meet working capital requirements. At December 31, 2007, the Company had no outstanding commercial paper borrowings. 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.
In December 2006, Energy Corp. and the Company amended and restated their revolving credit agreements to total in the aggregate $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. In November 2007, Energy corp. and the Company utilized one of these one-year extensions to extend the maturity of their credit agreements to December 6, 2012. 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. See Note 10 of Notes to Financial Statements for a discussion of Energy Corp.’s and the Company’s short term debt activity.
Future Financings Under Carbon Principles
In February 2008, three of the largest global financial institutions presented a set of principles (“Carbon Principles”) for meeting energy needs in the U.S. that they said balance cost, reliability and greenhouse gas concerns. These Carbon Principles focus on a portfolio approach that includes efficiency, renewable and low carbon power sources, as well as centralized generation sources in light of concerns regarding the impact of greenhouse gas emissions while recognizing the need to provide reliable power at a reasonable cost to consumers. According to financial institutions advocating the Carbon Principles, they are intended to create an industry best practice for the evaluation of options to meet the electric power needs of the U.S. in an environmentally responsible and cost effective manner. Some of the key points of the Carbon Principles are:
| • | Encourage clients to pursue cost-effective energy efficiency taking into consideration the potential value of avoided carbon dioxide emissions; |
| • | Encourage clients to invest in cost-effective renewables and distributed energy technologies; and |
| • | Educate clients, regulators and other industry participants regarding the additional diligence required for fossil fuel generation financings and encourage regulatory and legislative changes that facilitate carbon capture and storage to reduce carbon dioxide emissions. |
The advocates of the Carbon Principles would apply an enhanced diligence process to financings for companies that have announced plans to construct fossil fuel generation plants in the U.S. of over 200 MWs. The adoption of these Carbon Principles could negatively affect the Company’s ability to obtain financing in the future related to coal generation or expansion of capacity.
Critical Accounting Policies and Estimates
The Financial Statements and Notes to Financial Statements contain information that is pertinent to Management’s Discussion and Analysis. In preparing the Financial Statements, management is required to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and contingent liabilities at the date of the Financial Statements and the reported amounts of revenues and expenses during the reporting period. Changes to these assumptions and estimates could have a material effect on the Company’s Financial Statements. 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,
41
application and disclosure of the following critical accounting estimates have been discussed with Energy Corp.’s Audit Committee.
Pension and Postretirement Benefit Plans
Energy Corp. has defined benefit retirement and postretirement plans that cover substantially all of the Company’s employees. Pension and other postretirement plan expenses and liabilities are determined on an actuarial basis and are affected by the market value of plan assets, estimates of the expected return on plan assets, assumed discount rates and the level of funding. Actual changes in the fair market value of plan assets and differences between the actual return on plan assets and the expected return on plan assets could have a material effect on the amount of pension expense ultimately recognized. The pension plan rate assumptions are shown in Note 11 of Notes to Financial Statements. The assumed return on plan assets is based on management’s expectation of the long-term return on the plan assets portfolio. The discount rate used to compute the present value of plan liabilities is based generally on rates of high-grade corporate bonds with maturities similar to the average period over which benefits will be paid. The level of funding is dependent on returns on plan assets and future discount rates. Higher returns on plan assets and an increase in discount rates will reduce funding requirements to the pension plan. The following table indicates the sensitivity of the pension plan funded status to these variables.
|
|
| Impact on |
| Change |
| Funded Status |
Actual plan asset returns | +/- 5 percent |
| +/- $25.7 million |
Discount rate | +/- 0.25 percent |
| +/- $16.9 million |
Contributions | + $10.0 million |
| + $10.0 million |
Expected long-term return on plan assets | +/- 1 percent |
| None |
Commitments and Contingencies
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. When appropriate, 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 disclosed in this Annual Report on 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 12 and 13 of Notes to Financial Statements and Item 3 in this Annual Report on Form 10-K.
Asset Retirement Obligations
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 was 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. The Company did not recognize any new AROs during 2007; however, the Company has identified certain AROs that have not been recorded because the Company determined that these assets have indefinite lives.
Hedging Policies
The Company engages in cash flow and fair value hedge transactions to modify the rate composition of the debt portfolio. During 2005, 2006 and 2007, 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
42
issues. The treasury lock agreements in 2005 and 2006 qualified as cash flow hedges under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities.” The objective of these treasury lock agreements was to protect against the variability of future interest payments of long-term debt that was issued by the Company.
Regulatory Assets and Liabilities
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 required the Company to separately disclose the items that had 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 these charges to be included in Accumulated Other Comprehensive Income. However, for companies subject to SFAS No. 71, these charges were allowed to be recorded as a regulatory asset if: (i) the utility had historically recovered and currently recovers pension and postretirement benefit plan expense in its electric rates; and (ii) there was no negative evidence that the existing regulatory treatment will change. The Company met both criteria and, therefore, 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 indicate 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.
Unbilled Revenues
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, 2007, 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, 2007 and 2006, Accrued Unbilled Revenues were approximately $45.7 million and $39.7 million, respectively. The estimates that management uses in this calculation could vary from the actual amounts to be paid by customers.
Allowance for Uncollectible Accounts Receivable
Customer balances are generally written off if not collected within six months after the final billing date. The allowance for uncollectible accounts receivable 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, 2007, 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 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 $3.4 million and $3.3 million at December 31, 2007 and 2006, respectively.
Accounting Pronouncements
See Notes 1, 2, 3, 7 and 11 of Notes to Financial Statements for a discussion of recent accounting pronouncements that are applicable to the Company.
43
Electric Competition; Regulation
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 were postponed in 2001, 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. 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.
Commitments and Contingencies
Except as disclosed otherwise in this Annual Report on 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 12 and 13 of Notes to Financial Statements and Item 3 of Part I in this Annual Report on Form 10-K for a discussion of the Company’s commitments and contingencies.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk.
Market risks are, in most cases, risks that are actively traded in a marketplace and have been well studied in regards to quantification. Market risks include, but are not limited to, changes in interest rates. 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.
Risk Committee and Oversight
Management 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 Officer. This group, in conjunction with the aforementioned committees, is responsible for establishing and enforcing the Company’s risk policies.
Risk Policies
Management utilizes risk policies to control the amount of market risk exposure. These policies are designed to provide the Audit Committee of 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. Some of the measures in these policies include value-at-risk limits, position limits, tenor limits and stop loss limits.
Interest Rate Risk
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 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
44
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 two separate treasury lock agreements, effective November 16, 2007 and November 19, 2007, to hedge interest payments on the first $50.0 million and $25.0 million, respectively, of long-term debt that was issued in January 2008. These treasury lock agreements were settled on January 29, 2008 in conjunction with the issuance of long-term debt by the Company.
The fair value of the Company’s long-term debt is based on quoted market prices. At December 31, 2007, 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. There are no maturities of the Company’s long-term debt during the next five years.
Year ended December 31 | After |
| 12/31/07 |
(Dollars in millions) | 2012 | Total | Fair Value |
Fixed-rate debt (A) |
|
|
|
Principal amount | $ 710.0 | $ 710.0 | $ 729.2 |
Weighted-average |
|
|
|
interest rate | 6.20% | 6.20% | --- |
Variable-rate debt (B) |
|
|
|
Principal amount | $ 135.4 | $ 135.4 | $ 135.4 |
Weighted-average |
|
|
|
interest rate | 3.70% | 3.70% | --- |
(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.
Management 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. Management applies normal purchases and normal sales to electric power contracts by the Company and for fuel procurement by the Company.
Credit Risk
Credit risk includes the risk that counterparties that owe the Company money or energy will breach their obligations. If the counterparties to these arrangements fail to perform, the Company may be forced to enter into alternative arrangements. In that event, the Company’s financial results could be adversely affected and the Company could incur losses.
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 based on customer protection rules defined by the OCC and the APSC. The payment behavior of all existing customers is continuously monitored and, if the payment behavior indicates sufficient risk within the meaning of the applicable utility regulation, customers will be required to provide a security deposit.
45
Item 8. Financial Statements and Supplementary Data.
OKLAHOMA GAS AND ELECTRIC COMPANY
STATEMENTS OF INCOME
Year ended December 31 (In millions) | 2007 | 2006 | 2005 |
|
|
|
|
OPERATING REVENUES | $ 1,835.1 | $ 1,745.7 | $ 1,720.7 |
|
|
|
|
COST OF GOODS SOLD (exclusive of depreciation shown below) | 1,025.1 | 950.0 | 994.2 |
Gross margin on revenues | 810.0 | 795.7 | 726.5 |
Other operation and maintenance | 320.7 | 316.5 | 309.2 |
Depreciation | 141.3 | 132.2 | 134.4 |
Taxes other than income | 56.0 | 53.1 | 50.7 |
|
|
|
|
OPERATING INCOME | 292.0 | 293.9 | 232.2 |
|
|
|
|
OTHER INCOME (EXPENSE) |
|
|
|
Interest income | --- | 1.9 | 2.6 |
Allowance for equity funds used during construction | --- | 4.1 | --- |
Other income (loss) | 5.0 | 4.0 | (2.8) |
Other expense | (7.2) | (9.7) | (2.5) |
Net other income (expense) | (2.2) | 0.3 | (2.7) |
|
|
|
|
INTEREST EXPENSE |
|
|
|
Interest on long-term debt | 50.9 | 50.3 | 42.1 |
Allowance for borrowed funds used during construction | (4.0) | (4.5) | (2.2) |
Interest on short-term debt and other interest charges | 8.0 | 14.3 | 7.3 |
Interest expense | 54.9 | 60.1 | 47.2 |
|
|
|
|
INCOME BEFORE TAXES | 234.9 | 234.1 | 182.3 |
|
|
|
|
INCOME TAX EXPENSE | 73.2 | 84.8 | 52.6 |
|
|
|
|
NET INCOME | $ 161.7 | $ 149.3 | $ 129.7 |
The accompanying Notes to Financial Statements are an integral part hereof.
46
OKLAHOMA GAS AND ELECTRIC COMPANY
BALANCE SHEETS
December 31 (In millions) | 2007 | 2006 |
|
|
|
ASSETS |
|
|
CURRENT ASSETS |
|
|
Accounts receivable, less reserve of $3.4 and $3.3 respectively | $ 134.9 | $ 138.2 |
Accrued unbilled revenues | 45.7 | 39.7 |
Fuel inventories, at LIFO cost | 44.3 | 29.7 |
Materials and supplies, at average cost | 59.9 | 54.9 |
Price risk management | --- | 0.9 |
Gas imbalances | 0.1 | --- |
Accumulated deferred tax assets | 11.4 | 9.0 |
Fuel clause under recoveries | 27.3 | --- |
Prepayments | 3.8 | 4.3 |
Other | 4.2 | 5.2 |
Total current assets | 331.6 | 281.9 |
|
|
|
OTHER PROPERTY AND INVESTMENTS, at cost | 3.1 | 3.3 |
|
|
|
PROPERTY, PLANT AND EQUIPMENT |
|
|
In service | 5,363.1 | 4,977.2 |
Construction work in progress | 112.4 | 177.2 |
Total property, plant and equipment | 5,475.5 | 5,154.4 |
Less accumulated depreciation | 2,241.9 | 2,175.3 |
Net property, plant and equipment | 3,233.6 | 2,979.1 |
|
|
|
DEFERRED CHARGES AND OTHER ASSETS |
|
|
Income taxes recoverable from customers, net | 17.4 | 31.1 |
Regulatory asset - SFAS 158 | 174.6 | 231.1 |
McClain Plant deferred expenses | 12.4 | 18.7 |
Unamortized loss on reacquired debt | 18.9 | 20.1 |
Unamortized debt issuance costs | 6.4 | 6.9 |
Other | 76.9 | 17.5 |
Total deferred charges and other assets | 306.6 | 325.4 |
|
|
|
TOTAL ASSETS | $ 3,874.9 | $ 3,589.7 |
The accompanying Notes to Financial Statements are an integral part hereof.
47
OKLAHOMA GAS AND ELECTRIC COMPANY
BALANCE SHEETS (Continued)
December 31 (In millions) | 2007 | 2006 |
|
|
|
LIABILITIES AND STOCKHOLDER’S EQUITY |
|
|
CURRENT LIABILITIES |
|
|
Short-term debt | $ 0.8 | $ --- |
Accounts payable - affiliates | 10.5 | 5.2 |
Accounts payable - other | 164.3 | 95.2 |
Advances from parent | 348.0 | 102.1 |
Customer deposits | 53.6 | 50.9 |
Accrued taxes | 24.9 | 24.1 |
Accrued interest | 21.5 | 22.1 |
Accrued compensation | 28.8 | 24.2 |
Price risk management | 1.7 | --- |
Fuel clause over recoveries | 4.2 | 96.3 |
Other | 17.6 | 14.0 |
Total current liabilities | 675.9 | 434.1 |
|
|
|
LONG-TERM DEBT | 843.4 | 843.3 |
|
|
|
COMMITMENTS AND CONTINGENCIES (NOTE 12) |
|
|
|
|
|
DEFERRED CREDITS AND OTHER LIABILITIES |
|
|
Accrued benefit obligations | 118.1 | 173.1 |
Accumulated deferred income taxes | 633.0 | 644.0 |
Accumulated deferred investment tax credits | 22.0 | 26.8 |
Accrued removal obligations, net | 139.7 | 125.5 |
Other | 19.5 | 20.9 |
Total deferred credits and other liabilities | 932.3 | 990.3 |
|
|
|
STOCKHOLDER’S EQUITY |
|
|
Common stockholder’s equity | 665.4 | 665.4 |
Retained earnings | 757.9 | 656.0 |
Accumulated other comprehensive income, net of tax | --- | 0.6 |
Total stockholder’s equity | 1,423.3 | 1,322.0 |
|
|
|
TOTAL LIABILITIES AND STOCKHOLDER’S EQUITY | $ 3,874.9 | $ 3,589.7 |
The accompanying Notes to Financial Statements are an integral part hereof.
48
OKLAHOMA GAS AND ELECTRIC COMPANY
STATEMENTS OF CAPITALIZATION
December 31 (In millions) | 2007 | 2006 | |||
|
|
| |||
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 | 757.9 | 656.0 | |||
Accumulated other comprehensive income, net of tax | --- | 0.6 | |||
Total stockholder’s equity | 1,423.3 | 1,322.0 | |||
|
|
| |||
LONG-TERM DEBT |
|
| |||
SERIES | DATE DUE |
|
| ||
Senior Notes |
|
|
| ||
5.15 % | Senior Notes, Series Due January 15, 2016 | 110.0 | 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 | 110.0 | ||
Other Bonds |
|
|
| ||
3.25% - 4.07% Garfield Industrial Authority, January 1, 2025 | 47.0 | 47.0 | |||
3.24% - 4.03% Muskogee Industrial Authority, January 1, 2025 | 32.4 | 32.4 | |||
3.35% - 4.11% Muskogee Industrial Authority, June 1, 2027 | 56.0 | 56.0 | |||
|
|
| |||
Unamortized discount | (2.0) | (2.1) | |||
Total long-term debt | 843.4 | 843.3 | |||
|
|
| |||
Total Capitalization | $ 2,266.7 | $ 2,165.3 | |||
The accompanying Notes to Financial Statements are an integral part hereof.
49
OKLAHOMA GAS AND ELECTRIC COMPANY
STATEMENTS OF CHANGES IN STOCKHOLDER’S EQUITY
|
|
|
| Accumulated |
|
|
| Premium |
| Other |
|
| Common | on Capital | Retained | Comprehensive |
|
(In millions) | Stock | Stock | Earnings | Income (Loss) | Total |
|
|
|
|
|
|
Balance at December 31, 2004 | $ 100.9 | $ 564.5 | $ 461.0 | $ (64.1) | $ 1,062.3 |
Comprehensive income |
|
|
|
|
|
Net income for 2005 | --- | --- | 129.7 | --- | 129.7 |
Other comprehensive income, net of tax |
|
|
|
|
|
Minimum pension liability adjustment (($26.1) pre-tax) | --- | --- | --- | (16.0) | (16.0) |
Other comprehensive loss | --- | --- | --- | (16.0) | (16.0) |
Comprehensive income | --- | --- | 129.7 | (16.0) | 113.7 |
Dividends declared on common stock | --- | --- | (60.0) | --- | (60.0) |
|
|
|
|
|
|
Balance at December 31, 2005 | 100.9 | 564.5 | 530.7 | (80.1) | 1,116.0 |
Comprehensive income |
|
|
|
|
|
Net income for 2006 | --- | --- | 149.3 | --- | 149.3 |
Other comprehensive income, net of tax |
|
|
|
|
|
Minimum pension liability adjustment ($130.7 pre-tax) | --- | --- | --- | 80.1 | 80.1 |
Deferred hedging gains ($0.9 pre-tax) | --- | --- | --- | 0.6 | 0.6 |
Other comprehensive income | --- | --- | --- | 80.7 | 80.7 |
Comprehensive income | --- | --- | 149.3 | 80.7 | 230.0 |
Dividends declared on common stock | --- | --- | (24.0) | --- | (24.0) |
|
|
|
|
|
|
Balance at December 31, 2006 | 100.9 | 564.5 | 656.0 | 0.6 | 1,322.0 |
Comprehensive income |
|
|
|
|
|
Net income for 2007 | --- | --- | 161.7 | --- | 161.7 |
Other comprehensive income, net of tax |
|
|
|
|
|
Deferred hedging losses (($0.9) pre-tax) | --- | --- | --- | (0.6) | (0.6) |
Other comprehensive loss | --- | --- | --- | (0.6) | (0.6) |
Comprehensive income | --- | --- | 161.7 | (0.6) | 161.1 |
Dividends declared on common stock | --- | --- | (56.0) | --- | (56.0) |
FIN No. 48 adoption (($6.2) pre-tax) | --- | --- | (3.8) | --- | (3.8) |
|
|
|
|
|
|
Balance at December 31, 2007 | $ 100.9 | $ 564.5 | $ 757.9 | $ --- | $ 1,423.3 |
The accompanying Notes to Financial Statements are an integral part hereof.
