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: 1-1097
OKLAHOMA GAS AND ELECTRIC COMPANY
(Exact name of registrant as specified in its charter)
Oklahoma 73-0382390
State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
321 North Harvey
P. O. Box 321
Oklahoma City, Oklahoma 73101-0321
(Address of principal executive offices)
(Zip Code)
Registrant's telephone number, including area
code: 405-553-3000
Securities registered pursuant to Section 12(b) of the Act: None
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark 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. [ X ]
Indicate by check mark whether the registrant
is an accelerated filer (as defined in Rule 12b-2 of the Act).
Yes No X
As of June 28, 2002, the last business day of the
registrant’s most recently completed second fiscal quarter, 40,378,745 shares
of common stock, par value $2.50 per share, were outstanding, all of which were
held by OGE Energy Corp.
As of February 28, 2003,
40,378,745 shares of common stock, par value $2.50 per share, were outstanding,
all of which were held by OGE Energy Corp. There were no other shares of capital
stock of the registrant outstanding at such date.
DOCUMENTS INCORPORATED BY REFERENCE
None
OKLAHOMA GAS AND ELECTRIC COMPANY
FORM 10-K
FOR THE YEAR ENDED DECEMBER 31, 2002
TABLE OF CONTENTS
Part I Page
Item 1. Business................................................................ 1
The Company............................................................. 1
General............................................................. 2
Regulation and Rates................................................ 5
Rate Activities and Proposals....................................... 15
Fuel Supply......................................................... 16
Finance and Construction................................................ 18
Environmental Matters................................................... 20
Employees............................................................... 22
Access to Securities and Exchange Commission Filings.................... 23
Item 2. Properties.............................................................. 24
Item 3. Legal Proceedings....................................................... 25
Item 4. Submission of Matters to a Vote of Security Holders..................... 31
Executive Officers of the Registrant.................................... 32
Part II
Item 5. Market for Registrant's Common Equity and Related Stockholder
Matters............................................................... 35
Item 6. Selected Financial Data................................................. 36
Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations................................................. 37
Item 7A. Quantitative and Qualitative Disclosures About Market Risk.............. 57
Item 8. Financial Statements and Supplementary Data............................. 58
Item 9. Changes In and Disagreements with Accountants on Accounting and
Financial Disclosure.................................................. 97
i
TABLE OF CONTENTS (Continued)
Part III
Item 10. Directors and Executive Officers of the Registrant....................... 98
Item 11. Executive Compensation................................................... 98
Item 12. Security Ownership of Certain Beneficial Owners and Management and
Related Stockholder Matters............................................ 98
Item 13. Certain Relationships and Related Transactions........................... 98
Item 14. Controls and Procedures.................................................. 98
Part IV
Item 15. Exhibits, Financial Statement Schedules and Reports on Form 8-K.......... 99
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PART I
Item 1. Business.
THE COMPANY
Oklahoma Gas and Electric Company (the “Company”) generates, transmits, distributes and sells electric energy in Oklahoma and western Arkansas and is subject to regulation by the Oklahoma Corporation Commission (“OCC”), the Arkansas Public Service Commission (“APSC”) and the Federal Energy Regulatory Commission (“FERC”). The Company is a wholly-owned subsidiary of OGE Energy Corp. (“Energy Corp.”) which is an energy and energy services provider offering physical delivery and management of both electricity and natural gas in the south central United States. The Company 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. The Company sold its retail gas business in 1928 and is no longer engaged in the gas distribution business. The Company’s executive offices are located at 321 North Harvey, P.O. Box 321, Oklahoma City, Oklahoma 73101-0321; telephone (405) 553-3000.
The Company has been and will continue to be affected by competitive changes to the utility industry. Significant changes already have occurred and additional changes are being proposed to the wholesale electric market. Although it appears unlikely in the near future that changes will occur to retail regulation in the states serves by the Company 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 the Company 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, the Company, the OCC Staff, the Oklahoma Attorney General and other interested parties agreed to a settlement of the Company’s rate case. The terms of the settlement are described below in “Regulation and Rates - Recent Regulatory Matters.”
Company Strategy
In early 2002, Energy Corp. 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, Energy Corp. does not anticipate that deregulation of the electricity markets in Oklahoma or Arkansas will occur in the foreseeable future. The strategic direction of Energy Corp. has been revised to reflect these developments. As a result, Energy Corp. expects potentially slower earnings growth than associated with deregulation but with less variability of those earnings.
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Energy Corp.’s business strategy will utilize the diversified asset position of the Company and Enogex Inc. and its subsidiaries (“Enogex”) to provide energy products and services to customers primarily in the south central United States. Energy Corp. will focus on those products and services with limited or manageable commodity exposure. Energy Corp. intends for the Company to continue as an integrated utility engaged in the generation and the distribution of electricity and to represent over time approximately 70 percent of Energy Corp.’s consolidated assets. The remainder of Energy Corp.’s assets will be in Enogex’s pipeline businesses. In additions to the incremental growth opportunities that Enogex provides, Energy Corp. believes that Enogex’s risk management capabilities, commercial skills and market information provide value to all of Energy Corp.’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, Energy Corp. 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, the Company 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, the Company 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 the Company to generate electricity for its customers at prices below those being paid by the Company under existing qualified cogeneration and small power production producers’ contracts (“QF contracts”). Unless extended by the Company, many of these QF contracts will expire over the next one to five years. Accordingly, the Company will continue to explore opportunities to purchase power plants in order to serve its native load. The Company 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.
General
The Company 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 the Company 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.
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The Company’s system control area peak demand as reported by the system dispatcher during 2002 was approximately 5,696 MW’s on August 23, 2002. The Company’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 below and in the operating statistics on page 4, 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 the Company’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 (“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%
======== ======== ========
The Company is subject to competition in various degrees from government-owned electric systems, municipally-owned electric systems, rural electric cooperatives and, in certain respects, from other private utilities, power marketers and cogenerators. Oklahoma law forbids the granting of an exclusive franchise to a utility for providing electricity.
Besides competition from other suppliers or marketers of electricity, the Company competes with suppliers of other forms of energy. The degree of competition between suppliers may vary depending on relative costs and supplies of other forms of energy. See “Regulation and Rates - State Restructuring Initiatives and National Energy Legislation” for a discussion of the potential impact on competition from federal and state legislation.
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OKLAHOMA GAS AND ELECTRIC COMPANY
CERTAIN OPERATING STATISTICS
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
The Company’s retail electric tariffs are regulated by the OCC in Oklahoma and by the APSC in Arkansas. The issuance of certain securities by the Company is also regulated by the OCC and the APSC. The Company’s wholesale electric tariffs, short-term borrowing authorization and accounting practices are subject to the jurisdiction of the FERC. The Secretary of the Department of Energy has jurisdiction over some of the Company’s facilities and operations.
The order of the OCC authorizing the Company to reorganize into a subsidiary of Energy Corp. contains certain provisions which, among other things, ensure the OCC access to the books and records of Energy Corp. and its affiliates relating to transactions with the Company; require the Company to employ accounting and other procedures and controls to protect against subsidization of non-utility activities by the Company’s customers; and prohibit the Company from pledging its assets or income for affiliate transactions.
For the year ended December 31, 2002, approximately 88 percent of the Company’s 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 the Company. In the filing, the OCC Staff requested that the Company submit information for a test year ending September 30, 2001. On December 14, 2001, the Company, citing the need for investment in security and system reliability, filed a notice with the OCC of its intent to seek an increase in the Company’s electric rates. On January 28, 2002, the Company filed testimony with the OCC supporting the Company’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, the Company has had several rate reductions that have totaled more than $142.0 million annually.
Attempting to make security investments at the proper level, the Company 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 the Company 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 the Company was to invest in increased security. As described below, the Company 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. The Company 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,
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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, the Company 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 the Company 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 the Company’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, the Company announced it would withdraw the $10.3 million increased security portion of its January request. Simultaneously with that announcement, the Company 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, the Company filed a report outlining proposed expenditures and related actions for security enhancement. The Company 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 the Company.
On July 1, 2002, the Company filed direct testimony in support of recovery for the approximately $92.0 million in damages caused by the January 2002 ice storm. The Company 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, the Company, the OCC Staff, the Oklahoma Attorney General and other interested parties agreed to a settlement (the “Settlement Agreement”) of the Company’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 the Company’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 the Company, through rate base, of the capital expenditures associated with the January 2002 ice storm; (iii) recovery by the Company, over three years, of the $5.4 million in deferred operating costs, associated with the January 2002 ice storm, through the Company’s rider for off-system sales; (iv) the Company to acquire electric generating capacity (“New Generation”) of not less than 400 MW’s to be integrated into the Company’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 the Company would file tariffs, designed to reflect an annual reduction of $25.0 million in the Company’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 the Company 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 the Company 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 the Company’s rider for off-system sales. Currently, the Company 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 the Company’s off-system sales will go to the Company, the next $3.6 million in annual net profits from off-system sales will go to the Company’s Oklahoma customers, and any net profits of off-system sales in excess of these amounts will be credited in each sales year with 80 percent to the Company’s Oklahoma customers and the remaining 20 percent to the Company. 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
The Company intends to take steps to purchase electric generating facilities of not less than 400 MW’s to be integrated into the Company’s generation system. The Company 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, the Company must file an application with the OCC for the inclusion of the New Generation into the Company’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 the Company’s prospective cost of service. The period for recovery of the regulatory asset will be determined by the OCC. The Company expects this New Generation will provide savings, over a three-year period, in excess of $75.0 million to the Company’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 the Company’s Oklahoma customers, should have no effect on the profitability of the Company.
As indicated above, the Company’s decision with respect to the purchase of the New Generation will be subject to a review by the OCC as 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 the Company’s rate base. The OCC’s review is expected to include, but not be
7
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. The Company will provide monthly reports, for a period of 36 months, to the OCC Staff, documenting and providing proof of savings experienced by the Company’s customers. In determining the 36-month savings, the Company 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 the Company’s generating facilities including the New Generation compared to the fuel efficiencies of the Company’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, the Company will not include savings to its customers, which occur as the result of scheduled reductions in ongoing cogeneration contract payments. In the event the Company is unable to demonstrate at least $75.0 million in savings to its customers during this 36-month period, the Company will 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 the Company does not acquire the New Generation by December 31, 2003, the Company 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 the Company 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, the Company 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 the Company based on its performance in the utilization of its coal generation facilities. The greater the coal plant utilization, the greater the benefits received by the Company’s customers. The Company’s coal plants are among the nation’s most efficient and the energy produced by those plants displaces higher cost energy. The CUP Rider would have provided additional incentive for the Company by encouraging the Company 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”). The Company agreed not to seek implementation of a CUP Rider or a TIR Rider or other similar riders in the Company’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
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which increases costs to the Company’s Oklahoma customers, the Company will not be precluded from requesting a TIR Rider.
V. Gas Transportation Service
In a 1997 Order, the OCC approved a stipulation wherein the Company agreed to initiate a competitive bidding process for gas transportation service to its natural gas plants.
The Company’s current gas transportation service contract with Enogex for the Company’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, the Company agreed to consider competitive bidding as an option when analyzing the extension or renewal of the Company’s gas transportation service contract with Enogex prior to April 2004. The Company 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 the Company 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, the Company 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 the Company to reflect the completion of the recovery of the amortization premium paid by the Company 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 the Company from its Oklahoma customers in current rates.
In June 2001, the OCC approved a stipulation (the “Stipulation”) to the competitive bid process of the Company’s gas transportation service from Enogex. The Stipulation directed the Company 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 the Company’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.
The Company’s Generation Efficiency Performance Rider (“GEP Rider”) expired in June 2002. The GEP Rider was established initially in 1997 in connection with the Company’s 1996 general rate review and was intended to encourage the Company to lower its fuel costs by: (i) allowing the Company 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
9
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 the Company could recover under the GEP Rider by: (i) changing the Company’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 the Company’s costs exceed the new peer group by changing the percentage above which the Company 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 the Company’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 the Company or penalties charged to the Company. For the period between January 1, 2002 and June 30, 2002, the Company 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 the Company’s future operations. The Company’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 that component in cost-of-service for ratemaking, are passed through to the Company’s customers through automatic fuel adjustment clauses, which are subject to periodic review by the OCC, the APSC and the FERC. The OCC, the APSC and the FERC also have authority to review the appropriateness of gas transportation charges or other fees the Company 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 the Company. The Public Utility Regulatory Policy Act of 1978 requires electric utilities, such as the Company, 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. The Company 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 the Company, 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 (“ISOs”). On December 20, 1999, the FERC issued Order 2000,
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its final rule on 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 the Company) 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.
The Company is a member of the SPP, the regional reliability organization for Oklahoma, Arkansas, Kansas, Louisiana, Missouri and part of Texas. The Company 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, the Company 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, the Company executed the Conditional Withdrawal Agreement with the SPP. The Conditional Withdrawal Agreement would have had the effect of terminating the Company’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. The Company filed with the APSC a cost/benefit analysis to demonstrate that the Company's joining the MISO/SPP combination would have been in the public interest.
One of the conditions to 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 the merger because the conditions required to close the transaction would not be met in the foreseeable future. The Company has remained a member of the SPP while the MISO/SPP combination was pending, and the Company will continue to be a
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member of the SPP as the SPP, other SPP members and the Company 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 the Company's continued membership in the SPP are not expected to significantly impact the Company's 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 the Company 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
The Company, as a regulated utility, is subject to the accounting principles prescribed by the Financial Accounting Standards Board (“FASB”) Statement of Financial Accounting Standards (“SFAS”) No. 71, “Accounting for the Effects of Certain Types of Regulation.” SFAS No. 71 provides that certain 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.
The Company 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 the Company’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 the Company’s electric transmission and distribution assets and the Company believes that the continued use of SFAS No. 71 with respect to the related regulatory 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. The Company has taken steps in the past and intends to take appropriate steps in the future to remain a competitive supplier of electricity. While the Company is supportive of competition, it believes that all electric suppliers must be required to compete on a fair and equitable basis and the Company is advocating this position vigorously.
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Rate Activities and Proposals
In 2002, the Company 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, the Company, the OCC Staff, the Oklahoma Attorney General and other interested parties agreed to a Settlement Agreement which stipulated that the Company would file tariffs, designed to reflect an annual reduction of $25.0 million in the Company’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 the Company’s retail rates in the years 2003 and beyond.
The Company 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 the Company’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 the Company’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 the Company’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 the Company’s system conditions merit curtailment action. Customers that curtail their usage will receive payment for their curtailment response. This voluntary curtailment program seeks customers that can curtail on most curtailment event days, but may not be able to curtail every time that a curtailment event is required.
The previously discussed new rate options coupled with the Company’s existing rate choices provide many tariff options for the Company’s Oklahoma retail customers. The Company’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. The Company 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
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new rate option choices. There is 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 Company-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 24, 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 the Company 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, the Company was at one time 100 percent reliant upon natural gas as its fuel source for electric generation. In the early 1970’s, the Company 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 the Company's coal units, with an aggregate capability of approximately 2,535 MW's, are designed to burn low sulfur western coal. The Company purchases coal primarily under long-term contracts. During 2002, the Company 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, the Company'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, the Company 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.
The Company 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 the Company’s ability to use coal as its primary boiler fuel.
Natural Gas
The Company 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 the Company will be secured through monthly and day-to-day purchases as required.
In 1993, the Company began utilizing a natural gas storage facility that allows the Company to optimize the use of its generation assets.
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FINANCE AND CONSTRUCTION
Capital requirements and future contractual obligations as estimated for 2003 through 2006 are as follows:
- -----------------------------------------------------------------------------------------------------
Actual 2006 and
(In millions) 2002 2003 2004 2005 Beyond
- -----------------------------------------------------------------------------------------------------
Capital expenditures including AFUDC.........$ 198.7 (A) $ 149.0 (B) $ 142.0 $ 142.0 N/A
Maturities of long-term debt................. --- --- --- 109.4 $ 601.1
- -----------------------------------------------------------------------------------------------------
Total capital requirements............. 198.7 149.0 142.0 251.4 601.1
Operating lease obligations
Railcars.................................. 5.4 5.4 5.4 5.4 46.9
Unconditional purchase obligations
Cogeneration capacity payments............. 192.1 164.7 152.7 87.7 173.6
Other purchased power capacity payments.... 10.7 14.6 N/A N/A N/A
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.............................. 571.0 485.9 445.7 491.7 1,387.0
Amounts recoverable through automatic
fuel adjustment clause (C)................. (370.8) (334.9) (303.7) (240.3) (785.9)
- ------------------------------------------------------------------------------------------------------
Total, net............................$ 200.2 $ 151.0 $ 142.0 $ 251.4 $ 601.1
======================================================================================================
(A) Includes approximately $86.6 million from the January 2002 ice storm.
(B) Amounts do not include the acquisition of New Generation.
(C) Includes expected recoveries of costs incurred for the Company's railcar operating lease
obligations and the Company'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 the Company’s railcar leases shown above) and certain purchased power costs, as compared to the fuel component included in the cost-of-service for ratemaking, are passed through to the Company’s customers through automatic fuel adjustment clauses. Accordingly, while the cost of fuel related to operating leases and the vast majority of unconditional purchase obligations of the Company noted above may increase capital requirements, such costs are recoverable through automatic fuel adjustment clauses and have little, if any, impact on net capital requirements and future contractual obligations. The automatic fuel adjustment clauses are subject to periodic review by the OCC, the APSC and the FERC. The OCC, the APSC and the FERC also have authority to review the appropriateness of gas transportation charges or other fees the Company pays to Enogex. See Note 10 of Notes to Financial Statements for a further discussion.
The Company’s primary needs for capital are related to replacing or expanding existing facilities. Other capital requirements are primarily related to maturing debt, operating lease obligations, hedging activities and delays in recovering unconditional purchase obligations. The Company generally meets its cash needs through a
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combination of internally generated funds, short-term borrowings from Energy Corp. and permanent financings.
The amounts shown in the chart on page 18 do not include the cost of acquiring an electric generating plant with at least 400 MW of capacity, which the Company intends to acquire during 2003 in accordance with the Settlement Agreement approved by the OCC on November 20, 2002. Any generating facility acquired by the Company is expected to be financed through the issuance of common stock by Energy Corp. and through the issuance of debt by the Company.
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, the Company 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 its customers during the foreseeable future, the Company 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 and maturities of long-term debt.
The Company will use short-term borrowings from Energy Corp. to meet working capital requirements. The following table shows Energy Corp.‘s and the Company’s lines of credit in place at March 10, 2003. Energy Corp.’s short-term borrowings will consist of a combination of bank borrowings and commercial paper.
Lines of Credit (In millions)
-----------------------------------------------------------------------------------------
Entity Amount Maturity
-----------------------------------------------------------------------------------------
Energy Corp. (A) $ 15.0 April 6, 2003
200.0 January 8, 2004
100.0 January 15, 2004
The Company 100.0 June 26, 2003
-----------------------------------------------------------------------------------------
Total $ 415.0
=========================================================================================
(A) The lines of credit at Energy Corp. were used to back up its
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.
Energy Corp.‘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 Energy Corp. suffers an adverse ratings impact. The impact of a downgrade of Energy Corp.’s rating would result in an increase in the
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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 Energy Corp. and Enogex, the Company must obtain regulatory approval from the FERC in order to borrow on a short-term basis. The Company has the necessary regulatory approvals to incur up to $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 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”), the Company completed installation and certification of all required continuous emissions monitors at its generating stations in 1995. Since then the Company has submitted emissions data quarterly to the Environmental Protection Agency (“EPA”) as required by the CAAA. Beginning in 2000, the Company became subject to more stringent SO2 emission requirements. These lower limits had no significant financial impact due to the Company’s earlier decision to burn low sulfur coal. In 2002, the Company’s SO2 emissions were well below the allowable limits.
With respect to the NOX regulations of Title IV of the CAAA, the Company committed to meeting a 0.45 lbs/MMBtu NOX emission level in 1997 on all coal-fired boilers. As a result, the Company was eligible to exercise its option to extend the effective date of the lower emission requirements from the year 2000 until 2008. The Company’s average NOX emissions from its coal-fired boilers for 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
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that the Company’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, the Company had submitted all required permit applications. As of December 31, 2002, the Company had received Title V permits for all but one of its generating stations. Since the Company 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 the Company. 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 the Company 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 the Company’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. The Company has joined other utilities in voluntary CO2 sequestration projects through reforestation of land in the southern United States. In
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addition, the Company 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 the Company’s operations by requiring it to significantly reduce the use of coal as a fuel source.
The Company 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, the Company 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.
The Company has submitted one application during 2002 and will submit three more during 2003 to renew its Oklahoma Pollution Discharge Elimination System permits. The Company anticipates that the renewed permits will continue to allow operational flexibility.
The Company 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 the Company’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 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 financial position or results of operations.
EMPLOYEES
The Company had 1,972 employees at December 31, 2002.
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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.
The Company 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, the Company’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. The Company’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.
During the three years ended December 31, 2002, the Company’s gross property, plant and equipment additions were approximately $481.8 million and gross retirements were approximately $95.0 million. These additions were provided by internally generated funds from operating cash flows, short-term borrowings from Energy Corp. and permanent financings. The additions during this three-year period amounted to approximately 11.6 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 the Company of its intent to purchase the Company's electric distribution facilities for Enid and to terminate the Company'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 the Company 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, the Company 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 the Company the option to acquire the Company's electric system when the City Council approved the new 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) the Company's support of the Enid Citizens' Against the Government Takeover was improper; (v) the Company has violated the favored nations clause of the existing franchise; and (vi) the City of Enid and the Company 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 the Company's property to be transferred to the Company for inadequate consideration. Plaintiffs demand judgment for treble the value of the property
25
allegedly wrongfully transferred to the Company. On October 28, 1997, another resident filed a similar lawsuit against the Company, 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, the Company 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 the Company. (United States District Court for the Western District of Oklahoma, Case No. CIV-97-1010-L.) United States of America ex rel., Jack J. Grynberg v. Transok Inc. et al. (United States District Court for the Eastern District of Louisiana, Case No. 97-2089; United States District Court for the Western District of Oklahoma, Case No. 97-1009M.). On June 15, 1999, the Company was served with Plaintiff's Complaint. 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.
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
26
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 the Company, 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.
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. The Company 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.
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The Company filed an Amended Motion to Dismiss on January 23, 2002. Enogex and the Company 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. The Company entered into an agreement with the parent company of Central Oklahoma Oil and Gas Company ("COOG"), an unrelated third-party, to develop a natural gas storage facility (the "Stuart Storage Facility"). During 1996, the Company completed negotiations and contracted with COOG for gas storage service. Pursuant to the contract, COOG reimbursed the Company 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, Energy Corp. 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, Energy Corp. 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.
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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 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, Energy Corp. 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, Energy Corp. 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, Energy Corp. 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, Energy Corp. 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. Energy Corp. intends to continue to vigorously pursue its rights in conjunction with the NGSC Loan.
On August 12, 2002, Energy Corp. was improperly served with an Original Petition in a legal proceeding that has been filed by COOG and NGSC filed suit against Energy Corp. and Enogex in Texas. Enogex was properly served on August 12, 2002. COOG and NGSC have asserted 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) Energy Corp. was obligated to demand Enogex make the requisite payments to Energy Corp.; (2) Energy Corp. 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 Energy Corp.; (3) Enogex was and is obligated to make the payments to Energy Corp. until the indebtedness of NGSC to Energy Corp. 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 Energy Corp.; (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
29
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.
Energy Corp. 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 Energy Corp. 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. Enogex and Energy Corp. intend to continue to vigorously pursue their rights in conjunction with the Judgment and payment of the NGSC Loan.
5. The Company 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 the Company 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 the Company, Plaintiff has been permitted to amend its petition to include a claim based on theories of tort. Specifically, Plaintiff alleges, among other things, that the Company intentionally and tortuously interfered with contracts by falsifying documents, sponsoring false testimony and putting forward legal defenses, which are known by the Company to be without merit. If successful, Plaintiff believes that these theories could give Plaintiff a basis to seek punitive damages. The Company believes that, to the extent Plaintiff were successful on the merits of its claims of the Company's failure to take gas, these amounts would be recoverable through its regulated electric rates. The claims related to tortuous conduct, which the Company 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 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
30
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. 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 financial position, results of operations or cash flows.
Item 4. Submission of Matters to a Vote of Security Holders.
Under the reduced disclosure format permitted by General Instruction I(2)(c) of Form 10-K, the information otherwise required by this item has been omitted.
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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
James R. Hatfield 45 Senior Vice President and
Chief Financial Officer
Jack T. Coffman 59 Senior Vice President - Power Supply
Steven R. Gerdes 46 Vice President - Utility Operations
and Shared Services
Michael G. Davis 53 Vice President - Process Management
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 Energy Corp. Each Officer is to hold office until the Board of Directors meeting following the next Annual Meeting of Stockholders, currently scheduled for May 22, 2003.
