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, 2002
OR
[ ] 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: 1-12579
OGE Energy Corp.
(Exact name of registrant as specified in its charter)
Oklahoma
73-1481638
(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:
Title of each class
Name of each exchange on which registered
Common Stock
New York Stock Exchange and Pacific Stock Exchange
Rights to Purchase Series A Preferred Stock
New York Stock Exchange and Pacific Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None
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
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. [ ]
Indicate by check mark whether the registrant is
an accelerated filed (as defined in Rule 12b-2 of the
Act). Yes X
No
As of June 28, 2002, 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 $1,776,961,521 based
on the number of shares held by non-affiliates (77,732,350) and the reported
closing market price of the common stock on the New York Stock Exchange on such
date of $22.86.
As of February 28, 2003, 78,720,459 shares of
common stock were outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
The Proxy Statement for the Company's 2003 annual meeting of stockholders is incorporated by reference into Part III of this Form 10-K.
OGE ENERGY CORP.
FORM 10-K
FOR THE YEAR ENDED DECEMBER 31, 2002
TABLE OF CONTENTS
Part I Page
Item 1. Business.............................................................................. 1
The Company........................................................................... 1
Electric Operations................................................................... 3
General........................................................................... 3
Regulation and Rates.............................................................. 6
Rate Activities and Proposals..................................................... 16
Fuel Supply....................................................................... 17
Natural Gas Pipeline Operations - Enogex.............................................. 19
Finance and Construction.............................................................. 29
Environmental Matters................................................................. 31
Employees............................................................................. 35
Access to Securities and Exchange Commission Filings.................................. 35
Item 2. Properties............................................................................ 36
Item 3. Legal Proceedings..................................................................... 37
Item 4. Submission of Matters to a Vote of Security Holders................................... 45
Executive Officers of the Registrant................................................ 46
Part II
Item 5. Market for Registrant's Common Equity and Related Stockholder
Matters............................................................................. 49
Item 6. Selected Financial Data............................................................... 51
Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations............................................................... 52
Item 7A. Quantitative and Qualitative Disclosures About Market Risk............................ 89
Item 8. Financial Statements and Supplementary Data........................................... 92
Item 9. Changes In and Disagreements with Accountants on Accounting and
Financial Disclosure................................................................ 149
i
TABLE OF CONTENTS (Continued)
Part III
Item 10. Directors and Executive Officers of the Registrant.................................... 150
Item 11. Executive Compensation................................................................ 150
Item 12. Security Ownership of Certain Beneficial Owners and Management and
Related Stockholder Matters......................................................... 150
Item 13. Certain Relationships and Related Transactions........................................ 150
Item 14. Controls and Procedures............................................................... 151
Part IV
Item 15. Exhibits, Financial Statement Schedules and Reports on Form 8-K....................... 152
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PART I
Item 1. Business.
THE COMPANY
OGE Energy Corp. (collectively with its subsidiaries, the “Company”) is an energy and energy services provider offering physical delivery and management of both electricity and natural gas in the south central United States. The Company conducts these activities through two business segments, the Electric Utility and the Natural Gas Pipeline segments.
The Electric Utility segment generates, transmits, distributes and sells electric energy in Oklahoma and western Arkansas. Its operations are conducted through Oklahoma Gas and Electric Company (“OG&E”) and are subject to regulation by the Oklahoma Corporation Commission (“OCC”), the Arkansas Public Service Commission (“APSC”) and the Federal Energy Regulatory Commission (“FERC”). OG&E was incorporated in 1902 under the laws of the Oklahoma Territory and is the largest electric utility in Oklahoma and its franchised service territory includes the Fort Smith, Arkansas area. OG&E sold its retail gas business in 1928 and is no longer engaged in the gas distribution business.
OG&E 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 OG&E due to the significant problems faced by California in its electric deregulation efforts and other factors, significant changes are possible, which could significantly change the manner in which OG&E conducts its business. These developments at the federal and state levels are described in more detail below under “Regulation and Rates - State Restructuring Initiatives and National Energy Legislation.”
On October 11, 2002, OG&E, the OCC Staff, the Oklahoma Attorney General and other interested parties agreed to a settlement of OG&E’s rate case. The terms of the settlement are described below in “Regulation and Rates - Recent Regulatory Matters.”
The Natural Gas Pipeline segment is conducted through Enogex Inc. and its subsidiaries (“Enogex”) and consists of three related businesses: (i) the transportation and storage of natural gas, (ii) the gathering and processing of natural gas, and (iii) the marketing and trading of natural gas (collectively, the “pipeline businesses”). The vast majority of Enogex’s natural gas gathering, processing, transportation and storage assets are located in the major gas producing basins of Oklahoma. Through a 75 percent interest in the NOARK Pipeline System Limited Partnership (“NOARK”), Enogex also owns a controlling interest in and operates the Ozark Gas Transmission System (“Ozark”), a FERC regulated interstate pipeline that extends from southeast Oklahoma through Arkansas to southeast Missouri. Enogex’s marketing and trading activities include corporate price risk management and other optimization services. Enogex was previously engaged in the exploration and production of natural gas, however, this portion of Enogex’s business, along with interests in certain gas gathering and processing assets in Texas
1
were sold in 2002 and 2003 and are reported in the Consolidated Financial Statements as discontinued operations.
The Company was incorporated in August 1995 in the State of Oklahoma and its executive offices are located at 321 North Harvey, P.O. Box 321, Oklahoma City, Oklahoma 73101-0321; telephone (405) 553-3000.
Company Strategy
In early 2002, the Company completed a review of its business strategy that was largely driven by the anticipated deregulation of the retail electric markets in Oklahoma and Arkansas. Due to a variety of factors, including the current efforts to repeal the Oklahoma Electric Restructuring Act of 1997 and the recent repeal of the Restructuring Law in Arkansas, the Company does not anticipate that deregulation of the electricity markets in Oklahoma or Arkansas will occur in the foreseeable future. The strategic direction of the Company has been revised to reflect these developments. As a result, the Company expects potentially slower earnings growth than associated with deregulation but with less variability of those earnings.
The Company’s business strategy will utilize the diversified asset position of OG&E and Enogex to provide energy products and services to customers primarily in the south central United States. The Company will focus on those products and services with limited or manageable commodity exposure. The Company intends for OG&E to continue as an integrated utility engaged in the generation and the distribution of electricity and to represent over time approximately 70 percent of the Company’s consolidated assets. The remainder of the Company’s assets will be in Enogex’s pipeline businesses. In addition to the incremental growth opportunities that Enogex provides, the Company believes that Enogex’s risk management capabilities, commercial skills and market information provide value to all of the Company’s businesses. Federal regulation in regard to the operations of the wholesale power market may change with the proposed Standard Market Design initiative at the FERC. In addition, Oklahoma and Arkansas legislatures and utility commissions may propose changes from time to time that could subject the utilities to market risk. Accordingly, the Company is applying risk management practices to all of its operations in an effort to mitigate the potential adverse effect of any future regulatory changes.
In the near term, OG&E plans on increasing its investment and growing earnings largely through the acquisition of a merchant power plant. As part of the OCC’s rate order on November 20, 2002, OG&E is seeking to purchase an electric power plant with at least 400 megawatts (“MW”) of generating capacity and to include the cost of such plant in its rate base. Given the surplus power in the region, the Company believes there is a continuing opportunity to purchase existing power plants at prices below the cost to build. This should enable OG&E to generate electricity for its customers at prices below those being paid by OG&E under existing qualified cogeneration and small power production producers’ contracts (“QF contracts”). Unless extended by OG&E, many of these QF contracts will expire over the next one to five years. Accordingly, OG&E will continue to explore opportunities to purchase power plants in order to serve its native load. OG&E anticipates filing with appropriate regulatory agencies to increase base rates to recover its investment in any power plant acquired and expects that customers
2
should realize overall lower rates through fuel savings due to the increased efficiency of these new plants and lower capital costs than those associated with the expiring QF contracts.
Enogex initiated a program in 2002 to improve its financial performance. As a part of this performance improvement program, Enogex has sold approximately $103.8 million in assets, reduced debt by 17 percent, reduced its number of employees by 12 percent and reorganized its operations. In addition to improving its earnings, Enogex will continue to take actions to reduce its exposure to commodity prices by, among other things, mitigating its exposure to keep whole processing arrangements and reducing earnings volatility. While the Company believes substantial progress has been achieved, substantial opportunities remain. Enogex expects to continue reviewing its work processes, rationalizing assets, renegotiating contracts to improve pricing on existing volumes and reducing costs to further improve its financial return in addition to pursuing opportunities for organic growth.
In 2003, in addition to these ongoing efforts, a major upgrade of the information systems is expected to be substantially completed. The Company believes these upgrades will be a major step towards obtaining the data required for it to optimize its system, provide improved customer service and enable management to more accurately determine the earnings potential of the unregulated pipeline system. The Company does not anticipate significantly increasing its investment in Enogex in accordance with the goal of targeting its pipeline businesses at 30 percent of the Company’s consolidated assets.
ELECTRIC OPERATIONS - OG&E
General
The Electric Utility segment generates, transmits, distributes and sells electric energy in Oklahoma and western Arkansas. Its operations are conducted through OG&E. OG&E furnishes retail electric service in 270 communities and their contiguous rural and suburban areas. During 2002, seven other communities and two rural electric cooperatives in Oklahoma and western Arkansas purchased electricity from OG&E for resale. The service area, with an estimated population of 1.7 million, covers approximately 30,000 square miles in Oklahoma and western Arkansas; including Oklahoma City, the largest city in Oklahoma, and Fort Smith, Arkansas. Of the 279 communities served, 252 are located in Oklahoma and 27 in Arkansas. Approximately 90 percent of total electric operating revenues for the year ended December 31, 2002, were derived from sales in Oklahoma and the remainder from sales in Arkansas.
OG&E’s system control area peak demand as reported by the system dispatcher during 2002 was approximately 5,696 MW’s on August 23, 2002. OG&E’s load responsibility peak demand was approximately 5,427 MW’s on August 23, 2002, resulting in a capacity margin of approximately 18.9 percent. As reflected in the table on page 4 and in the operating statistics on page 5, total megawatt-hour (“MWH”) sales remained flat in 2002 as compared to a decrease of approximately 1.6 percent in 2001 and an increase of approximately 6.3 percent in 2000. MWH sales to OG&E’s customers (“system sales”) increased approximately 0.4 percent in 2002, due to favorable weather in the third quarter of 2002. Sales to other utilities and power marketers
3
(“off-system sales”) decreased approximately 25.0 percent in 2002 compared to an increase of approximately 33.3 percent in 2001 and a decrease of approximately 25.0 percent in 2000.
Variations in MWH sales for the three years are reflected in the following table:
(Millions of MWH)
Increase/ Increase/ Increase/
2002 (Decrease) 2001 (Decrease) 2000 (Decrease)
=============================================================================================
System Sales 24.6 0.4% 24.5 (2.0)% 25.0 6.4%
Off-System Sales 0.3 (25.0)% 0.4 33.3% 0.3 (25.0)%
------ ------ ------
Total Sales 24.9 --- 24.9 (1.6)% 25.3 6.3%
====== ====== ======
OG&E is subject to competition in various degrees from government-owned electric systems, municipally-owned electric systems, rural electric cooperatives and, in certain respects, from other private utilities, power marketers and cogenerators. Oklahoma law forbids the granting of an exclusive franchise to a utility for providing electricity.
Besides competition from other suppliers or marketers of electricity, OG&E competes with suppliers of other forms of energy. The degree of competition between suppliers may vary depending on relative costs and supplies of other forms of energy. See “Regulation and Rates - State Restructuring Initiatives and National Energy Legislation” for a discussion of the potential impact on competition from federal and state legislation.
4
OKLAHOMA GAS AND ELECTRIC COMPANY
CERTAIN OPERATING STATISTICS
Year ended December 31 (In millions) 2002 2001 2000
=========================================================================================================
ELECTRIC ENERGY
(Millions of MWH)
Generation (exclusive of station use)....................... 23.4 23.0 23.3
Purchased................................................... 3.5 3.7 3.7
----------- ----------- -----------
Total generated and purchased........................... 26.9 26.7 27.0
Company use, free service and losses........................ (2.0) (1.8) (1.7)
----------- ----------- -----------
Electric energy sold.................................... 24.9 24.9 25.3
=========== =========== ===========
ELECTRIC ENERGY SOLD
(Millions of MWH)
Residential................................................. 8.0 8.0 8.0
Commercial and industrial................................... 12.4 12.4 12.7
Public street and highway lighting.......................... 0.1 0.1 0.1
Other sales to public authorities........................... 2.6 2.5 2.4
System sales for resale..................................... 1.5 1.5 1.8
----------- ----------- -----------
Total system sales...................................... 24.6 24.5 25.0
Off-system sales............................................ 0.3 0.4 0.3
----------- ----------- -----------
Total sales............................................. 24.9 24.9 25.3
=========== =========== ===========
ELECTRIC OPERATING REVENUES
(In millions)
Residential................................................. $ 557.6 $ 578.9 $ 575.7
Commercial and industrial................................... 605.5 638.0 643.6
Public street and highway lighting.......................... 10.4 10.9 10.3
Other sales to public authorities........................... 125.1 127.9 124.2
System sales for resale..................................... 48.2 52.5 58.1
Provision for FERC rate refund.............................. --- (1.0) ---
----------- ----------- -----------
Total system sales...................................... 1,346.8 1,407.2 1,411.9
Off-system sales............................................ 6.3 13.0 12.9
----------- ----------- -----------
Total Electric Revenues................................. 1,353.1 1,420.2 1,424.8
Miscellaneous revenues...................................... 34.9 36.6 28.8
----------- ----------- -----------
Total Electric Operating Revenues....................... $ 1,388.0 $ 1,456.8 $ 1,453.6
=========== =========== ===========
ACTUAL NUMBER OF ELECTRIC CUSTOMERS
(At end of period)
Residential................................................. 616,712 609,408 603,826
Commercial and industrial................................... 88,466 87,511 86,659
Public street and highway lighting.......................... 249 250 250
Other sales to public authorities........................... 13,031 12,566 11,615
Sales for resale............................................ 55 62 52
----------- ----------- -----------
Total................................................... 718,513 709,797 702,402
=========== =========== ===========
AVERAGE RESIDENTIAL CUSTOMER SALES
Average annual revenue...................................... $ 907.95 $ 952.32 $ 957.54
Average annual use (KWH).................................... 13,095 13,131 13,264
Average price per KWH (cents)............................... $ 6.93 $ 7.25 $ 7.22
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Regulation and Rates
OG&E’s retail electric tariffs are regulated by the OCC in Oklahoma and by the APSC in Arkansas. The issuance of certain securities by OG&E is also regulated by the OCC and the APSC. OG&E’s wholesale electric tariffs, 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 OG&E’s facilities and operations.
The order of the OCC authorizing OG&E to reorganize into a subsidiary of the Company contains certain provisions which, among other things, ensure the OCC access to the books and records of the Company and its affiliates relating to transactions with OG&E; require the Company to employ accounting and other procedures and controls to protect against subsidization of non-utility activities by OG&E’s customers; and prohibit the Company from pledging OG&E assets or income for affiliate transactions.
For the year ended December 31, 2002, approximately 88 percent of OG&E’s electric revenue was subject to the jurisdiction of the OCC, eight percent to the APSC and four percent to the FERC.
Recent Regulatory Matters
In September 2001, the director of the OCC public utility division filed an application with the OCC to review the rates of OG&E. In the filing, the OCC Staff requested that OG&E submit information for a test year ending September 30, 2001. On December 14, 2001, OG&E, citing the need for investment in security and system reliability, filed a notice with the OCC of its intent to seek an increase in OG&E’s electric rates. On January 28, 2002, OG&E filed testimony with the OCC supporting OG&E’s request for a $22.0 million annual rate increase with approximately $10.3 million related to investments for security and approximately $11.7 million attributable to investments in increased system reliability and increased utility operating costs. Over the past 16 years, OG&E has had several rate reductions that have totaled more than $142.0 million annually.
Attempting to make security investments at the proper level, OG&E has developed a set of guidelines intended to minimize long-term or widespread outages, minimize the impact on critical national defense and related customers, maximize the ability to respond to and recover from an attack, minimize the financial impact on OG&E that might be caused by an attack and accomplish these efforts with minimal impact on ratepayers. Initially, approximately $10.3 million of the January 28, 2002 rate increase requested by OG&E was to invest in increased security. As described below, OG&E subsequently withdrew its request for the $10.3 million related to security.
The additional $11.7 million of the original $22.0 million request was for investment in increased system reliability and for increased utility operating costs. OG&E had added new generation capacity to meet growing customer demand and had determined that it needed to increase expenditures for distribution system reliability following a series of record-breaking storms, including a 1995 windstorm in the Oklahoma City area affecting 175,000 customers,
6
1999 tornadoes affecting about 150,000 customers and disrupting service at a power plant, July 2000 thunderstorms affecting 110,000 customers, a Christmas 2000 ice storm affecting 140,000 customers, Memorial Day 2001 storms leaving 143,000 customers without power and at least two other storms affecting at least 100,000 customers each.
As part of its filing, OG&E sought approval to offer several new rate program choices to customers. One such pilot program involves flat billing. This option would set a customer’s bill at a fixed dollar amount and would not change throughout the year regardless of the amount of power consumed. The bill amount would then be adjusted in the following year based on the previous year’s usage and other factors. Another proposed rate program, a Green Power option, would involve OG&E contracting with wind generators to purchase a quantity of wind-generated power, then offering that power to customers. The rate would reflect the higher cost of wind-generated power.
On January 30, 2002, a significant ice storm hit OG&E’s service territory and inflicted major damage to the transmission and distribution infrastructure requiring total expenditures for repairs of approximately $92.0 million. On April 8, 2002, OG&E announced it would withdraw the $10.3 million increased security portion of its January request. Simultaneously with that announcement, OG&E filed a Joint Application with the Staff of the OCC for separate consideration of costs related to increased security requirements. Thereafter, on August 14, 2002, OG&E filed a report outlining proposed expenditures and related actions for security enhancement. OG&E is working with the OCC Staff under this separate filing to determine the appropriate dollar amount for security upgrades and recovery mechanisms. The OCC Staff has indicated its intent to retain a security expert to review the report filed by OG&E.
On July 1, 2002, OG&E filed direct testimony in support of recovery for the approximately $92.0 million in damages caused by the January 2002 ice storm. OG&E requested approximately a $14.5 million annual increase in revenue requirement. The request included recovery of, and return on, approximately $86.6 million of capital expenditures related to the ice storm and recovery, over three years, of approximately $5.4 million of deferred operating costs. Recovery of costs associated with the January 2002 ice storm is included in the Joint Stipulation and Settlement Agreement discussed below.
On October 11, 2002, OG&E, the OCC Staff, the Oklahoma Attorney General and other interested parties agreed to a settlement (the “Settlement Agreement”) of OG&E’s rate case. The administrative law judge subsequently recommended approval of the Settlement Agreement and on November 22, 2002, the OCC signed a rate order containing the provisions of the Settlement Agreement. The Settlement Agreement provides for, among other items: (i) a $25.0 million annual reduction in the electric rates of OG&E’s Oklahoma customers which begins with the first regular billing cycle occurring 41 days after the issuance of the OCC order approving the Settlement Agreement; (ii) recovery by OG&E, through rate base, of the capital expenditures associated with the January 2002 ice storm; (iii) recovery by OG&E, over three years, of the $5.4 million in deferred operating costs, associated with the January 2002 ice storm, through OG&E’s rider for off-system sales; (iv) OG&E to acquire electric generating capacity (“New Generation”) of not less than 400 MW’s to be integrated into OG&E’s generation system. Key portions of the Settlement Agreement are described below.
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I. Rate Reduction to Oklahoma Customers
The Settlement Agreement stipulated that OG&E would file tariffs, designed to reflect an annual reduction of $25.0 million in OG&E’s Oklahoma jurisdictional operating revenue. The $25.0 million annual reduction began on January 6, 2003.
II. Recovery of Storm Damages
The Settlement Agreement stipulated that OG&E would be allowed to earn a return, through base rates, on the capital expenditures related to the January 2002 ice storm. The Settlement Agreement also stipulated that OG&E would be allowed recovery of $5.4 million of deferred operating costs related to the January 2002 ice storm. The recovery of the $5.4 million in operating costs will be recovered over a three-year period through OG&E’s rider for off-system sales. Currently, OG&E has a 50/50 sharing mechanism in Oklahoma for any off-system sales. The Settlement Agreement provided that the first $1.8 million in annual net profits from OG&E’s off-system sales will go to OG&E, the next $3.6 million in annual net profits from off-system sales will go to OG&E’s Oklahoma customers, and any net profits of off-system sales in excess of these amounts will be credited in each sales year with 80 percent to OG&E’s Oklahoma customers and the remaining 20 percent to OG&E. If any of the $5.4 million is not recovered at the end of the three years, the OCC will authorize the recovery of any remaining costs.
III. New Generation
OG&E intends to take steps to purchase electric generating facilities of not less than 400 MW’s to be integrated into OG&E’s generation system. OG&E will have the right to accrue a regulatory asset, for a period not to exceed 12 months subsequent to the acquisition and initial operation of the New Generation, consisting of the non-fuel operation and maintenance expenses, depreciation, cost of debt associated with the capital investment and ad valorem taxes related to the New Generation. In addition to the accrual of the regulatory asset, OG&E must file an application with the OCC for the inclusion of the New Generation into OG&E’s rate base, as part of a general rate review, no later than 12 months following the acquisition and initial operation of the New Generation. Upon approval by the OCC of the application, all prudently incurred costs accrued through the regulatory asset within the 12 month period will be included in OG&E’s prospective cost of service. The period for recovery of the regulatory asset will be determined by the OCC. OG&E expects this New Generation will provide savings, over a three-year period, in excess of $75.0 million to OG&E’s Oklahoma customers. These savings will be derived from: (i) the avoidance of purchase power contracts otherwise needed; (ii) replacing an above market cogeneration contract when it can be terminated at the end of August 2004; and (iii) fuel savings associated with operating efficiencies of a new plant. These savings, while providing real savings to OG&E’s Oklahoma customers, should have no effect on the profitability of OG&E.
As indicated above, OG&E’s decision with respect to the purchase of the New Generation will be subject to a review by the OCC as a part of a general rate case for the purpose of determining the level of just and reasonable costs associated with the New Generation to be included in OG&E’s rate base. The OCC’s review is expected to include, but not be limited to, an analysis and review of the alternatives to purchasing the New Generation, the amount paid for
8
such New Generation and the level of capacity purchases. OG&E will provide monthly reports, for a period of 36 months, to the OCC Staff, documenting and providing proof of savings experienced by OG&E’s customers. In determining the 36-month savings, OG&E will be required to include in its reports: (1) the avoidance of purchased capacity otherwise required to meet Southwest Power Pool (“SPP”) capacity margin requirements; (2) credits to customers accruing by virtue of cogeneration contract terminations; and (3) the fuel savings associated with the operating efficiencies of OG&E’s generating facilities including the New Generation compared to the fuel efficiencies of OG&E’s generation facilities in operation during the test year related to the Settlement Agreement. The operating costs associated with the New Generation will be deducted from the sum of the three items discussed above to determine the ultimate amount of savings. In determining the 36-month savings, OG&E will not include savings to its customers, which occur as the result of scheduled reductions in ongoing cogeneration contract payments. In the event OG&E is unable to demonstrate at least $75.0 million in savings to its customers during this 36-month period, OG&E will have an obligation to credit its customers any unrealized savings below $75.0 million as determined at the end of the 36- month period, which shall be no later than December 31, 2006.
In the event OG&E does not acquire the New Generation by December 31, 2003, OG&E will be required to 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. However, if OG&E purchases the New Generation subsequent to January 2004, the credit to Oklahoma customers will terminate in the first month that the New Generation begins initial operations and any credited amount to Oklahoma customers will be included in the determination of the $75.0 million targeted savings.
IV. Rate Design
As part of the Settlement Agreement, OG&E agreed to withdraw its request for a Coal Utilization Performance Rider (“CUP Rider”) and a Transmission Investment Recovery Rider (“TIR Rider”). The CUP Rider would have rewarded OG&E based on its performance in the utilization of its coal generation facilities. The greater the coal plant utilization, the greater the benefits received by OG&E’s customers. OG&E’s coal plants are among the nations most efficient and the energy produced by those plants displaces higher cost energy. The CUP Rider would have provided additional incentive for OG&E by encouraging OG&E to aggressively pursue even greater efficiencies from these best-in-class plants. Additional CUP Rider incentives would have commenced at 72 percent coal utilization and increased as percentages rose above the 72 percent threshold level. The TIR Rider would have been applicable to investments necessary for increased transmission service and interconnect costs not funded by a new transmission customer (such as an independent power producer (“IPP”)) or for investment to improve available transfer capability as defined and approved by the regional transmission organizations (“RTOs”). OG&E agreed not to seek implementation of a CUP Rider or a TIR Rider or other similar riders in OG&E’s next general rate proceeding or during the 36-month benefit period of the New Generation. However, in the event federal regulation of the interstate transmission grid results in a new rate design which increases costs to OG&E’s Oklahoma customers, OG&E will not be precluded from requesting a TIR Rider.
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V. Gas Transportation Service
In a 1997 Order, the OCC approved a stipulation wherein OG&E agreed to initiate a competitive bidding process for gas transportation service to its natural gas plants.
OG&E’s current gas transportation service contract with Enogex for OG&E’s current natural gas generation facilities has a primary term ending in April 2004 and provides for an annual payment to Enogex of approximately $32.3 million. As part of the Settlement Agreement, OG&E agreed to consider competitive bidding as an option when analyzing the extension or renewal of OG&E’s gas transportation service contract with Enogex prior to April 2004. OG&E further agreed to consider competitive bidding as an option for all natural gas transportation services and gas supply acquisition practices to all new generation facilities built, purchased or placed into service after October 9, 2002. If OG&E chooses not to utilize competitive bidding to obtain all natural gas transportation services to its current generation facilities, after April 2004, or to any new generation facilities, OG&E must then provide the OCC Staff and the office of the Oklahoma Attorney General all data and information upon which the decision was based.
Other Regulatory Actions
The Settlement Agreement, when it became effective, provided for the termination of the Acquisition Premium Credit Rider (“APC Rider”) and the Gas Transportation Adjustment Credit Rider (“GTAC Rider”).
The APC Rider was approved by the OCC in March 2000 and was implemented by OG&E to reflect the completion of the recovery of the amortization premium paid by OG&E when it acquired Enogex in 1986. The effect of the APC Rider was to remove approximately $10.7 million annually from the amount being recovered by OG&E from its Oklahoma customers in current rates.
In June 2001, the OCC approved a stipulation (the “Stipulation”) to the competitive bid process of OG&E’s gas transportation service from Enogex. The Stipulation directed OG&E to reduce its rates to its Oklahoma retail customers by approximately $2.7 million per year through the implementation of the GTAC Rider. The GTAC Rider was a credit for gas transportation cost recovery and was applicable to and became part of each Oklahoma retail rate schedule to which OG&E’s automatic fuel adjustment clause applies. As discussed above, the Settlement Agreement terminated the GTAC Rider. Consequently, these charges for gas transportation provided by Enogex are now included in base rates.
OG&E’s Generation Efficiency Performance Rider (“GEP Rider”) expired in June 2002. The GEP Rider was established initially in 1997 in connection with OG&E’s 1996 general rate review and was intended to encourage OG&E to lower its fuel costs by: (i) allowing OG&E to collect one-third of the amount by which its fuel costs were below a specified percentage (96.261 percent) of the average fuel costs of certain other investor-owned utilities in the region; and (ii) disallowing the collection of one-third of the amount by which its fuel costs exceeded a specified percentage (103.739 percent) of the average fuel costs of other investor-owned utilities. In June
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2000 the OCC made modifications to the GEP Rider which had the effect of reducing the amount OG&E could recover under the GEP Rider by: (i) changing OG&E’s peer group to include utilities with a higher coal-to-gas generation mix; (ii) reducing the amount of fuel costs that can be recovered if OG&E’s costs exceed the new peer group by changing the percentage above which OG&E will not be allowed to recover one-third of the fuel costs from Oklahoma customers from 103.739 percent to 101.0 percent; (iii) reducing OG&E’s share of cost savings as compared to its new peer group from 33 percent to 30 percent; and (iv) limiting to $10.0 million the amount of any awards paid to OG&E or penalties charged to OG&E. For the period between January 1, 2002 and June 30, 2002, OG&E recovered approximately $2.4 million under the GEP Rider.
State Restructuring Initiatives
Oklahoma
As previously reported, the Electric Restructuring Act of 1997 (the “1997 Act”) was designed to provide retail customers in Oklahoma a choice of their electric supplier by July 1, 2002. Additional implementing legislation was to be adopted by the Oklahoma Legislature to address many specific issues associated with the 1997 Act and with deregulation. In May 2000, a bill addressing the specific issues of deregulation was passed in the Oklahoma State Senate and then was defeated in the Oklahoma House of Representatives. In May 2001, the Oklahoma Legislature passed Senate Bill 440 (“SB 440”), which postponed the scheduled start date for customer choice from July 1, 2002 until at least 2003. In addition to postponing the date for customer choice, SB 440 calls for a nine-member task force to further study the issues surrounding deregulation. The task force includes the Governor or his designee, the Oklahoma Attorney General, the OCC Chair and several legislative leaders, among others. In the current legislative session, Senate Bill 383 has been recently introduced to repeal the 1997 Act. It is unknown at this time whether the bill will be passed into law. The Company will continue to actively participate in the legislative process and expects to remain a competitive supplier of electricity. As a result of the failures of California’s attempt to deregulate its electricity markets, the Enron bankruptcy, and associated impacts on the industry, efforts to restructure the electricity market in Oklahoma appear at this time to be delayed indefinitely.
Arkansas
In April 1999, Arkansas passed a law (the “Restructuring Law”) calling for restructuring of the electric utility industry at the retail level. The Restructuring Law, like the 1997 Act, would have significantly affected OG&E’s future operations. OG&E’s electric service area includes parts of western Arkansas, including Fort Smith. The Restructuring Law initially targeted customer choice of electricity providers by January 1, 2002. In February 2001, the Restructuring Law was amended to delay the start date of customer choice of electric providers in Arkansas until October 1, 2003, with the APSC having discretion to further delay implementation to October 1, 2005. In March 2003, the Restructuring Law was repealed.
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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 OG&E’s customers through automatic fuel adjustment clauses, which are subject to periodic review by the OCC, the APSC and the FERC. The OCC, the APSC and the FERC also have authority to review the appropriateness of gas transportation charges or other fees OG&E pays to Enogex. See “Regulation and Rates – Other Regulatory Actions” for a further discussion.
National Energy Legislation
Federal law imposes numerous responsibilities and requirements on OG&E. The Public Utility Regulatory Policy Act of 1978 requires electric utilities, such as OG&E, to purchase power generated in a manufacturing process from a qualified cogeneration facility (“QF”). Generally stated, electric utilities must purchase electric energy and production capacity made available by QF’s at a rate reflecting the cost that the purchasing utility can avoid as a result of obtaining energy and production capacity from these sources; rather than generating an equivalent amount of energy itself or purchasing the energy or capacity from other suppliers. OG&E has entered into agreements with four such cogenerators. Electric utilities also must furnish electric energy to QF’s on a non–discriminatory basis at a rate that is just and reasonable and in the public interest and must provide certain types of service which may be requested by QF’s to supplement or back up those facilities’ own generation.
Although efforts to increase competition at the state level have been stalled, there have been several initiatives implemented at the federal level to increase competition in the wholesale markets for electricity. The National Energy Policy Act of 1992 (“Energy Act”), among other things, promoted the development of IPP’s. The Energy Act was followed by FERC Order 888 and Order 889, which facilitated third-party utilization of the transmission grid for sales of wholesale power. The Energy Act, Orders 888 and 889, and other FERC policies and initiatives have significantly increased competition in the wholesale power market. Utilities, including OG&E, have increased their own in–house wholesale marketing efforts and the number of entities with whom they historically traded. Moreover, power marketers are an increasingly important presence in the industry. These entities typically arbitrage wholesale price differentials by buying power produced by others in one market and selling it in another. IPP’s also are becoming a more significant sector of the electric utility industry. In both Oklahoma and Arkansas, significant additions of new power plants have been announced, almost all of it from IPP’s.
Notwithstanding these developments in the wholesale power market, the FERC recognized that impediments remained to the achievement of fully competitive wholesale markets including: (i) engineering and economic inefficiencies inherent in the current operation and expansion of the transmission grid; and (ii) continuing opportunities for transmission owners (primarily electric utilities) to discriminate in the operation of their transmission facilities in favor of their own or affiliated power marketing activities. In the past, the FERC only encouraged utilities to join and place their transmission systems under the operational control of independent system operators (“ISO”). On December 20, 1999, the FERC issued Order 2000,
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its final rule on RTO’s. Order 2000 is intended to have the effect of turning the nation’s transmission facilities into independently operated “common carriers” that offer comparable service to all would-be-users. Although adopting a voluntary approach towards RTO formation, the FERC stressed that Order 2000 does not preclude it from requiring RTO participation. Order 2000 set out a timetable for every jurisdictional utility (including OG&E) to either join in an RTO filing, or, alternatively, to submit a filing describing its efforts to join an RTO, the reasons for not participating in an RTO proposal and any obstacles to participation, and its plans for further work toward participation.
OG&E is a member of the SPP, the regional reliability organization for Oklahoma, Arkansas, Kansas, Louisiana, Missouri and part of Texas. OG&E participated with the SPP in the development of regional transmission tariffs and executed an Agency Agreement with the SPP to facilitate interstate transmission operations within this region. In October 2000, the SPP filed its application with the FERC to become an RTO. In July 2001, the FERC determined that the SPP did not have adequate scope and configuration to be granted RTO status. The SPP was encouraged to explore the possibility of joining an RTO to be formed in the southeastern region of the United States and to explore the feasibility of becoming a part of the recently approved RTO being established by the Midwest Independent System Operator (“MISO”). The SPP and MISO entered negotiations during the late summer of 2001 to combine the SPP and MISO and to form a new regional transmission entity that would combine the control areas of MISO and SPP, capture certain synergies that would be available from the combined organization, and allow member companies in the SPP certain options with respect to membership in the combined organization. The officers of MISO and of SPP, under the direction of their respective Boards of Directors developed documentation to effect the merger of SPP and MISO into a new organization, and the transaction was approved by the SPP Board of Directors. On February 7, 2003, OG&E executed a Conditional MISO Membership Application to join the resulting company as a Transmission Owner, subject to certain conditions being either met or waived. On the same date, OG&E executed the Conditional Withdrawal Agreement with the SPP. The Conditional Withdrawal Agreement would have had the effect of terminating OG&E’s membership in the SPP, except for regional reliability purposes, at such time as the MISO - SPP combination received all necessary regulatory approvals, the required number of SPP member companies executed the Conditional Membership Application to join MISO, and the SPP and MISO merger transaction were closed. OG&E filed with the APSC a cost/benefit analysis to demonstrate that OG&E's joining the MISO/SPP combination would have been in the public interest.
One of the conditions to the SPP and MISO merger transaction was that two-thirds of the load served by transmission owners within the SPP were to execute the Conditional Membership Application and to execute the Conditional Withdrawal Agreement with the SPP. During March 2003 it became apparent to the SPP Board of Directors that the Conditional Membership Applications would not be executed by transmission owners representing two-thirds of the load in the SPP. At its meeting on March 12, 2003, the SPP Board of Directors directed the President of SPP to open discussion with the MISO Board of Directors concerning termination of the proposed MISO/SPP combination. On March 20, 2003, MISO and SPP announced that their respective Boards had voted to terminate their merger because the conditions required to close the transaction would not be met in the foreseeable future. OG&E has remained a member of the
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SPP while the MISO/SPP combination was pending, and OG&E will continue to be a member of the SPP as the SPP, other SPP members and OG&E evaluate the next steps necessary for compliance with the FERC's Order 2000. In the meantime, the SPP will continue to offer open access transmission service in the SPP region under the SPP Open Access Transmission Tariff. Termination of the proposed MISO/SPP combination and OG&E's continued membership in the SPP are not expected to significantly impact the Company's consolidated financial results.
In October 2001, the FERC issued a Notice of Proposed Rulemaking proposing to adopt new standards of conduct rules applicable to all jurisdictional electric and natural gas transmission providers. The proposed rules would replace the current rules governing the electric transmission and wholesale electric functions of electric utilities and the rules governing natural gas transportation and wholesale gas supply functions. The proposed rules would expand the definition of “affiliate” and further limit communications between transmission functions and supply functions, and could materially increase operating costs of market participants, including OG&E and Enogex. In April 2002, the FERC staff issued a reaction paper, generally rejecting the comments of parties opposed to the proposed rules. Final rules have been delayed while the FERC pursues development of its Standard Market Design Rulemaking.
In July 2002, the FERC issued a Notice of Proposed Rulemaking on Standard Market Design Rulemaking for regulated utilities. If implemented as proposed, the rulemaking will substantially change how wholesale markets operate throughout the United States. The proposed rulemaking expands the FERC’s intent to unbundle transmission operations from integrated utilities and ensure robust competition in wholesale markets. The rule contemplates that all wholesale and retail customers will be on a single network transmission service tariff. The rule also contemplates the implementation of a bid-based system for buying and selling energy in wholesale markets. RTOs or Independent Transmission Providers will administer the market. RTOs will also be responsible for regional plans that identify opportunities to construct new transmission, generation or demand side programs to reduce transmission constraints and meet regional energy requirements. Finally, the rule envisions the development of Regional Market Monitors responsible for ensuring the individual participants do not exercise unlawful market power. The FERC recently extended the comment period, but anticipates that the final rules will be in place in 2003 and the contemplated market changes will take place in 2003 and 2004.
On August 1, 2002, the FERC issued a Notice of Proposed Rulemaking proposing to adopt new rules governing corporate “money pools,” which include jurisdictional public utility or pipeline subsidiaries of nonregulated parent companies. The proposed rules would require documentation of transactions within such money pools, a proprietary capital account of the jurisdictional utility of 30 percent, and would require the nonregulated parent company to have an investment grade rating. Several parties have filed comments on the proposed rule. No final rule has been issued.
Regulatory Assets and Liabilities
OG&E, 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 costs that would otherwise be charged to expense can be deferred as
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regulatory assets, based on the expected recovery from customers in future rates. Likewise, certain credits that would otherwise reduce expense can be deferred as regulatory liabilities, based on the expected flowback to customers in future rates. Management’s expected recovery of deferred costs and flowback of deferred credits generally results from specific decisions by regulators granting such ratemaking treatment.
OG&E initially records costs: (i) that are probable of future recovery as a deferred charge until such time as the cost is approved by a regulatory authority, then the cost is reclassified as a regulatory asset; and (ii) that are probable of future liability as a deferred credit until such time as the amount is approved by a regulatory authority, then the amount is reclassified as a regulatory liability.
As discussed previously, legislation was enacted in Oklahoma and Arkansas that was to restructure the electric utility industry in those states. The Arkansas legislation was repealed and 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 would deregulate OG&E’s electric generation assets and cause the Company to discontinue the use of SFAS No. 71, with respect to its related regulatory assets. This may result in either full recovery of generation-related regulatory assets (net of related regulatory liabilities) or a non-cash, pre-tax write-off as an extraordinary charge of up to approximately $28.7 million, depending on the transition mechanisms developed by the legislature for the recovery of all or a portion of these net regulatory assets.
The previously enacted Oklahoma and Arkansas legislation would not affect OG&E’s electric transmission and distribution assets and the Company believes that the continued use of SFAS No. 71 with respect to the related regulatory assets is appropriate. However, if utility regulators in Oklahoma and Arkansas were to adopt regulatory methodologies in the future that are not based on the cost-of-service, the continued use of SFAS No. 71 with respect to the regulatory assets related to the electric transmission and distribution assets may no longer be appropriate. The Company has approximately $35.2 million of regulatory assets related to transmission and distribution assets. 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 Act, the actions of the FERC, the restructuring legislation in Oklahoma, and other factors are intended to increase competition in the electric industry. OG&E has taken steps in the past and intends to take appropriate steps in the future to remain a competitive supplier of electricity. While OG&E is supportive of competition, it believes that all electric suppliers must be required to compete on a fair and equitable basis and OG&E is advocating this position vigorously.
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Rate Activities and Proposals
In 2002, OG&E concluded its Oklahoma rate review proceeding before the OCC. This rate review was initiated in September 2001 by the OCC Staff and was concluded by order of the OCC on November 20, 2002. Under the rate review, OG&E, the OCC Staff, the Oklahoma Attorney General and other interested parties agreed to a Settlement Agreement which stipulated that OG&E would file tariffs, designed to reflect an annual reduction of $25.0 million in OG&E’s Oklahoma jurisdictional operating revenue. The $25.0 million annual reduction began on January 6, 2003.
Other elements of importance addressed in the Settlement Agreement stressed the importance of acquiring New Generation to meet growing customer electricity demands for 2004 and beyond; a modification of the sharing ratio of off-system sales, and the recognition of the reduction of cogeneration costs in OG&E’s retail rates in the years 2003 and beyond.
OG&E also received OCC approval in the Settlement Agreement for several new customer programs and rate options, as well as modifications to existing rate structures. The Guaranteed Flat Bill (“GFB”) option for residential and small general service accounts will allow 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 will benefit from the GFB option. A second tariff rate option approved in the Settlement Agreement is an offering to provide a “renewable energy” resource to OG&E’s Oklahoma retail customers. This renewable energy resource is a wind power purchase program and will be available as a voluntary option to all of OG&E’s Oklahoma retail customers. Oklahoma’s availability of wind resources makes the renewable wind power option a possible choice in meeting the renewable energy needs of our conservation-minded customers. A third new rate offering available to commercial and industrial customers is levelized demand billing. This program will be beneficial for medium to large size customers with seasonally consistent demand levels who wish to reduce the variability of their monthly electric bills. The levelized demand offering is not for every customer, but many customers will benefit from this program. The last new program being offered to OG&E’s commercial and industrial customers and approved by the OCC is a new voluntary load curtailment program. This program will provide customers with the opportunity to curtail on a voluntary basis when OG&E’s system conditions merit curtailment action. Customers that curtail their usage will receive payment for their curtailment response. This voluntary curtailment program seeks customers that can curtail on most curtailment event days, but may not be able to curtail every time that a curtailment event is required.
The previously discussed new rate options coupled with OG&E’s existing rate choices provide many tariff options for OG&E’s Oklahoma retail customers. OG&E’s rate choice flexibility, reduction in cogeneration rates, acquisition of additional generation resources, and overall low costs of production and deliverability are expected to provide valuable benefits for our customers for many years to come. OG&E began implementation of the new rate options during the first billing cycle in January 2003. Since many of these options are voluntary, customers may choose these options anytime after the January 2003 start date. The revenue impacts associated with these options are indeterminate since customers may choose to remain on existing rate options instead of volunteering for the new rate option choices. There is
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no overall material impact associated with these new rate options, but minimal revenue variations may occur based upon changes in customer’s usage characteristics if they choose these new programs.
Fuel Supply
During 2002, approximately 72 percent of the OG&E-generated energy was produced by coal units and 28 percent by natural gas units. Of the 5,696 total MW capability reflected in the table on page 36, approximately 3,160 MW’s or 55 percent are from natural gas generation and approximately 2,535 MW’s or 45 percent are from coal generation. Though OG&E has a higher installed capability of generation from natural gas units of 55 percent, it has been more economical to generate electricity for our customers using lower priced coal. With Oklahoma’s readily accessible supply of natural gas, OG&E was at one time 100 percent reliant upon natural gas as its fuel source for electric generation. In the early 1970‘s, OG&E turned to coal as a fuel source after natural gas was declared to be in limited supply and after enactment of the Fuel Use Act, which essentially prohibited any new electric generation fueled by natural gas. A slight decline in the percentage of coal generation in future years is expected to result from increased usage of natural gas generation required to meet growing energy needs. Over the last five years, the average cost of fuel used, by type, per million British thermal unit (“MMBtu”) was as follows:
2002 2001 2000 1999 1998
- ---------------------------------------------------------------------------------------------------
Coal............................ $ 0.93 $ 0.81 $ 0.87 $ 0.85 $ 0.85
Natural Gas..................... $ 3.78 $ 4.91 $ 4.93 $ 3.14 $ 2.83
Weighted Average................ $ 1.77 $ 1.97 $ 1.96 $ 1.54 $ 1.48
A portion of the fuel cost is included in base rates and differs for each jurisdiction. The portion of these costs that is not included in base rates is recovered through automatic fuel adjustment clauses. See "Regulation and Rates - Automatic Fuel Adjustment Clauses."
Coal
All of OG&E's coal units, with an aggregate capability of approximately 2,535 MW's, are designed to burn low sulfur western coal. OG&E purchases coal primarily under long-term contracts. During 2002, OG&E purchased approximately 10.7 million tons of coal from the following Wyoming suppliers: Kennecott Energy Company, Arco Coal Company, Peabody Coal Sales Company and Triton Coal Company. The combination of all coal has a weighted average sulfur content of less than 0.24 percent and can be burned in these units under existing federal, state and local environmental standards (maximum of 1.2 lbs. of sulfur dioxide per MMBtu) without the addition of sulfur dioxide removal systems. Based upon the average sulfur content, OG&E's units have an approximate emission rate of 0.504 lbs. of sulfur dioxide per MMBtu. In anticipation of the more strict provisions of Phase II of The Clean Air Act, which began in the year 2000, OG&E had contracts in place to allow for a supply of very low sulfur coal from suppliers in the Powder River Basin to meet the new sulfur dioxide standards.
OG&E has continued its efforts to maximize the utilization of its coal units at both the Sooner and Muskogee generating plants. See "Environmental Matters" for a discussion of an
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environmental proposal that, if implemented as proposed, could inhibit OG&E's ability to use coal as its primary boiler fuel.
Natural Gas
OG&E utilized a request for bid to acquire approximately 90 percent of its projected annual natural gas requirements for 2003. These contracts are tied to various gas price market indices and most will expire in April 2004. The remaining gas requirements of OG&E will be secured through monthly and day-to-day purchases as required.
In 1993, OG&E began utilizing a natural gas storage facility that allows OG&E to optimize the use of its generation assets.
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NATURAL GAS PIPELINE OPERATIONS - ENOGEX
The Natural Gas Pipeline segment is conducted through Enogex and consists of three related businesses: (i) the transportation and storage of natural gas, (ii) the gathering and processing of natural gas, and (iii) the marketing and trading of natural gas (collectively, the “pipeline businesses”). The vast majority of Enogex’s natural gas gathering, processing, transportation and storage assets are located in the major gas producing basins of Oklahoma. Enogex and its subsidiaries operate approximately 9,300 miles of gas gathering and transportation pipelines. Additionally, through a 75 percent interest in NOARK, Enogex also owns a controlling interest in and operates Ozark, a FERC regulated interstate pipeline that extends from southeast Oklahoma through Arkansas to southeast Missouri. Enogex’s marketing and trading activities include corporate price risk management and other optimization services. Enogex was previously engaged in the exploration and production of natural gas, however, this portion of Enogex’s business, along with interests in certain gas gathering and processing assets in Texas were sold in 2002 and 2003 and are reported in the Consolidated Financial Statements as discontinued operations.
The pipeline and storage assets of Enogex provide OG&E strategic access to natural gas supplies, and flexible and reliable delivery terms that are required to fuel OG&E's gas-fired generators. The natural gas generation peaking units require the ability to quickly change their status, to meet both the peak and off-peak demands of the retail load particularly when coal units have an unscheduled outage. The Enogex pipeline assets access major wellhead supply sources primarily located across Oklahoma and Arkansas, and the Enogex storage assets provide the ability to regulate the receipt and delivery of natural gas to match the instantaneous needs of these generation units.
Gas units contribute their highest value when they have the capability to provide "load following" service to the customer. While the physical characteristics of gas units are known to provide quick start-up and on-line functionality, and while their ability to efficiently provide varying levels of electric generation relative to other forms of generation is further acknowledged, their ultimate effectiveness is contingent upon having access to an integrated pipeline and storage system that can respond in a short term fashion to meet its corresponding fluctuating operational fuel requirements. The combination of these assets is critical to OG&E's ability to provide reliable generation service at reasonable prices to the consumer.
Not only is Enogex providing service to its own generation affiliate, but the same assets provide firm and interruptible services to a significant portion of the other gas-fired generation and numerous other loads in the State of Oklahoma, as well as certain such requirements in the adjoining States of Texas and Arkansas. Enogex understands the needs of generators, and more importantly has the appropriately sized pipelines, compression and storage assets necessary to meet their requirements.
Through Enogex's gathering and processing assets, Enogex aggregates gas supplies not only for its own markets but also, for those markets accessible via its numerous intrastate and interstate pipeline connections. It aggressively pursues new supplies from wells drilled by producers primarily in the prolific Anadarko and Arkoma basins. The system capacity, due to its large diameter pipelines and its natural gas processing plants, is capable of adapting to the
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varying pressure and quality requirements of the mid-continent production. Enogex is able to provide low-pressure service to extend the production life of older wells as well as meeting the high-pressure requirements of new exploration.
The activities described above, while central to Enogex's operations, are not its only businesses. The transmission capabilities and "on and off-system" markets of the pipeline assets provide other business opportunities. An equally important and valuable feature of Enogex and its assets is the ability of Enogex to use its pipeline system and storage assets as a "market hub". There are 60 major pipeline connections with 15 other intrastate and interstate pipeline companies providing access to markets in the western United States, the mid-west, northeast, and Gulf Coast in addition to Oklahoma and adjoining states. Therefore, regardless of the ever varying relationship between supply and market, both in volume and location, Enogex's assets sit in the geographic center of the United States, with sufficient capacity to provide cross-haul transportation and storage services to a variety of utility and industrial customers that need to access mid-continent supply for their own needs, or to suppliers from other regions seeking to provide gas to on-system markets which Enogex serves.
The marketing and trading businesses are an important element in realizing the full value from the pipeline and storage assets and in providing products and services that support the market hub strategy. The marketing and trading business offers the Company real–time and longer–term price discovery and capacity valuation for energy commodities (power, natural gas, and associated natural gas liquids) associated with the Company's assets. It is also instrumental in providing increased liquidity for these energy commodities, by focusing on developing supplies and markets that can access the Enogex systems either directly or via interconnections with intrastate and interstate pipelines. The marketing and trading businesses also provide the Company the capability of providing risk management services to its customers.
The Company intends to continue to build upon the foundation of services and products, which these assets can provide. In addition, the Company expects to realize incremental profit, by improving its ability to aggregate gas and to optimize its position based upon the information available from its operations and the marketplace.
Recent Actions
During 2002, Enogex evaluated, redesigned and reorganized its internal work processes in order to achieve cost reductions and revenue enhancements within its businesses. Enogex is beginning to see the positive results of these efforts and expects continued improvement during 2003. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Forward-Looking Statements.”
After a review of Enogex’s assets on the basis of their strategic value and other factors, the Company sold all of its exploration and production assets and its interest in Belvan Corp., Belvan Limited Partnership and Todd Ranch Limited Partnership (“Belvan”) in 2002 and its interest in the NuStar Joint Venture (“NuStar”) in February 2003. These dispositions have been reported as discontinued operations for the years ended December 31, 2002, 2001 and 2000 in the Consolidated Financial Statements.
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On August 2, 2002, Ozark entered into an Agreement of Sale and Purchase with CenterPoint Energy Gas Transmission Co. to sell approximately 29 miles of transmission lines of the Ozark pipeline located in Pittsburg and Latimer counties in Oklahoma. On November 18, 2002, the Company received FERC approval for the closing, which occurred on January 6, 2003.
On January 23, 2003, Enogex entered into an Agreement of Sale and Purchase with Benedum Gas Partners, L.P. to sell all of its interest in NuStar. The effective date of the sale was January 1, 2003 and the closing occurred on February 18, 2003.
In October 2002, the Emerging Issues Task Force (“EITF”) reached a consensus on certain issues covered in EITF No. 02-3, “Issues Related to Accounting for Contracts Involved in Energy Trading and Risk Management Activities.” One consensus of EITF 02-3 requires that all mark-to-market gains and losses, whether realized or unrealized, on financial derivative contracts as defined in SFAS No. 133 be shown net in the Income Statement for financial statements issued for periods beginning after December 15, 2002, with reclassification required for prior periods presented. The Company has adopted this consensus effective January 1, 2003 and the application of this consensus did not have a material impact on its consolidated financial position or results of operations as this consensus supports the Company’s historical presentation of financial derivative contracts.
In October 2002, the EITF reached a consensus to rescind EITF Issue No. 98-10, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities”, as amended effective for fiscal periods beginning after December 15, 2002. Effective October 25, 2002, all new contracts and physical inventories that would have been accounted for under EITF 98-10 are no longer marked to market through earnings unless the contracts meet the definition of derivative under SFAS No. 133. Application of the consensus for energy contracts and inventory that existed on or before October 25, 2002 that remain in effect at the date this consensus is initially applied will be recognized as a cumulative effect of a change in accounting principle in accordance with Accounting Principles Board Opinion No. 20, “Accounting Changes.” As a result, only energy contracts that meet the definition of a derivative in SFAS No. 133 will be carried at fair value. The Company has adopted this consensus effective January 1, 2003 resulting in an approximate $5.9 million after tax loss. The loss, which will be accounted for as a cumulative effect of a change in accounting principle, is primarily related to natural gas held in storage for trading purposes.
During the fourth quarter of 2002, Enogex recognized a pre-tax impairment loss of approximately $48.3 million. The impairment loss related to natural gas processing and compression assets. The impairments resulted from plans to dispose of these assets at prices below the carrying amount. The fair value of these assets was determined based on third-party evaluations, prices for similar assets, historical data and projected cash flows. See Note 4 of Notes to Consolidated Financial Statements for a further discussion.
FERC Section 311 Rate Case
In December 2001, Enogex made its filing at the FERC under Section 311 of the Natural Gas Policy Act to establish rates and a default processing fee and to address various other issues,
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for the combined Enogex and Transok pipeline systems effective January 1, 2002. Effective January 1, 2002, these systems began operating as a single Enogex pipeline system. The FERC Staff, Enogex and the active intervening parties have conducted settlement discussions. Enogex has negotiated a settlement of the case with the interveners. A Stipulation and Agreement of Settlement and related documents were filed with the FERC on March 5, 2003 to resolve all issues in dispute in Docket No. PR02-10-000. Comments are due March 25, 2003 and reply comments will be due April 4, 2003. The proposed settlement includes a fee for processing to bring gas gathered behind processing plants to pipeline gas quality Btu standards (processing fee) and a monthly low flow meter charge of $200 (offset in any month by the transportation revenues generated by gas through the meter). If the settlement is approved, Enogex will have no refund obligation. The outcome of this rate case will not have an adverse effect on the Company’s consolidated financial position or results of operations as any default processing fee billed through February 2003 has been fully reserved on the Company’s books. The Company expects to be charging a default processing fee this year and to recognize such fees in the Income Statement.
Transportation and Storage
General. One of Enogex’s primary lines of business is the transportation of natural gas, with current throughput of approximately 1.5 billion cubic feet per day ("Bcfd"). Enogex delivers natural gas to most interstate and intrastate pipelines and end-users connected to its systems from the Arkoma basin of eastern Oklahoma and Arkansas, the Anadarko basin of western Oklahoma and the Panhandle of west Texas. At December 31, 2002, Enogex was connected to 15 other major pipelines at approximately 60 pipeline interconnect points. These interconnections include Panhandle Eastern Pipe Line, Southern Star Central Gas Pipeline (formerly Williams Central), Natural Gas Pipeline Company of America, Oneok Gas Transmission, Northern Natural Gas Company, ANR Pipeline, Western Farmers Electric Cooperative and CenterPoint Energy Gas Transmission Co., as well as connections via Enogex’s Ozark system to Texas Eastern and Mississippi River Transmission. Further, Enogex is connected to various end-users including much of the natural gas generation facilities in Oklahoma. At December 31, 2002, the net property, plant and equipment balance for Enogex's transportation and storage business was approximately $764.2 million.
Enogex owns two storage facilities in Oklahoma, the Greasy Creek Facility and the Stuart Storage Facility. The Greasy Creek Facility has a working capacity of approximately 18 billion cubic feet (“Bcf”) with a maximum daily deliverability of 450 million cubic feet per day (“MMcfd”) and similar injection capability. Enogex offers both firm and interruptible storage services to third parties, under Section 311 of the Natural Gas Policy Act ("NGPA"), under terms and conditions specified in its Statement of Conditions for Gas Storage and at market-based rates to be negotiated with each customer. During 2002, Enogex expensed approximately $4.0 million for gas losses associated with the Greasy Creek storage field. While gas losses are normally associated with the operation of a natural gas storage field, this amount exceeds normal allowances. Enogex is currently analyzing the field and is taking actions to mitigate future losses.
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Enogex also recently purchased the Stuart Storage Facility from Central Oklahoma Oil and Gas Corp. (“COOG”). The Stuart Storage Facility has a working capacity of approximately 13 Bcf. The Stuart Storage Facility is used exclusively to support Enogex’s intrastate transportation and storage services for OG&E. See "Item 3. Legal Proceedings" for a discussion of the pending litigation associated with the purchase of the Stuart Storage Facility.
Enogex offers both firm and interruptible transportation services to customers with a majority of transportation revenues derived from firm contracts. Enogex offers interruptible service to customers when capacity is available.
Effective January 1, 2002, the Enogex and Transok L.L.C. (and its subsidiaries) (“Transok”) pipeline systems have been merged to simplify for both Enogex and its customers the administration and operation of maintaining two separate pipelines. Enogex provides firm intrastate transportation services to OG&E as well as Public Service Company of Oklahoma (“PSO”), the second largest electric utility in Oklahoma, serving the Tulsa market. In July 1999, Enogex acquired Transok. Transok maintained a sole-supplier relationship with PSO until 1998, when Oklahoma Natural Gas began supplying gas to three of the PSO generating stations pursuant to a competitive bid process put in place by the OCC. Notwithstanding the loss of the sole-supplier status, Enogex remains as the primary supplier to PSO. Enogex continues to provide gas transmission delivery services to all of PSO’s gas-fueled electric generation units in Oklahoma under a firm intrastate transportation contract. The current PSO contract, which expires January 1, 2005, and the OG&E contract, which expires April 30, 2004, provide for a monthly demand charge plus a variable transportation rate. In addition, Enogex provides transportation services via the leased Palo Duro pipeline system to Houston Pipe Line Company (“HPC”), an affiliate of PSO, for gas delivery service to certain HPC generating stations in the Texas panhandle. The lease for the Palo Duro pipeline terminates on June 30, 2003 unless Enogex exercises its option to renew the lease for an additional five year period. Enogex continues to evaluate the option to renew the lease but has not made any decision in that regard. During 2002, 2001 and 2000, Enogex’s revenues from the contracts with OG&E, PSO and HPC were approximately $53.9 million, $54.9 million and $54.5 million, respectively.
Relationship with OG&E. From its inception, Enogex has been the exclusive transporter of natural gas to OG&E electric power generating stations. Although Enogex is not directly regulated by the OCC, OG&E’s rates are subject to OCC jurisdiction. The OCC issued an order on November 20, 2002 which contained a provision, among other things, that OG&E would consider competitive bidding as an option in obtaining gas transportation service for its natural gas generating facilities when Enogex’s current contract expires in April 2004. The amount collected from OG&E by Enogex under the current contract was approximately $33.6 million, $36.3 million and $37.4 million, respectively, during 2002, 2001 and 2000, respectively.
Competition. Enogex’s pipeline and storage assets compete with interstate and other intrastate pipeline and storage facilities in the transportation and storage of natural gas. The principal elements of competition are rates, terms of services and flexibility and reliability of service.
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Natural gas competes with other forms of energy available to Enogex’s customers and end-users, including electricity, coal and fuel oils. The primary competitive factor is price. Changes in the availability or price of natural gas or other forms of energy as well as weather and other factors affect the demand for natural gas on the Enogex system.
Regulation. The rates charged by Enogex for transporting natural gas on behalf of an interstate natural gas pipeline company or a local distribution company served by an interstate natural gas pipeline company are subject to the jurisdiction of the FERC under Section 311 of the NGPA. Rates to provide such service must be "fair and equitable" under the NGPA and are subject to review and approval by the FERC at least once every three years. This rate review may involve an administrative-type trial and an administrative appellate review. By offering interruptible Section 311 transportation, the regulatory burden on Enogex is not appreciably increased, but does give Enogex the opportunity to utilize any unused capacity on an interruptible basis in interstate commerce and thus increase its transportation revenues. See "FERC Section 311 Case” for a discussion of Enogex’s current Section 311 case. As noted above, Ozark as an interstate pipeline is regulated by the FERC under The Natural Gas Act of 1938, as amended (the "Natural Gas Act").
The Company, through Enogex, owns a 75 percent interest in Ozark. Ozark transports natural gas in interstate commerce. As a result, it qualifies as a "natural gas company" under the Natural Gas Act, and is subject to the regulatory jurisdiction of the FERC. Under the Natural Gas Act, the FERC has jurisdiction to review and authorize the proposed construction of facilities for the transportation of natural gas in interstate commerce, the rendition of service through interstate facilities, the rates charged for such service, and the abandonment of such facilities or of services.
The Natural Gas Act requires that the rates charged, and the terms and conditions of service observed, by interstate pipelines be "just and reasonable", and not unduly discriminatory or preferential. All rates and terms and conditions of service proposed by an interstate pipeline must be filed with the FERC, and the FERC has jurisdiction under the Natural Gas Act to determine whether proposed rates or terms and conditions meet the statutory standards. The Act confers upon the FERC authority to determine a jurisdictional pipeline's rates, charges and terms and conditions of service, to establish depreciation rates and to prescribe uniform systems of accounts.
The rates charged by Enogex for transporting natural gas for OG&E and other shippers within Oklahoma are not subject to FERC regulation because they are intrastate transactions. With respect to state regulation, the rates charged by Enogex for any intrastate transportation service have not been subject to direct state regulation by the OCC, which is the state agency responsible for setting rates of public utilities within Oklahoma. Even though the intrastate pipeline business of Enogex is not directly regulated by the OCC, the OCC, the Arkansas Commission and the FERC (all of which approve various electric rates of OG&E) have the authority to examine the appropriateness of any transportation charges or other fees paid by OG&E to Enogex which OG&E seeks to recover from its ratepayers in its cost-of-service for electric service. See "Relationship with OG&E" below for a discussion of competitive bidding for OG&E's service.
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Enogex's pipeline operations are subject to various Oklahoma safety and environmental and non-discriminatory transportation requirements.
Gathering and Processing
General. Natural gas gathering operations are conducted through Enogex Gas Gathering L.L.C., and gas processing operations are conducted through Enogex Products Corporation (“Products”). The streams of processable natural gas gathered from wells and other sources are gathered through Enogex’s gas gathering systems to processing plants for the extraction of natural gas liquids. Products is one of the largest gas processors in the state of Oklahoma, owning 10 gas processing plants (of which seven are currently being operated) with an inlet capacity of over one Bcfd. During 2002, Products had ownership interests in two other gas processing plants related to NuStar, which were sold in February 2003. In 2002, it produced approximately eight million gross barrels of natural gas liquids. Products has been active since 1968 in the processing of natural gas and marketing of natural gas liquids. Products natural gas processing plant operations consist of the extraction and sale of natural gas liquids. The products extracted include condensate, marketable ethane, condensate, marketable ethane, propane, butanes and natural gasoline mix. The residue gas remaining after the liquid products have been extracted consists primarily of ethane and methane. At December 31, 2002, the net property, plant and equipment balance for Enogex's gathering and processing business was approximately $352.3 million.
Approximately 21 percent of the commercial grade propane processed at Products' plants is sold on the local market. The other natural gas liquids produced by Products are delivered into pipeline facilities of Koch Hydrocarbon and transported to Conway, Kansas and Mont Belvieu, Texas, where they are sold under contract or on the spot market. Ethane, which may be optionally produced at all of Products' plants except one, is sold in the spot market under a contract with Equistar Chemicals LP.
During 2002, Enogex took steps to decrease the volatility of its earnings stream by reducing its exposure to keep whole processing arrangements. Keep whole processing arrangements generally require a processor of natural gas to keep its shippers whole on a Btu basis and, thereby replacing the Btu value of the liquids with natural gas at market prices. Therefore, if natural gas prices increase and liquids prices do not increase by a corresponding amount, processing margins are negatively affected. In order to minimize the negative impact on processing margins, ethane and propane are rejected whenever possible. Exposure to keep whole processing arrangements was reduced through contract renegotiations and changes in the standards of service provided by Enogex under the FERC Section 311 filing discussed previously that provides for a processing fee in the event the fractionation spreads are negative. As a result of these actions, exposure to keep whole processing arrangements (without the processing fee provision) has been reduced to approximately 21 percent of total inlet volumes projected in 2003. The remaining 2003 projected inlet volumes are approximately 39 percent keep whole with the processing fee, 31 percent liquids and nine percent fixed fee. In addition, the Company actively monitors current and future prices for opportunities to hedge the processing margin. Enogex has executed physical and financial hedges by selling liquids forward as well as hedging the fractionation spread of various liquids' components. As of
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March 19, 2003, Enogex had hedged approximately 38 percent of its projected equity liquid volumes attributable to percentage of liquids agreements and approximately 10 percent of its projected keep whole processing volumes.
After a review of Enogex’s assets on the basis of their strategic value and other factors, the Company sold all of its interest in Belvan in 2002 and its interest in NuStar in February 2003. These dispositions have been reported as discontinued operations for the years ended December 31, 2002, 2001 and 2000 in the Consolidated Financial Statements. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations-Discontinued Operations” for a further discussion.
Competition. In processing and marketing natural gas liquids, Products competes against virtually all other gas processors producing and selling natural gas liquids. Competition for natural gas supply is based on efficiency and reliability of operations, reputation, availability of gathering and transportation to markets and pricing arrangements offered by the gatherer/processor. Products believes it will be able to continue to compete against such companies.
With respect to the profitability of the natural gas liquids industry generally, as the price of natural gas liquids fall without a corresponding decrease in the price of natural gas, it may become uneconomical to extract certain natural gas liquids. As explained under “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations”, this factor had a significant adverse impact on the results of Enogex during 2001. In addition to the commodity pricing impact that affects the entire industry, the profitability of Products is also largely affected by the volume of natural gas processed at its plants which is highly dependent upon the volume of natural gas gathered by the Enogex pipeline systems. Generally, if the volume of natural gas gathered increases, then the volume of liquids extracted by Products should also increase.
Marketing and Trading
Enogex’s commodity sales and services related to natural gas and electric power are conducted by Enogex primarily through its subsidiary, OGE Energy Resources, Inc. (“OERI”).
Natural Gas. OERI is engaged in the business of gas marketing. OERI's agreements with Enogex provide for OERI to provide marketing services for all natural gas volumes purchased by the pipeline at the wellhead from producers or otherwise. As a service to the producers on the Enogex system, Enogex may agree to purchase the gas at the wellhead in conjunction with gathering their gas for transportation to other markets.
OERI also purchases and sells natural gas pursuant to contracts with Enogex and Products relating to Enogex’s pipeline gathering, processing and storage assets. OERI marketed the natural gas produced by Enogex Exploration Corporation (“Exploration”) (prior to the sale of Exploration’s assets). In 2000, OERI purchased gas for OG&E. However, this was discontinued in 2001 and 2002. At December 31, 2002, the net property, plant and equipment balance for Enogex's marketing and trading business was approximately $3.5 million.
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OERI focuses on serving customers along the natural gas value chain, from producers to end-users, by purchasing natural gas from suppliers both on and off the Enogex and Ozark pipeline systems and reselling to pipelines, local distribution companies and end-users, including the electric generation sector.
The geographic scope of marketing efforts has been focused largely in the mid-continent area of the United States. These markets are natural extensions of OERI’s business on the Enogex system. OERI contracts for Enogex pipeline capacity to access multiple interconnections with the interstate pipeline system that moves natural gas from the production basins in the south central United States to the major consumption areas in Chicago, New York and other north central and mid Atlantic regions of the United States.
OERI participates in both long-term markets and short-term “spot” markets for natural gas. Although OERI continues to increase its focus on long-term sales, short-term sales of natural gas will continue to play a critical role in the overall strategy because they provide an important source of market intelligence as well as an important portfolio balancing function. In 2002, OERI bought and sold approximately 2.2 Bcfd of natural gas, of which approximately 25 percent moved on the Enogex pipeline system.
OERI’s risk management skills afford its customers the opportunity to tailor the risk profile and composition of their natural gas portfolio. The Company follows a policy of hedging price risk on gas purchases or sales contracts entered into by the marketing group by buying and selling natural gas futures contracts on the New York Mercantile Exchange futures exchange and other derivatives in the over-the-counter market, subject to a $2.5 million annual trading loss limit in accordance with corporate policies.
Electricity. OERI participates actively as a wholesale purchaser and reseller in the physical wholesale power markets of the mid-continent region. It has a fully-staffed 24-hour power desk that continually monitors the physical marketplace seeking to capture arbitrage opportunities by matching market participants with power surpluses to those market participants with power needs, primarily on an hourly or daily basis. OERI no longer participates in any speculative electricity trading activities. The expertise of OERI’s power desk in managing customer requirements and the complexities of the transmission grid provide OERI the opportunity to extract value from the daily marketplace. As the physical power broker for OG&E, OERI assists in the sale to and purchase from the physical power markets as required to meet the needs of OG&E. In accordance with applicable FERC affiliate rules, since March 2000, virtually all of OG&E’s surplus power sales activity has been performed by OERI who sold approximately 2,500 MW’s per day in 2002.