50
OKLAHOMA GAS AND ELECTRIC COMPANY
STATEMENTS OF CASH FLOWS
Year ended December 31 (In millions) | 2007 | 2006 | 2005 |
|
|
|
|
CASH FLOWS FROM OPERATING ACTIVITIES |
|
|
|
Net Income | $ 161.7 | $ 149.3 | $ 129.7 |
Adjustments to reconcile net income to net cash provided from operating |
|
|
|
activities |
|
|
|
Depreciation | 141.3 | 132.2 | 134.4 |
Deferred income taxes and investment tax credits, net | 3.6 | 11.3 | 11.5 |
Allowance for equity funds used during construction | --- | (4.1) | --- |
Loss on retirement and abandonment of assets | 3.8 | 6.0 | --- |
Price risk management assets | 0.9 | (0.8) | (0.1) |
Price risk management liabilities | 1.7 | (0.1) | (0.1) |
Other assets | (12.7) | (56.4) | (4.9) |
Other liabilities | (53.4) | 12.9 | (7.9) |
Change in certain current assets and liabilities |
|
|
|
Accounts receivable, net | 3.3 | 16.1 | (48.9) |
Accrued unbilled revenues | (6.0) | 2.1 | 3.7 |
Fuel, materials and supplies inventories | (19.6) | (4.1) | 12.0 |
Gas imbalance assets | (0.1) | --- | --- |
Fuel clause under recoveries | (27.3) | 101.1 | (46.8) |
Other current assets | 1.5 | 5.6 | 7.8 |
Accounts payable | 69.1 | (17.9) | 20.1 |
Accounts payable - affiliates | 5.3 | (5.5) | 2.0 |
Income taxes payable - affiliates | 44.3 | 12.3 | (3.5) |
Customer deposits | 2.7 | 4.6 | 0.7 |
Accrued taxes | 0.8 | 1.2 | 2.5 |
Accrued interest | (6.9) | 5.8 | (0.1) |
Accrued compensation | 4.6 | 4.1 | (1.0) |
Gas imbalance liability | --- | (0.2) | 0.1 |
Fuel clause over recoveries | (92.1) | 96.3 | --- |
Other current liabilities | 3.6 | (16.7) | (5.5) |
Net Cash Provided from Operating Activities | 230.1 | 455.1 | 205.7 |
|
|
|
|
CASH FLOWS FROM INVESTING ACTIVITIES |
|
|
|
Capital expenditures (less allowance for equity funds used during |
|
|
|
construction) | (377.3) | (411.1) | (249.1) |
Proceeds from sale of assets | 0.9 | 1.0 | 1.8 |
Net Cash Used in Investing Activities | (376.4) | (410.1) | (247.3) |
|
|
|
|
CASH FLOWS FROM FINANCING ACTIVITIES |
|
|
|
Proceeds from long-term debt | --- | 217.5 | --- |
Retirement of long-term debt | (0.1) | --- | (220.0) |
Increase (decrease) in short-term debt, net | 202.4 | (223.5) | 335.6 |
Dividends paid on common stock | (56.0) | (39.0) | (74.0) |
Net Cash Provided from (Used in) Financing Activities | 146.3 | (45.0) | 41.6 |
|
|
|
|
NET CHANGE IN CASH | --- | --- | --- |
CASH AT BEGINNING OF PERIOD | --- | --- | --- |
CASH AT END OF PERIOD | $ --- | $ --- | $ --- |
The accompanying Notes to Financial Statements are an integral part hereof.
51
OKLAHOMA GAS AND ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
1. | Summary of Significant Accounting Policies |
Organization
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.
Accounting Records
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 records certain actual or anticipated costs and obligations as regulatory assets or liabilities if it is probable, based on regulatory orders or other available evidence, that the cost or obligation will be included in amounts allowable for recovery or refund in future rates.
| The following table is a summary of the Company’s regulatory assets and liabilities at December 31: |
December 31 (In millions) | 2007 | 2006 |
Regulatory Assets |
|
|
Regulatory asset - SFAS 158 | $ 174.6 | $ 231.1 |
Deferred storm expenses | 35.9 | --- |
Fuel clause under recoveries | 27.3 | --- |
Deferred pension plan expenses | 24.8 | 14.7 |
Unamortized loss on reacquired debt | 18.9 | 20.1 |
Income taxes recoverable from customers, net | 17.4 | 31.1 |
Red Rock deferred expenses | 14.7 | --- |
McClain Plant deferred expenses | 12.4 | 18.7 |
Cogeneration credit rider under recovery | 3.9 | 3.1 |
Miscellaneous | 0.8 | 0.4 |
Total Regulatory Assets | $ 330.7 | $ 319.2 |
|
|
|
Regulatory Liabilities |
|
|
Accrued removal obligations, net | $ 139.7 | $ 125.5 |
Fuel clause over recoveries | 4.2 | 96.3 |
Deferred gain on sale of assets | 1.4 | 2.7 |
Miscellaneous | 2.9 | --- |
Total Regulatory Liabilities | $ 148.2 | $ 224.5 |
52
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 required the Company to separately disclose the items that had 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 these charges to be included in Accumulated Other Comprehensive Income. However, for companies subject to SFAS No. 71, these charges were allowed to be recorded as a regulatory asset if: (i) the utility had historically recovered and currently recovers pension and postretirement benefit plan expense in its electric rates; and (ii) there was no negative evidence that the existing regulatory treatment will change. The Company met both criteria and, therefore, 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 indicate 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 components of the SFAS No. 158 regulatory asset at December 31, 2007 and 2006 are as follows: |
December 31 (In millions) | 2007 | 2006 |
Defined benefit pension plan and retirement restoration plan: |
|
|
Net loss | $ 112.3 | $ 129.9 |
Prior service cost | 4.8 | 21.9 |
Defined benefit postretirement plans: |
|
|
Net loss | 42.5 | 60.3 |
Net transition obligation | 12.7 | 15.2 |
Prior service cost | 2.3 | 3.8 |
Total | $ 174.6 | $ 231.1 |
The following amounts in the SFAS No. 158 regulatory asset at December 31, 2007 are expected to be recognized as components of net periodic benefit cost in 2008:
(In millions) |
|
Defined benefit pension plan and retirement restoration plan: |
|
Net loss | $ 6.8 |
Prior service cost | 1.2 |
Defined benefit postretirement plans: |
|
Net loss | 3.3 |
Net transition obligation | 2.6 |
Prior service cost | 1.5 |
Total | $ 15.4 |
In accordance with the OCC order received by the Company in December 2005 in its Oklahoma rate case, the Company was allowed to recover Oklahoma storm-related expenses exceeding a $3.5 million threshold. During 2007, the Company’s service territory experienced several storms, including a significant ice storm in December 2007. At December 31, 2007, deferred storm-related expenses were approximately $35.9 million. This amount has been recorded as a regulatory asset as the Company believes these expenses are probable of future recovery.
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 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 Oklahoma rate case, the Company was allowed to recover a certain amount of pension plan expenses. At December 31, 2007, there was
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approximately $24.8 million of expenses exceeding this level primarily related to pension settlement charges recorded by the Company during 2006 and 2007 (see Note 11 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.
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.
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.
On October 11, 2007, the OCC issued an order denying the Company and Public Service Company of Oklahoma’s (“PSO”) request for pre-approval of their proposed 950 megawatt (“MW”) Red Rock power plant project. The plant, which was to be built at the Company’s Sooner plant site, was to be 42 percent owned by OG&E, 50 percent owned by PSO and eight percent owned by the Oklahoma Municipal Power Authority (“OMPA”). As a result, on October 11, 2007, the Company, PSO and the OMPA agreed to terminate agreements to build and operate the plant. At December 31, 2007, the Company had incurred approximately $17.5 million of capitalized costs associated with the Red Rock power plant project. In December 2007,the Company filed an application with the OCC requesting authorization to defer, and establish a method for recovery of, approximately $14.7 million of Oklahoma jurisdictional costs associated with the Red Rock power plant project that are currently reflected in Deferred Charges and Other Assets on the Company’s Balance Sheets. If the request for deferral is not approved, the deferred costs will be expensed. In February 2008, the OCC issued a procedural schedule with a hearing scheduled for May 7, 2008. The Company expects to receive an order from the OCC in this matter by the end of 2008.
As a result of the acquisition of a 77 percent interest in the 520 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, 2007, the McClain Plant regulatory asset was approximately $12.4 million which is being recovered over the remaining two-year time period as authorized in the OCC rate order which began in January 2006. Approximately $15.5 million of the McClain Plant deferred expenses are included in the Company’s rate base for purposes of earning a return.
The Company’s cogeneration credit rider was initially implemented in 2003 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 cogeneration credit rider was 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 was automatically included in the next year’s rider. The balance of the cogeneration credit rider under recovery was approximately $3.9 million and $3.1 million, respectively, at December 31, 2007 and 2006. The Company filed an application with the OCC in September 2007 to request a new cogeneration credit rider for years after 2007 as the Company’s current cogeneration credit rider expired on December 31, 2007. In December 2007, the OCC issued an order approving a cogeneration credit rider that expires on December 31, 2009. 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.
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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.
In December 2005, the OCC order in the Company’s Oklahoma rate case required that any gains related to the sale of assets should be returned to customers through adjustments to electric rates. During 2006, the Company sold certain assets for a gain of approximately $0.3 million which was recorded as a regulatory liability. There were no gains from the sale of assets in 2007. The Company expects to continue this treatment for any 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.
Use of Estimates
In preparing the Financial Statements, management is required to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and contingent liabilities at the date of the Financial Statements and the reported amounts of revenues and expenses during the reporting period. Changes to these assumptions and estimates could have a material effect on the Company’s Financial Statements. 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.
Cash
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 $36.0 million and $24.3 million at December 31, 2007 and 2006, 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.
Allowance for Uncollectible Accounts Receivable
Customer balances are generally written off if not collected within six months after the final billing date. The allowance for uncollectible accounts receivable for the Company 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. The allowance for uncollectible accounts receivable was approximately $3.4 million and $3.3 million at December 31, 2007 and 2006, respectively.
New business customers are required to provide a security deposit in the form of cash, bond or irrevocable letter of credit that is refunded when the account is closed. New residential customers, whose outside credit scores indicate risk, are required to provide a security deposit that is refunded based on customer protection rules defined by the OCC and the APSC. The payment behavior of all existing customers is continuously monitored and, if the payment behavior indicates sufficient risk within the meaning of the applicable utility regulation, customers will be required to provide a security deposit.
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Fuel Inventories
Fuel inventories for the generation of electricity consist of coal, natural gas and oil. For 2007 and 2006, these inventories were 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 $7.4 million and $13.7 million for 2007 and 2006, respectively, based on the average cost of fuel purchased. The amount of fuel inventory was approximately $44.3 million and $29.7 million at December 31, 2007 and 2006, respectively.
Effective January 1, 2008, the Company’s inventory that is physically added to or withdrawn from storage or stockpiles will be valued using the weighted-average cost method in accordance with legislation that was passed in Oklahoma in 2007 which required that electric utilities record fuel or natural gas removed from storage or stockpiles using the weighted-average cost method of accounting for inventory. See Note 13 for a further discussion.
Property, Plant and Equipment
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 interest in the McClain Plant and, as disclosed below, only this 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 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 was approximately $181.0 million and $180.2 million, respectively, at December 31, 2007 and 2006. The accumulated depreciation associated with the Company’s interest in the McClain Plant was approximately $35.4 million and $25.3 million, respectively, at December 31, 2007 and 2006.
The Company’s property, plant and equipment are divided into the following major classes at December 31, 2007 and 2006, respectively.
| Total Property, |
| Net Property, |
| Plant and | Accumulated | Plant and |
December 31, 2007 (In millions) | Equipment | Depreciation | Equipment |
Distribution assets | $ 2,361.4 | $ 792.0 | $ 1,569.4 |
Electric generation assets | 2,114.0 | 1,062.8 | 1,051.2 |
Transmission assets | 747.3 | 285.7 | 461.6 |
Intangible plant | 35.8 | 29.7 | 6.1 |
Other property and equipment | 217.0 | 71.7 | 145.3 |
Total property, plant and equipment | $ 5,475.5 | $ 2,241.9 | $ 3,233.6 |
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| Total Property, |
| Net Property, |
| Plant and | Accumulated | Plant and |
December 31, 2006 (In millions) | Equipment | Depreciation | Equipment |
Distribution assets | $ 2,205.3 | $ 775.4 | $ 1,429.9 |
Electric generation assets | 2,057.4 | 1,042.5 | 1,014.9 |
Transmission assets | 663.2 | 265.1 | 398.1 |
Intangible plant | 32.0 | 26.2 | 5.8 |
Other property and equipment | 196.5 | 66.1 | 130.4 |
Total property, plant and equipment | $ 5,154.4 | $ 2,175.3 | $ 2,979.1 |
Depreciation
The provision for depreciation, which was approximately 2.7 percent of the average depreciable utility plant for both 2007 and 2006, 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 2008, the provision for depreciation is projected to continue to be approximately 2.7 percent of the average depreciable utility plant. Amortization of intangibles is computed using the straight-line method. Approximately 83 percent of the remaining amortizable intangible plant balance at December 31, 2007 will be amortized over three years with approximately 17 percent of the remaining amortizable intangible plant balance at December 31, 2007 being amortized over their respective lives ranging from four to 25 years.
Asset Retirement Obligations
In accordance with SFAS No. 143, for periods subsequent to the initial measurement of an asset retirement obligations (“ARO”), the Company recognizes 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. Also, in accordance with FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations,” the Company recognizes a liability for the fair value of an ARO that is conditional on a future event if the liability’s fair value can be reasonably estimated. The fair value of a liability for the conditional ARO is recognized when incurred. Uncertainty surrounding the timing and method of settlement of a conditional ARO is 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 is initially recognized in the period in which sufficient information is available for the Company to make a reasonable estimate of the liability’s fair value.
Allowance for Funds Used During Construction
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 5.78 percent, 7.79 percent and 3.78 percent for the years 2007, 2006 and 2005, respectively. The decrease in the AFUDC rates in 2007 was primarily due to a decrease in equity funds in the AFUDC calculation that resulted from a lower level of construction costs funded by short-term borrowings in 2007.
Collection of Sales Tax
In the course of its operations, the Company collects sales tax from its customers. The Company records a current liability when it collects sales taxes from its customers and eliminates this liability when the taxes are remitted to the appropriate governmental authorities. The Company excludes the sales tax collected from its operating revenues.
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Revenue Recognition
General
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.
SPP Purchases and Sales
In February 2007, the Company began participating in the Southwest Power Pool’s (“SPP”) energy imbalance service market in a dual role as a load serving entity and as a generation owner. The energy imbalance service market requires cash settlements for over or under schedules of generation and load. Market participants, including the Company, are required to submit resource plans and can submit offer curves for each resource available for dispatch. A function of interchange accounting is to match participants’ megawatt-hour (“MWH”) entitlements (generation plus scheduled bilateral purchases) against their MWH obligations (load plus scheduled bilateral sales) during every hour of every day. If the net result during any given hour is an entitlement, the participant is credited with a spot-market sale to the SPP at the respective market price for that hour; if the net result is an obligation, the participant is charged with a spot-market purchase from the SPP at the respective market price for that hour. The SPP purchases and sales are not allocated to individual customers. The Company records the hourly sales to the SPP at market rates in Operating Revenues and the hourly purchases from the SPP at market rates in Cost of Goods Sold in its Financial Statements.