32
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
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
1998-1999: Vice President -
Power Supply
Steven R. Gerdes 2003-Present: Vice President - Utility Operations
and Shared Services
1998-2003: Vice President - Shared Services
1998: Director - Shared Services
Michael G. Davis 2002-Present: Vice President -
Process Management
1998-2002: Vice President - Marketing
and Customer Care
1998: Vice President -
Marketing and Customer
Services
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
33
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)
34
PART II
Item 5. Market for Registrant's Common Equity and Related
Stockholder Matters.
Currently, all Company Common Stock, 40,378,745 shares, is held by Energy Corp. Therefore, there is no public trading market for the Company’s Common Stock.
35
Item 6.Selected Financial Data.
HISTORICAL DATA
2002 2001 2000 1999 1998
-----------------------------------------------------------------
SELECTED FINANCIAL DATA
(In millions, except per share data)
Operating revenues............... $ 1,388.0 $ 1,456.8 $ 1,453.6 $ 1,286.8 $ 1,312.1
Cost of goods sold............... 695.8 766.5 752.4 600.0 597.3
------------- ------------ ------------ ------------ -----------
Gross margin on revenues......... 692.2 690.3 701.2 686.8 714.8
Other operating expenses......... 453.1 453.7 430.1 417.3 399.0
------------- ------------ ------------ ------------ -----------
Operating income................. 239.1 236.6 271.1 269.5 315.8
Other income..................... 0.7 1.1 0.1 1.0 0.7
Other expense.................... 3.1 3.5 2.8 2.3 3.0
Net interest expense............. 39.0 43.6 45.7 44.2 46.6
Income tax expense............... 71.6 69.4 80.3 85.0 106.6
------------- ------------ ------------ ------------ -----------
Net income....................... 126.1 121.2 142.4 139.0 160.3
Preferred dividend requirements.. --- --- --- --- 0.7
------------- ------------ ------------ ------------ -----------
Earnings available for common
shareholder.................... $ 126.1 $ 121.2 $ 142.4 $ 139.0 $ 159.6
============= ============ ============ ============ ===========
Earnings per average common
share.......................... $ 3.12 $ 3.00 $ 3.53 $ 3.44 $ 3.95
============= ============ ============ ============ ===========
Dividends declared per share..... $ 2.57 $ 2.57 $ 2.56 $ 2.56 $ 3.90
Long-term debt................... $ 710.5 $ 700.4 $ 702.6 $ 593.0 $ 702.9
Total assets..................... $ 2,550.6 $ 2,434.3 $ 2,437.4 $ 2,320.7 $ 2,320.1
CAPITALIZATION RATIOS (A)
Stockholders' equity............. 56.00% 56.93% 56.91% 59.99% 54.84%
Long-term debt................... 44.00% 43.07% 43.09% 40.01% 45.16%
INTEREST COVERAGES
Before federal income taxes
(including AFUDC)............... 5.79X 5.08X 5.54X 5.80X 6.34X
(excluding AFUDC)............... 5.77X 5.07X 5.50X 5.79X 6.32X
After federal income taxes
(including AFUDC)............... 4.06X 3.60X 3.91X 3.98X 4.21X
(excluding AFUDC)............... 4.04X 3.58X 3.86X 3.96X 4.19X
=========================================================================================================
(A)Capitalization ratios = [Stockholders’ equity / (Stockholders’ equity + Long-term debt)]
and [Long-term debt / (Stockholders’ equity + Long-term debt)].
36
Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations.
Introduction
Oklahoma Gas and Electric Company (the “Company”) generates, transmits, distributes and sells electric energy in Oklahoma and western Arkansas and is subject to regulation by the Oklahoma Corporation Commission (“OCC”), the Arkansas Public Service Commission (“APSC”) and the Federal Energy Regulatory Commission (“FERC”). The Company is a wholly-owned subsidiary of OGE Energy Corp. (“Energy Corp.”) which is an energy and energy services provider offering physical delivery and management of both electricity and natural gas in the south central United States. The Company 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. The Company sold its retail gas business in 1928 and is no longer engaged in the gas distribution business.
Company Strategy
In early 2002, Energy Corp. 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, Energy Corp. does not anticipate that deregulation of the electricity markets in Oklahoma or Arkansas will occur in the foreseeable future. The strategic direction of Energy Corp. has been revised to reflect these developments. As a result, Energy Corp. expects potentially slower earnings growth than associated with deregulation but with less variability of those earnings.
Energy Corp.’s business strategy will utilize the diversified asset position of the Company and Enogex Inc. and subsidiaries (“Enogex”) to provide energy products and services to customers primarily in the south central United States. Energy Corp. will focus on those products and services with limited or manageable commodity exposure. Energy Corp. intends for the Company to continue as an integrated utility engaged in the generation and the distribution of electricity and to represent over time approximately 70 percent of Energy Corp.’s consolidated assets. The remainder of Energy Corp.’s assets will be in Enogex’s pipeline businesses. In addition to the incremental growth opportunities that Enogex provides, Energy Corp. believes that Enogex’s risk management capabilities, commercial skills and market information provide value to all of Energy Corp.’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, Energy Corp. 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, the Company 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, the Company 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
37
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 the Company to generate electricity for its customers at prices below those being paid by the Company under existing qualified cogeneration and small power production producers’ contracts (“QF contracts”). Unless extended by the Company, many of these QF contracts will expire over the next one to five years. Accordingly, the Company will continue to explore opportunities to purchase power plants in order to serve its native load. The Company 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.
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”, “except”, “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; 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 results of operations and financial position during the last three years. The following information should be read in conjunction with the Financial Statements and Notes thereto. Known trends and contingencies of a material nature are discussed to the extent considered relevant.
Regulatory Considerations
On October 11, 2002, the Company, the OCC Staff, the Oklahoma Attorney General and other interested parties agreed to a settlement (the “Settlement Agreement”) of the Company’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 the Company’s Oklahoma customers which begins with the first regular billing cycle occurring 41 days after the issuance of the OCC order approving the Settlement
38
Agreement; (ii) recovery by the Company, through rate base, of the capital expenditures associated with the January 2002 ice storm; (iii) recovery by the Company, over three years, of the $5.4 million in deferred operating costs, associated with the January 2002 ice storm, through the Company’s rider for sales to other utilities and power marketers (“off-system sales”); (iv) the Company to acquire electric generating capacity (“New Generation”) of not less than 400 MW’s to be integrated into the Company’s generation system.
The Company expects that the New Generation will provide savings, over a three-year period, in excess of $75 million. If the Company is unable to demonstrate at least $75 million in savings, the Company will be required to credit to its Oklahoma customers any unrealized savings below $75 million. In the event the Company does not acquire the New Generation by December 31, 2003, the Company 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 the Company 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 10 of Notes to Financial Statements for a further discussion of the Settlement Agreement and of other recent actions relating to the Company’s rates.
The Company has been and will continue to be affected by competitive changes to the utility industry. Significant changes already have occurred and additional changes are being proposed to the wholesale electric market. Although it appears unlikely in the near future that changes will occur to retail regulation in the states served by the Company due to the significant problems faced by California in its electric deregulation efforts and other factors, significant changes are possible, which could significantly change the manner in which the Company conducts its business. These developments at the federal and state levels are described in more detail below under “Electric Competition; Regulation.”
2003 Outlook
Energy Corp. plans to issue equity in 2003 to support the capital structure of the Company for its purchase of generation and for any other corporate purposes including the repayment of short-term debt. Energy Corp. 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 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, the Company 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). The Company 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
39
affecting the Company’s 2003 net income will be weather, the Company’s ability to control operating and maintenance expenses and customer growth. Expected 2003 net income assumes a 37 percent effective tax rate.
The Company has significant seasonality in its earnings. The Company typically shows minimal earnings or slight losses in the first and fourth quarters with a majority of earnings in the third quarter due to the seasonal nature of air conditioning demand.
Percent Change
From Prior Year
---------------
(In millions, except per share data) 2002 2001 2000 2002 2001
- ---------------------------------------------------------------------------------------------------
Operating income............................. $ 239.1 $ 236.6 $ 271.1 1.1 (12.7)
Net income................................... $ 126.1 $ 121.2 $ 142.4 4.0 (14.9)
Average common shares outstanding............ 40.4 40.4 40.4 --- ---
Dividends declared per share................. $ 2.57 $ 2.57 $ 2.56 --- (0.4)
===================================================================================================
In reviewing its operating results, the Company believes that it is appropriate to focus on operating income as reported in its Statements of Income. Operating income was approximately $239.1 million, $236.6 million and $271.1 million in 2002, 2001 and 2000, respectively.
(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. The Company’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 the Company’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 the Company’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,
40
decreased the gross margin by approximately $3.6 million in 2002. Additionally, lower levels of natural gas transportation cost that the Company 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 10 of Notes to 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 the Company 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"). The Company's electric generating capability is fairly evenly divided between coal and natural gas and provides for flexibility to use either fuel to the best economic advantage for the Company and its customers. In 2002, the Company's fuel mix was 72 percent coal and 28 percent natural gas. Though the Company 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 the Company’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 the Company. The automatic fuel adjustment clauses are subject to periodic review by the OCC, the APSC and the FERC. The OCC, the APSC and the FERC have authority to review the appropriateness of gas transportation charges or other fees the Company pays to Enogex. See Note 10 of Notes to 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. The Company’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 the Company’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
41
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.
Other Income and Expense
Other income includes, among other things, contract work performed by the Company, non-operating rental income and profit on the retirement of fixed assets. Other income decreased approximately $0.4 million or 36.4 percent in 2002 as compared to 2001. This decrease was primarily due to approximately a $0.3 million decrease in non-operating rental income.
Other expense includes, among other things, expenses from loss on retirement of fixed assets, miscellaneous charitable donations and expenditures for certain civic, political and related activities. Other expense decreased approximately $0.4 million or 11.4 percent in 2002 as compared to 2001. This decrease was primarily due to approximately a $0.2 million decrease in miscellaneous charitable donations and a decrease of approximately $0.1 million in expenditures for certain civic, political and related activities.
Net Interest Expense
Net interest expense includes interest income, interest expense and other interest charges. Net interest expense decreased approximately $4.6 million or 10.6 percent in 2002 as compared to 2001. This decrease was primarily due to a reduction in interest expense of approximately $2.9 million related to lower interest rates on outstanding debt achieved from entering into an interest rate swap agreement in 2001. Also contributing to the decrease was approximately a $1.9 million decrease in interest expense due to Energy Corp. related to lower borrowings in 2002. These decreases were partially offset by approximately a $0.5 million increase in interest expense due to an increase in commercial paper service fees.
Income Tax Expense
Income tax expense increased approximately $2.2 million or 3.2 percent in 2002 as compared to 2001 primarily from higher pre-tax income in 2002.
2001 compared to 2000. The Company’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 the Company 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 10 of Notes to 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 the Company'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 the Company 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. The Company’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 the Company’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.
Other Income and Expense
Other income increased approximately $1.0 million in 2001 as compared to 2000. This increase was primarily due to approximately a $0.9 million increase in contract work performed by the Company.
43
Other expense increased approximately $0.7 million in 2001 as compared to 2000, primarily due to an increase of approximately $0.6 million in miscellaneous corporate expenses.
Net Interest Expense
Net interest expense decreased approximately $2.1 million or 4.6 percent in 2001 as compared to 2000. This decrease was primarily due to a reduction in interest expense of approximately $2.2 million related to lower interest rates on outstanding debt achieved from entering into an interest rate swap agreement in 2001 and approximately a $2.0 million decrease related to lower variable interest expense due to lower interest rates. 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
Income tax expense decreased approximately $10.9 million or 13.6 percent in 2001 as compared to 2000 primarily due to lower pre-tax income in 2001.
44
Liquidity and Capital Requirements
Capital requirements and future contractual obligations as estimated for 2003 through 2006 and beyond are as follows:
- --------------------------------------------------------------------------------------------------------
Actual 2006 and
(In millions) 2002 2003 2004 2005 Beyond
- --------------------------------------------------------------------------------------------------------
Capital expenditures including AFUDC.........$ 198.7 (A) $ 149.0 (B) $ 142.0 $ 142.0 N/A
Maturities of long-term debt................. --- --- --- 109.4 $ 601.1
- --------------------------------------------------------------------------------------------------------
Total capital requirements............. 198.7 149.0 142.0 251.4 601.1
Operating lease obligations
Railcars................................... 5.4 5.4 5.4 5.4 46.9
Unconditional purchase obligations
Cogeneration capacity payments............. 192.1 164.7 152.7 87.7 173.6
Other purchased power capacity payments.... 10.7 14.6 N/A N/A N/A
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.............................. 571.0 485.9 445.7 491.7 1,387.0
Amounts recoverable through automatic
fuel adjustment clause (C)................. (370.8) (334.9) (303.7) (240.3) (785.9)
- --------------------------------------------------------------------------------------------------------
Total, net............................$ 200.2 $ 151.0 $ 142.0 $ 251.4 $ 601.1
========================================================================================================
(A) Includes approximately $86.6 million from the January 2002 ice storm.
(B) Amounts do not include the acquisition of New Generation.
(C) Includes expected recoveries of costs incurred for the Company's railcar operating lease
obligations and the Company'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 the Company’s railcar leases shown above) and certain purchased power costs, as compared to the fuel component included in the cost-of-service for ratemaking, are passed through to the Company’s customers through automatic fuel adjustment clauses. Accordingly, while the cost of fuel related to operating leases and the vast majority of unconditional purchase obligations of the Company noted above may increase capital requirements, such costs are recoverable through automatic fuel adjustment clauses and have little, if any, impact on net capital requirements and future contractual obligations. The automatic fuel adjustment clauses are subject to periodic review by the OCC, the APSC and the FERC. The OCC, the APSC and the FERC also have authority to review the appropriateness of gas transportation charges or other fees the Company pays to Enogex. See Note 10 of Notes to Financial Statements for a further discussion.
The Company’s primary needs for capital are related to replacing or expanding existing facilities in its electric utility business. Other capital requirements are primarily related to maturing debt, operating lease obligations, hedging activities and delays in recovering unconditional purchase obligations. The Company generally meets its cash needs through a
45
combination of internally generated funds, short-term borrowings from Energy Corp. and permanent financings.
The amounts shown in the chart on page 45 do not include the cost of acquiring an electric generating plant with at least 400 MW of capacity, which the Company intends to acquire during 2003 in accordance with the Settlement Agreement approved by the OCC on November 20, 2002. Any generating facility acquired by the Company is expected to be financed through the issuance of common stock by Energy Corp. and through the issuance of debt by the Company.
2002 Capital Requirements and Financing Activities
Total capital requirements, consisting of capital expenditures and maturities of long-term debt, were approximately $198.7 million and contractual obligations, net of recoveries through automatic fuel adjustment clauses, were approximately $1.5 million resulting in total net capital requirements and contractual obligations of approximately $200.2 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 the Company’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 $112.1 million. This compares to net capital requirements of approximately $132.3 million and net contractual obligations of approximately $3.2 million totaling approximately $135.5 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 and short-term borrowings from Energy Corp. Energy Corp.’s short-term borrowings consist primarily of commercial paper and short-term bank loans. Energy Corp. 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, Energy Corp. commercial paper was used to fund expenditures associated with the ice storm. At December 31, 2002, the Company had outstanding short-term borrowings of approximately $101.1 million.
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 Statements of Income. The value of effective fair value hedges are recorded in Price Risk Management assets and liabilities in the accompanying 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.
During 2001, the Company 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“). This
46
interest rate swap qualified as a fair value hedge under SFAS No. 133 and met 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 this interest rate swap was to achieve a lower cost of debt and to raise the percentage of total corporate long-term floating rate debt to reflect a level more in line with industry standards.
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, the Company 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 its customers during the foreseeable future, the Company 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 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 $32.9 million in 2001 to approximately $37.3 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 $38.3 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 8 of Notes to 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
47
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 $29.6 million and $11.9 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 $137.8 million and $85.6 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 $141.3 million and $74.9 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 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 Statements of Income in future periods.
On October 31, 2002, Fitch Ratings (“Fitch”) reaffirmed the rating of the Company’s senior unsecured debt at AA- and short-term debt at F1. The rating outlook is stable as Fitch cited the solid financial position, low business risk and strong cash flows at the Company.
On January 15, 2003, Standard & Poor’s Ratings Services (“Standard & Poor’s”) lowered the credit rating of the Company’s senior unsecured debt from A- to BBB+. The outlook is now stable as Standard & Poor’s cited the relatively low-risk low-cost efficient operations of the Company. 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 financial position or results of operations.
At December 31, 2002, Moody’s Investors Service (“Moody’s”) credit rating of the Company’s senior unsecured debt was A1. On February 5, 2003, Moody’s lowered the credit rating of the Company’s senior unsecured debt to A2 from A1. The outlook for the Company is stable. Moody’s cited the diminished credit profile of the Company with the Company having competitive generation and stable cash flow but with regulatory risk associated with New Generation. 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 financial position or results of operations.
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.
48
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 and maturities of long-term debt.
The Company will use short-term borrowings from Energy Corp. to meet working capital requirements. The following table shows the Company’s and Energy Corp.’s lines of credit in place at March 10, 2003. Energy Corp.’s short-term borrowings will consist of a combination of bank borrowings and commercial paper.
Lines of Credit (In millions)
----------------------------------------------------------------------------------------------
Entity Amount Maturity
----------------------------------------------------------------------------------------------
Energy Corp. (A) $ 15.0 April 6, 2003
200.0 January 8, 2004
100.0 January 15, 2004
The Company 100.0 June 26, 2003
----------------------------------------------------------------------------------------------
Total $ 415.0
==============================================================================================
(A) The lines of credit at Energy Corp. were used to back up its 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.
Energy Corp.’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 Energy Corp. suffers an adverse ratings impact. The impact of a downgrade of Energy Corp.’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 Energy Corp. and Enogex, the Company must obtain regulatory approval from the FERC in order to borrow on a short-term basis. The Company has the necessary regulatory approvals to incur up to $400 million in short-term borrowings at any one time.
Critical Accounting Policies and Estimates
The Financial Statements and Notes to Financial Statements contain information that is pertinent to Management’s Discussion and Analysis. In preparing the financial statements, management is required to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial
49
statements and the reported amounts of revenues and expenses during the reporting period. Changes to these assumptions and estimates could have a material effect on the Company’s Financial Statements particularly as they relate to pension expense. 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, contingency reserves, unbilled revenue and the allowance for uncollectible accounts receivable. The selection, application and disclosure of the following critical accounting estimates have been discussed with the Company’s audit committee.
Pension and other postretirement plan expenses and liabilities are determined on an actuarial basis and are affected by the market value of plan assets, estimates of the expected return on plan assets 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 8 of Notes to Financial Statements. The assumed return on plan assets is based on management’s expectation of the long-term return on the plan assets portfolio. The discount rate used to compute the present value of plan liabilities is based generally on rates of high-grade corporate bonds with maturities similar to the average period over which benefits will be paid. See “Future Capital Requirements” for a further discussion.
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.
The Company reads its customers’ meters and sends bills to its customers throughout each month. As a result, there is a significant amount of customers’ electricity consumption that has not been billed at the end of each month. Unbilled revenue is presented in Accrued Unbilled Revenues on the Balance Sheets and in Operating Revenues on the Statements of Income based on estimates of usage and prices during the period. At December 31, 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 Balance Sheets and is included in Other Operation and
50
Maintenance Expense on the 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.
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 Statements of Income. The value of effective fair value hedges are recorded in Price Risk Management assets or liabilities in the accompanying 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.
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.” 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 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
51
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 required 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 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 financial position or results of operations.
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
52
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 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 failure 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 the Company’s future operations. The Company’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.
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 the Company, have increased their own in-house wholesale marketing efforts and the number of entities with whom they historically traded. Moreover, power marketers are an incresingly 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. IPPs 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 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 the Company) to either join in an RTO filing, or, alternatively, to submit a filing
53
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.
The Company is a member of the Southwest Power Pool (“SPP”), the regional reliability organization for Oklahoma, Arkansas, Kansas, Louisiana, Missouri and part of Texas. The Company 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, the Company 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, the Company executed the Conditional Withdrawal Agreement with the SPP. The Conditional Withdrawal Agreement would have had the effect of terminating the Company’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. The Company filed with the APSC a cost/benefit analysis to demonstrate that the Company'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 the merger because the conditions required to close the transaction would not be met in the foreseeable future. The Company has remained a member of the SPP while the MISO/SPP combination was pending, and the Company will continue to be a member of the SPP as the SPP, other SPP members and the Company 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 the Company's continued membership in the SPP are not expected to significantly impact the Company's financial results.
54
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 the Company 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.
The Company, as a regulated utility, is subject to the accounting principles prescribed by SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation.” SFAS No. 71 provides that certain 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.
The Company 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
55
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 the Company’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 the Company’s 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
Energy Corp. through its subsidiaries is defending various claims and legal actions, including environmental actions, which are common to its operations. Energy Corp.’s subsidiaries, primarily the Company, also could be impacted by various proposed environmental 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 9 of Notes to 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 economics conditions, abnormal weather, load growth, acquisitions of other businesses, actions by ratings agencies, inflation, changes in environment 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 interest rates.
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 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. This interest rate swap qualified as a fair value hedge under SFAS No. 133 and met 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 this interest rate swap was to achieve a lower cost of debt and to raise the percentage of total corporate long-term floating rate debt to reflect a level more in line with industry standards.
The fair value of the Company’s long-term debt is based on quoted market prices. The valuation of the Company’s interest rate swap was determined primarily based on quoted market prices. The Company has no long-term debt maturing until 2005. The following table shows the Company’s long-term debt maturities and the weighted-average interest rates by maturity date.
=======================================================================================
2002 Year-end
(Dollars in millions) 2005 Thereafter Total Fair Value
- ---------------------------------------------------------------------------------------
Fixed rate debt
Principal amount......... $ 109.4 $ 348.2 $ 457.6 $ 499.7
Weighted-average
interest rate.......... 7.125% 6.55% 6.69% ---
Variable rate debt
Principal amount (A)..... --- $ 252.9 $ 252.9 $ 252.9
Weighted-average
interest rate.......... --- 4.11% 4.11% ---
=======================================================================================
(A) Amount includes an increase to the fair value of long-term debt for
approximately $7.5 million due to the Company's interest rate swap.
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Item 8. Financial Statements and Supplementary Data.
OKLAHOMA GAS AND ELECTRIC COMPANY
BALANCE SHEETS
December 31 (In millions) 2002 2001
====================================================================================
ASSETS
CURRENT ASSETS
Cash and cash equivalents................................. $ 0.3 $ 0.4
Accounts receivable - customers, net...................... 97.7 98.3
Accrued unbilled revenues................................. 28.2 35.6
Accounts receivable - other, net.......................... 8.1 12.1
Fuel inventories, at LIFO cost............................ 65.4 54.9
Materials and supplies, at average cost................... 40.7 32.6
Accumulated deferred tax assets........................... 7.5 7.5
Fuel clause under recoveries.............................. 14.7 ---
Recoverable take or pay gas charges....................... --- 30.8
Other..................................................... 5.3 4.7
- ------------------------------------------------------------ --------- ---------
Total current assets.................................... 267.9 276.9
- ------------------------------------------------------------ --------- ---------
OTHER PROPERTY AND INVESTMENTS, at cost..................... 8.1 15.5
- ------------------------------------------------------------ --------- ---------
PROPERTY, PLANT AND EQUIPMENT
In service................................................ 4,099.2 3,961.7
Construction work in progress............................. 38.7 22.5
- ------------------------------------------------------------ --------- ---------
Total property, plant and equipment..................... 4,137.9 3,984.2
Less accumulated depreciation......................... 2,040.3 1,978.9
- ------------------------------------------------------------ --------- ---------
Net property, plant and equipment......................... 2,097.6 2,005.3
- ------------------------------------------------------------ --------- ---------
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........... 37.8 42.4
Prepaid benefit obligation................................ 29.6 11.8
Price risk management..................................... 7.5 ---
Other..................................................... 34.8 36.3
- ------------------------------------------------------------ --------- ---------
Total deferred charges and other assets................. 177.0 136.6
- ------------------------------------------------------------ --------- ---------
TOTAL ASSETS................................................ $2,550.6 $2,434.3
============================================================ ========= =========
The accompanying Notes to Financial Statements are an integral part hereof.