Competition. Marketing and Trading competes with major integrated oil companies, major interstate and intrastate pipelines, national and local natural gas brokers, marketers and distributors for natural gas supplies and in marketing and trading natural gas. Competition for natural gas supplies is based primarily on reputation, the availability of gathering and transportation to high-demand markets and the ability to obtain a satisfactory price for the producer's natural gas. Competition for sales to customers is based primarily upon reliability, services offered and price of delivered natural gas.
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For the year ended December 31, 2002, approximately 78 percent of OERI’s service volumes were with electric utilities, local gas distribution companies, pipelines and producers. The remaining 22 percent of service volumes were to marketers, municipals, cooperatives and industrials. As of December 31, 2002, approximately 79.5 percent of the exposure was to companies having investment grade ratings with Standard & Poor’s Ratings Services ("Standard & Poor's") and approximately 0.5 percent having less than investment grade ratings. The remaining 20 percent of OERI’s exposure is with privately held companies, municipals or cooperative that were not rated by Standard & Poor’s. These non-rated companies have satisfied our internal credit analyses and policies.
Exploration and Production
After a review of Enogex’s assets on the basis of their strategic value and other factors, the Company sold all of its exploration and production assets in 2002. These dispositions have been reported as discontinued operations for the years ended December 31, 2002, 2001 and 2000 in the Consolidated Financial Statements. The exploration and production activities were conducted through Exploration, which was formed in 1988 primarily to engage in the development and production of oil and natural gas. Exploration focused its early drilling activity in the Antrim Devonian shale trend in the state of Michigan and in recent years had concentrated on drilling opportunities in Oklahoma. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations–Results of Operations–Discontinued Operations” for a further discussion.
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FINANCE AND CONSTRUCTION
Capital requirements and future contractual obligations estimated for 2003 through 2006 and beyond are as follows:
- ----------------------------------------------------------------------------------------------------------
Actual 2006 and
(In millions) 2002 2003 2004 2005 Beyond
- ----------------------------------------------------------------------------------------------------------
OG&E capital expenditures including AFUDC......... $ 198.7 (A) $ 149.0 (B) $ 142.0 $ 142.0 N/A
Enogex capital expenditures and acquisitions (C).. 20.0 39.0 35.0 28.0 N/A
Other Operations capital expenditures............. 15.8 8.0 8.0 8.0 N/A
- ----------------------------------------------------------------------------------------------------------
Total capital expenditures.................. 234.5 196.0 185.0 178.0 N/A
Maturities of long-term debt...................... 115.0 20.8 52.8 146.1 $1,303.2
Retirement of long-term debt...................... 25.0 10.0 (D) N/A N/A N/A
- ----------------------------------------------------------------------------------------------------------
Total capital requirements.................. 374.5 226.8 237.8 324.1 1,303.2
Operating lease obligations
OG&E railcars.................................. 5.4 5.4 5.4 5.4 46.9
Enogex noncancellable operating leases......... 4.3 4.3 3.6 3.5 5.2
- ----------------------------------------------------------------------------------------------------------
Total operating lease obligations........... 9.7 9.7 9.0 8.9 52.1
Unconditional purchase obligations
OG&E cogeneration capacity payments............ 192.1 164.7 152.7 87.7 173.6
OG&E other purchased power capacity payments... 10.7 14.6 N/A N/A N/A
OG&E fuel minimum purchase commitments......... 164.1 152.2 145.6 147.2 565.4
- ----------------------------------------------------------------------------------------------------------
Total unconditional purchase obligations.... 366.9 331.5 298.3 234.9 739.0
Total capital requirements, operating lease
obligations and unconditional purchase
obligations..................................... 751.1 568.0 545.1 567.9 2,094.3
Amounts recoverable through automatic fuel
adjustment clause (E)........................... (370.8) (334.9) (303.7) (240.3) (785.9)
- ----------------------------------------------------------------------------------------------------------
Total, net.................................. $ 380.3 $ 233.1 $ 241.4 $ 327.6 $1,308.4
==========================================================================================================
(A) Includes approximately $86.6 million from the January 2002 ice storm.
(B) Amounts do not include the acquisition of New Generation.
(C) Amounts exclude discontinued operations capital expenditures.
(D) Reflects amounts that have been called to date for redemption in 2003.
(E) Includes expected recoveries of costs incurred for OG&E's railcar operating lease obligations
and OG&E's unconditional purchase obligations.
N/A - not applicable
Variances in the actual cost of fuel used in electric generation (which includes the operating lease obligations for OG&E’s railcar leases shown above) and certain purchased power costs, as compared to the fuel component included in the cost-of-service for ratemaking, are passed through to OG&E’s customers through automatic fuel adjustment clauses. Accordingly, while the cost of fuel related to operating leases and the vast majority of unconditional purchase obligations of OG&E 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
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subject to periodic review by the OCC, the APSC and the FERC. The OCC, the APSC and the FERC also have authority to review the appropriateness of gas transportation charges or other fees OG&E pays to Enogex. See Note 16 of Notes to Consolidated Financial Statements for a further discussion.
The Company’s primary needs for capital are related to replacing or expanding existing facilities in OG&E’s electric utility business and replacing or expanding existing facilities at Enogex. Other capital requirements are primarily related to maturing debt, operating lease obligations, hedging activities, natural gas storage and delays in recovering unconditional purchase obligations. The Company generally meets its cash needs through a combination of internally generated funds, short-term borrowings and permanent financings. Enogex retired $140.0 million of long-term debt that matured or was redeemed in 2002 with internally generated funds, funds from the sale of assets and short-term debt.
The amounts shown in the chart on page 29 do not include the cost of acquiring an electric generating plant with at least 400 MW of capacity, which OG&E intends to acquire during 2003 in accordance with the Settlement Agreement approved by the OCC on November 20, 2002. Any generating facility acquired by OG&E is expected to be financed through the issuance of common stock by the Company and through the issuance of debt by OG&E.
The Company’s 2003 to 2005 construction program does not include the building of any additional generating units. Instead, in accordance with the Settlement Agreement approved by the OCC on November 20, 2002, OG&E intends to purchase an electric generating plant with at least 400 MW’s of generating capacity. The Company believes that an efficient combined cycle plant can be purchased for a price less than the cost to build a new facility. To reliably meet the increased electricity needs of OG&E’s customers during the foreseeable future, OG&E will continue to invest to maintain the integrity of the delivery system. Approximately $4.9 million of the Company’s capital expenditures budgeted for 2003 are to comply with environmental laws and regulations.
Apart from the funds required to purchase at least 400 MW’s of a power plant pursuant to the Settlement Agreement, management expects that internally generated funds will be adequate over the next three years to meet other anticipated capital expenditures, operating needs, payment of dividends and maturities of long-term debt.
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Short-term borrowings will be used to meet working capital requirements. The following table shows the Company’s lines of credit in place at March 10, 2003. Short-term borrowings will consist of a combination of bank borrowings and commercial paper.
Lines of Credit (In millions)
-----------------------------------------------------------------------
Entity Amount Maturity
-----------------------------------------------------------------------
OGE Energy Corp. (A) $ 15.0 April 6, 2003
200.0 January 8, 2004
100.0 January 15, 2004
OG&E 100.0 June 26, 2003
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Total $ 415.0
=======================================================================
(A) The lines of credit at OGE Energy Corp. were used to back up the
Company's commercial paper borrowings, which were approximately $168.5
million at March 10, 2003. No borrowings were outstanding at
March 10, 2003 under any of the lines of credit shown above.
The Company’s ability to access the commercial paper market could be adversely impacted by a commercial paper ratings downgrade. The lines of credit contain ratings triggers that require annual fees and borrowing rates to increase if the Company suffers an adverse ratings impact. The impact of a downgrade of the Company’s rating would result in an increase in the cost of short-term borrowings of approximately five to 20 basis points, but would not result in any defaults or accelerations as a result of the ratings triggers. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Future Capital Requirements” for potential financing needs upon a downgrade by Moody’s Investors Service of Enogex’s long-term debt rating.
Also contributing to the liquidity of the Company have been numerous asset sales by Enogex. Since January 1, 2002, completed sales generated proceeds of approximately $103.8 million. Sales proceeds generated to date have been used to reduce debt at Enogex and commercial paper at the holding company.
Unlike the Company and Enogex, OG&E must obtain regulatory approval from the FERC in order to borrow on a short-term basis. OG&E has the necessary regulatory approvals to incur up to $400 million in short-term borrowings at any one time.
The Company continues to evaluate opportunities to enhance shareowner returns and achieve long-term financial objectives through acquisitions of assets that may complement its existing portfolio. Permanent financing would be required for any such acquisitions.
ENVIRONMENTAL MATTERS
Approximately $4.9 million of the Company’s capital expenditures budgeted for 2003 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
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enhance environmental quality will be approximately $54.1 million during 2003, compared to approximately $44.2 million utilized in 2002. 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.
Several pieces of national legislation were introduced in 2002 requiring the reduction in emission of sulfur dioxide (“SO2”), nitrogen oxide (“NOX”), carbon dioxide (“CO2”) and mercury from the electric utility industry. Among those was President Bush’s “Clear Skies” proposal. While not addressing CO2, this bill would require significant reductions in SO2, NOX and mercury emissions. None of the proposed legislation became law; however, it is expected that numerous multi-pollutant bills will again be introduced in 2003.
As required by Title IV of the Clean Air Act Amendments of 1990 (“CAAA”), OG&E completed installation and certification of all required continuous emissions monitors at its generating stations in 1995. Since then OG&E has submitted emissions data quarterly to the Environmental Protection Agency (“EPA”) as required by the CAAA. Beginning in 2000, OG&E became subject to more stringent SO2 emission requirements. These lower limits had no significant financial impact due to OG&E’s earlier decision to burn low sulfur coal. In 2002, OG&E’s SO2 emissions were well below the allowable limits.
With respect to the NOX regulations of Title IV of the CAAA, OG&E committed to meeting a 0.45 lbs/MMBtu NOX emission level in 1997 on all coal-fired boilers. As a result, OG&E was eligible to exercise its option to extend the effective date of the lower emission requirements from the year 2000 until 2008. OG&E’s average NOX emissions from its coal-fired boilers for 2002 was 0.32 lbs/MMBtu. However, further reductions in NOX emissions could be required if, among other things, proposed legislation is enacted requiring further reductions, a study currently being conducted by the state of Oklahoma determines that such NOX emissions are contributing to regional haze, if it is determined by the state of Oklahoma that OG&E’s facilities impact the air quality of the Tulsa or Oklahoma City metropolitan areas or if Oklahoma fails to meet the new fine particulate standards. Any of these scenarios would require significant capital and operating expenditures.
The Oklahoma Department of Environmental Quality’s Clean Air Act Amendment Title V permitting program was approved by the EPA in March 1996. By March of 1997, OG&E had submitted all required permit applications. As of December 31, 2002, OG&E had received Title V permits for all but one of its generating stations. Since OG&E submitted all of its permit applications on time it is considered in compliance with the Title V permit program even though all permits have not been issued. Air permit fees for generating stations were approximately $0.5 million in 2002. Due to an increase in fee amounts by the Oklahoma Department of Environmental Quality ("ODEQ") the fees for 2003 are estimated to be approximately $0.6 million.
Other potential air regulations have emerged that could impact OG&E. On December 14, 2000, the EPA announced its decision to regulate mercury emissions from coal-fired boilers. Limits on the amount of mercury emitted are expected to be finalized by December 2004, although full compliance by OG&E is not expected to be required until 2008. Depending
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upon the final regulations implemented, this could result in significant capital and operating expenditures.
In 1997, the EPA finalized revisions to the ambient ozone and particulate standards. After a court challenge, which delayed implementation, the EPA has now begun to finalize the implementation process. Based on the most recent monitoring data, it appears that the Tulsa metropolitan area will fail to meet the revised standard. However, Tulsa has entered into an “Early Action Compact” with the EPA whereby voluntary measures will be enacted to reduce ozone and thus delay any official non-attainment designation. While the Oklahoma City metropolitan area is near non-attainment, it appears it will be able to comply without any additional measures. The EPA has indicated that emission sources in Muskogee County in Oklahoma should be considered in any evaluation of the air quality for the Tulsa metropolitan area. If this occurs, NOX reduction at OG&E’s Muskogee generation station could be required.
The EPA also has issued regulations concerning regional haze. These regulations are intended to protect visibility in national parks and wilderness areas throughout the United States. In Oklahoma, the Wichita Mountains would be the only area covered under the regulation. Sulfates and nitrate aerosols (both emitted from coal-fired boilers) can lead to the degradation of visibility. Under these regulations, it is possible that controls on emission sources hundreds of miles away from the affected area may be required. The State of Oklahoma has begun the process of determining what, if any, impact emission sources in Oklahoma have on national parks and wilderness areas. If an impact is determined, then significant capital expenditures could be required for both the Sooner and Muskogee generating stations.
While the United States has withdrawn its support of the Kyoto Protocol on global warming, legislation has been drafted which would limit CO2 emissions. President Bush supports voluntary reductions by industry. OG&E has joined other utilities in voluntary CO2 sequestration projects through reforestation of land in the southern United States. In addition, OG&E has committed to reduce its CO2 emission rate (lbs. CO2/MWH) by up to five percent over the next 10 years. However, if legislation is passed requiring mandatory reductions this could have a tremendous impact on OG&E’s operations by requiring OG&E to significantly reduce the use of coal as a fuel source.
OG&E has and will continue to seek new pollution prevention opportunities and to evaluate the effectiveness of its waste reduction, reuse and recycling efforts. In 2002, OG&E obtained refunds of approximately $2.1 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.
OG&E has submitted one application during 2002 and will submit three more during 2003 to renew its Oklahoma Pollution Discharge Elimination System permits. OG&E anticipates that the renewed permits will continue to allow operational flexibility.
OG&E requested, based on the performance of a site-specific study, that the State agency responsible for the development of Water Quality Standards (“WQS”) adjust the in-stream
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copper criterion at one of its facilities. Without adjustment of this criterion, the facility could be subjected to costly treatment and/or facility reconfiguration requirements. The State has approved the WQS including the adjusted criterion and has transmitted the revised WQS to the EPA for their review and approval.
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’s original rules on this issue were set-aside in 1977 by the Fourth Circuit U.S. Court of Appeals. In 1993, the EPA announced its plan to develop new rules in part due to a lawsuit filed by the Hudson Riverkeeper. To settle the lawsuit, the EPA signed a court-approved consent decree to develop 316(b) regulations on an agreed upon schedule. Proposed rules, for existing utility sources, were published in 2002 and the final rules are expected to be promulgated in August 2003. Depending on the content of the final rules, capital and operating expenses may increase at most of OG&E’s generating facilities. Increased capital costs may be necessary to retrofit and/or redesign existing intake structures to comply with any new 316(b) regulations.
The construction and operation of pipelines, plants and other facilities for transporting, gathering, processing, treating or storing natural gas and other products may be subject to federal, state and local environmental laws and regulations, including those that can impose obligations to clean up hazardous substances at the locations at which Enogex operates. In most instances, the applicable regulatory requirements relate to water and air pollution control or solid waste management measures. Appropriate governmental authorities may enforce these laws and regulations with a variety of civil and criminal enforcement measures, including monetary penalties, assessment and remediation requirements and injunctions as to future compliance. Enogex generates some materials subject to the requirements of the Federal Resource Conservation and Recovery Act and the Clean Water Act and comparable state statutes, prepares and files reports and documents pursuant to the Toxic Substance Control Act and the Emergency Planning and Community Right to Know Act and obtains permits pursuant to the Federal Clean Air Act and comparable state air statutes.
Environmental regulation can increase the cost of planning, design, initial installation and operation of Enogex's facilities. Historically, Enogex's total expenditures for environmental control facilities and for remediation have not been significant in relation to its results of operations or financial condition. The Company believes, however, that it is reasonably likely that the trend in environmental legislation and regulations will continue to be towards stricter standards.
Beginning in 2000, the Company began a process to evaluate, determine and report emissions from its pipeline facilities for compliance with recently promulgated Maximum Achievable Control Technology regulations. After evaluating the submitted information, the ODEQ, in late 2001, issued Notices of Violation regarding potential air permitting issues at certain of these reported facilities. Generally, the notices alleged violations relating to the potential to emit various emission sources with the majority of the sources relating to glycol dehydrators. In compliance with Consent Orders entered between the parties, the Company has
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taken action to submit or modify permits, install control equipment, modify reporting procedures and pay penalties. See "Item 3. Legal Proceedings" for a further discussion of this matter.
The Company has and will continue to evaluate the impact of its operations on the environment. As a result, contamination on Company property may be discovered from time to time. One site has been identified as having been contaminated by historical operations. Remedial options based on the future use of this site are being pursued with appropriate regulatory agencies. The cost of these actions has not had and is not anticipated to have a material adverse impact on the Company’s consolidated financial position or results of operations.
EMPLOYEES
The Company and its subsidiaries had 2,995 employees at December 31, 2002.
ACCESS TO SECURITIES AND EXCHANGE COMMISSION FILINGS
The Company’s website address is www.oge.com. The Company makes available, free of charge through its website, its annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act as soon as reasonably practicable after such material is electronically filed with or furnished to the Securities and Exchange Commission. To access these filings from the Company’s website, please click “Investors”, “SEC Filings.”
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Item 2. Properties.
OG&E owns and operates an interconnected electric production, transmission and distribution system, located in Oklahoma and western Arkansas, which includes eight generating stations with an aggregate capability of approximately 5,696 MW’s. The following table sets forth information with respect to electric generating facilities, all of which are located in Oklahoma:
Unit Station
Station & Year Fuel Unit Capacity Capability Capability
Unit Installed Unit Design Type Capability Run Type Factor (A) (MW's) (MW's)
- -------------------------------------------------------------------------------------------------------------
Seminole 1 1971 Steam-Turbine Gas Base Load 28.2% 505.0
2 1973 Steam-Turbine Gas Base Load 24.9% 507.6
3 1975 Steam-Turbine Gas/Oil Base Load 23.6% 508.0 1,520.6
Muskogee 3 1956 Steam-Turbine Gas Base Load 18.6% 149.0
4 1977 Steam-Turbine Coal Base Load 72.7% 500.5
5 1978 Steam-Turbine Coal Base Load 74.9% 514.0
6 1984 Steam-Turbine Coal Base Load 77.8% 502.0 1,665.5
Sooner 1 1979 Steam-Turbine Coal Base Load 87.6% 505.3
2 1980 Steam-Turbine Coal Base Load 68.9% 513.8 1,019.1
Horseshoe 6 1958 Steam-Turbine Gas/Oil Base Load 29.3% 154.0
Lake 7 1963 Combined Cycle Gas/Oil Base Load 21.4% 227.5
8 1969 Steam-Turbine Gas Base Load 10.3% 369.5
9 2000 Combustion-Turbine Gas Peaking 4.4% (B) 45.5
10 2000 Combustion-Turbine Gas Peaking 4.3% (B) 45.5 842.0
Mustang 1 1950 Steam-Turbine Gas Peaking 1.5% (B) 55.0
2 1951 Steam-Turbine Gas Peaking 1.0% (B) 51.0
3 1955 Steam-Turbine Gas Base Load 22.4% 115.5
4 1959 Steam-Turbine Gas Base Load 33.3% 247.5
5 1971 Combustion-Turbine Gas/Jet Fuel Peaking 0.4% (B) 64.0 533.0
Conoco 1 1991 Combustion-Turbine Gas Base Load 49.4% 30.0
2 1991 Combustion-Turbine Gas Base Load 72.7% 31.0 61.0
Enid 1 1965 Combustion-Turbine Gas Peaking 8.9% (B) 12.0
2 1965 Combustion-Turbine Gas Peaking 7.1% (B) 10.0
3 1965 Combustion-Turbine Gas Peaking 12.0% (B) 11.0
4 1965 Combustion-Turbine Gas Peaking 14.1% (B) 11.3 44.3
Woodward 1 1963 Combustion-Turbine Gas Peaking 1.5% (B) 10.0 10.0
----------
Total Generating Capability (all stations) 5,695.5
==========
(A) Capacity Factor = Net Actual Generation / (Net Maximum Capacity (Nameplate Rating in MW's)
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.
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At December 31, 2002, OG&E’s transmission system included: (i) 31 substations with a total capacity of approximately 14.0 million kilo Volt-Amps (“kVA”) and approximately 3,995 structure miles of lines in Oklahoma; and (ii) two substations with a total capacity of approximately 1.4 million kVA and approximately 252 structure miles of lines in Arkansas. OG&E’s distribution system included: (i) 337 substations with a total capacity of approximately 8.1 million kVA, 22,429 structure miles of overhead lines, 1,794 miles of underground conduit and 7,325 miles of underground conductors in Oklahoma; and (ii) 36 substations with a total capacity of approximately 1.4 million kVA, 1,862 structure miles of overhead lines, 214 miles of underground conduit and 432 miles of underground conductors in Arkansas.
At December 31, 2002, Enogex and its subsidiaries owned: (i) approximately 8,370 miles of intrastate transmission and gathering lines in the states of Oklahoma and Texas; (ii) 10 natural gas processing plants with a capacity to process over one Bcfd, all located in Oklahoma; (iii) 75 percent interest in NOARK, which consists of approximately 960 miles of interstate transmission and gathering pipelines, located in eastern Oklahoma and Arkansas; (iv) an approximate 18 Bcf gas storage field in Oklahoma with an approximate withdrawal capacity of 450 MMcfd; (v) an approximate 13 Bcf gas storage field in Oklahoma; (vi) an 80 percent interest in NuStar, which includes a 66.67 percent interest in the 110 MMcfd capacity Benedum processing plant, a 100 percent interest in a smaller 30 MMcfd by-pass plant, over 200 miles of gathering pipelines and 52 miles of NGL pipeline, all located in the Permian Basin of west Texas. Enogex sold its interest in NuStar in February 2003.
During the three years ended December 31, 2002, the Company’s gross property, plant and equipment additions were approximately $752.5 million and gross retirements were approximately $137.6 million. These additions were provided by internally generated funds from operating cash flows, short-term borrowings and permanent financings. The additions during this three-year period amounted to approximately 13.6 percent of total property, plant and equipment at December 31, 2002.
Item 3. Legal Proceedings.
In the normal course of business, various lawsuits and claims have risen against the Company. When appropriate, management, after consultation with legal counsel, records an estimate of the probable cost of settlement or other disposition for such matters to the extent not covered by insurance or recoverable through regulated rates.
1. The City of Enid, Oklahoma ("Enid") through its City Council, notified OG&E of its intent to purchase OG&E's electric distribution facilities for Enid and to terminate OG&E's franchise to provide electricity within Enid as of June 26, 1998. On August 22, 1997, the City Council of Enid adopted Ordinance No. 97-30, which in essence granted OG&E a new 25-year franchise subject to approval of the electorate of Enid on November 18, 1997. In October 1997, 18 residents of Enid filed a lawsuit against Enid, OG&E and others in the District Court of Garfield County, State of Oklahoma, Case No. CJ-97-829-01. Plaintiffs seek a declaration holding that (i) the Mayor of Enid and the City Council breached their fiduciary duty to the public and violated Article 10, Section 17 of the Oklahoma Constitution by allegedly "gifting" to OG&E the option to acquire OG&E's electric system when the City Council approved the new
37
franchise by Ordinance No. 97-30; (ii) the subsequent approval of the new franchise by the electorate of the City of Enid at the November 18, 1997, franchise election cannot cure the alleged breach of fiduciary duty or the alleged constitutional violation; (iii) violations of the Oklahoma Open Meetings Act occurred and that such violations render the resolution approving Ordinance No. 97-30 invalid; (iv) OG&E's support of the Enid Citizens' Against the Government Takeover was improper; (v) OG&E has violated the favored nations clause of the existing franchise; and (vi) the City of Enid and OG&E have violated the competitive bidding requirements found at 11 O.S. 35-201, et seq. Plaintiffs seek money damages against the Defendants under 62 O.S. 372 and 373. Plaintiffs allege that the action of the City Council in approving the proposed franchise allowed the option to purchase OG&E's property to be transferred to OG&E for inadequate consideration. Plaintiffs demand judgment for treble the value of the property allegedly wrongfully transferred to OG&E. On October 28, 1997, another resident filed a similar lawsuit against OG&E, Enid and the Garfield County Election Board in the District Court of Garfield County, State of Oklahoma, Case No. CJ-97-852-01. However, Case No. CJ-97-852-01 was dismissed without prejudice in December 1997. On December 8, 1997, OG&E filed a Motion to Dismiss Case No. CJ-97-829-01 for failure to state claims upon which relief may be granted. This motion is currently pending. While the Company cannot predict the precise outcome of this proceeding, the Company believes at the present time that this lawsuit is without merit and intends to vigorously defend this case.
2. United States of America ex rel., Jack J. Grynberg v. Enogex Inc., Enogex Services Corporation and OG&E. (United States District Court for the Western District of Oklahoma, Case No. CIV-97-1010-L.) United States of America ex rel., Jack J. Grynberg v. Transok Inc. et al. (United States District Court for the Eastern District of Louisiana, Case No. 97-2089; United States District Court for the Western District of Oklahoma, Case No. 97-1009M.). On June 15, 1999, the Company was served with Plaintiff's Complaint. Plaintiff's action is a qui tam action under the False Claims Act. Jack J. Grynberg, as individual Relator on behalf of the United States Government, Plaintiff, alleges: (i) each of the named Defendants have improperly and intentionally mismeasured gas (both volume and Btu content) purchased from federal and Indian lands which have resulted in the under-reporting and underpayment of gas royalties owed to the Federal Government; (ii) certain provisions generally found in gas purchase contracts are improper; (iii) transactions by affiliated companies are not arms-length; (iv) excess processing cost deduction; and (v) failure to account for production separated out as a result of gas processing. Grynberg seeks the following damages: (a) additional royalties which he claims should have been paid to the Federal Government, some percentage of which Grynberg, as Relator, may be entitled to recover; (b) treble damages; (c) civil penalties; (d) an order requiring Defendants to measure the way Grynberg contends is the better way to do so; and (e) interest, costs and attorneys' fees. Plaintiff has filed over 70 other cases naming over 300 other defendants in various Federal Courts across the country containing nearly identical allegations.
In qui tam actions, the United States Government can intervene and take over such actions from the Relator. The Department of Justice, on behalf of the United States Government, has decided not to intervene in this action.
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The Multidistrict Litigation Panel (“MDL Panel”) entered its order in late 1999 transferring and consolidating for pretrial purposes approximately 76 other similar actions filed in nine other Federal Courts. The consolidated cases are now before the United States District Court for the District of Wyoming.
Multiple Defendants, including the Company, filed Motions to Dismiss on various procedural grounds in November, 1999. In May 2001, Judge Downes denied the Defendants’ Motions to Dismiss based on F.R. Civ.P. 8(a), 9(b) and 12 (b)(6). In July, 2000, the United States filed a Motion to Dismiss four of the allegations in Relator Grynberg’s Complaint related to the valuation of natural gas. This Motion was brought on various jurisdiction grounds under the False Claims Act. On October 9, 2002, the Court granted the Department of Justice’s Motion to Dismiss Certain of Grynberg’s Claims and issued its Order dismissing Grynberg’s valuation claims against all Defendants. The Court also ordered that Grynberg amend all complaints by December 13, 2002. Grynberg has filed numerous amended complaints, including amended complaints against the Company. All answer deadlines are stayed until further order of the Court. On November 13, 2002, Grynberg filed a Notice of Appeal to the Tenth Circuit regarding the Wyoming Court’s October 9, 2002, Order.
Discovery is proceeding on limited issues as ordered by the Court. The deposition of Relator Grynberg began in December, 2002, and has continued during January and February 2003.
The Company intends to vigorously defend this action. Since the case is in the early stages of motions and discovery, 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 at this time.
3. On September 24, 1999, the Company was served with the First Amended Class Action Petition filed in United States District Court, State of Kansas by Quinque Operating Company and other named plaintiffs, alleging mismeasurement of natural gas on non-federal lands. Second and Third Amended Class Action Petitions have now been filed. In the Third Amended Class Action Petition pending before the Court, Plaintiffs, Will Price, Stixon Petroleum, Inc., Thomas F. Boles and the Cooper Clark Foundation, on behalf of themselves and other royalty interest owners, overriding royalty interest owners and working interest owners, allege that 178 defendants, including OG&E, Enogex Inc. and a subsidiary of Enogex Inc., have improperly mismeasured natural gas (both volume and Btu content) on all non-federal and non-Indian lands in the United States. Plaintiffs claim underpayment by the Company and all other Defendants of gas royalties claimed to be owed to the Plaintiffs and the putative class under the following theories of recovery: (i) breach of contract; (ii) negligent misrepresentation; (iii) civil conspiracy/aiding and abetting civil conspiracy; (iv) common carrier liability; (v) conversion; (vi) Uniform Commercial Code; (vii) Kansas Consumer Protection Act; (viii) breach of fiduciary duty; and (ix) equity, including injunction, accounting, quantum merit and unjust enrichment. Plaintiffs seek an injunction and an accounting and a judgment in excess of approximately $0.1 million, including punitive damages, treble damages, attorneys' fees, costs and pre-judgment and post-judgment interest. Plaintiffs also seek an order certifying the case as a class action.
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On September 12, 2001, the Company filed a Motion to Dismiss Plaintiffs’ Second Amended Petition for failure to state a claim, for improper joinder of the defendants, lack of standing and lack of personal jurisdiction. OG&E and Enogex raised a personal jurisdiction defense. Pursuant to the Court’s scheduling order, a supporting brief on all issues except personal jurisdiction was filed contemporaneously with the Company’s Motion to Dismiss. Prior to the conclusion of the briefing on the Motion to Dismiss, the Court granted Plaintiffs leave to file a Third Amended Petition which was filed on March 4, 2002. Following the briefing of the parties on the new issues raised in the Third Amended Petition and oral arguments, the Court, on August 19, 2002, denied the Company’s Motion to Dismiss on all grounds, reserving its decision on the Motion to Dismiss for lack of personal jurisdiction, pursuant to the Court’s scheduling order.
The Company filed an Amended Motion to Dismiss on January 23, 2002. Enogex and OG&E filed briefs supporting their Motion to Dismiss for lack of personal jurisdiction. After full briefing by the parties, oral arguments on the Motion to Dismiss for lack of personal jurisdiction were held on August 29, 2002. The Court took the Motion under advisement and has not issued a ruling.
The Plaintiffs’ Motion to Certify this case as a Class Action was filed September 18, 2002. After full briefing by the parties, oral arguments were held on January 13, 2003. The Court has taken the motion under advisement and has not yet ruled.
A status conference was held on February 27, 2003. The Court set a Case Management Conference for April 17, 2003 to establish deadlines for issues remaining after the Court's ruling on the pending Motions to Dismiss for Lack of Jurisdiction. All discovery is stayed except for limited discovery related to the Defendants' Motions to Dismiss for Lack of Personal Jurisdiction and Plaintiffs' Motion to Certify a Class.
The Company intends to vigorously defend this action. Since the case is in the early stages of motions and discovery, 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 at this time.
4. Beginning in 2000, Enogex and Transok began a process to evaluate, determine and report emissions from their facilities for compliance with recently promulgated Maximum Achievable Control Technology (“MACT”) regulations. After evaluating the submitted information, the ODEQ, in late 2001, issued Notices of Violation (“NOV”) regarding potential air permitting issues at certain Enogex or Transok facilities. Generally, the NOV’s alleged violations relating to the potential to emit various emission sources with the majority of the sources relating to glycol dehydrators. As reported in the Company’s 2001 Form 10-K, one of the 2001 NOV’s was previously resolved. All but two of the remaining NOV’s relating to eight facilities were resolved by Consent Orders entered in 2002 that provided for Enogex to submit/modify permits, install control equipment, modify reporting procedures and pay penalties of approximately $0.2 million to the ODEQ.
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Enogex continues to work with and exchange information with the ODEQ regarding two remaining NOV sites, the Clinton Gas Plant and the Strong City Compressor Station. No fines have been proposed relating to the Strong City NOV and a proposed fine of approximately $0.1 million has been submitted by the ODEQ for the Clinton Gas Plant. Enogex has responded with information challenging the allegations and the fine proposed.
Two additional NOV’s relating to air permitting issues have been issued by ODEQ in November 2002 and January 2003, respectively, relating to the Cox City Compressor Station and the Comanche Tap Gas Plant. Enogex is in the process of responding to the ODEQ on these matters and no specific actions or penalties have been proposed. Enogex expects to resolve the issues at these remaining sites with the ODEQ in a similar manner. Enogex believes that the amounts of any penalty or expenditures for supplemental environmental projects on these facilities will not exceed $0.1 million for any single facility.
A Notice of Enforcement Action (“NOE”) by the Texas Natural Resource Conservation Commission (now known as the Texas Commission on Environmental Quality (“TCEQ”)) was issued to Products by letter dated July 26, 2002. The NOE relates to the operation of a sulfur recovery unit owned and operated by Belvan at its Crockett County, Texas natural gas processing facility. The TCEQ’s proposed fine was in the amount of approximately $0.1 million and Products is working with the current owner of Belvan to properly respond to the TCEQ, since Products sold its interest in Belvan in March 2002. Products has requested the TCEQ to issue the NOE in the permitted entity’s name and is waiting for this correction from the TCEQ. However, Products may retain some liability to the purchaser for any penalties that Belvan might incur from the NOE. Pursuant to the Agreement of Sale and Purchase with the purchaser, Products’ liability for any penalties that Belvan might incur from the NOE should not exceed approximately $0.1 million and this amount is fully reserved on Products books.
Enogex continues to monitor its operations to insure compliance with applicable air quality permitting and other environmental requirements.
5. OG&E entered into an agreement with the parent company of COOG, an unrelated third-party, to develop a natural gas storage facility (the "Stuart Storage Facility"). During 1996, OG&E completed negotiations and contracted with COOG for gas storage service. Pursuant to the contract, COOG reimbursed OG&E for all outstanding cash advances and interest of approximately $46.8 million. In 1997, COOG obtained permanent financing for the Stuart Storage Facility and issued a note (the "COOG Note"), originally in the amount of $49.5 million. In connection with the permanent financing, the Company entered into a note purchase agreement, where it agreed, upon the occurrence of a monetary default by COOG on its permanent financing, to purchase COOG's note from the holders at a price equal to the unpaid principal and interest under the COOG Note.
In 1998, Enogex entered into a Storage Lease Agreement (the “Agreement”) with COOG. Under the Agreement, COOG agreed to make certain enhancements to the Stuart Storage Facility to increase capacity and deliverability to a level specified and guaranteed by COOG. The Agreement was accounted for as a capital lease, and an asset was recorded for approximately $26.5 million, which was being amortized over 40 years.
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As part of the Agreement, the Company agreed to make up to a $12 million secured loan to Natural Gas Storage Corporation (“NGSC”), an affiliate of COOG (the “NGSC Loan”). As of December 31, 2002, the amount outstanding under the NGSC Loan was approximately $8.0 million plus accrued interest. The NGSC Loan was originally repayable in 2003 and was secured by the assets and stock of COOG. As of July 31, 2002, approximately a $9.0 million obligation remained on the balance sheet of Enogex for the capital lease, which was being amortized. Due to actions taken by the parties, as explained below, the outstanding balance on the NGSC Loan has now been offset against the capital lease obligation recorded on the books of Enogex.
After the completion of the enhancements by COOG in 1999, Enogex disputed whether the required and guaranteed level of natural gas deliverability for the Stuart Storage Facility was being provided by COOG and these issues were submitted to arbitration in October and November 2001. In July 2002, the Oklahoma District Court affirmed the arbitration award (the “Arbitration Award”) and entered judgment against COOG and in favor of Enogex in the amount of approximately $23.3 million (the “Judgment”). The Judgment is now final.
On July 24, 2002, Enogex exercised the Asset Purchase Option specified in the Agreement and specified a closing date of July 31, 2002. COOG failed and refused to close on July 31, 2002. The option price as of the Closing Date was calculated to be approximately $4.5 million, which was set off against the Judgment. The operation of the Stuart Storage Facility was turned over to Enogex by COOG on August 9, 2002.
By letter dated May 9, 2002, COOG advised the holder of the COOG Note that the Arbitration Award was in excess of $10 million and, in the event the Arbitration Award became a final, non-appealable order, it would constitute an event of default under the loan agreement relating to the note and that it was unable to make the payment of principal and interest on the note due May 1, 2002. As a result, the Company made the May 2002 principal and interest payment on the COOG Note of approximately $1.0 million and was required to purchase the note on August 1, 2002 at a price equal to its unpaid principal, interest and fees of approximately $33.8 million. As the holder of the note, the Company is a secured creditor, with a first mortgage or comparable security interest on all of the Stuart Storage Facility. As a result of the events discussed above, the Company recorded a note payable and an asset for approximately $33.8 million. The assumption of this note was included in the purchase price for the Stuart Storage Facility on the balance sheet of Enogex.
By letter dated June 24, 2002, the Company notified NGSC that the NGSC Loan was in default and, as a result, all amounts were immediately due and payable under the NGSC Loan. NGSC has failed and refused to repay the NGSC Loan. The Company intends to continue to vigorously pursue its rights in conjunction with the NGSC Loan.
On August 12, 2002, the Company was improperly served with an Original Petition in a legal proceeding that has been filed by COOG and NGSC against the Company and Enogex in Texas. Enogex was properly served on August 12, 2002. COOG and NGSC have stated a claim for declaratory judgment asserting, among other things, that NGSC is not obligated to make
42
payments on the NGSC Loan based on various theories and, that: (1) the Company was obligated to demand Enogex make the requisite payments to the Company; (2) the Company is liable to NGSC for failing to demand the requisite payments from Enogex, or alternatively, NGSC is entitled to a reduction in the amount it owes to the Company; (3) Enogex was and is obligated to make the payments to the Company until the indebtedness of NGSC to the Company is reduced to zero; (4) Enogex is not entitled to set off the Judgment against the lease payments that it originally owed to COOG and now owes to the Company; (5) no event of default has occurred; and (6) under the Agreement, the only remedy Enogex had or has if the Stuart Storage Facility did not perform was to seek a modification of the lease payments based upon COOG’s expert’s analysis of the performance of the Stuart Storage Facility. COOG and NGSC have also stated claims for breach of contract relating to the same allegations in its claim for declatory relief and include claims for attorneys’ fees.
The Company filed a Special Appearance and Original Answer Subject to Its Special Appearance objecting to being sued in Texas because the Texas Court does not have proper jurisdiction over the Company. On September 24, 2002, Enogex filed an Original Answer in response to the allegations, asserting, among other things, that the disputed issues have already been properly determined by the Arbitration Panel and the Oklahoma Court and, therefore, this action is improper.
On October 10, 2002, NGSC filed, in the Texas action, an Application for Temporary Injunction seeking to stop Enogex from proceeding against NGSC in the Oklahoma Court. On October 14, 2002, the Texas Court held a hearing on NGSC’s Application for Temporary Injunction. Without ordering the parties to mediate, the Court did direct the parties to mediation.
On October 24, 2002, mediation was held by the parties. An agreement, which provided several successive steps toward a potential settlement, was signed at that time. Under the agreement, COOG transferred full and complete title to the Stuart Storage Facility to Enogex effective August 9, 2002. Pursuant to the settlement agreement, all litigation between the parties was stayed for 45 days. The agreement also required COOG to have completed certain items within 45 days, or by December 12, 2002. COOG failed to do or complete the required items and therefore the stay of the execution of the Judgment is no longer in place. The Company intends to continue to vigorously pursue its rights in conjunction with the Judgment and payment of the NGSC Loan.
6. Farmland Industries, Inc. ("Farmland") voluntarily filed for Chapter 11 bankruptcy protection from creditors on May 31, 2002. Enogex provided gas transportation and supply services to Farmland, and is an unsecured creditor of Farmland. Enogex filed its Proof of Claim on January 7, 2003, for approximately $5.4 million. In its initial bankruptcy filing, Farmland asserted that it was a solvent entity with assets of approximately $2.7 billion and liabilities of approximately $1.9 billion. Farmland has been granted extensions of time in which to file its reorganization plan with the Court and is currently scheduled to file its plan by March 31, 2003.
7. On October 17, 2002, the City of Jenks, Oklahoma filed a petition in state district court in Tulsa County, Oklahoma against Enogex Inc. seeking damages associated with Enogex's
43
alleged failure to remit a Gross Receipts Tax to City relating to natural gas sold to an IPP within the city limits. Based on this claim, the city alleges damages "in excess of $10,000." The city claims that some of Enogex's pipelines are located within the city's public rights of way, and therefore, based on city ordinance, any sale of natural gas by Enogex to the IPP is subject to a two percent gross receipts tax. The city makes an identical claim against two other defendants, Exelon Generation Company, LLC, ("Exelon") as the "supplier" of natural gas to the IPP and the IPP, Green Country Energy, LLC. The city is also seeking interest on the amount in controversy, as well as its court costs and attorneys fees. Additionally, the city is asserting other claims against Exelon and the IPP pursuant to two other city ordinances. On December 2, 2002, Enogex and the other defendants filed answers denying plaintiff's claims. Enogex intends to vigorously defend against this action.
8. In 2000, Enogex entered into long-term firm transportation contracts with an IPP relating to a plant to be built in Wagoner County, Oklahoma. Effective July 1, 2000, the contracts were assigned to Calpine Energy Services, L.P. ("Calpine Energy"). In February 2002, Enogex requested a prepayment from Calpine Energy due to Calpine falling below the contractual creditworthiness provisions of the transportation contracts. Calpine Energy refused to pay for the full monthly demand fees pursuant to the transportation contracts on grounds of an alleged force majeure event. Enogex also made a demand on Calpine Corporation, as guarantor, relating to Calpine Energy's failure to make the required prepayment and demand payments. As of December 31, 2002, the amount of demand revenues due to Enogex was approximately $4 million, which amount has been fully reserved on the Company's financial statements. Enogex asserts that the remaining demand payments are due for all periods since March 6, 2002. Enogex also asserts that Calpine Corporation is liable for the amounts due and owing under the transportation agreements pursuant to the guarantee executed by Calpine Corporation, the parent corporation.
Calpine Energy and Calpine Corporation filed a declaratory judgment action in the United States District Court for the Northern District of Oklahoma relating to the dispute in September 2002. Calpine Energy seeks a declaratory judgment that demand charges are not due and owing and that Enogex had no reasonable ground to question its creditworthiness under the contracts. Enogex answered and filed a counterclaim on October 8, 2002. Enogex denied that either of the Calpine entities was entitled to the declaratory judgment requested and sought, under the counterclaim, an award based on breach of the contracts and the guarantee. Enogex also seeks a declaration that damages are due and owing under the contracts and the guarantee and a two-month prepayment should be awarded and maintained until the contractual creditworthiness provisions are met. For the months of November 2002 to February 2003, Calpine has paid the full monthly demand fee amounts.
9. OG&E has been sued by Kaiser-Francis Oil Company in District Court, Blaine County, Oklahoma. This case has been pending for more than ten years. Plaintiff alleges that OG&E breached the terms of numerous contracts covering approximately 60 wells by failing to purchase gas from Plaintiff in amounts set forth in the contracts. Plaintiff seeks $20.0 million in take-or-pay damages and $1.8 million in underpayment damages. Over the objection and unsuccessful appeal by OG&E, Plaintiff has been permitted to amend its petition to include a claim based on theories of tort. Specifically, Plaintiff alleges, among other things, that OG&E
44
intentionally and tortuously interfered with contracts by falsifying documents, sponsoring false testimony and putting forward legal defenses, which are known by OG&E to be without merit. If successful, Plaintiff believes that these theories could give Plaintiff a basis to seek punitive damages. OG&E believes that, to the extent Plaintiff were successful on the merits of its claims of OG&E's failure to take gas, these amounts would be recoverable through its regulated electric rates. The claims related to tortuous conduct, which OG&E believes at this time are without merit, would not appear to be properly recoverable in its rates. While the Company cannot predict the precise outcome of this lawsuit, the Company believes, based on the information known at this time, that this lawsuit will not have a material adverse effect on the Company's consolidated financial position or results of operations.
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 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 consolidated financial statements. Management, after consultation with legal counsel, does not anticipate that liabilities arising out of other currently pending or threatened lawsuits and claims will have a material adverse effect on the Company’s consolidated financial position, results of operations or cash flows.
Item 4. Submission of Matters to a Vote of Security Holders.
None
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Executive Officers of the Registrant.
The following persons were Executive Officers of the Registrant as of March 15, 2003:
Name Age Title
- ------------------ --- -----------------------------------------
Steven E. Moore 56 Chairman of the Board, President
and Chief Executive Officer
Al M. Strecker 59 Executive Vice President and
Chief Operating Officer
Peter B. Delaney 49 Executive Vice President, Finance and
Strategic Planning - OGE Energy
Corp. and Chief Executive Officer -
Enogex Inc.
James R. Hatfield 45 Senior Vice President and
Chief Financial Officer
Jack T. Coffman 59 Senior Vice President - Power Supply -
OG&E
Steven R. Gerdes 46 Vice President - Utility Operations
and Shared Services
Michael G. Davis 53 Vice President - Process Management -
OG&E
Donald R. Rowlett 45 Vice President and Controller
Eric B. Weekes 51 Treasurer
Carla D. Brockman 43 Corporate Secretary
Gary D. Huneryager 52 Internal Audit Officer
No family relationship exists between any of the Executive Officers of the Registrant. Messrs. Moore, Strecker, Hatfield, Gerdes, Rowlett, Weekes, Huneryager and Ms. Brockman are also officers of OG&E. Each Officer is to hold office until the Board of Directors meeting following the next Annual Meeting of Stockholders, currently scheduled for May 22, 2003.
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The business experience of each of the Executive Officers of the Registrant for the past five years is as follows:
Name Business Experience
- ------------------ ----------------------------------------------------
Steven E. Moore 1998-Present: Chairman of the Board,
President and Chief
Executive Officer
Al M. Strecker 1998-Present: Executive Vice President and
Chief Operating Officer
1998: Senior Vice President
Peter B. Delaney 2002-Present: Executive Vice President, Finance
and Strategic Planning - OGE
Energy Corp. and Chief Executive
Officer - Enogex Inc.
2001-2002: Principal, PD Energy Advisors
(consulting firm)
1998-2001: Managing Director, UBS Warburg
(investment banking firm)
James R. Hatfield 2000-Present: Senior Vice President and
Chief Financial Officer
1999-2000: Senior Vice President,
Chief Financial Officer
and Treasurer
1998-1999: Vice President and Treasurer
Jack T. Coffman 1999-Present: Senior Vice President -
Power Supply - OG&E
1998-1999: Vice President -
Power Supply - OG&E
Steven R. Gerdes 2003-Present: Vice President - Utility Operations
and Shared Services
1998-2003: Vice President - Shared Services
1998: Director - Shared Services
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Michael G. Davis 2002-Present: Vice President -
Process Management - OG&E
1998-2002: Vice President - Marketing
and Customer Care - OG&E
1998: Vice President -
Marketing and Customer
Services - OG&E
Donald R. Rowlett 1999-Present: Vice President and Controller
1998-1999: Controller Corporate
Accounting
Eric B. Weekes 2000-Present: Treasurer
1998-2000: Treasurer - Illinois Power
and Light
Carla D. Brockman 2002-Present: Corporate Secretary
2002: Assistant Corporate Secretary
1998-2002: Client Manager - Strategic
Planning
Gary D. Huneryager 2002-Present: Internal Audit Officer
2001-2002: Assistant Internal Audit Officer
1998-2001: Service Line Director
(Business Process
Outsourcing) - Arthur
Andersen LLP
1998: Chief Financial Officer -
The Abbey Group (equipment
rental company)
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PART II
Item 5. Market for Registrant's Common Equity and Related
Stockholder Matters.
The Company’s Common Stock is listed for trading on the New York and Pacific Stock Exchanges under the ticker symbol “OGE.” Quotes may be obtained in daily newspapers where the common stock is listed as “OGE Engy” in the New York Stock Exchange listing table. The following table gives information with respect to price ranges, as reported in The Wall Street Journal as New York Stock Exchange Composite Transactions, and dividends paid for the periods shown.
=================================================================================
Price
Dividend ----------------------
2001 Paid High Low
---------------------------------------------------------------------------------
First Quarter............................. $0.3325 $ 24.69 $ 21.25
Second Quarter............................ 0.3325 23.77 20.80
Third Quarter............................. 0.3325 23.48 20.25
Fourth Quarter............................ 0.3325 23.41 20.95
=================================================================================
=================================================================================
Price
Dividend ----------------------
2002 Paid High Low
---------------------------------------------------------------------------------
First Quarter............................. $0.3325 $ 24.12 $ 21.28
Second Quarter............................ 0.3325 24.24 21.82
Third Quarter............................. 0.3325 23.29 16.13
Fourth Quarter............................ 0.3325 18.34 13.70
=================================================================================
=================================================================================
Price
Dividend ----------------------
2003 Paid High Low
---------------------------------------------------------------------------------
First Quarter (through February 28)....... $ --- $ 19.37 $ 15.99
=================================================================================
The number of record holders of Common Stock at February 28, 2003, was 29,282. The book value of the Company's Common Stock at February 28, 2003, was $12.47.
Dividend Restrictions
Before the Company can pay any dividends on its common stock, the holders of any of its preferred stock that may be outstanding are entitled to receive their dividends at the respective rates as may be provided for the shares of their series. Currently, there are no shares of preferred stock of the Company outstanding. In addition, the Company may not, except in limited circumstances, declare or pay dividends on its common stock if it has deferred payment of interest o the junior subordinated debentures that were issued in connection with the trust
49
originated preferred securities issued and sold by its subsidiary trust, OGE Energy Capital Trust I. Because the Company is a holding company and conducts all of its operations through its subsidiaries, the Company’s cash flow and ability to pay dividends will be dependent on the earnings and cash flows of its subsidiaries and the distribution or other payment of those earnings to the Company in the form of dividends, or in the form of repayments of loans or advances to it. The Company expects to derive principally all of the funds required by it to enable it to pay dividends on its common stock from dividends paid by OG&E, on OG&E’s common stock. The Company’s ability to receive dividends on OG&E’s common stock is subject to the prior rights of the holders of any OG&E preferred stock that may be outstanding and the covenants of OG&E’s certificate of incorporation and its debt instruments limiting the ability of OG&E to pay dividends.
Under OG&E’s certificate of incorporation, if any shares of its preferred stock are outstanding, dividends (other than dividends payable in common stock), distributions or acquisitions of OG&E common stock:
- may not exceed 50 percent of net income for a prior 12-month period, after
deducting dividends on any preferred stock during the period, if the sum of
the capital represented by the common stock, premiums on capital stock
(restricted to premiums on common stock only by SEC orders), and surplus
accounts is less than 20 percent of capitalization;
- may not exceed 75 percent of net income for such 12-month period, as
adjusted if this capitalization ratio is 20 percent or more, but less than
25 percent; and
- if this capitalization ratio exceeds 25 percent, dividends, distributions or acquisitions may not reduce the ratio to less than 25 percent except to the extent permitted by the provisions described in the above two bullet points.
Currently, no shares of OG&E preferred stock are outstanding and no portion of the retained earnings of OG&E is presently restricted by this provision. OG&E’s certificate of incorporation further provides that no dividend may be declared or paid on the OG&E common stock until all amounts required to be paid or set aside for any sinking fund for the redemption or purchase of OG&E cumulative preferred stock, par value $25 per share, have been paid or set aside.
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Item 6. Selected Financial Data.
HISTORICAL DATA
2002 2001 2000 1999 1998
-------------------------------------------------------------------
SELECTED FINANCIAL DATA
(In millions, except per share data)
Operating revenues................. $ 3,023.9 $ 3,064.4 $ 3,184.4 $ 2,104.1 $ 1,569.9
Cost of goods sold................. 2,120.3 2,185.6 2,275.3 1,262.0 755.4
----------- ----------- ----------- ----------- -----------
Gross margin on revenues........... 903.6 878.8 909.1 842.1 814.5
Other operating expenses........... 667.9 607.9 574.5 518.1 478.2
----------- ----------- ----------- ----------- -----------
Operating income................... 235.7 270.9 334.6 324.0 336.3
Other income....................... 3.7 3.1 4.2 2.2 5.5
Other expense...................... 4.7 4.2 3.6 2.6 4.2
Net interest expense............... 109.1 123.0 129.4 97.4 67.1
Income tax expense................. 44.6 52.9 72.0 86.2 109.2
----------- ----------- ----------- ----------- -----------
Income from continuing
operations........................ 81.0 93.9 133.8 140.0 161.3
Income from discontinued
operations, net of tax............ 9.8 6.7 13.2 11.3 4.5
----------- ----------- ----------- ----------- -----------
Net income......................... 90.8 100.6 147.0 151.3 165.8
Preferred dividend requirements.... --- --- --- --- 0.7
----------- ----------- ----------- ----------- -----------
Earnings available for common
shareholders...................... $ 90.8 $ 100.6 $ 147.0 $ 151.3 $ 165.1
=========== =========== =========== =========== ===========
Basic and diluted earnings per
average common share
Income from continuing
operations........................ $ 1.04 $ 1.20 $ 1.72 $ 1.80 $ 1.99
Income from discontinued
operations, net of tax............ 0.12 0.09 0.17 0.14 0.05
----------- ----------- ----------- ----------- -----------
Earnings per average common
share............................. $ 1.16 $ 1.29 $ 1.89 $ 1.94 $ 2.04
=========== =========== =========== =========== ===========
Dividends declared per share......... $ 1.33 $ 1.33 $ 1.33 $ 1.33 $ 1.33
Long-term debt..................... $ 1,501.9 $ 1,526.3 $ 1,648.5 $ 1,140.5 $ 935.6
Total assets....................... $ 4,127.2 $ 3,996.6 $ 4,319.6 $ 3,921.3 $ 2,983.9
CAPITALIZATION RATIOS (A)
Stockholders' equity............... 39.58% 40.54% 39.23% 47.20% 52.72%
Long-term debt..................... 60.42% 59.46% 60.77% 52.80% 47.28%
INTEREST COVERAGES
Before federal income taxes
(including AFUDC)................ 2.20X 2.20X 2.66X 3.39X 4.84X
(excluding AFUDC)................ 2.19X 2.19X 2.64X 3.38X 4.82X
After federal income taxes
(including AFUDC)................ 1.81X 1.79X 2.09X 2.50X 3.31X
(excluding AFUDC)................ 1.80X 1.78X 2.07X 2.49X 3.30X
===========================================================================================================
(A) Capitalization ratios = [Stockholders' equity / (Stockholders' equity + Long-term debt)]
and [Long-term debt / (Stockholders' equity + Long-term debt)].
51
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations.
Introduction
OGE Energy Corp. (collectively with its subsidiaries, the “Company”) is an energy and energy services provider offering physical delivery and management of both electricity and natural gas in the south central United States. The Company conducts these activities through two business segments, the Electric Utility and the Natural Gas Pipeline segments.
The Electric Utility segment generates, transmits, distributes and sells electric energy in Oklahoma and western Arkansas. Its operations are conducted through Oklahoma Gas and Electric Company (“OG&E”) and are subject to regulation by the Oklahoma Corporation Commission (“OCC”), the Arkansas Public Service Commission (“APSC”) and the Federal Energy Regulatory Commission (“FERC”). OG&E sold its retail gas business in 1928 and is no longer engaged in the gas distribution business. OG&E is the largest electric utility in Oklahoma and its franchised service territory includes the Fort Smith, Arkansas area.
The Natural Gas Pipeline segment is conducted through Enogex Inc. and its subsidiaries (“Enogex”) and consists of three related businesses: (i) the transportation and storage of natural gas, (ii) the gathering and processing of natural gas, and (iii) the marketing and trading of natural gas (collectively, the “pipeline businesses”). The vast majority of Enogex’s natural gas gathering, processing, transportation and storage assets are located in the major gas producing basins of Oklahoma. Through a 75 percent interest in the NOARK Pipeline System Limited Partnership, Enogex also owns a controlling interest in and operates the Ozark Gas Transmission System (“Ozark”), a FERC regulated interstate pipeline that extends from southeast Oklahoma through Arkansas to southeast Missouri. Enogex’s marketing and trading activities include corporate price risk management and other optimization services. Enogex was previously engaged in the exploration and production of natural gas, however, this portion of Enogex’s business, along with interests in certain gas gathering and processing assets in Texas were sold in 2002 and 2003 and are reported in the Consolidated Financial Statements as discontinued operations.
Company Strategy
In early 2002, the Company completed a review of its business strategy that was largely driven by the anticipated deregulation of the retail electric markets in Oklahoma and Arkansas. Due to a variety of factors, including the current efforts to repeal the Oklahoma Electric Restructuring Act of 1997 and the recent repeal of the Restructuring Law in Arkansas, the Company does not anticipate that deregulation of the electricity markets in Oklahoma or Arkansas will occur in the foreseeable future. The strategic direction of the Company has been revised to reflect these developments. As a result, the Company expects potentially slower earnings growth than associated with deregulation but with less variability of those earnings.
The Company’s business strategy will utilize the diversified asset position of OG&E and Enogex to provide energy products and services to customers primarily in the south central
52
United States. The Company will focus on those products and services with limited or manageable commodity exposure. The Company intends for OG&E to continue as an integrated utility engaged in the generation and the distribution of electricity and to represent over time approximately 70 percent of the Company’s consolidated assets. The remainder of the Company’s assets will be in Enogex’s pipeline businesses. In addition to the incremental growth opportunities that Enogex provides, the Company believes that Enogex’s risk management capabilities, commercial skills and market information provide value to all of the Company’s businesses. Federal regulation in regard to the operations of the wholesale power market may change with the proposed Standard Market Design initiative at the FERC. In addition, Oklahoma and Arkansas legislatures and utility commissions may propose changes from time to time that could subject the utilities to market risk. Accordingly, the Company is applying risk management practices to all of its operations in an effort to mitigate the potential adverse effect of any future regulatory changes.
In the near term, OG&E plans on increasing its investment and growing earnings largely through the acquisition of a merchant power plant. As part of the OCC’s rate order on November 20, 2002, OG&E is seeking to purchase an electric power plant with at least 400 megawatts (“MW”) of generating capacity and to include the cost of such plant in its rate base. Given the surplus power in the region, the Company believes there is a continuing opportunity to purchase existing power plants at prices below the cost to build. This should enable OG&E to generate electricity for its customers at prices below those being paid by OG&E under existing qualified cogeneration and small power production producers' contracts (“QF contracts”). Unless extended by OG&E, many of these QF contracts will expire over the next one to five years. Accordingly, OG&E will continue to explore opportunities to purchase power plants in order to serve its native load. OG&E anticipates filing with appropriate regulatory agencies to increase base rates to recover its investment in any power plant acquired and expects that customers should realize overall lower rates through fuel savings due to the increased efficiency of these new plants and lower capital costs than those associated with the expiring QF contracts.
Enogex initiated a program in 2002 to improve its financial performance. As a part of this performance improvement program, Enogex has sold approximately $103.8 million in assets, reduced debt by 17 percent, reduced its number of employees by 12 percent and reorganized its operations. In addition to improving its earnings, Enogex will continue to take actions to reduce its exposure to commodity prices by, among other things, mitigating its exposure to keep whole processing arrangements and reducing earnings volatility. While the Company believes substantial progress has been achieved, substantial opportunities remain. Enogex expects to continue reviewing its work processes, rationalizing assets, renegotiating contracts to improve pricing on existing volumes and reducing costs to further improve its financial return in addition to pursuing opportunities for organic growth.
In 2003, in addition to these ongoing efforts, a major upgrade of the information systems is expected to be substantially completed. The Company believes these upgrades will be a major step towards obtaining the data required for it to optimize its system, provide improved customer service and enable management to more accurately determine the earnings potential of the unregulated pipeline system. The Company does not anticipate significantly increasing its
53
investment in Enogex in accordance with the goal of targeting its pipeline businesses at 30 percent of the Company’s consolidated assets.
Forward-Looking Statements
Except for the historical statements contained herein, the matters discussed in the following discussion and analysis, including the discussion in “2003 Outlook”, 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”, “estimate”, “expect”, “objective”, “possible”, “potential” and similar expressions. Actual results may vary materially. Factors that could cause actual results to differ materially include, but are not limited to: general economic conditions, including their impact on capital expenditures; prices of electricity, natural gas and natural gas liquids, each on a stand-alone basis and in relation to each other; 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; state and federal legislative and regulatory decisions and initiatives; changes in accounting standards, rules or guidelines; creditworthiness of suppliers, customers, and other contractual parties; actions by ratings agencies; and the other risk factors listed in the reports filed by the Company with the Securities and Exchange Commission.
Overview
General
The following discussion and analysis presents factors that affected the Company’s consolidated results of operations and consolidated financial position during the last three years. The following information should be read in conjunction with the Consolidated Financial Statements and Notes thereto. Known trends and contingencies of a material nature are discussed to the extent considered relevant.
Enogex previously was engaged in the exploration and production of natural gas (the “E&P business”). Since January 1, 2002, Enogex has sold all of its E&P business along with certain gas gathering and processing assets that were owned by Enogex through its interest in the NuStar Joint Venture (“NuStar”) and its interest in Belvan Corp., Belvan Limited Partnership and Todd Ranch Limited Partnership (“Belvan”). As required by accounting principles generally accepted in the United States, these dispositions have been reported as discontinued operations for the years ended December 31, 2002, 2001 and 2000 in the Consolidated Financial Statements.
Operating Results
2002 compared to 2001. The Company reported earnings of $1.16 per share in 2002 compared to earnings of $1.29 per share in 2001. The reduced earnings were primarily due to impairment losses of $0.39 per share in the fourth quarter of 2002 for Enogex and the Company. Excluding impairment charges, the Company’s earnings in 2002 would have been $1.55 per share compared to $1.34 per share in 2001, when the Company reported a $0.05 per share
54
impairment charge. The Company’s results for 2002 and 2001 include $0.12 per share and $0.09 per share, respectively, from the discontinued operations discussed above. See “Discontinued Operations” below for a further discussion.
OG&E contributed $1.61 per share in 2002 compared to $1.55 per share in 2001. The improvement in financial performance at OG&E is primarily attributable to lower operating and maintenance expenses, lower interest expenses and increased growth in OG&E’s service territory partially offset by lower levels of natural gas transportation cost recovered, lower recoveries of fuel costs from Arkansas customers, loss of revenue resulting from the January 2002 ice storm, lower kilowatt-hour sales to other utilities and power marketers (“off-system sales”), milder weather and higher depreciation expense.
Enogex’s operations, including discontinued operations, resulted in a loss of $0.28 per share in 2002 compared to a loss of $0.06 per share in 2001. The reduced earnings were primarily attributable to impairment losses of $0.38 per share in the fourth quarter of 2002 related to the disposition of gas processing plants and compression assets that were no longer needed in Enogex’s business. Absent impairment charges in 2002 and 2001 and including discontinued operations, Enogex would have earned $0.10 per share in 2002 compared with a loss of $0.01 per share in 2001. This improvement was primarily from the transportation and storage business as a result of additional firm revenues from new long-term contracts to merchant electric generation facilities and increased storage revenues. Additionally, better fuel recoveries and lower interest expense contributed to the improvement and were only partially offset by lower volumes in gathering and processing.
As stated above, Enogex’s E&P business, its interest in NuStar and its interest in Belvan have been reported as discontinued operations for the years ended December 31, 2002, 2001 and 2000 in the Consolidated Financial Statements as these assets have been sold. Earnings from discontinued operations improved from $0.09 per share in 2001 to $0.12 per share in 2002 primarily related to a higher gross margin on natural gas liquids sales, an impairment charge recorded in 2001 for Belvan, net gains on the sale of certain of these assets in 2002, lower depreciation expense and lower operating and maintenance expenses partially offset by a lower gross margin on natural gas sales. See “Results of Operations - Discontinued Operations.”
The results of the holding company reflect a loss of $0.17 per share in 2002 compared to a loss of $0.20 per share in 2001. The reduced loss was primarily attributable to lower interest expenses partially offset by a lower income tax benefit and an impairment loss in the fourth quarter of 2002 related to the Company’s aircraft.
2001 compared to 2000. The Company reported earnings of $1.29 per share in 2001 compared to earnings of $1.89 per share in 2000. The reduced earnings were due to lower earnings contributions from OG&E and Enogex and an impairment loss of $0.05 per share in the fourth quarter of 2001 at Enogex. Earnings from discontinued operations contributed $0.09 per share in 2001 and $0.17 per share in 2000 to the Company’s earnings.
OG&E contributed $1.55 per share in 2001 compared to $1.83 per share in 2000. The reduced earnings were primarily attributable to lower kilowatt-hour sales to OG&E’s customers
55
(“system sales”) due to milder weather, lower levels of revenues recovered under various fuel and incentive riders and higher operating and maintenance expenses partially offset by increased growth in OG&E’s service territory and lower interest expense.
Enogex’s operations, including discontinued operations, resulted in a loss of $0.06 per share in 2001 compared to earnings of $0.25 per share in 2000. The reduced earnings were primarily attributable to poor fractionation spreads in its gas processing business, lower margins in marketing and trading, higher operating expenses and a $0.05 per share impairment loss related to the anticipated disposition of the Belvan asset partially offset by better fuel recoveries and storage margins.
As stated above, Enogex’s E&P business, its interest in NuStar and its interest in Belvan have been reported as discontinued operations for the years ended December 31, 2002, 2001 and 2000 in the Consolidated Financial Statements. Earnings from these discontinued operations decreased from $0.17 per share in 2000 to $0.09 per share in 2001 primarily related to a lower gross margin on natural gas liquids sales, an impairment charge of $0.05 per share in the fourth quarter of 2001 for Belvan, a lower gain from the sale of working interests in 2000 for oil and gas properties located in Texas and Utah and higher operating and maintenance expenses partially offset by a higher natural gas sales gross margin, lower exploration expenses and lower depreciation expense. See “Results of Operations - Discontinued Operations.”
The results of the holding company reflect a loss of $0.20 per share in 2001 compared to a loss of $0.19 per share in 2000. The increased loss was primarily attributable to lower other income in 2001, primarily due to the sale of the Company’s aircraft in 2000, and a lower income tax benefit, partially offset by lower interest expenses.
Regulatory Considerations
On October 11, 2002, OG&E, the OCC Staff, the Oklahoma Attorney General and other interested parties agreed to a settlement (the “Settlement Agreement”) of OG&E’s rate case. The administrative law judge subsequently recommended approval of the Settlement Agreement and on November 22, 2002, the OCC signed a rate order containing the provisions of the Settlement Agreement and the new reduced rates went into effect January 6, 2003. The Settlement Agreement provides for, among other items: (i) a $25.0 million annual reduction in the electric rates of OG&E’s Oklahoma customers which begins with the first regular billing cycle occurring 41 days after the issuance of the OCC order approving the Settlement Agreement; (ii) recovery by OG&E, through rate base, of the capital expenditures associated with the January 2002 ice storm; (iii) recovery by OG&E, over three years, of the $5.4 million in deferred operating costs, associated with the January 2002 ice storm, through OG&E’s rider for off-system sales; (iv) OG&E to acquire electric generating capacity (“New Generation”) of not less than 400 MW’s to be integrated into OG&E’s generation system.
OG&E expects that the New Generation will provide savings, over a three-year period, in excess of $75 million. If OG&E is unable to demonstrate at least $75 million in savings, OG&E will be required to credit to its Oklahoma customers any unrealized savings below $75 million. In the event OG&E does not acquire the New Generation by December 31, 2003, OG&E will be
56
required to 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. However, if OG&E purchases the New Generation subsequent to January 2004, the credit to Oklahoma customers will terminate in the first month that the New Generation begins initial operations and any credited amount to Oklahoma customers will be included in the determination of the $75.0 million targeted savings. Reference is made to Note 16 of Notes to Consolidated Financial Statements for a further discussion of the Settlement Agreement and of other recent actions relating to OG&E’s rates.
OG&E 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 OG&E due to the significant problems faced by California in its electric deregulation efforts and other factors, significant changes are possible, which could significantly change the manner in which OG&E conducts its business. These developments at the federal and state levels are described in more detail below under “Electric Competition; Regulation.”
2003 Asset Disposals
Enogex sold approximately 29 miles of transmission lines of the Ozark pipeline located in Pittsburg and Latimer counties in Oklahoma for approximately $10.0 million in January 2003. The Company will recognize a pre-tax gain of approximately $5.3 million in the first quarter of 2003 related to the sale of these assets. These assets were part of the Natural Gas Pipeline segment.
Enogex sold its interest in NuStar for approximately $37.0 million in February 2003. The Company will recognize a pre-tax gain of approximately $2.3 million in the first quarter of 2003 related to the sale of these assets. These assets were part of the Natural Gas Pipeline segment.
2003 Outlook
General
The Company currently expects that earnings in 2003 will be between $1.35 and $1.45 per share, assuming, among other things, normal weather and continued customer growth in the electric utility service area and improved performance at Enogex. The Company anticipates a contribution of approximately $112 to $118 million from OG&E, approximately $14 to $16 million from Enogex and a loss of approximately $14 million at the holding company.