Automatic Fuel Adjustment Clauses
Variances in the actual cost of fuel used in electric generation and certain purchased power costs, as compared to the fuel component in the cost-of-service for ratemaking, are passed through to the Company’s customers through automatic fuel adjustment clauses, which are subject to periodic review by the OCC, the APSC and the FERC.
Stock-Based Compensation
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).
Accrued Vacation
The Company accrues vacation pay by establishing a liability for vacation earned during the current year, but not payable until the following year.
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Accumulated Other Comprehensive Income
Accumulated Other Comprehensive Income at December 31, 2006 included an after-tax hedging gain of approximately $0.6 million ($0.9 million pre-tax). There was no accumulated other comprehensive income balance at December 31, 2007.
Environmental Costs
Accruals for environmental costs are recognized when it is probable that a liability has been incurred and the amount of the liability can be reasonably estimated. Costs are charged to expense or deferred as a regulatory asset based on expected recovery from customers in future rates, if they relate to the remediation of conditions caused by past operations or if they are not expected to mitigate or prevent contamination from future operations. Where environmental expenditures relate to facilities currently in use, such as pollution control equipment, the costs may be capitalized and depreciated over the future service periods. Estimated remediation costs are recorded at undiscounted amounts, independent of any insurance or rate recovery, based on prior experience, assessments and current technology. Accrued obligations are regularly adjusted as environmental assessments and estimates are revised, and remediation efforts proceed. For sites where the Company has been designated as one of several potentially responsible parties, the amount accrued represents the Company’s estimated share of the cost.
Related Party Transactions
Energy Corp. allocated operating costs to the Company of approximately $96.4 million, $88.0 million and $86.2 million during 2007, 2006 and 2005, respectively. Energy Corp. allocates operating costs to its subsidiaries based on several factors. Operating costs directly related to specific subsidiaries are assigned to those subsidiaries. Where more than one subsidiary benefits from certain expenditures, the costs are shared between those subsidiaries receiving the benefits. Operating costs incurred for the benefit of all subsidiaries are allocated among the subsidiaries, 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 2007, 2006 and 2005, the Company recorded a payable to Enogex Inc. and its subsidiaries (“Enogex”) approximately $34.7 million, $34.9 million and $34.9 million, respectively, for transporting gas to the Company’s natural gas-fired generating facilities. In each of 2007, 2006 and 2005, the Company recorded a payable to Enogex approximately $12.7 million for natural gas storage services. In 2007, 2006 and 2005, the Company also recorded natural gas purchases from Enogex of approximately $55.2 million, $60.4 million and $94.6 million, respectively. Approximately $11.3 million and $5.4 million were recorded at December 31, 2007 and 2006, respectively, and are included in Accounts Payable – Affiliates in the Balance Sheet for these activities.
In 2006 and 2005, the Company recorded interest income of approximately $0.3 million each from Energy Corp. for advances made by the Company to Energy Corp. There was no interest income in 2007.
In 2007, 2006 and 2005, the Company recorded interest expense of approximately $6.1 million, $2.6 million and $1.0 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 2007, 2006 and 2005, the Company declared dividends of approximately $56.0 million, $24.0 million and $60.0 million, respectively, to Energy Corp.
Reclassifications
Certain prior year amounts have been reclassified on the Financial Statements to conform to the 2007 presentation.
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2. | Accounting Pronouncement |
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 generally are to be applied prospectively as of the beginning of the fiscal year in which it is initially applied. The Company adopted this new standard effective January 1, 2008. The adoption of this new standard is not expected to have a material impact on the Company’s financial position or results of operations.
3. | Stock-Based Compensation |
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 of Energy Corp. and its subsidiaries. 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) in 2005 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 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, the Company’s 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 compensation expense of approximately $1.8 million pre-tax ($1.1 million after tax) in 2006 related to the Company’s portion of Energy Corp.’s share-based payments. Also, as a result of adopting SFAS No. 123 (R), 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. 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 $0.9 million pre-tax ($0.6 million after tax) in 2007 related to the Company’s portion of Energy Corp.’s share-based payments.
Energy Corp. issues new shares to satisfy stock option exercises. During 2007, 2006 and 2005, there were 496,565 shares, 738,426 shares and 606,802 shares, respectively, of new common stock issued pursuant to Energy Corp.’s Plans related to exercised stock options and payouts of earned performance units, of which 129,568 shares, 299,331 shares and 150,169 shares, respectively, related to the Company’s employees. Energy Corp. received approximately $8.2 million and $14.5 million in 2007 and 2006, respectively, related to exercised stock options.
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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 $3.5 million in 2007 related to Energy Corp.’s 2007 share-based payments. Energy Corp. realized an excess tax benefit of approximately $2.8 million in 2007 related to Energy Corp.’s 2006 share-based payments, which amount was presented as a financing cash inflow and realized when Energy Corp.’s 2006 income tax return was filed in September 2007. Energy Corp. recorded an excess tax benefit of approximately $2.8 million in 2006 related to Energy Corp.’s 2006 share-based payments. 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.
Performance Units
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 2005, 2006 and 2007.
|
|
| SFAS No. 123(R) |
Condition | Settlement | Vesting Period | 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 |
|
|
|
|
(A) All of Energy Corp.’s 2006 and 2007 performance units will be settled in stock.
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 and 2007, 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 and 2007, 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 2007, 2006 and 2005, Energy Corp. awarded 162,730, 239,856, and 201,794 performance units, respectively, to certain employees of Energy Corp. and its subsidiaries, of which 27,322, 34,459 and 32,364, respectively, related to the Company’s employees.
Performance Units – Total Shareholder Return
The Company recorded compensation expense of approximately $0.6 million pre-tax ($0.4 million after tax), $1.4 million pre-tax ($0.9 million after tax) and less than $0.1 million pre-tax and after tax in 2007, 2006 and 2005, 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
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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.
| 2007 | 2006 | 2005 |
Expected dividend yield | 3.6% | 4.9% | 5.3% |
Expected price volatility | 15.9% | 16.8% | 22.3% |
Risk-free interest rate | 4.47% | 4.66% | 3.28% |
Expected life of units (in years) | 2.95 | 2.85 | 2.85 |
Fair value of units granted | $ 24.18 | $ 22.93 | $ 21.56 |
A summary of the activity for Energy Corp.’s performance units applicable to the Company’s employees based on TSR at December 31, 2007 and changes during 2007 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 and 2007, which will be made only in common stock) and are considered made when the payout is approved by the Compensation Committee.
|
| Stock | Aggregate |
| Number | Conversion | Intrinsic |
(dollars in millions) | of Units | Ratio (A) | Value |
Units Outstanding at 12/31/06 | 78,537 | 1 : 1 |
|
Granted (B) | 20,491 | 1 : 1 |
|
Converted | (26,755) | 1 : 1 | $ 0.8 |
Forfeited | (6,271) | 1 : 1 |
|
Employee migration (C) | 6,636 | 1 : 1 |
|
Units Outstanding at 12/31/07 | 72,638 | 1 : 1 | $ 2.8 |
Units Fully Vested at 12/31/07 (D) | 27,710 | 1 : 1 | $ 1.3 |
(A) One performance unit = one share of Energy Corp.’s common stock.
(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.
(C) Due to certain employees transferring between Energy Corp. and its subsidiaries.
(D) These performance units, which were awarded in 2005 and became fully vested at December 31, 2007, were certified by the Compensation Committee of Energy Corp.’s Board of Directors in February 2008.
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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, 2007 and changes during 2007 are summarized in the following table:
|
| Weighted-Average |
| Number | Grant Date |
| of Units | Fair Value |
Units Non-Vested at 12/31/06 | 51,782 | $ 22.26 |
Granted (E) | 20,491 | $ 24.18 |
Vested (F) | (27,710) | $ 21.56 |
Forfeited | (6,271) | $ 23.10 |
Employee migration (G) | 6,636 | $ 22.17 |
Units Non-Vested at 12/31/07 (H) | 44,928 | $ 23.43 |
(E) 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.
(F) These performance units, which were awarded in 2005 and became fully vested at December 31, 2007, were certified by the Compensation Committee of Energy Corp.’s Board of Directors in February 2008.
(G) Due to certain employees transferring between Energy Corp. and its subsidiaries.
(H) Of the 44,928 performance units not vested at December 31, 2007, 42,809 performance units are assumed to vest at the end of the applicable vesting period.
At December 31, 2007, there was approximately $0.4 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 1.62 years.
Performance Units – Earnings Per Share
The Company recorded compensation expense of approximately $0.3 million pre-tax ($0.2 million after tax), $0.4 million pre-tax ($0.2 million after tax) and less than $0.1 million pre-tax and after tax in 2007, 2006 and 2005, respectively, related to the performance units based on EPS. 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, 2006 and 2007 performance units was $23.78 and $28.00 and $33.59, respectively.
A summary of the activity for Energy Corp.’s performance units applicable to the Company’s employees based on EPS at December 31, 2007 and changes during 2007 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 and 2007, which will be made only in common stock) and are considered made when approved by the Compensation Committee.
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|
| Stock | Aggregate |
| Number | Conversion | Intrinsic |
(dollars in millions) | of Units | Ratio (A) | Value |
Units Outstanding at 12/31/06 | 17,254 | 1:1 |
|
Granted (B) | 6,831 | 1:1 |
|
Forfeited | (2,148) | 1:1 |
|
Employee migration (C) | 2,212 | 1:1 |
|
Units Outstanding at 12/31/07 | 24,149 | 1:1 | $ 1.5 |
Units Fully Vested at 12/31/07 (D) | 9,231 | 1:1 | $ 0.7 |
(A) One performance unit = one share of Energy Corp.’s common stock.
(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.
(C) Due to certain employees transferring between Energy Corp. and its subsidiaries.
(D) These performance units, which were awarded in 2005 and became fully vested December 31, 2007, were certified by the Compensation Committee of Energy Corp.’s Board of Directors in February 2008.
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, 2007 and changes during 2007 are summarized in the following table:
|
| Weighted-Average |
| Number | Grant Date |
| of Units | Fair Value |
Units Non-Vested at 12/31/06 | 17,254 | $ 25.93 |
Granted (E) | 6,831 | $ 33.59 |
Vested (F) | (9,231) | $ 23.78 |
Forfeited | (2,148) | $ 29.30 |
Employee migration (G) | 2,212 | $ 25.66 |
Units Non-Vested at 12/31/07 (H) | 14,918 | $ 30.24 |
(E) 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.
(F) These performance units, which were awarded in 2005 and became fully vested at December 31, 2007, were certified by the Compensation Committee of Energy Corp.’s Board of Directors in February 2008.
(G) Due to certain employees transferring between Energy Corp. and its subsidiaries.
(H) Of the 14,918 performance units not vested at December 31, 2007, 14,269 performance units are assumed to vest at the end of the applicable vesting period.
At December 31, 2007, there was approximately $0.1 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 1.00 years.
Stock Options
The Company recorded no compensation expense in 2007 related to stock options because at December 31, 2006, there was no unrecognized compensation cost related to non-vested options, which became fully vested in January 2007. The Company recorded compensation expense of less than $0.1 million pre-tax and after tax in 2006 related to stock options. No compensation expense related to stock options was recognized in 2005 as all options granted under the Plans had an exercise price equal to the market value of Energy Corp.’s common stock on the grant date.
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A summary of the activity for Energy Corp.’s options applicable to the Company’s employees at December 31, 2007 and changes during 2007 are summarized in the following table:
|
|
| Aggregate | Weighted-Average |
| Number | Weighted-Average | Intrinsic | Remaining |
(dollars in millions) | of Options | Exercise Price | Value | Contractual Term |
Options Outstanding at 12/31/06 | 157,958 | $ 22.83 |
|
|
Exercised | (95,735) | $ 22.96 | $ 1.3 |
|
Expired | (11) | $ 16.69 |
|
|
Options Outstanding at 12/31/07 | 62,212 | $ 22.64 | $ 0.8 | 4.45 years |
Options Fully Vested and Exercisable at 12/31/07 | 62,212 | $ 22.64 | $ 0.8 | 4.45 years |
A summary of the activity for Energy Corp.’s non-vested options applicable to the Company’s employees at December 31, 2007 and changes during 2007 are summarized in the following table:
|
| Weighted-Average |
| Number | Grant Date |
| of Options | Fair Value |
Options Non-Vested at 12/31/06 | 13,903 | $ 2.05 |
Vested | (13,903) | $ 2.05 |
Options Non-Vested at 12/31/07 | --- | $ --- |
4. | Loss on Retirement and Asset Retirement Obligation of Fixed Assets |
The Company had a power supply contract with a large industrial customer that expired on June 1, 2006. The Company evaluated options to utilize the assets dedicated to that customer and decided 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.
5. | Price Risk Management Assets and Liabilities |
The Company periodically utilizes derivative contracts to reduce exposure to adverse interest rate fluctuations. During 2007 and 2006, the Company’s use of price risk management instruments involved the use of treasury lock agreements. The treasury lock agreements help protect against the variability of future interest payments of long-term debt that was issued by the Company.
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. 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 transaction in a cash flow hedge are regularly evaluated to assess whether they continue to be probable of occurring. If the forecasted transactions are no longer probable of occurring, hedge accounting will cease on a prospective basis and all future changes in the fair value of the derivative will be recognized directly in earnings. 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.
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The Company measures ineffectiveness of the treasury lock cash flow hedges using the hypothetical derivative method prescribed by SFAS No. 133. Under the hypothetical derivative method, the Company designates 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.
Management 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. Management applies normal purchases and normal sales to electric power contracts and fuel procurement by the Company.
At December 31, 2007, the Company’s treasury lock agreements were not designated as cash flow hedges under SFAS No. 133. The 2007 treasury lock agreements were settled on January 29, 2008. At December 31, 2006, the Company’s treasury lock agreements were designated as cash flow hedges under SFAS No. 133. The 2006 treasury lock agreements expired March 29, 2007.
6. | Supplemental Cash Flow Information |
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.
Year ended December 31 (In millions) | 2007 | 2006 | 2005 |
NON-CASH INVESTING AND FINANCING ACTIVITIES |
|
|
|
|
|
|
|
Change in fair value of long-term debt due to interest rate swap | $ --- | $ --- | $ (3.9) |
Power plant long-term service agreement | 0.7 | --- | --- |
|
| ||
SUPPLEMENTAL CASH FLOW INFORMATION |
|
|
|
|
|
|
|
Cash Paid During the Period for |
|
|
|
Interest (net of interest capitalized of $4.0, $4.5, $2.2) | $ 57.9 | $ 50.5 | $ 50.2 |
Income taxes (net of income tax refunds) | 30.2 | 61.0 | 43.1 |
7. | Income Taxes |
| The items comprising income tax expense are as follows: |
Year ended December 31 (In millions) | 2007 | 2006 | 2005 |
Provision (Benefit) for Current Income Taxes |
|
|
|
Federal | $ 68.3 | $ 81.6 | $ 36.2 |
State | 0.6 | (7.7) | 5.6 |
Total Provision for Current Income Taxes | 68.9 | 73.9 | 41.8 |
Provision (Benefit) for Deferred Income Taxes, net |
|
|
|
Federal | 6.9 | 15.3 | 18.2 |
State | 1.5 | 1.0 | (1.6) |
Total Provision for Deferred Income Taxes, net | 8.4 | 16.3 | 16.6 |
Deferred Federal Investment Tax Credits, net | (4.8) | (5.0) | (5.1) |
Income Taxes Relating to Other Income and Deductions | 0.7 | (0.4) | (0.7) |
Total Income Tax Expense | $ 73.2 | $ 84.8 | $ 52.6 |
The Company is a member of an affiliated group that files consolidated income tax returns in the U.S. federal jurisdiction and various state jurisdictions. With few exceptions, the Company is no longer subject to U.S. Federal or state and local income tax examinations by tax authorities for years before 2002. Income taxes are
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generally allocated to each company in the affiliated group based on its separate taxable income or loss. Federal investment tax credits previously claimed on electric utility property have been deferred and are being amortized to income over the life of the related property. 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:
Year ended December 31 | 2007 | 2006 | 2005 |
Statutory federal tax rate | 35.0% | 35.0% | 35.0% |
State income taxes, net of federal income tax benefit | 1.2 | 2.5 | 1.2 |
Amortization of net unfunded deferred taxes | 1.3 | 1.1 | 1.2 |
Medicare Part D subsidy | (0.3) | (0.9) | (1.4) |
Federal investment tax credits, net | (2.0) | (2.1) | (2.8) |
Federal renewable energy credit (A) | (3.0) | --- | --- |
401(k) dividends | --- | 1.3 | (2.2) |
Excess deferred taxes (B) | --- | --- | (1.2) |
Other | (1.0) | (0.7) | (1.0) |
Effective income tax rate as reported | 31.2% | 36.2% | 28.8% |
(A) These are credits the Company began earning associated with the production from its 120 MW wind farm in northwestern Oklahoma (“Centennial”) that was placed in service during January 2007.