58
OKLAHOMA GAS AND ELECTRIC COMPANY
BALANCE SHEETS (Continued)
December 31 (In millions) 2002 2001
======================================================================================
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable - affiliates.............................. $ 26.1 $ 25.9
Accounts payable - other................................... 63.2 58.8
Advances from parent....................................... 101.1 ---
Customers' deposits........................................ 33.0 28.4
Accrued taxes.............................................. 20.3 20.3
Accrued interest........................................... 13.9 14.4
Tax collections payable.................................... 6.7 4.7
Accrued vacation........................................... 11.6 11.8
Provision for payments of take or pay gas.................. --- 30.8
Fuel clause over recoveries................................ --- 23.4
Other...................................................... 10.4 6.3
- ------------------------------------------------------------- --------- ---------
Total current liabilities................................ 286.3 224.8
- ------------------------------------------------------------- --------- ---------
LONG-TERM DEBT............................................... 710.5 700.4
- ------------------------------------------------------------- --------- ---------
DEFERRED CREDITS AND OTHER LIABILITIES
Accrued pension and benefit obligations.................... 148.6 80.8
Accumulated deferred income taxes.......................... 421.5 439.0
Accumulated deferred investment tax credits................ 47.1 52.3
Price risk management...................................... --- 2.4
Provision for payments of take or pay gas.................. 32.5 8.5
Other...................................................... --- 0.5
- ------------------------------------------------------------- --------- ---------
Total deferred credits and other liabilities............. 649.7 583.5
- ------------------------------------------------------------- --------- ---------
STOCKHOLDERS' EQUITY
Common stockholders' equity................................ 512.4 512.4
Retained earnings.......................................... 455.2 433.1
Accumulated other comprehensive loss, net of tax........... (63.5) (19.9)
- ------------------------------------------------------------- --------- ---------
Total stockholders' equity............................... 904.1 925.6
- ------------------------------------------------------------- --------- ---------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY................... $2,550.6 $2,434.3
============================================================= ========= =========
The accompanying Notes to Financial Statements are an integral part hereof.
59
OKLAHOMA GAS AND ELECTRIC COMPANY
STATEMENTS OF CAPITALIZATION
December 31 (In millions) 2002 2001
=============================================================================================
STOCKHOLDERS' EQUITY
Common stock, par value $2.50 per share; authorized 100.0 shares;
and outstanding 40.4 shares....................................... $ 100.9 $ 100.9
Premium on capital stock............................................ 411.5 411.5
Retained earnings................................................... 455.2 433.1
Accumulated other comprehensive loss, net of tax.................... (63.5) (19.9)
- ---------------------------------------------------------------------- --------- ---------
Total stockholders' equity...................................... 904.1 925.6
- ---------------------------------------------------------------------- --------- ---------
LONG-TERM DEBT
SERIES DATE DUE
Senior Notes-
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-
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)
- ---------------------------------------------------------------------- --------- ---------
Total long-term debt............................................ 710.5 700.4
- ---------------------------------------------------------------------- --------- ---------
Total Capitalization.................................................. $1,614.6 $1,626.0
====================================================================== ========= =========
The accompanying Notes to Financial Statements are an integral part hereof.
60
OKLAHOMA GAS AND ELECTRIC COMPANY
STATEMENTS OF INCOME
Year ended December 31 (In millions, except per share data) 2002 2001 2000
==================================================================================================
OPERATING REVENUES.......................................... $1,388.0 $1,456.8 $1,453.6
COST OF GOODS SOLD.......................................... 695.8 766.5 752.4
- ------------------------------------------------------------ --------- --------- ---------
Gross margin on revenues.................................... 692.2 690.3 701.2
Other operation and maintenance........................... 282.9 287.3 267.4
Depreciation.............................................. 123.1 119.8 117.2
Taxes other than income................................... 47.1 46.6 45.5
- ------------------------------------------------------------ --------- --------- ---------
OPERATING INCOME............................................ 239.1 236.6 271.1
- ------------------------------------------------------------ --------- --------- ---------
OTHER INCOME (EXPENSE)
Other income.............................................. 0.7 1.1 0.1
Other expense............................................. (3.1) (3.5) (2.8)
- ------------------------------------------------------------ --------- --------- ---------
Net other expense....................................... (2.4) (2.4) (2.7)
- ------------------------------------------------------------ --------- --------- ---------
INTEREST INCOME (EXPENSE)
Interest income........................................... 1.2 2.4 1.1
Interest on long-term debt................................ (38.1) (42.3) (45.9)
Allowance for borrowed funds used during construction..... 0.9 0.7 2.2
Interest on short-term debt and other interest charges.... (3.0) (4.4) (3.1)
- ------------------------------------------------------------ --------- --------- ---------
Net interest expense.................................... (39.0) (43.6) (45.7)
- ------------------------------------------------------------ --------- --------- ---------
INCOME BEFORE TAXES......................................... 197.7 190.6 222.7
INCOME TAX EXPENSE.......................................... 71.6 69.4 80.3
- ------------------------------------------------------------ --------- --------- ---------
NET INCOME.................................................. $ 126.1 $ 121.2 $ 142.4
============================================================ ========= ========= =========
AVERAGE COMMON SHARES OUTSTANDING........................... 40.4 40.4 40.4
EARNINGS PER AVERAGE COMMON SHARE........................... $ 3.12 $ 3.00 $ 3.53
============================================================ ========= ========= =========
DIVIDENDS DECLARED PER SHARE................................ $ 2.57 $ 2.57 $ 2.56
============================================================ ========= ========= =========
The accompanying Notes to Financial Statements are an integral part hereof.
61
OKLAHOMA GAS AND ELECTRIC COMPANY
STATEMENTS OF RETAINED EARNINGS
Year ended December 31 (In millions) 2002 2001 2000
====================================================================================================
BALANCE AT BEGINNING OF PERIOD................................... $ 433.1 $ 415.5 $ 376.7
ADD: Net income.................................................. 126.1 121.2 142.4
- ----------------------------------------------------------------- -------- -------- --------
Total..................................................... 559.2 536.7 519.1
- ----------------------------------------------------------------- -------- -------- --------
DEDUCT: Dividends declared on common stock....................... 104.0 103.6 103.6
- ----------------------------------------------------------------- -------- -------- --------
BALANCE AT END OF PERIOD......................................... $ 455.2 $ 433.1 $ 415.5
================================================================= ======== ======== ========
OKLAHOMA GAS AND ELECTRIC COMPANY
STATEMENTS OF COMPREHENSIVE INCOME
Year ended December 31 (In millions) 2002 2001 2000
====================================================================================================
Net income....................................................... $ 126.1 $ 121.2 $ 142.4
Other comprehensive loss, net of tax:
Minimum pension liability adjustment [($71.0) and ($32.5)
pre-tax, respectively]....................................... (43.6) (19.9) ---
- ----------------------------------------------------------------- -------- -------- --------
Total comprehensive income................................ $ 82.5 $ 101.3 $ 142.4
================================================================= ======== ======== ========
The accompanying Notes to Financial Statements are an integral part hereof.
62
OKLAHOMA GAS AND ELECTRIC COMPANY
STATEMENTS OF CASH FLOWS
Year ended December 31 (In millions) 2002 2001 2000
===================================================================================================
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income................................................... $ 126.1 $ 121.2 $ 142.4
Adjustments to reconcile net income to net cash provided
from operating activities
Depreciation............................................... 123.1 119.8 117.2
Deferred income taxes and investment tax credits, net...... 8.4 (0.2) (4.7)
Other assets............................................... (50.4) (26.9) (29.1)
Other liabilities.......................................... 25.1 0.6 5.7
Change in certain current assets and liabilities
Accounts receivable - customers, net...................... 0.6 32.6 (34.7)
Accounts receivable - other, net.......................... 4.0 2.0 (6.0)
Accrued unbilled revenues................................. 7.4 13.4 (8.8)
Fuel, materials and supplies inventories.................. (18.6) 20.8 (2.5)
Fuel clause under recoveries.............................. (14.7) 35.4 (35.4)
Other current assets...................................... (0.6) (3.1) (1.4)
Accounts payable.......................................... 4.4 (41.3) 70.2
Accounts payable - affiliates............................. 0.2 (25.4) (24.4)
Customers' deposits....................................... 4.6 5.8 0.5
Accrued taxes............................................. --- 0.3 0.4
Accrued interest.......................................... (0.5) (0.1) ---
Fuel clause over recoveries............................... (23.4) 23.4 (1.6)
Other current liabilities................................. 5.6 (3.2) 3.5
- -------------------------------------------------------------- -------- -------- --------
Net Cash Provided from Operating Activities............... 201.3 275.1 191.3
- -------------------------------------------------------------- -------- -------- --------
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures......................................... (198.7) (132.3) (128.4)
- -------------------------------------------------------------- -------- -------- --------
Net Cash Used in Investing Activities..................... (198.7) (132.3) (128.4)
- -------------------------------------------------------------- -------- -------- --------
CASH FLOWS FROM FINANCING ACTIVITIES
Increase (decrease) in short-term debt, net.................. 101.1 (39.2) 39.2
Dividends paid on common stock............................... (103.8) (103.6) (103.5)
- -------------------------------------------------------------- -------- -------- --------
Net Cash Used in Financing Activities..................... (2.7) (142.8) (64.3)
- -------------------------------------------------------------- -------- -------- --------
NET DECREASE IN CASH AND CASH EQUIVALENTS..................... (0.1) --- (1.4)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD.............. 0.4 0.4 1.8
- -------------------------------------------------------------- -------- -------- --------
CASH AND CASH EQUIVALENTS AT END OF PERIOD.................... $ 0.3 $ 0.4 $ 0.4
============================================================== ======== ======== ========
The accompanying Notes to Financial Statements are an integral part hereof.
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OKLAHOMA GAS AND ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
1. Summary of Significant Accounting Policies
Organization
Oklahoma Gas and Electric Company (the "Company") generates, transmits, distributes and sells electric energy in Oklahoma and western Arkansas. The Company is a wholly-owned subsidiary of OGE Energy Corp. ("Energy Corp.") which 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 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. The Company sold its retail gas business in 1928 and is no longer engaged in the gas distribution business.
Accounting Records
The accounting records of the Company are maintained in accordance with the Uniform System of Accounts prescribed by the Federal Energy Regulatory Commission (“FERC”) and adopted by the Oklahoma Corporation Commission (“OCC”) and the Arkansas Public Service Commission (“APSC”). Additionally, the Company, as a regulated utility, is subject to the accounting principles prescribed by the Financial Accounting Standards Board (“FASB”) Statement of Financial Accounting Standards (“SFAS”) No. 71, “Accounting for the Effects of Certain Types of Regulation.” SFAS No. 71 provides that certain 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.
The Company 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.
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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 the Company’s revenues. These amounts are being recovered in rates as the temporary differences that generated the income tax benefit turn around. The provisions of SFAS No. 71 allowed the Company to treat these amounts as regulatory assets and liabilities and they are being amortized over the estimated remaining life of the assets to which they relate. The regulatory assets and liabilities are netted on the Company’s 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.
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 Statements of Income. The value of effective fair value hedges are recorded in Price Risk Management assets and liabilities in the accompanying 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.
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
65
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.” 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 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 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
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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 financial position or results of operations.
Price Risk Management Assets and Liabilities
The Company periodically utilizes derivative contracts to reduce exposure to adverse interest rate fluctuations. During 2002 and 2001, the Company’s use of price risk management instruments primarily involved the use of an interest rate swap agreement 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. This agreement involves the receipt of fixed rate amounts in exchange for floating rate interest payments over the life of the agreement without an exchange of the underlying principal amount. The Company accounts for its use of 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 agreement has been designated as a fair value hedge 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.
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Use of Estimates
In preparing the financial statements, management is required to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Changes to these assumptions and estimates could have a material effect on the Company’s financial statements. In management’s opinion, the areas of the Company where the most significant judgment is exercised is in the valuation of pension plan assumptions, contingency reserves, unbilled revenue and the allowance for uncollectible accounts receivable.
Allowance for Uncollectible Accounts Receivable
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 was approximately $4.7 million and $6.2 million at December 31, 2002 and 2001, respectively.
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”). Replacement 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 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.
(In millions) 2002 2001
===========================================================================================
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
- -------------------------------------------------------------------------------------------
Total property, plant and equipment..................... $ 4,137.9 $ 3,984.2
===========================================================================================
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Depreciation
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.
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 Statements of Income and as a charge to Construction Work in Progress in the accompanying 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 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 $19.6 million and $20.2 million at December 31, 2002 and 2001, respectively, and are classified as Accounts Payable in the accompanying Balance Sheets. Sufficient funds were available to fund these outstanding checks when they were presented for payment.
Heat Pump Loans
The Company has a heat pump loan program, whereby, qualifying customers may obtain a loan from the Company 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.
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
The Company reads its customers’ meters and sends bills to its customers throughout each month. As a result, there is a significant amount of customers’ electricity consumption that has not been billed at the end of each month. An amount is accrued as a receivable for this unbilled revenue based on estimates of usage and prices during the period. The estimates that management uses in this calculation could vary from the actual amounts to be paid by customers.
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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 the Company’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 the Company’s rate case. The APC Rider and the GTAC Rider were both applicable to each Oklahoma retail rate schedule to which the Company’s fuel automatic adjustment clause applies. See Note 10 of Notes to Financial Statements for a further discussion.
Fuel Inventories
Fuel inventories for the generation of electricity consist of coal, natural gas and oil. These inventories are accounted for under the last-in, first-out (“LIFO”) cost method. The estimated replacement cost of fuel inventories was higher than the stated LIFO cost by approximately $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.
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 the Company has been designated as one of several potentially responsible parties, the amount accrued represents the Company's estimated share of the cost.
Related Party Transactions
Energy Corp. allocated operating costs to the Company of approximately $95.2 million, $85.5 million and $84.8 million during 2002, 2001 and 2000, respectively. Energy Corp. allocates operating costs to its affiliates based on several factors. Operating costs directly related
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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.
In 2002, 2001 and 2000, the Company paid its affiliate Enogex Inc. and subsidiaries ("Enogex") approximately $33.6 million, $36.3 million and $37.4 million, respectively, for transporting gas to the Company's natural gas generating stations. These purchases are priced based on a market basket of posted prices within the region and are priced similar to purchases, which had previously been made directly from unaffiliated sources. Approximately $1.7 million and $0.1 million were recorded at December 31, 2002 and 2001, respectively, and are included in Accounts Payable - Affiliates in the accompanying Balance Sheets for these activities.
Reclassifications
Certain prior year amounts have been reclassified on the financial statements to conform to the 2002 presentation.
2. Income Taxes
The items comprising income tax expense are as follows:
Year ended December 31 (In millions) 2002 2001 2000
======================================================================================================
Provision for Current Income Taxes
Federal............................................ $ 55.9 $ 59.7 $ 71.0
State.............................................. 7.7 9.9 14.6
- -------------------------------------------------------- ---------- ---------- ----------
Total Provision for Current Income Taxes....... 63.6 69.6 85.6
- -------------------------------------------------------- ---------- ---------- ----------
Provision (Benefit) for Deferred Income Taxes, net
Federal............................................ 11.0 3.9 1.1
State.............................................. 2.6 1.1 (0.6)
- -------------------------------------------------------- ---------- ---------- ----------
Total Provision for Deferred Income Taxes, net. 13.6 5.0 0.5
- -------------------------------------------------------- ---------- ---------- ----------
Deferred Investment Tax Credits, net.................... (5.2) (5.2) (5.2)
Income Taxes Relating to Other Income and Deductions.... (0.4) --- (0.6)
- -------------------------------------------------------- ---------- ---------- ----------
Total Income Tax Expense....................... $ 71.6 $ 69.4 $ 80.3
======================================================== ========== ========== ==========
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... 3.4 3.7 4.1
Tax credits, net........................................ (2.6) (2.7) (2.3)
Other, net.............................................. 0.4 0.4 (0.7)
- -------------------------------------------------------- ---------- ---------- ----------
Effective income tax rate as reported.............. 36.2% 36.4% 36.1%
======================================================== ========== ========== ==========
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The Company is a member of an affiliated group that files consolidated income tax returns. Income taxes are allocated to each company in the affiliated group based on its separate taxable income or loss. 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. Deferred income tax expenses or benefits are based on the changes in the asset or liability from period to period.
The deferred tax provisions, set forth above, are recognized as costs in the ratemaking process by the commissions having jurisdiction over the rates charged by the Company. The components of Accumulated Deferred Taxes at December 31, 2002 and 2001, respectively, are as follows:
(In millions) 2002 2001
====================================================================================================
Current Accumulated Deferred Tax Assets
Accrued vacation............................................ $ 4.2 $ 4.0
Uncollectible accounts...................................... 1.9 2.4
Other....................................................... 1.4 1.1
- ------------------------------------------------------------------ ------------- -------------
Total Current Accumulated Deferred Tax Assets........... $ 7.5 $ 7.5
================================================================== ============= =============
Non-Current Accumulated Deferred Tax Liabilities
Accelerated depreciation and other property related
differences............................................. $ 400.7 $ 408.2
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.. 468.8 482.6
- ------------------------------------------------------------------ ------------- -------------
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.......... (1.0) (0.1)
Company pension plan........................................ (19.4) (12.6)
Other....................................................... (2.2) (1.5)
- ------------------------------------------------------------------ ------------- ------------
Total Non-Current Accumulated Deferred Tax Assets....... (47.3) (43.6)
- ------------------------------------------------------------------ ------------- -------------
Non-Current Accumulated Deferred Income Tax Liabilities, net..... $ 421.5 $ 439.0
====================================================================================================
3. Supplemental Cash Flow Information
Non-cash financing activities for the year ended December 31, 2002 and 2001 included approximately $9.9 million and $2.4 million, respectively, related to the interest rate swap agreement 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.
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Cash payments for interest, net of interest capitalized of approximately $0.9 million, $0.7 million and $2.2 million, respectively, were approximately $41.4 million, $44.7 million and $47.2 million for the years ended December 31, 2002, 2001 and 2000, respectively. Cash payments for income taxes, less income tax refunds, were approximately $61.9 million, $75.2 million and $84.6 million for the years ended December 31, 2002, 2001 and 2000, respectively.
4. Common Stock and Retained Earnings
There were no new shares of common stock issued during 2002 or 2001.
5. Cumulative Preferred Stock
The Company’s Restated Certificate of Incorporation permits the issuance of new series of preferred stock with dividends payable other than quarterly.
6. Long-Term Debt
Maturities of the Company's long-term debt during the next five years consist of $110.0 million in 2005.
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 Balance Sheets and are being amortized over the life of the respective debt.
Interest Rate Swap Agreement
During 2001, the Company 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. This interest rate swap qualified as a fair value hedge under SFAS No. 133 and met all requirements for a determination that there was no ineffective portion as allowed by the shortcut method under SFAS No. 133. The objective of this interest rate swap was to achieve a lower cost of debt and to raise the percentage of total corporate long-term floating rate debt to reflect a level more in line with industry standards.
At December 31, 2002 and 2001, the fair values pursuant to the interest rate swap were approximately $7.5 million and $2.4 million, respectively and are included in non-current Price Risk Management in the accompanying Balance Sheets. A corresponding increase of approximately $7.5 million and a decrease of approximately $2.4 million, respectively, are reflected in Long-Term Debt at December 31, 2002 and 2001, as this fair value hedge was effective at December 31, 2002 and 2001.
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7. Short-Term Debt
The Company had approximately $101.1 million in short-term debt outstanding at December 31, 2002. The Company did not have any short-term debt outstanding at December 31, 2001. The Company will use short-term borrowings from Energy Corp. to meet working capital requirements. The following table shows Energy Corp.’s and the Company’s lines of credit in place at December 31, 2002. Energy Corp.’s short-term borrowings will consist of a combination of bank borrowings and commercial paper.
Lines of Credit (In millions)
-------------------------------------------------------------------------------------------------
Entity Amount Maturity
-------------------------------------------------------------------------------------------------
Energy Corp. (A) $ 15.0 April 6, 2003
200.0 January 8, 2004
100.0 January 15, 2004
The Company 100.0 June 26, 2003
-------------------------------------------------------------------------------------------------
Total $ 415.0
=================================================================================================
(A) The lines of credit at Energy Corp. were used to back up its 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.
Energy Corp.’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 Energy Corp. suffers an adverse ratings impact. The impact of a downgrade of Energy Corp.‘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 Energy Corp. and Enogex, the Company must obtain regulatory approval from the FERC in order to borrow on a short-term basis. The Company has the necessary regulatory approvals to incur up to $400 million in short-term borrowings at any one time.
8. 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 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
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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 $37.3 million and $32.9 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 $29.6 million and $11.9 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 $137.8 million and $85.6 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 $141.3 million and $74.9 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 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 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, 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. The Company charges to expense the SFAS No. 106, “Employers’ Accounting for Postretirement Benefits other than Pensions”, costs and includes an annual amount as a component of the cost-of-service in future ratemaking proceedings.
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A reconciliation of the funded status of the plans and the amounts included in the accompanying Balance Sheets are as follows:
Projected Benefit Obligations
==================================================================================================
Postretirement
Pension Plan Benefit Plans
- --------------------------------------------------------------------------------------------------
(In millions) 2002 2001 2002 2001
- --------------------------------------------------------------------------------------------------
Beginning obligations........... $ (345.2) $ (342.0) $ (107.0) $ (90.0)
Service cost.................... (9.1) (8.4) (1.9) (1.4)
Interest cost................... (24.5) (25.8) (8.5) (7.4)
Participants' contributions..... --- --- (1.1) (1.2)
Plan changes.................... (0.1) --- --- ---
Actuarial losses................ (41.0) (5.1) (51.7) (16.8)
Benefits paid................... 45.3 34.9 9.3 9.8
Expenses ....................... 0.7 1.2 --- ---
- --------------------------------------------------------------------------------------------------
Ending obligations.............. $ (373.9) $ (345.2) $ (160.9) $ (107.0)
==================================================================================================
Fair Value of Plans' Assets
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Postretirement
Pension Plan Benefit Plans
- ---------------------------------------------------------------------------------------------------
(In millions) 2002 2001 2002 2001
- ---------------------------------------------------------------------------------------------------
Beginning fair value............ $ 259.6 $ 254.1 $ 51.1 $ 53.8
Actual return on plans' assets.. (14.8) 8.7 (6.5) (2.6)
Employer contributions.......... 37.3 32.9 7.1 7.4
Participants' contributions..... --- --- 1.0 1.0
Benefits paid................... (45.3) (34.9) (8.1) (8.5)
Expenses........................ (0.7) (1.2) --- ---
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Ending fair value............... $ 236.1 $ 259.6 $ 44.6 $ 51.1
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Postretirement
Pension Plan Benefit Plans
- -----------------------------------------------------------------------------------------------
(In millions) 2002 2001 2000 2002 2001 2000
- -----------------------------------------------------------------------------------------------
Service cost...................... $ 9.1 $ 8.4 $ 7.4 $ 1.9 $ 1.4 $ 1.5
Interest cost..................... 24.5 25.8 24.0 8.5 7.4 6.4
Return on plan assets............. (22.6) (21.1) (22.8) (5.3) (5.1) (4.8)
Amortization of transition
obligation..................... --- (1.1) (1.1) 2.5 2.5 2.5
Amortization of net (gain) loss... 3.7 0.4 (0.4) 0.5 (0.6) (1.5)
Amortization of unrecognized
prior service cost............. 4.8 4.7 4.1 1.5 1.5 1.0
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Net periodic benefit cost......... $ 19.5 $ 17.1 $ 11.2 $ 9.6 $ 7.1 $ 5.1
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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
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Postretirement
Pension Plan Benefit Plans
- ---------------------------------------------------------------------------------------------
(In millions) 2002 2001 2002 2001
- ---------------------------------------------------------------------------------------------
Funded status of the plans.............. $ (137.8) $ (85.6) $ (116.3) $ (55.9)
Unrecognized net (gain) loss............ 129.6 55.0 73.7 10.6
Unrecognized prior service cost......... 37.8 42.4 9.9 11.4
Unrecognized transition obligation...... --- --- 25.4 28.0
- ---------------------------------------------------------------------------------------------
Net amount recognized................... $ 29.6 $ 11.8 $ (7.3) $ (5.9)
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Amounts recognized in the Balance Sheets consist of:
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Pension Plan
- --------------------------------------------------------------------------------------
(In millions) 2002 2001
- --------------------------------------------------------------------------------------
Prepaid benefit obligation..................................... $ 29.6 $ 11.8
Accrued pension and benefit obligations........................ (141.3) (74.9)
Intangible asset-unamortized prior service cost................ 37.8 42.4
Accumulated deferred tax asset................................. 40.0 12.6
Accumulated other comprehensive loss, net of tax............... 63.5 19.9
- --------------------------------------------------------------------------------------
Net amount recognized.......................................... $ 29.6 $ 11.8
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Rate Assumptions
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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
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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 $1.3 million, $1.0 million and $0.9 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 $1.0 million, $0.8 million and $0.7 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 $19.6 million, $11.8 million and $9.4 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 $16.1 million, $9.8 million and $7.8 million at December 31, 2002, 2001 and 2000, respectively.