The Company has assumed approximately 83.5 million average common shares outstanding for 2003, up from approximately a 78.1 million average in 2002. The Company plans to issue equity in 2003 to support the capital structure at OG&E for its purchase of generation and for other corporate purposes including the repayment of short-term debt. The Company plans to issue equity through a combination of a public offering and the issuance of shares through its Dividend Reinvestment Plan. The amount, method of issuance and timing
57
cannot be determined at this time but will be dependent upon, among other things, the timing of, and the cost to, purchase a generation facility and market conditions.
During 2003, OG&E expects operating revenues to decrease approximately $10.0 million, which reflects the $25.0 million rate reduction under the Settlement Agreement and approximately a $3.0 million reduction due to the expiration in June 2002 of the Generation Efficiency Performance Rider (“GEP Rider”). These decreases are expected to be partially offset by approximately two percent growth in electric usage (of approximately $14.0 million) and normalized weather (of approximately $4.0 million). OG&E expects an increase in operating and maintenance expenses of approximately $10.0 million partially offset by an increase in other miscellaneous income items of approximately $3.0 million. Key factors affecting OG&E’s 2003 net income will be weather, OG&E’s ability to control operating and maintenance expenses and customer growth. Expected 2003 net income assumes a 37 percent effective tax rate.
During 2002, Enogex evaluated, redesigned and reorganized its internal work processes in order to achieve cost reductions and revenue enhancements within its businesses. Enogex is beginning to see the positive results of these efforts and expects continued improvement during 2003. As stated above, Enogex manages its operations along three related businesses: transportation and storage; gathering and processing; and marketing and trading. In 2003, these businesses are expected to produce a gross margin of approximately $223 million, a $12 million reduction from 2002 including discontinued operations. The Company expects approximately 54 percent of Enogex’s gross margin during 2003 to be generated from its transportation and storage business as compared to 46 percent in 2002. Revenues in transportation and storage are primarily from gas transportation contracts with utilities in Oklahoma and Arkansas and independent power plants in Oklahoma. Revenues in the transportation and storage business are expected to increase due to providing gas transportation service for a new independent power plant, which began operations in 2002, and from a natural gas storage field purchased in 2002. The Company expects its gathering and processing operations to contribute approximately 36 percent of Enogex’s gross margin in 2003 as compared to 41 percent in 2002. Revenues in gathering and processing are expected to decrease in 2003 primarily due to anticipated lower volumes, the sale of the NuStar and Belvan properties, lower inlet volumes in Oklahoma and assumed relatively flat processing margins compared to 2002. Marketing and trading is expected to contribute approximately 10 percent of Enogex’s gross margin in 2003 as compared to eight percent in 2002. Revenues in marketing and trading are expected to increase in 2003 primarily due to increased volumes and higher margins. Enogex also expects approximately a $33.3 million decrease in expenses during 2003 primarily due to approximately a $25.6 million decrease in operating expenses and approximately a $7.7 million decline in interest expense. The $25.6 million decrease in operating expenses is primarily attributable to a reduction of approximately $17.1 million of expenses associated with discontinued operations and unusual charges of approximately $6.8 million in 2002 primarily from a large customer bankruptcy, lost gas expense and severance costs. The remaining $1.7 million reduction in operating expenses is primarily due to a 12 percent decrease in the number of employees during 2002 as well as process efficiencies which were partially offset by higher pension and medical expenses. Key factors affecting Enogex’s 2003 net income will be gathering and processing volumes on the system as well as natural gas and natural gas liquids prices and the level of system fuel costs. Gathering volumes will be determined by the level of natural gas production from the areas
58
served by Enogex. Processing volumes will be driven by the volume of wet gas on the system and whether, due to insufficient margins, any ethane or propane is rejected.
Enogex expects to continue to seek opportunities to rationalize its asset base in an effort to lower costs and increase the return on its asset base. The impairment of assets recorded in 2002 reflects these opportunities. The Company expects to continue to rationalize its compression and processing asset base, which may lead to future impairment charges. The Company does not currently anticipate that future charges, if any, will be of the magnitude recorded in 2002. The magnitude and timing, of these charges will be driven largely by the actual and projected utilization of compression and processing assets and the disposal value of any assets determined as surplus.
Both OG&E and Enogex have significant seasonality in their earnings. OG&E 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. At Enogex, due to the sale of the E&P business in 2002, the seasonality of its earnings has changed for 2003. Enogex expects to show a loss in the first quarter of 2003, with approximately 25 percent of its earnings in the second and fourth quarters and approximately 50 percent in the third quarter. The first quarter loss is primarily the result of underrecoveries of fuel in the transportation business. First quarter underrecoveries of fuel typically are recouped in the other three quarters of the year. As a result, the Company expects to report, on a consolidated basis, a loss in the first quarter, approximately 25 percent of its net income in the second quarter, approximately 75 percent of its net income in the third quarter and break-even results in the fourth quarter.
Dividend Policy
The Company’s dividend policy is determined by the Board of Directors and is based on numerous factors, including management’s estimation of the long-term earnings power of its businesses. The target payout ratio for the Company is to pay out as dividends approximately 75 percent of its earnings on an annual basis. The target payout ratio has been determined after consideration of numerous factors, including the largely retail composition of our shareholder base, our financial position, our growth targets, the composition of our assets and investment opportunities. On an operating basis excluding impairment charges, the Company’s earnings per share for 2002 exceeded the dividend rate of $1.33 per share. While the dividend payout ratio is expected to exceed the target payout ratio in 2003, management after considering estimates of future earnings and numerous other factors, expects at this time that it will continue to recommend to the Board of Directors a continuance of the current dividend rate.
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Results of Operations
Percent Change
From Prior Year
----------------
(In millions, except per share data) 2002 2001 2000 2002 2001
- -----------------------------------------------------------------------------------------------------------
Operating income................................. $ 235.7 $ 270.9 $ 334.6 (13.0) (19.0)
Net income....................................... $ 90.8 $ 100.6 $ 147.0 (9.7) (31.6)
Basic average common shares outstanding.......... 78.1 77.9 77.9 0.3 ---
Diluted average common shares outstanding........ 78.2 77.9 77.9 0.4 ---
Basic and diluted earnings per average
common share................................... $ 1.16 $ 1.29 $ 1.89 (10.1) (31.7)
Dividends declared per share..................... $ 1.33 $ 1.33 $ 1.33 --- ---
===========================================================================================================
In reviewing its consolidated operating results, the Company believes that it is appropriate to focus on operating income as reported in its Consolidated Statements of Income. Included in the 2002 operating income is a pre-tax impairment charge of approximately $50.1 million. These impairments, primarily for the disposition of Enogex natural gas processing and compression assets that were no longer needed in Enogex’s business, were made in accordance with accounting principles generally accepted in the United States and significantly reduced 2002 operating results. Operating income was approximately $235.7 million, $270.9 million and $334.6 million in 2002, 2001 and 2000, respectively. Amounts listed above exclude the results of Enogex’s E&P business, NuStar and Belvan, which, as explained above, were sold during 2002 and 2003 and which are reported as discontinued operations. See “Discontinued Operations” for a further discussion.
Operating Income (Loss) by Business Segment
(In millions) 2002 2001 2000 ============================================================================================== OG&E (Electric Utility).......................... $ 239.1 $ 236.6 $ 271.1 Enogex (Natural Gas Pipeline).................... (3.0) (A) 34.4 63.8 Other Operations (B)............................. (0.4) (0.1) (0.3) - ---------------------------------------------------------------------------------------------- Consolidated operating income.................... $ 235.7 $ 270.9 $ 334.6 ============================================================================================== (A) After recording an impairment charge of approximately $48.3 million in 2002. (B) Other Operations primarily includes unallocated corporate expenses.
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The following operating income analysis by business segment includes intercompany transactions that are eliminated in the Consolidated Financial Statements.
OG&E
(In millions) 2002 2001 2000 =============================================================================================== Operating revenues............................ $ 1,388.0 $ 1,456.8 $ 1,453.6 Fuel.......................................... 435.8 485.8 489.1 Purchased power............................... 260.0 280.7 263.3 - ----------------------------------------------------------------------------------------------- Gross margin on revenues...................... 692.2 690.3 701.2 Other operating expenses...................... 453.1 453.7 430.1 - ----------------------------------------------------------------------------------------------- Operating income.............................. $ 239.1 $ 236.6 $ 271.1 =============================================================================================== System sales - MWH (A)........................ 24.6 24.5 25.0 Off-system sales - MWH........................ 0.3 0.4 0.3 - ----------------------------------------------------------------------------------------------- Total sales - MWH............................. 24.9 24.9 25.3 =============================================================================================== (A) Megawatt-hour
2002 compared to 2001. OG&E's operating income increased approximately $2.5 million or 1.1 percent in 2002 as compared to 2001. The increase in operating income was primarily attributable to a slightly higher gross margin due to growth in electric usage in OG&E's service territory and slightly lower operating expenses.
Gross margin increased approximately $1.9 million or 0.3 percent in 2002 as compared to 2001. Growth in the number of customers in OG&E’s service territory and the resulting increase in electric sales of approximately 2.9 percent increased the gross margin by approximately $20.1 million. The increase was offset by lower recoveries of fuel costs from Arkansas customers through that state’s automatic fuel adjustment clause of approximately $5.9 million. In Arkansas, recovery of fuel costs is subject to a bandwidth mechanism. If fuel costs are within the bandwidth range, recoveries are not adjusted on a monthly basis; rather they are reset annually on April 1. Gross margin also was reduced by approximately $4.0 million due to milder weather. Lower recoveries under the GEP Rider, which terminated in June 2002, decreased the gross margin by approximately $3.6 million in 2002. Additionally, lower levels of natural gas transportation cost that OG&E was allowed to recover from its customers as a result of the Acquisition Premium Credit Rider (“APC Rider”) and the Gas Transportation Adjustment Credit Rider (“GTAC Rider”) decreased the gross margin by approximately $2.1 million. See Note 16 of Notes to Consolidated Financial Statements for a further discussion of these riders. Although total expenditures from the January 2002 ice storm of approximately $92.0 million, which have been capitalized or deferred, did not impact operating results, the related loss of revenue due to interruption of service to our customers resulted in a decrease in the gross margin of approximately $1.5 million in 2002. Reduced amounts of off-system sales decreased the gross margin by approximately $1.1 million.
Cost of goods sold for OG&E consists of fuel used in electric generation and purchased power. Fuel expense decreased approximately $50.0 million or 10.3 percent in 2002 as compared to 2001 primarily due to an 11.1 percent decrease in the average cost of fuel per kilowatt-hour ("Kwh"). OG&E's electric generating capability is fairly evenly divided between coal and natural gas and provides for flexibility to use either fuel to the best economic advantage
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for OG&E and its customers. In 2002, OG&E's fuel mix was 72 percent coal and 28 percent natural gas. Though OG&E has a higher installed capability of generation from natural gas units of 55 percent, it has been more economical to generate electricity for our customers with lower priced coal. Purchased power costs decreased approximately $20.7 million or 7.4 percent in 2002 as compared to 2001 primarily due to a 4.6 percent decrease in the volume of energy purchased and a 2.6 percent decrease in the cost of purchased energy per Kwh.
Variances in the actual cost of fuel used in electric generation and certain purchased power costs, as compared to the fuel component included in the cost-of-service for ratemaking, are passed through to OG&E’s customers through automatic fuel adjustment clauses. While the regulatory mechanisms for recovering fuel costs differ in Oklahoma and Arkansas, in both states the costs are passed through to customers and are intended to provide neither an ultimate benefit nor detriment to OG&E. 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 OG&E pays to Enogex. See Note 16 of Notes to Consolidated Financial Statements.
Other operating expenses, consisting of operating and maintenance expense, depreciation expense and taxes other than income, decreased approximately $0.6 million or 0.1 percent in 2002 as compared to 2001. OG&E’s operating and maintenance expense decreased approximately $4.4 million or 1.5 percent in 2002 as compared to 2001. This decrease was primarily due to a decrease of approximately $11.5 million in bad debt expense, a decrease of approximately $1.0 million in contract labor costs and a decrease of approximately $1.8 million in materials and supplies expense. Higher than normal bills driven by high natural gas prices early in 2001, along with customer cut-off moratoriums imposed during high temperature periods during the summer of 2001 contributed to significantly increased uncollectibles in 2001. The decrease in contract labor costs was due to higher contract labor costs incurred in 2001 due to the use of contractors to supplement OG&E’s own crews to restore power after a major ice storm at the beginning of 2001 and a major wind storm in the early summer of 2001. The decreased operating and maintenance expenses were partially offset by an increase in employee pension and benefit costs of approximately $9.9 million. Pension expense increased primarily due to lower than forecasted returns on assets in the pension trust and the effect of lower discount rates used to measure the accumulated pension benefit obligation. The general upward trend in medical costs also contributed to the increase in employee benefit costs.
Depreciation expense increased approximately $3.3 million or 2.8 percent in 2002 as compared to 2001 due to a higher level of depreciable plant. Taxes other than income increased approximately $0.5 million or 1.1 percent in 2002 as compared to 2001 due to higher ad valorem taxes.
2001 compared to 2000. OG&E's operating income decreased approximately $34.5 million or 12.7 percent in 2001 as compared to 2000. The decrease in operating income was primarily attributable to a lower gross margin and significantly higher other operating expenses.
Gross margin decreased approximately $10.9 million or 1.6 percent in 2001 as compared to 2000. Gross margin was reduced by approximately $9.8 million due to milder weather.
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Lower recoveries of fuel costs from Arkansas customers through that state's automatic fuel adjustment clause decreased the gross margin by approximately $3.8 million. Lower recoveries under the GEP Rider decreased the gross margin by approximately $4.0 million in 2001. Lower levels of natural gas transportation cost that OG&E was allowed to recover from its customers through the APC Rider and GTAC Rider decreased the gross margin by approximately $2.4 million in 2001. See Note 16 of Notes to Consolidated Financial Statements for a further discussion of these riders. Partially offsetting these decreases was an increase of approximately $9.3 million due to customer growth in OG&E's service territory and the resulting increase in electric sales of 1.3 percent.
Fuel expense decreased approximately $3.3 million or 0.7 percent in 2001 as compared to 2000 primarily due to lower fuel consumption in 2001. Although fuel consumed was down in 2001, the average cost of fuel per Kwh increased 1.0 percent. Purchased power costs increased approximately $17.4 million or 6.6 percent in 2001 as compared to 2000 primarily due to an increase in capacity purchases under a wholesale purchase contract that OG&E maintains with Southwestern Public Service Corp., a 5.8 percent increase in the cost of purchased energy per Kwh and a 1.9 percent increase in total energy purchased.
Other operating expenses, consisting of operating and maintenance expense, depreciation expense and taxes other than income, increased approximately $23.6 million or 5.5 percent in 2001 as compared to 2000. OG&E’s operating and maintenance expense increased approximately $19.9 million or 7.4 percent in 2001 as compared to 2000. This increase was due to an increase of approximately $11.6 million in bad debt expense, approximately $9.7 million in employee pension and benefit costs and approximately $5.9 million in contract labor costs. Bad debt expense increased due to higher than normal bills driven by high natural gas prices early in 2001, customer cut-off moratoriums imposed during high temperature periods in the summer and the general slow down in the economy. Employee pension and benefit costs increased primarily due to lower than forecasted returns on assets in the pension trust and the effect of lower discount rates used to measure the accumulated pension benefit obligation. The general upward trend in medical costs also contributed to the increase in employee benefit costs. Contract labor costs increased due to the use of contractors to supplement OG&E’s own crews to restore power after a major ice storm at the beginning of 2001 and a major wind storm in the early summer of 2001. These increases were partially offset by a decrease of approximately $7.3 million in miscellaneous expenses and an increase in the amount of certain expenses capitalized as part of electric plant.
Depreciation expense increased approximately $2.6 million or 2.2 percent in 2001 as compared to 2000 due to a higher level of depreciable plant. Taxes other than income increased approximately $1.1 million or 2.4 percent in 2001 as compared to 2000 due to higher ad valorem taxes.
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Enogex
(Dollars in millions) 2002 2001 2000 ==================================================================================================== Operating revenues.................................. $ 1,684.0 $ 1,649.8 $ 1,997.3 Gas and electricity purchased for resale............ 1,402.1 1,318.4 1,614.5 Natural gas purchases - other....................... 70.5 142.9 174.9 - ---------------------------------------------------------------------------------------------------- Gross margin on revenues............................ 211.4 188.5 207.9 Impairment of assets................................ 48.3 --- --- Other operating expenses............................ 166.1 154.1 144.1 - ---------------------------------------------------------------------------------------------------- Operating income (loss)............................. $ (3.0) $ 34.4 $ 63.8 ==================================================================================================== Physical system supply - MMcfd (A).................. 1,654 1,752 2,005 - ---------------------------------------------------------------------------------------------------- Natural gas processed - MMcfd....................... 455 641 724 Natural gas liquids sold - million gallons.......... 313 453 565 Average sales price per gallon...................... $ 0.397 $ 0.421 $ 0.515 - ---------------------------------------------------------------------------------------------------- Natural gas marketed - Bbtu (B)..................... 409,879 280,660 434,577 Average sales price per Bbtu........................ $ 3.236 $ 4.403 $ 3.960 - ---------------------------------------------------------------------------------------------------- Power marketed - MWH................................ 1,458,390 1,226,845 1,070,334 Average sales price per MWH......................... $ 27.752 $ 45.180 $ 46.530 - ---------------------------------------------------------------------------------------------------- (A) Million cubic feet per day. (B) Billion British thermal units.
2002 compared to 2001. Enogex’s operating income for 2002 decreased approximately $37.4 million or 108.7 percent as compared to 2001. The decrease was primarily attributable to impairment losses in the fourth quarter of 2002 related to gas processing plants and compression assets, which Enogex determined were no longer needed in its business. Absent the impairment charges, Enogex’s operating income for 2002 would have been approximately $10.9 million higher than in 2001 primarily due to improved gross margins in transportation and storage and in marketing and trading, which were only partially offset by increased operating and maintenance expenses for transportation and storage and decreased gross margins in gathering and processing. Enogex’s E&P business and its interest in Belvan were sold during 2002 and its interest in NuStar was sold in 2003; accordingly, these are reported as discontinued operations for the years ended December 31, 2002, 2001 and 2000 in the Consolidated Financial Statements. See “Discontinued Operations” below for a further discussion.
During 2002, gathering and processing posted a loss of approximately $49.5 million in operating income, which was a decrease of approximately $53.4 million as compared to 2001. The decrease in operating income is primarily due to approximately $46.6 million of impairment losses in the fourth quarter of 2002 related to the disposition of gas processing plants and compression assets that were no longer needed in Enogex’s business. Gross margins were approximately $73.3 million in 2002 down from approximately $82.8 million in 2001. The primary factors in reduced gross margins in 2002 as compared to 2001 are lower volumes of natural gas gathered of 426 million British thermal units ("MMBtu") as compared to 464 MMBtu’s in 2001 and processed volumes of 313 million gallons as compared to 453 million gallons in 2001. Processed volumes were adversely affected by the January 2002 ice storm, which Enogex estimates caused processed volumes to be approximately 10.7 million gallons less. The average natural gas liquids price realized in 2002 was $0.397 per gallon as compared to $0.421 per gallon in 2001.
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Other operating expenses in gathering and processing, consisting of operating and maintenance expense, impairment charges, depreciation expense and taxes other than income, increased approximately $43.9 million or 55.5 percent in 2002 as compared to 2001. The impairment charge noted above accounted for approximately $46.6 million of this increase. Operating and maintenance expense decreased approximately $2.0 million in 2002 as compared to 2001. Lower payroll expenses of approximately $2.0 million, lower materials and supplies expense of approximately $1.9 million and lower fees for outside services of approximately $2.3 million were partially offset by increased allocations of overhead from the Company. See Note 1 of Notes to Consolidated Financial Statements. Depreciation expense increased approximately $1.1 million as compared to 2001, primarily the result of a higher level of depreciable plant. Taxes other than income decreased approximately $1.8 million due to lower ad valorem taxes.
During 2002, transportation and storage contributed approximately $45.6 million of Enogex’s operating income, which was an increase of approximately $10.3 million as compared to 2001. The gross margin increased 26.7 percent to approximately $120.5 million in 2002 from approximately $95.1 million in 2001. Gross margins benefited from increased fuel recoveries of approximately $10.8 million as compared to 2001, increased firm transportation revenue, primarily the result of new transportation contracts to merchant electric generation, of approximately $6.1 million as compared to 2001, higher volumes and prices on interruptible transmission service of approximately $3.8 million as compared to 2001, increased firm and interruptible transportation on Ozark of approximately $3.3 million as compared to 2001 and increased storage revenues of approximately $1.4 million as compared to 2001.
Other operating expenses in transportation and storage, consisting of operating and maintenance expense, impairment charges, depreciation expense and taxes other than income, increased approximately $15.1 million or 25.1 percent in 2002 as compared to 2001. Operating and maintenance expense increased approximately $10.1 million in 2002 as compared to 2001. The primary increase was approximately $3.4 million in uncollectible accounts as a result of the bankruptcy of a large customer, increased employee benefit costs of approximately $3.0 million, increased materials and supplies expense of approximately $2.5 million and increased building rentals and other miscellaneous expenses of approximately $1.2 million. Taxes other than income increased approximately $1.8 million, the result of higher ad valorem taxes. Depreciation expense increased approximately $1.5 million as compared to 2001, primarily the result of a higher level of depreciable plant. The 2002 expenses include impairment charges of approximately $1.7 million in the fourth quarter of 2002 related to the disposition of compression assets that were no longer needed in Enogex’s business.
During 2002, marketing and trading contributed approximately $0.9 million to Enogex's operating income, which was an improvement of approximately $5.7 million as compared to the loss of approximately $4.8 million for 2001. The increased contribution to operating income is primarily due to an increase in gross margin of approximately $7.0 million in 2002 as compared to 2001. Gross margins benefited from approximately a $7.6 million increase in mark-to-market gains on storage contracts that should be substantially realized during the first quarter of 2003, increased natural gas sales margins of approximately $6.1 million and increased income from other financial instruments of approximately $0.7 million partially offset by approximately a $3.5 million increase related to demand fees expense, approximately a $2.2 million decrease in
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third party gas storage management revenues and approximately a $1.7 million decrease in the power sales gross margin.
2001 compared to 2000. Enogex’s operating income for 2001 decreased approximately $29.4 million or 46.1 percent as compared to 2000. The decrease was primarily attributable to decreased gross margins in processing and in marketing and trading and increased operating and maintenance expenses for gathering and for transmission. These decreases were partially offset by an increased gross margin in transmission. Enogex’s E&P business, its interest in NuStar and its interest in Belvan have been reported as discontinued operations for the years ended December 31, 2002, 2001 and 2000 in the Consolidated Financial Statements. See “Discontinued Operations” for a further discussion.
During 2001, gathering and transmission contributed approximately $36.8 million of Enogex’s operating income, which was an increase of approximately $40.1 million as compared to 2000. The increase can be directly attributable to efforts by Enogex in 2001 to resolve the under-recovery of pipeline system fuel expenses that was reported in the fourth quarter 2000 results. Enogex filed for fuel-recovery rate adjustments with the FERC and the new rates became effective February 1, 2001. The impact of the filing enabled Enogex to significantly improve the recovery of pipeline system fuel expenses for the remainder of the year and in the future. The gross margin for gathering and transmission increased approximately $51.7 million in 2001 as compared to 2000. This increase was primarily due to an increase of approximately $22.3 million in pipeline system gas fuel expenses recovered in 2001 compared to the under-recovery of pipeline system fuel expenses in 2000. Also contributing to the increased gross margin was an increase of approximately $16.2 million in storage margins, higher prices on interruptible transmission service of approximately $8.2 million, approximately $3.3 million increased firm transportation revenues, primarily the result of higher volumes, increased firm and interruptible transportation on Ozark of approximately $1.5 million and an increase of approximately $0.2 million in other operating revenues.
Other operating expenses in gathering and transmission, consisting of operating and maintenance expense, depreciation expense and taxes other than income, increased approximately $11.6 million or 11.5 percent in 2001 as compared to 2000. Operating and maintenance expense increased approximately $9.4 million in 2001 as compared to 2000. The increase was primarily due to higher fees for outside services of approximately $3.9 million, higher payroll expenses of approximately $2.4 million, higher materials and supplies expense of approximately $1.1 million and higher building rentals and other miscellaneous expenses of approximately $2.0 million. Depreciation expense increased approximately $1.2 million, primarily the result of a higher level of depreciable plant. Taxes other than income increased approximately $1.0 million due to higher ad valorem taxes.
During 2001, processing contributed approximately $2.4 million of Enogex’s operating income, which was a decrease of approximately $59.3 million as compared to 2000. The gross margin for processing decreased approximately $62.5 million in 2001 as compared to 2000 due to poor fractionation spreads during 2001. Fractionation spread is the price received for liquids sold after they are processed out of the natural gas stream, less the price of the natural gas lost in the process. During the first quarter of 2001, these spreads were negative. A significant
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percentage of volumes transported on the Enogex pipeline system were processed under “keep whole” arrangements. Under these arrangements, and in order to keep its shippers whole on a Btu basis, Enogex Products Corporation replaced the Btu value of the liquids with natural gas at market prices. In order to minimize the impact of negative fractionation spreads, ethane and propane were rejected whenever possible. During 2001, approximately 105.4 million gallons were rejected compared to approximately 18.8 million gallons in 2000. The average fractionation spread realized for 2001 was $1.041 per MMBtu compared to $2.232 per MMBtu for 2000.
Other operating expenses in processing, consisting of operating and maintenance expense, depreciation expense and taxes other than income, decreased approximately $3.2 million or 12.1 percent in 2001 as compared to 2000. Operating and maintenance expense decreased approximately $3.5 million in 2001 as compared to 2000. The decrease was primarily due to a decrease of approximately $5.0 million in electric compression partially offset by higher materials and supplies expense of approximately $1.5 million. Depreciation expense increased approximately $0.3 million, primarily the result of a higher level of depreciable plant.
During 2001, marketing and trading posted a loss of approximately $4.8 million to Enogex’s operating income, which was a decrease of approximately $10.2 million as compared to the contribution of approximately $5.4 million for 2000. The gross margin decreased approximately $8.6 million in 2001 as compared to 2000. This decrease in gross margin is primarily due to a decrease of approximately $12.1 million in the natural gas, crude oil and electric power trading gross margins, partially offset by an increase of approximately $3.5 million in other operating revenues primarily related to gas storage revenues.
Other operating expenses in marketing and trading, consisting of operating and maintenance expense, depreciation expense and taxes other than income, increased approximately $1.6 million or 9.5 percent in 2001 as compared to 2000. Operating and maintenance expense increased approximately $0.8 million primarily due to higher allocations of overhead from the Company. Depreciation expense increased approximately $0.7 million, primarily the result of accelerated depreciation on energy trading software that was replaced at the end of 2001. Taxes other than income increased approximately $0.1 million due to higher ad valorem taxes.
Consolidated Other Income and Expense, Interest Expense and Income Tax Expense
2002 compared to 2001. Other income includes, among other things, contract work performed by OG&E, non-operating rental income, profit on the retirement of fixed assets, minority interest income and miscellaneous non-operating income. Other income increased approximately $0.6 million or 19.4 percent in 2002 as compared to 2001. This increase was primarily due to a reduction of approximately $1.4 million in the liability associated with the deferred compensation plan and approximately a $0.4 million increase related to gain on the sale of assets. These increases were partially offset by a decrease in minority interest income of approximately $0.8 million and approximately a $0.3 million decrease in non-operating rental income.
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Other expense includes, among other things, expenses from loss on retirement of fixed assets, miscellaneous charitable donations, expenditures for certain civic, political and related activities and miscellaneous deductions. Other expense increased approximately $0.5 million or 11.9 percent in 2002 as compared to 2001. This increase was primarily due to approximately a $0.6 million loss on the value of plan assets of the deferred compensation plan and approximately a $0.4 million loss on the sale of inventory partially offset by an approximately $0.2 million decrease in miscellaneous charitable donations and a decrease of approximately $0.2 million in expenditures for certain civic, political and related activities.
Net interest expense includes interest income, interest expense and other interest charges. Net interest expense decreased approximately $13.9 million or 11.3 percent in 2002 as compared to 2001. This decrease was primarily due to a reduction in interest expense of approximately $6.8 million related to lower interest rates on outstanding debt achieved from entering into interest rate swap agreements in 2002 and 2001, approximately a $3.9 million decrease in interest expense related to the retirement of $140.0 million in debt during 2002 and approximately a $4.5 million decrease in interest expense related to commercial paper activity. These decreases were partially offset by approximately a $0.6 million increase in interest expense due to an increase in commercial paper service fees.
Income tax expense decreased approximately $8.3 million or 15.7 percent in 2002 as compared to 2001 primarily from a higher pre-tax loss at Enogex in 2002. In addition, there was a reversal of previously accrued federal income tax related to several issues that were resolved in favor of the Company and a refund of Oklahoma state income tax related to Oklahoma investment tax credits from prior years which lowered the effective tax rate from 34.3 percent in 2001 to 32.2 percent in 2002.
2001 compared to 2000. Other income decreased approximately $1.1 million or 26.2 percent in 2001 as compared to 2000. This decrease was primarily due to approximately a $1.6 million decrease related to gain on the sale of assets and approximately a $0.3 million decrease in minority interest income. These decreases were partially offset by approximately a $0.9 million increase in contract work performed by OG&E.
Other expense increased approximately $0.6 million in 2001 as compared to 2000, primarily due to an increase of approximately $0.6 million in miscellaneous corporate expenses.
Net interest expense decreased approximately $6.4 million or 4.9 percent in 2001 as compared to 2000. This decrease was primarily due to a reduction in interest expense of approximately $4.8 million related to lower interest rates on outstanding debt achieved from entering into interest rate swap agreements in 2001 and approximately a $2.8 million decrease in interest expense related to commercial paper activity. These decreases were partially offset by approximately a $1.5 million decrease in capitalized interest due to lower levels of construction work in progress.
Income tax expense decreased approximately $19.1 million or 26.5 percent in 2001 as compared to 2000 primarily due to lower pre-tax income in 2001.
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Discontinued Operations
On March 25, 2002, Enogex entered into an Agreement of Sale and Purchase with West Texas Gas, Inc. to sell all of its interests in Belvan for approximately $9.8 million. The effective date of the sale was January 1, 2002 and the closing occurred on March 28, 2002. The Company recognized approximately a $1.6 million gain related to the sale of these assets.
On August 5, 2002, Enogex entered into an Agreement of Sale and Purchase with Chesapeake Exploration Limited Partnership to sell all of its exploration and production assets located in Oklahoma, Texas, Arkansas and Mississippi for approximately $15.0 million. The effective date of the sale was July 1, 2002 and the closing occurred on September 19, 2002. The Company recognized approximately a $2.3 million loss related to the sale of these assets.
On November 14, 2002, Enogex entered into an Agreement of Sale and Purchase with Quicksilver Resources, Inc. to sell all of its exploration and production assets located in Michigan for approximately $32.0 million. The effective date of the sale was July 1, 2002 and the closing occurred on December 2, 2002. The Company recognized approximately a $2.9 million gain related to the sale of these assets.
During the third quarter of 2002, the Company decided to sell all of its interests in NuStar. On January 23, 2003, Enogex entered into an Agreement of Sale and Purchase with Benedum Gas Partners, L.P. to sell all of the interests of its subsidiary, Enogex Products Corporation, in the west Texas properties consisting of NuStar, which has operations consisting of the extraction and sale of natural gas liquids, for approximately $37.0 million. The effective date of the sale was January 1, 2003 and the closing occurred on February 18, 2003. The Company will recognize a pre-tax gain of approximately $2.3 million in the first quarter of 2003 related to the sale of these assets.
As a result of these sale transactions, Enogex’s E&P business, its interest in NuStar and its interest in Belvan, all of which were part of the Natural Gas Pipeline segment, have been reported as discontinued operations for the years ended December 31, 2002, 2001 and 2000 in the Consolidated Financial Statements. Results for these discontinued operations are summarized and discussed below.
(In millions) 2002 2001 2000 ===================================================================================== Operating revenues........................ $ 79.5 $ 121.4 $ 117.7 Gas purchased for resale.................. 49.5 81.0 74.8 Natural gas purchases - other............. 6.4 2.7 --- - ------------------------------------------------------------------------------------- Gross margin on revenues.................. 23.6 37.7 42.9 Other operating expenses.................. 17.1 30.6 26.8 - ------------------------------------------------------------------------------------- Operating income.......................... $ 6.5 $ 7.1 $ 16.1 =====================================================================================
2002 compared to 2001. Gross margin decreased approximately $14.1 million or 37.4 percent in 2002 as compared to 2001. The decrease was primarily attributable to approximately a $10.0 million decrease in natural gas sales due to lower prices and sales volumes in 2002 as compared to 2001 for exploration and production, approximately a $3.9 million decrease in
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natural gas and natural gas liquids sales related to lower prices and sales volumes related to NuStar and Belvan and approximately a $0.2 million decrease in crude oil sales.
Other operating expenses decreased approximately $13.5 million or 44.1 percent in 2002 as compared to 2001. Other operating expenses include operating and maintenance expenses, depreciation expense and taxes other than income. Operating and maintenance expenses decreased approximately $3.6 million or 21.9 percent in 2002 as compared to 2001. This decrease was due to approximately a $2.9 million decrease in exploration and production expenses as the exploration and production assets were sold in 2002 and approximately a $0.7 million decrease in miscellaneous operating expenses related to NuStar and Belvan as these assets have been or were in the process of being sold in 2002.
Depreciation expense decreased approximately $9.9 million or 68.8 percent in 2002 as compared to 2001. This decrease was primarily due to approximately a $6.0 million impairment charge in 2001 related to Belvan and approximately a $3.9 million decrease due to ceasing depreciation on the assets, which have been or were in the process of being sold.
2001 compared to 2000. Gross margin decreased approximately $5.2 million or 12.1 percent in 2001 as compared to 2000. The decrease was primarily attributable to approximately a $4.8 million decrease in natural gas sales due to lower prices in 2001 as compared to 2000 for exploration and production, approximately a $0.3 million decrease in crude oil sales and approximately a $0.1 million decrease in natural gas and natural gas liquids sales related to higher prices and lower volumes related to NuStar and Belvan.
Other operating expenses increased approximately $3.8 million or 14.2 percent in 2001 as compared to 2000. Other operating expenses include operating and maintenance expenses, depreciation expense and taxes other than income. Operating and maintenance expenses decreased approximately $1.6 million or 8.8 percent in 2001 as compared to 2000. This decrease was due to approximately a $3.3 million decrease in exploration and production expenses resulting from the sale of working interests in 2000 for oil and gas properties located in Texas and Utah partially offset by approximately a $1.7 million increase in miscellaneous operating expenses related to NuStar and Belvan in 2001 as compared to 2000.
Depreciation expense increased approximately $5.4 million or 60.0 percent in 2001 as compared to 2000. This increase was primarily due to approximately a $6.0 million impairment charge in 2001 related to Belvan partially offset by approximately a $0.6 million decrease due to ceasing depreciation on the assets, which were in the process of being sold.
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Liquidity and Capital Requirements
Capital requirements and future contractual obligations estimated for 2003 through 2006 and beyond are as follows:
- ----------------------------------------------------------------------------------------------------------
Actual 2006 and
(In millions) 2002 2003 2004 2005 Beyond
- ----------------------------------------------------------------------------------------------------------
OG&E capital expenditures including AFUDC......... $ 198.7 (A) $ 149.0 (B) $ 142.0 $ 142.0 N/A
Enogex capital expenditures and acquisitions (C).. 20.0 39.0 35.0 28.0 N/A
Other Operations capital expenditures............. 15.8 8.0 8.0 8.0 N/A
- ----------------------------------------------------------------------------------------------------------
Total capital expenditures.................. 234.5 196.0 185.0 178.0 N/A
Maturities of long-term debt...................... 115.0 20.8 52.8 146.1 $1,303.2
Retirement of long-term debt...................... 25.0 10.0 (D) N/A N/A N/A
- ----------------------------------------------------------------------------------------------------------
Total capital requirements.................. 374.5 226.8 237.8 324.1 1,303.2
Operating lease obligations
OG&E railcars.................................. 5.4 5.4 5.4 5.4 46.9
Enogex noncancellable operating leases......... 4.3 4.3 3.6 3.5 5.2
- ----------------------------------------------------------------------------------------------------------
Total operating lease obligations........... 9.7 9.7 9.0 8.9 52.1
Unconditional purchase obligations
OG&E cogeneration capacity payments............ 192.1 164.7 152.7 87.7 173.6
OG&E other purchased power capacity payments... 10.7 14.6 N/A N/A N/A
OG&E fuel minimum purchase commitments......... 164.1 152.2 145.6 147.2 565.4
- ----------------------------------------------------------------------------------------------------------
Total unconditional purchase obligations.... 366.9 331.5 298.3 234.9 739.0
Total capital requirements, operating lease
obligations and unconditional purchase
obligations..................................... 751.1 568.0 545.1 567.9 2,094.3
Amounts recoverable through automatic fuel
adjustment clause (E)........................... (370.8) (334.9) (303.7) (240.3) (785.9)
- ----------------------------------------------------------------------------------------------------------
Total, net.................................. $ 380.3 $ 233.1 $ 241.4 $ 327.6 $1,308.4
==========================================================================================================
(A) Includes approximately $86.6 million from the January 2002 ice storm.
(B) Amounts do not include the acquisition of New Generation.
(C) Amounts exclude discontinued operations capital expenditures.
(D) Reflects amounts that have been called to date for redemption in 2003.
(E) Includes expected recoveries of costs incurred for OG&E's railcar operating lease obligations
and OG&E's unconditional purchase obligations.
N/A - not applicable
Variances in the actual cost of fuel used in electric generation (which includes the operating lease obligations for OG&E’s railcar leases shown above) and certain purchased power costs, as compared to the fuel component included in the cost-of-service for ratemaking, are passed through to OG&E’s customers through automatic fuel adjustment clauses. Accordingly, while the cost of fuel related to operating leases and the vast majority of unconditional purchase obligations of OG&E 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. The OCC, the APSC and the
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FERC also have authority to review the appropriateness of gas transportation charges or other fees OG&E pays to Enogex. See Note 16 of Notes to Consolidated Financial Statements for a further discussion.
The Company’s primary needs for capital are related to replacing or expanding existing facilities in OG&E’s electric utility business and replacing or expanding existing facilities at Enogex. Other capital requirements are primarily related to maturing debt, operating lease obligations, hedging activities, natural gas storage and delays in recovering unconditional purchase obligations. The Company generally meets its cash needs through a combination of internally generated funds, short-term borrowings and permanent financings.
The amounts shown in the chart on page 71 do not include the cost of acquiring an electric generating plant with at least 400 MW of capacity, which OG&E intends to acquire during 2003 in accordance with the Settlement Agreement approved by the OCC on November 20, 2002. Any generating facility acquired by OG&E is expected to be financed through the issuance of common stock by the Company and through the issuance of debt by OG&E.
2002 Capital Requirements and Financing Activities
Total capital requirements, consisting of capital expenditures and maturities and retirements of long-term debt, were approximately $374.5 million and contractual obligations, net of recoveries through automatic fuel adjustment clauses, were approximately $5.8 million resulting in total net capital requirements and contractual obligations of approximately $380.3 million in 2002. Approximately $86.6 million of capital expenditures in 2002 were associated with the costs of the January 2002 ice storm, which severely damaged OG&E’s electric transmission and distribution systems. Approximately $2.8 million of the 2002 capital requirements were to comply with environmental regulations. Excluding the ice storm, total net capital requirements would have been approximately $287.9 million. This compares to net capital requirements of approximately $238.2 million and net contractual obligations of approximately $6.3 million totaling approximately $244.5 million in 2001, of which approximately $3.3 million was to comply with environmental regulations. During 2002, the Company’s sources of capital were internally generated funds from operating cash flows, short-term borrowings and proceeds from the sale of assets. The Company’s short-term borrowings consist primarily of commercial paper and short-term bank loans. The Company uses its commercial paper to fund changes in working capital. Changes in working capital reflect the seasonal nature of the Company’s business, the revenue lag between billing and collection for customers and fuel inventories. In 2002, OGE Energy Corp. commercial paper was used to fund expenditures associated with the ice storm. Additionally, the Company assumed debt of approximately $33.8 million related to the purchase of a gas storage facility. As a result, current liabilities exceed current assets by approximately $139.9 million at December 31, 2002. At December 31, 2002, the Company had outstanding short-term borrowings of approximately $275.0 million.
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During 2002, $113.0 million of Enogex’s long-term debt matured and $27.0 million was redeemed with internally generated funds, funds from the sale of assets and short-term debt. The following table itemizes the retirement of long-term debt during 2002.
(In millions) 2002
--------------------------------------------------------
Series Due 2002 -- 7.02% - 8.13%.............. $ 113.0
Series Due 2012 -- 8.35% - 8.90%.............. 10.0
Series Due 2017 -- 8.96%...................... 15.0
Series Due 2018 -- 7.15%...................... 2.0
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Total.................................... $ 140.0
========================================================
Effective January 1, 2001, the Company adopted Statement of Financial Accounting Standards (“SFAS”) No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended. SFAS No. 133 requires the Company to record all derivatives on the Balance Sheet at fair value. Changes in the fair value of derivatives that are not designated as hedges, as well as the ineffective portion of hedge derivatives, must be recognized as a derivative fair value gain or loss in the accompanying Consolidated Statements of Income. The value of effective fair value hedges are recorded in Price Risk Management assets and liabilities in the accompanying Consolidated Balance Sheets, with the corresponding offset recorded against the value in the hedged asset or liability. The value of effective cash flow hedges are recorded in Price Risk Management assets and liabilities with the corresponding component in Accumulated Other Comprehensive Income, which is later reclassified to earnings when the related hedged transaction is reflected in income. Physical delivery contracts that are deemed to be normal purchases or normal sales and have been designated as such are not accounted for as derivatives. Physical delivery contracts that are not deemed to be normal purchases or normal sales are accounted for as derivatives.
Based on the Company’s derivative positions related to non-trading activity and market prices in effect at January 1, 2001, the adoption of SFAS No. 133 resulted in a reduction to Accumulated Other Comprehensive Income of approximately $26.9 million ($16.5 million after tax). This amount was associated with certain cash flow hedges in place at January 1, 2001 and was reclassified into earnings during 2001 as the hedged production was sold. As a result of subsequent changes in market prices, the Company ultimately recognized a $0.8 million loss on the settlement of these contracts during 2001, including a gain of $4.7 million related to the ineffective portion of the change in value of the derivative contracts. As of December 31, 2002, the Company did not have any outstanding cash flow hedges, and, as such, had no amounts included in Accumulated Other Comprehensive Income related to cash flow hedges. As of December 31, 2001, the Company had one outstanding cash flow hedge, and approximately $0.1 million after tax was included in Accumulated Other Comprehensive Income.
During 2001, the Company entered into two separate interest rate swap agreements: (i) OG&E entered into an interest rate swap agreement, effective March 30, 2001, to convert $110.0 million of 7.30 percent fixed rate debt due October 15, 2025, to a variable rate based on the three month London InterBank Offering Rate (“LIBOR”) and (ii) Enogex entered into an interest rate swap agreement, effective July 15, 2001, to convert $200.0 million of 8.125 percent fixed rate debt due January 15, 2010, to a variable rate based on the three month LIBOR. On
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March 1, 2002, Enogex monetized its interest rate swap agreement and received cash of approximately $4.2 million, which is being amortized over the life of the related debt.
On March 4, 2002, Enogex entered into an interest rate swap agreement to convert $200.0 million of 8.125 percent fixed rate debt due January 15, 2010, to a variable rate based on the three month LIBOR. On July 2, 2002, Enogex monetized its interest rate swap agreement and received cash of approximately $6.6 million, of which approximately $3.2 million was recorded against interest receivable and the remaining amount of approximately $3.4 million is being amortized over the life of the related debt.
On August 7, and on October 24, 2002, Enogex entered into interest rate swap agreements to convert $100.0 million of 8.125 percent fixed rate debt due January 15, 2010, to a variable rate based on the six month LIBOR.
These interest rate swaps qualified as fair value hedges under SFAS No. 133 and meet all of the requirements for a determination that there was no ineffective portion as allowed by the shortcut method under SFAS No. 133. The objective of these interest rate swaps was to achieve a lower cost of debt and to raise the percentage of total corporate long-term floating rate debt to reflect a level more in line with industry standards.
On April 6, 2001, the Company entered into a one-year interest rate swap agreement to lock in a fixed rate of 4.41 percent, effective April 10, 2001, on $140.0 million of variable rate short-term debt. This interest rate swap initially qualified for hedge accounting treatment as a cash flow hedge under SFAS No. 133. However, due to unexpected changes in the level of commercial paper issued during the third quarter of 2001, hedge accounting treatment under SFAS No. 133 was discontinued as of July 1, 2001, and all subsequent changes in the fair value of the swap were recorded as Interest Expense. The objective of this interest rate swap was to achieve a lower cost of debt and to reduce exposure to short-term interest rate volatility associated with the Company’s commercial paper program.
Future Capital Requirements
The Company’s 2003 to 2005 construction program does not include the building of any additional generating units. Instead, in accordance with the Settlement Agreement approved by the OCC on November 20, 2002, OG&E intends to purchase an electric generating plant with at least 400 MW’s of generating capacity. The Company believes that an efficient combined cycle plant can be purchased for a price less than the cost to build a new facility. To reliably meet the increased electricity needs of OG&E’s customers during the foreseeable future, OG&E will continue to invest to maintain the integrity of the delivery system. Approximately $4.9 million of the Company’s capital expenditures budgeted for 2003 are to comply with environmental laws and regulations.
During 2002, actual asset returns for the Company’s defined benefit pension plan were adversely affected by continued deterioration in the equity markets. Approximately 60 percent of the pension plan assets are invested in listed common stocks with the balance invested in corporate debt and U.S. Government securities. For the year ended December 31, 2002, asset
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returns on the pension plan were approximately negative 5.75 percent. During the same time, corporate bond yields, which are used in determining the discount rate for future pension obligations, have continued to decline.
Contributions to the pension plan increased from approximately $43.0 million in 2001 to approximately $48.8 million in 2002. This increase was necessitated by the lower investment returns on assets and lower discount rates used to value the accumulated pension benefit obligations. During 2003, the Company plans to contribute approximately $50.0 million to the pension plan. 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. The following table indicates the sensitivity of the pension plans funded status to these variables.
Impact on
Change Funded Status
------------------ -----------------
Actual plan asset returns +/- 5 percent +/- $15.3 million
Discount rate +/- 0.25 percent +/- $ 7.9 million
Contributions + $10.0 million + $10.0 million
Expected long-term return on plan assets +/- 1 percent None
As discussed in Note 13 of Notes to Consolidated Financial Statements, in 2000 the Company made several changes to its pension plan, including the adoption of a cash balance benefit feature for employees hired after January 31, 2000. The cash balance plan may provide lower post-employment pension benefits to employees, which could result in less pension expense being recorded. Over the near term, the Company’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, the Company’s cash requirements should decrease and will be much less sensitive to changes in discount rates.
During 2002 and 2001, the Company made contributions to the pension plan that exceeded amounts previously recognized as net periodic pension expense and recorded a prepaid benefit obligation at December 31, 2002 and 2001 of approximately $44.9 million and $21.3 million, respectively. At December 31, 2002 and 2001, the Company’s projected pension benefit obligation exceeded the fair value of pension plan assets by approximately $156.7 million and $93.5 million, respectively. As a result of recording a prepaid benefit obligation and having a funded status where the projected benefit obligations exceeded the fair value of plan assets, provisions of SFAS No. 87, “Employers’ Accounting for Pensions”, required the recognition of an additional minimum liability in the amount of approximately $163.9 million and $83.1 million, respectively, at December 31, 2002 and 2001. The offset of this entry was an intangible asset and Accumulated Other Comprehensive Income, net of a deferred tax asset; therefore, this adjustment did not impact the results of operations in 2002 or 2001 and did not require a usage of cash and is therefore excluded from the Consolidated Statements of Cash Flows. The amount recorded as an intangible asset equaled the unrecognized prior service cost with the remainder recorded in Accumulated Other Comprehensive Income. The amount in Accumulated Other
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Comprehensive Income represents a net periodic pension cost to be recognized in the Consolidated Statements of Income in future periods.
On October 31, 2002, Fitch Ratings (“Fitch”) reaffirmed the ratings of OGE Energy Corp.'s senior unsecured debt at A and short-term debt at F1, OG&E’s senior unsecured debt at AA- and short-term debt at F1 and Enogex’s senior unsecured debt at BBB. The rating outlook is stable. Fitch cited the solid financial position, low business risk and strong cash flows at OG&E and the higher risk nature of Enogex acknowledging that renewed management focus on cost reductions and reducing cash flow volatility across all unregulated business lines should allow for gradual strengthening of Enogex’s credit profile.
On January 15, 2003, Standard & Poor’s Ratings Services (“Standard & Poor’s”) lowered the credit ratings of OGE Energy Corp.'s, OG&E’s and Enogex’s senior unsecured debt from A- to BBB+. OGE Energy Corp.'s short-term commercial paper ratings were affirmed at A-2. The outlook is now stable. Standard & Poor’s cited the relatively low-risk low-cost efficient operations of OG&E and the business and financial profile of Enogex, which has higher risk. Standard & Poor’s further cited the rationalization at Enogex has resulted in a business-risk reduction, but it is not adequate to warrant an improvement in the overall business score. The Company may experience somewhat higher borrowing costs but does not expect the actions by Standard & Poor’s to have a significant impact on the Company’s consolidated financial position or results of operations.
At December 31, 2002, Moody’s Investors Service (“Moody’s”) credit ratings of OGE Energy Corp. senior unsecured debt was A3, OG&E senior unsecured debt was A1 and Enogex senior unsecured debt was Baa2. On February 5, 2003, Moody’s lowered the credit ratings of OGE Energy Corp. senior unsecured debt to Baa1 from A3, OG&E senior unsecured debt to A2 from A1 and Enogex senior unsecured debt to Baa3 from Baa2. OGE Energy Corp.'s short-term commercial paper rating was unchanged at P-2. The outlook for OGE Energy Corp. and OG&E is stable and Enogex is negative. Moody’s cited the diminished credit profile of both OG&E and Enogex with OG&E having competitive generation and stable cash flow but with regulatory risk associated with New Generation and Enogex exposed to the seasonality of its gas processing business although it has reduced its keep whole exposure. The Company may experience somewhat higher borrowing costs but does not expect the actions by Moody’s to have a significant impact on the Company’s consolidated financial position or results of operations. As a result of Enogex’s rating being lowered to Baa3, OGE Energy Corp. was required to issue a $5.0 million guarantee on Enogex’s behalf for a counterparty. As of December 31, 2002, in the event Moody’s or Standard & Poor’s were to lower Enogex’s senior unsecured debt rating to a below investment grade rating, Enogex would be required to post less than $5.0 million of collateral to satisfy its obligation under its financial and physical contracts. In the event one or more of the credit ratings were to fall below investment grade, Enogex may seek OGE Energy Corp. guarantees to satisfy its customers in order to avoid disruption of its marketing and trading business.
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.
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Future financing requirements may be dependent, to varying degrees, upon numerous factors such as general economic conditions, abnormal weather, load growth, acquisitions of other businesses, 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
Apart from the funds required to purchase at least 400 MW’s of a power plant pursuant to the Settlement Agreement, management expects that internally generated funds will be adequate over the next three years to meet other anticipated capital expenditures, operating needs, payment of dividends and maturities of long-term debt.
Short-term borrowings will be used to meet working capital requirements. The following table shows the Company’s lines of credit in place at March 10, 2003. Short-term borrowings will consist of a combination of bank borrowings and commercial paper.
Lines of Credit (In millions)
-----------------------------------------------------------------------
Entity Amount Maturity
-----------------------------------------------------------------------
OGE Energy Corp. (A) $ 15.0 April 6, 2003
200.0 January 8, 2004
100.0 January 15, 2004
OG&E 100.0 June 26, 2003
-----------------------------------------------------------------------
Total $ 415.0
=======================================================================
(A) The lines of credit at OGE Energy Corp. were used to back up the
Company's commercial paper borrowings which were approximately $168.5
million at March 10, 2003. No borrowings were outstanding at
March 10, 2003 under any of the lines of credit shown above.
The Company’s ability to access the commercial paper market could be adversely impacted by a commercial paper ratings downgrade. The lines of credit contain ratings triggers that require annual fees and borrowing rates to increase if the Company suffers an adverse ratings impact. The impact of a downgrade of the Company’s rating would result in an increase in the cost of short-term borrowings of approximately five to 20 basis points, but would not result in any defaults or accelerations as a result of the ratings triggers. See “Future Capital Requirements” for potential financing needs upon a downgrade by Moody’s of Enogex’s long-term debt rating.
Also contributing to the liquidity of the Company have been numerous asset sales by Enogex. Since January 1, 2002, completed sales generated proceeds of approximately $103.8 million. Sales proceeds generated to date have been used to reduce debt at Enogex and commercial paper at the holding company.
Unlike the Company and Enogex, OG&E must obtain regulatory approval from the FERC in order to borrow on a short-term basis. OG&E has the necessary regulatory approvals to incur up to $400 million in short-term borrowings at any one time.
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The Company continues to evaluate opportunities to enhance shareowner returns and achieve long-term financial objectives through acquisitions of assets that may complement its existing portfolio. Permanent financing would be required for any such acquisitions.
Critical Accounting Policies and Estimates
The Consolidated Financial Statements and Notes to Consolidated Financial Statements contain information that is pertinent to Management’s Discussion and Analysis. In preparing the consolidated 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 liabilities at the date of the consolidated 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 Consolidated Financial Statements particularly as they relate to pension expense and impairment estimates. However, the Company believes it has taken 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, impairment estimates, contingency reserves, unbilled revenue for OG&E, the allowance for uncollectible accounts receivable, the valuation of energy purchases and sales contracts and gas storage inventory. The selection, application and disclosure of the following critical accounting estimates have been discussed with the Company’s audit committee.
Consolidated (including Electric Utility and Natural Gas Pipeline Segments)
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 and assumed discount rates. 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 13 of Notes to Consolidated 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. See “Future Capital Requirements” for a further discussion.
The Company assesses potential impairments of assets when there is evidence that events or changes in circumstances indicate that an asset’s carrying value may not be recoverable. An impairment loss is recognized when the sum of the expected future net cash flows is less than the carrying amount of the asset. The amount of any recognized impairment is based on the estimated fair value of the asset subject to impairment compared to the carrying amount of such asset.
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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 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.
Electric Utility Segment
OG&E reads its customers’ meters and sends bills to its customers throughout each month. As a result, there is a significant amount of customers’ electricity consumption that has not been billed at the end of each month. Unbilled revenue is presented in Accrued Unbilled Revenues on the Consolidated Balance Sheets and in Operating Revenues on the Consolidated Statements of Income based on estimates of usage and prices during the period. At December 31, 2002 and 2001, Accrued Unbilled Revenues were approximately $28.2 million and $35.6 million, respectively. The estimates that management uses in this calculation could vary from the actual amounts to be paid by customers.
All customer balances are written off if not collected within six months after the account is finalized. 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. The allowance for uncollectible accounts receivable is a reduction to Accounts Receivable on the Consolidated Balance Sheets and is included in Other Operation and Maintenance Expense on the Consolidated Statements of Income. The allowance for uncollectible accounts receivable was approximately $4.7 million and $6.2 million at December 31, 2002 and 2001, respectively.
Natural Gas Pipeline Segment
Operating revenues for transportation, gathering and storage services for Enogex are estimated each month based on the prior month’s activity and any known adjustments. The estimates are reversed in the following month and customers are billed on actual volumes and contracted prices. Gas sales are calculated on current month nominations and contracted prices. Operating revenues associated with the production of natural gas liquids are estimated based on current month estimated production and contracted prices. These amounts are reversed in the following month and the customers are billed on actual production and contracted prices. Estimated operating revenues are reflected in Accounts Receivable on the Consolidated Balance Sheets and in Operating Revenues on the Consolidated Statements of Income.
Estimates for gas purchases are based on sales volumes and contracted purchase prices. Estimated gas purchases are included in Accounts Payable on the Consolidated Balance Sheets and in Cost of Goods Sold on the Consolidated Statements of Income.
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In October 2002, the Emerging Issues Task Force (“EITF”) reached a consensus to rescind EITF Issue No. 98-10, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities”, as amended effective for fiscal periods beginning after December 15, 2002. Effective October 25, 2002, all new contracts and physical inventories that would have been accounted for under EITF 98-10 are no longer marked to market through earnings unless the contracts meet the definition of a derivative under SFAS No. 133. Contracts and physical inventories that existed at October 25, 2002 will continue to be accounted for under EITF 98-10 through December 31, 2002. Energy contracts are entered into by OGE Energy Resources, Inc. (“OERI”), the marketing subsidiary of Enogex. Corporate risk management and credit committees charged with enforcing the trading and credit policies, which include strict guidance on counterparties, procedures, credit and trading limits, monitor these activities. Marketing activities include the trading and marketing of natural gas, electricity, and natural gas liquids. The vast majority of positions expire within two years, which is when the cash aspect of the transactions will be realized. In nearly all cases, independent market prices are obtained and compared to the values used for the mark-to-market valuation, and an oversight group outside of the marketing organization monitors all modeling methodologies and assumptions. The recorded value of the energy contracts may change significantly in the future as the market price for the commodity changes, but the value is still subject to the risk loss limitations provided under the Company’s risk policies. The Company utilizes a model to a small extent to estimate the fair value of its energy contracts including derivatives that do not have an independent market price. Approximately 96.6 percent of the Company’s recorded fair value of energy contracts and gas in storage utilize quoted market prices in an active market. At December 31, 2002, unrealized mark-to-market gains were approximately $14.9 million, which included approximately $13.7 million based on independent market prices. Energy contracts are presented in Price Risk Management assets and liabilities on the Consolidated Balance Sheets and in Operating Revenues on the Consolidated Statements of Income. See “Accounting Pronouncements” for a further discussion.
Gas storage inventory used in OERI’s trading activities that was acquired prior to October 26, 2002 is marked to market utilizing a gas index that in management’s opinion approximates the current market value of natural gas in that region as of the Balance Sheet date. However, the actual market value could materially change in the future due to changes in market conditions such as weather or supply and demand. Gas storage inventory acquired after October 25, 2002 is accounted for at the lower of cost or market in accordance with the guidance in EITF 02-3. Gas storage inventory is presented in Fuel Inventories on the Consolidated Balance Sheets and in Cost of Goods Sold on the Consolidated Statements of Income.
Customer balances are written off when the Company concludes the required payment of specific amounts owed is unlikely to occur. The allowance for uncollectible accounts receivable is established on a case-by-case basis when the Company believes the required payment of specific amounts owed is unlikely to occur. The allowance for uncollectible accounts receivable is a reduction to Accounts Receivable on the Consolidated Balance Sheets and is included in Other Operation and Maintenance Expense on the Consolidated Statements of Income. The allowance for uncollectible accounts receivable was approximately $8.9 million and $3.5 million at December 31, 2002 and 2001, respectively.
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Accounting Pronouncements
Effective January 1, 2001, the Company adopted SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended. SFAS No. 133 requires the Company to record all derivatives on the Balance Sheet at fair value. Changes in the fair value of derivatives that are not designated as hedges, as well as the ineffective portion of hedge derivatives, must be recognized as a derivative fair value gain or loss in the accompanying Consolidated Statements of Income. The value of effective fair value hedges are recorded in Price Risk Management assets or liabilities in the accompanying Consolidated Balance Sheets, with the corresponding offset recorded against the value in the hedged asset or liability. The value of effective cash flow hedges are recorded in Price Risk Management assets or liabilities with the corresponding component in Accumulated Other Comprehensive Income, which is later reclassified to earnings when the related hedged transaction is reflected in income. Physical delivery contracts that are deemed to be normal purchases or normal sales and have been designated as such are not accounted for as derivatives. Physical delivery contracts that are not deemed to be normal purchases or normal sales are accounted for as derivatives.
Based on the Company’s derivative positions related to non-trading activity and market prices in effect at January 1, 2001, the adoption of SFAS No. 133 resulted in a reduction to Accumulated Other Comprehensive Income of approximately $26.9 million ($16.5 million after tax). This amount was associated with certain cash flow hedges in place at January 1, 2001 and was reclassified into earnings during 2001 as the hedged production was sold. As a result of subsequent changes in market prices, the Company ultimately recognized a $0.8 million loss on the settlement of these contracts during 2001, including a gain of $4.7 million related to the ineffective portion of the change in value of the derivative contracts. As of December 31, 2002, the Company did not have any outstanding cash flow hedges, and, as such, had no amounts included in Accumulated Other Comprehensive Income related to cash flow hedges. As of December 31, 2001, the Company had one outstanding cash flow hedge, and approximately $0.1 million after tax was included in Accumulated Other Comprehensive Income.
In June 2001, the FASB issued SFAS No. 143, “Accounting for Asset Retirement Obligations.” SFAS No. 143 applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or the normal operation of a long-lived asset. SFAS No. 143 will affect the Company’s accrued plant removal costs for generation, transmission, distribution and processing facilities and will require that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of the fair value can be made. If a reasonable estimate of the fair value cannot be made in the period the asset retirement obligation is incurred, the liability shall be recognized when a reasonable estimate of the fair value can be made. Retirement obligations associated with long-lived assets included within the scope of SFAS No. 143 are those for which a legal obligation exists under enacted laws, statutes, written or oral contracts, including obligations arising under the doctrine of promissory estoppel. The recognition of an asset retirement obligation is capitalized as part of the carrying amount of the long-lived asset. The net difference between the amounts determined under SFAS No. 143 and the Company’s previous method of accounting for such activities, net of expected regulatory recovery, will be recognized as a cumulative effect of a change in accounting principle, net of related taxes, in
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accordance with Accounting Principles Board Opinion No. 20, “Accounting Changes” (“APB 20”). Asset retirement obligations represent future liabilities and, as a result, accretion expense will be accrued on this liability until such time as the obligation is satisfied. Adoption of SFAS No. 143 is required for financial statements issued for fiscal years beginning after June 15, 2002. The Company has adopted this new standard effective January 1, 2003 and the adoption of this new standard did not have a material impact on its consolidated financial position or results of operations. As described below, the estimated asset retirement obligations recorded as a liability in Accumulated Depreciation will be reclassified as a regulatory liability in the first quarter of 2003.
SFAS No. 143 also requires that, if the conditions of SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation” are met, a regulatory asset or liability should be recorded to recognize differences between asset retirement costs recorded under SFAS No. 143 and legal or other asset retirement costs recognized for ratemaking purposes. Upon the application of SFAS No. 143, all rate regulated entities that are subject to the statement requirements will be required to quantify the amount of previously accumulated asset retirement costs for other than legal obligations and reclassify those differences as regulatory assets or liabilities.
The Company has approximately $109.3 million that has been accrued in depreciation rates and recorded as a liability in Accumulated Depreciation related to estimated asset retirement obligations. This balance will be reclassified as a regulatory liability in the first quarter of 2003. Also, beginning in the first quarter of 2003, changes in accounting procedures will direct accruals for removal costs to be credited directly to regulatory liabilities.
In August 2001, the FASB issued SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.” SFAS No. 144 requires that an impairment loss be recognized only if the carrying amount of a long-lived asset is not recoverable from its undiscounted cash flows and that the measurement of any impairment loss be the difference between the carrying amount and the fair value of the long-lived asset. SFAS No. 144 also requires companies to separately report discontinued operations and extends that reporting to a component of an entity that either has been disposed of (by sale, abandonment, or in a distribution to owners) or is classified as held for sale. Assets to be disposed of are reported at the lower of the carrying amount or fair value less costs to sell. Adoption of SFAS No. 144 is required for financial statements issued for fiscal years beginning after December 15, 2001. The Company adopted SFAS No. 144 effective January 1, 2002 and the adoption of this new standard did not have a material impact on its consolidated financial position or results of operations.
In July 2002, the FASB issued SFAS No. 146, “Accounting for Costs Associated with Exit or Disposal Activities.” SFAS No. 146 addresses financial accounting and reporting for costs associated with exit and disposal activities and supersedes EITF Issue No. 94-3, “Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring).” SFAS No. 146 requires recognition of a liability for a cost associated with an exit or disposal activity when the liability is incurred, as opposed to when the entity commits to an exit plan under EITF 94-3. SFAS No. 146 also establishes that the liability should initially be measured and recorded at fair value. Adoption of SFAS No. 146 is required for exit and disposal activities initiated after December 31, 2002. The Company has adopted this new standard effective January 1, 2003 and the adoption of this new
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standard did not have a material impact on its consolidated financial position or results of operations.
In October 2002, the EITF reached a consensus on certain issues covered in EITF No. 02-3, “Issues Related to Accounting for Contracts Involved in Energy Trading and Risk Management Activities.” One consensus of EITF No. 02-3 requires that all mark-to-market gains and losses, whether realized or unrealized, on financial derivative contracts as defined in SFAS No. 133 be shown net in the Income Statement for financial statements issued for periods beginning after December 15, 2002, with reclassification required for prior periods presented. The Company has adopted this consensus effective January 1, 2003 and the application of this consensus did not have a material impact on its consolidated financial position or results of operations as this consensus supports the Company’s historical presentation of financial derivative contracts.
In October 2002, the EITF reached a consensus to rescind EITF Issue No. 98-10, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities”, as amended effective for fiscal periods beginning after December 15, 2002. Effective October 25, 2002, all new contracts and physical inventories that would have been accounted for under EITF No. 98-10 are no longer marked to market through earnings unless the contracts meet the definition of a derivative under SFAS No. 133. Application of the consensus for energy contracts and inventory that existed on or before October 25, 2002 that remain in effect at the date this consensus is initially applied will be recognized as a cumulative effect of a change in accounting principle in accordance with APB 20. As a result, only energy contracts that meet the definition of a derivative in SFAS No. 133 will be carried at fair value. The Company has adopted this consensus effective January 1, 2003 resulting in an approximate $5.9 million after tax loss. The loss, which will be accounted for as a cumulative effect of a change in accounting principle, is primarily related to natural gas held in storage for trading purposes.
In December 2002, the FASB issued SFAS No. 148, “Accounting for Stock-Based Compensation - Transition and Disclosure - an amendment of FASB Statement No. 123.” SFAS No. 148 provides alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation which includes the prospective method, modified prospective method and retroactive restatement method. SFAS No. 148 also amends the disclosure requirements of SFAS No. 123, “Accounting for Stock-Based Compensation” to require prominent disclosures in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on reported results. Adoption of the annual disclosure and voluntary transition requirements of SFAS No. 148 is required for annual financial statements issued for fiscal years ending after December 15, 2002. Adoption of the interim disclosure requirements of SFAS No. 148 is required for interim periods beginning after December 15, 2002. Pursuant to the provisions of SFAS No. 123, the Company has elected to continue using the intrinsic value method of accounting for its stock-based employee compensation plans in accordance with APB Opinion No. 25, “Accounting for Stock Issued to Employees.” See Note 1 and Note 8 of Notes to Consolidated Financial Statements for a further discussion.
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Electric Competition; Regulation
As previously reported, the Electric Restructuring Act of 1997 (the “1997 Act”) was designed to provide retail customers in Oklahoma a choice of their electric supplier by July 1, 2002. Additional implementing legislation was to be adopted by the Oklahoma Legislature to address many specific issues associated with the 1997 Act and with deregulation. In May 2000, a bill addressing the specific issues of deregulation was passed in the Oklahoma State Senate and then was defeated in the Oklahoma House of Representatives. In May 2001, the Oklahoma Legislature passed Senate Bill 440 (“SB 440”), which postponed the scheduled start date for customer choice from July 1, 2002 until at least 2003. In addition to postponing the date for customer choice, SB 440 calls for a nine-member task force to further study the issues surrounding deregulation. The task force includes the Governor or his designee, the Oklahoma Attorney General, the OCC Chair and several legislative leaders, among others. In the current legislative session, Senate Bill 383 has been recently introduced to repeal the 1997 Act. It is unknown at this time whether the bill will be passed into law. The Company will continue to actively participate in the legislative process and expects to remain a competitive supplier of electricity. As a result of the failures of California’s attempt to deregulate its electricity markets, the Enron bankruptcy, and associated impacts on the industry, efforts to restructure the electricity market in Oklahoma appear at this time to be delayed indefinitely.
In April 1999, Arkansas passed a law (the “Restructuring Law”) calling for restructuring of the electric utility industry at the retail level. The Restructuring Law, like the 1997 Act, would have significantly affected OG&E’s future operations. OG&E’s electric service area includes parts of western Arkansas, including Fort Smith. The Restructuring Law initially targeted customer choice of electricity providers by January 1, 2002. In February 2001, the Restructuring Law was amended to delay the start date of customer choice of electric providers in Arkansas until October 1, 2003, with the APSC having discretion to further delay implementation to October 1, 2005. In March 2003, the Restructuring Law was repealed.
The OCC also has adopted rules that are designed to make the gas utility business in Oklahoma more competitive. These rules do not impact the electric industry. The rules are expected to offer increased opportunities to Enogex’s pipeline and related businesses.