(B) 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 of Energy Corp.’s 2002 consolidated income tax returns, 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. In Energy Corp.’s IRS examination for years 2002 and 2003, the IRS stated that it disagreed with the change made by the Company.
The Company adopted the provisions of FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes – an interpretation of FASB Statement No. 109,” on January 1, 2007. As a result of the implementation of FIN No. 48, the Company recognized an approximate $6.2 million increase in the accrued interest liability. The after-tax effect, of approximately $3.8 million, was accounted for as a reduction to the January 1, 2007 balance of retained earnings. The balance of uncertain tax positions at January 1, 2007 consisted of approximately $171.6 million of tax positions associated with the capitalization of costs for self-constructed assets discussed above. Because of the impact of deferred tax accounting, other than interest and penalties, the disallowance of the shorter deductibility period would not affect the annual effective tax rate but would accelerate the payment of cash to the taxing authority to an earlier period. The Company reached a final settlement with the IRS on November 27, 2007 related to the tax method of accounting for the capitalization of costs for self-constructed assets. A reconciliation of the beginning and ending amounts of unrecognized tax benefits is as follows:
(In millions)
Balance at January 1, 2007 | $ 66.4 |
Settlements with tax authorities | (66.4) |
Balance at December 31, 2007 | $ --- |
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The Company recognizes accrued interest related to tax benefits in interest expense and recognizes penalties in other expense. The Company recorded interest expense associated with the IRS audit of approximately $3.3 million in 2005, $0.3 million in 2006 and $2.6 million through October 2007. On November 27, 2007, the Company reached a final settlement with the IRS related to the tax method of accounting, which resulted in a reversal of approximately $9.5 million of previously accrued interest expense related to this previously uncertain tax position. Prior to the settlement with the IRS, the Company had accrued approximately $12.4 million related to this previously uncertain tax position. At December 31, 2007, the Company had approximately $2.9 million of accrued interest related to the capitalization of costs for self-constructed assets discussed above.
The Company follows the provisions of SFAS No. 109, “Accounting for Income Taxes,” 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, 2007 and 2006, respectively, were as follows:
December 31 (In millions) | 2007 | 2006 |
Current Accumulated Deferred Tax Assets |
|
|
Accrued vacation | $ 3.9 | $ 3.9 |
Uncollectible accounts | 1.4 | 1.2 |
Accrued liabilities | 1.2 | 2.1 |
Derivative instruments | 0.4 | --- |
Other | 4.5 | 2.5 |
Total Current Accumulated Deferred Tax Assets | 11.4 | 9.7 |
Current Accumulated Deferred Tax Liabilities |
|
|
Derivative instruments | --- | (0.7) |
Current Accumulated Deferred Tax Assets, net | $ 11.4 | $ 9.0 |
Non-Current Accumulated Deferred Tax Liabilities |
|
|
Accelerated depreciation and other property related differences | $ 524.7 | $ 554.8 |
Regulatory asset | 96.0 | 75.9 |
Company pension plan | 62.6 | 48.7 |
Income taxes refundable to customers, net | 6.7 | 13.0 |
Bond redemption-unamortized costs | 6.1 | 6.5 |
Total Non-Current Accumulated Deferred Tax Liabilities | 696.1 | 698.9 |
Non-Current Accumulated Deferred Tax Assets |
|
|
Regulatory liabilities | (34.3) | (29.1) |
Postretirement medical and life insurance benefits | (20.3) | (15.4) |
Deferred federal investment tax credits | (8.5) | (10.4) |
Total Non-Current Accumulated Deferred Tax Assets | (63.1) | (54.9) |
Non-Current Accumulated Deferred Income Tax Liabilities, net | $ 633.0 | $ 644.0 |
The Company fully utilized all of its Oklahoma investment tax credit carryovers from 2006 and prior periods in 2007. During 2007, additional Oklahoma tax credits of approximately $13.9 million were generated or purchased by the Company. The Company currently believes that approximately $9.4 million of these state tax credit amounts will be utilized in 2007 and approximately $4.5 million will be carried over to 2008 and later years. Credits not utilized in 2007 will begin expiring in 2018.
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8. | Common Stock and Cumulative Preferred Stock |
There were no new shares of common stock issued during 2007, 2006 or 2005. The Company’s Restated Certificate of Incorporation permits the issuance of a new series of preferred stock with dividends payable other than quarterly.
9. | Long-Term Debt |
A summary of the Company’s long-term debt is included in the Statements of Capitalization. At December 31, 2007, the Company was in compliance with all of its debt agreements.
Optional Redemption of Long-Term Debt
The Company’s $125.0 million principal amount 6.65 percent Senior Notes (“Senior Notes”) due July 15, 2027, included a one-time option of the holders to redeem the notes on July 15, 2007, at 100 percent of the principal amount with accrued and unpaid interest. In July 2007, $50,000 of the Senior Notes were redeemed by the holders and retired.
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):
SERIES | DATE DUE | AMOUNT |
3.25% - 4.07% Garfield Industrial Authority, January 1, 2025 | $ 47.0 | |
3.24% - 4.03% Muskogee Industrial Authority, January 1, 2025 | 32.4 | |
3.35% - 4.11% Muskogee Industrial Authority, June 1, 2027 | 56.0 | |
Total (redeemable during next 12 months) | $ 135.4 |
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 believes that it has sufficient long-term liquidity to meet these obligations.
Long-Term Debt Maturities
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.
Issuance of New Long-Term Debt
In January 2008, the Company issued $200.0 million of 6.45% senior notes due February 1, 2038. The proceeds from the issuance were used to repay commercial paper borrowings. The Company entered into two separate treasury lock arrangements, effective November 16, 2007 and November 19, 2007, to hedge interest payments on the first $50.0 million and $25.0 million, respectively, of the long-term debt that was issued in January 2008. These treasury lock agreements were settled on January 29, 2008.
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10. | Short-Term Debt |
At December 31, 2007 and 2006, the Company had approximately $348.0 million and $102.1 million, respectively, in outstanding advances from Energy Corp. The following table shows Energy Corp.’s and the Company’s revolving credit agreements and available cash at December 31, 2007.
Revolving Credit Agreements and Available Cash (In millions) | ||||
| Amount | Amount | Weighted-Average |
|
Entity | Available | Outstanding | Interest Rate | Maturity |
Energy Corp. (A) | $ 600.0 | $ --- | --- | December 6, 2012 (C) |
The Company (B) | 400.0 | --- | --- | December 6, 2012 (C) |
| 1,000.0 | --- | --- |
|
Cash | --- | N/A | N/A | N/A |
Total | $ 1,000.0 | $ --- | --- |
|
(A) This bank facility is available to back Energy Corp.’s commercial paper borrowings and to provide revolving credit borrowings. This bank facility can also be used as a letter of credit facility. At December 31, 2007, there was approximately $295.0 million in outstanding commercial paper borrowings. (B) This bank facility is available to back up the Company’s commercial paper borrowings and to provide revolving credit borrowings. At December 31, 2007, the Company had outstanding approximately $3.1 million supporting letters of credit and no commercial paper borrowings. (C) In December 2006, Energy Corp. and the Company amended and restated their revolving credit agreements to total in the aggregate $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 In November 2007, Energy Corp. and the Company utilized one of these one-year extensions to extend the maturity of their credit agreements to December 6, 2012. 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. |
Energy Corp.’s and the Company’s ability to access the commercial paper market could be adversely impacted by a credit rating downgrade or major market disruptions as experienced in August 2007. As a result of the market turmoil in August 2007, Energy Corp. and the Company utilized borrowings under their revolving credit agreements. During the third and fourth quarters of 2007, Energy Corp. and the Company repaid the borrowings under their revolving credit agreements and began utilizing commercial paper in the commercial paper market. 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 of the Company 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. Any future downgrade of the Company would also lead to higher long-term borrowing costs and, if below investment grade, would require Energy Corp. to post cash collateral or letters of credit.
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.
11. | Retirement Plans and Postretirement Benefit Plans |
In September 2006, the FASB issued SFAS No. 158 which required an employer to 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. The requirement to initially recognize the funded status of the defined benefit postretirement plan and the disclosure requirements was effective for the year ended December 31, 2006 for the Company.
Defined Benefit Pension Plan
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
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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 2007 and 2006, Energy Corp. made contributions to its pension plan of approximately $50.0 million and $90.0 million, respectively, of which approximately $38.3 million and $69.4 million, respectively, were the Company’s portion, to help ensure that the pension plan maintains an adequate funded status. Such contributions are intended to provide not only for benefits attributed to service to date, but also for those expected to be earned in the future. In August 2006, legislation was passed that changed the funding requirement for single- and multi-employer defined benefit pension plans as discussed below. During 2008, Energy Corp. may contribute up to $50.0 million to its pension plan, of which approximately $42.6 million is expected to be the Company’s portion. 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, 2007, 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 $414.4 million and $400.7 million, respectively, for an underfunded status of approximately $13.7 million. These amounts have been recorded in Accrued Benefit Obligations with the offset recorded as a regulatory asset in the Company’s Balance Sheet as discussed in Note 1. The amount recorded as a regulatory asset represents a net periodic benefit cost to be recognized in the Statements of Income in future periods.
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. These amounts were recorded in Accrued 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.
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 or the retirement restoration benefit obligation during a plan year exceed the service cost and interest cost components of the organization’s net periodic pension cost or retirement restoration cost. During 2007 and 2006, Energy Corp. and 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 as well as the death of the Company’s Chairman and Chief Executive Officer in September 2007. As a result, Energy Corp. recorded pension settlement charges for 2007 and 2006 and a retirement restoration plan settlement charge in 2007. The pension settlement charges and the retirement restoration plan settlement charge did not require a cash outlay by the Company and did not increase the Company’s total pension expense or restoration retirement expense over time, as the charges were an acceleration of costs that otherwise would have been recognized as pension expense or retirement restoration expense in future periods.
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(In millions) | Energy Corp. | Company’s Portion (A) |
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Pension Settlement Charges: |
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2007 | $ 16.7 | $ 13.3 |
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2006 | $ 17.1 | $ 13.3 |
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Retirement Restoration Plan Settlement Charge: |
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2007 | $ 2.3 | $ 0.1 |
(A) The Company’s Oklahoma jurisdictional portion of these charges were recorded as a regulatory asset (see Note 1 for a further discussion).
Pension Plan Costs and Assumptions
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.
Many of the changes enacted as part of the Pension Protection Act are required to be implemented as of the first plan year beginning in 2008. While Energy Corp. generally has until the last day of the first plan year beginning in 2009 to reflect those changes as part of the plan document, plans must nevertheless comply in operation as of each provision’s effective date. Energy Corp. is taking steps now to ensure that its plans, as well as participants and outside administrators, are aware of the changes. In some instances, changes will necessitate notices to participants and/or changes in the plan’s administrative forms.
Plan Investments, Policies and Strategies
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, 2007 and 2006:
December 31 | 2007 | 2006 |
Equity securities | 61 % | 64 % |
Debt securities | 37 % | 34 % |
Other | 2 % | 2 % |
Total | 100 % | 100 % |
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 “Investment Committee”).
The various investment managers used by the trust operate within the general operating objectives as established in the investment policy and within the specific guidelines established for their respective portfolio. The table below shows the target asset allocation percentages for each major category of plan assets:
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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 % |
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:
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 |
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 than the average company traded on the public exchanges with the following characteristics: price/earnings ratio at or near the Russell 2000, small dividend yield, return on equity at or near the Russell 2000 and 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
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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 Investment Committee is received. The purchase of securities on margin is prohibited as is securities lending. Private placement or venture capital may not be purchased. All interest and dividend payments must be swept on a daily basis into a short-term money market fund for re-deployment. The purchase of any of 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.
Restoration of Retirement Income Plan
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.
The Company expects to pay benefits related to its pension plan and restoration of retirement income plan of approximately $48.0 million in 2008, $49.1 million in 2009, $48.6 million in 2010, $50.0 million in 2011, $51.5 million in 2012 and an aggregate of $221.1 million in years 2013 to 2017. These expected benefits are 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.
Postretirement Benefit Plans
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 postretirement medical benefits while employees hired on or after February 1, 2000 are not entitled to postretirement medical benefits. All regular, full-time, active employees whose age and years of credited service total or exceed 80 or have attained age 55 with five years of vesting service at the time of retirement 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, 2007, the accumulated postretirement benefit obligation and fair value of assets of the Company’s portion of Energy Corp.’s postretirement benefit plans was approximately $179.2 million and $76.0 million, respectively, for an underfunded status of approximately $103.2 million. These amounts have been recorded
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in Accrued Benefit Obligations with the offset recorded as a regulatory asset in the Company’s Balance Sheet as discussed in Note 1. The amount recorded as a regulatory asset represents a net periodic benefit cost to be recognized in the Statements of Income in future periods.
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. These amounts have been recorded in Accrued 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 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 nine percent in 2008 with the rates decreasing in subsequent years by one percentage point per year through 2011. A one-percentage point change in the assumed health care cost trend rate would have the following effects:
ONE-PERCENTAGE POINT INCREASE | |||
Year ended December 31 (In millions) | 2007 | 2006 | 2005 |
Effect on aggregate of the service and interest cost components | $ 1.8 | $ 1.7 | $ 1.4 |
Effect on accumulated postretirement benefit obligations | 21.4 | 23.4 | 21.8 |
ONE-PERCENTAGE POINT DECREASE | |||
Year ended December 31 (In millions) | 2007 | 2006 | 2005 |
Effect on aggregate of the service and interest cost components | $ 1.5 | $ 1.4 | $ 1.1 |
Effect on accumulated postretirement benefit obligations | 17.8 | 19.3 | 18.0 |
Medicare Prescription Drug, Improvement and Modernization Act of 2003
On December 8, 2003, President Bush signed into law the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (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 $39.8 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 $5.5 million annually, of which approximately $4.6 million is expected to be the Company’s portion. The $4.6 million in annual savings is comprised of a reduction of approximately $2.3 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 $1.9 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 $10.5 million in 2008, $11.4 million in 2009, $12.3 million in 2010, $13.1 million in 2011, $13.8 million in 2012 and an aggregate of $77.7 million in years 2013 to 2017. The Company expects to receive federal subsidy receipts provided by the Medicare Act of approximately $1.2 million in 2008, $1.3 million in 2009, $1.5 million in 2010, $1.6 million in 2011, $1.7 million in 2012 and an aggregate of $10.2 million in years 2013 to 2017. Energy Corp. received approximately $1.9 million in federal subsidy receipts in 2007.