9. Commitments and Contingencies
Capital Expenditures
The Company’s capital expenditures for 2003, 2004 and 2005 are estimated at $149.0 million, $142.0 million and $142.0 million, respectively.
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Operating Lease Obligations
The Company has operating lease obligations expiring at various dates for railcar leases. Future minimum payments for noncancellable railcar leases are as follows:
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2008 and
(In millions) 2003 2004 2005 2006 2007 Beyond
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Operating lease obligations
Railcars...................... $ 5.4 $ 5.4 $ 5.4 $ 5.4 $ 5.4 $ 36.1
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Payments for operating lease obligations were approximately $5.4 million, $5.1 million and $5.4 million in 2002, 2001 and 2000, respectively.
Railcar Leases
At December 31, 2002, the Company 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 the Company’s tariffs and automatic fuel adjustment clauses.
The Company 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
The Company 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 the Company to purchase power generated in a manufacturing process from a qualified cogeneration facility (“QF”). The rate for such power to be paid by the Company was approved by the OCC. The rate generally consists of two components: one is a rate for actual electricity purchased from the QF by the Company; the other is a capacity charge, which the Company must pay the QF for having the capacity available. However, if no electrical power is made available to the Company for a period of time (generally three months), the Company’s obligation to pay the capacity charge is suspended. The total cost of cogeneration payments is recoverable in rates from customers.
During 2002, 2001, and 2000, the Company 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 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.
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Fuel Minimum Purchase Commitments
The Company 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.
The Company 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 Balance Sheets. The outstanding prepayments of gas relate to a reserve for litigation that the Company is currently involved in. As the Company 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 Balance Sheets as the Company expects full recovery through its regulatory approved fuel adjustment clause.
Natural Gas Units
The Company 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 the Company will be secured through monthly and day-to-day purchases as required.
Natural Gas Storage Facility Agreement with Central Oklahoma Oil and Gas Corp.
The Company 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, the Company completed negotiations and contracted with COOG for gas storage service. Pursuant to the contract, COOG reimbursed the Company 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, Energy Corp. 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, Energy Corp. 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, Energy Corp. 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, Energy Corp. 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, Energy Corp. 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, Energy Corp. 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. Energy Corp. intends to continue to vigorously pursue its rights in conjunction with the NGSC Loan.
On August 12, 2002, Energy Corp. was improperly served with an Original Petition in a legal proceeding that has been filed by COOG and NGSC against Energy Corp. 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) Energy Corp. was obligated to demand Enogex make the requisite payments to Energy Corp.; (2) Energy Corp. is liable to NGSC for failing to demand the requisite payments from Enogex, or alternatively,
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NGSC is entitled to a reduction in the amount it owes to Energy Corp.; (3) Enogex was and is obligated to make the payments to Energy Corp. until the indebtedness of NGSC to Energy Corp. 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 Energy Corp.; (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 declaratory relief and include claims for attorneys’ fees.
Energy Corp. 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 Energy Corp. 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. Energy Corp. intends to continue to vigorously pursue its rights in conjunction with the Judgment and payment of the NGSC Loan.
Natural Gas Measurement Cases
Grynberg. In 1999, the Company 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
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over 300 other defendants in various Federal Courts across the country containing nearly identical allegations. In late 1999, the actions against the Company 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 Energy Corp. 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.
Energy Corp. intends to vigorously defend this action. Since the case is in the early stages of motions and discovery, Energy Corp. is unable to provide an evaluation of the likelihood of an unfavorable outcome and an estimate of the amount or range of potential loss to Energy Corp. at this time.
Quinque. In September 1999, Energy Corp. 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 the Company, 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.
Energy Corp. 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.
Energy Corp. intends to vigorously defend this action. Since the case is in the early stages of motions and discovery, Energy Corp. is unable to provide an evaluation of the likelihood of an unfavorable outcome and an estimate of the amount or range of potential loss to Energy Corp. at this time.
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.
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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.
As required by Title IV of the Clean Air Act Amendments of 1990 (“CAAA”), the Company completed installation and certification of all required continuous emissions monitors at its generating stations in 1995. Since then the Company has submitted emissions data quarterly to the Environmental Protection Agency (“EPA”) as required by the CAAA. Beginning in 2000, the Company became subject to more stringent SO2 emission requirements. These lower limits had no significant financial impact due to the Company’s earlier decision to burn low sulfur coal. In 2002, the Company’s SO2 emissions were well below the allowable limits.
With respect to the NOX regulations of Title IV of the CAAA, the Company committed to meeting a 0.45 lbs/ million British thermal unit (“MMBtu”) NOX emission level in 1997 on all coal-fired boilers. As a result, the Company was eligible to exercise its option to extend the effective date of the lower emission requirements from the year 2000 until 2008. The Company’s average NOX emissions from its coal-fired boilers for 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 the Company’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, the Company had submitted all required permit applications. As of December 31, 2002, the Company had received Title V permits for all but one of its generating stations. Since the Company 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 the Company. On December 14, 2000, the EPA announced its decision to regulate mercury emissions from coal-
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fired boilers. Limits on the amount of mercury emitted are expected to be finalized by December 2004, although full compliance by the Company 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 the Company’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. The Company has joined other utilities in voluntary CO2 sequestration projects through reforestation of land in the southern United States. In addition, the Company 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 the Company’s operations by requiring the Company to significantly reduce the use of coal as a fuel source.
The Company 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, the Company 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.
The Company has submitted one application during 2002 and will submit three more during 2003 to renew its Oklahoma Pollution Discharge Elimination System permits. The Company anticipates that the renewed permits will continue to allow operational flexibility.
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The Company 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 the Company’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 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 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 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 financial position, results of operations or cash flows.
10. Rate Matters and Regulation
Regulation and Rates
The Company’s retail electric tariffs are regulated by the OCC in Oklahoma and by the APSC in Arkansas. The issuance of certain securities by the Company is also regulated by the OCC and the APSC. The Company’s wholesale electric tariffs, short-term borrowing authorization and accounting practices are subject to the jurisdiction of the FERC. The Secretary of the Department of Energy has jurisdiction over some of the Company’s facilities and operations.
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The order of the OCC authorizing the Company to reorganize into a subsidiary of Energy Corp. contains certain provisions which, among other things, ensure the OCC access to the books and records of Energy Corp. and its affiliates relating to transactions with the Company; require the Company to employ accounting and other procedures and controls to protect against subsidization of non-utility activities by the Company’s customers; and prohibit the Company from pledging its assets or income for affiliate transactions.
For the year ended December 31, 2002, approximately 88 percent of the Company’s 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 the Company. In the filing, the OCC Staff requested that the Company submit information for a test year ending September 30, 2001. On December 14, 2001, the Company, citing the need for investment in security and system reliability, filed a notice with the OCC of its intent to seek an increase in the Company’s electric rates. On January 28, 2002, the Company filed testimony with the OCC supporting the Company’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, the Company has had several rate reductions that have totaled more than $142.0 million annually.
Attempting to make security investments at the proper level, the Company 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 the Company 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 the Company was to invest in increased security. As described below, the Company 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. The Company 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, the Company 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
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based on the previous year’s usage and other factors. Another proposed rate program, a Green Power option, would involve the Company 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 the Company’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, the Company announced it would withdraw the $10.3 million increased security portion of its January request. Simultaneously with that announcement, the Company 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, the Company filed a report outlining proposed expenditures and related actions for security enhancement. The Company 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 the Company.
On July 1, 2002, the Company filed direct testimony in support of recovery for the approximately $92.0 million in damages caused by the January 2002 ice storm. The Company 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, the Company, the OCC Staff, the Oklahoma Attorney General and other interested parties agreed to a settlement (the “Settlement Agreement”) of the Company’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 the Company’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 the Company, through rate base, of the capital expenditures associated with the January 2002 ice storm; (iii) recovery by the Company, over three years, of the $5.4 million in deferred operating costs, associated with the January 2002 ice storm, through the Company’s rider for sales to other utilities and power marketers (“off system sales”); (iv) the Company to acquire electric generating capacity (“New Generation”) of not less than 400 megawatts (“MW”) to be integrated into the Company’s generation system. Key portions of the Settlement Agreement are described below.
I. Rate Reduction to Oklahoma Customers
The Settlement Agreement stipulated that the Company will file tariffs, designed to reflect an annual reduction of $25.0 million in the Company’s Oklahoma jurisdictional operating revenue. The $25.0 million annual reduction began on January 6, 2003.
88
II. Recovery of Storm Damages
The Settlement Agreement stipulated that the Company 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 the Company 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 the Company’s rider for off-system sales. Currently, the Company 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 the Company’s off-system sales will go to the Company, the next $3.6 million in annual net profits from off-system sales will go to the Company’s Oklahoma customers, and any net profits of off-system sales in excess of these amounts will be credited in each sales year with 80 percent to the Company’s Oklahoma customers and the remaining 20 percent to the Company. 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
The Company intends to take steps to purchase electric generating facilities of not less than 400 MW’s to be integrated into the Company’s generation system. The Company 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, the Company must file an application with the OCC for the inclusion of the New Generation into the Company’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 the Company’s prospective cost of service. The period for recovery of the regulatory asset will be determined by the OCC. The Company expects this New Generation will provide savings, over a three-year period, in excess of $75.0 million to the Company’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 the Company’s Oklahoma customers, should have no effect on the profitability of the Company.
As indicated above, the Company’s decision with respect to the purchase of the New Generation will be subject to a review by the OCC as 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 the Company’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. The Company will provide monthly reports, for a period of 36 months, to the OCC Staff, documenting and providing proof of savings experienced by the Company’s customers. In determining the 36-month savings, the Company will be required to include in its reports: (1) the avoidance of purchased capacity otherwise required to meet Southwest Power Pool capacity margin
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requirements; (2) credits to customers accruing by virtue of cogeneration contract terminations; and (3) the fuel savings associated with the operating efficiencies of the Company’s generating facilities including the New Generation compared to the fuel efficiencies of the Company’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, the Company will not include savings to its customers, which occur as the result of scheduled reduction in ongoing cogeneration contract payments. In the event the Company is unable to demonstrate at least $75.0 million in savings to its customers during this 36-month period, the Company will 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 the Company does not acquire the New Generation by December 31, 2003, the Company 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 the Company 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, the Company 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 the Company based on its performance in the utilization of its coal generation facilities. The greater the coal plant utilization, the greater the benefits received by the Company’s customers. The Company’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 the Company by encouraging the Company to aggressively pursue even greater efficiencies from these best-in-class plants. Additional CUP Rider incentives would have commemced 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. The Company agreed not to seek implementation of a CUP Rider or a TIR Rider or other similar riders in the Company’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 the Company’s Oklahoma customers, the Company 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 the Company agreed to initiate a competitive bidding process for gas transportation service to its natural gas plants.
The Company’s current gas transportation service contract with Enogex for the Company’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, the Company agreed to consider competitive bidding as an option when analyzing the extension or renewal of the Company’s gas transportation service contract with Enogex prior to April 2004. The Company 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 the Company 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, the Company 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 the Company to reflect the completion of the recovery of the amortization premium paid by the Company 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 the Company from its Oklahoma customers in current rates.
In June 2001, the OCC approved a stipulation (the “Stipulation”) to the competitive bid process of the Company’s gas transportation service from Enogex. The Stipulation directed the Company 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 the Company’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.
The Company’s Generation Efficiency Performance Rider (“GEP Rider”) expired in June 2002. The GEP Rider was established initially in 1997 in connection with the Company’s 1996 general rate review and was intended to encourage the Company to lower its fuel costs by: (i) allowing the Company 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 the Company could recover under the GEP Rider by:
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(i) changing the Company’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 the Company’s costs exceed the new peer group by changing the percentage above which the Company 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 the Company’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 the Company or penalties charged to the Company. For the period between January 1, 2002 and June 30, 2002, the Company 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 failure 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 the Company’s future operations. The Company’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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11. 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
Interest Rate Swap.................... $ 7.5 $ 7.5 $ --- $ ---
Price Risk Management Liabilities
Interest Rate Swap.................... $ --- $ --- $ 2.4 $ 2.4
Long-Term Debt
Senior Notes.......................... $ 575.1 $ 617.2 $ 565.0 $ 571.4
Industrial Authority Bonds............ 135.4 135.4 135.4 135.4
==================================================================================================
The carrying value of the financial instruments on the accompanying Balance Sheets not discussed above approximates fair value. The valuation of the Company’s interest rate swap was determined primarily based on quoted market prices. The fair value of the Company’s long-term debt is based on quoted market prices.
12. Subsequent Events (Unaudited)
On January 15, 2003, Standard & Poor’s Ratings Services lowered the credit rating of the Company's senior unsecured debt from A- to BBB+. 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 financial position or results of operations.
On February 5, 2003, Moody’s Investors Service lowered the credit rating of the Company’s senior unsecured debt to A2 from A1. 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 financial position or results of operations.
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REPORT OF INDEPENDENT AUDITORS
The Board of Directors and Shareowner
Oklahoma Gas and Electric Company
We have audited the accompanying balance sheets and statements of capitalization of Oklahoma Gas and Electric Company as of December 31, 2002 and 2001, and the related statements of income, retained earnings, comprehensive income and cash flows for each of the three years in the period ended December 31, 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 financial position of Oklahoma Gas and Electric Company at December 31, 2002 and 2001, and the 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
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REPORT OF MANAGEMENT
To Our Shareowner:
The management of the Company is responsible for the preparation, integrity and objectivity of the financial statements of the Company and other information included in this report. The 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 financial statements. Management believes that the system of control provides reasonable assurance that errors or irregularities that could be material to the 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 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 financial statements of the Company 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/ Donald R. Rowlett /s/ James R. Hatfield
-------------------------------------------- ---------------------------------------------
Donald R. Rowlett, Vice President James R. Hatfield, Sr. Vice President
and Controller and Chief Financial Officer
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Supplementary Data
Interim Financial Information (Unaudited)
In the opinion of the Company, the following quarterly information includes all adjustments, consisting of normal recurring adjustments, necessary for a fair statement of the results of operations for such periods:
Quarter ended (In millions, except per share Dec 31 Sep 30 Jun 30 Mar 31
data)
- -------------------------------------------------------------------------------------------------------
Operating revenues........................ 2002 $ 284.8 $ 488.9 $ 352.2 $ 262.1
2001 262.3 508.2 359.5 326.8
2000 343.7 529.0 335.6 245.3
- -------------------------------------------------------------------------------------------------------
Operating income (loss)................... 2002 $ 6.2 $ 170.2 $ 56.9 $ 5.8
2001 (1.0) 172.3 56.1 9.2
2000 24.6 185.0 55.7 5.8
- -------------------------------------------------------------------------------------------------------
Net income (loss)......................... 2002 $ (1.6) $ 98.4 $ 30.8 $ (1.5)
2001 (5.9) 100.1 28.0 (1.0)
2000 8.7 107.3 29.6 (3.2)
- --------------------------------------------------------------------------------------------------------
Earnings (loss) per average common share.. 2002 $ (0.04) $ 2.44 $ 0.76 $ (0.04)
2001 (0.15) 2.48 0.69 (0.02)
2000 0.22 2.66 0.73 (0.08)
- --------------------------------------------------------------------------------------------------------
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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 parent company of Oklahoma Gas and Electric Company (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 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.
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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.
Item 13. Certain Relationships and Related Transactions.
Under the reduced disclosure format permitted by General Instruction I(2)(c) of Form 10-K, the information otherwise required by Items 10, 11, 12 and 13 has been omitted.
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.
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PART IV
Item 15. Exhibits, Financial Statement Schedules and
Reports on Form 8-K.
(a) 1. Financial Statements
The following financial statements and supplementary data are included in Part II, Item 8 of this Report:
Supplementary Data
2. Financial Statement Schedule (included in Part IV) Page
Schedule II - Valuation and Qualifying Accounts 105
All other schedules have been omitted since the required information is not applicable or is not material, or because the information required is included in the respective financial statements or notes thereto.
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3. Exhibits
Exhibit No. Description
3.01 Copy of Restated Certificate of Incorporation. (Filed as Exhibit 4.01
to the Company's Registration Statement No. 33-59805, and
incorporated by reference herein)
3.02 By-laws. (Filed as Exhibit 4.02 to Post-Effective Amendment No. Three
to Registration Statement No. 2-94973 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 the Company'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)
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 the Company and
Atlantic Richfield Company. (Filed as Exhibit 5.19 to
Registration Statement No. 2-59887 and incorporated by reference
herein)
100
10.02 Amendment dated April 1, 1976, to Coal Supply Agreement dated March 1,
1973, between the Company 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 the Company 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 the Company and Thunder Basin
Coal Company, to Coal Supply Agreement dated March 1, 1973,
between the Company and Atlantic Richfield Company. (Filed as
Exhibit 10.04 to the Company'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
Energy Corp. (Filed as Exhibit 10.07 to Energy Corp.'s Form 10-K
Report for the year ended December 31, 1996 (File No. 1-12579)
and incorporated by reference herein)
10.06 Energy Corp.'s Stock Incentive Plan. (Filed as Exhibit 10.07 to Energy
Corp.'s Form 10-K Report for the year ended December 31, 1998
(File No. 1-12579) and incorporated by reference herein)
10.07 Oklahoma Gas and Electric Company Restoration of Retirement Income
Plan, as amended by Amendments No. 1 and No. 2. (Filed as Exhibit
10.12 to Energy Corp.'s Form 10-K Report for the year ended
December 31, 1996 (File No. 1-12579) and incorporated by
reference herein)
10.08 Amendment No. 3 to Energy Corp. Restoration of Retirement Income Plan.
(Filed as Exhibit 10.13 to Energy Corp.'s Form 10-K Report for
the year ended December 31, 2000 (File No. 1-12519) and
incorporated by reference herein)
101
10.09 Amendment No. 4 to Energy Corp. Restoration of Retirement Income Plan.
(Filed as Exhibit 10.14 to Energy Corp.'s Form 10-K Report for
the year ended December 31, 2000 (File No. 1-12519) and
incorporated by reference herein)
10.10 Oklahoma Gas and Electric Company Supplemental Executive Retirement
Plan. (Filed as Exhibit 10.15 to Energy Corp.'s Form 10-K Report
for the year ended December 31, 1996 (File No. 1-12579) and
incorporated by reference herein)
10.11 Energy Corp.'s Annual Incentive Compensation Plan. (Filed as Exhibit
10.12 to Energy Corp.'s Form 10-K Report for the year ended
December 31, 1998 (File No. 1-12579) and incorporated by
reference herein)
10.12 Energy Corp.'s Deferred Compensation Plan and Amendment No.1 to Energy
Corp.'s Deferred Compensation Plan.
10.13 Copy of Settlement Agreement with Oklahoma Corporation Commission
Staff, the Oklahoma Attorney General and others relating to the
Company's rate case. (Filed as Exhibit 99.02 to Energy's Form 10-Q
for the Quarter ended September 30, 2002 (File No. 1-12579) and
incorporated by reference herein)
10.14 Credit Agreement dated June 27, 2002 between the Company, Bank One, NA
and Wachovia Bank, National Association.
16.01 Letter of Arthur Andersen LLP regarding change in certifying
accountant. (Filed as Exhibit 16.01 to the Company's Form 8-K
filed May 21, 2002 (File 1-1097) and incorporated by reference
herein)
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.
102
Executive Compensation Plans and Arrangements
10.05 Form of Change of Control Agreement for Officers of the Company and
Energy Corp. (Filed as Exhibit 10.07 to Energy Corp.'s Form 10-K
Report for the year ended December 31, 1996 (File No. 1-12579)
and incorporated by reference herein)
10.06 Energy Corp.'s Stock Incentive Plan. (Filed as Exhibit 10.07 to Energy
Corp.'s Form 10-K for the year ended December 31, 1998 (File No.
1-12579) and incorporated by reference herein)
10.07 Oklahoma Gas and Electric Company Restoration of Retirement
Income Plan, as amended by Amendments No. 1 and No. 2. (Filed as
Exhibit 10.12 to Energy Corp.'s Form 10-K Report for the year
ended December 31, 1996 (File No. 1-12579) and incorporated by
reference herein)
10.08 Amendment No. 3 to Energy Corp. Restoration of Retirement Income Plan.
(Filed as Exhibit 10.13 to Energy Corp.'s Form 10-K Report for
the year ended December 31, 2000 (File No. 1-12519) and
incorporated by reference herein)
10.09 Amendment No. 4 to Energy Corp. Restoration of Retirement Income Plan.
(Filed as Exhibit 10.14 to Energy Corp.'s Form 10-K Report for
the year ended December 31, 2000 (File No. 1-12519) and
incorporated by reference herein)
10.10 Oklahoma Gas and Electric Company Supplemental Executive Retirement
Plan. (Filed as Exhibit 10.15 to Energy Corp.'s Form 10-K Report
for the year ended December 31, 1996 (File No. 1-12579) and
incorporated by reference herein)
10.11 Energy Corp.'s Annual Incentive Compensation Plan. (Filed as Exhibit
10.12 to Energy Corp.'s Form 10-K Report for the year ended
December 31, 1998 (File No. 1-12579) and incorporated by
reference herein)
10.12 Energy Corp.'s Deferred Compensation Plan and Amendment No.1 to Energy
Corp.'s Deferred Compensation Plan.
103
(b) Reports on Form 8-K
The Company filed a Current Report on Form 8-K on October 11, 2002 to report its rate case settlement.
The Company filed a Current Report on Form 8-K on November 21, 2002 to report the approval of its rate case settlement.
104
OKLAHOMA GAS AND ELECTRIC COMPANY
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 $ 3.4 $ 5.1 - $ 4.8 (A) $ 3.7
Year Ended December 31, 2001
Reserve for Uncollectible Accounts $ 3.7 $15.8 - $13.3 (A) $ 6.2
Year Ended December 31, 2002
Reserve for Uncollectible Accounts $ 6.2 $ 6.5 - $ 8.0 (A) $ 4.7
(A) Uncollectible accounts receivable written off, net of recoveries.
105
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.
OKLAHOMA GAS AND ELECTRIC COMPANY
(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
106
CERTIFICATIONS
I, Steven E. Moore, certify that:
1. I have reviewed this annual report on Form 10-K of Oklahoma Gas and Electric Company;
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
107
CERTIFICATIONS
I, James R. Hatfield, certify that:
1. I have reviewed this annual report on Form 10-K of Oklahoma Gas and Electric Company;
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
108
Exhibit Index
Exhibit No. Description
3.01 Copy of Restated Certificate of Incorporation. (Filed as Exhibit 4.01
to the Company's Registration Statement No. 33-59805, and
incorporated by reference herein)
3.02 By-laws. (Filed as Exhibit 4.02 to Post-Effective Amendment No. Three
to Registration Statement No. 2-94973 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 the Company'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 Report 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 Report filed on April 16, 1998 (File
No. 1-1097) and incorporated by reference herein)
4.05 Supplemental Indenture No. 4, dated as of October 15, 2000, being a
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 the Company and
Atlantic Richfield Company. (Filed as Exhibit 5.19 to
Registration Statement No. 2-59887 and incorporated by reference
herein)
109
10.02 Amendment dated April 1, 1976, to Coal Supply Agreement dated March 1,
1973, between the Company 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 the Company 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 the Company and Thunder Basin
Coal Company, to Coal Supply Agreement dated March 1, 1973,
between the Company and Atlantic Richfield Company. (Filed as
Exhibit 10.04 to the Company’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
Energy Corp. (Filed as Exhibit 10.07 to Energy Corp.‘s Form
10-K Report for the year ended December 31, 1996 (File No.
1-12579) and incorporated by reference herein)
10.06 Energy Corp.'s Stock Incentive Plan. (Filed as Exhibit 10.07 to Energy
Corp.'s Form 10-K Report for the year ended December 31, 1998
(File No. 1-12579) and incorporated by reference herein)
10.07 Oklahoma Gas and Electric Company Restoration of Retirement Income
Plan, as amended by Amendments No. 1 and No. 2. (Filed as Exhibit
10.12 to Energy Corp.'s Form 10-K Report for the year ended
December 31, 1996 (File No. 1-12579) and incorporated by
reference herein)
10.08 Amendment No. 3 to Energy Corp. Restoration of Retirement Income Plan.
(Filed as Exhibit 10.13 to Energy Corp.'s Form 10-K Report for
the year ended December 31, 2000 (File No. 1-12519) and
incorporated by reference herein)
110
10.09 Amendment No. 4 to Energy Corp. Restoration of Retirement Income Plan.
(Filed as Exhibit 10.14 to Energy Corp.'s Form 10-K Report for
the year ended December 31, 2000 (File No. 1-12519) and
incorporated by reference herein)
10.10 Oklahoma Gas and Electric Company Supplemental Executive Retirement
Plan. (Filed as Exhibit 10.15 to Energy Corp.'s Form 10-K Report
for the year ended December 31, 1996 (File No. 1-12579) and
incorporated by reference herein)
10.11 Energy Corp.'s Annual Incentive Compensation Plan. (Filed as Exhibit
10.12 to Energy Corp.'s Form 10-K Report for the year ended
December 31, 1998 (File No. 1-12579) and incorporated by
reference herein)
10.12 Energy Corp.'s Deferred Compensation Plan and Amendment No.1 to Energy
Corp.'s Deferred Compensation Plan.