Although efforts to increase electric competition at the state level have been stalled, there have been several initiatives implemented at the federal level to increase competition in the wholesale markets for electricity. The National Energy Policy Act of 1992 (“Energy Act”), among other things, promoted the development of independent power producers (“IPPs”). The Energy Act was followed by FERC Order 888 and Order 889, which facilitated third-party utilization of the transmission grid for sales of wholesale power. The Energy Act, Orders 888 and 889, and other FERC policies and initiatives have significantly increased competition in the wholesale power market. Utilities, including OG&E, have increased their own in-house wholesale marketing efforts and the number of entities with whom they historically traded. Moreover, power marketers are an increasingly important presence in the industry. These entities typically arbitrage wholesale price differentials by buying power produced by others in one market and selling it in another. IPP's also are becoming a more significant sector of the
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electric utility industry. In both Oklahoma and Arkansas, significant additions of new power plants have been announced, almost all of it from IPPs.
Notwithstanding these developments in the wholesale power market, the FERC recognized that impediments remained to the achievement of fully competitive wholesale markets including: (i) engineering and economic inefficiencies inherent in the current operation and expansion of the transmission grid; and (ii) continuing opportunities for transmission owners (primarily electric utilities) to discriminate in the operation of their transmission facilities in favor of their own or affiliated power marketing activities. In the past, the FERC only encouraged utilities to join and place their transmission systems under the operational control of independent system operators (“ISOs”). On December 20, 1999, the FERC issued Order 2000, its final rule on regional transmission organizations (“RTOs”). Order 2000 is intended to have the effect of turning the nation’s transmission facilities into independently operated “common carriers” that offer comparable service to all would-be-users. Although adopting a voluntary approach towards RTO formation, the FERC stressed that Order 2000 does not preclude it from requiring RTO participation. Order 2000 set out a timetable for every jurisdictional utility (including OG&E) to either join in an RTO filing, or, alternatively, to submit a filing describing its efforts to join an RTO, the reasons for not participating in an RTO proposal and any obstacles to participation, and its plans for further work toward participation.
OG&E is a member of the SPP, the regional reliability organization for Oklahoma, Arkansas, Kansas, Louisiana, Missouri and part of Texas. OG&E participated with the SPP in the development of regional transmission tariffs and executed an Agency Agreement with the SPP to facilitate interstate transmission operations within this region. In October 2000, the SPP filed its application with the FERC to become an RTO. In July 2001, the FERC determined that the SPP did not have adequate scope and configuration to be granted RTO status. The SPP was encouraged to explore the possibility of joining an RTO to be formed in the southeastern region of the United States and to explore the feasibility of becoming a part of the recently approved RTO being established by the Midwest Independent System Operator (“MISO”). The SPP and MISO entered negotiations during the late summer of 2001 to combine the SPP and MISO and to form a new regional transmission entity that would combine the control areas of MISO and SPP, capture certain synergies that would be available from the combined organization, and allow member companies in the SPP certain options with respect to membership in the combined organization. The officers of MISO and of SPP, under the direction of their respective Boards of Directors developed documentation to effect the merger of SPP and MISO into a new organization, and the transaction was approved by the SPP Board of Directors. On February 7, 2003, OG&E executed a Conditional MISO Membership Application to join the resulting company as a Transmission Owner, subject to certain conditions being either met or waived. On the same date, OG&E executed the Conditional Withdrawal Agreement with the SPP. The Conditional Withdrawal Agreement would have had the effect of terminating OG&E’s membership in the SPP, except for regional reliability purposes, at such time as the MISO - SPP combination received all necessary regulatory approvals, the required number of SPP member companies executed the Conditional Membership Application to join MISO, and the SPP and MISO merger transaction were closed. OG&E filed with the APSC a cost/benefit analysis to demonstrate that OG&E's joining the MISO/SPP combination would have been in the public interest.
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One of the conditions to the SPP and MISO merger transaction was that two-thirds of the load served by transmission owners within the SPP were to execute the Conditional Membership Application and to execute the Conditional Withdrawal Agreement with the SPP. During March 2003 it became apparent to the SPP Board of Directors that the Conditional Membership Applications would not be executed by transmission owners representing two-thirds of the load in the SPP. At its meeting on March 12, 2003, the SPP Board of Directors directed the President of SPP to open discussion with the MISO Board of Directors concerning termination of the proposed MISO/SPP combination. On March 20, 2003, MISO and SPP announced that their respective Boards had voted to terminate their merger because the conditions required to close the transaction would not be met in the foreseeable future. OG&E has remained a member of the SPP while the MISO/SPP combination was pending, and OG&E will continue to be a member of the SPP as the SPP, other SPP members and OG&E evaluate the next steps necessary for compliance with the FERC's Order 2000. In the meantime, the SPP will continue to offer open access transmission service in the SPP region under the SPP Open Access Transmission Tariff. Termination of the proposed MISO/SPP combination and OG&E's continued membership in the SPP are not expected to significantly impact the Company's consolidated financial results.
In October 2001, the FERC issued a Notice of Proposed Rulemaking proposing to adopt new standards of conduct rules applicable to all jurisdictional electric and natural gas transmission providers. The proposed rules would replace the current rules governing the electric transmission and wholesale electric functions of electric utilities and the rules governing natural gas transportation and wholesale gas supply functions. The proposed rules would expand the definition of “affiliate” and further limit communications between transmission functions and supply functions, and could materially increase operating costs of market participants, including OG&E and Enogex. In April 2002, the FERC staff issued a reaction paper, generally rejecting the comments of parties opposed to the proposed rules. Final rules have been delayed while the FERC pursues development of its Standard Market Design Rulemaking.
In July 2002, the FERC issued a Notice of Proposed Rulemaking on Standard Market Design Rulemaking for regulated utilities. If implemented as proposed, the rulemaking will substantially change how wholesale markets operate throughout the United States. The proposed rulemaking expands the FERC’s intent to unbundle transmission operations from integrated utilities and ensure robust competition in wholesale markets. The rule contemplates that all wholesale and retail customers will be on a single network transmission service tariff. The rule also contemplates the implementation of a bid-based system for buying and selling energy in wholesale markets. RTOs or Independent Transmission Providers will administer the market. RTOs will also be responsible for regional plans that identify opportunities to construct new transmission, generation or demand side programs to reduce transmission constraints and meet regional energy requirements. Finally, the rule envisions the development of Regional Market Monitors responsible for ensuring the individual participants do not exercise unlawful market power. The FERC recently extended the comment period, but anticipates that the final rules will be in place in 2003 and the contemplated market changes will take place in 2003 and 2004.
On August 1, 2002, the FERC issued a Notice of Proposed Rulemaking proposing to adopt new rules governing corporate “money pools,” which include jurisdictional public utility or pipeline subsidiaries of nonregulated parent companies. The proposed rules would require
86
documentation of transactions within such money pools, a proprietary capital account of the jurisdictional utility of 30 percent, and would require the nonregulated parent company to have an investment grade rating. Several parties have filed comments on the proposed rule. No final rule has been issued.
OG&E, 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 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 credits that would otherwise reduce expense can be deferred as regulatory liabilities, based on the expected flowback to customers in future rates. Management’s expected recovery of deferred costs and flowback of deferred credits generally results from specific decisions by regulators granting such ratemaking treatment.
OG&E initially records costs: (i) that are probable of future recovery as a deferred charge until such time as the cost is approved by a regulatory authority, then the cost is reclassified as a regulatory asset; and (ii) that are probable of future liability as a deferred credit until such time as the amount is approved by a regulatory authority, then the amount is reclassified as a regulatory liability.
As discussed previously, legislation was enacted in Oklahoma and Arkansas that was to restructure the electric utility industry in those states. The Arkansas legislation was repealed and 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 would deregulate OG&E’s electric generation assets and cause the Company to discontinue the use of SFAS No. 71, with respect to the related regulatory assets. This may result in either full recovery of generation-related regulatory assets (net of related regulatory liabilities) or a non-cash, pre-tax write-off as an extraordinary charge of up to approximately $28.7 million, depending on the transition mechanisms developed by the legislature for the recovery of all or a portion of these net regulatory assets.
The previously enacted Oklahoma and Arkansas legislation would not affect OG&E’s electric transmission and distribution assets and the Company believes that the continued use of SFAS No. 71 with respect to the related regulatory assets is appropriate. However, if utility regulators in Oklahoma and Arkansas were to adopt regulatory methodologies in the future that are not based on the cost-of-service, the continued use of SFAS No. 71 with respect to the regulatory assets related to the electric transmission and distribution assets may no longer be appropriate. The Company has approximately $35.2 million of regulatory assets related to the transmission and distribution assets. 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.
Commitments and Contingencies
The Company through its subsidiaries is defending various claims and legal actions, including environmental actions, which are common to its operations. The Company’s subsidiaries, primarily OG&E, also could be impacted by various proposed environmental
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regulations that if adopted, could result in significant increases in capital and operating expenditures.
Besides the various existing contingencies herein described, and those described in Note 15 of Notes to Consolidated Financial Statements, the Company’s ability to fund its future operational needs and to finance its construction program could be impacted by numerous factors beyond its control, such as general economic conditions, abnormal weather, load growth, acquisitions of other businesses, actions by rating agencies, inflation, changes in environmental laws or regulations, rate increases or decreases allowed by regulatory agencies and market entry of competing electric power generators.
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Item 7A. Quantitative and Qualitative Disclosures About Market Risk.
Risk Management
The risk management process established by the Company is designed to measure both quantitative and qualitative risks in its businesses. A corporate risk management department, under the direction of a corporate risk management committee, has been established to review these risks on a regular basis. The Company is exposed to market risk in its normal course of business, including changes in certain commodity prices and interest rates. The Company engages in price risk management for both trading and non-trading purposes.
To manage the volatility relating to these exposures, the Company enters into various derivative transactions pursuant to the Company’s policies on hedging practices. Derivative positions are monitored using techniques such as mark-to-market valuation, value-at-risk and sensitivity analysis.
Interest Rate Risk
The Company’s exposure to changes in interest rates relates primarily to long-term debt obligations 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 may utilize interest rate derivatives to alter interest rate exposure in an attempt to reduce interest rate 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.
During 2001, the Company entered into two separate interest rate swap agreements: (i) OG&E entered into an interest rate swap agreement, effective March 30, 2001, to convert $110.0 million of 7.30 percent fixed rate debt due October 15, 2025, to a variable rate based on the three month LIBOR and (ii) Enogex entered into an interest rate swap agreement, effective July 15, 2001, to convert $200.0 million of 8.125 percent fixed rate debt due January 15, 2010, to a variable rate based on the three month LIBOR. On March 1, 2002, Enogex monetized its interest rate swap agreement and received cash of approximately $4.2 million, which is being amortized over the life of the related debt.
On March 4, 2002, Enogex entered into a new interest rate swap agreement to convert $200.0 million of 8.125 percent fixed rate debt due January 15, 2010, to a variable rate based on the three month LIBOR. On July 2, 2002, Enogex monetized its interest rate swap agreement and received cash of approximately $6.6 million, of which approximately $3.2 million was recorded against interest receivable and the remaining amount of approximately $3.4 million is being amortized over the life of the related debt.
On August 7, and on October 24, 2002, Enogex entered into new interest rate swap agreements to convert $100.0 million of 8.125 percent fixed rate debt due January 15, 2010, to a variable rate based on the six month LIBOR.
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These interest rate swaps qualified as fair value hedges under SFAS No. 133 and meet all of the requirements for a determination that there was no ineffective portion as allowed by the shortcut method under SFAS No. 133. The objective of these interest rate swaps was to achieve a lower cost of debt and to raise the percentage of total corporate long-term floating rate debt to reflect a level more in line with industry standards.
On April 6, 2001, the Company entered into a one-year interest rate swap agreement to lock in a fixed rate of 4.41 percent, effective April 10, 2001, on $140.0 million of variable rate short-term debt. This interest rate swap initially qualified for hedge accounting treatment as a cash flow hedge under SFAS No. 133. However, due to unexpected changes in the level of commercial paper issued during the third quarter of 2001, hedge accounting treatment under SFAS No. 133 was discontinued as of July 1, 2001, and all subsequent changes in the fair value of the swap were recorded as Interest Expense. The objective of this interest rate swap was to achieve a lower cost of debt and to reduce exposure to short-term interest rate volatility associated with the Company’s commercial paper program.
The fair value of the Company’s long-term debt is based on quoted market prices and management’s estimate of current rates available for similar issues with similar maturities. The valuation of the Company’s interest rate swaps was determined primarily based on quoted market prices. The following table shows the Company’s long-term debt maturities and the weighted-average interest rates by maturity date.
===========================================================================================================
2002
Year-end
Fair
(Dollars in millions) 2003 2004 2005 2006 2007 Thereafter Total Value
- -----------------------------------------------------------------------------------------------------------
Fixed rate debt
Principal amount...... $ 20.8 $ 52.8 $ 146.1 $ 1.9 $ 4.9 $ 828.3 $ 1,054.8 $ 1,224.9
Weighted-average
interest rate....... 7.70% 7.22% 7.07% 7.15% 7.83% 7.43% 7.40% ---
Variable rate debt
Principal amount (A).. --- --- --- --- --- $ 468.1 $ 468.1 $ 468.1
Weighted-average
interest rate....... --- --- --- --- --- 3.99% 3.99% ---
===========================================================================================================
(A) Amount includes an increase to the fair value of long-term debt for approximately $15.9 million due
to the Company's interest rate swaps.
Commodity Price Risk
The market risks inherent in the Company’s market risk sensitive instruments, positions and anticipated commodity transactions are the potential losses in value arising from adverse changes in the Company’s commodity prices.
The trading activities are conducted throughout the year subject to a daily, monthly and annual trading stop loss limit of $4.0 million. The daily loss exposure from trading activities is measured primarily using value at risk as well as other quantitative risk measurement techniques
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and is limited to $1.5 million. These limits are designed to mitigate the possibility of trading activities having a material adverse effect on Enogex’s operating income.
The prices of natural gas, natural gas liquids, natural gas liquids processing spreads and electricity are subject to fluctuations resulting from changes in supply and demand. Processing spreads are the difference between the values of natural gas liquids compared to the value of an equivalent amount of MMBtu in natural gas form. To partially reduce commodity price risk incurred in the Company's normal course of business caused by these market fluctuations, the Company may hedge, through the utilization of derivatives, a portion of the Company's supply and related purchase and sale contracts, as well as any anticipated transactions (purchases and sales). See "Price Risk Management Assets and Liabilities" in Note 1 of Notes to Consolidated Financial Statements. Because the commodities covered by these derivatives are substantially the same commodities that the Company buys and sells in the physical market, no special studies other than monitoring the degree of correlation between the derivative and cash markets are deemed necessary.
A sensitivity analysis has been prepared to estimate the commodity price exposure to the market risk of the Company's natural gas, natural gas liquids and electricity commodity positions. The Company's daily net commodity position consists of natural gas inventories, commodity purchase and sales contracts, financial and commodity derivative instruments and anticipated natural gas processing spreads and fuel recoveries. The fair value of such position is a summation of the fair values calculated for each commodity by valuing each net position at quoted market prices. Market risk is estimated as the potential loss in fair value resulting from a hypothetical 10 percent adverse change in such prices over the next 12 months. The results of this analysis, which may differ from actual results, are as follows for 2002:
(In millions) Trading Non-Trading ================================================================================= Commodity market risk, net..................... $ 0.5 $ 3.4 =================================================================================
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Item 8. Financial Statements and Supplementary Data.
OGE ENERGY CORP.
CONSOLIDATED BALANCE SHEETS
December 31 (In millions) 2002 2001
=======================================================================================
ASSETS
CURRENT ASSETS
Cash and cash equivalents................................. $ 29.5 $ 32.5
Accounts receivable, net.................................. 304.6 214.9
Accrued unbilled revenues................................. 28.2 35.6
Fuel inventories.......................................... 99.7 77.2
Materials and supplies, at average cost................... 42.6 38.5
Price risk management..................................... 17.1 21.2
Pipeline imbalance........................................ 34.3 14.5
Accumulated deferred tax assets........................... 10.9 10.0
Fuel clause under recoveries.............................. 14.7 ---
Recoverable take or pay gas charges....................... --- 30.8
Other..................................................... 10.6 8.9
Current assets of discontinued operations................. 4.7 9.5
- ------------------------------------------------------------ --------- ---------
Total current assets.................................... 596.9 493.6
- ------------------------------------------------------------ --------- ---------
OTHER PROPERTY AND INVESTMENTS, at cost..................... 27.2 40.4
- ------------------------------------------------------------ --------- ---------
PROPERTY, PLANT AND EQUIPMENT
In service................................................ 5,500.2 5,361.4
Construction work in progress............................. 44.8 45.7
- ------------------------------------------------------------ --------- ---------
Total property, plant and equipment..................... 5,545.0 5,407.1
Less accumulated depreciation......................... 2,340.7 2,240.7
- ------------------------------------------------------------ --------- ---------
Net property, plant and equipment....................... 3,204.3 3,166.4
In service of discontinued operations..................... 54.2 145.3
Less accumulated depreciation......................... 11.4 50.5
- ------------------------------------------------------------ --------- ---------
Net property, plant and equipment of discontinued
operations............................................ 42.8 94.8
- ------------------------------------------------------------ --------- ---------
Net property, plant and equipment....................... 3,247.1 3,261.2
- ------------------------------------------------------------ --------- ---------
DEFERRED CHARGES AND OTHER ASSETS
Recoverable take or pay gas charges....................... 32.5 8.5
Income taxes recoverable from customers, net.............. 34.8 37.6
Intangible asset - unamortized prior service cost......... 42.7 47.3
Prepaid benefit obligation................................ 44.9 21.3
Price risk management..................................... 20.1 13.4
Other..................................................... 80.8 73.2
Deferred charges and other assets of discontinued
operations.............................................. 0.2 0.1
- ------------------------------------------------------------ --------- ---------
Total deferred charges and other assets................. 256.0 201.4
- ------------------------------------------------------------ --------- ---------
TOTAL ASSETS................................................ $4,127.2 $3,996.6
============================================================ ========= =========
The accompanying Notes to Consolidated Financial Statements are an integral part hereof.
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OGE ENERGY CORP.
CONSOLIDATED BALANCE SHEETS (Continued)
December 31 (In millions) 2002 2001
=======================================================================================
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Short-term debt............................................ $ 275.0 $ 115.0
Accounts payable .......................................... 254.1 149.2
Dividends payable.......................................... 26.1 25.9
Customers' deposits........................................ 33.0 28.4
Accrued taxes.............................................. 23.6 28.4
Accrued interest........................................... 35.7 40.3
Tax collections payable.................................... 6.7 4.7
Accrued vacation........................................... 16.9 16.9
Long-term debt due within one year......................... 21.0 115.0
Provision for payments of take or pay gas.................. --- 30.8
Fuel clause over recoveries................................ --- 23.4
Price risk management...................................... 13.9 7.9
Pipeline imbalance......................................... 9.4 5.6
Other...................................................... 19.4 14.0
Current liabilities of discontinued operations............. 2.0 0.5
- ------------------------------------------------------------- --------- ---------
Total current liabilities................................ 736.8 606.0
- ------------------------------------------------------------- --------- ---------
LONG-TERM DEBT............................................... 1,501.9 1,526.3
- ------------------------------------------------------------- --------- ---------
DEFERRED CREDITS AND OTHER LIABILITIES
Capital lease obligation - non-current..................... --- 8.9
Accrued pension and benefit obligations.................... 184.2 100.1
Accumulated deferred income taxes.......................... 627.0 634.9
Accumulated deferred investment tax credits................ 47.1 52.3
Price risk management...................................... 0.6 3.8
Provision for payments of take or pay gas.................. 32.5 8.5
Other...................................................... 4.1 5.1
Deferred credits and other liabilities of discontinued
operations............................................... 9.1 10.1
- ------------------------------------------------------------ --------- ---------
Total deferred credits and other liabilities............. 904.6 823.7
- ------------------------------------------------------------- --------- ---------
STOCKHOLDERS' EQUITY
Common stockholders' equity................................ 453.5 444.7
Retained earnings.......................................... 604.7 617.9
Accumulated other comprehensive loss, net of tax........... (74.3) (22.0)
- ------------------------------------------------------------- --------- ---------
Total stockholders' equity............................... 983.9 1,040.6
- ------------------------------------------------------------- --------- ---------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY................... $4,127.2 $3,996.6
============================================================= ========= =========
The accompanying Notes to Consolidated Financial Statements are an integral part hereof.
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OGE ENERGY CORP.
CONSOLIDATED STATEMENTS OF CAPITALIZATION
December 31 (In millions) 2002 2001
=======================================================================================
STOCKHOLDERS' EQUITY
Common stock, par value $0.01 per share; authorized 125.0
shares; and outstanding 78.5 and 78.0 shares, respectively... $ 0.8 $ 0.8
Premium on capital stock....................................... 452.7 443.9
Retained earnings.............................................. 604.7 617.9
Accumulated other comprehensive loss, net of tax............... (74.3) (22.0)
- ----------------------------------------------------------------- --------- ---------
Total stockholders' equity................................. 983.9 1,040.6
- ----------------------------------------------------------------- --------- ---------
LONG-TERM DEBT
SERIES DATE DUE
------ --------
Senior Notes-OG&E
7.125 % Senior Notes, Series Due October 15, 2005.......... 110.0 110.0
6.500 % Senior Notes, Series Due July 15, 2017............. 125.0 125.0
Variable % Senior Notes, Series Due October 15, 2025.......... 117.5 107.6
6.650 % Senior Notes, Series Due July 15, 2027............. 125.0 125.0
6.500 % Senior Notes, Series Due April 15, 2028............ 100.0 100.0
Other bonds-OG&E
Variable % Garfield Industrial Authority, January 1, 2025..... 47.0 47.0
Variable % Muskogee Industrial Authority, January 1, 2025..... 32.4 32.4
Variable % Muskogee Industrial Authority, June 1, 2027........ 56.0 56.0
Unamortized premium and discount, net.......................... (2.4) (2.6)
Enogex notes (Note 11)......................................... 612.4 740.9
Trust Originated Preferred Securities (Note 10)................ 200.0 200.0
- ----------------------------------------------------------------- --------- ---------
Total long-term debt....................................... 1,522.9 1,641.3
Less long-term debt due within one year.................. 21.0 115.0
- ----------------------------------------------------------------- --------- ---------
Total long-term debt (excluding long-term
debt due within one year)................................ 1,501.9 1,526.3
- ----------------------------------------------------------------- --------- ---------
Total Capitalization............................................. $2,485.8 $2,566.9
================================================================= ========= =========
The accompanying Notes to Consolidated Financial Statements are an integral part hereof.
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OGE ENERGY CORP.
CONSOLIDATED STATEMENTS OF INCOME
Year ended December 31 (In millions, except per share data) 2002 2001 2000
=================================================================================================
OPERATING REVENUES
Electric Utility operating revenues....................... $1,388.0 $1,456.8 $1,453.6
Natural Gas Pipeline operating revenues................... 1,635.9 1,607.6 1,730.8
- ------------------------------------------------------------ --------- --------- ---------
Total Operating revenues................................ 3,023.9 3,064.4 3,184.4
COST OF GOODS SOLD
Electric Utility cost of goods sold....................... 662.2 730.2 714.9
Natural Gas Pipeline cost of goods sold................... 1,458.1 1,455.4 1,560.4
- ------------------------------------------------------------ --------- --------- ---------
Total cost of goods sold................................ 2,120.3 2,185.6 2,275.3
- ------------------------------------------------------------ --------- --------- ---------
Gross margin on revenues.................................... 903.6 878.8 909.1
Other operation and maintenance........................... 370.0 370.3 345.1
Depreciation.............................................. 182.5 172.9 167.1
Impairment of assets...................................... 50.1 --- ---
Taxes other than income................................... 65.3 64.7 62.3
- ------------------------------------------------------------ --------- --------- ----------
OPERATING INCOME............................................ 235.7 270.9 334.6
- ------------------------------------------------------------ --------- --------- ---------
OTHER INCOME (EXPENSE)
Other income.............................................. 3.7 3.1 4.2
Other expense............................................. (4.7) (4.2) (3.6)
- ------------------------------------------------------------ --------- --------- ---------
Net other income (expense)................................ (1.0) (1.1) 0.6
- ------------------------------------------------------------ --------- --------- ---------
INTEREST INCOME (EXPENSE)
Interest income........................................... 1.7 4.2 3.3
Interest on long-term debt................................ (86.2) (98.2) (101.4)
Interest on trust preferred securities.................... (17.3) (17.3) (17.3)
Allowance for borrowed funds used during construction..... 0.9 0.7 2.2
Interest on short-term debt and other interest charges.... (8.2) (12.4) (16.2)
- ------------------------------------------------------------ --------- --------- ---------
Net interest expense.................................... (109.1) (123.0) (129.4)
- ------------------------------------------------------------ --------- --------- ---------
INCOME FROM CONTINUING OPERATIONS BEFORE TAXES.............. 125.6 146.8 205.8
INCOME TAX EXPENSE.......................................... 44.6 52.9 72.0
- ------------------------------------------------------------ --------- --------- ---------
INCOME FROM CONTINUING OPERATIONS........................... 81.0 93.9 133.8
DISCONTINUED OPERATIONS (NOTE 2)
Income from discontinued operations....................... 8.4 6.4 17.6
Income tax expense (benefit).............................. (1.4) (0.3) 4.4
- ------------------------------------------------------------ --------- --------- ---------
Income from discontinued operations....................... 9.8 6.7 13.2
- ------------------------------------------------------------ --------- --------- ---------
NET INCOME.................................................. $ 90.8 $ 100.6 $ 147.0
============================================================ ========= ========= =========
BASIC AVERAGE COMMON SHARES OUTSTANDING..................... 78.1 77.9 77.9
DILUTED AVERAGE COMMON SHARES OUTSTANDING................... 78.2 77.9 77.9
BASIC EARNINGS PER AVERAGE COMMON SHARE
Income from continuing operations......................... $ 1.04 $ 1.20 $ 1.72
Income from discontinued operations, net of tax........... 0.12 0.09 0.17
============================================================ ========= ========= =========
NET INCOME.................................................. $ 1.16 $ 1.29 $ 1.89
============================================================ ========= ========= =========
DILUTED EARNINGS PER AVERAGE COMMON SHARE
Income from continuing operations......................... $ 1.04 $ 1.20 $ 1.72
Income from discontinued operations, net of tax........... 0.12 0.09 0.17
- ------------------------------------------------------------ --------- --------- ---------
NET INCOME.................................................. $ 1.16 $ 1.29 $ 1.89
============================================================ ========= ========= =========
DIVIDENDS DECLARED PER SHARE................................ $ 1.33 $ 1.33 $ 1.33
============================================================ ========= ========= =========
The accompanying Notes to Consolidated Financial Statements are an integral part hereof.
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OGE ENERGY CORP.
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
Year ended December 31 (In millions) 2002 2001 2000
====================================================================================================
BALANCE AT BEGINNING OF PERIOD................................ $ 617.9 $ 621.0 $ 577.5
ADD: Net income............................................... 90.8 100.6 147.0
- -------------------------------------------------------------- --------- --------- ---------
Total.................................................. 708.7 721.6 724.5
- -------------------------------------------------------------- --------- --------- ---------
DEDUCT: Dividends declared on common stock.................... 104.0 103.7 103.5
- -------------------------------------------------------------- --------- --------- ---------
BALANCE AT END OF PERIOD...................................... $ 604.7 $ 617.9 $ 621.0
============================================================== ========= ========= =========
OGE ENERGY CORP.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Year ended December 31 (In millions) 2002 2001 2000
====================================================================================================
Net income.................................................... $ 90.8 $ 100.6 $ 147.0
Other comprehensive income (loss), net of tax:
Minimum pension liability adjustment [($85.5) and ($35.8)
pre-tax, respectively]..................................... (52.4) (21.9) ---
Transition adjustment [($26.9) pre-tax]..................... --- (16.5) ---
Gain on qualifying cash flow hedge (total gain less
ineffective portion) [$21.4 pre-tax]...................... --- 13.1 ---
Reclassification adjustments - transition adjustment
[$26.9 pre-tax]........................................... --- 16.5 ---
Reclassification adjustments - contract settlements
[($21.4) pre-tax]......................................... --- (13.1) ---
Deferred hedging losses [$0.2 and ($0.2) pre-tax,
respectively]............................................. 0.1 (0.1) ---
- -------------------------------------------------------------- --------- --------- ---------
Total other comprehensive loss, net of tax............. (52.3) (22.0) ---
- -------------------------------------------------------------- --------- --------- ---------
Total comprehensive income............................. $ 38.5 $ 78.6 $ 147.0
============================================================== ========= ========= =========
The accompanying Notes to Consolidated Financial Statements are an integral part hereof.
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OGE ENERGY CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year ended December 31 (In millions) 2002 2001 2000
=====================================================================================================
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income................................................. $ 90.8 $ 100.6 $ 147.0
Adjustments to reconcile net income to net cash provided
from operating activities
Income from discontinued operations...................... (9.8) (6.7) (13.2)
Depreciation............................................. 182.5 172.9 167.1
Impairment of assets..................................... 50.1 --- ---
Deferred income taxes and investment tax credits, net.... 33.1 27.1 45.4
Gain on sale of assets................................... (1.0) (0.2) (2.5)
Ineffectiveness of interest rate swap.................... 0.2 1.3 ---
Price risk management.................................... 21.9 (34.7) 15.9
Other assets............................................. (65.2) (35.9) (8.8)
Other liabilities........................................ 27.4 8.2 9.8
Change in certain current assets and liabilities
Accounts receivable, net................................ (90.4) 241.4 (192.7)
Accrued unbilled revenues............................... 7.4 13.4 (8.8)
Fuel, materials and supplies inventories................ (26.5) 125.8 (85.5)
Pipeline imbalance asset................................ (19.8) 51.5 (55.7)
Fuel clause under recoveries............................ (14.7) 35.4 (35.4)
Other current assets.................................... (2.7) (1.4) 0.6
Accounts payable........................................ 104.9 (163.5) 164.0
Customers' deposits..................................... 4.6 5.8 0.5
Accrued taxes........................................... (4.8) (4.2) (8.2)
Accrued interest........................................ (4.2) (0.4) 12.5
Fuel clause over recoveries............................. (23.4) 23.4 (1.6)
Pipeline imbalance liability............................ 3.8 (62.5) 63.2
Other current liabilities............................... 3.5 (6.1) (0.1)
- ------------------------------------------------------------ ----------- ----------- -----------
Net Cash Provided from Operating Activities........... 267.7 491.2 213.5
- ------------------------------------------------------------ ----------- ----------- -----------
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures....................................... (234.5) (211.7) (167.2)
Proceeds from sale of assets............................... 1.7 0.8 8.2
Other investing activities................................. (0.5) 0.4 1.6
- ------------------------------------------------------------ ----------- ----------- -----------
Net Cash Used in Investing Activities................. (233.3) (210.5) (157.4)
- ------------------------------------------------------------ ----------- ----------- -----------
CASH FLOWS FROM FINANCING ACTIVITIES
Retirement of long-term debt............................... (140.0) (11.2) (58.5)
Proceeds from long-term debt............................... --- --- 400.0
Increase (decrease) in short-term debt, net................ 126.2 (169.5) (304.6)
Premium on issuance of common stock........................ 8.8 1.4 1.5
Distribution from minority interest........................ --- 1.4 3.3
Capital lease obligation................................... --- (0.5) (0.3)
Dividends paid on common stock............................. (99.5) (103.6) (103.6)
- ------------------------------------------------------------ ----------- ----------- -----------
Net Cash Used in Financing Activities................. (104.5) (282.0) (62.2)
- ------------------------------------------------------------ ----------- ----------- -----------
DISCONTINUED OPERATIONS
Net cash provided from operating activities................ 17.2 46.0 1.4
Net cash provided from (used in) investing activities...... 51.3 (12.7) 2.4
Net cash used in financing activities...................... (1.4) --- (0.7)
- ------------------------------------------------------------ ----------- ----------- -----------
Net Cash Provided from Discontinued Operations........ 67.1 33.3 3.1
- ------------------------------------------------------------ ----------- ----------- -----------
NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS........ (3.0) 32.0 (3.0)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD............ 32.5 0.5 3.5
- ------------------------------------------------------------ ----------- ----------- -----------
CASH AND CASH EQUIVALENTS AT END OF PERIOD.................. $ 29.5 $ 32.5 $ 0.5
============================================================ =========== =========== ===========
The accompanying Notes to Consolidated Financial Statements are an integral part hereof.
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OGE ENERGY CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Summary of Significant Accounting Policies
Organization
OGE Energy Corp. (collectively with its subsidiaries, the “Company”) is an energy and energy services provider offering physical delivery and management of both electricity and natural gas in the south central United States. The Company conducts these activities through two business segments, the Electric Utility and the Natural Gas Pipeline segments. All significant intercompany transactions have been eliminated in consolidation.
The Electric Utility segment generates, transmits, distributes and sells electric energy in Oklahoma and western Arkansas. Its operations are conducted through Oklahoma Gas and Electric Company (“OG&E”) and are subject to regulation by the Oklahoma Corporation Commission (“OCC”), the Arkansas Public Service Commission (“APSC”) and the Federal Energy Regulatory Commission (“FERC”). OG&E sold its retail gas business in 1928 and is no longer engaged in the gas distribution business. OG&E is the largest electric utility in Oklahoma and its franchised service territory includes the Fort Smith, Arkansas area.
The Natural Gas Pipeline segment is conducted through Enogex Inc. and its subsidiaries (“Enogex”) and consists of three related businesses: (i) the transportation and storage of natural gas, (ii) the gathering and processing of natural gas, and (iii) the marketing and trading of natural gas (collectively, the “pipeline businesses”). The vast majority of Enogex’s natural gas gathering, processing, transportation and storage assets are located in the major gas producing basins of Oklahoma. Through a 75 percent interest in the NOARK Pipeline System Limited Partnership, Enogex also owns a controlling interest in and operates the Ozark Gas Transmission System (“Ozark”), a FERC regulated interstate pipeline that extends from southeast Oklahoma through Arkansas to southeast Missouri. Enogex’s marketing and trading activities include corporate price risk management and other optimization services. Enogex was previously engaged in the exploration and production of natural gas, however, this portion of Enogex’s business, along with interests in certain gas gathering and processing assets in Texas were sold in 2002 and 2003 and are reported in the Consolidated Financial Statements as discontinued operations.
The Company allocates operating costs to its affiliates based on several factors. Operating costs directly related to specific affiliates are assigned to those affiliates. Where more than one affiliate benefits from certain expenditures, the costs are shared between those affiliates receiving the benefits. Operating costs incurred for the benefit of all affiliates are allocated among the affiliates, based primarily upon head-count, occupancy, usage or the "Distragas" method. The Distragas method is a three-factor formula that uses an equal weighting of payroll, operating income and assets. The Company believes this method provides a reasonable basis for allocating common expenses.
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Accounting Records
The accounting records of OG&E are maintained in accordance with the Uniform System of Accounts prescribed by the FERC and adopted by the OCC and the APSC. Additionally, OG&E, as a regulated utility, is subject to 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 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 credits that would otherwise reduce expense can be deferred as regulatory liabilities, based on the expected flowback to customers in future rates. Management’s expected recovery of deferred costs and flowback of deferred credits generally results from specific decisions by regulators granting such ratemaking treatment. At December 31, 2002 and 2001, net regulatory assets of approximately $63.9 million and $62.5 million are being amortized and reflected in rates charged to customers over periods of up to 20 years.
OG&E initially records costs: (i) that are probable of future recovery as a deferred charge until such time as the cost is approved by a regulatory authority, then the cost is reclassified as a regulatory asset; and (ii) that are probable of future liability as a deferred credit until such time as the amount is approved by a regulatory authority, then the amount is reclassified as a regulatory liability.
The following table is a summary of the net regulatory assets at December 31:
(In millions) 2002 2001
============================================================================
Regulatory Assets
Income taxes recoverable from customers, net.... $ 34.8 $ 37.6
Unamortized loss on reacquired debt............. 23.3 24.5
January 2002 ice storm.......................... 5.4 ---
Miscellaneous................................... 0.4 0.4
- ----------------------------------------------------------------------------
Net Regulatory Assets......................... $ 63.9 $ 62.5
============================================================================
Income taxes recoverable from customers represent income tax benefits previously used to reduce OG&E’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 regulatory assets and liabilities are netted on the Company’s Consolidated Balance Sheets in the line item, “Income Taxes Recoverable from Customers, Net.”
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.
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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.
Accounting Pronouncements
Effective January 1, 2001, the Company adopted SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended. SFAS No. 133 requires the Company to record all derivatives on the Balance Sheet at fair value. Changes in the fair value of derivatives that are not designated as hedges, as well as the ineffective portion of hedge derivatives, must be recognized as a derivative fair value gain or loss in the accompanying Consolidated Statements of Income. The value of effective fair value hedges are recorded in Price Risk Management assets and liabilities in the accompanying Consolidated Balance Sheets, with the corresponding offset recorded against the value in the hedged asset or liability. The value of effective cash flow hedges are recorded in Price Risk Management assets and liabilities with the corresponding component in Accumulated Other Comprehensive Income, which is later reclassified to earnings when the related hedged transaction is reflected in income. Physical delivery contracts that are deemed to be normal purchases or normal sales and have been designated as such are not accounted for as derivatives. Physical delivery contracts that are not deemed to be normal purchases or normal sales are accounted for as derivatives.
In June 2001, the FASB issued SFAS No. 143, “Accounting for Asset Retirement Obligations.” SFAS No. 143 applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or the normal operation of a long-lived asset. SFAS No. 143 will affect the Company’s accrued plant removal costs for generation, transmission, distribution and processing facilities and will require that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of the fair value can be made. If a reasonable estimate of the fair value cannot be made in the period the asset retirement obligation is incurred, the liability shall be recognized when a reasonable estimate of the fair value can be made. Retirement obligations associated with long-lived assets included within the scope of SFAS No. 143 are those for which a legal obligation exists under enacted laws, statutes, written or oral contracts, including obligations arising under the doctrine of promissory estoppel. The recognition of an asset retirement obligation is capitalized as part of the carrying amount of the long-lived asset. The net difference between the amounts determined under SFAS No. 143 and the Company’s previous method of accounting for such activities, net of expected regulatory recovery, will be recognized as a cumulative effect of a change in accounting principle, net of related taxes, in accordance with Accounting Principles Board Opinion No. 20, “Accounting Changes” (“APB 20”). Asset retirement obligations represent future liabilities and, as a result, accretion expense will be accrued on this liability until such time as the obligation is satisfied. Adoption of SFAS No. 143 is required for financial statements issued for fiscal years beginning after June 15, 2002. The Company has adopted this new standard effective January 1, 2003 and the adoption of this new standard did not have a material impact on its consolidated financial position or results of operations. As described below, the estimated asset retirement obligations recorded as a liability in Accumulated Depreciation will be reclassified as a regulatory liability in the first quarter of 2003.
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SFAS No. 143 also requires that, if the conditions of SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation” are met, a regulatory asset or liability should be recorded to recognize differences between asset retirement costs recorded under SFAS No. 143 and legal or other asset retirement costs recognized for ratemaking purposes. Upon the application of SFAS No. 143, all rate regulated entities that are subject to the statement requirements will be required to quantify the amount of previously accumulated asset retirement costs for other than legal obligations and reclassify those differences as regulatory assets or liabilities.
The Company has approximately $109.3 million that has been accrued in depreciation rates and recorded as a liability in Accumulated Depreciation related to estimated asset retirement obligations. This balance will be reclassified as a regulatory liability in the first quarter of 2003. Also, beginning in the first quarter of 2003, changes in accounting procedures will direct accruals for removal costs to be credited directly to regulatory liabilities.
In August 2001, the FASB issued SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.” SFAS No. 144 requires that an impairment loss be recognized only if the carrying amount of a long-lived asset is not recoverable from its undiscounted cash flows and that the measurement of any impairment loss be the difference between the carrying amount and the fair value of the long-lived asset. SFAS No. 144 also requires companies to separately report discontinued operations and extends that reporting to a component of an entity that either has been disposed of (by sale, abandonment, or in a distribution to owners) or is classified as held for sale. Assets to be disposed of are reported at the lower of the carrying amount or fair value less costs to sell. Adoption of SFAS No. 144 is required for financial statements issued for fiscal years beginning after December 15, 2001. The Company adopted SFAS No. 144 effective January 1, 2002 and the adoption of this new standard did not have a material impact on its consolidated financial position or results of operations.
In July 2002, the FASB issued SFAS No. 146, “Accounting for Costs Associated with Exit or Disposal Activities.” SFAS No. 146 addresses financial accounting and reporting for costs associated with exit and disposal activities and supersedes Emerging Issues Task Force (“EITF”) Issue No. 94-3, “Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring).” SFAS No. 146 requires recognition of a liability for a cost associated with an exit or disposal activity when the liability is incurred, as opposed to when the entity commits to an exit plan under EITF 94-3. SFAS No. 146 also establishes that the liability should initially be measured and recorded at fair value. Adoption of SFAS No. 146 is required for exit and disposal activities initiated after December 31, 2002. The Company has adopted this new standard effective January 1, 2003 and the adoption of this new standard did not have a material impact on its consolidated financial position or results of operations.
In October 2002, the EITF reached a consensus on certain issues covered in EITF No. 02-3, “Issues Related to Accounting for Contracts Involved in Energy Trading and Risk Management Activities.” One consensus of EITF 02-3 requires that all mark-to-market gains and losses, whether realized or unrealized, on financial derivative contracts as defined in SFAS No. 133 be shown net in the Income Statement for financial statements issued for periods beginning after December 15, 2002, with reclassification required for prior periods presented.
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The Company has adopted this consensus effective January 1, 2003 and the application of this consensus did not have a material impact on its consolidated financial position or results of operations as this consensus supports the Company’s historical presentation of financial derivative contracts.
In October 2002, the EITF reached a consensus to rescind EITF Issue No. 98-10, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities”, as amended effective for fiscal periods beginning after December 15, 2002. Effective October 25, 2002, all new contracts and physical inventories that would have been accounted for under EITF 98-10 are no longer marked to market through earnings unless the contracts meet the definition of a derivative under SFAS No. 133. Application of the consensus for energy contracts and inventory that existed on or before October 25, 2002 that remain in effect at the date this consensus is initially applied will be recognized as a cumulative effect of a change in accounting principle in accordance with APB 20. As a result, only energy contracts that meet the definition of a derivative in SFAS No. 133 will be carried at fair value. The Company has adopted this consensus effective January 1, 2003 resulting in an approximate $5.9 million after tax loss. The loss, which will be accounted for as a cumulative effect of a change in accounting principle, is primarily related to natural gas held in storage for trading purposes.
In December 2002, the FASB issued SFAS No. 148, “Accounting for Stock-Based Compensation - Transition and Disclosure - an amendment of FASB Statement No. 123.” SFAS No. 148 provides alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation which includes the prospective method, modified prospective method and retroactive restatement method. SFAS No. 148 also amends the disclosure requirements of SFAS No. 123, “Accounting for Stock-Based Compensation” to require prominent disclosures in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on reported results. Adoption of the annual disclosure and voluntary transition requirements of SFAS No. 148 is required for annual financial statements issued for fiscal years ending after December 15, 2002. Adoption of the interim disclosure requirements of SFAS No. 148 is required for interim periods beginning after December 15, 2002. Pursuant to the provisions of SFAS No. 123, the Company has elected to continue using the intrinsic value method of accounting for its stock-based employee compensation plans in accordance with APB Opinion No. 25, “Accounting for Stock Issued to Employees” (“APB 25”). See “Stock-Based Compensation” and Note 8 for a further discussion.
Price Risk Management Assets and Liabilities
Non-Trading Activities
The Company periodically utilizes derivative contracts to manage exposure to unfavorable changes in commodity prices, as well as to reduce exposure to adverse interest rate fluctuations. During 2002 and 2001, the Company’s use of non-trading price risk management instruments primarily involved the use of interest rate swap agreements to hedge the Company’s exposure to interest rate risk by converting a portion of the Company’s fixed rate debt to a floating rate. These agreements involve the receipt of fixed rate amounts in exchange for
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floating rate interest payments over the life of the agreement without an exchange of the underlying principal amount. In addition, the Company utilized certain fixed price swap instruments to hedge the price to be received for a portion of the Company’s natural gas production as well as to hedge portions of the Company’s exposure to natural gas liquids prices and natural gas storage activities. The Company accounts for its use of non-trading price risk management instruments under the guidance provided by SFAS No. 133. In accordance with SFAS No. 133, which was adopted by the Company on January 1, 2001, the Company recognizes all of its derivative instruments as price risk management assets or liabilities in the Balance Sheet at fair value with such amounts classified as current or long-term based on their anticipated settlement. The accounting for changes in the fair value of a derivative depends on the intended use of the derivative and resulting designation. For derivative instruments that are designated and qualify as a fair value hedge, the gain or loss on the derivative instrument as well as the offsetting gain or loss on the hedged item attributable to the hedged risk are recognized in the same line item associated with the hedged item in current earnings during the period of the change in fair values. 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. Hedge effectiveness is measured at least quarterly based on the relative changes in fair value between the derivative contract and hedged item during the period of hedge designation. Forecasted transactions designated as the hedged item in a cash flow hedge are regularly evaluated to assess whether they continue to be probable of occurring. If the forecasted transactions are no longer probable of occurring, any gain or loss deferred in Accumulated Other Comprehensive Income is recognized currently in earnings. The Company’s interest rate swap agreements have been designated as fair value hedges and qualified for the shortcut method prescribed by SFAS No. 133. Under the shortcut method, the Company assumes that the hedged item’s change in fair value is exactly as much as the derivative’s change in fair value.
Based on the Company’s derivative positions related to non-trading activity and market prices in effect at January 1, 2001, the adoption of SFAS No. 133 resulted in a reduction to Accumulated Other Comprehensive Income of approximately $26.9 million ($16.5 million after tax). This amount was associated with certain cash flow hedges in place at January 1, 2001 and was reclassified into earnings during 2001 as the hedged production was sold. As a result of subsequent changes in market prices, the Company ultimately recognized a $0.8 million loss on the settlement of these contracts during 2001, including a gain of $4.7 million related to the ineffective portion of the change in value of the derivative contracts. As of December 31, 2002, the Company did not have any outstanding cash flow hedges, and, as such, had no amounts included in Accumulated Other Comprehensive Income related to cash flow hedges. As of December 31, 2001, the Company had one outstanding cash flow hedge, and approximately $0.1 million after tax was included in Accumulated Other Comprehensive Income.
Trading Activities
The Company, through its subsidiary, OGE Energy Resources, Inc. (“OERI”), engages in energy trading activities primarily related to the purchase and sale of natural gas and electricity
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as well as certain other commodities. Contracts utilized in these activities generally include futures and swap contracts, forward contracts, over-the-counter and exchange traded options and storage and transportation contracts. Energy trading activities are accounted for in accordance with SFAS No. 133 and EITF 98-10. The adoption of SFAS No. 133 had no impact on the Company’s accounting for its trading activities as such contracts were recorded at fair value under EITF 98-10 which was issued prior to SFAS No. 133. Under the guidance provided by SFAS No. 133 and EITF 98-10, all energy and energy related contracts are reflected at fair value with the resulting unrealized gains and losses recorded as Price Risk Management assets or liabilities in the accompanying Consolidated Balance Sheets, classified as current or long-term based on their anticipated settlement. Unrealized gains and losses from changes in the market value of open contracts are included in natural gas sales in the consolidated income statement. Energy trading contracts resulting in delivery of a commodity that meet the requirements of EITF Issue No. 99-19, “Reporting Revenues Gross as a Principal or Net as an Agent”, are included as sales or purchases in the accompanying Consolidated Statements of Income depending on whether the contract relates to the sale or purchase of the commodity. See “Accounting Pronouncements” for a further discussion of the accounting for the Company’s energy trading activities.
Use of Estimates
In preparing the consolidated 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 liabilities at the date of the consolidated 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 consolidated financial statements. In management’s opinion, the areas of the Company where the most significant judgment is exercised is in the valuation of pension plan assumptions, impairment estimates, contingency reserves, unbilled revenue for OG&E, the allowance for uncollectible accounts receivable, the valuation of energy purchases and sales contracts and gas storage inventory.
Allowance for Uncollectible Accounts Receivable
For OG&E, all customer balances are written off if not collected within six months after the account is finalized. The allowance for uncollectible accounts receivable for OG&E is calculated by multiplying the last six months of electric revenue by the provision rate. The provision rate is based on a 12-month historical average of actual balances written off. To the extent the historical collection rates are not representative of future collections, there could be an effect on the amount of uncollectible expense recognized. For Enogex, customer balances are written off when the Company concludes the required payment of specific amounts owed is unlikely to occur. The allowance for uncollectible accounts receivable for Enogex is established on a case-by-case basis when the Company believes the required payment of specific amounts owed is unlikely to occur. The allowance for uncollectible accounts receivable was approximately $13.6 million and $9.7 million at December 31, 2002 and 2001, respectively.
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Property, Plant and Equipment
All property, plant and equipment are recorded at cost. Newly constructed plant is added to plant balances at costs which include contracted services, direct labor, materials, overhead and the allowance for funds used during construction (“AFUDC”). Replacements of major units of property are capitalized as plant. The replaced plant is removed from plant balances and the cost of such property less salvage is charged to Accumulated Depreciation. Repair and replacement of minor items of property are included in the Consolidated Statements of Income as Other Operation and Maintenance Expense. Effective January 1, 2003, removal expense will no longer be charged to Accumulated Depreciation but rather will be a credit to regulatory liabilities in accordance with SFAS No. 143.
The Company’s property, plant and equipment are divided into the following major classes at December 31, 2002 and 2001, respectively. These amounts exclude property, plant and equipment related to discontinued operations.
(In millions) 2002 2001
==============================================================================
OGE Energy Corp. (holding company)
Property, plant and equipment..................... $ 59.6 $ 47.0
- ------------------------------------------------------------------------------
OGE Energy Corp. property, plant and equipment.. 59.6 47.0
- ------------------------------------------------------------------------------
OG&E
Distribution assets............................... 1,749.6 1,666.5
Electric generation assets........................ 1,609.5 1,599.5
Transmission assets............................... 520.7 465.4
Intangible plant.................................. 4.8 4.3
Other property and equipment...................... 253.3 248.5
- ------------------------------------------------------------------------------
OG&E property, plant and equipment.............. 4,137.9 3,984.2
- ------------------------------------------------------------------------------
Enogex
Gathering and transmission assets................. 1,175.2 1,186.6
Gas processing assets............................. 68.8 118.0
Natural gas storage facilities.................... 78.2 48.9
Other property and equipment...................... 25.3 22.4
- ------------------------------------------------------------------------------
Enogex property, plant and equipment............ 1,347.5 1,375.9
- ------------------------------------------------------------------------------
Total property, plant and equipment........... $ 5,545.0 $ 5,407.1
==============================================================================
Depreciation
OG&E
The provision for depreciation, which was approximately 3.1 percent of the average depreciable utility plant for 2002 and 2001, is provided on a straight-line method over the estimated service life of the property. 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.
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Enogex
Depreciation is computed principally on the straight-line method using estimated useful lives of 17 to 60 years for gathering and transmission assets, 20 years for gas processing assets, 60 years for natural gas storage facilities and three to 10 years for other property and equipment. Amortization of intangibles other than debt costs is computed using the straight-line method over the respective lives of the intangibles ranging up to 20 years.
Impairment of Assets
The Company assesses potential impairments of assets when there is evidence that events or changes in circumstances indicate that an asset’s carrying value may not be recoverable. An impairment loss is recognized when the sum of the expected future net cash flows is less than the carrying amount of the asset. The amount of any recognized impairment is based on the estimated fair value of the asset subject to impairment compared to the carrying amount of such asset. See Note 4 for a further discussion.
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 accompanying Consolidated Statements of Income and as a charge to Construction Work in Progress in the accompanying Consolidated Balance Sheets. AFUDC rates, compounded semi-annually, were 2.40 percent, 4.87 percent and 6.68 percent for the years 2002, 2001 and 2000, respectively.
Cash and Cash Equivalents
For purposes of the consolidated financial statements, the Company considers all highly liquid debt instruments purchased with an original maturity of three months or less to be cash equivalents. These investments are carried at cost, which approximates fair value.
The Company’s cash management program utilizes controlled disbursement banking arrangements. Outstanding checks in excess of cash balances were approximately $23.5 million and $28.9 million at December 31, 2002 and 2001, respectively, and are classified as Accounts Payable in the accompanying Consolidated Balance Sheets. Sufficient funds were available to fund these outstanding checks when they were presented for payment.
Heat Pump Loans
OG&E has a heat pump loan program, whereby, qualifying customers may obtain a loan from OG&E to purchase a heat pump. Customer loans are available for a minimum of $1,500 to a maximum of $13,000 with a term of six months to 72 months. The finance rate is based upon the short-term loan rates and is reviewed and updated periodically. The interest rates were 10.99 percent at December 31, 2002 and 2001.
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The Company sold approximately $8.5 million of its heat pump loans in 2002. The heat pump loan balance was approximately $0.5 million and $9.4 million at December 31, 2002 and 2001, respectively.
Revenue Recognition
OG&E
OG&E reads its customers’ meters and sends bills to its customers throughout each month. As a result, there is a significant amount of customers’ electricity consumption that has not been billed at the end of each month. 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.
Enogex
The Company recognizes revenue from natural gas gathering and processing and transportation and storage services to third parties as services are provided. Revenue associated with natural gas liquids is recognized when the production is processed and sold. Substantially all of Enogex’s natural gas and power marketing operations are accounted for under a mark-to-market accounting methodology. Under mark-to-market accounting, fixed-price forwards, swaps, options, futures and other financial instruments with third parties are recorded at estimated fair market values, net of reserves, with the corresponding market gains or losses recognized in earnings and offsetting amounts recorded as Price Risk Management assets and liabilities in the accompanying Consolidated Balance Sheets. See “Accounting Pronouncements” for a further discussion.
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 OG&E’s customers through automatic fuel adjustment clauses, which are subject to periodic review by the OCC, the APSC and the FERC. The Acquisition Premium Credit Rider (“APC Rider”) and the Gas Transportation Adjustment Credit Rider (“GTAC Rider”) were both terminated by the settlement reached in OG&E’s rate case. The APC Rider and the GTAC Rider were both applicable to each Oklahoma retail rate schedule to which OG&E’s automatic fuel adjustment clause applies. See Note 16 of Notes to Consolidated Financial Statements for a further discussion.
Fuel Inventories
OG&E
Fuel inventories for the generation of electricity consist of coal, natural gas and oil. These inventories are accounted for under the last-in, first-out (“LIFO”) cost method. The estimated replacement cost of fuel inventories was higher than the stated LIFO cost by
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approximately $7.0 million and $13.0 million for 2002 and 2001, respectively, based on the average cost of fuel purchased late in the respective years.
Enogex
Gas storage inventory used in OERI’s trading activities that was acquired prior to October 26, 2002 is marked to market utilizing a gas index that in management’s opinion approximates the current market value of natural gas in that region as of the Balance Sheet date. However, the actual market value could materially change in the future due to changes in market conditions such as weather or supply and demand. Gas storage inventory acquired after October 25, 2002 is accounted for at the lower of cost or market in accordance with the guidance in EITF 02-3. Natural gas inventories used in OERI’s trading activities, which are valued at market were approximately $30.6 million and $22.3 million at December 31, 2002 and 2001, respectively. Natural gas inventories, accounted for at the lower of cost or market were approximately $3.7 million at December 31, 2002. See “Accounting Pronouncements” for a further discussion.
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.
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. When a single estimate of the liability cannot be determined, the low end of the estimated range is recorded. Costs are charged to expense or deferred as a regulatory asset based on expected recovery from customers in future rates, if they relate to the remediation of conditions caused by past operations or if they are not expected to mitigate or prevent contamination from future operations. Where environmental expenditures relate to facilities currently in use, such as pollution control equipment, the costs may be capitalized and depreciated over the future service periods. Estimated remediation costs are recorded at undiscounted amounts, independent of any insurance or rate recovery, based on prior experience, assessments and current technology. Accrued obligations are regularly adjusted as environmental assessments and estimates are revised, and remediation efforts proceed. For sites where OG&E has been designated as one of several potentially responsible parties, the amount accrued represents OG&E’s estimated share of the cost.
Stock-Based Compensation
Pursuant to the provisions of SFAS No. 123, the Company has elected to continue using the intrinsic value method of accounting for its stock-based employee compensation plans in accordance with APB 25. Accordingly, the Company has not recognized compensation expense for its stock-based awards to employees. See Note 8 for a further discussion.
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The following table reflects pro forma net income and earnings per average common share had the Company elected to adopt the fair value based method of SFAS No. 123:
Year Ended December 31
------------------------------------
2002 2001 2000
------------------------------------
(In millions, except per share data)
Net income, as reported...................................... $ 90.8 $ 100.6 $ 147.0
Add:
Stock-based employee compensation expense included
in reported net income, net of related tax effects.......... --- --- ---
Deduct:
Stock-based employee compensation expense
determined under fair value based method for all awards,
net of related tax effects.................................. 1.5 0.9 0.6
----------------------------------
Pro forma net income......................................... $ 89.3 $ 99.7 $ 146.4
==================================
Earnings per average common share
Basic - as reported........................................ $ 1.16 $ 1.29 $ 1.89
Basic - pro forma.......................................... $ 1.14 $ 1.28 $ 1.88
Diluted - as reported...................................... $ 1.16 $ 1.29 $ 1.89
Diluted - pro forma........................................ $ 1.14 $ 1.28 $ 1.88
Reclassifications
Certain prior year amounts have been reclassified on the consolidated financial statements to conform to the 2002 presentation.
2. Discontinued Operations
On March 25, 2002, Enogex entered into an Agreement of Sale and Purchase with West Texas Gas, Inc. to sell all of its interests in Belvan Corp., Belvan Limited Partnership and Todd Ranch Limited Partnership (“Belvan”) for approximately $9.8 million. The effective date of the sale was January 1, 2002 and the closing occurred on March 28, 2002. The Company recognized approximately a $1.6 million gain related to the sale of these assets.
On August 5, 2002, Enogex entered into an Agreement of Sale and Purchase with Chesapeake Exploration Limited Partnership to sell all of its exploration and production assets located in Oklahoma, Texas, Arkansas and Mississippi for approximately $15.0 million. The effective date of the sale was July 1, 2002 and the closing occurred on September 19, 2002. The Company recognized approximately a $2.3 million loss related to the sale of these assets.
On November 14, 2002, Enogex entered into an Agreement of Sale and Purchase with Quicksilver Resources, Inc. to sell all of its exploration and production assets located in
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Michigan for approximately $32.0 million. The effective date of the sale was July 1, 2002 and the closing occurred on December 2, 2002. The Company recognized approximately a $2.9 million gain related to the sale of these assets.
During the third quarter of 2002, the Company decided to sell all of its interests in the NuStar Joint Venture (“NuStar”). On January 23, 2003, Enogex entered into an Agreement of Sale and Purchase with Benedum Gas Partners, L.P. to sell all of the interests of its subsidiary, Enogex Products Corporation, in the west Texas properties consisting of NuStar, which has operations consisting of the extraction and sale of natural gas liquids, for approximately $37.0 million. The effective date of the sale was January 1, 2003 and the closing occurred on February 18, 2003. The Company will recognize a pre-tax gain of approximately $2.3 million in the first quarter of 2003 related to the sale of these assets.
The Consolidated Financial Statements of the Company have been restated to reflect Enogex’s exploration and production assets, NuStar and Belvan, all of which were part of the Natural Gas Pipeline segment, as discontinued operations. Accordingly, revenues, costs and expenses, assets, liabilities and cash flows of the exploration and production assets, NuStar and Belvan have been excluded from the respective captions in the consolidated financial statements and have been reported as “Current Assets of Discontinued Operations”, “Net Property, Plant and Equipment of Discontinued Operations”, “Deferred Charges and Other Assets of Discontinued Operations”, “Current Liabilities of Discontinued Operations”, “Deferred Credits and Other Liabilities of Discontinued Operations”, “Income from Discontinued Operations” and “Net Cash Provided from Discontinued Operations.”
Summarized financial information for the discontinued operations is as follows:
CONSOLIDATED STATEMENTS OF INCOME DATA
(In millions) 2002 2001 2000 ================================================================================== Operating revenues from discontinued operations... $ 79.5 $ 121.4 $ 117.7 - ---------------------------------------------------------------------------------- Income from discontinued operations before taxes.. $ 8.4 $ 6.4 $ 17.6 - ----------------------------------------------------------------------------------
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CONSOLIDATED BALANCE SHEET DATA
December 31 (In millions) 2002 2001
=======================================================================================
Accounts receivable.............................................. $ 4.1 $ 7.8
Prepayments...................................................... --- 0.9
Other current assets............................................. 0.6 0.8
- ---------------------------------------------------------------------------------------
Total current assets of discontinued operations................ $ 4.7 $ 9.5
- ---------------------------------------------------------------------------------------
Plant in service of discontinued operations...................... 54.2 145.3
Less accumulated depreciation................................ 11.4 50.5
- ---------------------------------------------------------------------------------------
Net property, plant and equipment of discontinued operations... $ 42.8 $ 94.8
- ---------------------------------------------------------------------------------------
Total deferred charges and other assets of discontinued
operations...................................................... $ 0.2 $ 0.1
- ---------------------------------------------------------------------------------------
Accounts payable................................................. 1.1 ---
Accrued taxes ................................................... 0.4 0.5
Other current liabilities........................................ 0.5 ---
- ---------------------------------------------------------------------------------------
Total current liabilities of discontinued operations........... $ 2.0 $ 0.5
- ---------------------------------------------------------------------------------------
Total deferred credits and other liabilities of discontinued
operations...................................................... $ 9.1 $ 10.1
- ---------------------------------------------------------------------------------------
3. 2003 Asset Disposals
On August 2, 2002, Ozark, in which an Enogex subsidiary owns a 75 percent interest, entered into an Agreement of Sale and Purchase with CenterPoint Energy Gas Transmission Co. to sell approximately 29 miles of transmission lines of the Ozark pipeline located in Pittsburg and Latimer counties in Oklahoma for approximately $10.0 million. On November 18, 2002, the Company received FERC approval for the closing, which occurred on January 6, 2003. The Company will recognize a pre-tax gain of approximately $5.3 million in the first quarter of 2003 related to the sale of these assets. These assets were part of the Natural Gas Pipeline segment.
During the third quarter of 2002, the Company decided to sell all of its interests in NuStar. On January 23, 2003, Enogex entered into an Agreement of Sale and Purchase with Benedum Gas Partners, L.P. to sell all of the interests of its subsidiary, Enogex Products Corporation, in the west Texas properties consisting of NuStar, which has operations consisting of the extraction and sale of natural gas liquids, for approximately $37.0 million. The effective date of the sale was January 1, 2003 and the closing occurred on February 18, 2003. The Company will recognize a pre-tax gain of approximately $2.3 million in the first quarter of 2003 related to the sale of these assets. These assets were part of the Natural Gas Pipeline segment.
4. Impairment of Assets
During the fourth quarter of 2002, the Company recognized a pre-tax impairment loss of approximately $48.3 million and $1.8 million in the Natural Gas Pipeline segment and Other Operations, respectively. The impairment loss in the Natural Gas Pipeline segment related to natural gas processing and compression assets. The impairment loss in Other Operations related to the Company’s aircraft. The impairments resulted from plans to dispose of these assets at prices below the carrying amount. The fair value of these assets was determined based on third-party evaluations, prices for similar assets, historical data and projected cash flows. The
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carrying amount of the Natural Gas Pipeline segment assets and Other Operations assets were approximately $17.3 million and $6.8 million, respectively, at December 31, 2002. The Company anticipates selling these assets within a one to two year period depending on market conditions.
5. Income Taxes
The items comprising income tax expense are as follows:
Year ended December 31 (In millions) 2002 2001 2000
============================================================================================
Provision (Benefit) for Current Income Taxes from Continuing
Operations
Federal...................................................... $ 12.5 $ 22.4 $ 21.3
State........................................................ (0.6) 3.4 6.0
- --------------------------------------------------------------- ------- ------- -------
Total Provision for Current Income Taxes from
Continuing Operations.................................... 11.9 25.8 27.3
- --------------------------------------------------------------- ------- ------- -------
Provision for Deferred Income Taxes, net from
Continuing Operations
Federal...................................................... 31.7 27.2 43.5
State........................................................ 6.6 5.1 6.9
- --------------------------------------------------------------- ------- ------- -------
Total Provision for Deferred Income Taxes, net from
Continuing Operations..................................... 38.3 32.3 50.4
- --------------------------------------------------------------- ------- ------- -------
Deferred Investment Tax Credits, net........................... (5.2) (5.2) (5.2)
Income Taxes Relating to Other Income and Deductions........... (0.4) --- (0.5)
- --------------------------------------------------------------- ------- ------- -------
Total Income Tax Expense from Continuing
Operations ............................................... $ 44.6 $ 52.9 $ 72.0
=============================================================== ======= ======= =======
The following schedule reconciles the statutory federal tax rate to the effective income tax rate:
Year ended December 31 2002 2001 2000
============================================================================================
Statutory federal tax rate..................................... 35.0% 35.0% 35.0%
State income taxes, net of federal income tax benefit.......... 2.9 3.3 4.0
Tax credits, net............................................... (3.8) (6.2) (3.4)
Other, net..................................................... (1.9) 2.2 (1.4)
- --------------------------------------------------------------- ------- ------- -------
Effective income tax rate as reported..................... 32.2% 34.3% 34.2%
=============================================================== ======= ======= =======
The Company files consolidated income tax returns. Income taxes are allocated to each affiliate based on its separate taxable income or loss. Investment tax credits on electric utility property have been deferred and are being amortized to income over the life of the related property.
The Company 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.
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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 OG&E. The components of Accumulated Deferred Taxes at December 31, 2002 and 2001, respectively, are as follows:
(In millions) 2002 2001
====================================================================================
Current Accumulated Deferred Tax Assets
Accrued vacation .......................................... $ 6.2 $ 5.8
Uncollectible accounts..................................... 2.3 3.0
Other...................................................... 2.4 1.2
- --------------------------------------------------------------- -------- --------
Total Current Accumulated Deferred Tax Assets............ $ 10.9 $ 10.0
====================================================================================
Non-Current Accumulated Deferred Tax Liabilities
Accelerated depreciation and other property related
differences............................................... $ 597.5 $ 609.6
Allowance for funds used during construction............... 35.6 37.5
Income taxes refundable to customers....................... 24.4 28.4
Bond redemption-unamortized costs.......................... 8.1 8.5
- --------------------------------------------------------------- -------- --------
Total Non-Current Accumulated Deferred Tax
Liabilities............................................. 665.6 684.0
- --------------------------------------------------------------- -------- --------
Non-Current Accumulated Deferred Tax Assets
Deferred investment tax credits............................ (13.8) (15.6)
Income taxes recoverable from customers.................... (10.9) (13.8)
Postretirement medical and life insurance benefits......... (4.4) (3.0)
Company pension plan....................................... (2.8) (10.6)
Other...................................................... (6.7) (6.1)
- --------------------------------------------------------------- -------- --------
Total Non-Current Accumulated Deferred Tax Assets........ (38.6) (49.1)
- --------------------------------------------------------------- -------- --------
Non-Current Accumulated Deferred Income Tax Liabilities, net... $ 627.0 $ 634.9
====================================================================================
6. Supplemental Cash Flow Information
Non-cash financing activities for the year ended December 31, 2002 and 2001 included approximately $14.1 million and $1.8 million, respectively, related to the interest rate swap agreements and the corresponding change in long-term debt. There were no amounts related to interest rate swap agreements and long-term debt for the year ended December 31, 2000. Also, for the year ended December 31, 2002, approximately $42.5 million related to the assumption of an asset and debt related to the Stuart Storage Facility was included as a non-cash financing activity. Other financing activities included approximately $2.4 million related to proceeds from the sale of the Company aircraft for the year ended December 31, 2000.
Cash payments for interest, net of interest capitalized of approximately $0.9 million, $0.7 million and $2.2 million, respectively, were approximately $115.4 million, $115.9 million and $118.3 million for the years ended December 31, 2002, 2001 and 2000, respectively. Cash payments for income taxes, less income tax refunds, were approximately $28.6 million, $30.6 million and $37.5 million for the years ended December 31, 2002, 2001 and 2000, respectively.
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7. Common Stock and Retained Earnings
In 2002, there were 509,596 shares of new common stock issued which consisted of 325,254 shares issued pursuant to the Dividend Reinvestment Plan, 174,143 shares for the Stock Direct Purchase Plan and 10,199 for the Stock Incentive Plan, which related to exercised stock options. In 2002, the $8.8 million increase in Premium on Capital Stock in the accompanying Consolidated Statements of Capitalization represents the issuance of common stock pursuant to the Dividend Reinvestment Plan, the Stock Direct Purchase Plan and the Stock Incentive Plan.
In 2001, there were 69,716 shares of new common stock issued pursuant to the Stock Incentive Plan, of which 67,410 related to restricted stock and 2,306 related to exercised stock options. In 2001, the $1.4 million increase in Premium on Capital Stock represents the issuance of common stock pursuant to the Stock Incentive Plan.
At December 31, 2002, there were 11,459,440 shares of unissued common stock reserved for the various employee and Company stock plans. Beginning July 30, 2002, the Company issued new common stock to satisfy the common stock requirements of the Company’s stock plans rather than purchasing the common stock on the open market.