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Obligations and Funded Status
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:
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| Restoration of Retirement | Postretirement | |||||
| Pension Plan | Income Plan | Benefit Plans | |||||
December 31 (In millions) | 2007 | 2006 | 2007 | 2006 | 2007 | 2006 | ||
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Change in Benefit Obligation |
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Beginning obligations | $ (465.2) | $ (477.8) | $ (0.4) | $ (0.4) | $ (188.0) | $ (175.8) | ||
Service cost | (13.8) | (13.4) | --- | --- | (2.7) | (2.6) | ||
Interest cost | (25.6) | (24.7) | --- | --- | (10.4) | (10.0) | ||
Plan changes | 12.6 | --- | (0.1) | --- | --- | --- | ||
Participants’ contributions | --- | --- | --- | --- | (4.5) | (4.2) | ||
Actuarial gains (losses) | 13.2 | (10.6) | (0.5) | --- | 12.7 | (9.1) | ||
Benefits paid | 65.2 | 61.3 | 0.2 | --- | 13.7 | 13.7 | ||
Ending obligations | (413.6) | (465.2) | (0.8) | (0.4) | (179.2) | (188.0) | ||
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Change in Plans’ Assets |
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Beginning fair value | 410.1 | 350.6 | --- | --- | 71.7 | 65.1 |
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Actual return on plans’ assets | 17.5 | 51.3 | --- | --- | 5.4 | 8.1 |
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Employer contributions | 38.3 | 69.5 | 0.2 | --- | 8.1 | 8.0 |
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Participants’ contributions | --- | --- | --- | --- | 4.5 | 4.2 |
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Benefits paid | (65.2) | (61.3) | (0.2) | --- | (13.7) | (13.7) |
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Ending fair value | 400.7 | 410.1 | --- | --- | 76.0 | 71.7 |
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Funded status at end of year | $ (12.9) | $ (55.1) | $ (0.8) | $ (0.4) | $ (103.2) | $ (116.3) |
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Net Periodic Benefit Cost
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| Restoration of Retirement | Postretirement | ||||||
| Pension Plan | Income Plan | Benefit Plans | ||||||
Year ended December 31 |
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(In millions) | 2007 | 2006 | 2005 | 2007 | 2006 | 2005 | 2007 | 2006 | 2005 |
Service cost | $ 13.8 | $ 13.4 | $ 12.7 | $ --- | $ --- | $ --- | $ 2.7 | $ 2.6 | $ 2.3 |
Interest cost | 25.6 | 24.7 | 24.6 | --- | --- | --- | 10.4 | 10.0 | 8.9 |
Return on plan assets | (34.5) | (30.4) | (27.4) | --- | --- | --- | (5.7) | (5.5) | (5.2) |
Amortization of transition |
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obligation | --- | --- | --- | --- | --- | -- | 2.5 | 2.5 | 2.5 |
Amortization of net loss | 8.4 | 13.4 | 11.7 | --- | --- | --- | 5.5 | 7.6 | 4.5 |
Amortization of recognized |
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prior service cost | 4.5 | 4.6 | 5.1 | 0.1 | 0.1 | 0.1 | 1.5 | 1.5 | 1.5 |
Settlement | 13.3 | 13.3 | --- | 0.1 | --- | --- | --- | --- | --- |
Net periodic benefit cost (A) | $ 31.1 | $ 39.0 | $ 26.7 | $ 0.2 | $ 0.1 | $ 0.1 | $ 16.9 | $ 18.7 | $ 14.5 |
(A) Approximately $8.3 million of the Company’s net periodic benefit cost related to the Company’s Oklahoma jurisdiction has been recorded as a regulatory asset (see Note 1 for a further discussion). In addition, Energy Corp. allocated approximately $1.8 million in pension expense to the Company in 2007. The capitalized portion of the net periodic pension benefit cost was approximately $5.2 million, $7.2 million and $8.3 million at December 31, 2007, 2006 and 2005, respectively. The capitalized portion of the net periodic postretirement benefit cost was approximately $4.5 million, $5.6 million and $4.7 million at December 31, 2007, 2006 and 2005, respectively. |
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Rate Assumptions
| Pension Plan and | Postretirement | ||||
| Restoration of Retirement Income Plan | Benefit Plans | ||||
Year ended December 31 | 2007 | 2006 | 2005 | 2007 | 2006 | 2005 |
Discount rate | 6.25% | 5.75% | 5.50% | 6.25% | 5.75% | 5.50% |
Rate of return on plans’ assets | 8.50% | 8.50% | 8.50% | 8.50% | 8.50% | 8.50% |
Compensation increases | 4.50% | 4.50% | 4.50% | 4.50% | 4.50% | 4.50% |
Assumed health care cost trend: |
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Initial trend | N/A | N/A | N/A | 9.00% | 9.00% | 9.00% |
Ultimate trend rate | N/A | N/A | N/A | 4.50% | 4.50% | 4.50% |
Ultimate trend year | N/A | N/A | N/A | 2013 | 2012 | 2011 |
N/A - not applicable
The overall expected rate of return on plan assets assumption remained at 8.50 percent in 2006 and 2007 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.
Post-Employment Benefit Plan
Disabled employees receiving benefits from Energy Corp.’s Group Long-Term Disability Plan are entitled to continue participating in the Company’s Medical Plan along with their dependents. The post-employment benefit obligation represents the actuarial present value of estimated future medical benefits that are attributed to employee service rendered prior to the date as of which such information is presented. The obligation also includes future medical benefits expected to be paid to current employees participating in Energy Corp.’s Group Long-Term Disability Plan and their dependents, as defined in Energy Corp.’s Medical Plan.
The post-employment benefit obligation is determined by an actuary on a basis similar to the accumulated postretirement benefit obligation. The estimated future medical benefits are projected to grow with expected future medical cost trend rates and are discounted for interest at the discount rate and for the probability that the participant will discontinue receiving benefits from Energy Corp.’s Group Long-Term Disability Plan due to death, recovery from disability, or eligibility for retiree medical benefits. The Company’s post-employment benefit obligation was approximately $1.3 million and $1.5 million at December 31, 2007 and 2006, respectively.
Defined Contribution Plan
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. contributes 100 percent of the Regular Contributions deposited during such pay period by such participant. No Energy Corp.
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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 $4.7 million, $4.2 million and $4.2 million during 2007, 2006 and 2005, respectively, to the defined contribution plan.
Deferred Compensation 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 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.
Supplemental Executive Retirement Plan
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.
12. | Commitments and Contingencies |
Operating Lease Obligations
Future minimum payments for the noncancellable operating lease for railcars are as follows:
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| 2013 and |
Year ended December 31 (In millions) | 2008 | 2009 | 2010 | 2011 | 2012 | Beyond |
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Railcars | $ 3.7 | $ 3.7 | $ 3.6 | $ 34.9 | $ --- | $ --- |
Payments for operating lease obligations were approximately $3.9 million, $4.2 million and $5.4 million in 2007, 2006 and 2005, respectively.
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Railcar Lease Agreement
At December 31, 2007, the Company had a noncancellable operating lease with purchase options, covering 1,409 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 $28.8 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.
Public Utility Regulatory Policy Act of 1978
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”). See Note 13 for discussion of a recent FERC ruling related to QF obligations. 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 had a QF contract for approximately 110 MWs that expired at the end of 2007 and was not extended by the Company. For the AES-Shady Point, Inc. (“AES”) QF contract for 320 MWs, the Company purchases 100 percent of the electricity generated by the QF. In addition, effective September 1, 2004, the Company entered into a new 15-year power purchase agreement for 120 MWs with Powersmith Cogeneration Project, L.P. (“PowerSmith”) in which the Company purchases 100 percent of electricity generated by PowerSmith.
During 2007, 2006 and 2005, the Company made total payments to cogenerators of approximately $156.8 million, $162.6 million and $183.8 million, respectively, of which approximately $88.9 million, $94.9 million and $95.5 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: 2008 – $88.4 million, 2009 – $86.8 million, 2010 – $85.0 million, 2011 – $83.1 million and 2012 – $81.0 million.
Fuel Minimum Purchase Commitments
The Company purchased necessary fuel supplies of coal and natural gas for its generating units of approximately $190.2 million, $195.1 million and $163.5 million for the years ended December 31, 2007, 2006 and 2005, respectively. The Company has entered into purchase commitments of necessary fuel supplies of approximately: 2008 – $115.1 million, 2009 – $110.2 million, 2010 – $114.3 million, 2011 – $65.3 million, 2012 – $4.0 million and 2013 and Beyond – $19.6 million.
Natural Gas Units
In August 2007, the Company issued a request for proposal (“RFP”) for gas supply purchases for periods from November 2007 through March 2008, which accounted for approximately 15 percent of its projected 2008 natural gas requirements. The contracts resulting from this RFP are tied to various gas price market indices and will expire in 2008. Additional gas supplies to fulfill the Company’s remaining 2008 natural gas requirements will be acquired through additional RFPs in early to mid-2008, along with monthly and daily purchases, all of which are expected to be made at competitive market prices.
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Purchased Power
In March 2007, the Company issued an RFP for capacity and/or firm energy purchases for the summer periods of 2008, 2009 and/or 2010. In November 2007, the Company signed a purchase contract with Redbud for purchases in the summer periods of 2008 and 2009. The Company submitted notice of the contract to the OCC on January 2 and 3, 2008. Interventions and protests were due within 15 days of submission of the notice. No interventions or protests were received in this matter and the Company considers this purchase contract to be final. The purchase contract will be terminated if the acquisition of Redbud by the Company, the OMPA and the GRDA is completed as discussed in Note 13.
Natural Gas Measurement Cases
United States of America ex rel., Jack J. Grynberg v. Enogex Inc., Enogex Services Corporation and the Company. (U.S. 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. (U.S. District Court for the Eastern District of Louisiana, Case No. 97-2089; U.S. District Court for the Western District of Oklahoma, Case No. 97-1009M.). On June 15, 1999, the Company was served with the 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 Federal government, alleges: (a) 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; (b) certain provisions generally found in gas purchase contracts are improper; (c) transactions by affiliated companies are not arms-length; (d) excess processing cost deduction; and (e) 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 Federal government can intervene and take over such actions from the relator. The Department of Justice, on behalf of the Federal government, decided not to intervene in this action.
The 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 (“MDL”) 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 U.S. District court for the District of Wyoming.
In October 2002, the court granted the Department of Justice’s motion to dismiss certain of the plaintiff’s claims and issued an order dismissing the 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.
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 on various bases on January 8, 2007. The defendants also filed for other legal costs on December 18, 2006. A hearing on these motions was held on April 24, 2007, at which time the judge took these motions under advisement. Grynberg has also filed appeals with the Tenth Circuit Court of Appeals. In compliance with the Tenth Circuit’s June 19, 2007 scheduling order, Grynberg filed appellants’ opening brief on July 31, 2007 and the appellees’ consolidated response briefs were filed on November 21, 2007. Also, on December 5, 2007, Energy Corp. filed a notice of its intent to file a separate response brief, which Energy Corp. filed on January 11, 2008. At this time, oral arguments are preliminarily scheduled for the week of September 22, 2008. The Company intends to
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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, et al. v. El Paso Natural Gas Co., et al. (Price I). On September 24, 1999, various subsidiaries of Energy Corp. were served with a class action petition filed in the District Court of Stevens County, Kansas by Quinque Operating Company and other named plaintiffs alleging the mismeasurement of natural gas on non-federal lands. On April 10, 2003, the court entered an order denying class certification. On May 12, 2003, the plaintiffs (now Will Price, Stixon Petroleum, Inc., Thomas F. Boles and the Cooper Clark Foundation, on behalf of themselves and other royalty interest owners) filed a motion seeking to file an amended class action petition, and the court granted the motion on July 28, 2003. In its amended petition (the “Fourth Amended Petition”), the Company and Enogex Inc. were omitted from the case but two of Energy Corp.’s subsidiary entities remained as defendants. The plaintiffs’ Fourth Amended Petition seeks class certification and alleges that approximately 60 defendants, including two of Energy Corp.’s subsidiary entities, have improperly measured the volume of natural gas. The Fourth Amended Petition asserts theories of civil conspiracy, aiding and abetting, accounting and unjust enrichment. In their briefing on class certification, the plaintiffs seek to also allege a claim for conversion. The plaintiffs seek unspecified actual damages, attorneys’ fees, costs and pre-judgment and post-judgment interest. The plaintiffs also reserved the right to seek punitive damages.
Discovery was conducted on the class certification issues, and the parties fully briefed these same issues. A hearing on class certification issues was held April 1, 2005. In May 2006, the court heard oral argument on a motion to intervene filed by Colorado Consumers Legal Foundation, which is claiming entitlement to participate in the putative class action. The court has not yet ruled on the motion to intervene.
On July 2, 2007, the court ordered the plaintiffs and defendants to file proposed findings of facts and conclusions of law on class certification by July 31, 2007. On July 31, 2007, the two subsidiary entities of Energy Corp. filed their proposed findings of fact and conclusions of law regarding conflict of law issues and the coordinated defendants filed their proposed findings of facts and conclusions of law on class certification.
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.
Calpine Corporation Bankruptcy
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, Southern District of New York. A Calpine-owned power generation plant in Oklahoma is contractually obligated to provide capacity and energy to the Company; however, the contract terminated on December 31, 2007. The Calpine plant also pays, through the SPP, for transmission services provided by the Company. Whether Calpine will subsequently continue to require transmission services from the Company is unknown.
Environmental Laws and Regulations
Approximately $36.0 million and $120.5 million, respectively of the Company’s capital expenditures budgeted for 2008 and 2009 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 $94.7 million during 2008 as compared to approximately $63.5 million in 2007. 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.
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Air
On March 15, 2005, the U.S. Environmental Protection Agency (“EPA”) issued the Clean Air Mercury Rule (“CAMR”) to limit mercury emissions from coal-fired boilers. On February 8, 2008, the U.S. Court of Appeals for the D.C. Circuit Court vacated the rule. One possible consequence is that the EPA will develop regulations that are more stringent than the CAMR and the trading of mercury allowances will not be allowed. Until the rule was vacated, the CAMR required mercury monitoring to begin in 2009. Accordingly, the Company is in the process of installing mercury monitoring equipment on all five of its coal units. The cost of the monitoring equipment was approximately $5.0 million in 2007 and the Company expects to spend approximately $0.7 million in 2008. Because the CAMR was vacated, the cost to install additional mercury controls is uncertain at this time but may be significant, particularly if the EPA develops more stringent requirements. The outcome of the CAMR ruling does not preclude states from developing more stringent mercury reduction requirements. In 2006, the State of Oklahoma proposed to incorporate the EPA’s CAMR, along with the proposed mercury allowance allocations, into the state implementation program. In January 2008, in response to citizen requests, the Oklahoma Department of Environmental Quality (“ODEQ”) proposed three options for regulation of mercury emissions. As initially proposed, one option recommended by the ODEQ Staff was that the CAMR be incorporated by reference into the state implementation plan. The other two options are intended to be more restrictive than the recently vacated federal CAMR. In general, the proposed options include provisions that mercury trading will not be allowed, higher levels of mercury control will be required and compliance timelines may be shortened in comparison with the CAMR Promulgation of an Oklahoma rule may be further delayed if the ODEQ decides to wait for the EPA to re-promulgate a federal mercury rule. The Company will continue to participate in the state rule making process.
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 to address these visibility impacts.
In September 2005, the 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. Based on this modeling, the ODEQ made a preliminary determination to accept an application for a waiver for the Horseshoe Lake generating station. The Horseshoe Lake waiver is expected to be included in the ODEQ state implementation plan. The due date for the ODEQ submission of the state implementation plan was December 17, 2007; however, the ODEQ has not yet submitted a plan to the EPA for approval. It is not known whether approval for the state implementation plan will be granted by the EPA.
The modeling did not support waivers for the affected units at the Seminole, Muskogee and Sooner generating stations. The Company submitted a BART compliance plan for Seminole on March 30, 2007 committing to installation of nitrogen oxide (“NOX”) controls on all three units. At the same time, the Company submitted a determination to the ODEQ that an alternative compliance plan for the affected units at the Muskogee and Sooner power plants will achieve overall greater visibility improvement than BART in the affected Class I areas and the alternative plan extends the timeline for compliance to 2018. The estimated cost for this alternative plan and the BART compliance plan for the Seminole power plant is approximately $470 million. The alternative compliance plan includes installing semi-dry scrubbers on three of four affected coal units and low NOX burner equipment on all four coal units. This alternative plan was subject to approval by the ODEQ and the EPA. The EPA provided an opinion to the ODEQ that the Company’s alternative compliance plan does not meet the requirements of the regional haze rules. On November 16, 2007, the ODEQ notified the Company that additional analysis will be required before the Company BART plan can be accepted. As required by the ODEQ, the Company has initiated the additional analysis with a projected completion date of March 1, 2008. Until a compliance plan has been approved by the EPA, which is expected by December 31, 2008, the annual cost of compliance remains unknown at this time. The cost to comply with the regional haze regulations could increase substantially based on the interpretation of the requirements
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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.
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 2007 were approximately 0.32 lbs/MMBtu. The regulations require that the Company achieve a NOX emission level of 0.40 lbs/MMBtu for these boilers beginning in 2008. It is expected that NOX emissions will be further reduced to 0.15 lbs/MMBtu by 2016 if the regional haze compliance plan discussed above is approved by the EPA. Further reductions in NOX emissions could be required if the ODEQ determines that such NOX emissions are impacting 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 likely require significant capital and operating expenditures.
Currently, the EPA has designated Oklahoma “in attainment” with the ambient standard for ozone. However, future elevated readings could lead to redefinition of these areas as non-attainment. Both Tulsa and Oklahoma City have entered into an “Early Action Compact” with the EPA whereby voluntary measures are required to be enacted to reduce the impact of ambient levels of ozone. This compact expired in December 2007. However, a similar program called Ozone Flex began in January 2008 in which both Oklahoma City and Tulsa are participating. Currently, the EPA is reevaluating the current ozone standard and proposed further reductions in the ambient standard on September 20, 2007. The Company cannot predict the final outcome of this evaluation or its timing or affect on the Company’s operations.
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 this demonstration and Oklahoma does not affect air quality in downwind states. The demonstration was properly submitted by the state to the EPA on May 7, 2007, and additional information was submitted by the state to EPA on December 5, 2007. Assuming the state implementation plan is approved as submitted, there should be no significant adverse impact to the Company as a result of the April 25, 2005 finding. The date of EPA approval is currently unknown.
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 chimney. 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 2007, the Company’s SO2 emissions were below the allowable limits.
The EPA allocated SO2 allowances to the Company starting in 2000 and the Company started banking allowances in 2001. The Company sold no banked allowances in 2007. Also, during 2007, the Company received
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proceeds of approximately $0.5 million from the annual EPA spot (year 2007) and seven-year advance (year 2014) allowance auctions that were held in March 2007.