10.13 Copy of Settlement Agreement with Oklahoma Corporation Commission
Staff, the Oklahoma Attorney General and others relating to the
Company's rate case. (Filed as Exhibit 99.02 to Energy's Form 10-Q
for the Quarter ended September 30, 2002 (File No. 1-12579) and
incorporated by reference herein)
10.14 Credit Agreement dated June 27, 2002 between the Company, Bank One, NA
and Wachovia Bank, National Association.
16.01 Letter of Arthur Andersen LLP regarding change in certifying
accountant. (Filed as Exhibit 16.01 to the Company's Form 8-K
filed May 21, 2002 (File 1-1097) and incorporated by reference
herein.)
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.
111
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
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
7
deferrals, Matching Credits and Discretionary Credits 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.
8
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
10
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
13
group, any legal or equitable right unless such right shall be specifically provided 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.
14
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
19
Exhibit 10.14
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Bank One Plaza
10 South Dearborn Street
Chicago, Illinois 60603
TABLE OF CONTENTS
ARTICLE I DEFINITION.................................................................................1
ARTICLE II THE CREDITS...............................................................................12
2.1. Commitment................................................................................12
2.2. Required Payments; Termination............................................................13
2.3. Ratable Loans.............................................................................13
2.4. Types of Advances.........................................................................13
2.5. Facility Fee; Utilization Fee; Reductions in Aggregate Commitment.........................13
2.6. Minimum Amount of Each Advance............................................................14
2.7. Optional Principal Payments...............................................................14
2.8. Method of Selecting Types and Interest Periods for New Advances...........................14
2.9. Conversion and Continuation of Outstanding Advances.......................................14
2.10. Changes in Interest Rate, etc.............................................................15
2.11. Rates Applicable After Default............................................................15
2.12. Method of Payment.........................................................................16
2.13. Noteless Agreement; Evidence of Indebtedness..............................................16
2.14. Telephonic Notices........................................................................17
2.15. Interest Payment Dates; Interest and Fee Basis............................................17
2.16. Notification of Advances, Interest Rates, Prepayments and Commitment Reductions;
Availability or Loans...................................................................17
2.17. Lending Installations.....................................................................17
2.18. Non-Receipt of Funds by the Agent.........................................................18
2.19. Replacement of Lender.....................................................................18
ARTICLE III YIELD PROTECTION; TAXES..................................................................18
3.1. Yield Protection..........................................................................18
3.2. Changes in Capital Adequacy Regulations...................................................19
3.3. Availability of Types of Advances.........................................................20
3.4. Funding Indemnification...................................................................20
3.5. Taxes.....................................................................................20
3.6. Lender Statements; Survival of Indemnity..................................................22
3.7. Alternative Lending Installation..........................................................22
ARTICLE IV CONDITIONS PRECEDENT......................................................................23
4.1. Initial Advance...........................................................................23
4.2. Each Advance..............................................................................23
ARTICLE V REPRESENTATIONS AND WARRANTIES.............................................................24
5.1. Existence and Standing....................................................................24
5.2. Authorization and Validity................................................................24
5.3. No Conflict; Government Consent...........................................................24
5.4. Financial Statements......................................................................25
5.5. Material Adverse Change...................................................................25
5.6. Taxes.....................................................................................25
i
5.7. Litigation and Contingent Obligations......................................................26 5.8. Subsidiaries...............................................................................26 5.9. ERISA......................................................................................26 5.10. Accuracy of Information....................................................................26 5.11. Regulation U...............................................................................26 5.12. Material Agreements........................................................................26 5.13. Compliance With Laws.......................................................................27 5.14. Ownership of Properties....................................................................27 5.15. Plan Assets; Prohibited Transactions.......................................................27 5.16. Environmental Matters......................................................................27 5.17. Investment Company Act.....................................................................27 5.18. Public Utility Holding Company Act.........................................................27 5.19. Insurance..................................................................................28 5.20. No Default or Unmatured Default............................................................28 ARTICLE VI COVENANTS.................................................................................28 6.1. Financial Reporting........................................................................28 6.2. Use of Proceeds............................................................................29 6.3. Notice of Default..........................................................................29 6.4. Conduct of Business........................................................................29 6.5. Taxes......................................................................................29 6.6. Insurance..................................................................................30 6.7. Compliance with Laws.......................................................................30 6.8. Maintenance of Properties..................................................................30 6.9. Inspection; Keeping of Books and Records...................................................30 6.10. Merger.....................................................................................30 6.11. Sale of Assets.............................................................................30 6.12. Liens......................................................................................31 6.13. Affiliates.................................................................................33 6.14. Financial Contracts........................................................................33 6.15. Leverage Ratio.............................................................................33 6.16. FERC Approval..............................................................................33 ARTICLE VII ACCELERATION, WAIVERS, AMENDMENTS AND REMEDIES...........................................36 7.1. Acceleration...............................................................................36 7.2. Amendments.................................................................................36 7.3. Preservation of Rights.....................................................................37 ARTICLE VIII GENERAL PROVISIONS......................................................................37 8.1. Survival of Representations................................................................37 8.2. Governmental Regulation....................................................................37 8.3. Headings...................................................................................37 8.4. Entire Agreement...........................................................................37 8.5. Several Obligations; Benefits of this Agreement............................................38 8.6. Expenses; Indemnification..................................................................38 8.7. Numbers of Documents.......................................................................38
ii
8.8. Accounting.................................................................................39 8.9. Severability of Provisions.................................................................39 8.10. Nonliability of Lenders....................................................................39 8.11. Confidentiality............................................................................39 8.12. Lenders Not Utilizing Plan Assets..........................................................40 8.13. Nonreliance................................................................................40 8.14. Disclosure.................................................................................40 ARTICLE IX THE AGENT.................................................................................40 9.1. Appointment; Nature of Relationship........................................................40 9.2. Powers.....................................................................................41 9.3. General Immunity...........................................................................41 9.4. No Responsibility for Loans, Recitals, etc.................................................41 9.5. Action on Instructions of Lenders..........................................................41 9.6. Employment of Agents and Counsel...........................................................42 9.7. Reliance on Documents; Counsel.............................................................42 9.8. Agent's Reimbursement and Indemnification..................................................42 9.9. Notice of Default..........................................................................42 9.10. Rights as a Lender.........................................................................43 9.11. Lender Credit Decision.....................................................................43 9.12. Successor Agent............................................................................43 9.13. Agent and Arranger Fees....................................................................44 9.14. Delegation to Affiliates...................................................................44 ARTICLE X SETOFF; RATABLE PAYMENTS...................................................................44 10.1. Setoff.....................................................................................44 10.2. Ratable Payments...........................................................................44 ARTICLE XI BENEFIT OF AGREEMENT; ASSIGNMENTS; PARTICIPATIONS.........................................45 11.1. Successors and Assigns; Designated Lenders.................................................45 11.2. Participations.............................................................................47 11.3. Assignments................................................................................48 11.4. Dissemination of Information...............................................................49 11.5. Tax Certifications.........................................................................49 ARTICLE XII NOTICES..................................................................................49 12.1. Notices....................................................................................49 12.2. Change of Address..........................................................................50 ARTICLE XIII COUNTERPARTS............................................................................51 ARTICLE XIV CHOICE OF LAW; CONSENT TO JURISDICTION; WAIVER OF JURY TRIAL.............................51
iii
SCHEDULES
Commitment Schedule
Pricing Schedule
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CREDIT AGREEMENT
This Agreement, dated as of June 27, 2002, is among Oklahoma Gas and Electric Company, an Oklahoma corporation, the Lenders and Bank One, NA, a national banking association having its principal office in Chicago, Illinois, as Administrative Agent and Wachovia Bank, National Association, as Syndication Agent. The parties hereto agree as follows:
DEFINITIONS
As used in this Agreement:
“Accounting Changes” is defined in Section 9.8 hereof.
“Advance” means a borrowing hereunder, (i) made by the Lenders on the same Borrowing Date, or (ii) converted or continued by the Lenders on the same date of conversion or continuation, consisting, in either case, of the aggregate amount of the several Loans of the same Type and, in the case of Eurodollar Loans, for the same Interest Period.
“Affiliate” of any Person means any other Person directly or indirectly controlling, controlled by or under common control with such Person. A Person shall be deemed to control another Person if the controlling Person owns 10% or more of any class of voting securities (or other ownership interests) of the controlled Person or possesses, directly or indirectly, the power to direct or cause the direction of the management or policies of the controlled Person, whether through ownership of stock, by contract or otherwise.
“Agent” means Bank One in its capacity as contractual representative of the Lenders pursuant to Article X, and not in its individual capacity as a Lender, as Administrative Agent, and any successor Agent appointed pursuant to Article X.
“Aggregate Commitment” means the aggregate of the Commitments of all the Lenders, as reduced from time to time pursuant to the terms hereof. The initial Aggregate Commitment is One Hundred Million and 00/100 Dollars ($100,000,000).
“Aggregate Outstanding Credit Exposure” means, at any time, the aggregate of the Outstanding Credit Exposure of all the Lenders.
“Agreement” means this Credit Agreement, as it may be amended, restated, supplemented or otherwise modified and as in effect from time to time.
“Agreement Accounting Principles” means generally accepted accounting principles applied in a manner consistent with that used in preparing the financial statements referred to in Section 5.4.
“Alternate Base Rate” means, for any day, a fluctuating rate of interest per annum equal to the higher of (i) the Prime Rate for such day and (ii) the sum of the Federal Funds Effective Rate for such day and one half of one percent (0.5% ) per annum.
“Applicable Fee Rate” means, with respect to the Facility Fee and the Utilization Fee at any time, the percentage rate per annum which is applicable at such time with respect to each such fee as set forth in the Pricing Schedule.
“Applicable Margin” means, with respect to Advances of any Type at any time, the percentage rate per annum which is applicable at such time with respect to Advances of such Type as set forth in the Pricing Schedule.
“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.
“Arranger” means Banc One Capital Markets, Inc., a Delaware corporation, and its successors, in its capacity as Lead Arranger and Sole Book Runner.
“Article” means an article of this Agreement unless another document is specifically referenced.
“Authorized Officer” means any of the President, Chief Financial Officer, Treasurer, or any Vice President of the Borrower, acting singly.
“Bank One” means Bank One, NA, a national banking association having its principal office in Chicago, Illinois, in its individual capacity, and its successors.
“Borrower” means Oklahoma Gas and Electric Company, an Oklahoma corporation, and its permitted successors and assigns (including, without limitation, a debtor in possession on its behalf).
“Borrowing Date” means a date on which an Advance is made hereunder.
“Borrowing Notice” is defined in Section 2.8.
“Business Day” means (i) with respect to any borrowing, payment or rate selection of Eurodollar Advances, a day (other than a Saturday or Sunday) on which banks generally are open in Chicago, Illinois and New York, New York for the conduct of substantially all of their commercial lending activities, interbank wire transfers can be made on the Fedwire system and dealings in United States dollars are carried on in the London interbank market and (ii) for all other purposes, a day (other than a Saturday or Sunday) on which banks generally are open in Chicago, Illinois for the conduct of substantially all of their commercial lending activities and interbank wire transfers can be made on the Fedwire system.
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“Capitalized Lease” of a Person means any lease of Property by such Person as lessee which would be capitalized on a balance sheet of such Person prepared in accordance with Agreement Accounting Principles.
“Capitalized Lease Obligations” of a Person means the amount of the obligations of such Person under Capitalized Leases which would be shown as a liability on a balance sheet of such Person prepared in accordance with Agreement Accounting Principles.
“Change in Control” means (i) the acquisition by any Person, or two or more Persons acting in concert, of beneficial ownership (within the meaning of Rule 13d-3 of the Securities and Exchange Commission under the Securities Exchange Act of 1934) of 30% or more of the outstanding shares of voting stock of the Parent; (ii) the Parent shall cease to own, directly or indirectly and free and clear of all Liens or other encumbrances, at least 80% of the outstanding shares of voting stock of the Borrower on a fully diluted basis; or (iii) the majority of the Board of Directors of the Parent fails to consist of Continuing Directors.
“Closing Date” means June 27, 2002.
“Code” means the Internal Revenue Code of 1986, as amended, reformed or otherwise modified from time to time, and any rule or regulation issued thereunder.
“Commitment” means, for each Lender, the amount set forth on the Commitment Schedule opposite such Lender’s name, as it may be modified as a result of any assignment that has become effective pursuant to Section 12.3.2 or as otherwise modified from time to time pursuant to the terms hereof.
“Commitment Schedule” means the Schedule identifying each Lender’s Commitment as of the Closing Date attached hereto and identified as such.
“Consolidated Indebtedness” means at any time the Indebtedness of the Borrower and its Subsidiaries calculated on a consolidated basis as of such time.
“Consolidated Net Worth” means at any time the consolidated stockholders’ equity of the Borrower and its Subsidiaries calculated on a consolidated basis in accordance with Agreement Accounting Principles.
“Consolidated Total Capitalization” means at any time the sum of Consolidated Indebtedness and Consolidated Net Worth, each calculated at such time.
“Contingent Obligation” of a Person means any agreement, undertaking or arrangement by which such Person assumes, guarantees, endorses, contingently agrees to purchase or provide funds for the payment of, or otherwise becomes or is contingently liable upon, the obligation or liability of any other Person, or agrees to maintain the net worth or working capital or other financial condition of any other Person, or otherwise assures any creditor of such other Person against loss, including, without limitation, any comfort letter, operating agreement, take-or-pay contract or the obligations of any such Person as general partner of a partnership with respect to the liabilities of the partnership.
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“Continuing Director” means, with respect to any Person as of any date of determination, any member of the board of directors of such Person who (a) was a member of such board of directors on the Closing Date, or (b) was nominated for election or elected to such board of directors with the approval of a majority of the Continuing Directors who were members of such board at the time of such nomination or election.
“Controlled Group” means all members of a controlled group of corporations or other business entities and all trades or businesses (whether or not incorporated) under common control which, together with the Borrower or any of its Subsidiaries, are treated as a single employer under Section 414 of the Code.
“Conversion/Continuation Notice” is defined in Section 2.9.
“Default” means an event described in Article VII.
“Designated Lender” means, with respect to each Designating Lender, each Eligible Designee designated by such Designating Lender pursuant to Section 12.1.2.
“Designating Lender” means, with respect to each Designated Lender, the Lender that designated such Designated Lender pursuant to Section 12.1.2.
“Designation Agreement” is defined in Section 12.1.2.
“Dollar” and “$” means dollars in the lawful currency of the United States of America.
“Eligible Designee” means a special purpose corporation, partnership, limited partnership or limited liability company that is administered by the respective Designating Lender or an Affiliate of such Designating Lender and (i) is organized under the laws of the United States of America or any state thereof, (ii) is engaged primarily in making, purchasing or otherwise investing in commercial loans in the ordinary course of its business and (iii) issues (or the parent of which issues) commercial paper rated at least A-1 or the equivalent thereof by S&P or the equivalent thereof by Moody’s.
“Environmental Laws” means any and all federal, state, local and foreign statutes, laws, judicial decisions, regulations, ordinances, rules, judgments, orders, decrees, plans, injunctions, permits, concessions, grants, franchises, licenses, agreements and other governmental restrictions relating to (i) the protection of the environment, (ii) the effect of the environment on human health, (iii) emissions, discharges or releases of pollutants, contaminants, hazardous substances or wastes into surface water, ground water or land, or (iv) the manufacture, processing, distribution, use, treatment, storage, disposal, transport or handling of pollutants, contaminants, hazardous substances or wastes or the clean-up or other remediation thereof.
“ERISA” means the Employee Retirement Income Security Act of 1974, as amended from time to time, and any rules or regulations issued thereunder.
“Eurodollar Advance” means an Advance which, except as otherwise provided in Section 2.11, bears interest at the applicable Eurodollar Rate.
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“Eurodollar Base Rate” means, with respect to a Eurodollar Advance for the relevant Interest Period, the applicable British Bankers’ Association Interest Settlement Rate for deposits in Dollars appearing on Reuters Screen FRBD as of 11:00 a.m. (London time) two (2) Business Days prior to the first day of such Interest Period, and having a maturity equal to such Interest Period, provided that, (i) if Reuters Screen FRBD is not available to the Agent for any reason, the applicable Eurodollar Base Rate for the relevant Interest Period shall instead be the applicable British Bankers’ Association Interest Settlement Rate for deposits in Dollars as reported by any other generally recognized financial information service as of 11:00 a.m. (London time) two (2) Business Days prior to the first day of such Interest Period, and having a maturity equal to such Interest Period, and (ii) if no such British Bankers’ Association Interest Settlement Rate is available to the Agent, the applicable Eurodollar Base Rate for the relevant Interest Period shall instead be the rate determined by the Agent to be the rate at which Bank One or one of its affiliate banks offers to place deposits in Dollars with first class banks in the London interbank market at approximately 11:00 a.m. (London time) two (2) Business Days prior to the first day of such Interest Period, in the approximate amount of Bank One’s relevant Eurodollar Loan, and having a maturity equal to such Interest Period.
“Eurodollar Loan” means a Loan which, except as otherwise provided in Section 2.11, bears interest at the applicable Eurodollar Rate.
“Eurodollar Rate” means, with respect to a Eurodollar Advance for the relevant Interest Period, the sum of (i) the quotient of (a) the Eurodollar Base Rate applicable to such Interest Period, divided by (b) one minus the Reserve Requirement (expressed as a decimal) applicable to such Interest Period, plus (ii) the Applicable Margin.
“Excluded Taxes” means, in the case of each Lender or applicable Lending Installation and the Agent, taxes imposed on its overall net income, and franchise taxes (imposed in lieu of net income taxes) imposed on it, by (i) the jurisdiction under the laws of which such Lender or the Agent is incorporated or organized or any political combination or subdivision or taxing authority thereof or (ii) the jurisdiction in which the Agent’s or such Lender’s principal executive office or such Lender’s applicable Lending Installation is located.
“Exhibit” refers to an exhibit to this Agreement, unless another document is specifically referenced.
"Facility Fee" is defined in Section 2.5.1.
“Facility Termination Date” means the earlier of (a) June 26, 2003 and (b) the date of termination in whole of the Aggregate Commitment pursuant to Section 2.5 hereof or the Commitments pursuant to Section 8.1 hereof.
“Federal Funds Effective Rate” means, for any day, an interest rate per annum equal to the weighted average 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 for such day (or, if such day is not a Business Day, for the immediately preceding Business Day) by the Federal Reserve Bank of New York, or, if such rate is not so published for any day which is a
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Business Day, the average of the quotations at approximately 10:00 a.m. (Chicago time) on such day on such transactions received by the Agent from three Federal funds brokers of recognized standing selected by the Agent in its sole discretion.
"FERC" means the Federal Energy Regulatory Commission.
“Floating Rate” means, for any day, a rate per annum equal to (i) the Alternate Base Rate for such day plus (ii) the Applicable Margin, in each case changing when and as the Alternate Base Rate changes.
“Floating Rate Advance” means an Advance which, except as otherwise provided in Section 2.11, bears interest at the Floating Rate.
“Floating Rate Loan” means a Loan which, except as otherwise provided in Section 2.11, bears interest at the Floating Rate.
“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 effect from time to time.
“Indebtedness” of a Person means, at any time, without duplication, such Person’s (i) obligations for borrowed money, (ii) obligations representing the deferred purchase price of Property or services (other than accounts payable arising in the ordinary course of such Person’s business payable on terms customary in the trade), (iii) obligations, whether or not assumed, secured by Liens or payable out of the proceeds or production from Property now or hereafter owned or acquired by such Person, (iv) obligations which are evidenced by notes, acceptances, or other instruments, (v) obligations to purchase securities or other Property arising out of or in connection with the sale of the same or substantially similar securities or Property, (vi) Capitalized Lease Obligations, (vii) Contingent Obligations then due and payable by such Person, (viii) reimbursement obligations under Letters of Credit, (ix) Off-Balance Sheet Liabilities, (x) obligations under Sale and Leaseback Transactions and (xi) any other obligation for borrowed money which in accordance with Agreement Accounting Principles would be shown as a liability on the consolidated balance sheet of such Person.
“Interest Period” means, with respect to a Eurodollar Advance, a period of one, two, three or six months or such other period agreed to by the Lenders and the Borrower, commencing on a Business Day selected by the Borrower pursuant to this Agreement. Such Interest Period shall end on but exclude the day which corresponds numerically to such date one, two, three or six months or such other agreed upon period thereafter, provided, however, that if there is no such numerically corresponding day in such next, second, third or sixth succeeding month or such other succeeding period, such Interest Period shall end on the last Business Day of such next, second, third or sixth succeeding month or such other succeeding period. If an Interest Period would otherwise end on a day which is not a Business Day, such Interest Period shall end on the next succeeding Business Day, provided, however, that if said next succeeding Business Day
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falls in a new calendar month, such Interest Period shall end on the immediately preceding Business Day.
“Lenders” means the lending institutions listed on the signature pages of this Agreement and their respective successors and assigns.
“Lending Installation” means, with respect to a Lender or the Agent, the office, branch, subsidiary or affiliate of such Lender or the Agent listed on the signature pages hereof or on the administrative information sheets provided to the Agent in connection herewith or on a Schedule or otherwise selected by such Lender or the Agent pursuant to Section 2.17.
“Letter of Credit” of a Person means a letter of credit or similar instrument which is issued upon the application of such Person or upon which such Person is an account party or for which such Person is in any way liable.
“Lien” means any lien (statutory or other), mortgage, pledge, hypothecation, assignment, deposit arrangement, encumbrance or preference, priority or other security agreement or preferential arrangement of any kind or nature whatsoever (including, without limitation, the interest of a vendor or lessor under any conditional sale, Capitalized Lease or other title retention agreement).
“Loan” means, with respect to a Lender, such Lender’s loan made pursuant to Article II (or any conversion or continuation thereof).
“Loan Documents” means this Agreement and all other documents, instruments, notes (including any Notes issued pursuant to Section 2.13 (if requested)) and agreements executed in connection therewith or contemplated thereby, as the same may be amended, restated or otherwise modified and in effect from time to time.
“Material Adverse Effect” means a material adverse effect on (i) the business, Property, condition (financial or otherwise), operations or results of operations of the Borrower, or the Borrower and its Subsidiaries taken as a whole, (ii) the ability of the Borrower to perform its obligations under the Loan Documents, or (iii) the validity or enforceability of any of the Loan Documents or the rights or remedies of the Agent or the Lenders thereunder.
“Material Indebtedness” means Indebtedness in an outstanding principal amount of $20,000,000 or more in the aggregate (or the equivalent thereof in any currency other than U.S. dollars).
“Material Indebtedness Agreement” means any agreement under which any Material Indebtedness was created or is governed or which provides for the incurrence of Indebtedness in an amount which would constitute Material Indebtedness (whether or not an amount of Indebtedness constituting Material Indebtedness is outstanding thereunder).
“Material Subsidiary” means any Subsidiary that would be a “significant subsidiary” as defined in Article 1, Rule 1-02 of Regulation S-X, as promulgated under the Securities Act of 1933, as amended, as such regulation is in effect on the date of this Agreement, provided,
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however, a Subsidiary that would not be a “significant subsidiary” as defined in Regulation S-X will be treated as a Material Subsidiary to the extent necessary so that all Subsidiaries that are not Material Subsidiaries do not in the aggregate represent more than 25% of the consolidated total assets of the Borrower and its consolidated Subsidiaries or more than 25% of the total revenue of the Borrower and its consolidated Subsidiaries.
"Moody's" means Moody's Investors Service, Inc.
“Multiemployer Plan” means a multiemployer plan, as defined in Section 4001(a)(3) of ERISA, which is covered by Title IV of ERISA and to which the Borrower or any member of the Controlled Group is obligated to make contributions.
"Non-U.S. Lender" is defined in Section 3.5(iv).
"Note" is defined in Section 2.13.