Shareowners Rights Plan
In December 1990, OG&E adopted a Shareowners Rights Plan designed to protect shareowners’ interests in the event that OG&E was ever confronted with an unfair or inadequate acquisition proposal. In connection with the corporate restructuring, the Company adopted a substantially identical Shareowners Rights Plan in August 1995. Pursuant to the plan, the Company declared a dividend distribution of one “right” for each share of Company common stock. As a result of the June 1998 two-for-one stock split, each share of common stock is now entitled to one-half of a right. Each right entitles the holder to purchase from the Company one one-hundredth of a share of new preferred stock of the Company under certain circumstances. The rights may be exercised if a person or group announces its intention to acquire, or does acquire, 20 percent or more of the Company’s common stock. Under certain circumstances, the holders of the rights will be entitled to purchase either shares of common stock of the Company or common stock of the acquirer at a reduced percentage of the market value. In October 2000, the Shareowners Rights Plan was amended and restated to extend the expiration date to December 11, 2010 and to change the exercise price of the rights.
8. Stock Incentive Plan
On January 21, 1998, the Company adopted a Stock Incentive Plan (the “Plan”). Under this Plan, restricted stock, stock options, stock appreciation rights and performance units may be granted to officers, directors and other key employees. The Company has authorized the issuance of up to 4,000,000 shares under the Plan.
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Restricted Stock
During 2002, no restricted stock was distributed under the Plan. The Company distributed 67,410 shares of restricted common stock under the Plan during 2001 with a grant date fair value of $21.87 per share. The restricted stock distributed vests at the end of three years. Each share of restricted stock is subject to forfeiture if the recipient ceases to render substantial services to the Company or a subsidiary for any reason other than death, disability or retirement. Awards of restricted stock are subject to an additional condition with all or a portion of the shares of restricted stock being subject to forfeiture based on the Company’s return on equity compared to a peer group of companies during the three year restriction period.
Stock Options
Options granted under the Plan vest in one-third annual installments beginning one year from the date of grant and have a contractual life of 10 years. The Company has had no expirations of options. Stock option transactions related to the Plan are summarized in the following table:
2002 2001 2000
---------------------- ---------------------- ----------------------
Number Weighted Number Weighted Number Weighted
of Average of Average of Average
Options Price Options Price Options Price
============================================================================================================
Options Outstanding at beginning
of year............................ 1,570,027 $ 24.0475 1,190,200 $ 24.7186 870,400 $ 27.2361
Granted........................... 959,600 22.2716 428,100 22.5000 364,200 18.2500
Exercised......................... (10,199) 18.2500 (2,306) 18.2500 --- ---
Cancelled......................... (100,068) 22.2988 (45,967) 25.0179 (44,400) 24.1622
---------- ---------- ----------
Options Outstanding at end of year.. 2,419,360 $ 23.4400 1,570,027 $ 24.0475 1,190,200 $ 24.7186
- ------------------------------------------------------------------------------------------------------------
Options Exercisable at end of year.. 1,202,053 $ 24.8966 799,530 $ 25.6820 407,666 $ 26.6522
============================================================================================================
The fair value of each option grant under the Plan for the years ended December 31, 2002, 2001 and 2000, are estimated on the date of grant using the Black-Scholes option pricing model with the following weighted-average assumptions used for grants in 2002, 2001 and 2000:
2002 2001 2000
===================================================================================
Expected dividend yield.......................... 6.05% 5.70% 5.71%
Expected price volatility........................ 22.95% 24.03% 22.16%
Risk-free interest rate.......................... 4.90% 5.17% 5.08%
Expected life of options (in years).............. 7 7 7
Weighted-average fair value of options granted... $ 3.10 $ 3.61 $ 3.34
The following table provides additional information about stock options outstanding at December 31, 2002:
Options Outstanding Options Exercisable
------------------------------- --------------------------------
Weighted-Average
Range of Remaining Number Weighted-Average Number Weighted-Average
Exercise Prices Contractual Life Outstanding Exercise Price Outstanding Exercise Price
===========================================================================================================
$18.25 - $22.70 8.17 years 1,615,360 $21.5318 398,053 $20.0950
$25.75 - $28.75 5.09 years 804,000 $27.2739 804,000 $27.2739
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Common Stock
Changes in common stock outstanding at December 31, 2002 and 2001, were as follows:
(In millions) 2002 2001 - -------------------------------------------------------------------- Shares outstanding at beginning of year....... 78.0 77.9 Dividend Reinvestment Plan shares............. 0.3 --- Stock Incentive Plan shares, net.............. --- 0.1 Stock Direct Purchase Plan shares............. 0.2 --- - -------------------------------------------------------------------- Shares outstanding at end of year............. 78.5 78.0 ====================================================================
9. Earnings Per Share
For the year ended December 31, 2002, there was 0.1 million shares of employee stock options which were included in the computation of diluted earnings per average common share. No dilutive employee stock options were included in the computation of diluted earnings per average common share for the years ended December 31, 2001 and 2000. For the years ended December 31, 2002, 2001 and 2000, respectively, approximately 1.7 million shares, 1.1 million shares and 0.9 million shares subject to issuance related to employee stock options are not included in the calculation of adjusted average common shares outstanding for diluted earnings per average common share because the effect of including those shares is anti-dilutive.
10. Trust Originated Preferred Securities of Subsidiary
On October 21, 1999, the OGE Energy Capital Trust I, a wholly owned financing trust of the Company, issued $200.0 million principal amount of 8.375 percent trust preferred securities that mature on October 15, 2039. Distributions paid by the financing trust on the trust preferred securities are financed through payments on debt securities issued by the Company and held by the financing trust, which are eliminated in the Company’s consolidation. The trust preferred securities are redeemable at $25 per share beginning October 15, 2004. Distributions and redemption payments are guaranteed by the Company. Distributions paid to preferred security holders are recorded as Interest Expense in the accompanying Consolidated Statements of Income.
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11. Long-Term Debt
A summary of the long-term debt at OG&E is included in the accompanying Consolidated Statements of Capitalization. The following table itemizes Enogex’s long-term debt at December 31, 2002 and 2001:
(In millions) 2002 2001
- -------------------------------------------------------------------------------
Series Due 2002 -- 7.02% - 8.13%.......................... $ --- $ 113.0
Series Due 2003 -- 6.60% - 8.28%.......................... 19.0 19.0
Series Due 2004 -- 6.71% - 8.34%.......................... 51.0 51.0
Series Due 2005 -- 6.81% - 7.71%.......................... 34.2 34.2
Series Due 2007 -- 8.28%.................................. 3.0 3.0
Series Due 2008 -- 7.07%.................................. 1.0 1.0
Series Due 2010 -- 8.125%................................. 200.0 200.0
Series Due 2010 -- Variable %............................. 215.2 204.3
Series Due 2012 -- 8.35% - 8.90%.......................... --- 10.0
Series Due 2017 -- 8.96%.................................. --- 15.0
Series Due 2018 -- 7.15%.................................. 71.0 73.0
Series Due 2020 -- 7.00%.................................. 8.0 7.4
Series Due 2023 -- 7.75%.................................. 10.0 10.0
- -------------------------------------------------------------------------------
Total................................................ $ 612.4 $ 740.9
===============================================================================
The $71.0 million principal amount of 7.15 percent Senior Notes due June 1, 2018, shown above, are subject to semi-annual principal payments of $1.0 million each.
During 2002, $113.0 million of Enogex’s long-term debt matured and $27.0 million was redeemed which is itemized in the following table.
(In millions) 2002
------------------------------------------------------
Series Due 2002 -- 7.02% - 8.13%............ $ 113.0
Series Due 2012 -- 8.35% - 8.90%............ 10.0
Series Due 2017 -- 8.96%.................... 15.0
Series Due 2018 -- 7.15%.................... 2.0
------------------------------------------------------
Total.................................. $ 140.0
======================================================
On January 10, 2001, Enogex retired $5.0 million principal amount of 7.75 percent medium-term notes due April 24, 2023. On August 8, 2001, Enogex retired $4.75 million principal amount of 7.00 percent medium-term notes due December 1, 2004.
Maturities of the Company’s long-term debt during the next five years consist of $21.0 million in 2003; $53.0 million in 2004; $146.2 million in 2005; $2.0 million in 2006; and $5.0 million in 2007.
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 accompanying Consolidated Balance Sheets and are being amortized over the life of the respective debt.
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Interest Rate Swap Agreements
During 2001, the Company entered into two separate interest rate swap agreements: (i) OG&E entered into an interest rate swap agreement, effective March 30, 2001, to convert $110.0 million of 7.30 percent fixed rate debt due October 15, 2025, to a variable rate based on the three month London InterBank Offering Rate (“LIBOR”) and (ii) Enogex entered into an interest rate swap agreement, effective July 15, 2001, to convert $200.0 million of 8.125 percent fixed rate debt due January 15, 2010, to a variable rate based on the three month LIBOR. On March 1, 2002, Enogex monetized its interest rate swap agreement and received cash of approximately $4.2 million, which is being amortized over the life of the related debt.
On March 4, 2002, Enogex entered into an interest rate swap agreement to convert $200.0 million of 8.125 percent fixed rate debt due January 15, 2010, to a variable rate based on the three month LIBOR. On July 2, 2002, Enogex monetized its interest rate swap agreement and received cash of approximately $6.6 million, of which approximately $3.2 million was recorded against interest receivable and the remaining amount of approximately $3.4 million is being amortized over the life of the related debt.
On August 7, and on October 24, 2002, Enogex entered into interest rate swap agreements to convert $100.0 million of 8.125 percent fixed rate debt due January 15, 2010, to a variable rate based on the six month LIBOR.
These interest rate swaps qualified as fair value hedges under SFAS No. 133 and meet all of the requirements for a determination that there was no ineffective portion as allowed by the shortcut method under SFAS No. 133. The objective of these interest rate swaps was to achieve a lower cost of debt and to raise the percentage of total corporate long-term floating rate debt to reflect a level more in line with industry standards.
At December 31, 2002 and 2001, the fair values pursuant to the interest rate swaps were approximately $15.9 million and $1.8 million, respectively, and are included in non-current Price Risk Management in the accompanying Consolidated Balance Sheets. A corresponding net increase of approximately $15.9 million and $1.8 million is reflected in Long-Term Debt at December 31, 2002 and 2001, respectively, as these fair value hedges were effective at December 31, 2002 and 2001.
On April 6, 2001, the Company entered into a one-year interest rate swap agreement to lock in a fixed rate of 4.41 percent, effective April 10, 2001, on $140.0 million of variable rate short-term debt. This interest rate swap initially qualified for hedge accounting treatment as a cash flow hedge under SFAS No. 133. However, due to unexpected changes in the level of commercial paper issued during the third quarter of 2001, hedge accounting treatment under SFAS No. 133 was discontinued as of July 1, 2001, and all subsequent changes in the fair value of the swap were recorded as Interest Expense. During 2002 and 2001, approximately $0.2 million and $1.3 million, respectively, were recorded as Interest Expense in the accompanying Consolidated Statements of Income. The objective of this interest rate swap was to achieve a lower cost of debt and to reduce exposure to short-term interest rate volatility associated with the Company’s commercial paper program. At December 31, 2001, the fair value pursuant to the
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interest rate swap was approximately $0.1 million and is included in current Price Risk Management in the accompanying Consolidated Balance Sheet. A corresponding decrease of approximately $0.1 million after tax is reflected in the Company’s Accumulated Other Comprehensive Income at December 31, 2001 as the swap was deemed ineffective in the third quarter of 2001.
12. Short-Term Debt
The Company borrows on a short-term basis, as necessary, by the issuance of commercial paper and by loans under short-term bank facilities. The maximum and average amounts of short-term borrowings during 2002 on a consolidated basis were approximately $307.5 million and $191.7 million, respectively, at a weighted average interest rate of 2.40 percent. The weighted average interest rates for 2001 and 2000 were 4.87 percent and 6.68 percent, respectively.
Consolidated short-term debt of approximately $275.0 million was outstanding at December 31, 2002. The following table shows the Company’s lines of credit in place at December 31, 2002. Short-term borrowings will consist of a combination of bank borrowings and commercial paper.
Lines of Credit (In millions)
-------------------------------------------------------------------------------
Entity Amount Maturity
-------------------------------------------------------------------------------
OGE Energy Corp. (A) $ 15.0 April 6, 2003
200.0 January 8, 2004
100.0 January 15, 2004
OG&E 100.0 June 26, 2003
-------------------------------------------------------------------------------
Total $ 415.0
===============================================================================
(A) The lines of credit at OGE Energy Corp. were used to back up the Company's
commercial paper borrowings which were approximately $241.2 million at
December 31, 2002. No borrowings were outstanding at December 31, 2002
under any of the lines of credit shown above.
The Company’s ability to access the commercial paper market could be adversely impacted by a commercial paper ratings downgrade. The lines of credit contain ratings triggers that require annual fees and borrowing rates to increase if the Company suffers an adverse ratings impact. The impact of a downgrade of the Company’s rating would result in an increase in the cost of short-term borrowings of approximately five to 20 basis points, but would not result in any defaults or accelerations as a result of the ratings triggers.
Unlike the Company and Enogex, OG&E must obtain regulatory approval from the FERC in order to borrow on a short-term basis. OG&E has the necessary regulatory approvals to incur up to $400 million in short-term borrowings at any one time.
13. Pension and Postretirement Benefit Plans
All eligible employees of the Company are covered by a non-contributory defined benefit pension plan. In early 2000, the Board approved significant changes to the pension plan. Prior
119
to these changes, benefits were 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 that an employee retired and additional significant reductions for retirement prior to age 55. The changes made in 2000 included: (i) elimination of the significant reduction for employees electing to retire before age 55; (ii) the addition of an alternative method of computing the reduction in benefits (based on years of service and age) for an employee retiring prior to age 62, with an employee whose age and years of service total or exceed 80 at the time of retirement receiving no reduction in the benefits payable under the plan; and (iii) the ability of an employee at time of retirement to receive, in lieu of an annuity, a lump sum payment equal to the present value of the annuity. Also, for employees hired after January 31, 2000, the pension plan will be a cash balance plan, under which the Company 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 the benefit based on final average compensation as described above.
It is the Company’s policy to fund the plan on a current basis to comply with the minimum required contributions under existing tax regulations. Additional amounts may be contributed from time to time to increase the funded status of the plan. The Company made contributions of approximately $48.8 million and $43.0 million during 2002 and 2001 to increase the plan’s funded status. Such contributions are intended to provide not only for benefits attributed to service to date, but also for those expected to be earned in the future.
During 2002 and 2001, the Company made contributions to the pension plan that exceeded amounts previously recognized as net periodic pension expense and recorded a prepaid benefit obligation at December 31, 2002 and 2001 of approximately $44.9 million and $21.3 million, respectively. At December 31, 2002 and 2001, the Company’s projected pension benefit obligation exceeded the fair value of pension plan assets by approximately $156.7 million and $93.5 million, respectively. As a result of recording a prepaid benefit obligation and having a funded status where the projected benefit obligations exceeded the fair value of plan assets, provisions of SFAS No. 87, “Employers’ Accounting for Pensions”, required the recognition of an additional minimum liability in the amount of approximately $163.9 million and $83.1 million, respectively, at December 31, 2002 and 2001. The offset of this entry was an intangible asset and Accumulated Other Comprehensive Income, net of a deferred tax asset; therefore, this adjustment did not impact the results of operations in 2002 or 2001 and did not require a usage of cash and is therefore excluded from the accompanying Consolidated Statements of Cash Flows. The amount recorded as an intangible asset equaled the unrecognized prior service cost with the remainder recorded in Accumulated Other Comprehensive Income. The amount in Accumulated Other Comprehensive Income represents a net periodic pension cost to be recognized in the Consolidated Statements of Income in future periods.
The plan’s assets consist primarily of investments in mutual funds, U.S. Government securities, listed common stocks and corporate debt.
In addition to providing pension benefits, the Company provides certain medical and life insurance benefits for retired members (“postretirement benefits”). Under the existing plan,
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employees retiring from the Company on or after attaining age 55 who have met certain length of service requirements were entitled to these postretirement benefits. Pursuant to amendments made to the medical plan in 2000, employees hired prior to February 1, 2000, whose age and years of service total or exceed 80 or have attained age 55 with 10 years of service at the time of retirement are entitled to these postretirement benefits. Employees hired after January 31, 2000, are not entitled to the medical benefits but are entitled to the life insurance benefits. The benefits are subject to deductibles, co-payment provisions and other limitations. OG&E 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.
A reconciliation of the funded status of the plans and the amounts included in the accompanying Consolidated Balance Sheets are as follows:
Projected Benefit Obligations
================================================================================
Postretirement
Pension Plan Benefit Plans
- --------------------------------------------------------------------------------
(In millions) 2002 2001 2002 2001
- --------------------------------------------------------------------------------
Beginning obligations......... $ (402.2) $ (395.2) $ (120.8) $ (102.4)
Service cost.................. (13.3) (12.0) (2.7) (2.0)
Interest cost................. (28.7) (29.9) (9.6) (8.3)
Participants' contributions... --- --- (1.3) (1.2)
Plan changes.................. (0.3) --- --- ---
Actuarial losses.............. (51.9) (6.0) (58.9) (17.2)
Benefits paid................. 52.6 39.5 10.2 10.3
Expenses...................... 0.8 1.4 --- ---
- --------------------------------------------------------------------------------
Ending obligations............ $ (443.0) $ (402.2) $ (183.1) $ (120.8)
================================================================================
Fair Value of Plans' Assets
================================================================================
Postretirement
Pension Plan Benefit Plans
- --------------------------------------------------------------------------------
(In millions) 2002 2001 2002 2001
- --------------------------------------------------------------------------------
Beginning fair value.......... $ 308.7 $ 296.5 $ 52.8 $ 55.6
Actual return on plans'
assets....................... (17.8) 10.1 (6.8) (2.8)
Employer contributions........ 48.8 43.0 7.2 7.5
Participants' contributions... --- --- 1.1 1.1
Benefits paid................. (52.6) (39.5) (8.3) (8.6)
Expenses...................... (0.8) (1.4) --- ---
- --------------------------------------------------------------------------------
Ending fair value............. $ 286.3 $ 308.7 $ 46.0 $ 52.8
================================================================================
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Net Periodic Benefit Cost
=====================================================================================================
Postretirement
Pension Plan Benefit Plans
- -----------------------------------------------------------------------------------------------------
(In millions) 2002 2001 2000 2002 2001 2000
- -----------------------------------------------------------------------------------------------------
Service cost...................... $ 13.3 $ 12.0 $ 10.6 $ 2.7 $ 2.0 $ 2.1
Interest cost..................... 28.7 29.9 27.5 9.6 8.3 7.2
Return on plan assets............. (26.9) (24.7) (26.4) (5.6) (5.4) (5.0)
Amortization of transition
obligation....................... --- (1.3) (1.3) 2.7 2.7 2.7
Amortization of net (gain) loss... 4.7 0.9 (0.1) 0.5 (0.9) (1.7)
Amortization of unrecognized
prior service cost............... 5.4 5.5 4.6 2.1 2.2 1.5
- -----------------------------------------------------------------------------------------------------
Net periodic benefit cost......... $ 25.2 $ 22.3 $ 14.9 $ 12.0 $ 8.9 $ 6.8
=====================================================================================================
The capitalized portion of the net periodic pension benefit cost was approximately $3.9 million, $3.4 million and $2.2 million at December 31, 2002, 2001 and 2000, respectively. The capitalized portion of the net periodic postretirement benefit cost was approximately $1.9 million, $1.4 million and $1.0 million at December 31, 2002, 2001 and 2000, respectively.
Funded Status of Plans
=========================================================================================
Postretirement
Pension Plan Benefit Plans
- -----------------------------------------------------------------------------------------
(In millions) 2002 2001 2002 2001
- -------------------------------------------------------------------------- --------------
Funded status of the plans........... $ (156.7) $ (93.5) $ (137.1) $ (68.0)
Unrecognized net (gain) loss......... 158.9 67.0 79.5 8.7
Unrecognized prior service cost...... 42.7 47.8 13.2 15.3
Unrecognized transition obligation... --- --- 27.6 30.2
- -----------------------------------------------------------------------------------------
Net amount recognized................ $ 44.9 $ 21.3 $ (16.8) $ (13.8)
=========================================================================================
Amounts recognized in the Consolidated Balance Sheets consist of:
=========================================================================
Pension Plan
- -------------------------------------------------------------------------
(In millions) 2002 2001
- -------------------------------------------------------------------------
Prepaid benefit obligation.......................... $ 44.9 $ 21.3
Accrued pension and benefit obligations............. (163.9) (83.1)
Intangible asset - unamortized prior service cost... 42.7 47.3
Accumulated deferred tax asset...................... 46.9 13.9
Accumulated other comprehensive loss, net of tax.... 74.3 21.9
- -------------------------------------------------------------------------
Net amount recognized............................... $ 44.9 $ 21.3
=========================================================================
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Rate Assumptions
==============================================================================================
Postretirement
Pension Plan Benefit Plans
- ----------------------------------------------------------------------------------------------
2002 2001 2000 2002 2001 2000
- ----------------------------------------------------------------------------------------------
Discount rate........................ 6.75% 7.25% 8.00% 6.75% 7.25% 8.00%
Rate of return on plans' assets...... 9.00% 9.00% 9.00% 9.00% 9.00% 9.00%
Compensation increases............... 4.50% 4.50% 4.50% 4.50% 4.50% 4.50%
Assumed health care cost trend:
Initial trend..................... N/A N/A N/A 12.00% 6.00% 6.50%
Ultimate trend rate............... N/A N/A N/A 4.50% 4.50% 4.50%
Ultimate trend year............... N/A N/A N/A 2010 2006 2006
==============================================================================================
N/A - not applicable
Assumed health care cost trend rates have a significant effect on the amounts reported for the postretirement medical benefit plans.
The effects of a one-percentage point increase on the aggregate of the service and interest components of the net periodic postretirement health care benefits would be increases of approximately $1.6 million, $1.2 million and $1.1 million at December 31, 2002, 2001 and 2000, respectively. The effects of a one-percentage point decrease on the aggregate of the service and interest components of the net periodic postretirement health care benefits would be decreases of approximately $1.3 million, $1.0 million and $0.9 million at December 31, 2002, 2001 and 2000, respectively.
The effects of a one-percentage point increase on the aggregate of accumulated postretirement benefit obligations for health care benefits would be increases of approximately $23.2 million, $14.0 million and $11.3 million at December 31, 2002, 2001 and 2000, respectively. The effects of a one-percentage point decrease on the aggregate of accumulated postretirement benefit obligations for health care benefits would be decreases of approximately $19.0 million, $11.5 million and $9.4 million at December 31, 2002, 2001 and 2000, respectively.
14. Report of Business Segments
The Company’s Electric Utility operations are conducted through OG&E, a regulated utility engaged in the generation, transmission, distribution and sale of electric energy. The Company’s Natural Gas Pipeline operations are conducted through Enogex. Enogex is engaged in transporting natural gas through its pipelines to various customers (including OG&E), gathering and processing natural gas and marketing electricity, natural gas and natural gas liquids. Enogex also has been involved in investing in the development for and production of natural gas and crude oil, which investments Enogex sold during 2002. Other Operations primarily includes unallocated corporate expenses and interest expense on commercial paper and the Trust Originated Preferred Securities. Intersegment revenues are recorded at prices comparable to those of unaffiliated customers and are affected by regulatory considerations. The following tables are a summary of the results of the Company’s business segments for the years ended December 31, 2002, 2001 and 2000.
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==============================================================================================================
Electric Natural Gas Other
2002 Utility Pipeline (A) Operations Intersegment Total
- --------------------------------------------------------------------------------------------------------------
(In millions)
Operating revenues........................ $ 1,388.0 $ 1,684.0 $ --- $ (48.1) $ 3,023.9
Fuel ..................................... 435.8 --- --- (33.6) 402.2
Purchased power........................... 260.0 --- --- --- 260.0
Gas and electricity purchased for resale.. --- 1,402.1 --- (14.5) 1,387.6
Natural gas purchases - other............. --- 70.5 --- --- 70.5
- --------------------------------------------------------------------------------------------------------------
Cost of goods sold........................ 695.8 1,472.6 --- (48.1) 2,120.3
Gross margin on revenues.................. 692.2 211.4 --- --- 903.6
- --------------------------------------------------------------------------------------------------------------
Other operation and maintenance........... 282.9 101.1 (14.0) --- 370.0
Depreciation.............................. 123.1 49.3 10.1 --- 182.5
Impairment of assets...................... --- 48.3 1.8 --- 50.1
Taxes other than income................... 47.1 15.7 2.5 --- 65.3
- --------------------------------------------------------------------------------------------------------------
Operating income (loss)................... 239.1 (3.0) (0.4) --- 235.7
- --------------------------------------------------------------------------------------------------------------
Other income ............................ 0.7 1.5 1.5 --- 3.7
Other expense............................. (3.1) (0.6) (1.0) --- (4.7)
Interest income........................... 1.2 1.1 19.1 (19.7) 1.7
Interest expense.......................... (40.2) (49.7) (40.6) 19.7 (110.8)
Income tax expense (benefit).............. 71.6 (19.2) (7.8) --- 44.6
- --------------------------------------------------------------------------------------------------------------
Income (loss) from continuing operations.. $ 126.1 $ (31.5) $ (13.6) $ --- $ 81.0
- --------------------------------------------------------------------------------------------------------------
Income from discontinued operations....... --- 9.8 --- --- 9.8
- --------------------------------------------------------------------------------------------------------------
Net income (loss)......................... $ 126.1 $ (21.7) $ (13.6) $ --- $ 90.8
==============================================================================================================
Total assets.............................. $ 2,550.6 $ 1,504.2 $ 1,820.4 $ (1,748.0) $ 4,127.2
Capital expenditures...................... $ 198.7 $ 20.0 $ 14.8 $ 1.0 $ 234.5
==============================================================================================================
(A) Beginning with the first quarter of 2002, Natural Gas Pipeline's operations consisted of three related
businesses: Transportation and Storage, Gathering and Processing, and Marketing and Trading. The following
table is supplemental Natural Gas Pipeline information.
==============================================================================================================
Transportation Gathering Marketing
and and and
2002 Storage Processing Trading Eliminations Total
- --------------------------------------------------------------------------------------------------------------
(In millions)
Operating revenues...................... $ 444.6 $ 179.0 $ 1,350.5 $ (290.1) $ 1,684.0
Operating income (loss)................. $ 45.6 $ (49.5) $ 0.9 $ --- $ (3.0)
==============================================================================================================
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==============================================================================================================
Electric Natural Gas Other
2001 Utility Pipeline Operations Intersegment Total
- --------------------------------------------------------------------------------------------------------------
(In millions)
Operating revenues........................ $ 1,456.8 $ 1,649.8 $ --- $ (42.2) $ 3,064.4
Fuel ..................................... 485.8 --- --- (36.3) 449.5
Purchased power........................... 280.7 --- --- --- 280.7
Gas and electricity purchased for resale.. --- 1,318.4 --- (5.9) 1,312.5
Natural gas purchases - other............. --- 142.9 --- --- 142.9
- --------------------------------------------------------------------------------------------------------------
Cost of goods sold........................ 766.5 1,461.3 --- (42.2) 2,185.6
Gross margin on revenues.................. 690.3 188.5 --- --- 878.8
- --------------------------------------------------------------------------------------------------------------
Other operation and maintenance........... 287.3 93.0 (10.0) --- 370.3
Depreciation.............................. 119.8 45.4 7.7 --- 172.9
Taxes other than income................... 46.6 15.7 2.4 --- 64.7
- --------------------------------------------------------------------------------------------------------------
Operating income (loss)................... 236.6 34.4 (0.1) --- 270.9
- --------------------------------------------------------------------------------------------------------------
Other income ............................ 1.1 1.9 0.1 --- 3.1
Other expense............................. (3.5) (0.1) (0.6) --- (4.2)
Interest income........................... 2.4 3.2 22.4 (23.8) 4.2
Interest expense.......................... (46.0) (57.9) (47.1) 23.8 (127.2)
Income tax expense (benefit).............. 69.4 (6.8) (9.7) --- 52.9
- --------------------------------------------------------------------------------------------------------------
Income (loss) from continuing operations.. $ 121.2 $ (11.7) $ (15.6) $ --- $ 93.9
- --------------------------------------------------------------------------------------------------------------
Income from discontinued operations....... --- 6.7 --- --- 6.7
- --------------------------------------------------------------------------------------------------------------
Net income (loss)......................... $ 121.2 $ (5.0) $ (15.6) $ --- $ 100.6
==============================================================================================================
Total assets.............................. $ 2,434.3 $ 1,520.8 $ 1,691.8 $ (1,650.3) $ 3,996.6
Capital expenditures...................... $ 132.3 $ 70.0 $ 9.4 $ --- $ 211.7
==============================================================================================================
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==============================================================================================================
Electric Natural Gas Other
2000 Utility Pipeline Operations Intersegment Total
- --------------------------------------------------------------------------------------------------------------
(In millions)
Operating revenues........................ $ 1,453.6 $ 1,997.3 $ --- $ (266.5) $ 3,184.4
Fuel ..................................... 489.1 --- --- (37.5) 451.6
Purchased power........................... 263.3 --- --- --- 263.3
Gas and electricity purchased for resale.. --- 1,614.5 --- (229.0) 1,385.5
Natural gas purchases - other............. --- 174.9 --- --- 174.9
- --------------------------------------------------------------------------------------------------------------
Cost of goods sold........................ 752.4 1,789.4 --- (266.5) 2,275.3
Gross margin on revenues.................. 701.2 207.9 --- --- 909.1
- --------------------------------------------------------------------------------------------------------------
Other operation and maintenance........... 267.4 86.2 (8.5) --- 345.1
Depreciation.............................. 117.2 43.2 6.7 --- 167.1
Taxes other than income................... 45.5 14.7 2.1 --- 62.3
- --------------------------------------------------------------------------------------------------------------
Operating income (loss)................... 271.1 63.8 (0.3) --- 334.6
- --------------------------------------------------------------------------------------------------------------
Other income ............................ 0.1 3.3 0.8 --- 4.2
Other expense............................. (2.8) (0.3) (0.5) --- (3.6)
Interest income........................... 1.1 2.4 22.0 (22.2) 3.3
Interest expense.......................... (46.8) (57.9) (50.2) 22.2 (132.7)
Income tax expense (benefit).............. 80.3 4.8 (13.1) --- 72.0
- --------------------------------------------------------------------------------------------------------------
Income (loss) from continuing operations.. $ 142.4 $ 6.5 $ (15.1) $ --- $ 133.8
- --------------------------------------------------------------------------------------------------------------
Income from discontinued operations....... --- 13.2 --- --- 13.2
- --------------------------------------------------------------------------------------------------------------
Net income (loss)......................... $ 142.4 $ 19.7 $ (15.1) $ --- $ 147.0
==============================================================================================================
Capital expenditures...................... $ 128.4 $ 34.9 $ 3.9 $ --- $ 167.2
==============================================================================================================
15. Commitments and Contingencies
Capital Expenditures
The Company’s capital expenditures for 2003, 2004 and 2005 are estimated at $196.0 million, $185.0 million and $178.0 million, respectively.
Operating Lease Obligations
The Company has operating lease obligations expiring at various dates, primarily for OG&E railcar leases and Enogex noncancellable operating leases. Future minimum payments for noncancellable operating leases are as follows:
- ---------------------------------------------------------------------------------------------------
2008 and
(In millions) 2003 2004 2005 2006 2007 Beyond
===================================================================================================
Operating lease obligations
OG&E railcars............................ $ 5.4 $ 5.4 $ 5.4 $ 5.4 $ 5.4 $ 36.1
Enogex noncancellable operating leases... 4.3 3.6 3.5 2.8 1.8 0.6
- ---------------------------------------------------------------------------------------------------
Total operating lease obligations...... $ 9.7 $ 9.0 $ 8.9 $ 8.2 $ 7.2 $ 36.7
===================================================================================================
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Payments for operating lease obligations were approximately $11.9 million, $11.5 million and $13.2 million in 2002, 2001 and 2000, respectively.
OG&E Railcar Leases
At December 31, 2002, OG&E held noncancellable operating leases which have purchase and renewal options covering 1,481 coal hopper railcars. Rental payments are charged to Fuel Expense and are recovered through OG&E’s tariffs and automatic fuel adjustment clauses.
OG&E is 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
OG&E has entered into agreements with four 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 OG&E to purchase power generated in a manufacturing process from a qualified cogeneration facility (“QF”). The rate for such power to be paid by OG&E was approved by the OCC. The rate generally consists of two components: one is a rate for actual electricity purchased from the QF by OG&E; the other is a capacity charge, which OG&E must pay the QF for having the capacity available. However, if no electrical power is made available to OG&E for a period of time (generally three months), OG&E’s obligation to pay the capacity charge is suspended. The total cost of cogeneration payments is recoverable in rates from customers.
During 2002, 2001 and 2000, OG&E made total payments to cogenerators of approximately $227.3 million, $222.5 million and $227.6 million, respectively, of which approximately $192.1 million, $190.7 million and $189.6 million, respectively, represented capacity payments. All payments for purchased power, including cogeneration, are included in the Consolidated Statements of Income as Cost of Goods Sold. The future minimum capacity payments under the contracts are approximately: 2003 - $164.7 million, 2004 - $152.7 million, 2005 - $87.7 million, 2006 - $86.1 million, 2007 - $84.4 million and 2008 and Beyond - $3.1 million. Other purchased power capacity payments are approximately $14.6 million in 2003.
Fuel Minimum Purchase Commitments
OG&E has entered into purchase commitments of necessary fuel supplies of coal and natural gas for its generating units of approximately $164.1 million, $120.0 million and $151.0 million for the years ended December 31, 2002, 2001 and 2000, respectively. Fuel minimum purchase commitments are approximately: 2003 - $152.2 million, 2004 - $145.6 million, 2005 - $147.2 million, 2006 - $142.7 million, 2007 - $129.3 million and 2008 and Beyond - $293.4 million.
127
OG&E acquires some of its natural gas for boiler fuel under a wellhead contract that contains provisions allowing the owner to require prepayments for gas if certain minimum quantities are not taken. At December 31, 2002 and 2001, outstanding prepayments for gas of approximately $32.5 million and $39.3 million, respectively, have been recorded in the Provision for Payments of Take or Pay Gas classified as Current Liabilities and as Deferred Credits and Other Liabilities in the accompanying Consolidated Balance Sheets. The outstanding prepayments of gas relate to a reserve for litigation that OG&E is currently involved in. As OG&E may be required to make these prepayments, offsetting amounts of approximately $32.5 million and $39.3 million have been recorded at December 31, 2002 and 2001, respectively, in Recoverable Take or Pay Gas Charges classified as Current Assets and as Deferred Charges and Other Assets in the accompanying Consolidated Balance Sheets as OG&E expects full recovery through its regulatory approved fuel adjustment clause.
Natural Gas Units
OG&E utilized a request for bid to acquire approximately 90 percent of its projected annual natural gas requirements for 2003. These contracts are tied to various gas price market indices and most will expire in April 2004. The remaining gas requirements of OG&E will be secured through monthly and day-to-day purchases as required.
Natural Gas Storage Facility Agreement with Central Oklahoma Oil and Gas Corp.
OG&E entered into an agreement with the parent company of Central Oklahoma Oil and Gas Corp. (“COOG”), an unrelated third-party, to develop a natural gas storage facility (the “Stuart Storage Facility”). During 1996, OG&E completed negotiations and contracted with COOG for gas storage service. Pursuant to the contract, COOG reimbursed OG&E for all outstanding cash advances and interest of approximately $46.8 million. In 1997, COOG obtained permanent financing for the Stuart Storage Facility and issued a note (the “COOG Note”), originally in the amount of $49.5 million. In connection with the permanent financing, the Company entered into a note purchase agreement, where it agreed, upon the occurrence of a monetary default by COOG on its permanent financing, to purchase COOG’s note from the holders at a price equal to the unpaid principal and interest under the COOG Note.
In 1998, Enogex entered into a Storage Lease Agreement (the “Agreement”) with COOG. Under the Agreement, COOG agreed to make certain enhancements to the Stuart Storage Facility to increase capacity and deliverability to a level specified and guaranteed by COOG. The Agreement was accounted for as a capital lease, and an asset was recorded for approximately $26.5 million, which was being amortized over 40 years.
As part of the Agreement, the Company agreed to make up to a $12 million secured loan to Natural Gas Storage Corporation (“NGSC”), an affiliate of COOG (the “NGSC Loan”). As of December 31, 2002, the amount outstanding under the NGSC Loan was approximately $8.0 million plus accrued interest. The NGSC Loan was originally repayable in 2003 and was secured by the assets and stock of COOG. As of July 31, 2002, approximately a $9.0 million obligation remained on the balance sheet of Enogex for the capital lease, which was being amortized. Due to actions taken by the parties, as explained below, the outstanding balance on
128
the NGSC Loan has now been offset against the capital lease obligation recorded on the books of Enogex.
After the completion of the enhancements by COOG in 1999, Enogex disputed whether the required and guaranteed level of natural gas deliverability for the Stuart Storage Facility was being provided by COOG and these issues were submitted to arbitration in October and November 2001. In July 2002, the Oklahoma District Court affirmed the arbitration award (the “Arbitration Award”) and entered judgment against COOG and in favor of Enogex in the amount of approximately $23.3 million (the “Judgment”). The Judgment is now final.
On July 24, 2002 Enogex exercised the Asset Purchase Option specified in the Agreement and specified a closing date of July 31, 2002. COOG failed and refused to close on July 31, 2002. The option price as of the Closing Date was calculated to be approximately $4.5 million which was set off against the Judgment. The operation of the Stuart Storage Facility was turned over to Enogex by COOG on August 9, 2002.
By letter dated May 9, 2002, COOG advised the holder of the COOG Note that the Arbitration Award was in excess of $10 million and, in the event the Arbitration Award became a final, non-appealable order, it would constitute an event of default under the loan agreement relating to the note and that it was unable to make the payment of principal and interest on the note due May 1, 2002. As a result, the Company made the May 2002 principal and interest payment on the COOG Note of approximately $1.0 million and was required to purchase the note on August 1, 2002 at a price equal to its unpaid principal, interest and fees of approximately $33.8 million. As the holder of the note, the Company is a secured creditor, with a first mortgage or comparable security interest on all of the Stuart Storage Facility. As a result of the events discussed above, the Company recorded a note payable and an asset for approximately $33.8 million. The assumption of this note was included in the purchase price for the Stuart Storage Facility on the balance sheet of Enogex.
By letter dated June 24, 2002, the Company notified NGSC that the NGSC Loan was in default and, as a result, all amounts were immediately due and payable under the NGSC Loan. NGSC has failed and refused to repay the NGSC Loan. The Company intends to continue to vigorously pursue its rights in conjunction with the NGSC Loan.
On August 12, 2002, the Company was improperly served with an Original Petition in a legal proceeding that has been filed by COOG and NGSC against the Company and Enogex in Texas. Enogex was properly served on August 12, 2002. COOG and NGSC have stated a claim for declaratory judgment asserting, among other things, that NGSC is not obligated to make payments on the NGSC Loan based on various theories and, that: (1) the Company was obligated to demand Enogex make the requisite payments to the Company; (2) the Company is liable to NGSC for failing to demand the requisite payments from Enogex, or alternatively, NGSC is entitled to a reduction in the amount it owes to the Company; (3) Enogex was and is obligated to make the payments to the Company until the indebtedness of NGSC to the Company is reduced to zero; (4) Enogex is not entitled to set off the Judgment against the lease payments that it originally owed to COOG and now owes to the Company; (5) no event of default has occurred; and (6) under the Agreement, the only remedy Enogex had or has if the Stuart Storage Facility
129
did not perform was to seek a modification of the lease payments based upon COOG’s expert’s analysis of the performance of the Stuart Storage Facility. COOG and NGSC have also stated claims for breach of contract relating to the same allegations in its claim for declaratory relief and include claims for attorneys’ fees.
The Company filed a Special Appearance and Original Answer Subject to Its Special Appearance objecting to being sued in Texas because the Texas Court does not have proper jurisdiction over the Company. On September 24, 2002, Enogex filed an Original Answer in response to the allegations, asserting, among other things, that the disputed issues have already been properly determined by the Arbitration Panel and the Oklahoma Court and, therefore, this action is improper.
On October 10, 2002, NGSC filed, in the Texas action, an Application for Temporary Injunction seeking to stop Enogex from proceeding against NGSC in the Oklahoma Court. On October 14, 2002, the Texas Court held a hearing on NGSC’s Application for Temporary Injunction. Without ordering the parties to mediate, the Court did direct the parties to mediation.
On October 24, 2002, mediation was held by the parties. An agreement, which provided several successive steps toward a potential settlement, was signed at that time. Under the agreement, COOG transferred full and complete title to the Stuart Storage Facility to Enogex effective August 9, 2002. Pursuant to the settlement agreement, all litigation between the parties was stayed for 45 days. The agreement also required COOG to have completed certain items within 45 days, or by December 12, 2002. COOG failed to do or complete the required items and therefore the stay of the execution of the Judgment is no longer in place. The Company intends to continue to vigorously pursue its rights in conjunction with the Judgment and payment of the NGSC Loan.
FERC Section 311 Rate Case
In December 2001, Enogex made its filing at the FERC under Section 311 of the Natural Gas Policy Act to establish rates and a default processing fee and to address various other issues, for the combined Enogex and Transok pipeline systems effective January 1, 2002. Effective January 1, 2002, these systems began operating as a single Enogex pipeline system. The FERC Staff, Enogex and the active intervening parties have conducted settlement discussions. Enogex has negotiated a settlement of the case with the interveners. A Stipulation and Agreement of Settlement and related documents were filed with the FERC on March 5, 2003 to resolve all issues in dispute in Docket No. PR02-10-000. Comments are due March 25, 2003 and reply comments will be due April 4, 2003. The proposed settlement includes a fee for processing to bring gas gathered behind processing plants to pipeline gas quality Btu standards (processing fee) and a monthly low flow meter charge of $200 (offset in any month by the transportation revenues generated by gas through the meter). If the settlement is approved, Enogex will have no refund obligation. The outcome of this rate case will not have an adverse effect on the Company’s consolidated financial position or results of operations as any default processing fee billed through February 2003 has been fully reserved on the Company’s books.
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Natural Gas Measurement Cases
Grynberg. In 1999, the Company's OG&E and certain Enogex Inc. subsidiaries were served with complaints under the False Claims Act by an individual, Jack J. Grynberg, on behalf of the United States Government. Plaintiff alleged: (i) each of the defendants have improperly and intentionally mismeasured gas (both volume and Btu content) purchased from federal and Indian lands which have resulted in the under-reporting and underpayment of gas royalties owed to the Federal Government; (ii) certain provisions generally found in gas purchase contracts are improper; (iii) transactions by affiliated companies are not arms-length; (iv) excess processing cost deduction; and (v) failure to account for production separated out as a result of gas processing. Plaintiff 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 of the claim, may be entitled to recover; (b) treble damages; (c) civil penalties; (d) an order requiring defendants to measure the gas in a manner Grynberg contends is the better way to do so; and (e) interest, costs and attorneys' fees. Plaintiff has filed over 70 other cases naming over 300 other defendants in various Federal Courts across the country containing nearly identical allegations. In late 1999, the actions against OG&E and Enogex were transferred and consolidated for pretrial purposes with approximately 76 other similar actions filed in nine other Federal Courts. The consolidated cases are now before the United States District Court for the District of Wyoming.
In October, 2002, the Court granted the United States Department of Justice’s motion to dismiss certain of Grynberg’s claims and issued an order dismissing Grynberg’s valuation claims against all Defendants. The Court also ordered that Grynberg amend all complaints by December 13, 2002. Grynberg has filed numerous amended complaints, including amended complaints against the Company. All answer deadlines are stayed until further order of the Court. On November 13, 2002, Grynberg filed a Notice of Appeal to the Tenth Circuit regarding the Wyoming Court’s October 2002, Order.
The Company intends to vigorously defend this action. Since the case is in the early stages of motions and discovery, 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 at this time.
Quinque. In September 1999, the Company was served with a complaint filed in United States District Court, State of Kansas by Quinque Operating Company and other named plaintiffs, alleging mismeasurement of natural gas on non-federal lands. Subsequent amended complaints have now been filed alleging that 178 defendants, including OG&E, Enogex Inc. and a subsidiary of Enogex Inc., have improperly mismeasured natural gas (both volume and Btu content) on all non-federal and non-Indian lands in the United States. Plaintiffs claim underpayment by the Company and all other defendants of gas royalties claimed to be owed to the plaintiffs and the putative class under the following theories of recovery: (i) breach of contract; (ii) negligent misrepresentation; (iii) civil conspiracy/aiding and abetting civil conspiracy; (iv) common carrier liability; (v) conversion; (vi) Uniform Commercial Code; (vii) Kansas Consumer Protection Act; (viii) breach of fiduciary duty; and (ix) equity, including injunction, accounting, quantum merit and unjust enrichment. Plaintiffs seek an injunction and
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an accounting and a judgment in excess of approximately $0.1 million, including punitive damages, treble damages, attorneys' fees, costs and pre-judgment and post-judgment interest. Plaintiffs also seek an order certifying the case as a class action.
The Company has filed various motions to dismiss the complaint. The court has not yet ruled on these motions or on the plaintiffs’ motions to certify the complaint as a class action.
The Company intends to vigorously defend this action. Since the case is in the early stages of motions and discovery, 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 at this time.
Firm Transportation Contract with Calpine Energy Services, L.P.
In 2000, Enogex entered into long-term firm transportation contracts with an IPP relating to a plant to be built in Wagoner County, Oklahoma. Effective July 1, 2000, the contracts were assigned to Calpine Energy Services, L.P. (“Calpine Energy”). In February 2002, Enogex requested a prepayment from Calpine Energy due to Calpine falling below the contractual creditworthiness provisions of the transportation contracts. Calpine Energy refused to pay for the full monthly demand fees pursuant to the transportation contracts on grounds of an alleged force majeure event. Enogex also made a demand on Calpine Corporation, as guarantor, relating to Calpine Energy’s failure to make the required prepayment and demand payments. As of December 31, 2002, the amount of demand revenues due to Enogex was approximately $4 million, which amount has been fully reserved on the Company’s financial statements. Enogex asserts that the remaining demand payments are due for all periods since March 6, 2002. Enogex also asserts that Calpine Corporation is liable for the amounts due and owing under the transportation agreements pursuant to the guarantee executed by Calpine Corporation, the parent corporation.
Calpine Energy and Calpine Corporation filed a declaratory judgment action in the United States District Court for the Northern District of Oklahoma relating to the dispute in September 2002. Calpine Energy seeks a declaratory judgment that demand charges are not due and owing and that Enogex had no reasonable ground to question its creditworthiness under the contracts. Enogex answered and filed a counterclaim on October 8, 2002. Enogex denied that either of the Calpine entities was entitled to the declaratory judgment requested and sought, under the counterclaim, an award based on breach of the contracts and the guarantee. Enogex also seeks a declaration that damages are due and owing under the contracts and the guarantee and a two-month prepayment should be awarded and maintained until the contractual creditworthiness provisions are met. For the months of November 2002 to February 2003, Calpine has paid the full monthly demand fee amounts.
Farmland Industries
Farmland Industries, Inc. (“Farmland”) voluntarily filed for Chapter 11 bankruptcy protection from creditors on May 31, 2002. Enogex provided gas transportation and supply services to Farmland, and is an unsecured creditor of Farmland. Enogex filed its Proof of Claim
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on January 7, 2003, for approximately $5.4 million. In its initial bankruptcy filing, Farmland asserted that it was a solvent entity with assets of approximately $2.7 billion and liabilities of approximately $1.9 billion. Farmland has been granted extensions of time in which to file its reorganization plan with the Court and is currently scheduled to file its plan by March 31, 2003.
Guarantees
During the normal course of business, Enogex issues guarantees on behalf of OERI for the purpose of securing credit for marketing and trading activities. These guarantees are for payment when due of amounts payable by OERI under various agreements with counterparties. At December 31, 2002, accounts payable supported by guarantees was approximately $49.9 million. Since these guarantees by Enogex represent security for payment of payables obtained in the normal course of OERI’s marketing and trading activities, the Company, on a consolidated basis, does not assume any additional liability as a result of this arrangement.
OGE Energy Corp. has issued two guarantees on behalf of OERI for the purpose of securing credit for marketing and trading activities. These guarantees are for payment when due of amounts payable by OERI under various agreements with counterparties. At December 31, 2002, accounts payable supported by guarantees was approximately $15.0 million. Since these guarantees by OGE Energy Corp. represent security for payment of payables obtained in OERI’s marketing and trading activities, the Company, on a consolidated basis, does not assume any additional liability as a result of this arrangement.
As of December 31, 2002, in the event Moody’s Investors Service or Standard & Poor’s Ratings Services were to lower Enogex’s senior unsecured debt rating to a below investment grade rating, Enogex would be required to post less than $5.0 million of collateral to satisfy its obligation under its financial and physical contracts.
Environmental Laws and Regulations
Approximately $4.9 million of the Company’s capital expenditures budgeted for 2003 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 $54.1 million during 2003, compared to approximately $44.2 million utilized in 2002. 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.
Several pieces of national legislation were introduced in 2002 requiring the reduction in emission of sulfur dioxide (“SO2”), nitrogen oxide (“NOX”), carbon dioxide (“CO2”) and mercury from the electric utility industry. Among those was President Bush’s “Clear Skies” proposal. While not addressing CO2, this bill would require significant reductions in SO2, NOX and mercury emissions. None of the proposed legislation became law; however, it is expected that numerous multi-pollutant bills will again be introduced in 2003.
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As required by Title IV of the Clean Air Act Amendments of 1990 (“CAAA”), OG&E completed installation and certification of all required continuous emissions monitors at its generating stations in 1995. Since then OG&E has submitted emissions data quarterly to the Environmental Protection Agency (“EPA”) as required by the CAAA. Beginning in 2000, OG&E became subject to more stringent SO2 emission requirements. These lower limits had no significant financial impact due to OG&E’s earlier decision to burn low sulfur coal. In 2002, OG&E’s SO2 emissions were well below the allowable limits.
With respect to the NOX regulations of Title IV of the CAAA, OG&E 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, OG&E was eligible to exercise its option to extend the effective date of the lower emission requirements from the year 2000 until 2008. OG&E’s average NOX emissions from its coal-fired boilers for 2002 were 0.32 lbs/MMBtu. However, further reductions in NOX emissions could be required if, among other things, proposed legislation is enacted requiring further reductions, a study currently being conducted by the state of Oklahoma determines that such NOX emissions are contributing to regional haze, if it is determined by the state of Oklahoma that OG&E's facilities impact the air quality of the Tulsa or Oklahoma City metropolitan areas or if Oklahoma fails to meet the new fine particulate standards. Any of these scenarios would require significant capital and operating expenditures.
The Oklahoma Department of Environmental Quality’s Clean Air Act Amendment Title V permitting program was approved by the EPA in March 1996. By March of 1997, OG&E had submitted all required permit applications. As of December 31, 2002, OG&E had received Title V permits for all but one of its generating stations. Since OG&E submitted all of its permit applications on time it is considered in compliance with the Title V permit program even though all permits have not been issued. Air permit fees for generating stations were approximately $0.5 million in 2002. Due to an increase in fee amounts by the Oklahoma Department of Environmental Quality the fees for 2003 are estimated to be approximately $0.6 million.
Other potential air regulations have emerged that could impact OG&E. On December 14, 2000, the EPA announced its decision to regulate mercury emissions from coal-fired boilers. Limits on the amount of mercury emitted are expected to be finalized by December 2004, although full compliance by OG&E is not expected to be required until 2008. Depending upon the final regulations implemented, this could result in significant capital and operating expenditures.
In 1997, the EPA finalized revisions to the ambient ozone and particulate standards. After a court challenge, which delayed implementation, the EPA has now begun to finalize the implementation process. Based on the most recent monitoring data, it appears that the Tulsa metropolitan area will fail to meet the revised standard. However, Tulsa has entered into an “Early Action Compact” with the EPA whereby voluntary measures will be enacted to reduce ozone and thus delay any official non-attainment designation. While the Oklahoma City metropolitan area is near non-attainment, it appears it will be able to comply without any additional measures. The EPA has indicated that emission sources in Muskogee County in Oklahoma should be considered in any evaluation of the air quality for the Tulsa metropolitan area. If this occurs, NOX reduction at OG&E’s Muskogee generation station could be required.
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The EPA also has issued regulations concerning regional haze. These regulations are intended to protect visibility in national parks and wilderness areas throughout the United States. In Oklahoma, the Wichita Mountains would be the only area covered under the regulation. Sulfates and nitrate aerosols (both emitted from coal-fired boilers) can lead to the degradation of visibility. Under these regulations, it is possible that controls on emission sources hundreds of miles away from the affected area may be required. The State of Oklahoma has begun the process of determining what, if any, impact emission sources in Oklahoma have on national parks and wilderness areas. If an impact is determined, then significant capital expenditures could be required for both the Sooner and Muskogee generating stations.
While the United States has withdrawn its support of the Kyoto Protocol on global warming, legislation has been drafted which would limit CO2 emissions. President Bush supports voluntary reductions by industry. OG&E has joined other utilities in voluntary CO2 sequestration projects through reforestation of land in the southern United States. In addition, OG&E has committed to reduce its CO2 emission rate (lbs. CO2/megawatt-hour) by up to five percent over the next 10 years. However, if legislation is passed requiring mandatory reductions this could have a tremendous impact on OG&E’s operations by requiring OG&E to significantly reduce the use of coal as a fuel source.
OG&E has and will continue to seek new pollution prevention opportunities and to evaluate the effectiveness of its waste reduction, reuse and recycling efforts. In 2002, OG&E obtained refunds of approximately $2.1 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.
OG&E has submitted one application during 2002 and will submit three more during 2003 to renew its Oklahoma Pollution Discharge Elimination System permits. OG&E anticipates that the renewed permits will continue to allow operational flexibility.
OG&E requested, based on the performance of a site-specific study, that the State agency responsible for the development of Water Quality Standards (“WQS”) adjust the in-stream copper criterion at one of its facilities. Without adjustment of this criterion, the facility could be subjected to costly treatment and/or facility reconfiguration requirements. The State has approved the WQS including the adjusted criterion and has transmitted the revised WQS to the EPA for their review and approval.
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’s original rules on this issue were set aside in 1977 by the Fourth Circuit U.S. Court of Appeals. In 1993, the EPA announced its plan to develop new rules in part due to a lawsuit filed by the Hudson Riverkeeper. To settle the lawsuit, the EPA signed a court-approved consent decree to develop 316(b) regulations on an agreed upon schedule. Proposed rules, for existing utility sources, were published in 2002 and the final rules are expected to be promulgated in August 2003. Depending on the content of the final rules, capital and operating expenses may increase at most of OG&E’s generating facilities. Increased
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capital costs may be necessary to retrofit and/or redesign existing intake structures to comply with any new 316(b) regulations.
Beginning in 2000, the Company began a process to evaluate, determine and report emissions from its pipeline facilities for compliance with recently promulgated Maximum Achievable Control Technology regulations. After evaluating the submitted information, the Oklahoma Department of Environmental Quality, in late 2001, issued Notices of Violation regarding potential air permitting issues at certain of these reported facilities. Generally, the notices alleged violations relating to the potential to emit various emission sources with the majority of the sources relating to glycol dehydrators. In compliance with Consent Orders entered between the parties, the Company has taken action to submit or modify permits, install control equipment, modify reporting procedures and pay penalties.
The Company has and will continue to evaluate the impact of its operations on the environment. As a result, contamination on Company property may be discovered from time to time. One site has been identified as having been contaminated by historical operations. Remedial options based on the future use of this site are being pursued with appropriate regulatory agencies. The cost of these actions has not had and is not anticipated to have a material adverse impact on the Company’s consolidated financial position or results of operations.
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 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 consolidated financial statements. Management, after consultation with legal counsel, does not anticipate that liabilities arising out of other currently pending or threatened lawsuits and claims will have a material adverse effect on the Company’s consolidated financial position, results of operations or cash flows.
16. Rate Matters and Regulation
Regulation and Rates
OG&E’s retail electric tariffs are regulated by the OCC in Oklahoma and by the APSC in Arkansas. The issuance of certain securities by OG&E is also regulated by the OCC and the APSC. OG&E’s wholesale electric tariffs, 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 OG&E’s facilities and operations.
The order of the OCC authorizing OG&E to reorganize into a subsidiary of the Company contains certain provisions which, among other things, ensure the OCC access to the books and records of the Company and its affiliates relating to transactions with OG&E; require the Company to employ accounting and other procedures and controls to protect against
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subsidization of non-utility activities by OG&E’s customers; and prohibit the Company from pledging OG&E assets or income for affiliate transactions.
For the year ended December 31, 2002, approximately 88 percent of OG&E’s electric revenue was subject to the jurisdiction of the OCC, eight percent to the APSC and four percent to the FERC.
Recent Regulatory Matters
In September 2001, the director of the OCC public utility division filed an application with the OCC to review the rates of OG&E. In the filing, the OCC Staff requested that OG&E submit information for a test year ending September 30, 2001. On December 14, 2001, OG&E, citing the need for investment in security and system reliability, filed a notice with the OCC of its intent to seek an increase in OG&E’s electric rates. On January 28, 2002, OG&E filed testimony with the OCC supporting OG&E’s request for a $22.0 million annual rate increase with approximately $10.3 million related to investments for security and approximately $11.7 million attributable to investments in increased system reliability and increased utility operating costs. Over the past 16 years, OG&E has had several rate reductions that have totaled more than $142.0 million annually.
Attempting to make security investments at the proper level, OG&E has developed a set of guidelines intended to minimize long-term or widespread outages, minimize the impact on critical national defense and related customers, maximize the ability to respond to and recover from an attack, minimize the financial impact on OG&E that might be caused by an attack and accomplish these efforts with minimal impact on ratepayers. Initially, approximately $10.3 million of the January 28, 2002 rate increase requested by OG&E was to invest in increased security. As described below, OG&E subsequently withdrew its request for the $10.3 million related to security.
The additional $11.7 million of the original $22.0 million request was for investment in increased system reliability and for increased utility operating costs. OG&E had added new generation capacity to meet growing customer demand and had determined that it needed to increase expenditures for distribution system reliability following a series of record-breaking storms, including a 1995 windstorm in the Oklahoma City area affecting 175,000 customers, 1999 tornadoes affecting about 150,000 customers and disrupting service at a power plant, July 2000 thunderstorms affecting 110,000 customers, a Christmas 2000 ice storm affecting 140,000 customers, Memorial Day 2001 storms leaving 143,000 customers without power and at least two other storms affecting at least 100,000 customers each.
As part of its filing, OG&E sought approval to offer several new rate program choices to customers. One such pilot program involves flat billing. This option would set a customer’s bill at a fixed dollar amount and would not change throughout the year regardless of the amount of power consumed. The bill amount would then be adjusted in the following year based on the previous year’s usage and other factors. Another proposed rate program, a Green Power option, would involve OG&E contracting with wind generators to purchase a quantity of wind-generated
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power, then offering that power to customers. The rate would reflect the higher cost of wind-generated power.
On January 30, 2002, a significant ice storm hit OG&E’s service territory and inflicted major damage to the transmission and distribution infrastructure requiring total expenditures for repairs of approximately $92.0 million. On April 8, 2002, OG&E announced it would withdraw the $10.3 million increased security portion of its January request. Simultaneously with that announcement, OG&E filed a Joint Application with the Staff of the OCC for separate consideration of costs related to increased security requirements. Thereafter, on August 14, 2002, OG&E filed a report outlining proposed expenditures and related actions for security enhancement. OG&E is working with the OCC Staff under this separate filing to determine the appropriate dollar amount for security upgrades and recovery mechanisms. The OCC Staff has indicated its intent to retain a security expert to review the report filed by OG&E.
On July 1, 2002, OG&E filed direct testimony in support of recovery for the approximately $92.0 million in damages caused by the January 2002 ice storm. OG&E requested approximately a $14.5 million annual increase in revenue requirement. The request included recovery of, and return on, approximately $86.6 million of capital expenditures related to the ice storm and recovery, over three years, of approximately $5.4 million of deferred operating costs. Recovery of costs associated with the January 2002 ice storm is included in the Joint Stipulation and Settlement Agreement discussed below.
On October 11, 2002, OG&E, the OCC Staff, the Oklahoma Attorney General and other interested parties agreed to a settlement (the “Settlement Agreement”) of OG&E’s rate case. The administrative law judge subsequently recommended approval of the Settlement Agreement and on November 22, 2002, the OCC signed a rate order containing the provisions of the Settlement Agreement. The Settlement Agreement provides for, among other items: (i) a $25.0 million annual reduction in the electric rates of OG&E’s Oklahoma customers which begins with the first regular billing cycle occurring 41 days after the issuance of the OCC order approving the Settlement Agreement; (ii) recovery by OG&E, through rate base, of the capital expenditures associated with the January 2002 ice storm; (iii) recovery by OG&E, over three years, of the $5.4 million in deferred operating costs, associated with the January 2002 ice storm, through OG&E’s rider for sales to other utilities and power marketers (“off-system sales”); (iv) OG&E to acquire electric generating capacity (“New Generation”) of not less than 400 megawatts (“MW”) to be integrated into OG&E’s generation system. Key portions of the Settlement Agreement are described below.
I. Rate Reduction to Oklahoma Customers
The Settlement Agreement stipulated that OG&E will file tariffs, designed to reflect an annual reduction of $25.0 million in OG&E’s Oklahoma jurisdictional operating revenue. The $25.0 million annual reduction began on January 6, 2003.
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II. Recovery of Storm Damages
The Settlement Agreement stipulated that OG&E would be allowed to earn a return, through base rates, on the capital expenditures related to the January 2002 ice storm. The Settlement Agreement also stipulated that OG&E would be allowed recovery of $5.4 million of deferred operating costs related to the January 2002 ice storm. The recovery of the $5.4 million in operating costs will be recovered over a three-year period through OG&E’s rider for off-system sales. Currently, OG&E has a 50/50 sharing mechanism in Oklahoma for any off-system sales. The Settlement Agreement provided that the first $1.8 million in annual net profits from OG&E’s off-system sales will go to OG&E, the next $3.6 million in annual net profits from off-system sales will go to OG&E’s Oklahoma customers, and any net profits of off-system sales in excess of these amounts will be credited in each sales year with 80 percent to OG&E’s Oklahoma customers and the remaining 20 percent to OG&E. If any of the $5.4 million is not recovered at the end of the three years, the OCC will authorize the recovery of any remaining costs.
III. New Generation
OG&E intends to take steps to purchase electric generating facilities of not less than 400 MW’s to be integrated into OG&E’s generation system. OG&E will have the right to accrue a regulatory asset, for a period not to exceed 12 months subsequent to the acquisition and initial operation of the New Generation, consisting of the non-fuel operation and maintenance expenses, depreciation, cost of debt associated with the capital investment and ad valorem taxes related to the New Generation. In addition to the accrual of the regulatory asset, OG&E must file an application with the OCC for the inclusion of the New Generation into OG&E’s rate base, as part of a general rate review, no later than 12 months following the acquisition and initial operation of the New Generation. Upon approval by the OCC of the application, all prudently incurred costs accrued through the regulatory asset within the 12 month period will be included in OG&E’s prospective cost of service. The period for recovery of the regulatory asset will be determined by the OCC. OG&E expects this New Generation will provide savings, over a three-year period, in excess of $75.0 million to OG&E’s Oklahoma customers. These savings will be derived from: (i) the avoidance of purchase power contracts otherwise needed; (ii) replacing an above market cogeneration contract when it can be terminated at the end of August 2004; and (iii) fuel savings associated with operating efficiencies of a new plant. These savings, while providing real savings to OG&E’s Oklahoma customers, should have no effect on the profitability of OG&E.
As indicated above, OG&E’s decision with respect to the purchase of the New Generation will be subject to a review by the OCC as a part of a general rate case for the purpose of determining the level of just and reasonable costs associated with the New Generation to be included in OG&E’s rate base. The OCC’s review is expected to include, but not be limited to, an analysis and review of the alternatives to purchasing the New Generation, the amount paid for such New Generation and the level of capacity purchases. OG&E will provide monthly reports, for a period of 36 months, to the OCC Staff, documenting and providing proof of savings experienced by OG&E’s customers. In determining the 36-month savings, OG&E will be required to include in its reports: (1) the avoidance of purchased capacity otherwise required to meet Southwest Power Pool capacity margin requirements; (2) credits to customers accruing by
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virtue of cogeneration contract terminations; and (3) the fuel savings associated with the operating efficiencies of OG&E’s generating facilities including the New Generation compared to the fuel efficiencies of OG&E’s generation facilities in operation during the test year related to the Settlement Agreement. The operating costs associated with the New Generation will be deducted from the sum of the three items discussed above to determine the ultimate amount of savings. In determining the 36-month savings, OG&E will not include savings to its customers, which occur as the result of scheduled reduction in ongoing cogeneration contract payments. In the event OG&E is unable to demonstrate at least $75.0 million in savings to its customers during this 36-month period, OG&E will have an obligation to credit its customers any unrealized savings below $75.0 million as determined at the end of the 36-month period, which shall be no later than December 31, 2006.
In the event OG&E does not acquire the New Generation by December 31, 2003, OG&E will be required to 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. However, if OG&E purchases the New Generation subsequent to January 2004, the credit to Oklahoma customers will terminate in the first month that the New Generation begins initial operations and any credited amount to Oklahoma customers will be included in the determination of the $75.0 million targeted savings.
IV. Rate Design
As part of the Settlement Agreement, OG&E agreed to withdraw its request for a Coal Utilization Performance Rider (“CUP Rider”) and a Transmission Investment Recovery Rider (“TIR Rider”). The CUP Rider would have rewarded OG&E based on its performance in the utilization of its coal generation facilities. The greater the coal plant utilization, the greater the benefits received by OG&E’s customers. OG&E’s coal plants are among the nations most efficient and the energy produced by those plants displaces higher cost energy. The CUP Rider would have provided additional incentive for OG&E by encouraging OG&E to aggressively pursue even greater efficiencies from these best-in-class plants. Additional CUP Rider incentives would have commenced at 72 percent coal utilization and increased as percentages rose above the 72 percent threshold level. The TIR Rider would have been applicable to investments necessary for increased transmission service and interconnect costs not funded by a new transmission customer (such as an independent power producer) or for investment to improve available transfer capability as defined and approved by the regional transmission organization. OG&E agreed not to seek implementation of a CUP Rider or a TIR Rider or other similar riders in OG&E’s next general rate proceeding or during the 36-month benefit period of the New Generation. However, in the event federal regulation of the interstate transmission grid results in a new rate design which increases costs to OG&E’s Oklahoma customers, OG&E will not be precluded from requesting a TIR Rider.
V. Gas Transportation Service
In a 1997 Order, the OCC approved a stipulation wherein OG&E agreed to initiate a competitive bidding process for gas transportation service to its natural gas plants.
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OG&E’s current gas transportation service contract with Enogex for OG&E’s current natural gas generation facilities has a primary term ending in April 2004 and provides for an annual payment to Enogex of approximately $32.3 million. As part of the Settlement Agreement, OG&E agreed to consider competitive bidding as an option when analyzing the extension or renewal of OG&E’s gas transportation service contract with Enogex prior to April 2004. OG&E further agreed to consider competitive bidding as an option for all natural gas transportation services and gas supply acquisition practices to all new generation facilities built, purchased or placed into service after October 9, 2002. If OG&E chooses not to utilize competitive bidding to obtain all natural gas transportation services to its current generation facilities, after April 2004, or to any new generation facilities, OG&E must then provide the OCC Staff and the office of the Oklahoma Attorney General all data and information upon which the decision was based.
Other Regulatory Actions
The Settlement Agreement, when it became effective, provided for the termination of the APC Rider and the GTAC Rider.
The APC Rider was approved by the OCC in March 2000 and was implemented by OG&E to reflect the completion of the recovery of the amortization premium paid by OG&E when it acquired Enogex in 1986. The effect of the APC Rider was to remove approximately $10.7 million annually from the amount being recovered by OG&E from its Oklahoma customers in current rates.
In June 2001, the OCC approved a stipulation (the “Stipulation”) to the competitive bid process of OG&E’s gas transportation service from Enogex. The Stipulation directed OG&E to reduce its rates to its Oklahoma retail customers by approximately $2.7 million per year through the implementation of the GTAC Rider. The GTAC Rider was a credit for gas transportation cost recovery and was applicable to and became part of each Oklahoma retail rate schedule to which OG&E’s automatic fuel adjustment clause applies. As discussed above, the Settlement Agreement terminated the GTAC Rider. Consequently, these charges for gas transportation provided by Enogex are now included in base rates.