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, 2007, 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 2007. In January 2008, the ODEQ proposed a fee increases of approximately 28 percent for Title V sources. These fee increases were approved by the Oklahoma Air Quality Advisory Council on February 5, 2008. The final outcome of this measure is dependent upon approval by the ODEQ Board and the Oklahoma state legislature. If approved, the fee increases will be effective July 1, 2008.
In addition to the requirements related to emissions of SO2, NOX and mercury discussed above, there is a growing concern nationally and internationally about global climate change and the contribution of emissions of greenhouse gases including, most significantly, carbon dioxide. This concern has led to increased interest in legislation at the federal level, actions at the state level, as well as litigation relating to greenhouse gas emissions, including a recent U.S. Supreme Court decision holding that the EPA has the authority to regulate carbon dioxide emissions from motor vehicles under the Clean Air Act. Increased pressure for carbon dioxide emissions reduction also is coming from investor organizations and the international community.
On the legislative front, in June 2005, the U.S. Senate adopted a resolution declaring that mandatory reductions in greenhouse gases are needed. Despite executive branch opposition to any mandatory requirements, several bills that would cap or tax greenhouse gases from electric utilities are being considered by Congress, and the concept of such regulation has received support from the majority leadership in both the U.S. Senate and U.S. House of Representatives.
Oklahoma and Arkansas have not, at this time, established any mandatory programs to regulate carbon dioxide and other greenhouse gases. However, government officials in these states have declared support for state and federal action on climate change issues. The Company reports quarterly its carbon dioxide emissions and is continuing to evaluate various options for reducing, avoiding, off-setting or sequestering its carbon dioxide emissions. If legislation or regulations are passed at the federal or state levels in the future requiring mandatory reductions of carbon dioxide and other greenhouse gases on generation facilities to address climate change, this could result in significant additional compliance costs that would affect our future financial position, results of operations and cash flows if such costs are not recovered through regulated rates.
Waste
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 2007, the Company obtained refunds of approximately $1.0 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.
Water
The Company received two Oklahoma Pollutant Discharge Elimination System (“OPDES”) permits in February 2008. The Company is currently reviewing these permits to determine if they are reasonable in their 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. This new permit was issued in the fourth 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 Section 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
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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 Section 316(b) rules on the Company. On January 25, 2007, a federal court reversed and remanded certain portions of the Section 316(b) rules to the EPA. On July 9, 2007, the EPA suspended these portions of the Section 316(b) rules for existing facilities. As a result of such suspension, permits required for existing facilities are to be developed by the individual states using their best professional judgment until the EPA completes its review of the suspended sections. In September 2007, the State of Oklahoma indicated that it was requiring a comprehensive demonstration study be submitted by January 7, 2008 for each affected facility. On January 7, 2008, the Company submitted the requested studies for its facilities. It is not clear what changes, if any, the EPA will ultimately make to the Section 316(b) rules or how those changes may affect the Company. Depending on the ultimate analysis and final determinations regarding the Section 316(b) rules and the Oklahoma comprehensive demonstration studies, capital and/or operating costs may increase at any affected Company generating facility.
Other
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. When appropriate, 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 13 below and in Item 3 of this Annual Report on 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.
13. | Rate Matters and Regulation |
Regulation and Rates
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, 2007, 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.
Completed Regulatory Matters
OCC Order Confirming Savings / Acquisition of McClain Power Plant
The 2002 Settlement Agreement required that, if the Company did not acquire electric generation of not less than 400 MW (“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. On July 9, 2004, the Company
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completed the acquisition of the McClain Plant which was intended to satisfy the requirement in the 2002 Settlement Agreement to acquire New Generation. On June 7, 2007, the Company filed an application with the OCC supporting its compliance with the 2002 Settlement Agreement. On November 21, 2007, the Company received an order from the OCC affirming that the acquisition of the McClain Plant provided savings to the Company’s Oklahoma customers in excess of the required $75 million over the three-year period from January 1, 2004 through December 31, 2006.
Security Enhancements
The Company 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 with an associated annual revenue requirement of approximately $2.7 million. On June 26, 2007, the OCC issued an order approving approximately $17.6 million of security capital expenditures and the associated revenue requirement of approximately $2.6 million, which the Company implemented during the first billing cycle of July 2007.
Review of the Company’s Fuel Adjustment Clause for Calendar Year 2005
The OCC routinely audits activity in the Company’s fuel adjustment clause for each calendar year. In October 2006, the OCC Staff filed an application for a review of the Company’s 2005 fuel adjustment clause. In September 2007, the OCC issued an order approving the fuel, purchased power and purchase gas adjustment clause cost recoveries for calendar year 2005.
Cogeneration Credit Rider
The Company’s cogeneration credit rider was initially implemented in 2005 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 cogeneration credit rider was 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 was automatically included in the next year’s rider. The Company filed an application with the OCC in September 2007 to request a new cogeneration credit rider for years after 2007 as the Company’s current cogeneration credit rider expired on December 31, 2007. In December 2007, the OCC issued an order approving a cogeneration credit rider that expires on December 31, 2009.
Wind Power Filing
In January 2007, the Company’s 120 MW Centennial wind farm was fully in service. As a result, on January 17, 2007, the Company sent notice of this to the OCC which triggered the recovery rider in the first billing cycle of February 2007. The recovery rider, which was previously approved in an OCC settlement, authorized recovery for up to $205 million in construction costs and allowance for funds used during construction and was designed to recover the lower of a capped or actual revenue requirement including a return on equity of 10.75 percent. The Company spent approximately $203.8 million related to the Centennial wind farm. The Company expects the recovery rider to remain in effect through late 2009. As indicated in the settlement agreement with the OCC related to the Company’s Centennial wind farm, the Company must file for a general rate review that will permit the OCC to issue an order no later than December 31, 2009.
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 January 5, 2007, the APSC issued an order providing for a $5.4 million annual increase in the Company’s electric rates, a 10.0 percent return on equity and the recovery of the Arkansas portion of the Centennial wind farm expenditures. The Arkansas rates became effective in February 2007.
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FERC Audit
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 FERC regulations. Over the past several years, the FERC has conducted numerous audits of utilities across the country to ensure regulatory compliance. On June 29, 2007, the FERC issued its final audit report with a limited set of findings and recommended certain actions that the Company has since implemented. Among its findings, the FERC concluded that the Company did not make the appropriate refunds to certain wholesale customers subsequent to the OCC issuing an order changing the amount of storage costs in the Company’s gas transportation and storage agreement with Enogex that are recoverable from Oklahoma retail customers. As a result, the Company recomputed billings made after May 2003 to certain wholesale customers and issued refunds in accordance with FERC regulations. The total amount of the refunds was approximately $1.0 million, including interest, which the Company had fully reserved on its books in December 2006.
Southwest Power Pool
In February 2007, the Company began participating in the SPP’s energy imbalance service market in a dual role as a load serving entity and as a generation owner. The energy imbalance service market requires cash settlements for over or under schedules of generation and load. Market participants, including the Company, are required to submit resource plans and can submit offer curves for each resource available for dispatch. A function of interchange accounting is to match participants’ MWH entitlements (generation plus scheduled bilateral purchases) against their MWH obligations (load plus scheduled bilateral sales) during every hour of every day. If the net result during any given hour is an entitlement, the participant is credited with a spot-market sale to the SPP at the respective market price for that hour; if the net result is an obligation, the participant is charged with a spot-market purchase from the SPP at the respective market price for that hour. The SPP purchases and sales are not allocated to individual customers. The Company records the hourly sales to the SPP at market rates in Operating Revenues and the hourly purchases from the SPP at market rates in Cost of Goods Sold in its Financial Statements.
FERC Ruling under PURPA
On September 25, 2007, as amended on October 24, 2007, the Company filed an application with the FERC seeking relief from its obligation to purchase electric energy and capacity from QFs with a net capacity greater than 20 MW as required by PURPA. The Energy Policy Act of 2005 established a process that allows utilities to terminate the mandatory purchase obligation in certain circumstances. In an order dated January 22, 2008, the FERC found that the Company had met the aforementioned standard and granted the Company’s request. The order does not affect the Company’s existing QF contracts with AES and PowerSmith; however, it does grant the Company an exemption from any purchase obligations otherwise arising under PURPA after the date of filing of the Company’s application.
Pending Regulatory Matters
Proposed Acquisition of Power Plant
On January 21, 2008, the Company entered into a Purchase and Sale Agreement (“Purchase and Sale Agreement”) with Redbud Energy I, LLC, Redbud Energy II, LLC and Redbud Energy III, LLC (“Redbud Sellers”), which are indirectly owned by Kelson Holdings LLC, a subsidiary of Harbinger Capital Partners Master Fund I, Ltd. and Harbinger Capital Partners Special Situations Fund, L.P. Pursuant to the Purchase and Sale Agreement, the Company agreed to acquire from the Redbud Sellers the entire partnership interest in Redbud Energy LP which currently owns a 1,230 MW natural gas-fired, combined-cycle power generation facility in Luther, Oklahoma (“Redbud Facility”), for approximately $852 million, subject to working capital and inventory adjustments in accordance with the terms of the Purchase and Sale Agreement.
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In connection with the Purchase and Sale Agreement, the Company also entered into (i) an Asset Purchase Agreement (“Asset Purchase Agreement”) with the OMPA and the Grand River Dam Authority (“GRDA”), pursuant to which the Company agreed that it would, after the closing of the transaction contemplated by the Purchase and Sale Agreement, dissolve Redbud Energy LP and sell a 13 percent undivided interest in the Redbud Facility to the OMPA and sell a 36 percent undivided interest in the Redbud Facility to the GRDA, and (ii) an Ownership and Operating Agreement (“Ownership and Operating Agreement”) with the OMPA and the GRDA, pursuant to which the Company, the OMPA and the GRDA, following the completion of the transaction contemplated by the Asset Purchase Agreement, would jointly own the Redbud Facility and the Company will act as the operations manager and perform the day-to-day operation and maintenance of the Redbud Facility. Under the Ownership and Operating Agreement, each of the parties would be entitled to its pro rata share, which is equal to its respective ownership interest, of all output of the Redbud Facility and would pay its pro rata share of all costs of operating and maintaining the Redbud Facility, including its pro rata share of the operations manager’s general and administrative overhead allocated to the Redbud Facility.
The transactions described above are subject to the expiration or termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act, an order from the FERC authorizing the contemplated transactions, an order from the OCC approving the prudence of the transactions and an appropriate reasonable recovery mechanism, and other customary conditions. The Company will not be obligated to complete the transactions if the orders from the FERC and the OCC contain any conditions or restrictions which are materially more burdensome than those proposed in the Company’s applications. Either the Company or the Redbud Sellers may terminate the Purchase and Sale Agreement if the closing has not occurred on or prior to November 16, 2008; provided that the Redbud Sellers have the option to extend such deadline for up to an additional 180 days if the sole reason the closing has not occurred is because the governmental and regulatory approvals have not been obtained. There can be no assurances that the transactions will be completed or as to its ultimate timing. The Company expects to file an application with the OCC in March 2008 asking the OCC to approve the prudency of the transactions and an appropriate reasonable recovery mechanism. The OCC rules provide that the OCC has up to 240 days to issue an order determining the Company’s pre-approval request. Absent a settlement, the earliest the Company expects an order from the OCC is November 2008.
Cancelled Red Rock Power Plant
On October 11, 2007, the OCC issued an order denying the Company and PSO’s request for pre-approval of their proposed 950 MW Red Rock power plant project. The plant, which was to be built at the Company’s Sooner plant site, was to be 42 percent owned by the Company, 50 percent owned by PSO and eight percent owned by the OMPA. As a result, on October 11, 2007, the Company, PSO and the OMPA agreed to terminate agreements to build and operate the plant. At December 31, 2007, the Company had incurred approximately $17.5 million of capitalized costs associated with the Red Rock power plant project. In December 2007, the Company filed an application with the OCC requesting authorization to defer, and establish a method of recovery of, approximately $14.7 million of Oklahoma jurisdictional costs associated with the Red Rock power plant project that are currently reflected in Deferred Charges and Other Assets on the Company’s Balance Sheets. If the request for deferral is not approved, the deferred costs will be expensed. In February 2008, the OCC issued a procedural schedule with a hearing scheduled for May 7, 2008. The Company expects to receive an order from the OCC in this matter by the end of 2008.
Review of the Company’s Fuel Adjustment Clause for Calendar Year 2006
The OCC routinely audits activity in the Company’s fuel adjustment clause for each calendar year. In September 2007, the OCC Staff filed an application for a prudence review of the Company’s 2006 fuel adjustment clause. The Company is required to provide minimum filing requirements (“MFR”) within 60 days of the application; however, the Company requested and was granted an extension to file the MFRs by January 15, 2008, on which date the MFRs were submitted by the Company’s. In February 2008, the OCC issued a procedural schedule with a hearing scheduled for August 21, 2008. The Company expects to receive an order from the OCC in this matter by the end of 2008.
88
FERC Formula Rate Filing
On November 30, 2007, the Company made a filing at the FERC to increase its transmission rates to wholesale customers moving electricity on the Company’s transmission lines. Interventions and protests were due by December 21, 2007. While several parties filed motions to intervene in the docket, only the OMPA filed a protest to the contents of the Company’s filing. The Company filed an answer to the OMPA’s protest on January 7, 2008. On January 31, 2008, the FERC issued an order (i) conditionally accepting the rates; (ii) suspending the effectiveness of such rates for five months, to be effective July 1, 2008, subject to refund; (iii) establishing hearing and settlement judge procedures; and (iv) directing the Company to make a compliance filing. The first settlement conference was held on February 20, 2008. Another settlement conference is scheduled for May 9, 2008.
Market-Based Rate Authority
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’s control area. The Company and OERI provided an explanation as to why their failure of the market share screen in the Company’s 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’s 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’s 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’s control area. The FERC also expanded the scope of the proposed mitigation to all sales made within the Company’s control area (instead of only to sales sinking to load within the Company’s 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
89
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 the Company’s 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. On March 9, 2007, the FERC accepted the Company’s and OERI’s change of status filing. On June 21, 2007, the FERC issued a final rule codifying and revising standards for market-based rate sales of electric energy, capacity and ancillary services. This final rule clarifies the scope of the mitigation applicable to sales within the Company’s control area. The Company began complying with the final rule and must formally incorporate certain provisions into its market-based rate tariff the next time the Company proposes a tariff change, makes a change in status filing or submits an updated market power analysis.
North American Electric Reliability Council
The Energy Policy Act of 2005 gave the FERC authority to establish mandatory electric reliability rules enforceable with monetary penalties. The FERC approved the North American Electric Reliability Council (“NERC”) as the Electric Reliability Organization for North America and delegated to it the development and enforcement of electric transmission reliability rules. On April 19, 2007, the FERC approved the SPP as a Regional Entity whose primary function is to review and enforce compliance of reliability standards with all registered entities in the region. In March 2007, the FERC approved mandatory NERC reliability standards which became effective June 18, 2007. In June 2007, the Company completed a NERC readiness evaluation. The Company received the evaluation report from the NERC in December 2007 and has already implemented several of the recommendations. The Company is subject to a NERC readiness evaluation and compliance audit every three years. The next compliance audit is scheduled for 2008 and the next readiness evaluation is scheduled for 2010.
National Legislative Initiatives
In December 2007, the United States Congress passed and the President signed into law the Energy Independence and Security Act of 2007. Among other things, that legislation aims to create significant changes in the use of energy in the United States in the transportation and electric utility sectors. With regard to the impact on the utility sector in general and the Company in particular, the new energy law has a large number of provisions designed to increase the efficiency with which electricity is used in homes, as well as in commercial and industrial applications. New federal electric efficiency standards are to be developed and imposed on a wide range of appliances and equipment, buildings and manufacturing facilities. In addition, beyond direct action mandated to be taken by federal agencies to incentivize increased use of combined heat and power systems, cogeneration and demand response programs, the legislation also directs state public utility commissions to consider imposing similar proposals on utilities operating within the states’ retail jurisdiction. Collectively, these provisions of the new law are intended to lower demand growth in the electricity sector through efficiency gains and reduce air emissions associated with the generation of electricity by utilities and the use of electricity by virtually every customer segment in the economy.
In December 2007, the United States Senate Environmental and Public Works Committee reported a bill to impose a federal “cap and trade” regime to control greenhouse gas emissions in this country. The legislation would impose significant regulatory and cost burdens on the utility sector, especially for those utilities like the Company with coal-based generation. The Senate leadership intends to present the bill in 2008. In the United States House of Representatives, the Democratic leadership also aspires to have a global climate bill in 2008, with the intent to reach a final bill with the Senate that can be presented to the President before the end of 2008.