“Obligations” means all Loans, advances, debts, liabilities, obligations, covenants and duties owing by the Borrower to the Agent, any Lender, the Arranger, any affiliate of the Agent, any Lender or the Arranger, or any indemnitee under the provisions of Section 9.6 or any other provisions of the Loan Documents, in each case of any kind or nature, present or future, arising under this Agreement or any other Loan Document, whether or not evidenced by any note, guaranty or other instrument, whether or not for the payment of money, whether arising by reason of an extension of credit, loan, foreign exchange risk, guaranty, indemnification, or in any other manner, whether direct or indirect (including those acquired by assignment), absolute or contingent, due or to become due, now existing or hereafter arising and however acquired. The term includes, without limitation, all interest, charges, expenses, fees, attorneys’ fees and disbursements, paralegals’ fees, and any other sum chargeable to the Borrower or any of its Subsidiaries under this Agreement or any other Loan Document.
“Off-Balance Sheet Liability” of a Person means the principal component of (i) any liability under any Sale and Leaseback Transaction which is not a Capitalized Lease, (ii) any liability under any so-called “synthetic lease” transaction entered into by such Person, or (iii) any obligation arising with respect to any other transaction which is the functional equivalent of or takes the place of borrowing but which does not constitute a liability on the balance sheets of such Person, but excluding from this clause (iii) Operating Leases and also excluding liabilities in connection with any Receivables Purchase Facility.
“Other Taxes” is defined in Section 3.5(ii).
“Outstanding Credit Exposure” means, as to any Lender, the aggregate principal amount of its Loans outstanding at such time.
"Parent" means OGE Energy Corp., an Oklahoma corporation.
"Participants" is defined in Section 12.2.1.
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“Payment Date” means the last day of March, June, September and December and the Facility Termination Date.
“PBGC” means the Pension Benefit Guaranty Corporation, or any successor thereto.
“Person” means any natural person, corporation, firm, joint venture, partnership, limited liability company, association, enterprise, trust or other entity or organization, or any government or political subdivision or any agency, department or instrumentality thereof.
“Plan” means an employee pension benefit plan, excluding any Multiemployer Plan, which is covered by Title IV of ERISA or subject to the minimum funding standards under Section 412 of the Code as to which the Borrower or any member of the Controlled Group may have any liability.
“Pricing Schedule” means the Schedule identifying the Applicable Margin and Applicable Fee Rate attached hereto and identified as such.
“Prime Rate” means a rate per annum equal to the prime rate of interest announced from time to time by Bank One or its parent (which is not necessarily the lowest rate charged to any customer), changing when and as said prime rate changes.
“Property” of a Person means any and all property, whether real, personal, tangible, intangible, or mixed, of such Person, or other assets owned, leased or operated by such Person.
“Pro Rata Share” means, with respect to a Lender, a portion equal to a fraction the numerator of which is such Lender’s Commitment at such time (in each case, as adjusted from time to time in accordance with the provisions of this Agreement) and the denominator of which is the Aggregate Commitment at such time, or, if the Aggregate Commitment has been terminated, a fraction the numerator of which is such Lender’s Outstanding Credit Exposure at such time and the denominator of which is the sum of the aggregate outstanding amount of all Loans at such time.
"Purchasers" is defined in Section 12.3.1.
“Rate Management Obligations” of a Person means any and all obligations of such Person, whether absolute or contingent and howsoever and whensoever created, arising, evidenced or acquired (including all renewals, extensions and modifications thereof and substitutions therefor), under (i) any and all Rate Management Transactions, and (ii) any and all cancellations, buy backs, reversals, terminations or assignments of any Rate Management Transactions.
“Rate Management Transaction” means any transaction (including an agreement with respect thereto) now existing or hereafter entered by the Borrower which is a rate swap, basis swap, forward rate transaction, equity or equity index swap, equity or equity index option, bond option, interest rate option, foreign exchange transaction, cap transaction, floor transaction, collar transaction, forward transaction, currency swap transaction, cross-currency rate swap transaction, currency option or any other similar transaction (including any option with respect to any of these
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transactions) or any combination thereof, whether linked to one or more interest rates, foreign currencies, or equity prices.
“Receivables Purchase Documents” means any series of receivables purchase or sale agreements generally consistent with terms contained in comparable structured finance transactions pursuant to which the Borrower or any of its Subsidiaries, in their respective capacities as sellers or transferors of any consumer loan receivables, sell or transfer to SPVs all of their respective rights, title and interest in and to certain consumer loan receivables for further sale or transfer to other purchasers of or investors in such assets (and the other documents, instruments and agreements executed in connection therewith), as any such agreements may be amended, restated, supplemented or otherwise modified from time to time, or any replacement or substitution therefor.
“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 SPVs, and thereafter to certain investors, pursuant to the terms and conditions of the Receivables Purchase Documents.
“Regulation D” means Regulation D of the Board of Governors of the Federal Reserve System as from time to time in effect and any successor thereto or other regulation or official interpretation of said Board of Governors relating to reserve requirements applicable to member banks of the Federal Reserve System.
“Regulation U” means Regulation U of the Board of Governors of the Federal Reserve System as from time to time in effect and any successor or other regulation or official interpretation of said Board of Governors relating to the extension of credit by banks for the purpose of purchasing or carrying margin stocks applicable to member banks of the Federal Reserve System.
“Regulation X” means Regulation X of the Board of Governors of the Federal Reserve System as from time to time in effect and any successor or other regulation or official interpretation of said Board of Governors relating to the extension of credit by foreign lenders for the purpose of purchasing or carrying margin stock (as defined therein).
“Reportable Event” means a reportable event as defined in Section 4043 of ERISA and the regulations issued under such section, with respect to a Plan subject to Title IV of ERISA, excluding, however, such events as to which the PBGC has by regulation waived the requirement of Section 4043(a) of ERISA that it be notified within 30 days of the occurrence of such event, provided, however, that a failure to meet the minimum funding standard of Section 412 of the Code and of Section 302 of ERISA shall be a Reportable Event regardless of the issuance of any such waiver of the notice requirement in accordance with either Section 4043(a) of ERISA or Section 412(d) of the Code.
“Required Lenders” means Lenders in the aggregate having greater than fifty-five percent (55%) of the Aggregate Commitment or, if the Aggregate Commitment has been terminated,
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Lenders in the aggregate holding greater than fifty-five percent (55%) of the Aggregate Outstanding Credit Exposure.
“Reserve Requirement” means, with respect to an Interest Period, the maximum aggregate reserve requirement (including all basic, supplemental, marginal and other reserves) which is imposed under Regulation D on Eurocurrency liabilities.
“S&P” means Standard and Poor’s Ratings Services, a division of The McGraw Hill Companies, Inc.
“Sale and Leaseback Transaction” means any sale or other transfer of Property by any Person with the intent to lease such Property as lessee.
“Schedule” refers to a specific schedule to this Agreement, unless another document is specifically referenced.
“SEC Reports” means (i) the Annual Report on Form 10-K of the Borrower for the fiscal year ended December 31, 2001; (ii) the Quarterly Report on Form 10-Q of the Borrower for the fiscal quarter ended March 31, 2002; and (iii) the Current Report on Form 8-K of the Borrower dated May 16, 2002.
“Section” means a numbered section of this Agreement, unless another document is specifically referenced.
“Single Employer Plan” means a Plan maintained by the Borrower or any member of the Controlled Group for employees of the Borrower or any member of the Controlled Group.
“SPV” means any special purpose entity established for the purpose of purchasing consumer loan receivables in connection with a receivables securitization transaction permitted under the terms of this Agreement.
“Subsidiary” of a Person means (i) any corporation more than 50% of the outstanding securities having ordinary voting power of which shall at the time be owned or controlled, directly or indirectly, by such Person or by one or more of its Subsidiaries or by such Person and one or more of its Subsidiaries, or (ii) any partnership, limited liability company, association, joint venture or similar business organization more than 50% of the ownership interests having ordinary voting power of which shall at the time be so owned or controlled. Unless otherwise expressly provided, all references herein to a “Subsidiary” shall mean a Subsidiary of the Borrower.
“Substantial Portion” means, with respect to the Property of the Borrower and its Subsidiaries, Property which represents more than 10% of the consolidated assets of the Borrower and its Subsidiaries or property which is responsible for more than 10% of the consolidated net sales or of the consolidated net income of the Borrower and its Subsidiaries, in each case, as would be shown in the consolidated financial statements of the Borrower and its Subsidiaries as at the end of the four fiscal quarter period ending with the fiscal quarter immediately prior to the fiscal quarter in which such determination is made (or if financial
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statements have not been delivered hereunder for that fiscal quarter which ends the four fiscal quarter period, then the financial statements delivered hereunder for the quarter ending immediately prior to that quarter).
“Syndication Agent” means Wachovia Bank, National Association, in its capacity as Syndication Agent hereunder.
“Taxes” means any and all present or future taxes, duties, levies, imposts, deductions, charges or withholdings, and any and all liabilities with respect to the foregoing, but excluding Excluded Taxes and Other Taxes.
"Transferee" is defined in Section 12.4.
“Type” means, with respect to any Advance, its nature as a Floating Rate Advance or a Eurodollar Advance and with respect to any Loan, its nature as a Floating Rate Loan or a Eurodollar Loan.
“Unfunded Liabilities” means the amount (if any) by which the present value of all vested and unvested accrued benefits under each Single Employer Plan subject to Title IV of ERISA exceeds the fair market value of all such Plan’s assets allocable to such benefits, all determined as of the then most recent valuation date for such Plan for which a valuation report is available, using actuarial assumptions for funding purposes as set forth in such report.
“Unmatured Default” means an event which but for the lapse of time or the giving of notice, or both, would constitute a Default.
“Utilization Fee” is defined in Section 2.5.2.
“Wholly-Owned Subsidiary” of a Person means (i) any Subsidiary all of the outstanding voting securities of which shall at the time be owned or controlled, directly or indirectly, by such Person or one or more Wholly-Owned Subsidiaries of such Person, or by such Person and one or more Wholly-Owned Subsidiaries of such Person, or (ii) any partnership, limited liability company, association, joint venture or similar business organization 100% of the ownership interests having ordinary voting power of which shall at the time be so owned or controlled.
The foregoing definitions shall be equally applicable to both the singular and plural forms of the defined terms.
2.1. Commitment. From and including the date of this Agreement and prior to the Facility Termination Date, upon the satisfaction of the conditions precedent set forth in Section 4.1 and 4.2, as applicable, each Lender severally agrees, on the terms and conditions set forth in this Agreement, to make Loans to the Borrower from time to time in an amount not to exceed in the aggregate at any one time outstanding its Pro Rata Share of the Aggregate Commitment;
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provided that at no time shall the Aggregate Outstanding Credit Exposure hereunder exceed the Aggregate Commitment. Subject to the terms of this Agreement, the Borrower may borrow, repay and reborrow at any time prior to the Facility Termination Date. The commitment of each Lender to lend hereunder shall expire on the Facility Termination Date.
2.2. Required Payments; Termination. Any outstanding Advances and all other unpaid Obligations shall be paid in full by the Borrower on the Facility Termination Date. Notwithstanding the termination of this Agreement on the Facility Termination Date, until all of the Obligations (other than contingent indemnity obligations) shall have been fully paid and satisfied and all financing arrangements among the Borrower and the Lenders hereunder and under the other Loan Documents shall have been terminated, all of the rights and remedies under this Agreement and the other Loan Documents shall survive.
2.3. Ratable Loans. Each Advance hereunder shall consist of Loans made from the several Lenders ratably in proportion to the ratio that their respective Commitments bear to the Aggregate Commitment.
2.4. Types of Advances. The Advances may be Floating Rate Advances or Eurodollar Advances, or a combination thereof, selected by the Borrower in accordance with Sections 2.8 and 2.9.
2.5. Facility Fee; Utilization Fee; Reductions in Aggregate Commitment.
| Facility Fee. The Borrower agrees to pay to the Agent for the account of each Lender a Facility Fee (the “Facility Fee”) at a per annum rate equal to the Applicable Fee Rate on such Lender’s Commitment (whether used or unused) from the date hereof to and including the Facility Termination Date, payable on each Payment Date hereafter and on the Facility Termination Date, provided that, if any Lender continues to have Loans outstanding hereunder after the termination of its Commitment (including, without limitation, during any period when Loans may be outstanding but new Loans may not be borrowed hereunder), then the Facility Fee shall continue to accrue on the aggregate principal amount of the Loans owed to such Lender until such Loans are repaid in full. |
| Utilization Fee. If the Aggregate Outstanding Credit Exposure of all the Lenders hereunder exceeds thirty-three and one-third percent (331/3%) of the Aggregate Commitment hereunder (which, after the Commitments have been terminated, shall be based on the Aggregate Commitment immediately prior to such termination) then in effect on such date, the Borrower will pay to the Agent for the ratable benefit of the Lenders a utilization fee (the “Utilization Fee”) at a per annum rate equal to the Applicable Fee Rate on the average daily Aggregate Outstanding Credit Exposure for the then current fiscal quarter (or portion thereof), payable quarterly in arrears on each Payment Date and on the date this Agreement is terminated in full and all Obligations hereunder have been paid in full pursuant to Section 2.2. |
| Reductions in Aggregate Commitment. The Borrower may permanently reduce the Aggregate Commitment in whole, or in part, ratably among the Lenders in integral |
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| multiples of $5,000,000, upon at least two Business Days’ written notice to the Agent, which notice shall specify the amount of any such reduction, provided, however, that the amount of the Aggregate Commitment may not be reduced below the aggregate principal amount of the outstanding Advances. All accrued facility fees shall be payable on the effective date of any termination of the obligations of the Lenders to make Loans hereunder and on the final date upon which all Loans are repaid hereunder. |
2.6. Minimum Amount of Each Advance. Each Eurodollar Advance shall be in the minimum amount of $5,000,000 (and in multiples of $1,000,000 if in excess thereof), and each Floating Rate Advance shall be in the minimum amount of $5,000,000 (and in multiples of $1,000,000 if in excess thereof), provided, however, that any Floating Rate Advance may be in the amount of the unused Aggregate Commitment.
2.7. Optional Principal Payments. The Borrower may from time to time pay, without penalty or premium, all outstanding Floating Rate Advances, or, in a minimum aggregate amount of $1,000,000 or any integral multiple of $1,000,000 in excess thereof, any portion of the outstanding Floating Rate Advances on any Business Day upon notice to the Agent by no later than 10:00 a.m. (Chicago time) on the date of such prepayment. The Borrower may from time to time pay, subject to the payment of any funding indemnification amounts required by Section 3.4 but without penalty or premium, all outstanding Eurodollar Advances, or, in a minimum aggregate amount of $1,000,000 or any integral multiple of $500,000 in excess thereof, any portion of the outstanding Eurodollar Advances upon three Business Days' prior notice to the Agent.
2.8. Method of Selecting Types and Interest Periods for New Advances. The Borrower shall select the Type of Advance and, in the case of each Eurodollar Advance, the Interest Period applicable thereto from time to time. The Borrower shall give the Agent irrevocable notice (a "Borrowing Notice") not later than 10:00 a.m. (Chicago time) on the Borrowing Date of each Floating Rate Advance and three Business Days before the Borrowing Date for each Eurodollar Advance, specifying:
the Borrowing Date, which shall be a Business Day, of such Advance,
the aggregate amount of such Advance,
the Type of Advance selected, and
in the case of each Eurodollar Advance, the Interest Period applicable thereto.
Not later than noon (Chicago time) on each Borrowing Date, each Lender shall make available its Loan or Loans in funds immediately available in Chicago to the Agent at its address specified pursuant to Article XIII. The Agent will promptly make the funds so received from the Lenders available to the Borrower at the Agent’s aforesaid address.
2.9 Conversion and Continuation of Outstanding Advances. Floating Rate Advances shall continue as Floating Rate Advances unless and until such Floating Rate Advances are converted into Eurodollar Advances pursuant to this Section 2.9 or are repaid in accordance with
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Section 2.7. Each Eurodollar Advance shall continue as a Eurodollar Advance until the end of the then applicable Interest Period therefor, at which time such Eurodollar Advance shall be automatically converted into a Floating Rate Advance unless (x) such Eurodollar Advance is or was repaid in accordance with Section 2.7 or (y) the Borrower shall have given the Agent a Conversion/Continuation Notice (as defined below) requesting that, at the end of such Interest Period, such Eurodollar Advance continue as a Eurodollar Advance for the same or another Interest Period. Subject to the terms of Section 2.6, the Borrower may elect from time to time to convert all or any part of a Floating Rate Advance into a Eurodollar Advance. The Borrower shall give the Agent irrevocable notice (a “Conversion/Continuation Notice”) of each conversion of a Floating Rate Advance into a Eurodollar Advance or continuation of a Eurodollar Advance not later than 10:00 a.m. (Chicago time) on the third Business Day prior to the date of the requested conversion or continuation, specifying:
the requested date, which shall be a Business Day, of such conversion or continuation,
the aggregate amount and Type of the Advance which is to be converted or continued, and
the amount of such Advance which is to be converted into or continued as a Eurodollar Advance and the duration of the Interest Period applicable thereto.
2.10. Changes in Interest Rate, etc. Each Floating Rate Advance shall bear interest on the outstanding principal amount thereof, for each day from and including the date such Advance is made or is automatically converted from a Eurodollar Advance into a Floating Rate Advance pursuant to Section 2.9, to but excluding the date it is paid or is converted into a Eurodollar Advance pursuant to Section 2.9 hereof, at a rate per annum equal to the Floating Rate for such day. Changes in the rate of interest on that portion of any Advance maintained as a Floating Rate Advance will take effect simultaneously with each change in the Alternate Base Rate. Each Eurodollar Advance shall bear interest on the outstanding principal amount thereof from and including the first day of the Interest Period applicable thereto to (but not including) the last day of such Interest Period at the interest rate determined by the Agent as applicable to such Eurodollar Advance based upon the Borrower's selections under Sections 2.8 and 2.9 and otherwise in accordance with the terms hereof. No Interest Period may end after the Facility Termination Date.
2.11. Rates Applicable After Default. Notwithstanding anything to the contrary contained in Section 2.8, 2.9 or 2.10, during the continuance of a Default or Unmatured Default the Required Lenders may, at their option, by notice to the Borrower, declare that no Advance may be made as, converted into or continued as a Eurodollar Advance. During the continuance of a Default the Required Lenders may, at their option, by notice to the Borrower (which notice may be revoked at the option of the Required Lenders notwithstanding any provision of Section 8.2 requiring unanimous consent of the Lenders to changes in interest rates), declare that (i) each Eurodollar Advance shall bear interest for the remainder of the applicable Interest Period at the rate otherwise applicable to such Interest Period plus 2% per annum and (ii) each Floating Rate Advance shall bear interest at a rate per annum equal to the Floating Rate in effect from time to
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time plus 2% per annum, provided that, during the continuance of a Default under Section 7.6 or 7.7, the interest rates set forth in clauses (i) and (ii) above shall be applicable to all Advances without any election or action on the part of the Agent or any Lender.
2.12. Method of Payment. All payments of the Obligations hereunder shall be made, without setoff, deduction, or counterclaim, in immediately available funds to the Agent at the Agent's address specified pursuant to Article XIII, or at any other Lending Installation of the Agent specified in writing by the Agent to the Borrower, by noon (local time) on the date when due and shall be applied ratably by the Agent among the Lenders. Each payment delivered to the Agent for the account of any Lender shall be delivered promptly by the Agent to such Lender in the same type of funds that the Agent received at its address specified pursuant to Article XIII or at any Lending Installation specified in a notice received by the Agent from such Lender. The Agent is hereby authorized to charge the account of the Borrower maintained with Bank One for each payment of principal, interest and fees as it becomes due hereunder.
2.13. Noteless Agreement; Evidence of Indebtedness. 99.02.1.1Each Lender shall maintain in accordance with its usual practice an account or accounts evidencing the indebtedness of the Borrower to such Lender resulting from each Loan made by such Lender from time to time, including the amounts of principal and interest payable and paid to such Lender from time to time hereunder.
The Agent shall also maintain accounts in which it will record (a) the
amount of each Loan made hereunder, the Type thereof and the Interest
Period with respect thereto, (b) the amount of any principal or
interest due and payable or to become due and payable from the
Borrower to each Lender hereunder and (c) the amount of any sum
received by the Agent hereunder from the Borrower and each
Lender’s share thereof.
The entries maintained in the accounts maintained pursuant to paragraphs
(i) and (ii) above shall be prima facie evidence of the
existence and amounts of the Obligations therein recorded;
provided, however, that the failure of the Agent or any Lender
to maintain such accounts or any error therein shall not in any manner
affect the obligation of the Borrower to repay the Obligations in
accordance with their terms.
Any Lender may request that its Loans be evidenced by a promissory note in
substantially the form of Exhibit E (a “Note”). In such
event, the Borrower shall prepare, execute and deliver to such Lender
such Note payable to the order of such Lender. Thereafter, the Loans
evidenced by such Note and interest thereon shall at all times (prior
to any assignment pursuant to Section 12.3) be represented by one or
more Notes payable to the order of the payee named therein, except to
the extent that any such Lender subsequently returns any such Note for
cancellation and requests that such Loans once again be evidenced as
described in paragraphs (i) and (ii) above.
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2.14. Telephonic Notices. The Borrower hereby authorizes the Lenders and the Agent to extend, convert or continue Advances, effect selections of Types of Advances and to transfer funds based on telephonic notices made by any person or persons the Agent or any Lender in good faith believes to be acting on behalf of the Borrower, it being understood that the foregoing authorization is specifically intended to allow Borrowing Notices and Conversion/Continuation Notices to be given telephonically. The Borrower agrees to deliver promptly to the Agent a written confirmation, if such confirmation is requested by the Agent or any Lender, of each telephonic notice signed by an Authorized Officer. If the written confirmation differs in any material respect from the action taken by the Agent and the Lenders, the records of the Agent and the Lenders shall govern absent manifest error.
2.15. Interest Payment Dates; Interest and Fee Basis. Interest accrued on each Floating Rate Advance shall be payable in arrears on each Payment Date, commencing with the first such date to occur after the date hereof, on any date on which the Floating Rate Advance is prepaid, whether due to acceleration or otherwise, and at maturity. Interest accrued on that portion of the outstanding principal amount of any Floating Rate Advance converted into a Eurodollar Advance on a day other than a Payment Date shall be payable on the date of conversion. Interest accrued on each Eurodollar Advance shall be payable on the last day of its applicable Interest Period, on any date on which the Eurodollar Advance is prepaid, whether by acceleration or otherwise, and at maturity. Interest accrued on each Eurodollar Advance having an Interest Period longer than three months shall also be payable on the last day of each three-month interval during such Interest Period. Interest and fees shall be calculated for actual days elapsed on the basis of a 360-day year. Interest shall be payable for the day an Advance is made but not for the day of any payment on the amount paid if payment is received prior to noon (local time) at the place of payment. If any payment of principal of or interest on an Advance, any fees or any other amounts payable to the Agent or any Lender hereunder shall become due on a day which is not a Business Day, such payment shall be made on the next succeeding Business Day and, in the case of a principal payment, such extension of time shall be included in computing interest, fees and commissions in connection with such payment.
2.16. Notification of Advances, Interest Rates, Prepayments and Commitment Reductions; Availability or Loans. Promptly after receipt thereof, the Agent will notify each Lender of the contents of each Aggregate Commitment reduction notice, Borrowing Notice, Conversion/Continuation Notice, and repayment notice received by it hereunder. The Agent will notify the Borrower and each Lender of the interest rate applicable to each Eurodollar Advance promptly upon determination of such interest rate and will give the Borrower and each Lender prompt notice of each change in the Alternate Base Rate. Not later than 12:00 noon (Chicago time) on each Borrowing Date, each Lender shall make available its Loan or Loans in funds immediately available in Chicago to the Agent at its address specified pursuant to Article XIII. The Agent will promptly make the funds so received from the Lenders available to the Borrower at the Agent's aforesaid address.
2.17. Lending Installations. Each Lender may book its Loans at any Lending Installation selected by such Lender and may change its Lending Installation from time to time. All terms of this Agreement shall apply to any such Lending Installation and the Loans and any Notes issued hereunder shall be deemed held by each Lender for the benefit of any such Lending Installation.
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Each Lender may, by written notice to the Agent and the Borrower in accordance with Article XIII, designate replacement or additional Lending Installations through which Loans will be made by it and for whose account Loan payments are to be made.
2.18. Non-Receipt of Funds by the Agent. Unless the Borrower or a Lender, as the case may be, notifies the Agent prior to the date on which it is scheduled to make payment to the Agent of (i) in the case of a Lender, the proceeds of a Loan or (ii) in the case of the Borrower, a payment of principal, interest or fees to the Agent for the account of the Lenders, that it does not intend to make such payment, the Agent may assume that such payment has been made. The Agent may, but shall not be obligated to, make the amount of such payment available to the intended recipient in reliance upon such assumption. If such Lender or the Borrower, as the case may be, has not in fact made such payment to the Agent, the recipient of such payment shall, on demand by the Agent, repay to the Agent the amount so made available together with interest thereon in respect of each day during the period commencing on the date such amount was so made available by the Agent until the date the Agent recovers such amount at a rate per annum equal to (x) in the case of payment by a Lender, the Federal Funds Effective Rate for such day for the first three days and, thereafter, the interest rate applicable to the relevant Loan or (y) in the case of payment by the Borrower, the interest rate applicable to the relevant Loan.