OG&E’s Generation Efficiency Performance Rider (“GEP Rider”) expired in June 2002. The GEP Rider was established initially in 1997 in connection with OG&E’s 1996 general rate review and was intended to encourage OG&E to lower its fuel costs by: (i) allowing OG&E to collect one-third of the amount by which its fuel costs were below a specified percentage (96.261 percent) of the average fuel costs of certain other investor-owned utilities in the region; and (ii) disallowing the collection of one-third of the amount by which its fuel costs exceeded a specified percentage (103.739 percent) of the average fuel costs of other investor-owned utilities. In June 2000 the OCC made modifications to the GEP Rider which had the effect of reducing the amount OG&E could recover under the GEP Rider by: (i) changing OG&E’s peer group to include utilities with a higher coal-to-gas generation mix; (ii) reducing the amount of fuel costs that can be recovered if OG&E’s costs exceed the new peer group by changing the percentage above which OG&E will not be allowed to recover one-third of the fuel costs from Oklahoma customers from 103.739 percent to 101.0 percent; (iii) reducing OG&E’s share of cost savings as
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compared to its new peer group from 33 percent to 30 percent; and (iv) limiting to $10.0 million the amount of any awards paid to OG&E or penalties charged to OG&E. For the period between January 1, 2002 and June 30, 2002, OG&E recovered approximately $2.4 million under the GEP Rider.
FERC Section 311 Rate Case
In December 2001, Enogex made its filing at the FERC under Section 311 of the Natural Gas Policy Act to establish rates and a default processing fee and to address various other issues, for the combined Enogex and Transok pipeline systems effective January 1, 2002. Effective January 1, 2002, these systems began operating as a single Enogex pipeline system. The FERC Staff, Enogex and the active intervening parties have conducted settlement discussions. Enogex has negotiated a settlement of the case with the interveners. A Stipulation and Agreement of Settlement and related documents were filed with the FERC on March 5, 2003 to resolve all issues in dispute in Docket No. PR02-10-000. Comments are due March 25, 2003 and reply comments will be due April 4, 2003. The proposed settlement includes a fee for processing to bring gas gathered behind processing plants to pipeline gas quality Btu standards (processing fee) and a monthly low flow meter charge of $200 (offset in any month by the transportation revenues generated by gas through the meter). If the settlement is approved, Enogex will have no refund obligation. The outcome of this rate case will not have an adverse effect on the Company’s consolidated financial position or results of operations as any default processing fee billed through February 2003 has been fully reserved on the Company’s books.
State Restructuring Initiatives
Oklahoma
As previously reported, the Electric Restructuring Act of 1997 (the “1997 Act”) was designed to provide retail customers in Oklahoma a choice of their electric supplier by July 1, 2002. Additional implementing legislation was to be adopted by the Oklahoma Legislature to address many specific issues associated with the 1997 Act and with deregulation. In May 2000, a bill addressing the specific issues of deregulation was passed in the Oklahoma State Senate and then was defeated in the Oklahoma House of Representatives. In May 2001, the Oklahoma Legislature passed Senate Bill 440 (“SB 440”), which postponed the scheduled start date for customer choice from July 1, 2002 until at least 2003. In addition to postponing the date for customer choice, SB 440 calls for a nine-member task force to further study the issues surrounding deregulation. The task force includes the Governor or his designee, the Oklahoma Attorney General, the OCC Chair and several legislative leaders, among others. In the current legislative session, Senate Bill 383 has been recently introduced to repeal the 1997 Act. It is unknown at this time whether the bill will be passed into law. The Company will continue to actively participate in the legislative process and expects to remain a competitive supplier of electricity. As a result of the failures of California’s attempt to deregulate its electricity markets, the Enron bankruptcy, and associated impacts on the industry, efforts to restructure the electricity market in Oklahoma appear at this time to be delayed indefinitely.
142
Arkansas
In April 1999, Arkansas passed a law (the “Restructuring Law”) calling for restructuring of the electric utility industry at the retail level. The Restructuring Law, like the 1997 Act, would have significantly affected OG&E’s future operations. OG&E’s electric service area includes parts of western Arkansas, including Fort Smith. The Restructuring Law initially targeted customer choice of electricity providers by January 1, 2002. In February 2001, the Restructuring Law was amended to delay the start date of customer choice of electric providers in Arkansas until October 1, 2003, with the APSC having discretion to further delay implementation to October 1, 2005. In March 2003, the Restructuring Law was repealed.
17. 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:
2002 2001
------------------- --------------------
Carrying Fair Carrying Fair
(In millions) Amount Value Amount Value
============================================================================================
Price Risk Management Assets
Energy Trading Contracts................ $ 21.4 $ 21.4 $ 25.5 $ 25.5
Interest Rate Swaps..................... 15.9 15.9 4.2 4.2
Price Risk Management Liabilities
Energy Trading Contracts................ $ 14.6 $ 14.6 $ 8.7 $ 8.7
Interest Rate Swaps..................... --- --- 2.4 2.4
Long-Term Debt and Preferred Securities
Senior Notes............................ $ 575.1 $ 617.2 $ 565.0 $ 571.4
Industrial Authority Bonds.............. 135.4 135.4 135.4 135.4
Enogex Notes............................ 612.4 727.2 740.9 765.5
Trust Originated Preferred Securities... 200.0 213.2 200.0 212.9
============================================================================================
The carrying value of the financial instruments on the accompanying Consolidated Balance Sheets not discussed above approximates fair value. The valuation of the Company’s interest rate swaps and energy trading contracts was determined primarily based on quoted market prices. However, in certain instances where market quotes are not available, other valuation techniques or models are used to estimate market values. The valuation of instruments also considers the credit risk of the counterparties and the potential impact of liquidating the position in an orderly manner over a reasonable period of time. The fair value of the Company’s long-term debt and preferred securities is based on quoted market prices and management’s estimate of current rates available for similar issues with similar maturities.
143
18. Subsequent Events (Unaudited)
On January 15, 2003, Standard & Poor’s Ratings Services lowered the credit ratings of OGE Energy Corp.’s, OG&E’s and Enogex’s senior unsecured debt from A- to BBB+. OGE Energy Corp.’s short-term commercial paper ratings were affirmed at A-2. The Company may experience somewhat higher borrowing costs but does not expect the actions by Standard & Poor’s to have a significant impact on the Company’s consolidated financial position or results of operations.
On February 5, 2003, Moody’s Investors Service lowered the credit ratings of OGE Energy Corp. senior unsecured debt to Baa1 from A3, OG&E senior unsecured debt to A2 from A1 and Enogex senior unsecured debt to Baa3 from Baa2. OGE Energy Corp.’s short-term commercial paper rating was unchanged at P-2. The Company may experience somewhat higher borrowing costs but does not expect the actions by Moody’s to have a significant impact on the Company’s consolidated financial position or results of operations. As a result of Enogex’s rating being lowered to Baa3, OGE Energy Corp. was required to issue a $5.0 million guarantee on Enogex’s behalf for a counterparty.
144
REPORT OF INDEPENDENT AUDITORS
The Board of Directors and Shareowners
OGE Energy Corp.
We have audited the accompanying consolidated balance sheets and statements of capitalization of OGE Energy Corp. as of December 31, 2002 and 2001, and the related consolidated statements of income, retained earnings, comprehensive income and cash flows for each of the three years in the period ended December 31, 2002. Our audits also included the financial statement schedule listed in the Index at Item 15. These financial statements and schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the 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 consolidated financial position of OGE Energy Corp. at December 31, 2002 and 2001, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2002, in conformity with accounting principles generally accepted in the United States. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly, in all material respects, the information set forth herein.
/s/ Ernst and Young LLP
Ernst and Young LLP
Oklahoma City, Oklahoma,
January 24, 2003
145
REPORT OF MANAGEMENT
To Our Shareowners:
The management of OGE Energy Corp. is responsible for the preparation, integrity and objectivity of the consolidated financial statements of the Company and its subsidiaries and other information included in this report. The consolidated financial statements have been prepared in conformity with accounting principles generally accepted in the United States. As appropriate, the statements include amounts based on informed estimates and judgments of management.
The management of the Company has established and maintains a system of internal control designed to provide reasonable assurance, on a cost-effective basis, that assets are safeguarded, transactions are executed in accordance with management’s authorization and financial records are reliable for preparing consolidated financial statements. Management believes that the system of control provides reasonable assurance that errors or irregularities that could be material to the consolidated financial statements are prevented or would be detected within a timely period. Key elements of this system include the effective communication of established written policies and procedures, selection and training of qualified personnel and organizational arrangements that provide an appropriate division of responsibility. This system of control is augmented by an ongoing internal audit program designed to evaluate its adequacy and effectiveness. Management considers the recommendations of the internal auditors and independent auditors concerning the Company’s system of internal control and takes timely and appropriate actions to alleviate their concerns. Management believes that as of December 31, 2002, the Company’s system of internal control was adequate to accomplish the objectives discussed herein.
The Board of Directors of the Company addresses its oversight responsibility for the consolidated financial statements through its Audit Committee, which is composed of directors who are not employees of the Company. The Audit Committee meets regularly with the Company’s management, internal auditors and independent auditors to review matters relating to financial reporting, auditing and internal control. To ensure auditor independence, both the internal auditors and independent auditors have full and free access to the Audit Committee.
The independent public accounting firm of Ernst and Young LLP is engaged to audit, in accordance with auditing standards generally accepted in the United States, the consolidated financial statements of the Company and its subsidiaries and to issue their report thereon.
/s/ Steven E. Moore /s/ Al M. Strecker
----------------------------------------------- --------------------------------------------
Steven E. Moore, Chairman of the Board, Al M. Strecker, Executive Vice President
President and Chief Executive Officer and Chief Operating Officer
/s/ Peter B. Delaney /s/ James R. Hatfield
----------------------------------------------- --------------------------------------------
Peter B. Delaney, Executive Vice President, James R. Hatfield, Sr. Vice President
Finance and Strategic Planning - OGE and Chief Financial Officer
Energy Corp. and Chief Executive
Officer - Enogex Inc.
/s/ Donald R. Rowlett
-----------------------------------------------
Donald R. Rowlett, Vice President
and Controller
146
Supplementary Data
Interim Consolidated Financial Information (Unaudited)
In the opinion of the Company, the following quarterly information includes all adjustments, consisting of normal recurring adjustments, necessary for a fair statement of the results of operations for such periods:
Quarter ended (In millions, except per Dec 31 Sep 30 Jun 30 Mar 31
share data)
- -----------------------------------------------------------------------------------------------------------
Operating revenues (A) (B)..................... 2002 $ 829.9 $ 887.3 $ 730.8 $ 575.9
2001 522.9 803.9 717.2 1,020.4
2000 947.2 978.0 699.5 559.7
- -----------------------------------------------------------------------------------------------------------
Operating income (loss) (A) (C)................ 2002 $ (29.4) $ 185.9 $ 64.1 $ 15.1
2001 18.9 187.8 65.9 (1.7)
2000 36.1 199.9 69.2 29.4
- -----------------------------------------------------------------------------------------------------------
Net income (loss) (C).......................... 2002 $ (30.4) $ 99.0 $ 28.4 $ (6.2)
2001 (6.3) 97.1 24.8 (15.0)
2000 7.2 107.3 31.7 0.8
- -----------------------------------------------------------------------------------------------------------
Earnings (loss) available for common stock..... 2002 $ (30.4) $ 99.0 $ 28.4 $ (6.2)
2001 (6.3) 97.1 24.8 (15.0)
2000 7.2 107.3 31.7 0.8
- -----------------------------------------------------------------------------------------------------------
Earnings (loss) per average common share....... 2002 $ (0.39) $ 1.27 $ 0.36 $ (0.08)
2001 (0.09) 1.25 0.32 (0.19)
2000 0.09 1.38 0.41 0.01
- -----------------------------------------------------------------------------------------------------------
(A) These amounts have been restated due to Enogex's exploration and production assets, NuStar and Belvan
being reported as discontinued operations during 2002, 2001 and 2000.
(B) In the third quarter of 2002, the Company restated revenues to report on a net basis, all realized gains
and losses from energy trading contracts (accounted for under EITF 98-10) that resulted in physical
delivery as required by EITF 02-3. In the fourth quarter of 2002, the EITF reversed their previous position
regarding this issue, and returned to the previous method of reporting these revenues on a gross basis.
(C) In the fourth quarter of 2002, the Company recognized an impairment loss of approximately $48.3 million
and $1.8 million in the Natural Gas Pipeline segment and Other Operations, respectively. The impairment loss
in the Natural Gas Pipeline segment related to gas processing plants and compression assets. The impairment
loss in Other Operations related to the Company's aircraft.
Dividends
COMMON STOCK
Common quarterly dividends paid (as declared) in 2002,
2001, and 2000 were $0.33 ¼.
Present rate-$0.33 ¼
Payable 30th of January, April, July, and October
147
Security Ratings*
Standard
Moody's & Poor's Fitch's
===================================================================================
OG&E Senior Notes A2 BBB+ AA-
- -----------------------------------------------------------------------------------
Enogex Notes Baa3 BBB+ BBB
- -----------------------------------------------------------------------------------
OGE Energy Corp. Commercial Paper P-2 A-2 F1
- -----------------------------------------------------------------------------------
*The ratings of Moody’s, Standard & Poor’s and Fitch’s reflect only the views of such organizations and each rating should be evaluated independently of the other. The ratings are not recommendations to purchase, sell or hold a security. There can be no assurance that such ratings will remain in effect for any given period of time or that they will not be revised downward or withdrawn entirely by either of such rating agencies if, in the judgment of either circumstances so warrant. Moody’s currently maintains a stable outlook on its rating of the OG&E Senior Notes and OGE Energy Corp. commercial paper and a negative outlook on its rating of Enogex Notes. Standard & Poor’s and Fitch’s currently maintain a stable outlook on its ratings of the OG&E Senior Notes, Enogex Notes and OGE Energy Corp. commercial paper.
For further information regarding these ratings, please contact the Corporate Secretary of the Company at P. O. Box 321, Oklahoma City, Oklahoma 73101-0321, (405) 553-3622.
Market Prices
2002 2001
-------------------- -------------------
NEW YORK STOCK EXCHANGE High Low High Low
==================================================================================
Common
- ----------------------------------------------------------------------------------
First Quarter $ 24.12 $ 21.28 $ 24.69 $ 21.25
- ----------------------------------------------------------------------------------
Second Quarter 24.24 21.82 23.77 20.80
- ----------------------------------------------------------------------------------
Third Quarter 23.29 16.13 23.48 20.25
- ----------------------------------------------------------------------------------
Fourth Quarter 18.34 13.70 23.41 20.95
==================================================================================
148
Item 9. Changes In and Disagreements with Accountants on Accounting
and Financial Disclosure.
On May 16, 2002, the Board of Directors of OGE Energy Corp. (the “Company”), upon recommendation of its Audit Committee, decided to engage the services of Ernst and Young LLP to serve as its independent auditors for the fiscal year 2002. The Company’s management then notified Arthur Andersen LLP that the firm would no longer be engaged as its principal independent auditors.
During the two most recent fiscal years of the Company ended December 31, 2001, and the subsequent interim period through May 16, 2002, there were no disagreements between the Company and Arthur Andersen LLP on any matter of accounting principles or practices, financial statement disclosure, or auditing scope or procedure, which disagreements, if not resolved to Arthur Andersen LLP’s satisfaction, would have caused Arthur Andersen LLP to make reference to the subject matter of the disagreement in connection with its reports.
None of the reportable events described under Item 304(a)(1)(v) of Regulation S-K occurred within the two most recent fiscal years of the Company ended December 31, 2001 or within the interim period through May 16, 2002.
The audit reports of Arthur Andersen LLP on the consolidated financial statements of the Company as of and for the fiscal years ended December 31, 2000 and 2001 did not contain any adverse opinion or disclaimer of opinion, nor were they qualified or modified as to uncertainty, audit scope or accounting principles.
The Company provided Arthur Andersen LLP with a copy of the foregoing disclosures. Attached as Exhibit 16.01 is a copy of Arthur Andersen LLP’s letter dated May 21, 2002, stating its agreement with such statements.
During the two
most recent fiscal years of the Company ended December 31, 2001, and the
subsequent interim period through May 16, 2002, the Company did not consult with
Ernst and Young LLP regarding any of the matters or events set forth in Item
304(a)(2)(i) and (ii) of Regulation
S-K.
149
PART III
Item 10. Directors and Executive Officers of the Registrant.
Item 11. Executive Compensation.
Item 12. Security Ownership of Certain Beneficial Owners and Management
and Related Stockholder Matters.
Equity Compensation Plan Information
The following table provides certain information as of December 31, 2002 with respect to the shares of the Company’s Common Stock that may be issued under the existing equity compensation plans:
A B C
-------------------------------------------------------------------------
Number of Securities
Number of Remaining Available
Securities to be for future issuances
Issued upon Weighted under equity
Exercise of Average Price compensation plans
Outstanding of Outstanding (excluding securities
Plan Category Options Options reflected in Column A)
- ------------------------------------------------------------------------------------------------------------
Equity Compensation Plans
Approved by
Shareowners (A)................ 2,419,360 $23.44 1,299,118 (B)
Equity Compensation Plans
Not Approved by
Shareowners.................... N/A N/A N/A
(A) Consists of the OGE Energy Corp. Stock Incentive Plan, which was approved by shareowners at the
1998 annual meeting.
(B) Awards under the Stock Incentive Plan can take the form of stock options, stock appreciation
rights, restricted stock or performance units.
N/A - not applicable
Item 13. Certain Relationships and Related Transactions.
Items 10, 11, 12 and 13 (other than Item 12 information required by Item 201(d) of Regulation S-K) are omitted pursuant to General Instruction G of Form 10-K, since the Company will file copies of a definitive proxy statement with the Securities and Exchange Commission on or about March 31, 2003. Such proxy statement is incorporated herein by reference. In accordance with General Instruction G of Form 10-K, the information required by Item 10 relating to Executive Officers has been included in Part I, Item 4, of this Form 10-K.
150
Item 14. 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 rules and forms. Within the 90-day period prior to the filing of this report, an evaluation was carried out under the supervision and with the participation of the Company’s management, including the Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”), of the effectiveness of the Company’s disclosure controls and procedures. Based on that evaluation, the CEO and CFO have concluded that the Company’s disclosure controls and procedures are effective.
Subsequent to the date of their evaluation, there have been no significant changes in the Company’s internal controls or in other factors that could significantly affect these controls.
151
PART IV
Item 15. Exhibits, Financial Statement Schedules and
Reports on Form 8-K.
(a) 1. Financial Statements
The following consolidated financial statements and supplementary data are included in Part II, Item 8 of this Report:
- Consolidated Balance Sheets at December 31, 2002 and 2001
- Consolidated Statements of Capitalization at December 31, 2002 and 2001
- Consolidated Statements of Income for the years ended December 31, 2002, 2001 and 2000
- Consolidated Statements of Retained Earnings for the years ended December 31, 2002, 2001
and 2000
- Consolidated Statements of Comprehensive Income for the years ended December 31, 2002,
2001 and 2000
- Consolidated Statements of Cash Flows for the years ended December 31, 2002, 2001 and
2000
- Notes to Consolidated Financial Statements
- Report of Independent Auditors
- Report of Management
Supplementary Data
- Interim Consolidated Financial Information
2. Financial Statement Schedule (included in Part IV) Page
Schedule II - Valuation and Qualifying Accounts 159
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 consolidated financial statements or notes thereto.
152
3. Exhibits
Exhibit No. Description
2.01 Purchase Agreement, dated as of May 14, 1999, by and between Tejas
Gas, LLC and Enogex Inc. (Filed as Exhibit 2.01 to OGE Energy's
Form 10-Q for the quarter ended June 30, 1999 (File No. 1-12579)
and incorporated by reference herein)
3.01 Copy of Restated Certificate of Incorporation. (Filed as Exhibit 3.01
to OGE Energy's Form 10-K for the year ended December 31, 1996
(File No. 1-12579) and incorporated by reference herein)
3.02 By-laws. (Filed as Exhibit 3.02 to OGE Energy's Form 10-K for the year
ended December 31, 1996 (File No. 1-12579) and incorporated by
reference herein)
4.01 Copy of Trust Indenture dated October 1, 1995, from OG&E 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 Copy of Supplemental Trust Indenture No. 1 dated October 16, 1995,
being a supplemental instrument to Exhibit 4.01 hereto. (Filed as
Exhibit 4.01 to OG&E's Form 8-K Report dated October 23,
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 OG&E's Form 8-K filed on 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 OG&E's Form 8-K filed on April 16, 1998 (File No.
1-1097) and incorporated by reference herein)
153
4.05 Supplemental Indenture No. 4, dated as of October 15, 2000, being a
supplement instrument to Exhibit 4.01 hereto. (Filed as Exhibit
4.02 to OG&E's Form 8-K filed on October 20, 2000 (File No.
1-1097) and incorporated by reference herein)
10.01 Coal Supply Agreement dated March 1, 1973, between OG&E and
Atlantic Richfield Company. (Filed as Exhibit 5.19 to
Registration Statement No. 2-59887 and incorporated by reference
herein)
10.02 Amendment dated April 1, 1976, to Coal Supply Agreement dated March 1,
1973, between OG&E and Atlantic Richfield Company, together
with related correspondence. (Filed as Exhibit 5.21 to
Registration Statement No. 2-59887 and incorporated by reference
herein)
10.03 Second Amendment dated March 1, 1978, to Coal Supply Agreement dated
March 1, 1973, between OG&E and Atlantic Richfield Company.
(Filed as Exhibit 5.28 to Registration Statement No. 2-62208 and
incorporated by reference herein)
10.04 Amendment dated June 27, 1990, between OG&E and Thunder Basin Coal
Company, to Coal Supply Agreement dated March 1, 1973, between
OG&E and Atlantic Richfield Company. (Filed as Exhibit 10.04
to OG&E’s Form 10-K Report for the year ended December
31, 1994, (File No. 1-1097), and incorporated by reference
herein) [Confidential Treatment has been requested for certain
portions of this exhibit.]
10.05 Form of Change of Control Agreement for Officers of the Company and
OG&E. (Filed as Exhibit 10.07 to OGE Energy's Form 10-K for
the year ended December 31, 1996 (File No. 1-12579) and
incorporated by reference herein)
10.06 Company's Stock Incentive Plan. (Filed as Exhibit 10.07 to OGE
Energy's Form 10-K for the year ended December 31, 1998 (File No.
1-12579) and incorporated by reference herein)
154
10.07 OGE Energy Corp. Restoration of Retirement Income Plan, as amended by
Amendments No. 1 and No. 2. (Filed as Exhibit 10.12 to OGE
Energy's Form 10-K for the year ended December 31, 1996 (File
No.1-12579) and incorporated by reference herein)
10.08 Amendment No. 3 to the OGE Energy Corp. Restoration of Retirement
Income Plan. (Filed as Exhibit 10.13 to OGE Energy's Form 10-K
for the year ended December 31, 2000 (File No. 1-12579) and
incorporated by reference herein)
10.09 Amendment No. 4 to the OGE Energy Corp. Restoration of Retirement
Income Plan. (Filed as Exhibit 10.14 to OGE Energy's Form 10-K
for the year ended December 31, 2000 (File No. 1-12579) and
incorporated by reference herein)
10.10 OGE Energy Corp. Supplemental Executive Retirement Plan, as amended.
(Filed as Exhibit 10.15 to OGE Energy's Form 10-K for the year
ended December 31, 1996 (File No. 1-12579) and incorporated by
reference herein)
10.11 Company's Annual Incentive Compensation Plan. (Filed as Exhibit 10.12
to OGE Energy's Form 10-K for the year ended December 31, 1998
(File No. 1-12579) and incorporated by reference herein)
10.12 OGE Energy Corp. Deferred Compensation Plan and Amendment No. 1 to
OGE Energy Corp. Deferred Compensation Plan.
10.13 Copy of Amended and Restated Rights Agreement, dated as of October 10,
2000 between OGE Energy Corp. and Chase Mellon Shareholder
Services, LLC, as Rights Agent. (Filed as Exhibit 4.1 to OGE
Energy's Form 8-K filed on November 1, 2000 (File No. 1-12579)
and incorporated by reference herein)
10.14 Copy of Settlement Agreement with Oklahoma Corporation Commission
Staff, the Oklahoma Attorney General and others relating to
OG&E’s rate case. (Filed as Exhibit 99.02 to OGE
Energy’s Form 10-Q for the Quarter ended September 30, 2002
(File No. 1-12579) and incorporated by reference herein)
10.15 Copy of Employment Agreement with Peter B. Delaney.
10.16 Copy of Severance Agreement with Roger A. Farrell.
155
10.17 Credit Agreement dated January 8, 2003 between OGE Energy Corp. and
Bank of America, N.A.
10.18 Credit Agreement dated June 27, 2002 between OG&E, Bank One, NA
and Wachovia Bank, National Association.
10.19 Revolving Note Agreement as amended by Amendments No. 1 and No. 2,
dated April 6, 2002 between OGE Energy Corp. and Bank of
Oklahoma, N.A.
10.20 Credit Agreement dated January 15, 1999 between OGE Energy Corp. and
The First National Bank of Chicago, NationsBank, N.A. and Bank
of Oklahoma, N.A.
16.01 Letter of Arthur Andersen LLP regarding change in certifying
accountant. (Filed as Exhibit 16.01 to OGE Energy's Form 8-K
filed on May 21, 2002 (File No. 1-12579) and incorporated by
reference herein)
21.01 Subsidiaries of the Registrant.
23.01 Consent of Ernst and Young LLP.
24.01 Power of Attorney.
99.01 Cautionary Statement for Purposes of the "Safe Harbor" Provisions of
the Private Securities Litigation Reform Act of 1995.
99.02 Certification Pursuant to 18 U.S.C. Section 1350 As Adopted Pursuant
to Section 906 of the Sarbanes-Oxley Act of 2002.
156
Executive Compensation Plans and Arrangements
10.05 Form of Change of Control Agreement for Officers of the Company and
OG&E. (Filed as Exhibit 10.07 to OGE Energy's Form 10-K for
the year ended December 31, 1996 (File No. 1-12579) and
incorporated by reference herein)
10.06 Company's Stock Incentive Plan. (Filed as Exhibit 10.07 to OGE
Energy's Form 10-K for the year ended December 31, 1998 (File No.
1-12579) and incorporated by reference herein)
10.07 OGE Energy Corp. Restoration of Retirement Income Plan, as amended by
Amendments No. 1 and No. 2. (Filed as Exhibit 10.12 to OGE
Energy's Form 10-K for the year ended December 31, 1996 (File No.
1-12579) and incorporated by reference herein)
10.08 Amendment No. 3 to the OGE Energy Corp. Restoration of Retirement
Income Plan. (Filed as Exhibit 10.13 to OGE Energy's Form 10-K
for the year ended December 31, 2000 (File No. 1-12579) and
incorporated by reference herein)
10.09 Amendment No. 4 to the OGE Energy Corp. Restoration of Retirement
Income Plan. (Filed as Exhibit 10.14 to OGE Energy's Form 10-K
for the year ended December 31, 2000 (File No. 1-12579) and
incorporated by reference herein)
10.10 OGE Energy Corp. Supplemental Executive Retirement Plan, as amended.
(Filed as Exhibit 10.15 to OGE Energy's Form 10-K for the year
ended December 31, 1996 (File No. 1-12579) and incorporated by
reference herein)
10.11 Company's Annual Incentive Compensation Plan. (Filed as Exhibit 10.12
to OGE Energy's Form 10-K for the year ended December 31, 1998
(File No. 1-12579) and incorporated by reference herein)
10.12 OGE Energy Corp. Deferred Compensation Plan and Amendment No. 1 to
OGE Energy Corp. Deferred Compensation Plan.
10.15 Copy of Employment Agreement with Peter B. Delaney.
10.16 Copy of Severance Agreement with Roger A. Farrell.
157
(b) Reports on Form 8-K
The Company filed a Current Report on Form 8-K on October 11, 2002 to report the rate case settlement of its subsidiary, Oklahoma Gas and Electric Company.
The Company filed a Current Report on Form 8-K on October 18, 2002 to report performance improvements and enhancements of its unregulated business subsidiary, Enogex Inc.
The Company filed a Current Report on Form 8-K on November 21, 2002 to report the approval of the rate case settlement of its subsidiary, Oklahoma Gas and Electric Company.
158
OGE ENERGY CORP.
SCHEDULE II - Valuation and Qualifying Accounts
Additions
Balance at Charged to Charged to Balance at
Beginning Costs and Other End of
Description of Period Expenses Accounts Deductions Period
(In millions)
Year Ended December 31, 2000
Reserve for Uncollectible Accounts $ 5.3 $ 9.8 - $ 8.4 (A) $ 6.7
Year Ended December 31, 2001
Reserve for Uncollectible Accounts $ 6.7 $18.5 - $15.5 (A) $ 9.7
Year Ended December 31, 2002
Reserve for Uncollectible Accounts $ 9.7 $11.0 $3.7 $10.8 (A) $13.6
(A) Uncollectible accounts receivable written off, net of recoveries.
159
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, as amended, the Registrant has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Oklahoma City, and State of Oklahoma on the 25th day of March, 2003.
OGE ENERGY CORP.
(REGISTRANT)
/s/ Steven E. Moore
----------------------------------
By Steven E. Moore
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 in the capacities and on the dates indicated.
Signature Title Date
- ------------------------- -------------------------------- --------------
/ s / Steven E. Moore
Steven E. Moore Principal Executive
Officer and Director; March 25, 2003
/ s / James R. Hatfield
James R. Hatfield Principal Financial Officer; and March 25, 2003
/ s / Donald R. Rowlett
Donald R. Rowlett Principal Accounting Officer. March 25, 2003
Herbert H. Champlin Director;
Luke R. Corbett Director;
William E. Durrett Director;
Martha W. Griffin Director;
John D. Groendyke Director;
Hugh L. Hembree, III Director;
Robert Kelley Director;
Ronald H. White, M.D. Director; and
J. D. Williams Director.
/ s / Steven E. Moore
By Steven E. Moore (attorney-in-fact) March 25, 2003
160
CERTIFICATIONS
I, Steven E. Moore, certify that:
1. I have reviewed this annual report on Form 10-K of OGE Energy Corp.;
2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):
a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and
6. The registrant's other certifying officers and I have indicated in this annual report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.
Date: March 25, 2003
/s/ Steven E. Moore
- -----------------------------------------
Steven E. Moore
Chairman of the Board, President and
Chief Executive Officer
161
CERTIFICATIONS
I, James R. Hatfield, certify that:
1. I have reviewed this annual report on Form 10-K of OGE Energy Corp.;
2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):
a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and
6. The registrant's other certifying officers and I have indicated in this annual report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.
Date: March 25, 2003
/s/ James R. Hatfield
- ------------------------------
James R. Hatfield
Senior Vice President and
Chief Financial Officer
162
Exhibit Index
Exhibit No. Description
2.01 Purchase Agreement, dated as of May 14, 1999, by and between Tejas
Gas, LLC and Enogex Inc. (Filed as Exhibit 2.01 to OGE Energy's
Form 10-Q for the quarter ended June 30, 1999 (File No. 1-12579)
and incorporated by reference herein)
3.01 Copy of Restated Certificate of Incorporation. (Filed as Exhibit 3.01
to OGE Energy's Form 10-K for the year ended December 31, 1996
(File No. 1-12579) and incorporated by reference herein)
3.02 By-laws. (Filed as Exhibit 3.02 to OGE Energy's Form 10-K for the year
ended December 31, 1996 (File No. 1-12579) and incorporated by
reference herein)
4.01 Copy of Trust Indenture, dated October 1, 1995, from OG&E 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 Copy of Supplemental Trust Indenture No. 1, dated October 16, 1995,
being a supplemental instrument to Exhibit 4.01 hereto. (Filed as
Exhibit 4.01 to OG&E's Form 8-K Report dated October 23,
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 OG&E's Form 8-K filed on 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 OG&E's Form 8-K filed on April 16, 1998 (File No.
1-1097) and incorporated by reference herein)
163
4.05 Supplemental Indenture No. 4, dated as of October 15, 2000, being a
supplement instrument to Exhibit 4.01 hereto. (Filed as Exhibit
4.02 to OG&E's Form 8-K filed on October 20, 2000 (File No.
1-1097) and incorporated by reference herein)
10.01 Coal Supply Agreement dated March 1, 1973, between OG&E and
Atlantic Richfield Company. (Filed as Exhibit 5.19 to
Registration Statement No. 2-59887 and incorporated by reference
herein)
10.02 Amendment dated April 1, 1976, to Coal Supply Agreement dated March 1,
1973, between OG&E and Atlantic Richfield Company, together
with related correspondence. (Filed as Exhibit 5.21 to
Registration Statement No. 2-59887 and incorporated by reference
herein)
10.03 Second Amendment dated March 1, 1978, to Coal Supply Agreement dated
March 1, 1973, between OG&E and Atlantic Richfield Company.
(Filed as Exhibit 5.28 to Registration Statement No. 2-62208 and
incorporated by reference herein)
10.04 Amendment dated June 27, 1990, between OG&E and Thunder Basin Coal
Company, to Coal Supply Agreement dated March 1, 1973, between
OG&E and Atlantic Richfield Company. (Filed as Exhibit 10.04
to OG&E’s Form 10-K Report for the year ended December
31, 1994, (File No. 1-1097) and incorporated by reference herein)
[Confidential Treatment has been requested for certain portions
of this exhibit.]
10.05 Form of Change of Control Agreement for Officers of the Company and
OG&E. (Filed as Exhibit 10.07 to OGE Energy's Form 10-K for
the year ended December 31, 1996 (File No. 1-12579) and
incorporated by reference herein)
10.06 Company's Stock Incentive Plan. (Filed as Exhibit 10.07 to OGE
Energy's Form 10-K for the year ended December 31, 1998 (File No.
1-12579) and incorporated by reference herein)
164
10.07 OGE Energy Corp. Restoration of Retirement Income Plan, as amended by
Amendments No. 1 and No. 2. (Filed as Exhibit 10.12 to OGE
Energy's Form 10-K for the year ended December 31, 1996 (File No.
1-12579) and incorporated by reference herein)
10.08 Amendment No. 3 to the OGE Energy Corp. Restoration of Retirement
Income Plan. (Filed as Exhibit 10.13 to OGE Energy's Form 10-K
for the year ended December 31, 2000 (File No. 1-12579) and
incorporated by reference herein)
10.09 Amendment No. 4 to the OGE Energy Corp. Restoration of Retirement
Income Plan. (Filed as Exhibit 10.14 to OGE Energy's Form 10-K
for the year ended December 31, 2000 (File No. 1-12579) and
incorporated by reference herein)
10.10 OGE Energy Corp. Supplemental Executive Retirement Plan, as amended.
(Filed as Exhibit 10.15 to OGE Energy's Form 10-K for the year
ended December 31, 1996 (File No. 1-12579) and incorporated by
reference herein)
10.11 Company's Annual Incentive Compensation Plan. (Filed as Exhibit 10.12
to OGE Energy's Form 10-K for the year ended December 31, 1998
(File No. 1-12579) and incorporated by reference herein)
10.12 OGE Energy Corp. Deferred Compensation Plan and Amendment No. 1 to
OGE Energy Corp. Deferred Compensation Plan.
10.13 Copy of Amended and Restated Rights Agreement, dated as of October 10,
2000 between OGE Energy Corp. and Chase Mellon Shareholder
Services, LLC, as Rights Agent. (Filed as Exhibit 4.1 to OGE
Energy's Form 8-K filed on November 1, 2000 (File No. 1-12579)
and incorporated by reference herein)
10.14 Copy of Settlement Agreement with Oklahoma Corporation Commission
Staff, the Oklahoma Attorney General and others relating to
OG&E’s rate case. (Filed as Exhibit 99.02 to OGE
Energy’s Form 10-Q for the Quarter ended September 30, 2002
(File No. 1-12579) and incorporated by reference herein)
10.15 Copy of Employment Agreement with Peter B. Delaney.
10.16 Copy of Severance Agreement with Roger A. Farrell.
165
10.17 Credit Agreement dated January 8, 2003, between OGE Energy Corp. and
Bank of America, N.A.
10.18 Credit Agreement dated June 27, 2002 between OG&E, Bank One, NA and
Wachovia Bank, National Association.
10.19 Revolving Note Agreement as amended by Amendments No. 1 and No. 2,
dated April 6, 2002 between OGE Energy Corp. and Bank of
Oklahoma, N.A.
10.20 Credit Agreement dated January 15, 1999 between OGE Energy Corp. and
The First National Bank of Chicago, NationsBank, N.A. and Bank
of Oklahoma, N.A.
16.01 Letter of Arthur Andersen LLP regarding change in certifying
accountant. (Filed as Exhibit 16.01 to OGE Energy's Form 8-K
filed on May 21, 2002 (File No. 1-12579) and incorporated by
reference herein)
21.01 Subsidiaries of the Registrant.
23.01 Consent of Ernst and Young LLP.
24.01 Power of Attorney.
99.01 Cautionary Statement for Purposes of the "Safe Harbor" Provisions of
the Private Securities Litigation Reform Act of 1995.
99.02 Certification Pursuant to 18 U.S.C. Section 1350 As Adopted Pursuant
to Section 906 of the Sarbanes-Oxley Act of 2002.
166
Exhibit 10.12
OGE ENERGY CORP.
DEFERRED COMPENSATION PLAN
As Amended and Restated Effective March 27, 2001
TABLE OF CONTENTS
Page
I. PURPOSE AND EFFECTIVE DATE...................................................................... 1
1.1. Purpose.................................................................................. 1
1.2. Effective Date........................................................................... 1
1.3. Continuation of Prior Plan............................................................... 1
II. DEFINITIONS..................................................................................... 1
2.1. "Account"................................................................................ 1
2.2. "Administrator".......................................................................... 1
2.3. "Affiliate".............................................................................. 1
2.4. "Base Salary"............................................................................ 2
2.5. "Beneficiary"............................................................................ 2
2.6. "Board".................................................................................. 2
2.7. "Bonus".................................................................................. 2
2.8. "Change in Control"...................................................................... 2
2.9. "Code"................................................................................... 3
2.10. "Company"................................................................................ 3
2.11. "Compensation"........................................................................... 3
2.12. "Deferral Election"...................................................................... 3
2.13. "Director Compensation".................................................................. 3
2.14. "Disability"............................................................................. 4
2.15. "Discretionary Credit"................................................................... 4
2.16. "Election Period"........................................................................ 4
2.17. "Eligible Director"...................................................................... 4
2.18. "Eligible Employee"...................................................................... 4
2.19. "Matching Credit"........................................................................ 4
2.20. "Participant"............................................................................ 4
2.21. "Plan"................................................................................... 4
2.22. "Plan Year".............................................................................. 4
2.23. "Prior Plan"............................................................................. 4
2.24. "Retirement"............................................................................. 4
2.25. "RSP".................................................................................... 4
2.26. "Supplemental RSP"....................................................................... 4
2.27. "Valuation Date"......................................................................... 4
III. PARTICIPATION................................................................................... 5
IV. DEFERRAL OF COMPENSATION........................................................................ 5
4.1. Deferral of Base Salary.................................................................. 5
4.2. Deferral of Bonus........................................................................ 5
4.3. Deferral of Director Compensation........................................................ 5
4.4. Deferral Elections....................................................................... 5
4.5. Crediting of Deferral Elections.......................................................... 6
i
TABLE OF CONTENTS
(continued)
Page
V. EMPLOYER CREDITS................................................................................ 6
5.1. Matching Credits......................................................................... 6
5.2. Discretionary Credits.................................................................... 7
5.3. Vesting.................................................................................. 7
5.4. Acceleration of Vesting.................................................................. 7
VI. PLAN ACCOUNTS................................................................................... 7
6.1. Valuation of Accounts.................................................................... 7
6.2. Crediting of Investment Return........................................................... 8
6.3. Assumed Investment Alternatives.......................................................... 8
6.4. Investment Alternatives After Death...................................................... 9
VII. PAYMENT OF BENEFITS............................................................................. 9
7.1. Distribution at Specific Future Date..................................................... 9
7.2. Distribution Upon Retirement or Disability............................................... 9
7.3. Distribution On Other Termination of Employment.......................................... 10
7.4. Unscheduled Withdrawal................................................................... 10
7.5. Unforeseeable Emergency.................................................................. 10
7.6. Time and Form of Elections............................................................... 10
7.7. Form of Payment; Withholding............................................................. 11
VIII. DEATH BENEFITS.................................................................................. 11
8.1. Death Prior to Commencement of Benefits.................................................. 11
8.2. Death After Commencement of Benefits..................................................... 11
8.3. Post-Retirement Survivor Benefit......................................................... 12
8.4. Other Conditions......................................................................... 12
8.5. Administrator Discretion Regarding Form.................................................. 12
IX. ADMINISTRATION.................................................................................. 12
9.1. Authority of Administrator............................................................... 12
9.2. Participant's Duty to Furnish Information................................................ 13
9.3. Claims Procedure......................................................................... 13
X. AMENDMENT AND TERMINATION....................................................................... 13
XI. MISCELLANEOUS................................................................................... 13
11.1. No Implied Rights; Rights on Termination of Service...................................... 13
11.2. No Employment Rights..................................................................... 14
11.3. Unfunded Plan............................................................................ 14
11.4. Nontransferability....................................................................... 14
11.5. Successors and Assigns................................................................... 14
11.6. Applicable Law........................................................................... 15
ii
OGE ENERGY CORP.
DEFERRED COMPENSATION PLAN
I. PURPOSE AND EFFECTIVE DATE
1.1. Purpose. The OGE Energy Corp. Deferred Compensation Plan has been established by OGE Energy Corp. to attract and retain key management employees by providing a tax-deferred capital accumulation vehicle and to supplement such employees' 401(k) contributions, thereby encouraging savings for retirement.
1.2. Effective Date. The following provisions constitute an amendment and restatement of the Plan, effective March 27, 2001. The Plan shall remain in effect until terminated in accordance with Article 10.
1.3. Continuation of Prior Plan. The Plan as originally adopted was intended to be an amendment, restatement and continuation of the OGE Energy Corp. Restoration of Retirement Savings Plan (the "Supplemental RSP"). Effective March 27, 2001, the OGE Energy Corp. Directors' Deferred Compensation Plan (formerly known as the Stock Equivalent and Deferred Compensation Plan For Directors of OGE Energy Corp.) (the "Directors' Plan") was merged with and into the Plan. This amendment and restatement of the Plan is also intended to be an amendment, restatement and continuation of the Directors' Plan.
II. DEFINITIONS
When used in the Plan and initially capitalized, the following words and phrases shall have the meanings indicated:
2.1. "Account" means the recordkeeping account established for each Participant in the Plan for purposes of accounting for the amount of Base Salary, Bonus or Director Compensation deferred under Article 4 and Matching and Discretionary Credits, if any, to be credited under Article 5, adjusted periodically to reflect assumed investment return on such deferrals, Matching and Discretionary Credits in accordance with Article 6.
2.2. "Administrator" means the Benefits Committee or such other individual or committee appointed by the Benefits Oversight Committee to administer the Plan in accordance with Article 9.
2.3. "Affiliate" means (i) any corporation, partnership, joint venture, trust, association or other business enterprise which is a member of the same controlled group of corporations, trades or businesses as the Company within the meaning of Code Section 414, and (ii) any other entity that is designated as an Affiliate by the Board.
2.4. "Base Salary" means a Participant's base salary as shown in the personnel records of the Company.
2.5. "Beneficiary" means the person or entity designated by the Participant to receive the Participant's Plan benefits in the event of the Participant's death. If the Participant does not designate a Beneficiary, or if the Participant's designated Beneficiary predeceases the Participant, the Participant's estate shall be the Beneficiary under the Plan.
2.6. "Board" means the Board of Directors of the Company.
2.7. "Bonus" means the annual bonus payable to a Participant under the OGE Energy Corp. Annual Incentive Compensation Plan, and any other bonus which the Administrator, in its sole discretion, determines is eligible for deferral under the Plan.
2.8. "Change in Control" means the happening of any of the following events:
(a) an acquisition by any individual, entity or group (within the meaning of Section 13(d)(3) or 14(d)(2) of the Securities Exchange Act of 1934 ("Exchange Act")) (a "Person") of beneficial ownership (within the meaning of Rule 13d-3 promulgated under the Exchange Act) of 20% or more of either (1) the then outstanding shares of common stock of the Company (the "Outstanding Company Common Stock") or (2) the combined voting power of the then outstanding voting securities of the Company entitled to vote generally in the election of directors (the "Outstanding Company Voting Securities"); excluding however the following: (1) any acquisition directly from the Company, (2) any acquisition by the Company, (3) any acquisition by any employee benefit plan (or related trust) sponsored by or maintained by the Company or any corporation controlled by the Company or (4) any acquisition by any corporation pursuant to a transaction which complies with clauses (1), (2) and (3) of subsection (c) of this Section 2.8;
(b) a change in the composition of the Board such that the individuals who as of January 1, 2000, constitute the Board (the "Incumbent Board") cease for any reason to constitute at least a majority of the Board; provided, however, for purposes of this Section 2.8, that any individual who becomes a member of the Board subsequent to January 1, 2000, whose election or nomination for election by the Company's shareowners was approved by a vote of at least a majority of those individuals then comprising the Incumbent Board shall be considered as though such individual were a member of the Incumbent Board; but provided further, that any such individual whose initial assumption of office occurs as a result of either an actual or threatened election contest with respect to the election or removal of directors or other actual or threatened solicitation of proxies or consents by or on behalf of a Person other than the Board shall not be so considered as a member of the Incumbent Board; or
2
(c) consummation of a reorganization, merger, share exchange or consolidation or sale or other disposition of all or substantially all of the assets of the Company (a "Business Combination"), excluding, however, such a Business Combination pursuant to which (1) all or substantially all of the individuals and entities who are the beneficial owners, respectively, of the Outstanding Company Common Stock and Outstanding Company Voting Securities immediately prior to such Business Combination beneficially own, directly or indirectly, more than 60% of, respectively, the outstanding shares of common stock and the combined voting power of the then outstanding voting securities entitled to vote generally in the election of directors, as the case may be, of the corporation resulting from such Business Combination (including, without limitation, a corporation which as a result of such transaction owns the Company or all or substantially all of the Company's assets either directly or through one or more subsidiaries) in substantially the same proportions as their ownership, immediately prior to such Business Combination, of the Outstanding Company Common Stock and Outstanding Company Voting Securities, as the case may be, (2) no Person (other than the corporation resulting from such Business Combination or any employee benefit plan (or related trust) of the Company or such corporation resulting from such Business Combination) beneficially owns, directly or indirectly, 20% or more of, respectively, the outstanding shares of common stock of the corporation resulting from such Business Combination or the combined voting power of the outstanding voting securities of such corporation except to the extent that such ownership existed prior to the Business Combination and (3) at least a majority of the members of the board of directors of the corporation resulting from such Business Combination were members of the Incumbent Board at the time of the execution of the initial agreement, or the action of the Board providing for such Business Combination; or
(d) the approval by the shareholders of the Company of a complete liquidation or dissolution of the Company.
2.9. "Code" means the Internal Revenue Code of 1986, as amended.
2.10. "Company" means OGE Energy Corp. and any successor thereto.
2.11. "Compensation" means Base Salary and/or Bonus with respect to an Eligible Employee and means Director Compensation with respect to an Eligible Director.
2.12. "Deferral Election" means the election made by an Eligible Employee or Eligible Director to defer Compensation in accordance with Article 4.
2.13. "Director Compensation" means annual retainer and attendance fees payable to an Eligible Director for services as a member of the Board.
3
2.14. "Disability" shall have the same meaning as permanent disability under the RSP. A Participant who has ceased active employment with the Company and its Affiliates because of Disability will be treated as having terminated employment for purposes of the Plan.
2.15. "Discretionary Credit" means an amount credited to a Participant's Account, as determined by the Company in its sole discretion.
2.16. "Election Period" means the period specified by the Administrator during which a Deferral Election may be made with respect to Compensation payable for a Plan Year.
2.17. "Eligible Director" means a member of the Board who is not also an employee of the Company.
2.18. "Eligible Employee" means, with respect to any Plan Year, unless determined otherwise by the Board, an employee of the Company or an Affiliate whose projected compensation (within the meaning of the RSP) for the immediately preceding Plan Year is at least $100,000.
2.19. "Matching Credit" means the amount credited to a Participant's Account pursuant to Section 5.1.
2.20. "Participant" means an Eligible Employee or Eligible Director who has elected to defer Compensation or who has been credited with a Discretionary Credit.
2.21. "Plan" means the OGE Energy Corp. Deferred Compensation Plan, as amended from time to time.
2.22. "Plan Year" means the calendar year.
2.23. "Prior Plan" means the Plan as in effect prior to this amendment and restatement, the Supplemental RSP or the Directors' Plan, as applicable.
2.24. "Retirement" means termination of employment with the Company or its Affiliates as defined by the OGE Energy Corp. Employees' Retirement Plan.
2.25. "RSP" means the OGE Energy Corp. Employees' Stock Ownership and Retirement Savings Plan, as amended from time to time.
2.26. "Supplemental RSP" has the meaning ascribed to such term in Section 1.3.
2.27. "Valuation Date" means a date on which a Participant's Account is valued, which shall be each business day, and such other dates as may be specified by the Administrator.
4
III. PARTICIPATION
An Eligible Employee or Eligible Director shall become a Participant in the Plan by filing a Deferral Election with the Administrator in accordance with Article 4. An Eligible Employee or Eligible Director who is not otherwise a Participant in the Plan shall become a Participant in the Plan on the date he or she is credited with a Discretionary Credit. If the Administrator determines that participation by one or more Participants shall cause the Plan to be subject to Part 2, 3 or 4 of Title I of the Employee Retirement Income Security Act of 1974, as amended, the entire interest of such Participant or Participants under the Plan shall be paid immediately to such Participant or Participants or shall otherwise be segregated from the Plan in the discretion of the Administrator, and such Participant or Participants shall cease to have any interest under the Plan.
IV. DEFERRAL OF COMPENSATION
4.1. Deferral of Base Salary. An Eligible Employee may elect to defer up to 70% of his or her Base Salary for a Plan Year by filing a Deferral Election in accordance with Section 4.4.
4.2. Deferral of Bonus. An Eligible Employee may elect to defer up to 100% of his or her Bonus for a Plan Year by filing a Deferral Election in accordance with Section 4.4.
4.3. Deferral of Director Compensation. An Eligible Director may elect to defer up to 100% of his or her Director Compensation for a Plan Year by filing a Deferral Election in accordance with Section 4.4.
4.4. Deferral Elections. A Participant's Deferral Election shall be in writing, and shall be filed with the Administrator at such time and in such manner as the Administrator shall provide, subject to the following:
(a) A Deferral Election shall be made during the election period established by the Administrator which, in the case of Base Salary and Director Compensation, shall end no later than the day preceding the first day of the Plan Year in which such Base Salary or Director Compensation would otherwise be payable and, in the case of Bonus, shall end no later than the last day of the Plan Year preceding the Plan Year to which such Bonus relates.
(b) Deferral Elections may be expressed as a percentage or fixed dollar amount of Base Salary, Bonus, or Director Compensation, as applicable, within the limits provided under the Plan.
(c) The minimum annual deferral under the Plan shall be $2,500 and any Deferral Election which would provide a lesser deferral for a Plan Year shall be disregarded for such Plan Year.
5
(d) If permitted by the Administrator, the Participant may elect with respect to a Plan Year, that deferrals of Base Salary and Bonus shall be made to the Plan starting when the Participant has made the maximum deferrals permitted for the Plan Year under the RSP because of limitations on such deferrals contained in the RSP or the Code. Any such election will be based on the deferral percentage elected for that Plan Year under the RSP and may not be revoked after the beginning of the Plan Year.
Once made, a Deferral Election shall remain in effect for subsequent Plan Years unless changed or revoked by the Participant in accordance with rules established by the Administrator. Any such modification or revocation shall be effective for the Plan Year following the Plan Year in which it is made; provided that such revocation shall become effective as soon as practicable in the event it is made because of the Participant’s Disability or if the Administrator, in its sole discretion, determines that the Participant has suffered a severe financial hardship or a bona fide administrative mistake was made. If a Deferral Election is revoked in accordance with the preceding sentence, the Participant may not make a new Deferral Election until the election period established by the Administrator for making deferrals for the next Plan Year.
Notwithstanding the foregoing provisions of this Section 4.4, the Administrator may provide that an individual who becomes an Eligible Director after the first day of a Plan Year may make a Deferral Election within 30 days of becoming an Eligible Director, which Deferral Election shall relate to Director Compensation earned for periods after the date such election is made.
4.5. Crediting of Deferral Elections. The amount of Compensation that a Participant elects to defer under the Plan shall be credited by the Company to the Participant's Account as of the first day of the month in which the Compensation would have been payable absent the Deferral Election.
V. EMPLOYER CREDITS
5.1. Matching Credits. A Participant (other than an Eligible Director) who has made a Deferral Election for a Plan Year shall be credited with a "Matching Credit" equal to the excess of (i) the matching contribution that would have been made under the RSP for such Plan Year if the first 6% of the Participant's total compensation deferred under this Plan and the RSP were treated as Tax-Deferred Contributions under the RSP, without regard to any limitations on such matching contributions contained in the RSP due to the application of Sections 401(a)(17), 401(k)(3), 401(m), 402(g) or 415 of the Code, over (ii) the greater of (A) maximum amount of matching contributions the Participant is eligible to receive under the RSP with respect to Tax Deferred Contributions (determined by taking into account the provisions of the RSP), or (B) the actual matching contributions received under the RSP with respect to all contributions. Such Matching Credit shall be credited
6
to the Participant's Account at the same time that the underlying Base Salary or Bonus deferral is credited to the Participant's Account.
5.2. Discretionary Credits. The Administrator may award a Participant a Discretionary Credit in an amount determined by the Administrator in its sole discretion. Any such Discretionary Credit shall be credited to the Participant's Account at the time determined by the Administrator and shall be subject to such terms and conditions as the Administrator may establish, including those relating to how such credit shall be deemed invested.
5.3. Vesting. A Participant's Matching Credits shall vest based on the Participant's years of service (within the meaning of the RSP) under the following schedule:
Percentage of
Years of Service Matching Credits Vested
Less than 3 0%
3 but less than 4 30%
4 but less than 5 40%
5 but less than 6 60%
6 but less than 7 80%
7 or more 100%
A Participant’s Discretionary Credit, if any, shall vest in accordance with the terms established by the Administrator at the time it is awarded. Subject to Section 5.4, any portion of a Participant’s Account that is not vested upon the Participant’s termination of employment with the Company and its Affiliates shall be permanently forfeited.
5.4. Acceleration of Vesting. Notwithstanding the provisions of Section 5.3, a Participant's Matching Credits and Discretionary Credits, if any, shall become fully vested upon the following events:
(a) the Participant's Retirement;
(b) the Participant's Disability;
(c) A Change in Control; or
(d) Termination of the Plan under Article 10.
VI. PLAN ACCOUNTS
6.1. Valuation of Accounts. The Administrator shall establish an Account for each Participant who has filed a Deferral Election to defer Compensation or who has been awarded a Discretionary Credit, or who had an account under the Prior Plans as of the effective date of this restatement of the Plan. Such Account shall be credited with a Participant's deferrals, Matching Credits and Discretionary Credits
7
as set forth in Sections 4.5, 5.1 and 5.2, respectively, and with the Participant's Prior Plan account balance, if any. As of each Valuation Date, the Participant's Account shall be adjusted upward or downward to reflect (i) the investment return to be credited as of such Valuation Date pursuant to Section 6.2, (ii) the amount of distributions, if any, to be debited as of that Valuation Date under Article 7 or Article 8, and (iii) the amount of forfeitures, if any, to be debited under Sections 5.3 or 7.4.
6.2. Crediting of Investment Return. Subject to such rules and limitations as the Administrator may determine, each Participant shall designate from among the assumed investment alternatives established by the Administrator under Section 6.3, one or more assumed investments in which the amounts credited to his or her Account shall be deemed invested. As of each Valuation Date, a Participant's Account balance shall be adjusted upward or downward for increases and decreases in the fair market value of the investments in which it is deemed invested during the period since the immediately preceding Valuation Date. On or before the first day of each month, a Participant may make a new election with respect to the assumed investments in which his Account shall be deemed invested in the future. Any such election shall be made in the form and at the time specified by the Administrator; provided, however, prior to a Participant's attainment of age 55, Matching Credits shall be deemed to be invested in the assumed investment alternative based on the Company's common stock. The portion of a Participant's Account that is deemed invested in Company common stock, if any, shall also be credited with deemed dividends as of the first day of the month in which dividends on Company common stock are paid.
If the Participant is an Eligible Director who elected to have any portion of his or her account under the prior Directors’ Plan invested in split dollar life insurance, the portion so elected shall continue to be subject to the split dollar life insurance provisions of the prior Directors’ Plan and no assumed investment elections may be made with respect to such amount under this Section 6.2.
Participants who are subject to the reporting requirements of Section 16 of the Securities Exchange Act of 1934 may be subject to election restrictions with respect to the assumed investment alternative based on the Company’s common stock, including a restriction that such election will not take effect until approved by the Secretary of the Company.
6.3. Assumed Investment Alternatives. The Administrator shall designate the assumed investment alternatives that will be available from time to time under the Plan for purposes of measuring a Participant's investment return under Section 6.2. Such assumed investment alternatives shall include an assumed investment in Company common stock. The value of deemed investments in Company common stock shall be determined based on the fair market value of a share of Company common stock as reported on the New York Stock Exchange composite tape at the close of business on the last business day of the month preceding the date on which the amount or value of such investment is being determined.
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6.4. Investment Alternatives After Death. For periods after the Valuation Date coincident with or following a Participant's death, the Participant's Account balance shall be treated as if it were invested in a fixed interest rate account at prevailing short-term interest rates, as determined by the Administrator. Beneficiaries shall not be permitted to make elections with respect to assumed investment alternatives under the Plan.
VII. PAYMENT OF BENEFITS
7.1. Distribution at Specific Future Date. At the time a Participant initially elects to participate in the Plan, the Participant may elect one or more future Valuation Dates on which all or a portion of his or her Account as of such date shall be paid. Any such future date shall be a Valuation Date in a specific future year which is at least two Plan Years after the Plan Year for which the initial Deferral Election is made; provided, however, that only one distribution per Plan Year may be elected under this Section 7.1; provided, further that, if the Participant elects a distribution at one or more specific future dates and has a termination of employment prior to any such date, distribution shall commence pursuant to Sections 7.2, 7.3, 8.1 or 8.2, as applicable. A distribution election under this Section 7.1 may be revoked or extended to a Valuation Date in a future Plan Year by filing a revocation or extension election with the Administrator at least 12 months prior to the first day of the Plan Year in which such distribution was scheduled to take place. Only one subsequent change shall be permitted with respect to any distribution election.
7.2. Distribution Upon Retirement or Disability; Termination of Board Service. If a Participant terminates employment with the Company and/or Affiliates by reason of Retirement or Disability or, with respect to an Eligible Director, upon termination of service on the Board, distribution of the Participant's Account shall be made or commence as of one of the following dates elected by the Participant in his or her Deferral Election:
(a) the Valuation Date coincident with or next following the Participant's termination of employment or Board service, as applicable; or
(b) the first Valuation Date in the Plan Year immediately following the Plan Year in which such termination of employment or Board service occurs.
Distribution under this Section 7.2 shall be made (i) in a lump sum, (ii) in substantially equal annual installments of up to 15 years, or (iii) in a combination of (i) and (ii), as elected by the Participant. A Participant may change the time and form of his or her distribution election under this Section 7.2 by filing a new election with the Administrator; provided, however, that any election that has not been on file with the Administrator at least 12 months prior to the first day of the Plan Year in which the Participant’s termination of employment or service occurs shall be void and disregarded. Notwithstanding the foregoing, a Participant whose termination of employment occurs by reason of Disability may request that
9
the Administrator distribute the Participant’s Account in a lump sum payment following such termination of employment, in which case the Administrator, in its sole discretion, shall determine whether to make payment in a lump sum. If the Participant does not have a valid election on file with the Administrator at the time of Retirement or Disability, the Participant’s Account shall be paid in a single sum under paragraph (a) next above.
7.3. Distribution On Other Termination of Employment. If a Participant's employment with the Company or Affiliates terminates for any reason other than Retirement, Disability or death, the Participant's Account shall be paid in a lump sum payment as soon as practicable following the Valuation Date coincident with or next following such termination of employment. Notwithstanding the foregoing, the Administrator, in its sole discretion, may elect to distribute the Participant's Account under this Section 7.3 in up to five substantially equal annual payments commencing as of the Valuation Date coincident with or next following the Participant's termination of employment.
7.4. Unscheduled Withdrawal. A Participant may request a withdrawal of all or a portion of his or her vested Account by filing an election with the Administrator specifying the amount of the Account to be withdrawn. Payment of such amount, adjusted by the amount forfeited in subsection (a) below, shall be made as of the first Valuation Date administratively practicable after such request is received, and shall be subject to the following:
(a) An amount equal to 10% of the withdrawal requested shall be debited to the Participant's Account and permanently forfeited.
(b) Any Deferral Election in effect at the time of such withdrawal shall be void for periods after such withdrawal.
(c) The Participant shall not be eligible to file a new Deferral Election until the election period for the Plan Year commencing at least one year after such withdrawal.
7.5. Unforeseeable Emergency. Prior to the date otherwise scheduled for payment under the Plan, upon showing an unforeseeable emergency, a Participant may request that the Administrator accelerate payment of all or a portion of his or her Account in an amount not exceeding the amount necessary to meet the unforeseeable emergency. For purposes of the Plan, an unforeseeable emergency means an unanticipated emergency that is caused by an event beyond the control of the Participant and that would result in severe financial hardship to the Participant if early withdrawal were not permitted. The determination of an unforeseeable emergency shall be made by the Administrator in its sole discretion, based on such information as the Administrator shall deem to be necessary.
7.6. Time and Form of Elections. All distribution and withdrawal elections under this Article 7 shall be made at the time and in the form established by the
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Administrator and shall be subject to such other rules and limitations that the Administrator, in its sole discretion, may establish.
7.7. Form of Payment; Withholding. All payments under the Plan shall be made in cash and are subject to the withholding of all applicable taxes.
VIII. DEATH BENEFITS
8.1. Death Prior to Commencement of Benefits.
(a) Participants other than Eligible Directors. If a Participant, other than an Eligible Director, dies prior to commencement of payment of his or her Account, the Participant's Beneficiary shall receive a survivor benefit in an amount equal to the sum of:
(i) the Participant's Account balance,
plus
(ii) the Participant's total Base Salary and Bonus deferrals under the Plan, multiplied by two.
(b) Eligible Directors. If a Participant who is an Eligible Director dies prior to commencement of payment of his or her Account, the Participant's Beneficiary shall receive a survivor benefit in an amount equal to the sum of:
(i) the Participant's Account balance,
plus
(ii) the Participant's total Director Compensation deferrals under the Plan for periods on or after January 1, 2000, multiplied by two.
Such survivor benefits shall be paid in a single lump sum as soon as practicable following the Participant’s death.
8.2. Death After Commencement of Benefits. Subject to Section 8.3, if a Participant terminates employment due to Retirement or Disability or, in the case of an Eligible Director, terminates service on the Board for any reason, and dies prior to the time his or her Account balance has been fully distributed, the Participant's Beneficiary shall receive the remaining portion of the Participant's Account at the regularly-scheduled date of payment for any remaining installment payments of the Participant's Account.
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8.3. Post-Retirement Survivor Benefit. If a Participant terminates employment by reason of Retirement and dies with an Eligible Spouse (defined below), then in addition to the remaining installments payable to the Participant's Beneficiary under Section 8.2, if any, the Participant's Eligible Spouse shall be entitled to a "Supplemental Retirement Benefit." The Supplemental Retirement Benefit shall be payable in the form of an annual annuity for the life of the Eligible Spouse. The amount of the annuity shall be the amount that would be payable if 50% of the Participant's Account balance as of the Valuation Date coincident with or next following the Participant's Retirement had been used to purchase an annual annuity for the life of the spouse, determined using interest and actuarial factors established by the Administrator. For purposes of this Section 8.3, the term "Eligible Spouse" means the person to whom the Participant was married on the date of his or her Retirement.
If such Participant does not have an Account balance under the Plan at the time of his or her death, payment of the annual Supplemental Retirement Benefit shall commence in the month following the Participant’s death. If the Participant has an Account balance at the time of death, payment of the annual Supplemental Retirement Benefit shall commence in the month that is 12 months after the month in which the last installment payment of the Participant’s Account is made. This Section 8.3 shall not apply to a Participant who is an Eligible Director.
8.4. Other Conditions. Notwithstanding the foregoing provisions of this Article 8, if the Participant's death occurs within two years of initial Plan participation, and such death occurs by reason of suicide (as reported on the Participant's death certificate or determined by the Administrator in good faith), the Participant's Beneficiary shall receive the Participant's Account balance as of the date of his or her death in full satisfaction of the Company's obligations under the Plan.
8.5. Administrator Discretion Regarding Form. Notwithstanding the foregoing provisions of this Article 8, a Beneficiary may request that the Administrator approve an alternate form of payment of survivor benefits under this Article 8 which request may be granted in the sole discretion of the Administrator.
IX. ADMINISTRATION
9.1. Authority of Administrator. The Administrator shall have full power and authority to carry out the terms of the Plan. The Administrator's interpretation, construction and administration of the Plan, including any adjustment of the amount or recipient of the payments to be made, shall be binding and conclusive on all persons for all purposes. Neither the Company, including its officers, employees or directors, nor the Administrator or the Board or any member thereof, shall be liable to any person for any action taken or omitted in connection with the interpretation, construction and administration of the Plan.
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9.2. Participant's Duty to Furnish Information. Each Participant shall furnish to the Administrator such information as it may from time to time request for the purpose of the proper administration of this Plan.
9.3. Claims Procedure. If a Participant or Beneficiary ("Claimant") is denied all or a portion of an expected benefit under this Plan for any reason, he or she may file a claim with the Administrator. The Administrator shall notify the Claimant within 90 days of allowance or denial of the claim, unless the Claimant receives written notice from the Administrator prior to the end of the 90-day period stating that special circumstances require an extension (of up to 90 additional days) of the time for decision. The notice of the decision shall be in writing, sent by mail to Claimant's last known address, and if a denial of the claim, shall contain the following information: (a) the specific reasons for the denial; (b) specific reference to pertinent provisions of the Plan on which the denial is based; and (c) if applicable, a description of any additional information or material necessary to perfect the claim, an explanation of why such information or material is necessary, and an explanation of the claims review procedure. A Claimant is entitled to request a review of any denial of his or her claim by the Board. The request for review must be submitted within 60 days of mailing of notice of the denial. Absent a request for review within the 60-day period, the claim shall be deemed to be conclusively denied. The Claimant or his or her representatives shall be entitled to review all pertinent documents, and to submit issues and comments orally and in writing. The Board shall render a review decision in writing within 60 days after receipt of a request for a review, provided that, in special circumstances the Board may extend the time for decision by not more than 60 days upon written notice to the Claimant. The Claimant shall receive written notice of the Board's review decision, together with specific reasons for the decision and reference to the pertinent provisions of the Plan.
X. AMENDMENT AND TERMINATION
The Board may amend or terminate the Plan at any time; provided, however, the Benefits Oversight Committee of the Company shall also have the authority to amend the Plan to the extent that such amendment (i) is necessary or desirable to comply with legal requirements, (ii) is a non-substantive administrative amendment, or (iii) does not result, alone or in the aggregate with other amendments, in an estimated annual cost to the Plan of $1 million or more. Notwithstanding the foregoing, no such amendment or termination shall have a material adverse affect on any Participant’s rights under the Plan accrued as of the date of such amendment or termination. Upon termination of the Plan, the Board shall cause a lump-sum payment of all benefits for all Participants at substantially the same time.
XI. MISCELLANEOUS
11.1. No Implied Rights; Rights on Termination of Service. Neither the establishment of the Plan nor any amendment thereof shall be construed as giving any Participant, Beneficiary or any other person, individually or as a member of a group, any legal or equitable right unless such right shall be specifically provided
13
for in the Plan or conferred by specific action of the Board or the Administrator in accordance with the terms and provisions of the Plan. Except as expressly provided in this Plan, neither the Company nor any of its Affiliates shall be required or be liable to make any payment under the Plan.
11.2. No Employment Rights. Nothing herein shall constitute a contract of employment or of continuing service or in any manner obligate the Company or any Affiliate to continue the services of any Participant, or obligate any Participant to continue in the service of the Company or Affiliates, or as a limitation of the right of the Company or Affiliates to discharge any of their employees, with or without cause.
11.3. Unfunded Plan. No funds shall be segregated or earmarked for any current or former Participant, Beneficiary or other person under the Plan. However, the Company may establish one or more trusts to assist in meeting its obligations under the Plan, the assets of which shall be subject to the claims of the Company’s general creditors. No current or former Participant, Beneficiary or other person, individually or as a member of a group, shall have any right, title or interest in any account, fund, grantor trust, or any asset that may be acquired by the Company in respect of its obligations under the Plan (other than as a general creditor of the Company with an unsecured claim against its general assets). The Company may also choose to use life insurance to assist it in meeting its obligations under the Plan. As a condition of participation in the Plan, each Participant agrees to execute any documents that may be required in connection with obtaining such insurance and to cooperate with any life insurance underwriting requirements; provided, however, that a Participant shall not be required to undergo a medical examination in connection therewith.
11.4. Nontransferability. Prior to payment thereof, no benefit under the Plan shall be assignable or subject to any manner of alienation, sale, transfer, claims of creditors, pledge, attachment or encumbrances of any kind, except pursuant to a domestic relations order awarding benefits to an "alternate payee" (within the meaning of Code Section 414(p)(8)) that the Administrator determines satisfies the criteria set forth in paragraphs (1), (2) and (3) of Code Section 414(p) (a "DRO"). Notwithstanding any provision of the Plan to the contrary, the Plan benefits awarded to an alternate payee under a DRO shall be paid in a single lump sum to the alternate payee on the Valuation Date as soon as administratively practicable following the date the Administrator determines the order is a DRO, and such amounts, as adjusted for earnings, gains and losses, will be deducted from the Participant's Accounts as of such Valuation Date.