State Legislative Initiatives
In the 2007 legislative session, legislation was introduced in the Oklahoma legislature which proposed that electric utilities record fuel or natural gas removed from storage or stockpiles using the weighted-average cost method of accounting for inventory. Historically, the Company has used the LIFO method of accounting for inventory removed from storage or stockpiles. This legislation passed the legislature and was signed into law on June 5, 2007 and was effective January 1, 2008. The Company filed an application with the OCC in September
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2007 to address the accounting issues for the change in accounting for fuel inventory. In December 2007, the OCC issued an order approving the change in accounting for fuel inventory effective January 1, 2008. This change in accounting for fuel inventory is not expected to have a material impact on the Company’s financial position or results of operations.
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.
Summary
The Energy Policy Act of 2005, 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.
14. | Fair Value of Financial Instruments |
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:
| 2007 |
| 2006 | ||
| Carrying | Fair |
| Carrying | Fair |
December 31 (In millions) | Amount | Value |
| Amount | Value |
Price Risk Management Assets |
|
|
|
|
|
Interest Rate Swap | $ --- | $ --- |
| $ 0.9 | $ 0.9 |
|
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|
|
|
Price Risk Management Liabilities |
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|
|
Interest Rate Swap | $ 1.7 | $ 1.7 |
| $ --- | $ --- |
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Long-Term Debt |
|
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|
|
Senior Notes | $ 708.0 | $ 729.2 |
| $ 707.9 | $ 725.0 |
Industrial Authority Bonds | 135.4 | 135.4 |
| 135.4 | 135.4 |
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 generally based on quoted market prices. The fair value of the Company’s long-term debt is based on quoted market prices.
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Stockholder
Oklahoma Gas and Electric Company
We have audited the accompanying balance sheets and statements of capitalization of Oklahoma Gas and Electric Company as of December 31, 2007 and 2006, and the related statements of income, changes in stockholder’s equity, and cash flows for each of the three years in the period ended December 31, 2007. Our audits also included the financial statement schedule listed in the Index at Item 15(a). These financial statements and schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Oklahoma Gas and Electric Company at December 31, 2007 and 2006, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2007, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Oklahoma Gas and Electric Company’s internal control over financial reporting as of December 31, 2007, 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 26, 2008 expressed an unqualified opinion thereon.
As discussed in Notes 1, 3, 7 and 11 to the financial statements, in 2006 the Company adopted Statement of Financial Accounting Standards No. 123 (Revised), “ShareBased Payment,” and Statement of Financial Accounting Standards No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans,” and in 2007, the Company adopted Financial Accounting Standards Board Interpretation No. 48, “Accounting for Uncertainty in Income Taxes.”
| /s/ Ernst & Young LLP |
| Ernst & Young LLP |
Oklahoma City, Oklahoma
February 26, 2008
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Supplementary Data
Interim Financial Information (Unaudited)
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) |
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| Mar 31 |
| Jun 30 |
| Sep 30 |
| Dec 31 |
| Total | ||
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Operating revenues | 2007 | $ | 340.7 | $ | 429.9 | $ | 633.2 | $ | 431.3 | $ | 1,835.1 | ||
| 2006 | $ | 374.0 | $ | 444.7 | $ | 608.7 | $ | 318.3 | $ | 1,745.7 | ||
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Operating income (loss) | 2007 | $ | 16.0 | $ | 66.6 | $ | 178.7 | $ | 30.7 | $ | 292.0 | ||
| 2006 | $ | 9.8 | $ | 88.8 | $ | 195.5 | $ | (0.2) | $ | 293.9 | ||
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Net income (loss) | 2007 | $ | 1.9 | $ | 35.1 | $ | 109.0 | $ | 15.7 | $ | 161.7 | ||
| 2006 | $ | (1.1) | $ | 44.0 | $ | 107.4 | $ | (1.0) | $ | 149.3 | ||
In January 2007, the Company determined that the approved tariffs in its December 12, 2005 OCC rate case order 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 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 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.
| None. |
Item 9A. Controls and Procedures.
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).
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Management’s Report on Internal Control Over Financial Reporting
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, 2007. 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, 2007, 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 the Company’s internal control over financial reporting. This report appears on the following page.
/s/ Peter B. Delaney |
| /s/ Danny P. Harris |
Peter B. Delaney, Chairman of the Board, President |
| Danny P. Harris, Senior Vice 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 |
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Stockholder
Oklahoma Gas and Electric Company
We have audited Oklahoma Gas and Electric Company’s internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Oklahoma Gas and Electric Company’s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance
regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, Oklahoma Gas and Electric Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007, 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, 2007 and 2006, and the related statements of income, changes in stockholder’s equity, and cash flows for each of the three years in the period ended December 31, 2007 of Oklahoma Gas and Electric Company and our report dated February 26, 2008 expressed an unqualified opinion thereon.
| /s/ Ernst & Young LLP |
| Ernst & Young LLP |
Oklahoma City, Oklahoma
February 26, 2008
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Item 9B. Other Information.
None.
| PART III |
Item 10. Directors, Executive Officers and Corporate Governance.
CODE OF ETHICS POLICY
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.
Under the reduced disclosure format permitted by General Instruction I(2)(c) of Form 10-K, the information otherwise required by Item 10 has been omitted.
Item 11. Executive Compensation.
Under the reduced disclosure format permitted by General Instruction I(2)(c) of Form 10-K, the information required by Item 11 has been omitted.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.
Under the reduced disclosure format permitted by General Instruction I(2)(c) of Form 10-K, the information required by Item 12 has been omitted.
Item 13. Certain Relationships and Related Transactions, and Director Independence.
Under the reduced disclosure format permitted by General Instruction I(2)(c) of Form 10-K, the information required by Items 13 has been omitted.
Item 14. Principal Accounting Fees and Services.
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.
Fees for Independent Auditors
Audit Fees
Total audit fees for 2007 were $2,302,000 for Energy Corp.’s 2007 financial statement audit. These fees include $595,000 for the audit of internal control over financial reporting pursuant to the requirements of Sarbanes-Oxley section 404 and $332,000 for services in support of debt and stock offerings. Total audit fees for 2006 were $1,996,069 for Energy Corp.’s 2006 financial statement audit. These fees include $682,669 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.
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 2007, this amount includes estimated billings for the completion of the 2007 audit, which were rendered after year-end.
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Audit-Related Fees
The aggregate fees billed for audit-related services for the fiscal year ended December 31, 2007 were $112,000, of which $94,500 was for employee benefit plan audits and $17,500 for other audit-related services.
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.
Tax Fees
The aggregate fees billed for tax services for the fiscal year ended December 31, 2007 were $363,590. These fees include $160,765 for tax preparation and compliance ($65,960 for the review of federal and state tax returns and $94,805 for assistance with examinations and other return issues) and $202,825 for other tax 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.
All Other Fees
| These were no other fees billed to Energy Corp. in 2007 and 2006 for other services. |
Audit Committee Pre-Approval Procedures
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 2007, 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.
PART IV
Item 15. Exhibits, Financial Statement Schedules.
(a) 1. Financial Statements
The following financial statements and supplementary data are included in Part II, Item 8 of this Annual Report:
• | Balance Sheets at December 31, 2007 and 2006 |
• | Statements of Capitalization at December 31, 2007 and 2006 |
• | Statements of Income for the years ended December 31, 2007, 2006 and 2005 |
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• | Statements of Stockholder’s Equity for the years ended December 31, 2007, 2006 and 2005 |
• | Statements of Cash Flows for the years ended December 31, 2007, 2006 and 2005 |
• | Notes to Financial Statements |
• | Report of Independent Registered Public Accounting Firm (Audit of Financial Statements) |
• | Management’s Report on Internal Control Over Financial Reporting |
• | Report of Independent Registered Public Accounting Firm (Audit of Internal Control) |
Supplementary Data
• | Interim Financial Information |
2. Financial Statement Schedule (included in Part IV) | Page |
| Schedule II - Valuation and Qualifying Accounts | 106 |
All other schedules have been omitted since the required information is not applicable or is not material, or because the information required is included in the respective financial statements or notes thereto.
3. Exhibits
Exhibit No. | Description |
1.01 | Underwriting Agreement, dated January 4, 2006 between the Company and J.P. Morgan Securities Inc. and Wachovia Capital Markets, LLC, on behalf of themselves and the other underwriters named therein relating to $110,000,000 in aggregate principal amount of the Company’s 5.15% Senior Notes, Series due January 15, 2016 and $110,000,000 in aggregate principal amount of its 5.75% Senior Notes, Series due January 15, 2036 (collectively, the “Senior Notes”).Filed as Exhibit 1.01 to the Company’s Form 8-K filed January 6, 2006 (File No. 1-1097) and incorporated by reference herein) |
1.02 | Underwriting Agreement, dated January 28, 2008 between the Company and Greenwich Capital Markets Inc. and BNY Capital Markets, Inc., on behalf of themselves and the other underwriters named therein relating to $200,000,000 in aggregate principal amount of the Company’s 6.45% Senior Notes, Series due February 1, 2038 (the “Senior Notes”). (Filed as Exhibit 1.01 to the Company’s Form 8-K filed January 31, 2008 (File No. 1-1097) and incorporated by reference herein) |
2.01 | Asset Purchase Agreement, dated as of August 18, 2003 by and between the Company and NRG McClain LLC. (Certain exhibits and schedules were omitted and registrant agrees to furnish supplementally a copy of such omitted exhibits and schedules to the Commission upon request) (Filed as Exhibit 2.01 to Energy Corp.’s Form 8-K filed August 20, 2003 (File No. 1-12579) and incorporated by reference herein) |
2.02 | Amendment No. 1 to Asset Purchase Agreement, dated as of October 22, 2003 by and between the Company and NRG McClain LLC. (Filed as Exhibit 2.03 to Energy Corp.’s Form 10-K for the year ended December 31, 2003 (File No. 1-12579) and incorporated by reference herein) |
2.03 | Amendment No. 2 to Asset Purchase Agreement, dated as of October 27, 2003 by and between the Company and NRG McClain LLC. (Filed as Exhibit 2.04 to Energy Corp.’s Form 10-K for the year ended December 31, 2003 (File No. 1-12579) and incorporated by reference herein) |
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2.04 | Amendment No. 3 to Asset Purchase Agreement, dated as of November 25, 2003 by and between the Company and NRG McClain LLC. (Filed as Exhibit 2.05 to Energy Corp.’s Form 10-K for the year ended December 31, 2003 (File No. 1-12579) and incorporated by reference herein) |
2.05 | Amendment No. 4 to Asset Purchase Agreement, dated as of January 28, 2004 by and between the Company and NRG McClain LLC. (Filed as Exhibit 2.06 to Energy Corp.’s Form 10-K for the year ended December 31, 2003 (File No. 1-12579) and incorporated by reference herein) |
2.06 | Amendment No. 5 to Asset Purchase Agreement, dated as of February 13, 2004 by and between the Company and NRG McClain LLC. (Filed as Exhibit 2.07 to Energy Corp.’s Form 10-K for the year ended December 31, 2003 (File No. 1-12579) and incorporated by reference herein) |
2.07 | Amendment No. 6 to Asset Purchase Agreement, dated as of March 12, 2004 by and between the Company and NRG McClain LLC. (Filed as Exhibit 2.01 to Energy Corp.’s Form 10-Q for the quarter ended March 31, 2004 (File No. 1-12579) and incorporated by reference herein) |
2.08 | Amendment No. 7 to Asset Purchase Agreement, dated as of April 15, 2004 by and between the Company and NRG McClain LLC. (Filed as Exhibit 2.02 to Energy Corp.’s Form 10-Q for the quarter ended March 31, 2004 (File No. 1-12579) and incorporated by reference herein) |
2.09 | Amendment No. 8 to Asset Purchase Agreement, dated as of May 15, 2004 by and between the Company and NRG McClain LLC. (Filed as Exhibit 2.01 to Energy Corp.’s Form 10-Q for the quarter ended June 30, 2004 (File No. 1-12579) and incorporated by reference herein) |
2.10 | Amendment No. 9 to Asset Purchase Agreement, dated as of June 2, 2004 by and between the Company and NRG McClain LLC. (Filed as Exhibit 2.02 to Energy Corp.’s Form 10-Q for the quarter ended June 30, 2004 (File No. 1-12579) and incorporated by reference herein) |
2.11 | Amendment No. 10 to Asset Purchase Agreement, dated as of June 17, 2004 by and between the Company and NRG McClain LLC. (Filed as Exhibit 2.03 to Energy Corp.’s Form 10-Q for the quarter ended June 30, 2004 (File No. 1-12579) and incorporated by reference herein) |
2.12 | Purchase and Sale Agreement, dated as of January 21, 2008, entered into by and among Redbud Energy I, LLC, Redbud Energy II, LLC and Redbud Energy III, LLC and the Company (Certain exhibits and schedules hereto have been omitted and the registrant agrees to furnish supplementally a copy of such omitted exhibits and schedules to the Commission upon request) (Filed as Exhibit 2.01 to Energy Corp.’s Form 8-K filed January 25, 2008 (File No. 1-12579) and incorporated by reference herein) |
2.13 | Asset Purchase Agreement, dated as of January 21, 2008, entered into by and among the Company, the Oklahoma Municipal Power Authority and the Grand River Dam Authority (Certain exhibits and schedules hereto have been omitted and the registrant agrees to furnish supplementally a copy of such omitted exhibits and schedules to the Commission upon request) (Filed as Exhibit 2.01 to Energy Corp.’s Form 8-K filed January 25, 2008 (File No. 1-12579) and incorporated by reference herein) |
3.01 | Copy of Restated Certificate of Incorporation. (Filed as Exhibit 4.01 to the Company’s Registration Statement No. 33-59805, and incorporated by reference herein) |
3.02 | Copy of Amended By-laws. (Filed as Exhibit 3.02 to Energy Corp.’s Form 8-K filed January 23, 2007 (File No. 1-12579) and incorporated by reference herein) |
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4.01 | Trust Indenture dated October 1, 1995, from the Company to Boatmen’s First National Bank of Oklahoma, Trustee. (Filed as Exhibit 4.29 to Registration Statement No. 33-61821 and incorporated by reference herein) |
4.02 | Supplemental Trust Indenture No. 1 dated October 16, 1995, being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 4.01 to the Company’s Form 8-K filed October 24, 1995 (File No. 1-1097) and incorporated by reference herein) |
4.03 | Supplemental Indenture No. 2, dated as of July 1, 1997, being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 4.01 to the Company’s Form 8-K filed July 17, 1997 (File No. 1-1097) and incorporated by reference herein) |
4.04 | Supplemental Indenture No. 3, dated as of April 1, 1998, being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 4.01 to the Company’s Form 8-K filed April 16, 1998 (File No. 1-1097) and incorporated by reference herein) |
4.05 | Supplemental Indenture No. 4, dated as of October 15, 2000, being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 4.02 to the Company’s Form 8-K filed October 20, 2000 (File No. 1-1097) and incorporated by reference herein) |
4.06 | Supplemental Indenture No. 5 dated as of October 24, 2001, being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 4.06 to Registration Statement No. 333-104615 and incorporated by reference herein) |
4.07 | Supplemental Indenture No. 6 dated as of August 1, 2004, being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 4.02 to the Company’s Form 8-K filed August 6, 2004 (File No 1-1097) and incorporated by reference herein) |
4.08 | Supplemental Indenture No. 7 dated as of January 1, 2006 being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 4.08 to the Company’s Form 8-K filed January 6, 2006 (File No. 1-1097) and incorporated by reference herein) |
4.09 | Supplemental Indenture No. 8 dated as of January 15, 2008 being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 4.01 to the Company’s Form 8-K filed January 31, 2008 (File No. 1-1097) and incorporated by reference herein) |