2.19. Replacement of Lender. If the Borrower is required pursuant to Section 3.1, 3.2 or 3.5 to make any additional payment to any Lender or if any Lender's obligation to make or continue, or to convert Floating Rate Advances into, Eurodollar Advances shall be suspended pursuant to Section 3.3 (any Lender so affected an "Affected Lender"), the Borrower may elect, if such amounts continue to be charged or such suspension is still effective, to replace such Affected Lender as a Lender party to this Agreement, provided that no Default or Unmatured Default shall have occurred and be continuing at the time of such replacement, and provided further that, concurrently with such replacement, (i) another bank or other entity which is reasonably satisfactory to the Borrower and the Agent shall agree, as of such date, to purchase for cash the Loans due to the Affected Lender pursuant to an assignment substantially in the form of Exhibit C and to become a Lender for all purposes under this Agreement and to assume all obligations of the Affected Lender to be terminated as of such date and to comply with the requirements of Section 12.3 applicable to assignments, and (ii) the Borrower shall pay to such Affected Lender in same day funds on the day of such replacement (A) all interest, fees and other amounts then accrued but unpaid to such Affected Lender by the Borrower hereunder to and including the date of termination, including without limitation payments due to such Affected Lender under Sections 3.1, 3.2 and 3.5, and (B) an amount, if any, equal to the payment which would have been due to such Lender on the day of such replacement under Section 3.4 had the Loans of such Affected Lender been prepaid on such date rather than sold to the replacement Lender, in each case to the extent not paid by the purchasing lender.
YIELD PROTECTION; TAXES
3.1. Yield Protection. If, on or after the date of this Agreement, the adoption of any law or any governmental or quasi-governmental rule, regulation, policy, guideline or directive
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(whether or not having the force of law), or any change in any such law, rule, regulation, policy, guideline or directive or in the interpretation or administration thereof by any governmental or quasi-governmental authority, central bank or comparable agency charged with the interpretation or administration thereof, or compliance by any Lender or applicable Lending Installation with any request or directive (whether or not having the force of law) of any such authority, central bank or comparable agency:
subjects any Lender or any applicable Lending Installation to any Taxes, or changes the basis of taxation of payments (other than with respect to Excluded Taxes) to any Lender in respect of its Eurodollar Loans, or
imposes or increases or deems applicable any reserve, assessment, insurance charge, special deposit or similar requirement against assets of, deposits with or for the account of, or credit extended by, any Lender or any applicable Lending Installation (other than reserves and assessments taken into account in determining the interest rate applicable to Eurodollar Advances), or
imposes any other condition the result of which is to increase the cost to any Lender or any applicable Lending Installation of making, funding or maintaining its Commitment or Eurodollar Loans or reduces any amount receivable by any Lender or any applicable Lending Installation in connection with its Commitment or Eurodollar Loans, or requires any Lender or any applicable Lending Installation to make any payment calculated by reference to the amount of Commitment or Eurodollar Loans held or interest received by it, by an amount deemed material by such Lender.
and the result of any of the foregoing is to increase the cost to such Lender or applicable Lending Installation of making or maintaining its Eurodollar Loans or Commitment or to reduce the return received by such Lender or applicable Lending Installation in connection with such Eurodollar Loans or Commitment, then, within 15 days of demand, accompanied by the written statement required by Section 3.6, by such Lender, the Borrower shall pay such Lender such additional amount or amounts as will compensate such Lender for such increased cost or reduction in amount received.
3.2. Changes in Capital Adequacy Regulations. If a Lender determines the amount of capital required or expected to be maintained by such Lender, any Lending Installation of such Lender or any corporation controlling such Lender is increased as a result of a Change, then, within 15 days of demand, accompanied by the written statement required by Section 3.6, by such Lender, the Borrower shall pay such Lender the amount necessary to compensate for any shortfall in the rate of return on the portion of such increased capital which such Lender determines is attributable to this Agreement, its Loans or its Commitment to make Loans hereunder (after taking into account such Lender's policies as to capital adequacy). "Change" means (i) any change after the date of this Agreement in the Risk-Based Capital Guidelines or (ii) any adoption of, or change in, the interpretation or administration of any other law, governmental or quasi-governmental rule, regulation, policy, guideline, interpretation, or directive (whether or not having the force of law) after the date of this Agreement which affects the amount of capital required or expected to be maintained by any Lender or any Lending
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Installation or any corporation controlling any Lender. "Risk-Based Capital Guidelines" means (i) the risk-based capital guidelines in effect in the United States on the date of this Agreement, including transition rules, and (ii) the corresponding capital regulations promulgated by regulatory authorities outside the United States implementing the July 1988 report of the Basle Committee on Banking Regulation and Supervisory Practices entitled "International Convergence of Capital Measurements and Capital Standards," including transition rules, and any amendments to such regulations adopted prior to the date of this Agreement.
3.3. Availability of Types of Advances. If any Lender determines that maintenance of its Eurodollar Loans at a suitable Lending Installation would violate any applicable law, rule, regulation, or directive, whether or not having the force of law, or if the Required Lenders determine that (i) deposits of a type and maturity appropriate to match fund Eurodollar Advances are not available or (ii) the interest rate applicable to Eurodollar Advances does not accurately reflect the cost of making or maintaining Eurodollar Advances, then the Agent shall suspend the availability of Eurodollar Advances and require any affected Eurodollar Advances to be repaid or converted to Floating Rate Advances on the respective last days of the then current Interest Periods with respect to such Loans or within such earlier period as required by law, subject to the payment of any funding indemnification amounts required by Section 3.4.
3.4. Funding Indemnification. If any payment of a Eurodollar Advance occurs on a date which is not the last day of the applicable Interest Period, whether because of acceleration, prepayment or otherwise, or a Eurodollar Advance is not made on the date specified by the Borrower for any reason other than default by the Lenders, or a Eurodollar Advance is not prepaid on the date specified by the Borrower for any reason, the Borrower will indemnify each Lender for any loss or cost incurred by it resulting there from, including, without limitation, any loss or cost in liquidating or employing deposits acquired to fund or maintain such Eurodollar Advance.
3.5. Taxes. 99.02.1.2 All payments by the Borrower to or for the account of any Lender or the Agent hereunder or under any Note shall be made free and clear of and without deduction for any and all Taxes. If the Borrower shall be required by law to deduct any Taxes from or in respect of any sum payable hereunder to any Lender or the Agent, (a) the sum payable shall be increased as necessary so that after making all required deductions (including deductions applicable to additional sums payable under this Section 3.5) such Lender or the Agent (as the case may be) receives an amount equal to the sum it would have received had no such deductions been made, (b) the Borrower shall make such deductions, (c) the Borrower shall pay the full amount deducted to the relevant authority in accordance with applicable law and (d) the Borrower shall furnish to the Agent the original copy of a receipt evidencing payment thereof or, if a receipt cannot be obtained with reasonable efforts, such other evidence of payment as is reasonably acceptable to the Agent, in each case within 30 days after such payment is made.
In addition, the Borrower shall pay any present or future stamp or
documentary taxes and any other excise or property taxes, charges or
similar levies which arise from any payment made hereunder or under
any Note or from the execution or delivery of, or otherwise with
respect to, this Agreement or any Note (“Other Taxes”).
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The Borrower shall indemnify the Agent and each Lender for the full amount
of Taxes or Other Taxes (including, without limitation, any Taxes or
Other Taxes imposed on amounts payable under this Section 3.5) paid by
the Agent or such Lender as a result of its Commitment, any Loans made
by it hereunder, or otherwise in connection with its participation in
this Agreement and any liability (including penalties, interest and
expenses) arising there from or with respect thereto. Payments due
under this indemnification shall be made within 30 days of the date
the Agent or such Lender makes demand therefor pursuant to Section
3.6.
Each Lender that is not incorporated under the laws of the United States of
America or a state thereof (each a “Non-U.S. Lender”) agrees
that it will, not more than ten Business Days after the date on which
it becomes a party to this Agreement (but in any event before a
payment is due to it hereunder), (i) deliver to each of the Borrower
and the Agent two duly completed copies of United States Internal
Revenue Service Form W-8BEN or W-8ECI, certifying in either case that
such Lender is entitled to receive payments under this Agreement
without deduction or withholding of any United States federal income
taxes, or (ii) in the case of a Non-U.S. Lender that is fiscally
transparent, deliver to the Agent a United States Internal Revenue
Form W-8IMY together with the applicable accompanying forms, W-8 or
W-9, as the case may be, and certify that it is entitled to an
exemption from United States withholding tax. Each Non-U.S. Lender
further undertakes to deliver to each of the Borrower and the Agent
(x) renewals or additional copies of such form (or any successor form)
on or before the date that such form expires or becomes obsolete, and
(y) after the occurrence of any event requiring a change in the most
recent forms so delivered by it, such additional forms or amendments
thereto as may be reasonably requested by the Borrower or the Agent.
All forms or amendments described in the preceding sentence shall
certify that such Lender is entitled to receive payments under this
Agreement without deduction or withholding of any United States
federal income taxes, unless an event (including without
limitation any change in treaty, law or regulation) has occurred prior
to the date on which any such delivery would otherwise be required
which renders all such forms inapplicable or which would prevent such
Lender from duly completing and delivering any such form or amendment
with respect to it and such Lender advises the Borrower and the Agent
that it is not capable of receiving payments without any deduction or
withholding of United States federal income tax.
For any period during which a Non-U.S. Lender has failed to provide the
Borrower with an appropriate form pursuant to clause (iv) above
(unless such failure is due to a change in treaty, law or regulation,
or any change in the interpretation or administration thereof by any
governmental authority, occurring subsequent to the date on which a
form originally was required to be provided), such Non-U.S. Lender
shall not be entitled to gross up or indemnification under this
Section 3.5 with respect to Taxes imposed by the United States;
provided that, should a Non-U.S. Lender which is otherwise
exempt from or subject to a reduced rate of withholding tax become
subject to Taxes because of its failure to deliver a form
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required under clause (iv) above, the Borrower shall take such steps as
such Non-U.S. Lender shall reasonably request to assist such Non-U.S.
Lender to recover such Taxes.
Any Lender that is entitled to an exemption from or reduction of
withholding tax with respect to payments under this Agreement or any
Note pursuant to the law of any relevant jurisdiction or any treaty
shall deliver to the Borrower (with a copy to the Agent), at the time
or times prescribed by applicable law, such properly completed and
executed documentation prescribed by applicable law as will permit
such payments to be made without withholding or at a reduced rate.
If the U.S. Internal Revenue Service or any other governmental authority
of the United States or any other country or any political subdivision
thereof asserts a claim that the Agent did not properly withhold tax
from amounts paid to or for the account of any Lender (because the
appropriate form was not delivered or properly completed, because such
Lender failed to notify the Agent of a change in circumstances which
rendered its exemption from withholding ineffective, or for any other
reason), such Lender shall indemnify the Agent fully for all amounts
paid, directly or indirectly, by the Agent as tax, withholding
therefor, or otherwise, including penalties and interest, and
including taxes imposed by any jurisdiction on amounts payable to the
Agent under this subsection, together with all costs and expenses
related thereto (including attorneys fees and time charges of
attorneys for the Agent, which attorneys may be employees of the
Agent). The obligations of the Lenders under this Section 3.5(vii)
shall survive the payment of the Obligations and termination of this
Agreement.
3.6. Lender Statements; Survival of Indemnity. Each Lender shall deliver a written statement of such Lender to the Borrower (with a copy to the Agent) as to the amount due, if any, under Section 3.1, 3.2, 3.4 or 3.5. Such written statement shall set forth in reasonable detail the calculations upon which such Lender determined such amount and shall be final, conclusive and binding on the Borrower in the absence of manifest error. Determination of amounts payable under such Sections in connection with a Eurodollar Loan shall be calculated as though each Lender funded its Eurodollar Loan through the purchase of a deposit of the type and maturity corresponding to the deposit used as a reference in determining the Eurodollar Rate applicable to such Loan, whether in fact that is the case or not. Unless otherwise provided herein, the amount specified in the written statement of any Lender shall be payable on demand after receipt by the Borrower of such written statement. The obligations of the Borrower under Sections 3.1, 3.2, 3.4 and 3.5 shall survive payment of the Obligations and termination of this Agreement.
3.7. Alternative Lending Installation. To the extent reasonably possible, each Lender shall designate an alternate Lending Installation with respect to its Eurodollar Loans to reduce any liability of the Borrower to such Lender under Sections 3.1, 3.2 and 3.5 or to avoid the unavailability of Eurodollar Advances under Section 3.3, so long as such designation is not, in the judgment of such Lender, reasonably disadvantageous to such Lender. A Lender's designation of an alternative Lending Installation shall not affect the Borrower's rights under Section 2.19 to replace a Lender.
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CONDITIONS PRECEDENT
4.1. Initial Advance. The Lenders shall not be required to make the initial Advance hereunder unless the following conditions precedent have been satisfied and the Borrower has furnished to the Agent with sufficient copies for the Lenders:
Copies of the articles or certificate of incorporation of the Borrower, together with all amendments, and a certificate of good standing, each certified by the appropriate governmental officer in its jurisdiction of incorporation.
Copies, certified by the Secretary or Assistant Secretary of the Borrower, of its by-laws and of its Board of Directors’ resolutions and of resolutions or actions of any other body authorizing the execution of the Loan Documents to which the Borrower is a party.
An incumbency certificate, executed by the Secretary or Assistant Secretary of the Borrower, which shall identify by name and title and bear the signatures of the Authorized Officers and any other officers of the Borrower authorized to sign the Loan Documents to which the Borrower is a party, upon which certificate the Agent and the Lenders shall be entitled to rely until informed of any change in writing by the Borrower.
A certificate, signed by the chief financial officer of the Borrower, stating that on the Closing Date no Default or Unmatured Default has occurred and is continuing.
A written opinion of the Borrower’s counsels, in form and substance satisfactory to the Agent and addressed to the Lenders, in substantially the form of Exhibit A.
Any Notes requested by a Lender pursuant to Section 2.13 payable to the order of each such requesting Lender.
Written money transfer instructions, in substantially the form of Exhibit D, addressed to the Agent and signed by an Authorized Officer, together with such other related money transfer authorizations as the Agent may have reasonably requested.
The Agent shall have determined that there is an absence of any material adverse change or disruption in primary or secondary loan syndication markets, financial markets or in capital markets generally that would likely impair syndication of the Loans hereunder.
Such other documents as any Lender or its counsel may have reasonably requested.
4.2. Each Advance. The Lenders shall not be required to make any Advance (including the initial Advance hereunder) unless on the applicable Borrowing Date:
There exists no Default or Unmatured Default.
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The representations and warranties contained in Article V are true and correct as of such Borrowing Date except to the extent any such representation or warranty is stated to relate solely to an earlier date, in which case such representation or warranty shall have been true and correct on and as of such earlier date.
The aggregate amount of short-term debt of the Borrower, after taking into account the requested Advances, will not exceed the maximum amount of short-term debt permitted under all rules, regulations and orders of FERC applicable to the Borrower and its Subsidiaries.
All legal matters incident to the making of such Advance shall be satisfactory to the Lenders and their counsel.
Each Borrowing Notice with respect to each such Advance shall constitute a representation and warranty by the Borrower that the conditions contained in Sections 4.2.1, 4.2.2 and 4.2.3 have been satisfied. Any Lender may require a duly completed compliance certificate in substantially the form of Exhibit B as a condition to making an Advance.
REPRESENTATIONS AND WARRANTIES
The Borrower represents and warrants to the Lenders that:
5.1. Existence and Standing. Each of the Borrower and its Subsidiaries is a corporation, partnership (in the case of Subsidiaries only) or limited liability company duly and properly incorporated or organized, as the case may be, validly existing and (to the extent such concept applies to such entity) in good standing under the laws of its jurisdiction of incorporation or organization and has all requisite authority to conduct its business in each jurisdiction in which its business is conducted, except where the failure to be in good standing could not reasonably be expected to have a Material Adverse Effect.
5.2. Authorization and Validity. The Borrower has the power and authority and legal right to execute and deliver the Loan Documents and to perform its obligations thereunder. The execution and delivery by the Borrower of the Loan Documents and the performance of its obligations thereunder have been duly authorized by proper corporate proceedings, and the Loan Documents to which the Borrower is a party constitute legal, valid and binding obligations of the Borrower enforceable against the Borrower in accordance with their terms, except as enforceability may be limited by bankruptcy, insolvency or similar laws affecting the enforcement of creditors' rights generally.
5.3. No Conflict; Government Consent. Neither the execution and delivery by the Borrower of the Loan Documents, nor the consummation of the transactions therein contemplated, nor compliance with the provisions thereof will violate (i) any law, rule, regulation, order, writ, judgment, injunction, decree or award binding on the Borrower or any of its Subsidiaries or (ii) the Borrower's or any Subsidiary's articles or certificate of incorporation,
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partnership agreement, certificate of partnership, articles or certificate of organization, by-laws, or operating or other management agreement, as the case may be, or (iii) the provisions of any indenture, instrument or agreement to which the Borrower or any of its Subsidiaries is a party or is subject, or by which it, or its Property, is bound, or conflict with or constitute a default thereunder, or result in, or require, the creation or imposition of any Lien in, of or on the Property of the Borrower or a Subsidiary pursuant to the terms of any such indenture, instrument or agreement, except for any such violations which, individually and in the aggregate, could not reasonably be expected to have a Material Adverse Effect. Except as described in the next succeeding sentences, no order, consent, adjudication, approval, license, authorization, or validation of, or filing, recording or registration with, or exemption by, or other action in respect of any governmental or public body or authority, or any subdivision thereof, which has not been obtained by the Borrower or any of its Subsidiaries, is required to be obtained by the Borrower or any of its Subsidiaries in connection with the execution and delivery of the Loan Documents, the borrowings under this Agreement, the payment and performance by the Borrower of the Obligations or the legality, validity, binding effect or enforceability of any of the Loan Documents. FERC has issued its order authorizing the incurrence by the Borrower of short-term debt in the aggregate principal amount not exceeding $400,000,000 outstanding at any one time, subject to the condition that, among other things, all such short-term debt shall be incurred on or before December 31, 2002 and shall mature no later than December 31, 2003. Additional authorization of FERC will be necessary in order for the Borrower to obtain any Advances under this Agreement after December 31, 2002 or to have outstanding more than $400,000,000 in principal amount of short-term debt (including Loans under this Agreement).
5.4 Financial Statements. The December 31, 2001 consolidated financial statements of the Borrower and its Subsidiaries heretofore delivered to the Lenders were prepared in accordance with generally accepted accounting principles in effect on the date such statements were prepared and fairly present the consolidated financial condition and operations of the Borrower and its Subsidiaries at such date and the consolidated results of their operations for the period then ended.
5.5. Material Adverse Change. Since December 31, 2001, except as disclosed in the SEC Reports, there has been no change in the business, Property, condition (financial or otherwise) or results of operations of the Borrower and its Subsidiaries which could reasonably be expected to have a Material Adverse Effect.
5.6. Taxes. The Borrower and its Subsidiaries have filed all United States federal tax returns and all other tax returns which are required to be filed and have paid all taxes due pursuant to said returns or pursuant to any assessment received by the Borrower or any of its Subsidiaries, except in respect of such taxes, if any, which are not in the aggregate material or as are being contested in good faith and as to which adequate reserves have been provided in accordance with GAAP and as to which no Lien exists (except as permitted by Section 6.12.1). The United States income tax returns of the Borrower and its Subsidiaries have been audited by the Internal Revenue Service through the fiscal year ended December 31, 1998. The charges, accruals and reserves on the books of the Borrower and its Subsidiaries in respect of any taxes or other governmental charges are adequate.
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5.7. Litigation and Contingent Obligations. Except as disclosed in the SEC Reports, there is no litigation, arbitration, governmental investigation, proceeding or inquiry pending or, to the knowledge of any of their officers, threatened against or affecting the Borrower or any of its Subsidiaries which could reasonably be expected to have a Material Adverse Effect or which seeks to prevent, enjoin or delay the making of any Loans. Except as disclosed in the SEC Reports, other than any liability incident to any litigation, arbitration or proceeding which could not reasonably be expected to have a Material Adverse Effect, the Borrower has no material contingent obligations not provided for or disclosed in the financial statements referred to in Section 5.4.
5.8. Subsidiaries. Schedule 1 contains an accurate list of all Subsidiaries of the Borrower as of the date of this Agreement, setting forth their respective jurisdictions of organization and the percentage of their respective capital stock or other ownership interests owned by the Borrower or other Subsidiaries. All of the issued and outstanding shares of capital stock or other ownership interests of such Subsidiaries have been (to the extent such concepts are relevant with respect to such ownership interests) duly authorized and issued and are fully paid and non-assessable.
5.9. ERISA. The Unfunded Liabilities of all Single Employer Plans could not in the aggregate reasonably be expected to have a Material Adverse Effect. Neither the Borrower nor any other member of the Controlled Group has incurred, or is reasonably expected to incur, pursuant to Section 4201 of ERISA, any withdrawal liability to Multiemployer Plans in excess of $20,000,000 in the aggregate that has not been satisfied. Each Plan complies in all material respects with all applicable requirements of law and regulations, except for noncompliance that, in the aggregate, would not have a Material Adverse Effect. No Reportable Event has occurred with respect to any Plan, other than those that, in aggregate, would not have a Material Adverse Effect. Neither the Borrower nor any other member of the Controlled Group has withdrawn from any Multiemployer Plan within the meaning of Title IV of ERISA or initiated steps to do so, and, to the knowledge of the Borrower, no steps have been taken to reorganize or terminate, within the meaning of Title IV of ERISA, any Multiemployer Plan.
5.10. Accuracy of Information. The information, exhibits or reports furnished by the Borrower to the Agent or to any Lender in connection with the negotiation of, or compliance with, the Loan Documents, taken as a whole, do not contain any material misstatement of fact or omit to state a material fact or any fact necessary to make the statements contained therein not misleading.
5.11. Regulation U. Neither the Borrower nor any of its Subsidiaries is engaged principally, or as one of its important activities, in the business of extending credit for the purpose, whether immediate, incidental or ultimate of buying or carrying margin stock (as defined in Regulation U), and after applying the proceeds of each Advance, margin stock (as so defined) constitutes less than 25% of the value of those assets of the Borrower and its Subsidiaries which are subject to any limitation on sale, pledge, or other restriction hereunder.
5.12. Material Agreements. Neither the Borrower nor any Subsidiary is a party to any agreement or instrument or subject to any charter or other corporate restriction which could
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reasonably be expected to have a Material Adverse Effect. Neither the Borrower nor any Subsidiary is in default in the performance, observance or fulfillment of any of the obligations, covenants or conditions contained in (i) any agreement to which it is a party, which default could reasonably be expected to have a Material Adverse Effect or (ii) any Material Indebtedness Agreement.
5.13. Compliance With Laws. The Borrower and its Subsidiaries have complied with all applicable statutes, rules, regulations, orders and restrictions of any domestic or foreign government or any instrumentality or agency thereof having jurisdiction over the conduct of their respective businesses or the ownership of their respective Property except for any failure to comply with any of the foregoing which could not reasonably be expected to have a Material Adverse Effect.
5.14. Ownership of Properties. Except (i) for assets disposed of in the ordinary course of business since March 31, 2002, (ii) as described in SEC Reports and (iii) as set forth on Schedule 2, on the date of this Agreement, the Borrower and its Subsidiaries have good title, free of all Liens other than those permitted by Section 6.12, to all of the assets reflected in the Borrower's consolidated balance sheet as of March 31, 2002, as owned by the Borrower and its Subsidiaries.
5.15. Plan Assets; Prohibited Transactions. The Borrower is not an entity deemed to hold "plan assets" within the meaning of 29 C.F.R.ss.2510.3-101 of an employee benefit plan (as defined in Section 3(3) of ERISA) which is subject to Title I of ERISA or any plan (within the meaning of Section 4975 of the Code), and assuming the accuracy of the representations and warranties made in Section 9.12 and in any assignment made pursuant to Section 12.3.3, neither the execution of this Agreement nor the making of Loans hereunder gives rise to a prohibited transaction within the meaning of Section 406 of ERISA or Section 4975 of the Code.