11.5. Successors and Assigns. The rights, privileges, benefits and obligations under the Plan are intended to be, and shall be treated as legal obligations of and binding upon the Company, its successors and assigns, including successors by merger, consolidation, reorganization or otherwise.
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11.6. Applicable Law. This Plan is established under and will be construed according to the laws of the State of Oklahoma, to the extent not preempted by the laws of the United States.
15
Amendment Number 1 to the
OGE Energy Corp. Deferred Compensation Plan
(As Amended and Restated Effective March 27, 2001)
OGE Energy Corp., an Oklahoma corporation (the “Company”), by action of its Benefits Oversight Committee taken in accordance with the authority granted to it by Article X of the OGE Energy Corp. Deferred Compensation Plan (As Amended and Restated Effective March 27, 2001), (the “Plan”), hereby amends the Plan in the following respects effective as of January 1, 2002 unless another date is specified:
1. By deleting, effective January 1, 2003, Section 2.18 of the Plan and inserting in lieu thereof the following:
"2.18. "Eligible Employee" means, with respect to any Plan Year commencing on or after January 1, 2003, unless determined otherwise by the Board, an employee of the Company or an Affiliate who (i) is at OGE Grade 31 or above or, if OGE Grade levels do not apply to the particular business unit in which the employee is employed, is in a comparable salary grade or has comparable salary to employees at OGE Grade 31 or above, as determined by the Administrator, or (ii) was an Eligible Employee under the Plan as in effect prior to January 1, 2003 and had a Deferral Election in effect for the Plan Year beginning January 1, 2002."
2. By deleting Section 2.24 of the Plan and inserting in lieu thereof the following:
"2.24. “Retirement” means termination of employment with the Company or its Affiliates on or after either the Participant’s Early Retirement Age or Normal Retirement Age, as such terms are defined in the OGE Energy Corp. Retirement Plan.”
3. By adding a new sentence at the end of Article 3 as follows:
"Subject to the preceding sentence, if a Participant ceases for any Plan Year to be an Eligible Employee but remains an employee of the Company or an Affiliate, the Participant shall no longer be able to defer Compensation under Article 4 or receive Matching and Discretionary Credits, if any, under Article 5 for such Plan Year or for any subsequent Plan Year until the Participant should again become an Eligible Employee, but such Participant’s Account shall continue to be subject to all the terms and conditions of the Plan, including Sections 5.3 and 5.4 and Articles 6, 7 and 8, as if such Participant had remained an Eligible Employee.”
4. By deleting Section 4.4(c) of the Plan and inserting in lieu thereof the following:
"(c) The minimum annual deferral under the Plan for any Plan Year beginning prior to January 1, 2002 shall be $2,500, and any Deferral Election which would provide a lesser deferral for any such Plan Year shall be disregarded. In addition, any Deferral Election for the Pan Year beginning January 1, 2002 which was disregarded prior to July 1, 2002 because it provided a lesser deferral than $2,500 shall continue to be disregarded under the Plan."
16
5. By adding a new sentence at the end of Section 4.5 of the Plan as follows:
"The amounts so credited shall be deemed invested in the assumed investment alternatives available under the Plan as provided in Article VI.”
6. By adding a new sentence at the end of Section 5.1 of the Plan as follows:
"The amounts so credited shall be deemed invested in the assumed investment alternatives available under the Plan as provided in Article VI.”
7. By deleting the first sentence of Section 5.3 of the Plan and inserting in lieu thereof the following:
"A Participant’s Matching Credits, as adjusted for assumed investment return, shall vest based on the Participant’s years of service (which shall be equal to the Participant’s “Years of Vesting Service” within the meaning of and as credited to the Participant under the RSP) under the following schedule:
Percentage of
Years of Service Matching Credits Vested
Less than 3 0%
3 but less than 4 30%
4 but less than 5 40%
5 but less than 6 60%
6 but less than 7 80%
7 or more 100%
Notwithstanding the foregoing, with respect to any Participant who is employed by the Company or Affiliates on or after January 1, 2002, the Participant’s vested percentage of the Participant’s Matching Credits, as adjusted for assumed investment return, shall be determined in accordance with the following schedule:
Percentage of
Years of Service Matching Credits Vested
Less than 2 0%
2 but less than 3 20%
3 but less than 4 40%
4 but less than 5 60%
5 but less than 6 80%
6 or more 100%"
8. By deleting Section 5.4 of the Plan and inserting in lieu thereof the following:
"5.4. Acceleration of Vesting. Notwithstanding the provisions of Section 5.3, a Participant's Matching Credits and Discretionary Credits, if any, as adjusted for assumed investment return, shall become fully vested upon the following events:
17
(a) the Participant's Retirement;
(b) the Participant's Disability;
(c) the Participant's death;
(d) a Change in Control; or
(e) termination of the Plan under Article 10."
9. By deleting the third and fourth sentences of Section 6.2 of the Plan and inserting in lieu thereof the following three sentences:
"On or before the last day of each month, a Participant may make a new election, to be effective immediately after the close of business on the last business day of the month in which the election is filed with the Administrator, with respect to the assumed investments in which his or her Account shall be deemed invested in the future. Such new election may, subject to the following sentence, (i) redirect the investment of his or her ending Account balance as of the close of business on the Valuation Date coinciding with the last business day of such month among the assumed investment alternatives and/or (ii) change the assumed investment alternatives in which future contribution credits to be made as of or after the effective date of the election will be deemed invested. Any such election shall be made in the form and at the time specified by the Administrator; provided, however, prior to a Participant’s attainment of age 55, Matching Credits and the portion of his or her Account attributable to Matching Credits shall be deemed to be invested only in the assumed investment alternative based on the Company’s common stock.”
10. By deleting the second sentence of Section 7.2 of the Plan and inserting in lieu thereof the following two new sentences:
"Distribution under this Section 7.2 shall be made (i) in a lump sum, (ii) in annual installments of up to 15 years, or (iii) in a combination of (i) and (ii), as elected by the Participant. The amount of each installment payment to be made to a Participant under clause (ii) above shall be equal to the quotient obtained by dividing the balance in his or her Account as of the Valuations Date coincident with or next preceding the date of such installment payment by the number of installment payments remaining to be made to the Participant at the time of such calculation.” By deleting the phrase “at least one year” where it appears in Section 7.4(c) of the Plan and inserting in lieu thereof the phrase “at least 12 months”.
11. By adding a new Section 9.4 after Section 9.3 of the Plan as follows:
"9.4. Participant Statements. As soon as practicable after the end of each calendar quarter, a statement will be furnished to each Participant showing the status of his or her Account as of the beginning and end of the calendar quarter, any changes to such Account during such calendar quarter, and such other information as the Administrator may determine. The
18
Administrator may, in its sole discretion, change the frequency in which statements are provided to any or all Participants.”
IN WITNESS WHEREOF, the Company’s Benefits Oversight Committee has caused this instrument to be signed by a duly authorized member on this 26th day of July, 2002.
OGE ENERGY CORP.
By: Its Benefits Oversight Committee
By:/ s /
---------------------------------
One of its Members
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Exhibit 10.15
EMPLOYMENT AGREEMENT
This EMPLOYMENT AGREEMENT, (the “Agreement”), dated as of April 1, 2002, but effective as provided herein, is made and entered into by and between OGE Energy Corp., an Oklahoma corporation (the “Company”), and Peter B. Delaney (the “Executive”).
WHEREAS, the Company believes that it would benefit from the application of Executive’s particular and unique skill, experience and background to the management and operation of the Company, and that the Executive will make major contributions to the short- and long-term profitability, growth and financial strength of the Company;
WHEREAS, the Company considers it in the best interests of its stockholders to foster the continuous employment of certain key management personnel; and
WHEREAS, the Company wishes to employ the Executive and the Executive is willing to render services and accept the offer of the Company, both on the terms and subject to the conditions set forth in this Agreement;
NOW, THEREFORE, in consideration of the promises and of the mutual covenants herein contained, it is agreed as follows:
1. Employment.
1.1 Employment. The Company hereby agrees to employ the Executive, and the Executive hereby agrees to undertake employment with the Company, upon the terms and conditions herein set forth.
1.2 Term. This Agreement shall be effective and shall govern the terms of the Executive’s employment for a period commencing on April 1, 2002 (the “Commencement Date”) and, subject to earlier expiration upon the Executive’s termination under Section 5, ending on March 31, 2005 (the “Termination Date”). For purposes of this Agreement, any reference to the “Employment Term” of this Agreement shall mean the period of time from the Commencement Date through the Termination Date. Executive and the Company understand and acknowledge that Executive’s employment with the Company constitutes “at-will” employment.
2. Positions and Duties.
2.1 Positions and Duties. During the Employment Term, the Executive will serve in the positions of Executive Vice-President of the Company with responsibility for corporate strategic planning and Chief Executive Officer of the Company’s unregulated businesses and will have such powers, duties, functions, authority and additional responsibilities as are (a) consistent with the Executive’s positions; or (b) assigned to his office in the Company’s by-laws; or (c) reasonably assigned to him by the Company’s Chief Executive Officer (the
“CEO”). The Executive will report directly to the CEO, except that prior to, November 1, 2002 or such earlier date determined by the CEO, the Executive will report directly to the Company’s Chief Operating Officer.
2.2 Commitment. During the Employment Term, the Executive will be a full-time employee of the Company and, excluding any periods of vacation and sick leave to which the Executive is entitled, the Executive agrees to devote reasonable attention and time during normal business hours to the business and affairs of the Company and its affiliates and, to the extent necessary to discharge the responsibilities assigned to the Executive hereunder, to use the Executive’s reasonable best efforts to perform faithfully and efficiently such responsibilities.
3. Place of Performance. In connection with his employment during the Employment Term, the Executive will be based at the principal executive offices of the Company or a subsidiary of the Company in the Oklahoma City, Oklahoma area. The Executive will undertake normal business travel on behalf of the Company.
4. Compensation and Related Matters.
4.1 Compensation.
(a) Annual Base Salary. During the Employment Term, the Company will pay to the Executive an annual base salary ("Base Salary") at the minimum rate of $400,000. The Executive's Base Salary shall be subject to review annually, based on the Executive's performance, by the Board of Directors of the Company or the Compensation Committee thereof, at which time the Executive's Base Salary may be raised by the Board in its sole discretion (and, as so raised, shall thereafter constitute "Base Salary" hereunder). Base Salary may not be decreased. For purposes of this Agreement, any reference to the "Board" shall mean the Board of Directors of the Company or the Compensation Committee or other appropriate authorized committee thereof. Base Salary shall be payable at the times and in the manner consistent with the Company's general policies regarding compensation of executive employees. The Board may from time to time authorize such additional compensation to the Executive, in cash or in property, as the Board may determine in its sole discretion to be appropriate.
(b) Annual Incentive Compensation. During the Employment Term, the Executive will be eligible to participate in the Company's Annual Incentive Compensation Plan, or any successor thereto (the "Performance Incentive Program"), under the general terms and conditions applicable to executive and management employees. The Executive's annual target payout under Performance Incentive Program shall be at least $240,000 (i.e., 60% of his initial Base Salary), subject to achievement of applicable performance measures and criteria as established by the Board. For 2002, however, the Executive's target payment will be prorated based on the number of full months during 2002 beginning on or following the Commencement Date. Subject to the foregoing, nothing in this Section 4.1(b) will guarantee to the Executive any specific amount of annual incentive compensation, or prevent the Board from establishing performance goals and compensation targets applicable only to the Executive.
(c) Long-Term Incentive Compensation Plans. During the Employment Term, the Executive will be eligible to participate in the Company's Stock
Incentive Plan or any successor long-term incentive plan thereto (the "LTIP") under the general terms and conditions applicable to executive and management employees. Executive's participation in the LTIP will be at an annual level of not less than $400,000 (i.e., 100% of his initial Base Salary). For 2002, however, the Executive's annual level of participation shall be prorated based on the number of full months during 2002 beginning on or following the Commencement Date. Such long-term incentive compensation for 2002 shall be provided in the following forms: (i) 75% shall be delivered in the form of non-qualified stock options as of the date specified by the Board in the resolution granting such options, with an exercise price per option share equal to not more than the fair market value of a share of the Company's common stock as of the date of the grant, and (ii) the remaining 25% shall be delivered in the form of restricted stock subject to the approval in November 2002 of the Compensation Committee of the Board. Subject to the foregoing, nothing in this Section 4.1(c) will guarantee the Executive any specific amount of long-term incentive compensation, or prevent the Board from establishing performance goals and compensation applicable only to the Executive.
4.2 Employee Benefits. In addition to the compensation described in Section 4.1 and subject to the following provisions of this Section 4, the Company will make available to the Executive and his eligible dependents, subject to the terms and conditions of the applicable plans, including without limitation the eligibility rules, participation in all employee benefit plans sponsored by the Company or an affiliate, including all employee retirement income and welfare benefit policies, plans, programs or arrangements, provided generally to executives of the Company, including, without limitation, any stock option, stock purchase, stock appreciation, savings, pension, supplemental executive retirement or other retirement income or welfare benefit, disability, salary continuation, and any other deferred compensation, incentive compensation, group and/or executive life, health, medical/hospital or other insurance (whether funded by actual insurance or self-insured), expense reimbursement or other employee benefit policies, plans, programs or arrangements or any equivalent successor policies, plans, programs or arrangements that may now exist or be adopted hereafter by the Company or its affiliates.
4.3 Vacation and Fringe Benefits. During the Employment Term, the Executive shall be entitled to 20 business days of paid vacation annually, such vacation to be taken in accordance with the Company’s normal vacation policies. The Executive will be entitled to the perquisites and other fringe benefits made available generally to executives of the Company.
4.4 Expenses. The Company will promptly reimburse the Executive for all travel and other business expenses the Executive incurs in order to perform his duties to the Company under this Agreement in a manner commensurate with the Executive’s position and level of responsibility with the Company, and in accordance with the Company’s policy regarding substantiation of expenses.
4.5 Relocation Expenses. As soon as possible but in any event no later than August 1, 2002, the Executive will relocate his family and primary residence to the general area of the Company’s current headquarters in Oklahoma City, Oklahoma. The Company will pay the Executive and, where applicable, upon substantiation of expenses (a) for temporary housing for two months, (b) on the Commencement Date, one month’s Base Salary for incidental expenses, (c) reasonable relocation expenses associated with moving the Executive’s household and
personal goods from his current residence in New Jersey to the Oklahoma City, Oklahoma area, and (d) the normal seller’s broker’s commissions and expenses associated with the sale of the Executive’s residence in New Jersey and the normal inspection and similar expenses associated with buying a home in the Oklahoma City, Oklahoma area.
4.6 Supplemental Retirement Benefits. The Executive will be eligible to participate, effective as of the Commencement Date, in the OGE Energy Corp. Supplemental Executive Retirement Plan, as amended from time to time (the “SERP”). For purpose of applying the SERP, the Executive will be credited as of the Commencement Date with three “years of Service” under the SERP.
5. Termination. Notwithstanding the Employment Term specified in Section 1.2, the termination of the Executive's employment hereunder will be governed by the following provisions:
5.1 Death. If the Executive dies prior to the end of the Employment Term, the Company will pay the Executive’s beneficiaries or estate, as appropriate, promptly after the Executive’s death, (a) the unpaid Base Salary to which the Executive is entitled, pursuant to Section 4.1, through the date of the Executive’s death, and (b) for any accrued but unused vacation days, to the extent and in the amounts, if any, provided under the Company’s usual policies and arrangements. This Section 5.1 will not limit the entitlement of the Executive’s estate or beneficiaries to any death or other benefits then available to the Executive under any life insurance, stock ownership, stock options, or other benefit plan or policy that is maintained by the Company or its affiliates for the Executive’s benefit or in which the Executive participated.
5.2 Disability.
(a) If the Company determines in good faith that the Executive has incurred a Disability (as defined below) prior to the end of the Employment Term, the Company may give the Executive written notice of its intention to terminate the Executive's employment. In such event, the Executive's employment with the Company will terminate effective on the 30th calendar day after receipt of such notice by the Executive, provided that within the 30 calendar days after such receipt, the Executive will not have returned to full-time performance of his duties. The Executive will continue to receive his Base Salary (less any amounts payable to the Executive for such period under any short- or long-term disability plan maintained by the Company or its affiliates) and benefits until the date of termination. In the event of the Executive's Disability, the Company will pay the Executive, promptly after the Executive's termination, (i) the unpaid Base Salary to which he is entitled, pursuant to Section 4.1, through the date of the Executive's termination (less any amounts payable to the Executive for such period under any short- or long-term disability plan maintained by the Company or its affiliates), and (ii) for any accrued but unused vacation days, to the extent and in the amounts, if any, provided under the Company's usual policies and arrangements. This Section 5.2 will not limit the entitlement of the Executive or the Executive's estate or beneficiaries to any disability or other benefits then available to the Executive under any disability insurance or other benefit plan or policy that is maintained by the Company or its affiliates for the Executive's benefit or in which the Executive participated.
(b) For purposes of this Agreement, "Disability" shall mean the absence of the Executive from the Executive's duties with the Company and its affiliates on a full-time basis for 180 consecutive business days as a result of incapacity due to mental or physical illness or injury which is determined to be total and permanent by a physician selected by the Company or its insurers and acceptable to the Executive or the Executive's legal representative.
5.3 Cause.
(a) The Company may terminate the Executive's employment hereunder for Cause (as defined below) prior to the end of the Employment Term by written notice as provided in Section 10.5. If the Executive is terminated for Cause, the Company will promptly pay to the Executive (or his representative) the unpaid Base Salary to which he is entitled, pursuant to Section 4.1, through the date the Executive is terminated and the Executive will be entitled to no other compensation or benefits, except as otherwise due to him under applicable law or pursuant to any benefit plan or policy that is maintained by the Company or its affiliates in which the Executive participated.
(b) For purposes of this Agreement, "Cause" means:
(i) the willful and continued failure of the Executive to perform substantially the Executive's duties with the Company or one of its affiliates (other than any such failure resulting from incapacity due to physical or mental illness or injury), after a written demand for substantial performance is delivered to the Executive by the Board or the CEO which specifically identifies the manner in which the Board or CEO believes that the Executive has not substantially performed the Executive's duties, or
(ii) the willful engaging by the Executive in illegal conduct or gross misconduct which is materially and demonstrably injurious to the Company or its affiliates.
For purposes of this provision, no act or failure to act, on the part of the Executive, shall be considered “willful” unless it is done, or omitted to be done, by the Executive in bad faith or without reasonable belief that the Executive’s action or omission was in the best interests of the Company and its affiliates. Any act, or failure to act, based upon authority given pursuant to a resolution duly adopted by the Board or upon the instructions of the CEO or based upon the advice of counsel for the Company shall be conclusively presumed to be done, or omitted to be done, by the Executive in good faith and in the best interests of the Company and its affiliates. The cessation of employment of the Executive shall not be deemed to be for Cause unless and until there shall have been delivered to the Executive a copy of a resolution duly adopted by the affirmative vote of not less than three quarters of the entire membership of the Board at a meeting of the Board called and held for such purpose (after reasonable notice is provided to the Executive and the Executive is given an opportunity, together with counsel, to be heard before the Board), finding that, in the good faith opinion of the Board, the Executive is guilty of the conduct described in subparagraph (i) or (ii) above, and specifying the particulars thereof in detail.
5.4 Termination.
(a) Involuntary Termination. The Executive's employment hereunder may be terminated prior to the end of the Employment Term by the Company for any reason other than death, Disability or Cause by written notice as provided in Section 10.5. In the event of such an involuntary termination, the Executive will be entitled to the payments and benefits provided in Section 5.5. This Section 5.4(a) and Section 5.5, however, will not limit the entitlement of the Executive to any other benefits then available to the Executive under any benefit plan or policy (other than any severance plan or policy) that is maintained by the Company or its affiliates for the Executive's benefit or in which the Executive participated.
(b) Voluntary Termination. The Executive may voluntarily terminate this Agreement at any time by notice to the Company as provided in Section 10.5. In the event of the Executive's voluntary termination, the Company will promptly pay the Executive (i) the unpaid Base Salary to which the Executive is entitled, pursuant to Section 4.1, through the date of the Executive's termination, and (b) for any accrued but unused vacation days, to the extent and in the amounts, if any, provided under the Company's usual policies and arrangements. This Section 5.4(b) will not limit the entitlement of the Executive to any other benefits then available to the Executive under any benefit plan or policy that is maintained by the Company or its affiliates for the Executive's benefit or in which the Executive participated.
5.5 Termination Payments and Benefits.
(a) Form and Amount. Upon the Executive's involuntary termination other than by reason of death, Disability or Cause as provided in Section 5.4(a), the Company will promptly pay or provide to the Executive:
(i) the unpaid Base Salary to which the Executive is entitled, pursuant to Section 4.1, through the date of the Executive's termination,
(ii) for any accrued but unused vacation days, to the extent and in the amounts, if any, provided under the Company's usual policies and arrangements, and
(iii) with continued payment of the Executive's Base Salary as in effect immediately prior to his termination of employment and incentive compensation set forth in Section 4.1(b) and Section 4.1(c) as if he had remained employed by the Company pursuant to this Agreement through the end of the Employment Term (determined without regard to its early expiration upon the Executive's termination of employment), subject to the following: (i) such payments of Base Salary shall be payable at the times and in the manner consistent with the Company's general policies regarding compensation for executive employees; (ii) the Executive's annual incentive compensation for each fiscal year of the Company ending after the termination of Executive's employment and prior to the end of the Employment Term shall be paid in cash within 15 days of termination of Executive's employment and shall be equal to the sum of the minimum annual target payouts (i.e., $240,000) that the Executive
would have been eligible to earn for each fiscal year ending during such period; (iii) in lieu of stock-based or equity-based awards under any LTIP that were to be made to Executive during the Employment Term under Section 4.1(c) and subject to the following clause (iv) of this Section 5.5(a), the Executive will be paid cash within 15 days of termination of Executive's employment in an amount equal to the annual level of participation at which the Executive participated under such plan for the last complete fiscal year of the Company ending prior to his termination (unless such termination occurs prior to January 1, 2003, in which case at the annual level set forth in Section 4.1(c)); and (iv) at the Executive's sole election by written notice to the Company within 10 days of termination of Executive's employment and in lieu of the payment described in the immediately preceding clause (iii) of this Section 5.5(a), Executive shall be paid in cash $400,000 upon surrender of all prior stock-based or equity-based awards made to Executive under any LTIP. The foregoing payments shall be in lieu of any severance payments to which the Executive may be entitled under any severance pay plan or policy of the Company or its affiliates, which payments the Executive hereby waives.
(b) Resignation. If at the Executive's termination of employment the Executive is a member of the Board or a board of any affiliate of the Company, no benefit will be paid or made available or vest, as the case may be, under Section 5.5(a)(iii) unless the Executive first executes and delivers to the Company a resignation from membership on the Board and from membership on the boards of all affiliates of the Company, as the case may be, such resignation to be effective as of the Executive's termination of employment.
(c) Release. Payment of any amount described in Section 5.5(a)(iii) is conditioned upon the Executive executing and not revoking a Release of Claims Agreement in the form attached hereto as Exhibit A.
5.6 Effect of Change-of-Control Agreement.Notwithstanding anything to the contrary in the foregoing provisions of this Section 5, in the event that upon a termination of employment for any reason the Executive is entitled to benefits pursuant to both this Agreement and the Change-of-Control Employment Agreement executed by the Executive and the Company as of the date hereof, as such agreement may be amended from time to time (the “Change-of-Control Agreement”), any payments or benefits to be paid or provided pursuant to Sections 5.1, 5.2, 5.3, 5.4 and 5.5 of this Agreement shall be reduced (but not below zero) by the amount of any comparable payments or benefits to which the Executive (or, in the event of the Executive’s death, his beneficiaries or estate) is or becomes entitled under the terms of the Change-of-Control Agreement.
6. Mitigation and Offset. The payment of severance compensation by the Company to the Executive in accordance with the terms of the Agreement is hereby acknowledged by the Company to be reasonable, and the Executive is under no obligation to mitigate damages or the amount of any payment provided for hereunder by seeking other employment or otherwise; nor, except as provided in Section 5.6, will any profits, income, earnings or other benefits from any source whatsoever create any mitigation, offset, reduction or any other obligation on the part of the Executive hereunder or otherwise.
7. Competition; Confidentiality; Nonsolicitation.
7.1 The Executive hereby covenants and agrees that during the Employment Term and for one year following the Employment Term he will not, without the prior written consent of the Board, engage in Competition (as defined below) with the Company. The foregoing covenant, however, will not apply during the period following the Executive’s termination of employment if his employment is terminated by the Company for reasons other than Cause. For purposes of this Agreement, if the Executive takes any of the following actions he will be engaged in “Competition”: engaging in or carrying on, directly or indirectly, any enterprise, whether as an advisor, principal, agent, partner, officer, director, employee, stockholder, associate or consultant to any person, partnership, corporation or any other business entity that is principally engaged in the business of the Company and its affiliates in their market areas; provided, however, that “Competition” will not include the mere ownership of 1% or less of the outstanding securities in any enterprise and exercise of rights appurtenant thereto.
7.2 The Executive acknowledges that in the course of his employment by the Company, he will or may have access to and become informed of confidential or proprietary information, trade secrets, substances and inventions which are a competitive asset of the Company or its affiliates (“Confidential Information”), including, without limitation, i) the terms of any agreement between the Company or affiliate and any employee, customer or supplier, ii) pricing strategy, iii) merchandising and marketing methods, iv) product development ideas and strategies, v) personnel training and development programs, vi) financial results, vii) strategic plans and demographic analyses, viii) proprietary computer and systems software, and ix) any non-public information concerning the Company, its employees, affiliates, suppliers or customers. The Executive agrees that he will keep all Confidential Information in strict confidence and as belonging to the Company during the term of his employment by the Company and thereafter, and will never directly or indirectly, without the prior written consent of the Company make known, divulge, reveal, furnish, make available, or use any Confidential Information (except in the course of his regular authorized duties on behalf of the Company and its affiliates). The Executive agrees that the obligations of confidentiality hereunder shall survive termination of his employment at the Company regardless of any actual or alleged breach by the Company of this Agreement, until and unless any such Confidential Information shall have become, through no fault of the Executive, generally known to the public or the Executive is required by law to make disclosure (after giving the Company notice and an opportunity to contest such requirement). The Executive’s obligations under this Section 7.2 are in addition to, and not in limitation of or preemption of, all other obligations of confidentiality which the Executive may have to the Company under general legal or equitable principles.
7.3 The Executive hereby covenants and agrees that during the Employment Term and for one year thereafter the Executive will not attempt to influence, persuade or induce, or assist any other person in so influencing, persuading or inducing, any employee of the Company or an affiliate thereof to give up, or to not commence, employment or a business relationship with the Company or its affiliates, or hire any employee of the Company or its affiliates either directly or on behalf of others.
7.4 The Executive agrees that the Company would suffer an irreparable injury if the Executive were to breach the covenants contained in Sections 7.1, 7.2 or 7.3, and that the Company would by reason of such breach or threatened breach be entitled to injunctive relief in
a court of appropriate jurisdiction and the Executive hereby stipulates to the entering of such injunctive relief prohibiting the Executive from engaging in such breach.
8. Post-termination Assistance. The Executive agrees that after the Executive's employment with the Company has terminated the Executive will provide, upon reasonable notice, such information and assistance to the Company as may reasonably be requested by the Company in connection with any dispute or litigation in which it or any of its affiliates is or may become a party; provided, however, that the Company agrees to reimburse the Executive for any related out-of-pocket expenses, including travel expenses.
9. Survival. The expiration or termination of the Employment Term will not impair the rights or obligations of any party hereto that accrue hereunder prior to such expiration or termination, except to the extent specifically stated herein. In addition to the foregoing, the Executive's covenants contained in Sections 7.1, 7.2, 7.3, 7.4 and 8 and the Company's obligations under Section 5 will survive the expiration or termination of this Agreement or the termination of the Executive's employment for any reason whatsoever.
10. Miscellaneous Provisions.
10.1 Successors and Binding Agreement. x) The Company will require any successor (whether direct or indirect, by purchase, merger, consolidation, reorganization, operation of law or otherwise) to all or substantially all of the business or assets of the Company, by agreement in form and substance satisfactory to the Executive, expressly to assume and agree to perform this Agreement in the same manner and to the same extent the Company would be required to perform if no such succession had taken place. This Agreement will be binding upon and inure to the benefit of the Company and any successor to the Company, including without limitation any persons acquiring directly or indirectly all or substantially all of the business or assets of the Company whether by purchase, merger, consolidation, reorganization, operation of law or otherwise (and such successor shall thereafter be deemed the “Company” for the purposes of this Agreement), but will not otherwise be assignable, transferable or delegable by the Company.
(b) This Agreement will inure to the benefit of and be enforceable by the Executive's personal or legal representatives, executors, administrators, successors, heirs, distributees and legatees.
(c) This Agreement is personal in nature and neither of the parties hereto shall, without the consent of the other, assign, transfer or delegate this Agreement or any rights or obligations hereunder except as expressly provided in Sections 10.1(a) and 10.1(b). Without limiting the generality or effect of the foregoing, the Executive's right to receive payments hereunder will not be assignable, transferable or delegable, whether by pledge, creation of a security interest, or otherwise, other than by a transfer by the Executive's will or by the laws of descent and distribution and, in the event of any attempted assignment or transfer
contrary to this Section 10.1(c), the Company shall have no liability to pay any amount so attempted to be assigned, transferred or delegated.
10.2 Governing Law. This Agreement will be governed, construed, interpreted and enforced in accordance with the substantive laws of the State of Oklahoma, without regard to conflicts of law principles.
10.3 Withholding of Taxes. The Company may withhold from any amounts payable under this Agreement all federal, state, city or other taxes as the Company is required to withhold pursuant to any law or government regulation or ruling.
10.4 Severability. Any provision of this Agreement that is deemed invalid, illegal or unenforceable in any jurisdiction will, as to that jurisdiction, be ineffective to the extent of such invalidity, illegality or unenforceability, without affecting in any way the remaining provisions hereof in such jurisdiction or rendering that or any other provisions of this Agreement invalid, illegal, or unenforceable in any other jurisdiction. If any covenant should be deemed invalid, illegal or unenforceable because its scope is considered excessive, such covenant will be modified so that the scope of the covenant is reduced only to the minimum extent necessary to render the modified covenant valid, legal and enforceable.
10.5 Notices. For all purposes of this Agreement, all communications, including without limitation notices, consents, requests or approvals, required or permitted to be given hereunder will be in writing and will be deemed to have been duly given when hand delivered or dispatched by electronic facsimile transmission (with receipt thereof confirmed), or five business days after having been mailed by United States registered or certified mail, return receipt requested, postage prepaid, or three business days after having been sent by a nationally recognized overnight courier service such as Federal Express, UPS, or Purolator, addressed to the Company (to the attention of the Secretary of the Company) at its principal executive offices and to the Executive at his principal residence, or to such other address as any party may have furnished to the other in writing and in accordance herewith, except that notices of changes of address will be effective only upon receipt.
(a) To the Company. If to the Company, addressed to the attention of the Corporate Secretary, 321 North Harvey, Oklahoma City, Oklahoma 73102.
(b) To the Executive. If to the Executive, to him at his residence as identified in the Company's payroll system at the time of the applicable notice.
10.6 Counterparts. This Agreement may be executed in several counterparts, each of which will be deemed to be an original, but all of which together will constitute one and the same Agreement.
10.7 Entire Agreement; Change-of-Control Agreement. Other than the Change-of-Control Agreement, the terms of this Agreement (a) are intended by the parties to be the final expression of their agreement with respect to the Executive’s employment by the Company and (b) shall supercede and may not be contradicted by evidence of any prior or contemporaneous agreement. The parties further intend that this Agreement will constitute the complete and exclusive statement of its terms and that no extrinsic evidence whatsoever may be
introduced in any judicial, administrative or other legal proceeding to vary the terms of this Agreement.
10.8 Amendments; Waivers. This Agreement may not be modified, amended, or terminated except by an instrument in writing, signed by the Executive and the Company. Failure on the part of either party to complain of any action or omission, breach or default on the part of the other party, no matter how long the same may continue, will never be deemed to be a waiver of any rights or remedies hereunder, at law or in equity. The Executive or the Company may waive compliance by the other party with any provision of this Agreement that such other party was or is obligated to comply with or perform only through an executed writing; provided, however, that such waiver will not operate as a waiver of, or estoppel with respect to, any other or subsequent failure.
10.9 No Inconsistent Actions. The parties will not voluntarily undertake or fail to undertake any action or course of action that is inconsistent with the provisions or essential intent of this Agreement. Furthermore, it is the intent of the parties hereto to act in a fair and reasonable manner with respect to the interpretation and application of the provisions of this Agreement.
10.10 Headings and Section References. The headings used in this Agreement are intended for convenience or reference only and will not in any manner amplify, limit, modify or otherwise be used in the construction or interpretation of any provision of this Agreement. All section references are to sections of this Agreement, unless otherwise noted.
10.11 Affiliates. For purposes of this Agreement, the term “affiliate” means with respect to the Company or any other entity, an entity that directly, or indirectly through one or more intermediaries, controls, is controlled by, or is under common control with, the Company or such other entity, and an entity.
IN WITNESS WHEREOF, the parties have executed this Agreement as of the date and year first above written, but effective as provided in Section 1.2.
/ s / Peter B. Delaney
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Peter B. Delaney
OGE ENERGY CORP.
By:/ s / Steven E. Moore
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Steven E. Moore
Its: Chairman of the Board, President and Chief
Executive Officer
EXHIBIT A
RELEASE OF CLAIMS AGREEMENT
This Release of Claims Agreement ("Agreement") is made by and between OGE Energy Corp. (the "Company") and Peter B. Delaney ("Executive").
WHEREAS, Executive was employed by the Company;
WHEREAS, the Company and Executive have entered into an Employment Agreement effective as of April 1, 2002 (the “Employment Agreement”).
NOW THEREFORE, in consideration of the mutual promises made herein, the Company and Executive (collectively referred to as the “Parties”) hereby agree as follows:
1. Termination. Executive's employment from the Company terminated on __________.
2. Consideration. Subject to and in consideration of Executive's release of claims as provided herein, the Company has agreed to pay Executive certain benefits as set forth in the Employment Agreement.
3. Payment of Salary. Executive acknowledges and represents that the Company has paid all salary, wages, bonuses, accrued vacation, commissions and any and all other benefits due to Executive, except ___________________________.
4. Release of Claims. Executive agrees that the foregoing consideration represents settlement in full of all outstanding obligations owed to Executive by the Company. Executive, on behalf of himself, and his respective heirs, family members, executors and assigns, hereby fully and forever releases the Company and its past, present and future officers, agents, directors, executives, investors, shareholders, administrators, affiliates, divisions, subsidiaries, parents, predecessor and successor corporations, and assigns, from, and agrees not to sue or otherwise institute or cause to be instituted any legal or administrative proceedings concerning, any claim, duty, obligation or cause of action relating to any matters of any kind, whether presently known or unknown, suspected or unsuspected, that he may possess arising from any omissions, acts or facts that have occurred up until and including the Effective Date of this Agreement including, without limitation,
(a) any and all claims relating to or arising from Executive's employment relationship with the Company and the termination of that relationship;
(b) any and all claims relating to, or arising from, Executive's right to purchase, or actual purchase, of shares of stock of the Company, including, without limitation, any claims for fraud, misrepresentation, breach of fiduciary duty, breach of duty under applicable state corporate law, and securities fraud under any state of federal law;
(c) any and all claims for wrongful discharge of employment; termination in violation of public policy; discrimination; breach of contract, both express and implied; breach of
a covenant of good faith and fair dealing, both express and implied; promissory estoppel; negligent or intentional infliction of emotional distress; negligent or intentional misrepresentation; negligent or intentional interference with contract or prospective economic advantage; unfair business practices; defamation; libel; slander; negligence; personal injury; assault; battery; invasion of privacy; false imprisonment; and conversion;
(d) any and all claims for violation of any federal, state or municipal statute, including, but not limited to, Title VII of the Civil Rights Act of 1964, the Civil Rights Act of 1991, the Age Discrimination in Employment Act of 1967, the Americans with Disabilities Act of 1990, the Fair Labor Standards Act, the Employee Retirement Income Security Act of 1974, The Worker Adjustment and Retraining Notification Act, and all amendments to each such Act as well as the regulations issued thereunder;
(e) any and all claims for violation of the federal, or any state, constitution;
(f) any and all claims arising out of any other laws and regulations relating to employment or employment discrimination; and
(g) any and all claims for attorneys' fees and costs.
Executive agrees that the release set forth in this section shall be and remain in effect in all respects as a complete general release as to the matters released. This release does not extend to any obligations under the Employment Agreement that survive termination of Executive’s employment with the Company or any obligations incurred under this Agreement.
Notwithstanding the foregoing, this Release shall not cover Executive’s rights to payments and benefits under any benefit plan or policy (other than any severance plan or policy), Executive’s rights to indemnification under the by-laws or Articles of Incorporation of the Company or any other rights to indemnification or Executive’s rights with regard to any equity granted or under any benefit plan.
5. Acknowledgement of Waiver of Claims under ADEA. Executive acknowledges that he is waiving and releasing any rights he may have under the Age Discrimination in Employment Act of 1967 ("ADEA") and that this waiver and release is knowing and voluntary. Executive and the Company agree that this waiver and release does not apply to any rights or claims that may arise under the ADEA after the Effective Date of this Agreement. Executive acknowledges that the consideration given for this waiver and release Agreement is in addition to anything of value to which Executive was already entitled. Executive further acknowledges that he has been advised by this writing that (a) he should consult with an attorney prior to executing this Agreement; (b) he has at least twenty-one (21) days within which to consider this Agreement; (c) he has seven (7) days following the executing of this Agreement by the Parties to revoke the Agreement; and (d) this Agreement shall not be effective until the revocation period has expired. Any revocation should be in writing and delivered as provided in Section 10.5(a) of the Employment Agreement, by close of business on the seventh day from the date that Executive signs this Agreement.
6. No Pending or Future Lawsuits. Executive represents that he has no lawsuits, claims, or actions pending in his name, or on behalf of any other person or entity, against the
Company or any other person or entity referred to herein. Executive also represents that he does not intend to bring any claims on his own behalf or on behalf of any other person or entity against the Company or any other person or entity referred to herein with regard to matters released hereunder.
7. Costs. The Parties shall each bear their own costs, expert fees, attorneys' fees and other fees incurred in connection with this Agreement.
8. Authority. Executive represents and warrants that he has the capacity to act on his own behalf and on behalf of all who might claim through him to bind them to the terms and conditions of this Agreement.
9. No Representations. Executive represents that he has had the opportunity to consult with an attorney, and has carefully read and understands the scope and effect of the provisions of this Agreement. Neither party has relied upon any representations or statements made by the other party hereto which are not specifically set forth in this Agreement.
10. Severability. In the event that any provision hereof becomes or is declared by a court of competent jurisdiction to be illegal, unenforceable or void, this Agreement shall continue in full force and effect without said provision.
11. Entire Agreement. This Agreement and the Employment Agreement and the agreements and plans referenced therein represent the entire agreement and understanding between the Company and Executive concerning Executive's separation from the Company, and supersede and replace and all prior agreements and understandings concerning Executive's relationship with the Company and his compensation by the Company. This Agreement may only be amended in writing signed by Executive and an executive officer of the Company.
12. Governing Law. This Agreement shall be governed by the internal substantive laws, but not the choice of law rules, of the State of Oklahoma.
13. Effective Date. This Agreement is effective eight (8) days after it has been signed by both Parties.
14. Counterparts. This Agreement may be executed in counterparts, and each counterpart shall have the same force and effect as an original and shall constitute an effective, binding agreement on the part of each of the undersigned.
15. Voluntary Execution of Agreement. This Agreement is executed voluntarily and without any duress or undue influence on the part or behalf of the Parties hereto, with the full intent of releasing all claims. The Parties acknowledge that:
(a) They have read this Agreement;
(b) They have been represented in the preparation, negotiation, and execution of this Agreement by legal counsel of their own choice or that they have voluntarily declined to seek such counsel;
(c) They understand the terms and consequences of this Agreement and of the releases it contains;
(d) They are fully aware of the legal and binding effect of the Agreement.
IN WITNESS WHEREOF, the Parties have executed this Agreement on the respective dates set forth below.
OGE ENERGY CORP.
Dated: By:/ s /
------------, ------- --------------------------------------
Dated:
------------, ------- -----------------------, an individual
Exhibit 10.16
AGREEMENT
This AGREEMENT (the "Agreement"), dated as of August 1, 2002 (the "Effective Date"), is made and entered into by and among OGE Energy Corp., an Oklahoma corporation (the "Company"), Enogex, Inc., an Oklahoma corporation ("Enogex"), and Roger A. Farrell (the "Executive").
WHEREAS, the Executive is currently employed as the President and Chief Executive Officer (“CEO”) and serves as a director of Enogex, a wholly-owned subsidiary of the Company; and
WHEREAS, the Executive desires to resign from his employment with Enogex on or before November 30, 2002 and the Company and Enogex are willing to accept such resignation;
NOW, THEREFORE, in consideration of the mutual covenants and provisions of the parties to this Agreement, including but not limited to the agreement to pay the Executive, subsequent to his resignation, the payments described in this Agreement, the Company, Enogex and the Executive agree as follows:
1. Employment and Resignation.
1.1 Resignation.
(a) The Executive hereby submits and Enogex and the Company hereby accept his irrevocable written resignation as President and CEO and an employee of Enogex effective as of November 30, 2002 or such earlier date after August 31, 2002 as the Executive shall specify on seven days prior written notice to the Company as provided in Section 7.5 (the "Resignation Date"). From and after the Resignation Date, the Executive shall no longer be an officer or employee of Enogex or an officer or employee of any of its affiliates and shall not for any purpose be considered or treated as an officer or employee of Enogex or an officer or employee of any of its affiliates.
(b) The Executive hereby submits and Enogex and the Company hereby accept, effective as of the Effective Date, his irrevocable resignation as a director of Enogex and any of its affiliates of which he is a director. From and after the Effective Date, the Executive shall no longer be a director of Enogex or any affiliate thereof and shall not for any purpose be considered or treated as a director of Enogex or any of its affiliates.
(c) Within 72 hours after execution of this Agreement by all parties, internal and external announcements in the forms appended as Exhibit A shall be issued by the Company (collectively referred to as the "Announcements"). The Executive acknowledges that he has reviewed the Announcements and they are acceptable to him.
1.2 Position and Duties. Effective as of the Effective Date and continuing through the Resignation Date (the “Transition Period”), the Executive will continue to serve in his current position of President and CEO of Enogex. During the Transition Period, the Executive’s responsibilities shall be limited solely to (i) reasonable consultation with the Company and Peter Delaney and assistance in the transition of the Executive’s replacement as President and CEO of Enogex, (ii) actively working with an outplacement agency to seek other employment and (iii) assistance in the disposing by the Company and Enogex of the Company’s natural gas reserves in Oklahoma and Michigan. The Executive’s obligation after August 31, 2002 to consult with and assist the Company and Peter Delaney under (i) and (iii) above shall be secondary to his work with the outplacement agency and/or his other efforts to obtain new employment. During the Transition Period, the Executive shall be provided his current office and with secretarial assistance for his use primarily in performing services for the Company under (i) or (iii) above. The Executive shall have no operating responsibilities at any time during the Transition Period. During the Transition Period, the Executive may, at his option, continue to attend functions associated with industry groups to which he belongs or in which he has been active, including but not limited to Southern Gas Association, Gas Processor’s Association, and OIPA. Upon proper substantiation and in accordance with Company policies, the Company will continue to reimburse usual and customary expenses incurred by Executive in connection with attendance of such meetings during the Transition Period.
1.3 Terms and Conditions. During the Transition Period, the Executive’s salary rate (“Base Salary”) and employee benefits, each as in effect as of the Effective Date, shall continue in effect; provided, however, any change in employee benefits effective during the Transition Period that is applicable to employees of the Company and its affiliates generally shall also be applicable to the Executive. The Company represents that it has no knowledge as of the Effective Date of any contemplated changes in employee benefits to be made during the Transition Period. In addition, the Company, upon execution of the Agreement, shall provide to the Executive, at the Company’s expense, in an amount not to exceed $35,000, outplacement services through the firm of Challenger, Gray & Christmas.
2. Termination. Notwithstanding Sections 1.1, 1.2 and 1.3 or any other provision of this Agreement, the termination of the Executive's employment hereunder will be governed by the following provisions:
2.1 Death. If the Executive dies prior to the end of the Transition Period, Enogex will pay the Executive’s beneficiaries or estate, as appropriate, promptly after the Executive’s death, only the unpaid Base Salary to which the Executive is entitled, pursuant to Section 1.3, through the date of the Executive’s death and the Executive’s beneficiaries or estate will be entitled to no other compensation or benefits, except as otherwise due the Executive under applicable law or pursuant to any benefit plan or policy that is maintained by the Company or its affiliates in which the Executive participated. This Section 2.1 will not limit the entitlement of the Executive’s estate or beneficiaries to any death or other benefits then available to the Executive under any life insurance, stock ownership, stock options, or other benefit plan or policy that is maintained by the Company or its affiliates for the Executive’s benefit or in which the Executive participated.
2.2 Cause.
(a) Enogex may terminate the Executive's employment hereunder for Cause (as defined below) prior to the end of the Transition Period by written notice as provided in Section 7.5. If the Executive is terminated for Cause, Enogex will promptly pay to the Executive (or his representative) the unpaid Base Salary to which he is entitled, pursuant to Section 1.3, through the date the Executive is terminated and the Executive will be entitled to no other compensation or benefits, except as otherwise due to him under applicable law or pursuant to any benefit plan or policy that is maintained by the Company or its affiliates in which the Executive participated.
(b) For purposes of this Agreement, "Cause" means:
(i) the willful and continued failure of the Executive to perform substantially the Executive's duties with Enogex as provided in Section 1.2 (other than any such failure resulting from incapacity due to physical or mental illness or injury), after (A) a written demand for substantial performance is delivered to the Executive by the Board of Directors of the Company (the "Board") or the CEO of the Company which specifically identifies the manner in which the Board or CEO of the Company believes that the Executive has not substantially performed the Executive's duties and (B) the Executive has failed to cure such non-performance within five days after receipt of such written demand, or
(ii) the willful engaging by the Executive in illegal conduct or gross misconduct which is materially and demonstrably injurious to the Company or its affiliates.
For purposes of this provision, no act or failure to act, on the part of the Executive, shall be considered “willful” unless it is done, or omitted to be done, by the Executive in bad faith or without reasonable belief that the Executive’s action or omission was in the best interests of the Company and its affiliates. Any act, or failure to act, based upon authority given pursuant to a resolution duly adopted by the Board or upon the instructions of the CEO of the Company or based upon the advice of counsel for the Company shall be conclusively presumed to be done, or omitted to be done, by the Executive in good faith and in the best interests of the Company and its affiliates. The cessation of employment of the Executive shall not be deemed to be for Cause unless and until there shall have been delivered to the Executive a copy of a resolution duly adopted by the affirmative vote of not less than three quarters of the entire membership of the Board at a meeting of the Board called and held for such purpose (after reasonable notice is provided to the Executive and the Executive is given an opportunity, together with counsel, to be heard before the Board), finding that, in the good faith opinion of the Board, the Executive is guilty of the conduct described in subparagraph (i) or (ii) above, and specifying the particulars thereof in detail.
3. Severance Compensation and Benefits.
3.1 Form and Amount. Following the Executive’s Resignation Date, unless the Executive’s employment has been terminated prior thereto by reason of death or Cause as provided in Section 2, Enogex or the Company will promptly pay or provide to the Executive:
(a) the unpaid Base Salary to which the Executive is entitled, pursuant to Section 1.3, through the Resignation Date;
(b) as severance compensation continued payment to the Executive (i) until August 1, 2003 of an amount equal to the Executive's Base Salary, as in effect immediately prior to the Effective Date and (ii) provided he has not been employed by a new employer, as defined below, prior to August 1, 2003, from August 1, 2003 until the earlier of January 31, 2004 or the date he becomes employed by a new employer of an amount equal to the Executive's Base Salary, as in effect immediately prior to the Effective Date, such payments of continued Base Salary under (i) and (ii) to be payable at the times and in the manner consistent with Enogex's general policies regarding compensation for executive employees. For purposes of Section 3.1(b)(ii), the Executive will be deemed to be employed by a new employer at such time as he becomes an advisor, principal, agent, partner, officer, director, employee, associate, sole proprietor or consultant to or of any person, partnership, corporation or any other business entity, other than the Company or Enogex or any of their affiliates, on a full-time basis. For purposes of the foregoing, "full-time basis" shall be defined as either (I) full-time employment as an employee of such business entity or (II) performing services for such business entities for compensation in any calendar month in excess of 80 hours; provided, however, that notwithstanding the preceding provisions of Section 3.1(b)(ii), if the Executive performs services in any calendar month beginning on or after the Effective Date in excess of 80 hours as provided in (II) above and he has not been employed as provided in (I) above, he shall continue to be entitled to severance compensation under this Section 3.1(b) for the period from August 1, 2003 until January 31, 2004, except that the amount of such severance compensation for each month during such period shall be reduced by the amount earned by the Executive (irrespective of when paid) from performing services during such month. The Executive shall report to the Company immediately after the end of each month beginning on the Effective Date and continuing through January 31, 2004 the amount of such earnings and his employment status. To the extent that any overpayment to the Executive or other recipient for any month beginning on or after August 1, 2003 results from the operation of the preceding provisions, the Company or Enogex may reduce any future payments due the Executive under this Agreement or otherwise until such overpayment has been recovered. If no further payments are due the Executive from which to recover any overpayment, the Executive shall reimburse the Company for the amount of such overpayment within ten business days after demand notice from the Company.
(c) commencing as of the Resignation Date and continuing for the period (the "Continuation Period") ending on the last day of the month in which occurs the earlier of (i) January 31, 2004 or (ii) the date on which the Executive is eligible for coverage (whether or not he elects such coverage) under a group health plan of his new employer, and provided the Executive was enrolled in the medical and dental plans made available to him by the Company and Enogex immediately prior to the Resignation Date, medical and dental benefits for the Executive and his dependents on terms and conditions (including employee contributions toward premium payments) substantially similar to those applicable generally to Enogex
employees and their dependents during the Continuation Period. If and to the extent that any such benefit is not or cannot be paid or provided under any policy, plan, program or arrangement of the Company or affiliate, as the case may be, then the Company or Enogex will itself pay or provide for the payment to the Executive and his dependents of such medical and dental benefits on such terms and conditions;
(d) a prorated annual bonus under the Company's 2002 annual incentive plan, such payment to be calculated based on the level of achievement of the Executive's performance goals for 2002 had he remained employed through December 31, 2002 and the proration to be determined based on the number of full months the Executive worked during 2002 up to and including the Resignation Date. Such prorated annual bonus shall be payable to the Executive at the time payment of bonuses for 2002 are made to other participants under the Company's 2002 annual incentive plan;
(e) the ability to purchase at cost from Enogex or the Company, within 30 days after the Resignation Date, the Executive's country club membership, if any, in effect at the Resignation Date; and
(f) commencing as of the Resignation Date and continuing until he is reemployed, continuation of the outplacement services through the Oklahoma City offices of Challenger, Gray & Christmas as provided in Section 1.3. The Company shall not access any information from Challenger, Gray & Christmas regarding the Executive or his employment efforts.
3.2 Release. Payment of any amount described in Section 3.1(b), 3.1(c), 3.1(d), 3.1(e) or 3.1(f) is conditioned upon the Executive executing and not revoking a Release of Claims Agreement in the form attached hereto as Exhibit B.
3.3 Other Benefits. Any termination of Executive’s employment will not affect any rights that the Executive may have pursuant to any other agreement, policy, plan, program or arrangement of the Company or any affiliate providing benefits, which rights shall be governed by the terms thereof; provided, however, that any payments or benefits under Section 3.1(b), 3.1(c), 3.1(d), 3.1(e) or 3.1(f) to which the Executive is entitled shall be in lieu of any severance payments and benefits to which the Executive may be entitled under any severance pay plan or policy of the Company or its affiliates, which payments and benefits the Executive hereby waives.
4. Mitigation and Offset. The payment of severance compensation and benefits to the Executive in accordance with the terms of the Agreement is hereby acknowledged by the Company and Enogex to be reasonable, and the Executive is under no obligation to mitigate damages or the amount of any payment provided for hereunder by seeking other employment or otherwise; nor, will any profits, income, earnings or other benefits from any source whatsoever create any mitigation, offset, reduction or any other obligation on the part of the Executive hereunder or otherwise, except as provided in Section 3.1(b).
5. Competition; Confidentiality; Nonsolicitation; Nondisparagement.
5.1 The Executive hereby covenants and agrees that during the Transition Period and until such later date as severance compensation payments cease to be payable under
Section 3.1(b), he will not, without the prior written consent of the Chief Executive Officer of the Company, engage in Competition (as defined below) with the Company or its affiliates. For purposes of this Agreement, if the Executive takes any of the following actions he will be engaged in “Competition”: (i) acting as an advisor, principal, agent, partner, officer, director, employee, associate, or consultant to any of ONEOK Inc. or its affiliates, Duke Energy Corporation or its affiliates, Dynegy Inc. or its affiliates, Reliant Energy or its affiliates, or any successor to any such entity, or (ii) assisting, whether in the capacity of advisor, principal, agent, partner, officer, director, employee, associate, consultant or otherwise, any ratepayer, intervener or other party in any proceeding involving the Company or any affiliate of the Company before any state regulatory agency (including the Oklahoma Corporation Commission or the Arkansas Public Service Commission) or the Federal Energy Regulatory Commission.
5.2 The Executive acknowledges that in the course of his employment by the Company or its affiliates, he has or may continue to have access to and become informed of confidential or proprietary information, trade secrets, substances and inventions which are a competitive asset of the Company or its affiliates (“Confidential Information”), including, without limitation, (a) the terms of any agreement between the Company or affiliate and any employee, customer or supplier, (b) pricing strategy, (c) merchandising and marketing methods, (d) product development ideas and strategies, (e) personnel training and development programs, (f) financial results, (g) strategic plans and demographic analyses, (h) proprietary computer and systems software, and (i) any non-public information concerning the Company, its employees, affiliates, suppliers or customers. The Executive agrees that he will keep all Confidential Information in strict confidence and as belonging to the Company during the term of his employment by Enogex and thereafter, and will never directly or indirectly, without the prior written consent of the Company make known, divulge, reveal, furnish, or make available any Confidential Information (except in the course of his regular authorized duties on behalf of the Company and its affiliates). The Executive agrees that the obligations of confidentiality hereunder shall survive termination of his employment at Enogex regardless of any actual or alleged breach by the Company or Enogex of this Agreement, until and unless any such Confidential Information shall have become, through no fault of the Executive, generally known to the public or the Executive is required by law to make disclosure (after giving the Company notice and an opportunity to contest such requirement). The Executive’s obligations under this Section 5.2 are in addition to, and not in limitation of or preemption of, all other obligations of confidentiality which the Executive may have to the Company or Enogex under general legal or equitable principles.
5.3 The Executive hereby covenants and agrees that during the Transition Period and for one year thereafter or until such later date as severance compensation payments cease to be payable under Section 3.1(b) the Executive will not attempt to influence, persuade or induce, or assist any other person in so influencing, persuading or inducing, any employee of the Company or an affiliate thereof to give up, or to not commence, employment or a business relationship with the Company or its affiliates, or hire any employee of the Company or its affiliates either directly or on behalf of others.
5.4 (a) From and after the Effective Date, Executive shall not (i) make any written or oral statement that brings the Company or any of its affiliates or the employees, officers or agents of the Company or any of its affiliates into disrepute, or tarnishes any of their images or reputations or (ii) publish, comment upon or disseminate any statements suggesting or
accusing Company or any of its affiliates or any agents, employees or officers of the Company or any of its affiliates of any misconduct or unlawful behavior. This Section shall not be deemed to be breached by testimony of the Executive given in any judicial or governmental proceeding which the Executive reasonably believes to be truthful at the time given or by any other action of the Executive which he reasonably believes is taken in accordance with the requirements of applicable law or administrative regulation. In addition, this Section 5.4(a) shall not be deemed to be breached by any private conversation between the Executive and either Steve Moore, Peter Delaney, Al Strecker and/or Peter Clarke, in which the Executive is requested to express an opinion concerning any matter relating to the Company or Enogex or by any private conversations between the Executive and his family members which are not likely to become public.
(b) From and after the Effective Date, neither the Company nor Enogex, including their officers and directors, shall make any public statements, whether written or oral, or any other statements which are likely to become public, which statements disparage or defame the Executive or his wife. Any statement by the Company or Enogex, including its officers and directors, consistent with the Announcements shall not be deemed to violate this Section 5.4(b).
5.5 The Executive agrees that the Company and Enogex would suffer an irreparable injury if the Executive were to breach the covenants contained in Section 5.1, 5.2, 5.3, 5.4(a) or 5.6. Accordingly, without limiting any other remedies available to the Company and Enogex at law or in equity, if the Executive breaches any of the covenants of such Sections, the Company and Enogex shall be entitled to recover and/or discontinue any or all consideration provided in Section 3 of this Agreement. In addition, the Executive agrees that the Company and Enogex would by reason of such breach or threatened breach be entitled to injunctive relief in a court of appropriate jurisdiction and the Executive hereby stipulates to the entering of such injunctive relief prohibiting the Executive from engaging in such breach.
5.6 The Executive agrees that he will reasonably cooperate at the request of the Company or Enogex in the defense or prosecution of any claims or lawsuits in which the Company or Enogex or any of their affiliates are or may become involved and which relate to matters occurring while Executive was employed by Enogex; provided, however, that the Company agrees to reimburse the Executive upon proper substantiation for any related out-of-pocket expenses, including travel expenses. Executive agrees that, unless compelled by subpoena or court order, he will not testify for, give information to, assist in any manner, or cooperate with any third parties who are or who may become involved in business disputes or litigation with the Company or Enogex or any of their affiliates. The Executive agrees that he will not suggest, directly or indirectly, or in any manner, to any such third party that a subpoena or court order should be sought or obtained. The Executive agrees to immediately notify the Company as provided in Section 7.5 upon receipt of any such informal or formal request, subpoena or court order and to allow the Company or Enogex to respond to any such request subpoena or court order.
The Company agrees to indemnify and defend the Executive of and from any and all claims, demands, actions, proceedings, damages, and attorney’s fees and costs asserted against the Executive for actions or inactions in his capacity as an officer, director, agent or employee of the Company during the term of his employment, as and to the extent the Company is required
by applicable law or under its Articles of Incorporation or by-laws to indemnify the Executive as of the Effective Date.
The Company agrees that it will maintain all records, memoranda, letters, data compilations and other documents generated by, or in the business files of, the Executive in accordance with normal business practices.
6. Survival. The expiration or termination of the Transition Period will not impair the rights or obligations of any party hereto that accrue hereunder prior to such expiration or termination, except to the extent specifically stated herein. In addition to the foregoing, the covenants contained in Sections 5.1, 5.2, 5.3, 5.4 and 5.6 and the Company's obligations under Section 3 will survive the expiration or termination of this Agreement or the termination of the Executive's employment for any reason whatsoever.
7. Miscellaneous Provisions.
7.1 Successors and Binding Agreement. (a) The Company and Enogex will require any successor (whether direct or indirect, by purchase, merger, consolidation, reorganization, operation of law or otherwise) to all or substantially all of the business or assets of the Company or Enogex, as the case may be, by agreement in form and substance satisfactory to the Executive, expressly to assume and agree to perform this Agreement in the same manner and to the same extent the Company or Enogex would be required to perform if no such succession had taken place. This Agreement will be binding upon and inure to the benefit of the Company and Enogex and any successors to the Company and Enogex, including without limitation any persons acquiring directly or indirectly all or substantially all of the business or assets of the Company or Enogex whether by purchase, merger, consolidation, reorganization, operation of law or otherwise (and such successor shall thereafter be deemed the “Company” or “Enogex”, as the case may be, for the purposes of this Agreement), but will not otherwise be assignable, transferable or delegable by the Company or Enogex.
(b) This Agreement will inure to the benefit of and be enforceable by the Executive's personal or legal representatives, executors, administrators, successors, heirs, distributees and legatees.
(c) This Agreement is personal in nature and the parties hereto shall not, without the consent of the others, assign, transfer or delegate this Agreement or any rights or obligations hereunder except as expressly provided in Sections 7.1(a) and 7.1(b). Without limiting the generality or effect of the foregoing, the Executive's right to receive payments hereunder will not be assignable, transferable or delegable, whether by pledge, creation of a security interest, or otherwise, other than by a transfer by the Executive's will or by the laws of descent and distribution and, in the event of any attempted assignment or transfer contrary to this Section 7.1(c), the Company and Enogex shall have no liability to pay any amount so attempted to be assigned, transferred or delegated.
7.2 Governing Law. This Agreement will be governed, construed, interpreted and enforced in accordance with the substantive laws of the State of Oklahoma, without regard to conflicts of law principles.
7.3 Withholding of Taxes. The Company or Enogex may withhold from any amounts payable under this Agreement all federal, state, city or other taxes as the Company or Enogex is required to withhold pursuant to any law or government regulation or ruling.
7.4 Severability. Any provision of this Agreement that is deemed invalid, illegal or unenforceable in any jurisdiction will, as to that jurisdiction, be ineffective to the extent of such invalidity, illegality or unenforceability, without affecting in any way the remaining provisions hereof in such jurisdiction or rendering that or any other provisions of this Agreement invalid, illegal, or unenforceable in any other jurisdiction. If any covenant should be deemed invalid, illegal or unenforceable because its scope is considered excessive, such covenant will be modified so that the scope of the covenant is reduced only to the minimum extent necessary to render the modified covenant valid, legal and enforceable.
7.5 Notices. For all purposes of this Agreement, all communications, including without limitation notices, consents, requests or approvals, required or permitted to be given hereunder will be in writing and will be deemed to have been duly given when hand delivered or dispatched by electronic facsimile transmission (with receipt thereof confirmed), or five business days after having been mailed by United States registered or certified mail, return receipt requested, postage prepaid, or three business days after having been sent by a nationally recognized overnight courier service such as Federal Express, UPS, or Purolator, addressed to the Company (to the attention of the Secretary of the Company) at its principal executive offices and to the Executive at his principal residence, or to such other address as any party may have furnished to the other in writing and in accordance herewith, except that notices of changes of address will be effective only upon receipt.
(a) To The Company. If to the Company, addressed to the attention of the Corporate Secretary, 321 North Harvey, Oklahoma City, Oklahoma 73102.
(b) To the Executive. If to the Executive, to him at his residence as identified in the Enogex's payroll system at the time of the applicable notice.
7.6 Counterparts. This Agreement may be executed in several counterparts, each of which will be deemed to be an original, but all of which together will constitute one and the same Agreement.
7.7 Entire Agreement. The terms of this Agreement (a) are intended by the parties to be the final expression of their agreement with respect to the Executive’s employment and severance compensation and benefits payable by the Company or Enogex and (b) shall supercede and may not be contradicted by evidence of any prior or contemporaneous agreement. The parties further intend that this Agreement will constitute the complete and exclusive statement of its terms and that no extrinsic evidence whatsoever may be introduced in any judicial, administrative or other legal proceeding to vary the terms of this Agreement.
7.8 Amendments; Waivers. This Agreement may not be modified, amended, or terminated except by an instrument in writing, signed by the Executive, the Company and Enogex. Failure on the part of any party to complain of any action or omission, breach or default on the part of another party, no matter how long the same may continue, will never be deemed to be a waiver of any rights or remedies hereunder, at law or in equity. The Executive or the
Company and Enogex may waive compliance by the other party with any provision of this Agreement that such other party was or is obligated to comply with or perform only through an executed writing; provided, however, that such waiver will not operate as a waiver of, or estoppel with respect to, any other or subsequent failure.
7.9 No Inconsistent Actions. The parties will not voluntarily undertake or fail to undertake any action or course of action that is inconsistent with the provisions or essential intent of this Agreement. Furthermore, it is the intent of the parties hereto to act in a fair and reasonable manner with respect to the interpretation and application of the provisions of this Agreement.
7.10 Headings and Section References. The headings used in this Agreement are intended for convenience or reference only and will not in any manner amplify, limit, modify or otherwise be used in the construction or interpretation of any provision of this Agreement. All section references are to sections of this Agreement, unless otherwise noted.
7.11 Affiliates. For purposes of this Agreement, the term “affiliate” means with respect to the Company or any other entity, an entity that directly, or indirectly through one or more intermediaries, controls, is controlled by, or is under common control with, the Company or such other entity, and an entity.
IN WITNESS WHEREOF, the parties have executed this Agreement as of the date and year first above written.
/ s / Roger A. Farrell
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Roger A. Farrell
OGE ENERGY CORP.
By:/ s /
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ENOGEX, INC.
By:/ s /
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EXHIBIT B
RELEASE OF CLAIMS AGREEMENT
This Release of Claims Agreement ("Agreement") is made by and between OGE Energy Corp. (the "Company"), Enogex, Inc. ("Enogex") and Roger A. Farrell ("Executive").
WHEREAS, Executive was employed by the Enogex;
WHEREAS, the Company, Enogex and Executive have entered into an Agreement effective as of August 1, 2002 (the “Severance Agreement”).
NOW THEREFORE, in consideration of the mutual promises made herein, the Company, Enogex and Executive (collectively referred to as the “Parties”) hereby agree as follows:
1. Termination. Executive's employment from Enogex terminated on __________.
2. Consideration. Subject to and in consideration of Executive's release of claims as provided herein, the Company and Enogex have agreed to pay Executive certain benefits as set forth in the Severance Agreement.
3. Payment of Salary. Executive acknowledges and represents that the Company and Enogex have paid all salary, wages, bonuses, accrued vacation, commissions and any and all other benefits due to Executive, except such bonuses as may be payable under the terms of the bonus plan at a point in time after the execution of this Agreement.
4. Release of Claims. Executive agrees that the foregoing consideration represents settlement in full of all outstanding obligations owed to Executive by the Company or Enogex. Executive, on behalf of himself, and his respective heirs, family members, executors and assigns, hereby fully and forever releases the Company and Enogex and their past, present and future officers, agents, directors, executives, investors, shareholders, administrators, affiliates, divisions, subsidiaries, parents, predecessor and successor corporations, and assigns, from, and agrees not to sue or otherwise institute or cause to be instituted any legal or administrative proceedings concerning, any claim, duty, obligation or cause of action relating to any matters of any kind, whether presently known or unknown, suspected or unsuspected, that he may possess arising from any omissions, acts or facts that have occurred up until and including the Effective Date of this Agreement including, without limitation,
(a) any and all claims relating to or arising from Executive's employment relationship with the Company or Enogex and the termination of that relationship;
(b) any and all claims relating to, or arising from, Executive's right to purchase, or actual purchase, of shares of stock of the Company, including, without limitation, any claims for fraud, misrepresentation, breach of fiduciary duty, breach of duty under applicable state corporate law, and securities fraud under any state or federal law;
(c) any and all claims for wrongful discharge of employment; termination in violation of public policy; discrimination; breach of contract, both express and implied; breach of a covenant of good faith and fair dealing, both express and implied; promissory estoppel; negligent or intentional infliction of emotional distress; negligent or intentional misrepresentation; negligent or intentional interference with contract or prospective economic advantage; unfair business practices; defamation; libel; slander; negligence; personal injury; assault; battery; invasion of privacy; false imprisonment; and conversion;
(d) any and all claims for violation of any federal, state or municipal statute, including, but not limited to, Title VII of the Civil Rights Act of 1964, the Civil Rights Act of 1991, the Age Discrimination in Employment Act of 1967, the Americans with Disabilities Act of 1990, the Fair Labor Standards Act, the Employee Retirement Income Security Act of 1974, The Worker Adjustment and Retraining Notification Act, and all amendments to each such Act as well as the regulations issued thereunder;
(e) any and all claims for violation of the federal, or any state, constitution;
(f) any and all claims arising out of any other laws and regulations relating to employment or employment discrimination; and
(g) any and all claims for attorneys' fees and costs.
Executive agrees that the release set forth in this section shall be and remain in effect in all respects as a complete general release as to the matters released. This release does not extend to any obligations under the Severance Agreement that survive termination of Executive’s employment with Enogex or any obligations incurred under this Agreement.
Notwithstanding the foregoing, this release shall not cover Executive’s rights to payments and benefits under any benefit plan or policy (other than any severance plan or policy), Executive’s rights to indemnification under the by-laws or Articles of Incorporation of the Company or Enogex or under any directors’ and officers’ liability insurance coverage maintained by the Company or Enogex or any other rights to indemnification or Executive’s rights with regard to any equity granted or under any benefit plan.