10.01 | Form of Change of Control Agreement for Officers of the Company and Energy Corp. (Filed as Exhibit 10.07 to Energy Corp.’s Form 10-K for the year ended December 31, 1996 (File No. 1-12579) and incorporated by reference herein) |
10.02 | Energy Corp.’s 1998 Stock Incentive Plan. (Filed as Exhibit 10.07 to Energy Corp.’s Form 10-K for the year ended December 31, 1998 (File No. 1-12579) and incorporated by reference herein) |
10.03 | Energy Corp.’s 2003 Stock Incentive Plan. (Filed as Annex A to Energy Corp.’s Proxy Statement for the 2003 Annual Meeting of Shareowners (File No. 1-12579) and incorporated by reference herein) |
10.04 | Energy Corp.’s Restoration of Retirement Income Plan, as amended by Amendments No. 1 and No. 2. (Filed as Exhibit 10.12 to Energy Corp.’s Form 10-K for the year ended December 31, 1996 (File No.1-12579) and incorporated by reference herein) |
10.05 | Amendment No. 3 to the Energy Corp. Restoration of Retirement Income Plan. (Filed as Exhibit 10.13 to Energy Corp.’s Form 10-K for the year ended December 31, 2000 (File No. 1-12579) and incorporated by reference herein) |
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10.06 | Amendment No. 4 to the Energy Corp. Restoration of Retirement Income Plan. (Filed as Exhibit 10.14 to Energy Corp.’s Form 10-K for the year ended December 31, 2000 (File No. 1-12579) and incorporated by reference herein) |
10.07 | Energy Corp. Supplemental Executive Retirement Plan, as amended by Amendment No. 1. (Filed as Exhibit 10.07 to Energy Corp.’s Form 10-K for the year ended December 31, 2004 (File No. 1-12579) and incorporated by reference herein) |
10.08 | Energy Corp.’s 2003 Annual Incentive Compensation Plan. (Filed as Annex B to Energy Corp.’s Proxy Statement for the 2003 Annual Meeting of Shareowners (File No. 1-12579) and incorporated by reference herein) |
10.09 | Energy Corp.’s Deferred Compensation Plan and Amendment No. 1 to Energy Corp.’s Deferred Compensation Plan. (Filed as Exhibit 10.12 to Energy Corp.’s Form 10-K for the year ended December 31, 2002 (File No. 1-12579) and incorporated by reference herein) |
10.10 | Copy of Settlement Agreement with Oklahoma Corporation Commission Staff, the Oklahoma Attorney General and others relating to the Company’s rate case. (Filed as Exhibit 99.02 to Energy Corp.’s Form 10-Q for the quarter ended September 30, 2002 (File No. 1-12579) and incorporated by reference herein) |
10.11 | Amended and Restated Facility Operating Agreement for the McClain Generating Facility dated as of July 9, 2004 between the Company and the Oklahoma Municipal Power Authority. (Filed as Exhibit 10.03 to Energy Corp.’s Form 10-Q for the quarter ended June 30, 2004 (File No. 1-12579) and incorporated by reference herein) |
10.12 | Amended and Restated Ownership and Operation Agreement for the McClain Generating Facility dated as of July 9, 2004 between the Company and the Oklahoma Municipal Power Authority. (Filed as Exhibit 10.04 to Energy Corp.’s Form 10-Q for the quarter ended June 30, 2004 (File No. 1-12579) and incorporated by reference herein) |
10.13 | Operating and Maintenance Agreement for the Transmission Assets of the McClain Generating Facility dated as of August 25, 2003 between the Company and the Oklahoma Municipal Power Authority. (Filed as Exhibit 10.05 to Energy Corp.’s Form 10-Q for the quarter ended June 30, 2004 (File No. 1-12579) and incorporated by reference herein) |
10.14 | Amendment No. 1 to Energy Corp.’s 2003 Stock Incentive Plan. (Filed as Exhibit 10.23 to Energy Corp.’s Form 10-K for the year ended December 31, 2004 (File No. 1-12579) and incorporated by reference herein) |
10.15 | Intrastate Firm No-Notice, Load Following Transportation and Storage Services Agreement dated as of May 1, 2003 between the Company and Enogex. [Confidential treatment has been requested for certain portions of this exhibit.] (Filed as Exhibit 10.24 to Energy Corp.’s Form 10-K for the year ended December 31, 2004 (File No. 1-12579) and incorporated by reference herein) |
10.16 | Amendment No. 5 to the Energy Corp. Restoration of Retirement Income Plan. (Filed as Exhibit 10.26 to Energy Corp.’s Form 10-K for the year ended December 31, 2004 (File No. 1-12579) and incorporated by reference herein) |
10.17 | Form of Non-Qualified Stock Option Agreement under Energy Corp.’s 2003 Stock Incentive Plan. (Filed as Exhibit 10.29 to Energy Corp.’s Form 10-K for the year ended December 31, 2004 (File No. 1-12579) and incorporated by reference herein) |
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10.18 | Form of Performance Unit Agreement under Energy Corp.’s 2003 Stock Incentive Plan. (Filed as Exhibit 10.30 to Energy Corp.’s Form 10-K for the year ended December 31, 2004 (File No. 1-12579) and incorporated by reference herein) |
10.19 | Form of Restricted Stock Agreement under Energy Corp.’s 2003 Stock Incentive Plan. (Filed as Exhibit 10.31 to Energy Corp.’s Form 10-K for the year ended December 31, 2004 (File No. 1-12579) and incorporated by reference herein) |
10.20 | Form of Split Dollar Agreement. (Filed as Exhibit 10.32 to Energy Corp.’s Form 10-K for the year ended December 31, 2004 (File No. 1-12579) and incorporated by reference herein) |
10.21 | Credit agreement dated December 6, 2006, by and between the Company, the Lenders thereto, Wachovia Bank, National Association, as Administrative Agent, JPMorgan Chase Bank, N.A., as Syndication Agent, and The Royal Bank of Scotland plc, Mizuho Corporate Bank and Union Bank of California, N.A., as Co-Documentation Agents. (Filed as Exhibit 99.02 to Energy Corp.’s Form 8-K filed December 12, 2006 (File No. 1-12579) and incorporated by reference herein) |
10.22 | Amendment No. 6 to the OGE Energy Corp. Restoration of Retirement Income Plan. (Filed as Exhibit 10.33 to Energy Corp.’s Form 10-K for the year ended December 31, 2005 (File No. 1-12579) and incorporated by reference herein) |
10.23 | Amendment No. 1 to Energy Corp.’s 1998 Stock Incentive Plan. (Filed as Exhibit 10.26 to Energy Corp.’s Form 10-K for the year ended December 31, 2006 (File No. 1-12579) and incorporated by reference herein) |
10.24 | Amendment No. 2 to Energy Corp.’s 2003 Stock Incentive Plan. (Filed as Exhibit 10.27 to Energy Corp.’s Form 10-K for the year ended December 31, 2006 (File No. 1-12579) and incorporated by reference herein) |
10.25 | Directors’ Compensation. (Filed as Exhibit 10.28 to Energy Corp.’s Form 10-K for the year ended December 31, 2007 (File No. 1-12579) and incorporated by reference herein) |
10.26 | Executive Officer Compensation. (Filed as Exhibit 10.29 to Energy Corp.’s Form 10-K for the year ended December 31, 2007 (File No. 1-12579) and incorporated by reference herein) |
10.27 | Energy Corp.’s Employees’ Stock Ownership and Retirement Savings Plan, as amended and restated. (Filed as Exhibit 10.31 to Energy Corp.’s Form 10-K for the year ended December 31, 2006 (File No. 1-12579) and incorporated by reference herein) |
10.28 | Ownership and Operating Agreement, dated as of January 21, 2008, entered into by and among the Company, the Oklahoma Municipal Power Authority and the Grand River Dam Authority (Filed as Exhibit 10.01 to Energy Corp.’s Form 8-K filed January 25, 2008 (File No. 1-12579) and incorporated by reference herein) |
10.29 | Amendment No. 1 to Energy Corp. Employees’ Stock Ownership and Retirement Savings Plan, as amended and restated. (Filed as Exhibit 10.33 to Energy Corp.’s Form 10-K for the year ended December 31, 2007 (File No. 1-12579) and incorporated by reference herein) |
10.30 | Amendment No. 2 to Energy Corp. Employees’ Stock Ownership and Retirement Savings Plan, as amended and restated. (Filed as Exhibit 10.34 to Energy Corp.’s Form 10-K for the year ended December 31, 2007 (File No. 1-12579) and incorporated by reference herein) |
10.31 | Letter of extension for the Company’s credit agreement dated November 11, 2007, by and between the Company and the Lenders thereto, related to the Company’s credit agreement dated December 6, |
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| 2006. (Filed as Exhibit 10.36 to Energy Corp.’s Form 10-K for the year ended December 31, 2007 (File No. 1-12579) and incorporated by reference herein) |
12.01 | Calculation of Ratio of Earnings to Fixed Charges. |
23.01 | Consent of Ernst & Young LLP. |
24.01 | Power of Attorney. |
31.01 | Certifications Pursuant to Rule 13a-15(e)/15d-15(e) As Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
32.01 | Certification Pursuant to 18 U.S.C. Section 1350 As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
99.01 | Cautionary Statement for Purposes of the “Safe Harbor” Provisions of the Private Securities Litigation Reform Act of 1995. |
99.02 | Copy of OCC order with Oklahoma Corporation Commission Staff, the Oklahoma Attorney General and others relating to the Company’s rate case. (Filed as Exhibit 99.02 to Energy Corp.’s Form 8-K filed December 16, 2005 (File No. 1-12579) and incorporated by reference herein) |
99.03 | Copy of APSC order with Arkansas Public Service Commission Staff, the Arkansas Attorney General and others relating to the Company’s rate case. (Filed as Exhibit 99.03 to Energy Corp.’s Form 8-K filed January 11, 2007 (File No. 1-12579) and incorporated by reference herein) |
Executive Compensation Plans and Arrangements
10.01 | Form of Change of Control Agreement for Officers of the Company and Energy Corp. (Filed as Exhibit 10.07 to Energy Corp.’s Form 10-K for the year ended December 31, 1996 (File No. 1-12579) and incorporated by reference herein) |
10.02 | Energy Corp.’s 1998 Stock Incentive Plan. (Filed as Exhibit 10.07 to Energy Corp.’s Form 10-K for the year ended December 31, 1998 (File No. 1-12579) and incorporated by reference herein) |
10.03 | Energy Corp.’s 2003 Stock Incentive Plan. (Filed as Annex A to Energy Corp.’s Proxy Statement for the 2003 Annual Meeting of Shareowners (File No. 1-12579) and incorporated by reference herein) |
10.04 | Energy Corp.’s Restoration of Retirement Income Plan, as amended by Amendments No. 1 and No. 2. (Filed as Exhibit 10.12 to Energy Corp.’s Form 10-K for the year ended December 31, 1996 (File No.1-12579) and incorporated by reference herein) |
10.05 | Amendment No. 3 to the Energy Corp. Restoration of Retirement Income Plan. (Filed as Exhibit 10.13 to Energy Corp.’s Form 10-K for the year ended December 31, 2000 (File No. 1-12579) and incorporated by reference herein) |
10.06 | Amendment No. 4 to the Energy Corp. Restoration of Retirement Income Plan. (Filed as Exhibit 10.14 to Energy Corp.’s Form 10-K for the year ended December 31, 2000 (File No. 1-12579) and incorporated by reference herein) |
10.07 | Energy Corp. Supplemental Executive Retirement Plan, as amended by Amendment No. 1. (Filed as Exhibit 10.07 to Energy Corp.’s Form 10-K for the year ended December 31, 2004 (File No. 1-12579) and incorporated by reference herein) |
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10.08 | Energy Corp.’s 2003 Annual Incentive Compensation Plan. (Filed as Annex B to Energy Corp.’s Proxy Statement for the 2003 Annual Meeting of Shareowners (File No. 1-12579) and incorporated by reference herein) |
10.09 | Energy Corp.’s Deferred Compensation Plan and Amendment No. 1 to Energy Corp.’s Deferred Compensation Plan. (Filed as Exhibit 10.12 to Energy Corp.’s Form 10-K for the year ended December 31, 2002 (File No. 1-12579) and incorporated by reference herein) |
10.14 | Amendment No. 1 to Energy Corp.’s 2003 Stock Incentive Plan. (Filed as Exhibit 10.23 to Energy Corp.’s Form 10-K for the year ended December 31, 2004 (File No. 1-12579) and incorporated by reference herein) |
10.16 | Amendment No. 5 to the Energy Corp. Restoration of Retirement Income Plan. (Filed as Exhibit 10.26 to Energy Corp.’s Form 10-K for the year ended December 31, 2004 (File No. 1-12579) and incorporated by reference herein) |
10.17 | Form of Non-Qualified Stock Option Agreement under Energy Corp.’s 2003 Stock Incentive Plan. (Filed as Exhibit 10.29 to Energy Corp.’s Form 10-K for the year ended December 31, 2004 (File No. 1-12579) and incorporated by reference herein) |
10.18 | Form of Performance Unit Agreement under Energy Corp.’s 2003 Stock Incentive Plan. (Filed as Exhibit 10.30 to Energy Corp.’s Form 10-K for the year ended December 31, 2004 (File No. 1-12579) and incorporated by reference herein) |
10.19 | Form of Restricted Stock Agreement under Energy Corp.’s 2003 Stock Incentive Plan. (Filed as Exhibit 10.31 to Energy Corp.’s Form 10-K for the year ended December 31, 2004 (File No. 1-12579) and incorporated by reference herein) |
10.20 | Form of Split Dollar Agreement. (Filed as Exhibit 10.32 to Energy Corp.’s Form 10-K for the year ended December 31, 2004 (File No. 1-12579) and incorporated by reference herein) |
10.22 | Amendment No. 6 to the OGE Energy Corp. Restoration of Retirement Income Plan. (Filed as Exhibit 10.33 to Energy Corp.’s Form 10-K for the year ended December 31, 2005 (File No. 1-12579) and incorporated by reference herein) |
10.23 | Amendment No. 1 to Energy Corp.’s 1998 Stock Incentive Plan. (Filed as Exhibit 10.26 to Energy Corp.’s Form 10-K for the year ended December 31, 2006 (File No. 1-12579) and incorporated by reference herein) |
10.24 | Amendment No. 2 to Energy Corp.’s 2003 Stock Incentive Plan. (Filed as Exhibit 10.27 to Energy Corp.’s Form 10-K for the year ended December 31, 2006 (File No. 1-12579) and incorporated by reference herein) |
10.25 | Directors’ Compensation. (Filed as Exhibit 10.28 to Energy Corp.’s Form 10-K for the year ended December 31, 2007 (File No. 1-12579) and incorporated by reference herein) |
10.26 | Executive Officer Compensation. (Filed as Exhibit 10.29 to Energy Corp.’s Form 10-K for the year ended December 31, 2007 (File No. 1-12579) and incorporated by reference herein) |
10.27 | Energy Corp.’s Employees’ Stock Ownership and Retirement Savings Plan, as amended and restated. (Filed as Exhibit 10.31 to Energy Corp.’s Form 10-K for the year ended December 31, 2006 (File No. 1-12579) and incorporated by reference herein) |
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10.29 | Amendment No. 1 to Energy Corp. Employees’ Stock Ownership and Retirement Savings Plan, as amended and restated. (Filed as Exhibit 10.33 to Energy Corp.’s Form 10-K for the year ended December 31, 2007 (File No. 1-12579) and incorporated by reference herein) |
10.30 | Amendment No. 2 to Energy Corp. Employees’ Stock Ownership and Retirement Savings Plan, as amended and restated. (Filed as Exhibit 10.34 to Energy Corp.’s Form 10-K for the year ended December 31, 2007 (File No. 1-12579) and incorporated by reference herein) |
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OKLAHOMA GAS AND ELECTRIC COMPANY
SCHEDULE II - Valuation and Qualifying Accounts
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Additions |
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| Balance at | Charged to | Charged to |
| Balance at |
| Beginning | Costs and | Other |
| End of |
Description | of Period | Expenses Accounts
(In millions) | Deductions | Period | |
Year Ended December 31, 2005
Reserve for Uncollectible Accounts
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$ 2.7
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$ 3.3 $ --- |
$ 3.5 (A) |
$ 2.5 | |
Year Ended December 31, 2006 |
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Reserve for Uncollectible Accounts | $ 2.5 | $ 6.8 $ --- | $ 6.0 (A) | $ 3.3 |
Year Ended December 31, 2007 |
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Reserve for Uncollectible Accounts | $ 3.3 | $ 6.0 $ --- | $ 5.9 (A) | $ 3.4 |
(A) Uncollectible accounts receivable written off, net of recoveries.
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SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, as amended, the Registrant has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Oklahoma City, and State of Oklahoma on the 28th day of February, 2008.
| OKLAHOMA GAS AND ELECTRIC COMPANY |
| (Registrant) |
| By | /s/ Peter B. Delaney |
| Peter B. Delaney |
| Chairman of the Board, President |
| and Chief Executive Officer |
Pursuant to the requirements of the Securities Exchange Act of 1934, as amended, this Report has been signed below by the following persons on behalf of the Registrant in the capacities and on the dates indicated.
Signature |
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/ s / Peter B. Delaney |
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Peter B. Delaney |
| Principal Executive |
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| Officer and Director; |
| February 28, 2008 |
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/ s / James R. Hatfield |
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James R. Hatfield |
| Principal Financial Officer; and | February 28, 2008 | |
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/ s / Scott Forbes |
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Scott Forbes |
| Principal Accounting Officer | February 28, 2008 | |
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Herbert H. Champlin | Director; |
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Luke R. Corbett | Director; |
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John D. Groendyke | Director; |
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Kirk Humphreys | Director; |
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Robert Kelley | Director; |
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Linda P. Lambert | Director; |
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Robert O. Lorenz | Director; |
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Leroy C. Richie | Director; |
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Ronald H. White, M.D. | Director; and |
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J. D. Williams | Director. |
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/ s / Peter B. Delaney
By Peter B. Delaney (attorney-in-fact) February 28, 2008
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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.
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