5. Acknowledgement of Waiver of Claims under ADEA. Executive acknowledges that he is waiving and releasing any rights he may have under the Age Discrimination in Employment Act of 1967 ("ADEA") and that this waiver and release is knowing and voluntary. Executive and the Company and Enogex agree that this waiver and release does not apply to any rights or claims that may arise under the ADEA after the Effective Date of this Agreement. Executive acknowledges that the consideration given for this waiver and release Agreement is in addition to anything of value to which Executive was already entitled. Executive further acknowledges that he has been advised by this writing that (a) he should consult with an attorney prior to executing this Agreement; (b) he has at least forty-five (45) days within which to consider this Agreement; (c) he has seven (7) days following the executing of this Agreement by the Parties to revoke the Agreement; and (d) this Agreement shall not be effective until the revocation period has expired. Any revocation should be in writing and delivered as provided in
Section 7.5(a) of the Severance Agreement, by close of business on the seventh day from the date that Executive signs this Agreement.
6. No Pending or Future Lawsuits; Representations. Executive represents that he has no lawsuits, claims, or actions pending in his name, or on behalf of any other person or entity, against the Company or Enogex or any other person or entity referred to herein. Executive also represents that he does not intend to bring any claims on his own behalf or on behalf of any other person or entity against the Company or Enogex or any other person or entity referred to herein with regard to matters released hereunder. Executive represents that he was unaware of any unlawful actions or inactions at or by the Company or Enogex or their affiliates on August 1, 2002 and that he is unaware of any unlawful actions or inactions at or by the Company or Enogex or their affiliates as of the date of execution of this Agreement by him unless such have been disclosed in writing to the Chief Executive Officer of the Company prior thereto.
7. Costs. The Parties shall each bear their own costs, expert fees, attorneys' fees and other fees incurred in connection with this Agreement.
8. Authority. Executive represents and warrants that he has the capacity to act on his own behalf and on behalf of all who might claim through him to bind them to the terms and conditions of this Agreement.
9. No Representations. Executive represents that he has had the opportunity to consult with an attorney, and has carefully read and understands the scope and effect of the provisions of this Agreement. Neither party has relied upon any representations or statements made by the other party hereto which are not specifically set forth in this Agreement.
10. Severability. In the event that any provision hereof becomes or is declared by a court of competent jurisdiction to be illegal, unenforceable or void, this Agreement shall continue in full force and effect without said provision.
11. Entire Agreement. This Agreement and the Severance Agreement and the agreements and plans referenced therein represent the entire agreement and understanding between the Company, Enogex and Executive concerning Executive's separation from Enogex, and supersede and replace and all prior agreements and understandings concerning Executive's relationship with the Company and Enogex and his compensation by the Company and Enogex. This Agreement may only be amended in writing signed by Executive and an executive officer of the Company and of Enogex.
12. Governing Law. This Agreement shall be governed by the internal substantive laws, but not the choice of law rules, of the State of Oklahoma.
13. Effective Date. This Agreement is effective eight (8) days after it has been signed by all Parties.
14. Counterparts. This Agreement may be executed in counterparts, and each counterpart shall have the same force and effect as an original and shall constitute an effective, binding agreement on the part of each of the undersigned.
15. Voluntary Execution of Agreement. This Agreement is executed voluntarily and without any duress or undue influence on the part or behalf of the Parties hereto, with the full intent of releasing all claims. The Parties acknowledge that:
(a) They have read this Agreement;
(b) They have been represented in the preparation, negotiation, and execution of this Agreement by legal counsel of their own choice or that they have voluntarily declined to seek such counsel;
(c) They understand the terms and consequences of this Agreement and of the releases it contains;
(d) They are fully aware of the legal and binding effect of the Agreement.
IN WITNESS WHEREOF, the Parties have executed this Agreement on the respective dates set forth below.
OGE ENERGY CORP.
Dated: By:/ s /
-------------, ------- ----------------------------------
ENOGEX, INC.
Dated: By:/ s /
-------------, ------- ----------------------------------
Dated:
---------------, ------- -------------------, an individual
Exhibit 10.17
$200,000,000
CREDIT AGREEMENT
among
OGE ENERGY CORP.
as Borrower,
AND
THE LENDERS IDENTIFIED HEREIN,
AND
BANK OF AMERICA, N.A.,
as Administrative Agent
DATED AS OF JANUARY 8, 2003
BANK OF AMERICA SECURITIES LLC AND
WACHOVIA SECURITIES, INC.
as Joint Lead Arrangers and Co-Book Managers
TABLE OF CONTENTS
SECTION 1 DEFINITIONS AND ACCOUNTING TERMS..........................................................1
1.1 Definitions..............................................................................1
1.2 Computation of Time Periods and Other Definitional Provisions...........................17
1.3 Accounting Terms/Calculation of Financial Covenants.....................................17
1.4 Time....................................................................................17
1.5 Rounding of Financial Covenants.........................................................18
1.6 References to Agreements and Requirement of Laws........................................18
SECTION 2 CREDIT FACILITY..........................................................................18
2.1 Revolving Loans.........................................................................18
2.2 Continuations and Conversions...........................................................19
2.3 Minimum Amounts.........................................................................20
SECTION 3 GENERAL PROVISIONS APPLICABLE TO REVOLVING LOANS.........................................20
3.1 Interest................................................................................20
3.2 Payments Generally......................................................................20
3.3 Prepayments.............................................................................22
3.4 Fees....................................................................................23
3.5 Payment in full at Maturity.............................................................23
3.6 Computations of Interest and Fees.......................................................23
3.7 Pro Rata Treatment......................................................................24
3.8 Sharing of Payments.....................................................................25
3.9 Capital Adequacy........................................................................26
3.10 Eurodollar Provisions...................................................................26
3.11 Illegality..............................................................................26
3.12 Requirements of Law; Reserves on Eurodollar Loans.......................................27
3.13 Taxes...................................................................................27
3.14 Compensation............................................................................30
3.15 Determination and Survival of Provisions................................................30
SECTION 4 CONDITIONS PRECEDENT TO CLOSING..........................................................31
4.1 Closing Conditions......................................................................31
SECTION 5 CONDITIONS TO ALL EXTENSIONS OF CREDIT...................................................32
5.1 Funding Requirements....................................................................32
SECTION 6 REPRESENTATIONS AND WARRANTIES...........................................................33
6.1 Organization and Good Standing..........................................................33
6.2 Due Authorization.......................................................................33
6.3 No Conflicts............................................................................33
6.4 Consents................................................................................34
6.5 Enforceable Obligations.................................................................34
6.6 Financial Condition.....................................................................34
6.7 No Material Change......................................................................34
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6.8 No Default/Material Adverse Agreements..................................................35 6.9 Litigation..............................................................................35 6.10 Taxes...................................................................................35 6.11 Compliance with Law.....................................................................35 6.12 ERISA...................................................................................35 6.13 Use of Proceeds; Margin Stock...........................................................36 6.14 Government Regulation...................................................................36 6.15 Solvency................................................................................37 6.16 Disclosure..............................................................................37 6.17 Environmental Matters...................................................................37 6.18 Ownership of Property; Liens............................................................37 6.19 Subsidiaries............................................................................37 SECTION 7 AFFIRMATIVE COVENANTS....................................................................38 7.1 Information Covenants...................................................................38 7.2 Financial Covenants.....................................................................40 7.3 Preservation of Existence and Franchises................................................40 7.4 Books and Records.......................................................................40 7.5 Compliance with Law.....................................................................40 7.6 Payment of Taxes and Other Indebtedness.................................................40 7.7 Insurance...............................................................................41 7.8 Performance of Obligations..............................................................41 7.9 Use of Proceeds.........................................................................41 7.10 Audits/Inspections......................................................................41 SECTION 8 NEGATIVE COVENANTS.......................................................................42 8.1 Nature of Business......................................................................42 8.2 Consolidation and Merger................................................................42 8.3 Sale or Lease of Assets.................................................................42 8.4 Affiliate Transactions..................................................................42 8.5 Liens...................................................................................43 8.6 Fiscal Year; Accounting; Organizational Documents.......................................44 8.7 Burdensome Agreements...................................................................44 SECTION 9 EVENTS OF DEFAULT........................................................................45 9.1 Events of Default.......................................................................45 9.2 Acceleration; Remedies..................................................................47 9.3 Allocation of Payments After Event of Default...........................................48 SECTION 10 AGENCY PROVISIONS.......................................................................49 10.1 Appointment and Authorization of Administrative Agent...................................49 10.2 Delegation of Duties....................................................................49 10.3 Liability of Administrative Agent.......................................................50 10.4 Reliance by Administrative Agent........................................................50 10.5 Notice of Default.......................................................................51 10.6 Credit Decision; Disclosure of Information by the Administrative Agent..................51 10.7 Indemnification of Administrative Agent.................................................52
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10.8 Administrative Agent in its Individual Capacity.........................................52 10.9 Successor Administrative Agent..........................................................52 10.10 Administrative Agent May File Proofs of Claim...........................................53 10.11 Other Agents; Arrangers and Managers....................................................54 SECTION 11 MISCELLANEOUS...........................................................................54 11.1 Notices and Other Communications; Facsimile Copies......................................54 11.2 Right of Set-Off........................................................................55 11.3 Successors and Assigns..................................................................56 11.4 No Waiver; Remedies Cumulative..........................................................59 11.5 Attorney Costs, Expenses and Indemnification by Borrower................................59 11.6 Amendments, Waivers and Consents........................................................61 11.7 Counterparts............................................................................62 11.8 Headings................................................................................62 11.9 Survival of Indemnification and Representations and Warranties..........................62 11.10 Governing Law; Venue; Jurisdiction......................................................63 11.11 Waiver of Jury Trial; Waiver of Consequential Damages...................................63 11.12 Severability............................................................................64 11.13 Further Assurances......................................................................64 11.14 Confidentiality.........................................................................64 11.15 Entirety................................................................................64 11.16 Binding Effect; Continuing Agreement....................................................65
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CREDIT AGREEMENT
THIS CREDIT AGREEMENT (this "Credit Agreement") is entered into as of January 8, 2003 among OGE ENERGY CORP., an Oklahoma corporation, as Borrower, the Lenders and BANK OF AMERICA, N.A., as Administrative Agent.
RECITALS
WHEREAS, the Borrower has requested the Lenders to provide a senior credit facility to the Borrower in an aggregate principal amount of $200,000,000; and
WHEREAS, the Lenders party hereto have agreed to make the requested senior credit facility available to the Borrower on the terms and conditions hereinafter set forth.
NOW, THEREFORE, IN CONSIDERATION of the premises and other good and valuable consideration, the receipt and sufficiency of which is hereby acknowledged, the parties hereto agree as follows:
SECTION 1
DEFINITIONS AND ACCOUNTING TERMS
1.1 Definitions.
The following terms shall have the meanings specified herein unless the context otherwise requires. Defined terms herein shall include in the singular number the plural and in the plural the singular:
“Adjusted Eurodollar Rate” means the Eurodollar Rate plus the Applicable Percentage.
“Administrative Agent” means Bank of America or any successor administrative agent appointed pursuant to Section 10.9.
“Administrative Agent’s Office” means the Administrative Agent’s address and, as appropriate, account as set forth on Schedule 11.1 or such other address or account as the Administrative Agent may from time to time notify the Borrower and the Lenders.
“Administrative Fees” has the meaning set forth in Section 3.4(c).
“Administrative Questionnaire” means an Administrative Questionnaire in a form supplied by the Administrative Agent.
“Affiliate ” means, with respect to any Person, any other Person directly or indirectly controlling (including but not limited to all directors and officers of such
Person), controlled by or under direct or indirect common control with such Person. A Person shall be deemed to control a corporation if such Person possesses, directly or indirectly, the power (a) to vote 5% or more of the securities having ordinary voting power for the election of directors of such corporation or (b) to direct or cause direction of the management and policies of such corporation, whether through the ownership of voting securities, by contract or otherwise.
“Agent-Related Persons” means the Administrative Agent, together with its Affiliates and the officers, directors, employees, agents and attorneys-in-fact of the Administrative Agent and its Affiliates.
“Applicable Percentage” means, for Eurodollar Loans, Facility Fees and Utilization Fees, the appropriate applicable percentages, in each case, corresponding to the Debt Rating in effect as of the most recent Calculation Date as shown below:
============================================================================================================
Pricing Applicable
Level Applicable Percentage Applicable Percentage for
Debt Rating for Facility Fees Percentage for Eurodollar Rate
Utilization Fees Loans
- ------------------------------------------------------------------------------------------------------------
I =A+/A1 .08% .10% .32%
- ------------------------------------------------------------------------------------------------------------
II A/A2 .10% .125% .525%
- ------------------------------------------------------------------------------------------------------------
III A-/A3 .125% .125% .625%
- ------------------------------------------------------------------------------------------------------------
IV BBB+/Baa1 .15% .125% .725%
- ------------------------------------------------------------------------------------------------------------
V BBB/Baa2 .225% .125% .90%
- ------------------------------------------------------------------------------------------------------------
VI BBB-/Baa3 .30% .25% 1.20%
- ------------------------------------------------------------------------------------------------------------
VII (BBB-/Baa3 .50% .25% 1.50%
or
unrated by S&P or Moody's
============================================================================================================
The Applicable Percentages shall be determined and adjusted on the date (each a “Calculation Date”) one Business Day after the date on which the Borrower’s Debt Rating is upgraded or downgraded in a manner which requires a change in the then applicable Pricing Level set forth above. If at any time there is a split in the Borrower’s Debt Ratings between S&P and Moody’s, the Applicable Percentages shall be determined by the lower of the two Debt Ratings (i.e. the higher pricing); provided that if the two Debt Ratings are more than one level apart, the Applicable Percentage shall be based on the Debt Rating which is one level higher than the lower rating. Each Applicable Percentage shall be effective from one Calculation Date until the next Calculation Date. Any adjustment in the Applicable Percentage shall be applicable to all existing Eurodollar Loans as well as any new Eurodollar Loans made.
“Approved Fund” means any Fund that is administered or managed by (a) a Lender, (b) an Affiliate of a Lender or (c) an entity or an Affiliate of an entity that administers or manages a Lender.
“Arrangers” means BAS and Wachovia Securities, Inc., together with their successors and/or assigns.
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“Assignment and Assumption” means an Assignment and Assumption substantially in the form of Exhibit 11.3(b).
“Authorized Officer” means any of the president, chief executive officer, chief financial officer or treasurer of the Borrower.
“Bank of America” means Bank of America, N.A., together with its successors and/or assigns.
“Bankruptcy Code” means the Bankruptcy Code in Title 11 of the United States Code, as amended, modified, succeeded or replaced from time to time.
“BAS” means Banc of America Securities, LLC.
“Base Rate” means for any day a fluctuating rate per annum equal to the higher of (a) the Federal Funds Rate plus 1/2 of 1% and (b) the rate of interest in effect for such day as publicly announced from time to time by Bank of America as its “prime rate” (the “Prime Rate”). The Prime Rate is a rate set by Bank of America based upon various factors including Bank of America’s costs and desired return, general economic conditions and other factors, and is used as a reference point for pricing some loans, which may be priced at, above, or below such announced rate. Any change in such rate announced by Bank of America shall take effect at the opening of business on the day specified in the public announcement of such change.
“Base Rate Loan” means any Revolving Loan bearing interest at a rate determined by reference to the Base Rate.
“Borrower” means OGE Energy Corp., an Oklahoma corporation, together with its successors and permitted assigns.
“Borrower Obligations” means, without duplication, all of the obligations of the Borrower to the Lenders and the Administrative Agent, whenever arising, under this Credit Agreement, the Revolving Notes, or any of the other Credit Documents.
“Borrowing” means a borrowing consisting of simultaneous Revolving Loans of the same Type and, in the case of Eurodollar Loans, having the same Interest Period made by each of the Lenders pursuant to Section 2.1.
“Business Day” means any day other than a Saturday, a Sunday, a legal holiday or a day on which banking institutions are authorized or required by Law or other governmental action to close in New York, New York or Charlotte, North Carolina; provided that in the case of Eurodollar Loans such day is also a day on which dealings are conducted by and between banks in the London interbank market.
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“Capitalized Lease Obligation” means the amount of the obligations of a Person under capital leases which would be shown as a liability on a balance sheet of such Person prepared in accordance with GAAP.
“Capital Stock” means (a) in the case of a corporation, all classes of capital stock of such corporation, (b) in the case of a partnership, partnership interests (whether general or limited), (c) in the case of a limited liability company, membership interests and (d) any other interest or participation that confers on a Person the right to receive a share of the profits and losses of, or distributions of assets of, the issuing Person; including, in each case, all warrants, rights or options to purchase any of the foregoing.
“Change of Control” means either of the following events:
(a) As of any date, any "person" or "group" (within the meaning of Section 13(d) or 14(d) of the Exchange Act) has become, directly or indirectly, the "beneficial owner" (as defined in Rules 13d-3 and 13d-5 under the Exchange Act), by way of merger, consolidation or otherwise of 30% or more of the Voting Stock of the Borrower; or
(b) During any period of two consecutive calendar years, individuals who at the beginning of such period constituted the board of directors of the Borrower together with any new members of such board of directors whose elections by such board of directors or whose nomination for election by the stockholders of the Borrower was approved by a vote of a majority of the members of such board of directors then still in office who either were directors at the beginning of such period or whose election or nomination for election was previously so approved cease for any reason to constitute a majority of the directors of the Borrower then in office.
“Closing Date” means the date of this Credit Agreement, which is the first date all the conditions precedent in Section 5.1 are satisfied or waived in accordance with Section 5.1.
“Code” means the Internal Revenue Code of 1986 and the rules and regulations promulgated thereunder, as amended, modified, succeeded or replaced from time to time.
“Commitment” means, as to each Lender, its obligation to make Revolving Loans to the Borrower pursuant to Section 2.1 in an aggregate principal amount at any one time outstanding not to exceed such Lender’s Pro Rata Share of the Revolving Committed Amount as set forth opposite such Lender’s name on Schedule 1.1(a) or in the Assignment and Assumption pursuant to which such Lender becomes a party hereto, as applicable, as such amount may be adjusted from time to time in accordance with this Credit Agreement.
“Compensation Period” has the meaning set forth in Section 3.2(c)(ii).
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“Compliance Certificate” means, a fully completed and duly executed officer’s certificate in the form of Exhibit 7.1(c), together with a Covenant Compliance Worksheet.
“Consolidated Capitalization” means, the sum of (a) all of the shareholders’ equity or net worth of the Borrower and its Subsidiaries on a consolidated basis, as determined in accordance with GAAP plus (b) Consolidated Indebtedness plus (c) 50% of the principal amount of the 8.375% Trust Preferred Securities maturing 2039 as long as (i) they are fully subordinated to all current and future debt obligations of the Borrower and its Subsidiaries and (ii) no amortization, redemption or defeasance is required or occurs with respect to such Indebtedness prior to the maturity of such Indebtedness.
“Consolidated EBITDA” means, for any period, without duplication, an amount equal to (a) Consolidated Net Income (excluding any extraordinary gains or any extraordinary losses) for such period plus (b) an amount which in the determination of Consolidated Net Income for such period was deducted for (i) Consolidated Interest Expense, (ii) income tax expense, (iii) depreciation expense and (iv) amortization expense plus (c) non-cash items reducing Consolidated Net Income for such period less (d) non-cash items increasing Consolidated Net Income for such period.
“Consolidated Indebtedness” means, as of any date of determination, with respect to the Borrower and its Subsidiaries on a consolidated basis, an amount equal to all Indebtedness of the Borrower and its Subsidiaries as of such date; provided that it is understood and agreed that (a) Indebtedness of NOARK Pipeline Finance, L.L.C. that is not guaranteed by Enogex, Inc. (even if such Indebtedness is consolidated for accounting purposes) shall not be considered to be Consolidated Indebtedness, (b) Indebtedness in connection with the off-balance sheet leasing of rail cars by a regulated subsidiary of the Borrower shall not be considered to be Consolidated Indebtedness if the payments in connection therewith are included in the rate base as approved by the applicable governing commissions and are collected from customers who are obligated to make such payments, (c) 50% of the principal amount of the 8.375% Trust Preferred Securities maturing 2039 shall not be considered to be Consolidated Indebtedness as long as (A) they are fully subordinated to all current and future debt obligations of the Borrower and its Subsidiaries and (B) no amortization, redemption or defeasance is required or occurs with respect to such Indebtedness prior to the maturity of such Indebtedness and (d) Indebtedness of any special purpose Subsidiary in connection with Existing Receivables Purchase Facilities which Indebtedness is not reflected on the consolidated balance of the Borrower and does not exceed, in the aggregate at any one time, $15,200,000 shall not be considered to be Consolidated Indebtedness.
“Consolidated Interest Expense” means, for any period, with respect to the Borrower and its Subsidiaries on a consolidated basis, an amount equal to total interest expense of the Borrower and its Subsidiaries for such period (including, without limitation, all such interest expense accrued or capitalized during such period, whether or not actually paid during such period), as determined in accordance with GAAP.
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“Consolidated Net Income” means, the consolidated net income of the Borrower and its Subsidiaries, as determined in accordance with GAAP.
“Contingent Obligation” means, with respect to any Person, any direct or indirect liability of such Person with respect to any Indebtedness, liability or other obligation (the “primary obligation”) of another Person (the “primary obligor”), whether or not contingent, (a) to purchase, repurchase or otherwise acquire such primary obligation or any property constituting direct or indirect security therefore, (b) to advance or provide funds (i) for the payment or discharge of any such primary obligation or (ii) to maintain working capital or equity capital of the primary obligor or otherwise to maintain the net worth or solvency or any balance sheet item, level of income or financial condition of the primary obligor, (c) to purchase property, securities or services primarily for the purpose of assuring the owner of any such primary obligation of the ability of the primary obligor in respect thereof to make payment of such primary obligation or (d) otherwise to assure or hold harmless the owner of any such primary obligation against loss or failure or inability to perform in respect thereof; provided, however, that, with respect to the Borrower and its Subsidiaries, the term Contingent Obligation shall not include endorsements for collection or deposit in the ordinary course of business. The amount of any Contingent Obligation of any Person shall be deemed to be an amount equal to the maximum amount of such Person’s liability with respect to the stated or determinable amount of the primary obligation for which such Contingent Obligation is incurred or, if not stated or determinable, the maximum reasonably anticipated liability in respect thereof (assuming such Person is required to perform thereunder).
“Covenant Compliance Worksheet” shall mean a fully completed worksheet in the form of Attachment A to Exhibit 7.1(c).
“Credit Agreement” has the meaning set forth in the Preamble hereof.
“Credit Documents” means, this Credit Agreement, the Revolving Notes, any Notice of Borrowing, any Notice of Continuation/Conversion, and any other document, agreement or instrument entered into or executed in connection with the foregoing.
“Debt Rating” means, the long term unsecured senior non-credit enhanced debt rating of the Borrower by S&P and Moody’s.
“Debtor Relief Laws” means, the Bankruptcy Code, and all other liquidation, conservatorship, bankruptcy, assignment for the benefit of creditors, moratorium, rearrangement, receivership, insolvency, reorganization, or similar debtor relief Laws of the United States or other applicable jurisdictions from time to time in effect and affecting the rights of creditors generally.
“Default” means any event, act or condition which with notice or lapse of time, or both, would constitute an Event of Default.
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“Default Rate” means, an interest rate equal to two percent (2%) plus the rate that otherwise would be applicable (or if no rate is applicable, the Base Rate plus two percent (2%) per annum).
“Defaulting Lender” means, at any time, any Lender that, (a) has failed to make a Revolving Loan or purchase or fund a Participation Interest (but only for so long as such Revolving Loan is not made or such Participation Interest is not purchased or funded), (b) has failed to pay to the Administrative Agent or any Lender an amount owed by such Lender pursuant to the terms of this Credit Agreement (but only for so long as such amount has not been repaid) or (c) has been deemed insolvent or has become subject to a bankruptcy or insolvency proceeding or to a receiver, trustee or similar official.
“Dollars” and “$” means, dollars in lawful currency of the United States of America.
“Eligible Assignee” means, (a) a Lender, (b) an Affiliate of a Lender, (c) an Approved Fund and (d) any other Person approved by the Administrative Agent and the Borrower (such approval not to be unreasonably withheld or delayed); provided that (i) the Borrower’s consent is not required during the existence and continuation of a Default or an Event of Default, (ii) approval by the Borrower shall be deemed given if no objection is received by the assigning Lender and the Administrative Agent from the Borrower within five Business Days after notice of such proposed assignment has been delivered to the Borrower and (iii) neither the Borrower nor any Subsidiary or Affiliate of the Borrower shall qualify as an Eligible Assignee.
“Environmental Claims” means, any and all administrative, regulatory or judicial actions, suits, demands, demand letters, claims, liens, accusations, allegations, notices of noncompliance or violation, investigations (other than internal reports prepared by any Person in the ordinary course of its business and not in response to any third party action or request of any kind) or proceedings relating in any way to any actual or alleged violation of or liability under any Environmental Law or relating to any permit issued, or any approval given, under any such Environmental Law (collectively, “Claims”), including, without limitation, (a) any and all Claims by Governmental Authorities for enforcement, cleanup, removal, response, remedial or other actions or damages pursuant to any applicable Environmental Law and (b) any and all Claims by any third party seeking damages, contribution, indemnification, cost recovery, compensation or injunctive relief resulting from Hazardous Substances or arising from alleged injury or threat of injury to human health or the environment.
“Environmental Laws” shall mean any and all federal, state and local laws, statutes, ordinances, rules, regulations, permits, licenses, approvals, rules of common law and orders of courts or Governmental Authorities, relating to the protection of human health or occupational safety or the environment, now or hereafter in effect and in each case as amended from time to time, including, without limitation, requirements pertaining to the manufacture, processing, distribution, use, treatment, storage, disposal,
7
transportation, handling, reporting, licensing, permitting, investigation or remediation of Hazardous Substances.
“ERISA” means, the Employee Retirement Income Security Act of 1974, as amended from time to time, and any successor statute, and all rules and regulations from time to time promulgated thereunder.
“ERISA Affiliate” means, any Person (including any trade or business, whether or not incorporated) that would be deemed to be under “common control” with, or a member of the same “controlled group” as, the Borrower or any of its Subsidiaries, within the meaning of Sections 414(b), (c), (m) or (o) of the Code or Section 4001 of ERISA.
“ERISA Event” means: (a) a Reportable Event with respect to a Single Employer Plan or, where applicable, a Multiemployer Plan, (b) a complete or partial withdrawal (as described in Sections 4203 or 4205, respectively, of ERISA) by the Borrower, any of its Subsidiaries or any ERISA Affiliate from a Multiemployer Plan, or the receipt by the Borrower, any of its Subsidiaries or any ERISA Affiliate of notice from a Multiemployer Plan that it is in reorganization or insolvency pursuant to Section 4241 or 4245 of ERISA or that it intends to terminate or has terminated under Section 4041A of ERISA, (c) the distribution by the Borrower, any of its Subsidiaries or any ERISA Affiliate under Section 4041 of ERISA of a notice of intent to terminate any Single Employer Plan or the treatment of an amendment to a Single Employer Plan as a termination under Section 4041 of ERISA, (d) the commencement of proceedings by the PBGC under Section 4042 of ERISA for the termination of, or the appointment of a trustee to administer, any Single Employer Plan, or the receipt by the Borrower, any of its Subsidiaries or any ERISA Affiliate of a notice from any Multiemployer Plan that such action has been taken by the PBGC with respect to such Multiemployer Plan, (e) the institution of a proceeding by any fiduciary of any Multiemployer Plan against the Borrower, any of its Subsidiaries or any ERISA Affiliate to enforce Section 515 of ERISA, which is not dismissed within thirty (30) days, (f) the imposition upon the Borrower, any of its Subsidiaries or any ERISA Affiliate of any liability under Title IV of ERISA, other than for PBGC premiums due but not delinquent under Section 4007 of ERISA, or the imposition of any Lien upon any assets of the Borrower, any of its Subsidiaries or any ERISA Affiliate as a result of any alleged failure to comply with the Code or ERISA in respect of any Plan or Multiemployer Plan, (g) the engaging in or otherwise becoming liable for a nonexempt Prohibited Transaction with respect to any Plan or Multiemployer Plan by the Borrower or any of its Subsidiaries, (h) a violation of the applicable requirements of Section 404 or 405 of ERISA or the exclusive benefit rule under Section 401(a) of the Code by any fiduciary of any Plan for which the Borrower, any of its Subsidiaries or any ERISA Affiliate may be directly or indirectly liable, (i) the adoption of an amendment to any Plan that, pursuant to Section 401(a)(29) of the Code, would result in the loss of tax-exempt status of the trust of which such Plan is a part if the Borrower, any of its Subsidiaries or any ERISA Affiliate fails to timely provide security to such Plan in accordance with the provisions of such section or (j) the withdrawal of the Borrower, any of its Subsidiaries or any ERISA Affiliate from a Multiple Employer Plan during a plan
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year in which it was a substantial employer (as such term is defined in Section 4001(a)(2) of ERISA), or the termination of a Multiple Employer Plan.
“Eurodollar Loan” means, a Revolving Loan bearing interest based at a rate determined by reference to the Adjusted Eurodollar Rate.
“Eurodollar Rate” means, for any Interest Period with respect to any Eurodollar Loan:
(a) the rate per annum equal to the rate determined by the Administrative Agent to be the offered rate that appears on the page of the Telerate screen (or any successor thereto) that displays an average British Bankers Association Interest Settlement Rate for deposits in Dollars (for delivery on the first day of such Interest Period) with a term equivalent to such Interest Period, determined as of approximately 11:00 a.m. (London time) two Business Days prior to the first day of such Interest Period, or
(b) if the rate referenced in the preceding clause (i) does not appear on such page or service or such page or service shall not be available, the rate per annum equal to the rate determined by the Administrative Agent to be the offered rate on such other page or other service that displays an average British Bankers Association Interest Settlement Rate for deposits in Dollars (for delivery on the first day of such Interest Period) with a term equivalent to such Interest Period, determined as of approximately 11:00 a.m. (London time) two Business Days prior to the first day of such Interest Period, or
(c) if the rates referenced in the preceding clauses (i) and (ii) are not available, the rate per annum reasonably determined by the Administrative Agent as the rate of interest at which deposits in Dollars for delivery on the first day of such Interest Period in same day funds in the approximate amount of the Eurodollar Loan being made, continued or converted by Bank of America and with a term equivalent to such Interest Period would be offered by Bank of America's London Branch to major banks in the London interbank eurodollar market at their request at approximately 4:00 p.m. (London time) two Business Days prior to the first day of such Interest Period.
“Event of Default” has the meaning set forth in Section 9.1.
“Exchange Act” means, the Securities Exchange Act of 1934, and the rules and regulations promulgated thereunder, as amended, modified, succeeded or replaced from time to time.
“Existing Credit Agreement” means, that certain Credit Agreement, dated as of January 9, 2002, among the Borrower, the lenders party thereto, and Bank of America, as
9
Administrative Agent, as previously amended, modified or supplemented prior to the Closing Date.
“Existing Receivables Purchase Facilities” means, the Receivables Purchase Facilities set forth on Schedule 1.1(c).
“Federal Funds Rate” means, for any day, the rate per annum equal to the weighted average (rounded upward, if necessary, to a whole multiple of 1/100 of 1%) of the rates on overnight Federal funds transactions with members of the Federal Reserve System arranged by Federal funds brokers on such day, as published by the Federal Reserve Bank on the Business Day next succeeding such day; provided that (a) if such day is not a Business Day, the Federal Funds Rate for such day shall be such rate on such transactions on the next preceding Business Day as so published on the next succeeding Business Day, and (b) if no such rate is so published on such next succeeding Business Day, the Federal Funds Rate for such day shall be the average rate (rounded upward, if necessary, to a whole multiple of 1/100 of 1%) charged to Bank of America on such day on such transactions as determined by the Administrative Agent.
“Fee Letters” means, (a) that certain letter agreement, dated as of December 3, 2002, among the Borrower, Bank of America and Banc of America Securities, LLC, as amended, modified, supplemented or restated from time to time (the “Bank of America Fee Letter”) and (b) that certain letter agreement, dated as of December 16, 2002, between the Borrower and Wachovia Securities Inc., as amended, modified, supplemented or restated from time to time.
“Financial Officer” means, the chief financial officer, vice president-finance, principal accounting officer or treasurer of the Borrower.
“Foreign Lender” has the meaning set forth in Section 3.13(f).
“Fund” means, any Person (other than a natural person) that is (or will be) engaged in making, purchasing, holding or otherwise investing in commercial loans and similar extensions of credit in the ordinary course of its business.
“GAAP” means, generally accepted accounting principles in the United States set forth in the opinions and pronouncements of the Accounting Principles Board and the American Institute of Certified Public Accountants and statements and pronouncements of the Financial Accounting Standards Board (or agencies with similar functions of comparable stature and authority within the U.S. accounting profession) or that are promulgated by any Governmental Authority having appropriate jurisdiction.
“Governmental Authority” means, any domestic or foreign nation or government, any state or other political subdivision thereof and any central bank thereof, any municipal, local, city or county government, and any entity exercising executive, legislative, judicial, regulatory or administrative functions of or pertaining to government (including, without limitation, any state dental board) and any corporation or other entity
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owned or controlled, through stock or capital ownership or otherwise, by any of the foregoing.
“Granting Lender” has the meaning specified in Section 11.3(g).
“Hazardous Substances” means, any substances or materials (a) that are or become defined as hazardous wastes, hazardous substances, pollutants, contaminants or toxic substances under any Environmental Law, (b) that are defined by any Environmental Law as toxic, explosive, corrosive, ignitable, infectious, radioactive, mutagenic or otherwise hazardous, (c) the presence of which require investigation or response under any Environmental Law, (d) that constitute a nuisance, trespass or health or safety hazard to Persons or neighboring properties, (e) that consist of underground or aboveground storage tanks, whether empty, filled or partially filled with any substance, or (f) that contain, without limitation, asbestos, polychlorinated biphenyls, urea formaldehyde foam insulation, petroleum hydrocarbons, petroleum derived substances or wastes, crude oil, nuclear fuel, natural gas or synthetic gas.
“Hedging Agreements” means, collectively, interest rate protection agreements, equity index agreements, foreign currency exchange agreements, or other interest or exchange rate hedging agreements, in each case, entered into or purchased by the Borrower or any of its Subsidiaries.
“Indebtedness” means, with respect to any Person (without duplication), (a) all indebtedness and obligations of such Person for borrowed money or in respect of loans or advances of any kind, (b) all obligations of such Person evidenced by notes, bonds, debentures or similar instruments, (c) all reimbursement obligations of such Person with respect to surety bonds, letters of credit and bankers’ acceptances (in each case, whether or not drawn or matured and in the stated amount thereof), (d) all obligations of such Person to pay the deferred purchase price of property or services, (e) all indebtedness created or arising under any conditional sale or other title retention agreement with respect to property acquired by such Person, (f) all Capitalized Lease Obligations of such Person, (g) all obligations and liabilities of such Person incurred in connection with any transaction or series of transactions providing for the financing of assets through one or more securitizations or in connection with, or pursuant to, any synthetic lease or similar off-balance sheet financing, (h) all Contingent Obligations of such Person in respect of the Indebtedness of the types described in clauses (a) – (g) above of another Person, (i) the net termination obligations of such Person under any Hedging Agreements, calculated as of any date as if such agreement or arrangement were terminated as of such date, (j) the aggregate amount of uncollected accounts receivable of such Person subject at the time of determination to a sale of receivables (or similar transaction) to the extent such transaction is effected with recourse to such Person (whether or not such transaction would be reflected on the balance sheet of such Person in accordance with GAAP) and (k) all indebtedness secured by any Lien on any property or asset owned or held by such Person regardless of whether the indebtedness secured thereby shall have been assumed by such Person or is nonrecourse to the credit of such Person.
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“Indemnified Liabilities” has the meaning set forth in Section 11.5(b).
“Indemnitees” has the meaning set forth in Section 11.5(b).
“Interest Payment Date” means, (a) as to any Eurodollar Loan, the last day of each Interest Period applicable to such Loan and the Maturity Date; provided, however, that if any Interest Period for a Eurodollar Loan exceeds three months, the respective dates that fall every three months after the beginning of such Interest Period shall also be Interest Payment Dates and (b) as to any Base Rate Loan, the last Business Day of each fiscal quarter of the Borrower and the Maturity Date.
“Interest Period” means, as to each Eurodollar Loan, the period commencing on the date such Eurodollar Loan is disbursed or converted to or continued as a Eurodollar Loan and ending on the date one, two, three or six months thereafter, as selected by the Borrower in its Notice of Borrowing or Notice of Continuation/Conversion; provided that:
(a) any Interest Period that would otherwise end on a day that is not a Business Day shall be extended to the next succeeding Business Day unless such Business Day falls in another calendar month, in which case such Interest Period shall end on the next preceding Business Day;
(b) any Interest Period that begins on the last Business Day of a calendar month (or on a day for which there is no numerically corresponding day in the calendar month at the end of such Interest Period) shall end on the last Business Day of the calendar month at the end of such Interest Period; and
(c) no Interest Period shall extend beyond the Maturity Date.
“Laws” means, collectively, all international, foreign, federal, state and local statutes, treaties, rules, guidelines, regulations, ordinances, codes and administrative or judicial precedents or authorities, including the interpretation or administration thereof by any Governmental Authority charged with the enforcement, interpretation or administration thereof, and all applicable administrative orders, directed duties, requests, licenses, authorizations and permits of, and agreements with, any Governmental Authority, in each case whether or not having the force of law.
“Lender” means, any of the Persons identified as a “Lender” on the signature pages hereto (unless it has assigned all of its Commitment and Loans pursuant to the terms hereof), and any Eligible Assignee which may become a Lender by way of assignment in accordance with the terms hereof, together with their successors and permitted assigns.
“Lending Office” means, as to any Lender, the office or offices of such Lender described as such in such Lender’s Administrative Questionnaire, or such other office or
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offices as a Lender may from time to time notify the Borrower and the Administrative Agent.
“Lien” means, any mortgage, pledge, hypothecation, assignment, security interest, lien (statutory or otherwise), preference, priority, charge or other encumbrance of any nature, whether voluntary or involuntary, including, without limitation, the interest of any vendor or lessor under any conditional sale agreement, title retention agreement, capital lease or any other lease or arrangement having substantially the same effect as any of the foregoing.
“Margin Stock” has the meaning ascribed to such term in Regulation U.
“Material Adverse Change” means, a material adverse change in the condition (financial or otherwise), operations, business, performance, properties or assets of the Borrower.
“Material Adverse Effect” means, a material adverse effect upon (a) the business, assets, liabilities (actual or contingent), operations, condition (financial or otherwise) or prospects of the Borrower, (b) the ability of the Borrower to perform its obligations under this Credit Agreement or any of the other Credit Documents or (c) the legality, validity or enforceability of this Credit Agreement or any of the other Credit Documents or the rights and remedies of the Administrative Agent and the Lenders hereunder and thereunder.
“Material Subsidiary” means, any Subsidiary of the Borrower (a) the total assets of which exceed, on a book value basis, $20,000,000 or (b) the total annual revenues of which, for the most recent ended fiscal year, exceed $20,000,000.
“Maturity Date” means, January 7, 2004.
“Moody's” means, Moody's Investors Service, Inc. and its successors.
“Multiemployer Plan” means, any “multiemployer plan” within the meaning of Section 4001(a)(3) of ERISA that is subject to Title IV of ERISA and to which the Borrower, any of its Subsidiaries or any ERISA Affiliate makes, is making or is obligated to make contributions or has made or been obligated to make contributions.
“Multiple Employer Plan” means, a Single Employer Plan to which the Borrower, any of its Subsidiaries or any ERISA Affiliate and at least one employer other than the Borrower, any of its Subsidiaries or any ERISA Affiliate are contributing sponsors.
“Notice of Borrowing” means, a request by the Borrower for a Revolving Loan in the form of Exhibit 2.1(b).
“Notice of Continuation/Conversion” means, a request by the Borrower to continue an existing Eurodollar
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Loan to a new Interest Period or to convert a Eurodollar Loan to a Base Rate Loan or a Base Rate Loan to a Eurodollar Loan, in the form of Exhibit 2.2.
“Other Taxes” has the meaning set forth in Section 3.13(b).
“PBGC” means, the Pension Benefit Guaranty Corporation and any successor thereto.
“Participant” has the meaning set forth in Section 11.3(d).
“Participation Interest” means, the purchase by a Lender of a participation in any Revolving Loan as provided in Section 3.8.
“Person” means, any individual, partnership, joint venture, firm, corporation, limited liability company, association, trust or other enterprise (whether or not incorporated), or any Governmental Authority.
“Plan” means, any “employee benefit plan” (within the meaning of Section 3(3) of ERISA), excluding any Multiemployer Plan, which is covered by ERISA and with respect to which the Borrower, any of its Subsidiaries or any ERISA Affiliate is (or, if such plan were terminated at such time, would under Section 4069 of ERISA be deemed to be) an “employer” within the meaning of Section 3(5) of ERISA.
“Prime Rate” has the meaning set forth in the definition of Base Rate in this Section 1.1.
“Pro Rata Share” means, with respect to each Lender at any time, a fraction (expressed as a percentage, carried out to the ninth decimal place), the numerator of which is the amount of the Commitment of such Lender at such time and the denominator of which is the amount of the Revolving Committed Amount at such time; provided that if the Commitment of each Lender to make Revolving Loans has been terminated pursuant to Section 9.2 or otherwise, then the Pro Rata Share of each Lender shall be determined based on such Lender’s percentage ownership of the sum of the aggregate amount of outstanding Revolving Loans. The initial Pro Rata Share of each Lender is set forth opposite the name of such Lender on Schedule 1.1(a) or in the Assignment and Assumption pursuant to which such Lender becomes a party hereto, as applicable.
“Prohibited Transaction” means, any transaction described in (a) Section 406 of ERISA that is not exempt by reason of Section 408 of ERISA or by reason of a Department of Labor prohibited transaction individual or class exemption or (b) Section 4975(c) of the Code that is not exempt by reason of Section 4975(c)(2) or 4975(d) of the Code.
“Property” means, any right, title or interest in or to any property or asset of any kind whatsoever, whether real, personal or mixed and whether tangible or intangible.
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“PUHCA” means the Public Utility Holding Company Act of 1935, as amended.
“Receivables Purchase Facility” means, any securitization facility made available to the Borrower or any of its Subsidiaries, pursuant to which consumer loan receivables of the Borrower or any of its Subsidiaries are transferred to one or more special purposes entities, and thereafter to certain investors, pursuant to the terms and conditions of the applicable receivables purchase and sale agreements.
“Register” has the meaning set forth in Section 11.3(c).
“Regulations T, U and X” means, Regulations T, U and X, respectively, of the Federal Reserve Board, and any successor regulations.
“Reportable Event” means, (a) any “reportable event” within the meaning of Section 4043(c) of ERISA for which the notice under Section 4043(a) of ERISA has not been waived by the PBGC, (b) any such “reportable event” subject to advance notice to the PBGC under Section 4043(b)(3) of ERISA, (c) any application for a funding waiver or an extension of any amortization period pursuant to Section 412 of the Code, and (d) a cessation of operations described in Section 4062(e) of ERISA.
“Required Lenders” means, Lenders whose aggregate Credit Exposure (as hereinafter defined) constitutes more than 66 2/3% of the Credit Exposure of all Lenders at such time; provided, however, that if any Lender shall be a Defaulting Lender at such time then there shall be excluded from the determination of Required Lenders the aggregate principal amount of Credit Exposure of such Lender at such time. For purposes of the preceding sentence, the term “Credit Exposure” as applied to each Lender shall mean (a) at any time prior to the termination of the Commitments, the Pro Rata Share of such Lender of the Revolving Committed Amount multiplied by the Revolving Committed Amount and (b) at any time after the termination of the Commitments, the principal balance of the outstanding Revolving Loans of such Lender.
“Requirement of Law” means, with respect to any Person, the organizational documents of such Person and any Law applicable to or binding upon such Person or any of its property or to which such Person or any of its property is subject or otherwise pertaining to any or all of the transactions contemplated by this Credit Agreement and the other Credit Documents.
“Responsible Officer” means, the president, the chief executive officer, the co-chief executive officer, the chief financial officer, any executive officer, vice president-finance, principal accounting officer or treasurer of the Borrower, and any other officer or similar official thereof responsible for the administration of the obligations of the Borrower in respect of this Credit Agreement and the other Credit Documents.
“Revolving Committed Amount” means, TWO HUNDRED MILLION DOLLARS ($200,000,000) or such lesser amount, as it may be reduced from time to time in accordance with Section 2.1(d).
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“Revolving Loans” or “Loans” has the meaning set forth in Section 2.1(a).
“Revolving Notes” or “Notes” means, the promissory notes of the Borrower in favor of each of the Lenders evidencing the Revolving Loans provided pursuant to Section 2.1, individually or collectively, as appropriate, as such promissory notes may be amended, modified, supplemented, extended, renewed or replaced from time to time and as evidenced in the form of Exhibit 2.1(e).
“SEC Reports” means, the reports filed by the Borrower with the Securities and Exchange Commission between December 31, 2001 and the Closing Date as more fully set forth on Schedule 1.1(b).
“S&P” means Standard & Poor’s Rating Service, a division of The McGraw-Hill Companies, Inc. and its successors.
“Securities Act” means, the Securities Act of 1933, as amended, and the rules and regulations promulgated thereunder.
“Single Employer Plan” means any Plan which is covered by Title IV of ERISA.
“Solvent” means, with respect to any Person as of a particular date, that on such date (a) such Person is able to pay its debts and other liabilities, Contingent Obligations and other commitments as they mature in the normal course of business, (b) such Person does not intend to, and does not believe that it will, incur debts or liabilities beyond such Person’s ability to pay as such debts and liabilities mature in their ordinary course, (c) such Person is not engaged in a business or a transaction, and is not about to engage in a business or a transaction, for which such Person’s assets would constitute unreasonably small capital after giving due consideration to the prevailing practice in the industry in which such Person is engaged or is to engage, (d) the fair value of the assets of such Person is greater than the total amount of liabilities, including, without limitation, Contingent Obligations, of such Person and (e) the present fair saleable value of the assets of such Person is not less than the amount that will be required to pay the probable liability of such Person on its debts as they become absolute and matured.
“SPC” has the meaning set forth in Section 11.3(g).
“Subsidiary” means, as to any Person, (a) any corporation more than 50% of whose stock of any class or classes having by the terms thereof ordinary voting power to elect a majority of the directors of such corporation (irrespective of whether or not at the time, any class or classes of such corporation shall have or might have voting power by reason of the happening of any contingency) is at the time owned by such Person directly or indirectly through Subsidiaries, and (b) any partnership, association, joint venture or other entity in which such person directly or indirectly through Subsidiaries has more than a 50% equity interest at any time. Any reference to Subsidiary herein, unless otherwise identified, shall mean a Subsidiary, direct or indirect, of the Borrower.
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“Taxes” has the meaning set forth in Section 3.13(a).
“Total Assets” means, all assets of the Borrower as shown on its most recent quarterly consolidated balance sheet, as determined in accordance with GAAP.
“Type” means, with respect to a Revolving Loan, its character as a Base Rate Loan or a Eurodollar Loan.
“Utilization Fees” has the meaning set forth in Section 3.4(b).
“Voting Stock” means, the capital stock of a Person that is then outstanding and normally entitled to vote in the election of directors on a fully diluted basis after giving effect to the conversion and exercise of all outstanding warrants, options and other securities of such Person convertible into or exercisable for such capital stock (whether or not such securities are then currently convertible or exercisable).
1.2 Computation of Time Periods and Other Definitional Provisions.
For purposes of computation of periods of time hereunder, the word “from” means “from and including” and the words “to” and “until” each mean “to but excluding.” References in this Credit Agreement to “Articles”, “Sections”, “Schedules” or “Exhibits” shall be to Articles, Sections, Schedules or Exhibits of or to this Credit Agreement unless otherwise specifically provided.
1.3 Accounting Terms/Calculation of Financial Covenants.
Except as otherwise expressly provided herein, all accounting terms used herein or incorporated herein by reference shall be interpreted, and all financial statements and certificates and reports as to financial matters required to be delivered to the Administrative Agent or the Lenders hereunder shall be prepared, in accordance with GAAP applied on a consistent basis. Notwithstanding anything to the contrary in this Credit Agreement, for purposes of calculation of the financial covenants set forth in Section 7.2, all accounting determinations and computations thereunder shall be made in accordance with GAAP as in effect as of the date of this Credit Agreement applied on a basis consistent with the application used in preparing the most recent financial statements of the Borrower referred to in Section 4.1(d). In the event that any changes in GAAP after such date are required to be applied to the Borrower and would affect the computation of the financial covenants contained in Section 7.2, such changes shall be followed for purposes of calculating the financial covenants set forth in Section 7.2 only from and after the date this Credit Agreement shall have been amended to take into account any such changes.
1.4 Time.
All references to time herein shall be references to Central Standard Time or Central Daylight time, as the case may be, unless specified otherwise.
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1.5 Rounding of Financial Covenants.
Any financial ratios required to be maintained by the Borrower pursuant to this Credit Agreement shall be calculated by dividing the appropriate component by the other component, carrying the result to one place more than the number of places by which such ratio is expressed herein and rounding the result up or down to the nearest number (with a rounding-up if there is no nearest number).
1.6 References to Agreements and Requirement of Laws.
Unless otherwise expressly provided herein: (a) references to organization documents, agreements (including the Credit Documents) and other contractual instruments shall be deemed to include all subsequent amendments, restatements, extensions, supplements and other modifications thereto, but only to the extent that such amendments, restatements, extensions, supplements and other modifications are not prohibited by any Credit Document and (b) references to any Requirement of Law shall include all statutory and regulatory provisions consolidating, amending, replacing, supplementing or interpreting such Requirement of Law.
SECTION 2
CREDIT FACILITY
2.1 Revolving Loans.
(a) Revolving Loan Commitment. Subject to the terms and conditions set forth herein, each Lender severally agrees to make revolving loans (each a "Revolving Loan" or "Loan" and collectively the "Revolving Loans" or "Loans") in Dollars to the Borrower, at any time and from time to time, during the period from and including the Closing Date to but not including the Maturity Date (or such earlier date if the Commitments have been terminated as provided herein); provided, however, that after giving effect to any Borrowing (i) the aggregate principal amount of outstanding Revolving Loans shall not exceed the Revolving Committed Amount and (ii) with respect to each individual Lender, the aggregate principal amount of outstanding Revolving Loans of such Lender shall not exceed such Lender's Pro Rata Share of the Revolving Committed Amount. Subject to the terms of this Credit Agreement (including Section 3.3), the Borrower may borrow, repay and reborrow Revolving Loans.
(b) Method of Borrowing for Revolving Loans. By no later than 11:00 a.m. (i) on the date of the requested Borrowing of Revolving Loans that will be Base Rate Loans and (ii) three Business Days prior to the date of the requested Borrowing of Revolving Loans that will be Eurodollar Loans, the Borrower shall telephone the Administrative Agent as well as submit a written Notice of Borrowing in the form of Exhibit 2.1(b) to the Administrative Agent setting forth (A) the amount requested, (B) the date of the requested Borrowing, (C) the Type of Revolving Loan, (D) with respect to Revolving Loans that will be Eurodollar Loans, the Interest Period applicable thereto, and
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(E) certification that the Borrower has complied in all respects with Section 5. If the Borrower shall fail to specify (1) an Interest Period in the case of a Eurodollar Loan, then such Eurodollar Loan shall be deemed to have an Interest Period of one month or (2) the Type of Revolving Loan requested, then such Revolving Loan shall be deemed to be a Base Rate Loan. All Revolving Loans made on the Closing Date shall be Base Rate Loans. Thereafter, all or any portion of the Revolving Loans may be converted into Eurodollar Loans in accordance with the terms of Section 2.2.
(c) Funding of Revolving Loans. Upon receipt of a Notice of Borrowing, the Administrative Agent shall promptly inform the Lenders as to the terms thereof. Each such Lender shall make its Pro Rata Share of the requested Revolving Loans available to the Administrative Agent in immediately available funds at the Administrative Agent's Office not later than 1:00 p.m. on the Business Day specified in the applicable Notice of Borrowing. Upon satisfaction of the conditions set forth in Section 5, the amount of the requested Revolving Loans will then be made available to the Borrower by the Administrative Agent either by (i) crediting the account of the Borrower on the books of the Administrative Agent with the amount of such funds or (ii) wire transfer of such funds, in each case in accordance with instructions provided to (and reasonably acceptable to) the Administrative Agent by the Borrower.
(d) Reductions of Revolving Committed Amount. Upon at least three Business Days' notice, the Borrower shall have the right to permanently terminate or reduce the aggregate unused amount of the Revolving Committed Amount at any time or from time to time; provided that (i) each partial reduction shall be in an aggregate amount at least equal to $10,000,000 and in integral multiples of $1,000,000 above such amount and (ii) no reduction shall be made which would reduce the Revolving Committed Amount to an amount less than the aggregate principal amount of outstanding Revolving Loans. Any reduction in (or termination of) the Revolving Committed Amount shall be permanent and may not be reinstated.
(e) Revolving Notes. The Revolving Loans made by each Lender shall be evidenced by a duly executed promissory note of the Borrower to such Lender in substantially the form of Exhibit 2.1(e).
2.2 Continuations and Conversions.
Subject to the terms below, the Borrower shall have the option, on any Business Day prior to the Maturity Date, to continue existing Eurodollar Loans for a subsequent Interest Period, to convert Base Rate Loans into Eurodollar Loans or to convert Eurodollar Loans into Base Rate Loans. By no later than 11:00 a.m. (a) on the date of the requested conversion of a Eurodollar Loan to a Base Rate Loan and (b) three Business Days prior to the date of the requested continuation of a Eurodollar Loan or conversion of a Base Rate Loan to a Eurodollar Loan, the Borrower shall provide telephonic notice to the Administrative Agent, followed promptly by a written Notice of Continuation/Conversion in the form of Exhibit 2.2, setting forth whether the Borrower wishes to continue or convert such Revolving Loans. Notwithstanding anything herein to the contrary, (A) except as provided in Section 3.11, Eurodollar Loans may
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only be continued or converted into Base Rate Loans on the last day of the Interest Period applicable thereto, (B) Eurodollar Loans may not be continued nor may Base Rate Loans be converted into Eurodollar Loans during the existence and continuation of a Default or an Event of Default and (C) any request to continue a Eurodollar Loan that fails to comply with the terms hereof or any failure to request a continuation of a Eurodollar Loan at the end of an Interest Period shall be deemed a request to convert such Eurodollar Loan to a Base Rate Loan on the last day of the applicable Interest Period.
2.3 Minimum Amounts.
Each request for a borrowing, conversion or continuation shall be subject to the requirements that (a) each Eurodollar Loan shall be in a minimum amount of $10,000,000 and in integral multiples of $1,000,000 in excess thereof, (b) each Base Rate Loan shall be in a minimum amount of $3,000,000 and in integral multiples of $100,000 in excess thereof (or the remaining amount available under the Revolving Committed Amount) and (c) no more than five Eurodollar Loans shall be outstanding hereunder at any one time. For the purposes of this Section 2.3, Eurodollar Loans that end on different dates, even if they begin on the same date, shall be considered to be separate Eurodollar Loans.
SECTION 3
GENERAL PROVISIONS APPLICABLE
TO REVOLVING LOANS
3.1 Interest.
(a) Interest Rate. Subject to Sections 3.1(b), (i) all Base Rate Loans shall accrue interest at the Base Rate and (ii) all Eurodollar Loans shall accrue interest at the applicable Adjusted Eurodollar Rate.
(b) Default Rate of Interest. After the occurrence, and during the continuation, of an Event of Default, the principal of and, to the extent permitted by Law, interest on the Revolving Loans and any other amounts owing hereunder or under the other Credit Documents (including without limitation fees and expenses) shall bear interest, payable on demand, at the Default Rate.
(c) Interest Payments. Interest on Revolving Loans shall be due and payable in arrears on each Interest Payment Date.
3.2 Payments Generally.
(a) No Deductions; Place and Time of Payments. All payments to be made by the Borrower shall be made without condition or deduction for any counterclaim, defense, recoupment or setoff. Except as otherwise expressly provided herein, all payments by the Borrower hereunder shall be made to the Administrative Agent, for the
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account of the respective Lenders to which such payment is owed, at the Administrative Agent's Office in Dollars and in immediately available funds not later than 2:00 p.m. on the date specified herein. The Administrative Agent will promptly distribute to each Lender its Pro Rata Share (or other applicable share as provided herein) of such payment in like funds as received by wire transfer to such Lender's Lending Office. All payments received by the Administrative Agent after 2:00 p.m. shall be deemed received on the next succeeding Business Day and any applicable interest or fee shall continue to accrue.
(b) Payment Dates. Subject to the definition of "Interest Period," if any payment to be made by the Borrower shall come due on a day other than a Business Day, payment shall be made on the next following Business Day, and such extension of time shall be reflected in computing interest or fees, as the case may be.
(c) Advances by Administrative Agent. Unless the Borrower or any Lender has notified the Administrative Agent, prior to the date any payment is required to be made by it to the Administrative Agent hereunder, that the Borrower or such Lender, as the case may be, will not make such payment, the Administrative Agent may assume that the Borrower or such Lender, as the case may be, has timely made such payment and may (but shall not be so required to), in reliance thereon, make available a corresponding amount to the Person entitled thereto. If and to the extent that such payment was not in fact made to the Administrative Agent in immediately available funds, then:
(i) if the Borrower failed to make such payment, each Lender shall forthwith on demand repay to the Administrative Agent the portion of such assumed payment that was made available to such Lender in immediately available funds, together with interest thereon in respect of each day from and including the date such amount was made available by the Administrative Agent to such Lender to the date such amount is repaid to the Administrative Agent in immediately available funds at the Federal Funds Rate from time to time in effect; and
(ii) if any Lender failed to make such payment, such Lender shall forthwith on demand pay to the Administrative Agent the amount thereof in immediately available funds, together with interest thereon for the period from the date such amount was made available by the Administrative Agent to the Borrower to the date such amount is recovered by the Administrative Agent (the "Compensation Period") at a rate per annum equal to the Federal Funds Rate from time to time in effect. If such Lender pays such amount to the Administrative Agent, then such amount shall constitute such Lender's Revolving Loan included in the applicable Borrowing. If such Lender does not pay such amount forthwith upon the Administrative Agent's demand therefore, the Administrative Agent may make a demand therefore upon the Borrower, and the Borrower shall pay such amount to the Administrative Agent, together with interest thereon for the Compensation Period at a rate per annum equal to the rate of interest applicable to such Borrowing. Nothing herein shall be deemed to relieve any Lender from its obligation to fulfill its Commitment or to prejudice any rights which the
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Administrative Agent or the Borrower may have against any Lender as a result of any default by such Lender hereunder.
A notice of the Administrative Agent to any Lender or the Borrower with respect to any amount owing under this subsection (c) shall be conclusive, absent manifest error.
(d) Several Obligations. The obligations of the Lenders hereunder to make Revolving Loans and to purchase Participation Interests are several and not joint. The failure of any Lender to make any Revolving Loan or to purchase any Participation Interest on any date required hereunder shall not relieve any other Lender of its corresponding obligation to do so on such date, and no Lender shall be responsible for the failure of any other Lender to so make its Revolving Loan or purchase its Participation Interest.
(e) Funding Offices. Nothing herein shall be deemed to obligate any Lender to obtain the funds for any Revolving Loan in any particular place or manner or to constitute a representation by any Lender that it has obtained or will obtain the funds for any Revolving Loan in any particular place or manner.
3.3 Prepayments.
(a) Voluntary Prepayments. The Borrower shall have the right to prepay the Revolving Loans in whole or in part from time to time without premium or penalty; provided, however, that (i) all prepayments under this Section 3.3(a) shall be subject to Section 3.14, (ii) Eurodollar Loans may only be prepaid on three Business Days' prior written notice to the Administrative Agent, (iii) each such partial prepayment of Eurodollar Loans shall be in the minimum principal amount of $10,000,000 and integral multiples of $1,000,000 and (iv) each such partial prepayment of Base Rate Loans shall be in the minimum principal amount of $3,000,000 and integral multiples of $1,000,000 or, in the case of clauses (iii) and (iv), if less than such minimum amounts, the entire principal amount thereof then outstanding. Amounts prepaid pursuant to this Section 3.3(a) shall be applied as the Borrower may elect based on the Lenders' Pro Rata Shares; provided, however, if the Borrower fails to specify, such prepayment shall be applied by the Administrative Agent, subject to Section 3.7, in such manner as it deems reasonably appropriate.
(b) Mandatory Prepayments. If at any time the aggregate principal amount of Revolving Loans outstanding exceeds the Revolving Committed Amount, the Borrower shall immediately make a principal payment to the Administrative Agent in a manner, in an amount and in Dollars as is necessary to be in compliance with Section 2.1. All amounts required to be prepaid pursuant to this Section 3.3(b) shall be applied first to Base Rate Loans and second to Eurodollar Loans in direct order of Interest Period maturities. All prepayments pursuant to this Section 3.3(b) shall be subject to Section 3.14.
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3.4 Fees.
(a) Facility Fees. In consideration of the Revolving Committed Amount being made available by the Lenders hereunder, the Borrower agrees to pay to the Administrative Agent, for the pro rata benefit of each Lender based on its Pro Rata Share, a fee equal to the product of (i) a per annum percentage equal to the Applicable Percentage for Facility Fees for each day during the period of determination multiplied by (ii) the Revolving Committed Amount for each such day (the "Facility Fees"). The Facility Fees shall commence to accrue on the Closing Date and shall be due and payable in arrears on the last Business Day of each fiscal quarter of the Borrower (as well as on the Maturity Date and on any date that the Revolving Committed Amount is reduced) for the fiscal quarter (or portion thereof) then ending, beginning with the first of such dates to occur after the Closing Date.
(b) Utilization Fees. If at any time the aggregate principal amount of outstanding Revolving Loans exceeds an amount equal to thirty-three percent (33%) of the Revolving Committed Amount, the Borrower shall pay to the Administrative Agent, for the ratable benefit of the Lenders, a utilization fee (the "Utilization Fees") equal to the product of (i) the average daily aggregate principal amount of outstanding Revolving Loans, calculated from the date the aggregate principal amount of outstanding Revolving Loans exceeds an amount equal to thirty-three percent (33%) of the Revolving Committed Amount but excluding the date the aggregate principal amount of outstanding Revolving Loans falls below an amount equal to thirty-three percent (33%) multiplied by (ii) a per annum percentage equal to the Applicable Percentage for Utilization Fees for each day during such period. The Utilization Fees shall be payable in arrears on the last Business Day of each fiscal quarter of the Borrower (as well as on the Maturity Date and on any date that the Revolving Committed Amount is reduced) for the fiscal quarter (or portion thereof) then ending.
(c) Administrative Fees. The Borrower agrees to pay to the Administrative Agent, for its own account, an annual fee as agreed to between the Borrower and the Administrative Agent (the "Administrative Fees") in the Bank of America Fee Letter.
3.5 Payment in full at Maturity.
On the Maturity Date, the entire outstanding principal balance of all Revolving Loans, together with accrued but unpaid interest and all fees and other sums owing under the Credit Documents, shall be due and payable in full, unless accelerated sooner pursuant to Section 9.2; provided that if the Maturity Date is not a Business Day, then such principal, interest, fees and other sums shall be due and payable in full on the next preceding Business Day.
3.6 Computations of Interest and Fees.
(a) Calculation of Interest. Except for Base Rate Loans that are based upon the Prime Rate, in which case interest shall be computed on the basis of the actual number of days elapsed over a year of 365 or 366 days, as the case may be, all
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computations of interest and fees hereunder shall be made on the basis of the actual number of days elapsed over a year of 360 days. Interest shall accrue from and including the first date of Borrowing (or continuation or conversion) to but excluding the last day occurring in the period for which such interest is payable.
(b) Usury. It is the intent of the Lenders and the Borrower to conform to and contract in strict compliance with applicable usury Law from time to time in effect. All agreements between the Lenders and the Borrower are hereby limited by the provisions of this subsection which shall override and control all such agreements, whether now existing or hereafter arising and whether written or oral. In no way, nor in any event or contingency (including but not limited to prepayment or acceleration of the maturity of any Borrower Obligation), shall the interest taken, reserved, contracted for, charged, or received under this Credit Agreement, under the Revolving Notes or otherwise, exceed the maximum nonusurious amount permissible under applicable Law. If, from any possible construction of any of the Credit Documents or any other document, interest would otherwise be payable in excess of the maximum nonusurious amount, any such construction shall be subject to the provisions of this subsection and such documents shall be automatically reduced to the maximum nonusurious amount permitted under applicable Law, without the necessity of execution of any amendment or new document. If any Lender shall ever receive anything of value which is characterized as interest on the Revolving Loans under applicable Law and which would, apart from this provision, be in excess of the maximum nonusurious amount, an amount equal to the amount which would have been excessive interest shall, without penalty, be applied to the reduction of the principal amount owing on the Revolving Loans and not to the payment of interest, or refunded to the Borrower or the other payor thereof if and to the extent such amount which would have been excessive exceeds such unpaid principal amount of the Revolving Loans. The right to demand payment of the Revolving Loans or any other Indebtedness evidenced by any of the Credit Documents does not include the right to accelerate the payment of any interest which has not otherwise accrued on the date of such demand, and the Lenders do not intend to charge or receive any unearned interest in the event of such demand. All interest paid or agreed to be paid to the Lenders with respect to the Revolving Loans shall, to the extent permitted by applicable Law, be amortized, prorated, allocated, and spread throughout the full stated term (including any renewal or extension) of the Revolving Loans so that the amount of interest on account of the Revolving Loans does not exceed the maximum nonusurious amount permitted by applicable Law.
3.7 Pro Rata Treatment.
Except to the extent otherwise provided herein, each Borrowing, each payment or prepayment of principal of any Revolving Loan, each payment of interest, each payment of fees (other than administrative fees paid to the Administrative Agent), each conversion or continuation of any Revolving Loans and each reduction in the Revolving Committed Amount, shall be allocated pro rata among the relevant Lenders in accordance with their Pro Rata Shares; provided that, if any Lender shall have failed to pay its Pro Rata Share of any Revolving Loan or fund or purchase its Participation Interest, then any amount to which such Lender would
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otherwise be entitled pursuant to this Section 3.7 shall instead be payable to the Administrative Agent until the share of such Revolving Loan or such Participation Interest not funded or purchased by such Lender has been repaid. In the event any principal, interest, fee or other amount paid to any Lender pursuant to this Credit Agreement or any other Credit Document is rescinded or must otherwise be returned by the Administrative Agent, (a) such principal, interest, fee or other amount that had been satisfied by such payment shall be revived, reinstated and continued in full force and effect as if such payment had not occurred and (b) such Lender shall, upon the request of the Administrative Agent, repay to the Administrative Agent the amount so paid to such Lender, with interest for the period commencing on the date such payment is returned by the Administrative Agent until the date the Administrative Agent receives such repayment at a rate per annum equal to the Federal Funds Rate if repaid within two (2) Business Days after such request and thereafter the Base Rate.
3.8 Sharing of Payments.
The Lenders agree among themselves that, except to the extent otherwise provided herein, in the event that any Lender shall obtain payment in respect of any Revolving Loan or any other obligation owing to such Lender under this Credit Agreement through the exercise of a right of setoff, banker’s lien or counterclaim, or pursuant to a secured claim under Section 506 of the Bankruptcy Code or other security or interest arising from, or in lieu of, such secured claim, received by such Lender under any applicable Debtor Relief Law or other similar Law or otherwise, or by any other means, in excess of its Pro Rata Share of such payment as provided for in this Credit Agreement, such Lender shall promptly pay in cash or purchase from the other Lenders a participation in such Revolving Loans and other obligations in such amounts, and make such other adjustments from time to time, as shall be equitable to the end that all Lenders share such payment in accordance with their Pro Rata Shares. The Lenders further agree among themselves that if payment to a Lender obtained by such Lender through the exercise of a right of setoff, banker’s lien, counterclaim or other event as aforesaid shall be rescinded or must otherwise be returned, each Lender which shall have shared the benefit of such payment shall, by payment in cash or a repurchase of a participation theretofore sold, return its share of that benefit (together with its share of any accrued interest payable with respect thereto) to each Lender whose payment shall have been rescinded or otherwise returned. The Borrower agrees that (a) any Lender so purchasing such a participation may, to the fullest extent permitted by Law, exercise all rights of payment, including setoff, banker’s lien or counterclaim, with respect to such participation as fully as if such Lender were a holder of such Revolving Loan or other obligation in the amount of such participation and (b) the Borrower Obligations that have been satisfied by a payment that has been rescinded or otherwise returned shall be revived, reinstated and continued in full force and effect as if such payment had not occurred. Except as otherwise expressly provided in this Credit Agreement, if any Lender or the Administrative Agent shall fail to remit to any other Lender an amount payable by such Lender or the Administrative Agent to such other Lender pursuant to this Credit Agreement on the date when such amount is due, such payments shall be made together with interest thereon for each date from the date such amount is due until the date such amount is paid to the Administrative Agent or such other Lender at a rate per annum equal to the Federal Funds Rate. If under any applicable Debtor Relief Law or other similar Law, any Lender receives a secured claim in lieu of a setoff to which this Section 3.8 applies, such Lender shall, to the extent practicable, exercise its rights in respect of such secured
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claim in a manner consistent with the rights of the Lenders under this Section 3.8 to share in the benefits of any recovery on such secured claim.
3.9