5.16. Environmental Matters. In the ordinary course of its business, the officers of the Borrower consider the effect of Environmental Laws on the business of the Borrower and its Subsidiaries, in the course of which they identify and evaluate potential risks and liabilities accruing to the Borrower due to Environmental Laws. On the basis of this consideration, the Borrower has concluded that, except as disclosed in the SEC Reports, Environmental Laws cannot reasonably be expected to have a Material Adverse Effect. Except as disclosed in the SEC Reports, neither the Borrower nor any Subsidiary has received any notice to the effect that its operations are not in material compliance with any of the requirements of applicable Environmental Laws or are the subject of any federal or state investigation evaluating whether any remedial action is needed to respond to a release of any toxic or hazardous waste or substance into the environment, which non-compliance or remedial action could reasonably be expected to have a Material Adverse Effect.
5.17. Investment Company Act. Neither the Borrower nor any Subsidiary is an "investment company" or a company "controlled" by an "investment company", within the meaning of the Investment Company Act of 1940, as amended.
5.18. Public Utility Holding Company Act.The Borrower is a "public utility company" and a "subsidiary company" of the Parent, which is a "holding company", as such terms are
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defined in the Public Utility Holding Company Act of 1935, as amended (the "1935 Act"), and such "holding company" and the Borrower are currently exempt from the provisions of the 1935 Act (except Section 9 thereof).
5.19. Insurance. The Borrower maintains, and has caused each Subsidiary to maintain, with financially sound and reputable insurance companies insurance on all their Property in such amounts, subject to such deductibles and self-insurance retentions and covering such risks as is consistent with sound business practice of similarly situated companies.
5.20. No Default or Unmatured Default. No Default or Unmatured Default has occurred and is continuing.
COVENANTS
During the term of this Agreement, unless the Required Lenders shall otherwise consent in writing:
6.1. Financial Reporting. The Borrower will maintain, for itself and each Subsidiary, a system of accounting established and administered in accordance with generally accepted accounting principles, and furnish to the Lenders:
| Within 90 days after the close of each of its fiscal years, financial statements prepared in accordance GAAP on a consolidated and consolidating basis for itself and its Subsidiaries, including balance sheets as of the end of such period, statements of income and statements of cash flows, accompanied by (a) an audit report, unqualified as to scope, of a nationally recognized firm of independent public accountants or other independent public accountants reasonably acceptable to the Required Lenders; (b) any management letter prepared by said accountants, and (c) a certificate of said accountants that, in the course of their examination necessary for their certification of the foregoing, they have obtained no knowledge of any Default or Unmatured Default, or if, in the opinion of such accountants, any Default or Unmatured Default shall exist, stating the nature and status thereof. |
| Within 45 days after the close of the first three quarterly periods of each of its fiscal years, for itself and its Subsidiaries, consolidated and consolidating unaudited balance sheets as at the close of each such period and consolidated and consolidating statements of income and a statement of cash flows for the period from the beginning of such fiscal year to the end of such quarter, all certified by its chief financial officer or treasurer. |
| Together with the financial statements required under Sections 6.1(i) and (ii), a compliance certificate in substantially the form of Exhibit B signed by its chief financial officer or treasurer showing the calculations necessary to determine compliance with this |
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| Agreement and stating that no Default or Unmatured Default exists, or if any Default or Unmatured Default exists, stating the nature and status thereof. |
| Within 270 days after the close of each fiscal year of the Borrower, a copy of the actuarial report showing the Unfunded Liabilities of each Single Employer Plan as of the valuation date occurring in such fiscal year, certified by an actuary enrolled under ERISA. |
| As soon as possible and in any event within 10 days after the Borrower knows that any Reportable Event has occurred with respect to any Plan that could reasonably be expected to have a Material Adverse Effect, a statement, signed by the chief financial officer of the Borrower, describing said Reportable Event and the action which the Borrower proposes to take with respect thereto. |
| As soon as possible and in any event within 10 days after receipt by the Borrower, a copy of (a) any notice or claim to the effect that the Borrower or any of its Subsidiaries is or may be liable to any Person as a result of the release by the Borrower, any of its Subsidiaries, or any other Person of any toxic or hazardous waste or substance into the environment, and (b) any notice alleging any violation of any federal, state or local environmental, health or safety law or regulation by the Borrower or any of its Subsidiaries, which, in either case, could reasonably be expected to have a Material Adverse Effect. |
| Promptly upon the filing thereof, copies of all registration statements and annual, quarterly, monthly or other regular reports which the Borrower or any of its Subsidiaries files with the Securities and Exchange Commission. |
| Such other information (including non-financial information) as the Agent or any Lender may from time to time reasonably request. |
6.2. Use of Proceeds. The Borrower will, and will cause each Subsidiary to, use the proceeds of the Advances for general corporate purposes, including without limitation commercial paper liquidity support. The Borrower shall use the proceeds of the Advances in compliance with all applicable legal and regulatory requirements and any such use shall not result in a violation of any such requirements, including, without limitation, Regulation U and X, the Securities Act of 1933, as amended, and the Securities Exchange Act of 1934, as amended, and the regulations promulgated thereunder.
6.3. Notice of Default. The Borrower will, and will cause each Subsidiary to, give prompt notice in writing to the Lenders of the occurrence of any Default or Unmatured Default and of any other development, financial or otherwise, which could reasonably be expected to have a Material Adverse Effect.
6.4. Conduct of Business. The Borrower will, and will cause each Subsidiary to, be primarily engaged in energy-related businesses and/or other businesses as are ancillary thereto.
6.5. Taxes. The Borrower will, and will cause each Subsidiary to, timely file complete and correct United States federal and applicable foreign, state and local tax returns required by
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law and pay when due all taxes, assessments and governmental charges and levies upon it or its income, profits or Property, except those which are not in the aggregate material or which are being contested in good faith by appropriate proceedings and with respect to which adequate reserves have been set aside in accordance with GAAP.
6.6. Insurance. The Borrower will, and will cause each Subsidiary to, maintain with financially sound and reputable insurance companies insurance on all their Property in such amounts, subject to such deductibles and self-insurance retentions, and covering such risks as is consistent with sound business practice, and the Borrower will furnish to any Lender upon request full information as to the insurance carried.
6.7. Compliance with Laws. The Borrower will, and will cause each Subsidiary to, comply with all laws, rules, regulations, orders, writs, judgments, injunctions, decrees or awards to which it may be subject including, without limitation, all Environmental Laws, except where failure to so comply could not reasonably be expected to result in a Material Adverse Effect.
6.8. Maintenance of Properties. Subject to Section 6.11, the Borrower will, and will cause each Subsidiary to, do all things necessary to maintain, preserve, protect and keep its Property used in the operation of its business in good repair, working order and condition, and make all necessary and proper repairs, renewals and replacements so that its business carried on in connection therewith may be properly conducted at all times.
6.9. Inspection; Keeping of Books and Records. The Borrower will, and will cause each Subsidiary to, permit the Agent and the Lenders, by their respective representatives and agents, to inspect any of the Property, books and financial records of the Borrower and each Subsidiary, to examine and make copies of the books of accounts and other financial records of the Borrower and each Subsidiary, and to discuss the affairs, finances and accounts of the Borrower and each Subsidiary with, and to be advised as to the same by, their respective officers at such reasonable times and intervals as the Agent or any Lender may designate. The Borrower shall keep and maintain, and cause each of its Subsidiaries to keep and maintain, in all material respects, proper books of record and account in which entries in conformity with GAAP shall be made of all dealings and transactions in relation to their respective businesses and activities. If a Default has occurred and is continuing, the Borrower, upon the Agent's request, shall turn over copies of any such records to the Agent or its representatives.
6.10. Merger. The Borrower will not, nor will it permit any Subsidiary to, merge or consolidate with or into any other Person, except that a Subsidiary may merge into the Borrower or a Wholly-Owned Subsidiary.
6.11. Sale of Assets. The Borrower will not, nor will it permit any Subsidiary to, lease, sell or otherwise dispose of its Property to any other Person, except:
| Sales of inventory in the ordinary course of business. |
| A disposition of assets by a Subsidiary to the Borrower or another Subsidiary or by the Borrower to a Subsidiary. |
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| A disposition of obsolete property, property no longer used in business or other assets in the ordinary course of business of the Borrower or any Subsidiary. |
| A disposition of assets for an aggregate purchase price of up to $50,000,000 pursuant to, and in accordance with, Receivables Purchase Facilities. |
| Leases, sales or other dispositions of its Property that, together with all other Property of the Borrower and its Subsidiaries previously leased, sold or disposed of (other than dispositions otherwise permitted by this Section 6.11) as permitted by this Section during the twelve-month period ending with the month in which any such lease, sale or other disposition occurs, do not constitute a Substantial Portion of the Property of the Borrower and its Subsidiaries. |
6.12. Liens. The Borrower will not, nor will it permit any Subsidiary to, create, incur, or suffer to exist any Lien in, of or on the Property of the Borrower or any of its Subsidiaries, except:
| Liens for taxes, assessments or governmental charges or levies on its Property if the same shall not at the time be delinquent or thereafter can be paid without penalty, or are being contested in good faith and by appropriate proceedings and for which adequate reserves in accordance with GAAP shall have been set aside on its books. |
| Liens imposed by law, such as carriers’, warehousemen’s and mechanics’ liens and other similar liens arising in the ordinary course of business which secure payment of obligations not more than 60 days past due or which are being contested in good faith by appropriate proceedings and for which adequate reserves in accordance with GAAP shall have been set aside on its books. |
| Liens arising out of pledges or deposits under worker’s compensation laws, unemployment insurance, old age pensions, or other social security or retirement benefits, or similar legislation. |
| Liens existing on the date hereof and described in Schedule 3. |
| Deposits securing liability to insurance carriers under insurance or self-insurance arrangements. |
| Deposits to secure the performance of bids, trade contracts (other than for borrowed money), leases, statutory obligations, surety and appeal bonds, performance bonds and other obligations of a like nature incurred in the ordinary course of business. |
| Easements, reservations, rights-of-way, restrictions, survey exceptions and other similar encumbrances as to real property of the Borrower and its Subsidiaries which customarily exist on properties of corporations engaged in similar activities and similarly situated and which do not materially interfere with the conduct of the business of the Borrower or such Subsidiary conducted at the property subject thereto. |
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| Liens existing on property or assets at the time of acquisition thereof by the Borrower or a Subsidiary, provided that (i) such Liens existed at the time of such acquisition and were not created in anticipation thereof, and (ii) any such Lien does not encumber any other property or assets (other than additions thereto and property in replacement or substitution thereof). |
| Liens existing on property or assets of a Person which becomes a Subsidiary of the Borrower; provided that (i) such Liens existed at the time such Person became a Subsidiary and were not created in anticipation thereof, and (ii) any such Lien does not encumber any other property or assets (other than additions thereto and property in replacement or substitution thereof). |
| Liens arising by reason of any judgment, decree or order of any court or other governmental authority, if appropriate legal proceedings are being diligently prosecuted and shall not have been finally terminated or the period within which such proceedings may be initiated shall not have expired, in an aggregate amount not to exceed $20,000,000 at any time outstanding. |
| Leases and subleases of real property owned or leased by the Borrower or any Subsidiary not interfering with the ordinary conduct of the business of the Borrower and the Subsidiaries. |
| Liens securing Indebtedness (including Capitalized Lease Obligations) of the Borrower and its Subsidiaries incurred to finance the acquisition, repair, construction, development or improvement of fixed or capital assets; provided that (i) such Liens shall be created substantially simultaneously with or within 18 months of the acquisition or completion of repair, construction, development or improvement of such fixed or capital assets and (ii) such Liens do not encumber any property other than the property financed by such Indebtedness (other than additions thereto and property in replacement or substitution thereof). |
| Liens in favor of the United States of America or any state thereof, or any department, agency or instrumentality or political subdivision of the United States of America or any state thereof, or for the benefit of holders of securities issued by any such entity, to secure any Indebtedness incurred for the purpose of financing all or any part of the purchase price of the cost of the repair, construction, development or improvement of any fixed or capital assets; provided that such Liens do not encumber any property other than the property financed by such Indebtedness (other than additions thereto and property in replacement or substitution thereof). |
| Liens securing Indebtedness of the Borrower to a Subsidiary or of a Subsidiary to the Borrower or another Subsidiary. |
| Liens arising in connection with a Receivables Purchase Facility. |
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| Renewals, extensions and replacements of the Liens permitted under Sections 6.12.4, 6.12.8, 6.12.9, 6.12.12 and 6.12.13 above; provided that no such Lien shall as a result thereof cover any additional assets (other than additions thereto and property in replacement or substitution thereof). |
| Liens not described in Sections 6.12.1 through 6.12.16, inclusive, securing Indebtedness of the Borrower (other than Indebtedness of the Borrower owed to any Subsidiary) and/or securing Indebtedness of the Borrower’s Subsidiaries (other than Indebtedness of any Subsidiary owed to the Borrower or any other Subsidiary), in an aggregate outstanding amount not to exceed ten percent (10%) of the consolidated assets of the Borrower and its Subsidiaries at the time of such incurrence. |
6.13. Affiliates. The Borrower will not, and will not permit any Subsidiary to, enter into any transaction (including, without limitation, the purchase or sale of any Property or service) with, or make any payment or transfer to, any Affiliate (other than the Borrower and its Subsidiaries) except in the ordinary course of business and pursuant to the reasonable requirements of the Borrower's or such Subsidiary's business and upon fair and reasonable terms no less favorable to the Borrower or such Subsidiary than the Borrower or such Subsidiary would obtain in a comparable arms-length transaction.
6.14. Financial Contracts. The Borrower will not, nor will it permit any Subsidiary to, enter into or remain liable upon any Rate Management Transactions except for those entered into in the ordinary course of business for bona fide hedging purposes and not for speculative purposes.
6.15. Leverage Ratio. The Borrower will not permit the ratio, determined as of the end of each of its fiscal quarters, of (i) Consolidated Indebtedness to (ii) Consolidated Total Capitalization to be greater than 0.65 to 1.0.
6.16. FERC Approval. From time to time prior to the expiration of the approval of FERC with respect to the short-term debt of the Borrower, the Borrower will obtain an extension of such approval and the Borrower shall provide a notice to the Agent of the receipt of such extension, including the expiration date of the most recent approval and the total amount of short-term debt of the Borrower authorized therein. The Borrower further agrees not to request Advances, or have outstanding Loans, hereunder in violation of the FERC approval mentioned above.
DEFAULTS
The occurrence of any one or more of the following events shall constitute a Default:
7.1. Any representation or warranty made or deemed made by or on behalf of the Borrower or any of its Subsidiaries to the Lenders or the Agent under or in connection with this
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Agreement, any Loan, or any certificate or information delivered in connection with this Agreement or any other Loan Document shall be materially false on the date as of which made.
7.2. Nonpayment of principal of any Loan when due, or nonpayment of interest upon any Loan or of any fee or other obligations under any of the Loan Documents within five days after the same becomes due.
7.3. The breach by the Borrower of any of the terms or provisions of Section 6.2, 6.10, 6.11, 6.12, 6.13, 6.14, 6.15 or 6.16.
7.4. The breach by the Borrower (other than a breach which constitutes a Default under another Section of this Article VII) of any of the terms or provisions of this Agreement which is not remedied within five days after written notice from the Agent or any Lender.
7.5. Failure of the Borrower or any of its Subsidiaries to pay when due any Material Indebtedness; or the default by the Borrower or any of its Subsidiaries in the performance (beyond the applicable grace period with respect thereto, if any) of any term, provision or condition contained in any Material Indebtedness Agreement, or any other event shall occur or condition exist, the effect of which default, event or condition is to cause, or to permit the holder(s) of such Material Indebtedness or the lender(s) under any Material Indebtedness Agreement to cause, such Material Indebtedness to become due prior to its stated maturity or any commitment to lend under any Material Indebtedness Agreement to be terminated prior to its stated expiration date; or any Material Indebtedness of the Borrower or any of its Subsidiaries shall be declared to be due and payable or required to be prepaid or repurchased (other than by a regularly scheduled payment) prior to the stated maturity thereof; or the Borrower or any of its Subsidiaries shall not pay, or admit in writing its inability to pay, its debts generally as they become due.
7.6. The Borrower or any of its Material Subsidiaries shall (i) have an order for relief entered with respect to it under the Federal bankruptcy laws as now or hereafter in effect, (ii) make an assignment for the benefit of creditors, (iii) apply for, seek, consent to, or acquiesce in, the appointment of a receiver, custodian, trustee, examiner, liquidator or similar official for it or any Substantial Portion of its Property, (iv) institute any proceeding seeking an order for relief under the Federal bankruptcy laws as now or hereafter in effect or seeking to adjudicate it a bankrupt or insolvent, or seeking dissolution, winding up, liquidation, reorganization, arrangement, adjustment or composition of it or its debts under any law relating to bankruptcy, insolvency or reorganization or relief of debtors or fail to file an answer or other pleading denying the material allegations of any such proceeding filed against it, (v) take any corporate or partnership action to authorize or effect any of the foregoing actions set forth in this Section 7.6 or (vi) fail to contest in good faith any appointment or proceeding described in Section 7.7.
7.7. Without the application, approval or consent of the Borrower or any of its Material Subsidiaries, a receiver, trustee, examiner, liquidator or similar official shall be appointed for the Borrower or any of its Material Subsidiaries or any Substantial Portion of its Property, or a proceeding described in Section 7.6(iv) shall be instituted against the Borrower or
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any of its Material Subsidiaries and such appointment continues undischarged or such proceeding continues undismissed or unstayed for a period of 60 consecutive days.
7.8. Any court, government or governmental agency shall condemn, seize or otherwise appropriate, or take custody or control of, all or any portion of the Property of the Borrower and its Subsidiaries which, when taken together with all other Property of the Borrower and its Subsidiaries so condemned, seized, appropriated, or taken custody or control of, during the twelve-month period ending with the month in which any such action occurs, constitutes a Substantial Portion.
7.9. The Borrower or any of its Subsidiaries shall fail within 45 days to pay, bond or otherwise discharge one or more (i) judgments or orders for the payment of money in excess of $20,000,000 (or the equivalent thereof in currencies other than U.S. Dollars) in the aggregate, or (ii) nonmonetary judgments or orders which, individually or in the aggregate, could reasonably be expected to have a Material Adverse Effect, which judgment(s), in any such case, is/are not stayed on appeal or otherwise being appropriately contested in good faith and with respect to which adequate reserves have been set aside on its books in accordance with GAAP.
7.10. The Unfunded Liabilities of all Single Employer Plans could in the aggregate reasonably be expected to result in a Material Adverse Effect or any Reportable Event shall occur in connection with any Plan that could reasonably be expected to have a Material Adverse Effect.
7.11. Nonpayment by the Borrower or any Subsidiary of any Rate Management Obligation, in an outstanding principal amount of $20,000,000 or more, when due or the breach by the Borrower or any Subsidiary of any term, provision or condition contained in any Rate Management Transaction or any transaction of the type described in the definition of “Rate Management Transactions,” whether or not any Lender or Affiliate of a Lender is a party thereto.
7.12. Any Change in Control shall occur.
7.13. The Borrower or any other member of the Controlled Group shall have been notified by the sponsor of a Multiemployer Plan that it has incurred, pursuant to Section 4201 of ERISA, withdrawal liability to such Multiemployer Plan in an amount which, when aggregated with all other amounts required to be paid to Multiemployer Plans by the Borrower or any other member of the Controlled Group as withdrawal liability (determined as of the date of such notification), exceeds $20,000,000 or requires payments exceeding $5,000,000 per annum.
7.14. The Borrower or any other member of the Controlled Group shall have been notified by the sponsor of a Multiemployer Plan that such Multiemployer Plan is in reorganization or is being terminated, within the meaning of Title IV of ERISA, if as a result of such reorganization or termination the aggregate annual contributions of the Borrower and the other members of the Controlled Group (taken as a whole) to all Multiemployer Plans which are then in reorganization or being terminated have been or will be increased, in the aggregate, over the amounts contributed to such Multiemployer Plans for the respective plan years of such Multiemployer Plans immediately preceding the plan year in which the reorganization or termination occurs by an amount exceeding $20,000,000.
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7.15. The Borrower or any of its Subsidiaries shall (i) be the subject of any proceeding or investigation pertaining to the release by the Borrower, any of its Subsidiaries or any other Person of any toxic or hazardous waste or substance into the environment, or (ii) violate any Environmental Law, which, in the case of an event described in clause (i) or clause (ii), has resulted in a judgment or order of liability against the Borrower or any of its Subsidiaries in an amount in excess of $20,000,000, which liability is not paid, bonded or otherwise discharged within 45 days or which is not stayed on appeal and being appropriately contested in good faith.
7.16. Any Loan Document shall fail to remain in full force or effect or any action shall be taken to discontinue or to assert the invalidity or unenforceability of any Loan Document.
ACCELERATION, WAIVERS, AMENDMENTS AND REMEDIES
7.1. Acceleration. If any Default described in Section 7.6 or 7.7 occurs with respect to the Borrower, the obligations of the Lenders to make Loans hereunder shall automatically terminate and the Obligations shall immediately become due and payable without any election or action on the part of the Agent or any Lender. If any other Default occurs, the Required Lenders (or the Agent with the consent of the Required Lenders) may terminate or suspend the obligations of the Lenders to make Loans hereunder, or declare the Obligations to be due and payable, or both, whereupon the Obligations shall become immediately due and payable, without presentment, demand, protest or notice of any kind, all of which the Borrower hereby expressly waives.
If, after acceleration of the maturity of the Obligations or termination of the obligations of the Lenders to make Loans hereunder as a result of any Default (other than any Default as described in Section 7.6 or 7.7 with respect to the Borrower) and before any judgment or decree for the payment of the Obligations due shall have been obtained or entered, the Required Lenders (in their sole discretion) shall so direct, the Agent shall, by notice to the Borrower, rescind and annul such acceleration and/or termination.
7.2. Amendments. Subject to the provisions of this Section 8.2, the Required Lenders (or the Agent with the consent in writing of the Required Lenders) and the Borrower may enter into agreements supplemental hereto for the purpose of adding or modifying any provisions to the Loan Documents or changing in any manner the rights of the Lenders or the Borrower hereunder or waiving any Default hereunder; provided, however, that no such supplemental agreement shall, without the consent of all of the Lenders:
| Extend the final maturity of any Loan or postpone any regularly scheduled payment of principal of any Loan or forgive all or any portion of the principal amount thereof, or reduce the rate or extend the time of payment of interest or fees thereon (other than a waiver of the application of the default rate of interest pursuant to Section 2.11 hereof). |
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| Reduce the percentage specified in the definition of Required Lenders or any other percentage of Lenders specified to be the applicable percentage in this Agreement to act on specified matters or amend the definition of “Pro Rata Share”. |
| Extend the Facility Termination Date, or reduce the amount or extend the payment date for, the mandatory payments required under Section 2.2, or increase the amount of the Commitment of any Lender hereunder, or permit the Borrower to assign its rights or obligations under this Agreement. |
| Amend this Section 8.2. |
No amendment of any provision of this Agreement relating to the Agent shall be effective without the written consent of the Agent. The Agent may waive payment of the fee required under Section 12.3.2 without obtaining the consent of any other party to this Agreement.
7.3. Preservation of Rights. No delay or omission of the Lenders or the Agent to exercise any right under the Loan Documents shall impair such right or be construed to be a waiver of any Default or an acquiescence therein, and the making of a Loan notwithstanding the existence of a Default or the inability of the Borrower to satisfy the conditions precedent to such Loan shall not constitute any waiver or acquiescence. Any single or partial exercise of any such right shall not preclude other or further exercise thereof or the exercise of any other right, and no waiver, amendment or other variation of the terms, conditions or provisions of the Loan Documents whatsoever shall be valid unless in writing signed by the Lenders required pursuant to Section 8.2, and then only to the extent in such writing specifically set forth. All remedies contained in the Loan Documents or by law afforded shall be cumulative and all shall be available to the Agent and the Lenders until the Obligations have been paid in full.
GENERAL PROVISIONS
8.1. Survival of Representations. All representations and warranties of the Borrower contained in this Agreement shall survive the making of the Loans herein contemplated.
8.2. Governmental Regulation. Anything contained in this Agreement to the contrary notwithstanding, no Lender shall be obligated to extend credit to the Borrower in violation of any limitation or prohibition provided by any applicable statute or regulation.
8.3. Headings. Section headings in the Loan Documents are for convenience of reference only, and shall not govern the interpretation of any of the provisions of the Loan Documents.
8.4. Entire Agreement. The Loan Documents embody the entire agreement and understanding among the Borrower, the Agent and the Lenders and supersede all prior agreements and understandings among the Borrower, the Agent and the Lenders relating to the subject matter thereof other than those contained in the fee letter described in Section 10.13 which shall survive and remain in full force and effect during the term of this Agreement.
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8.5. Several Obligations; Benefits of this Agreement. The respective obligations of the Lenders hereunder are several and not joint and no Lender shall be the partner or agent of any other (except to the extent to which the Agent is authorized to act as such). The failure of any Lender to perform any of its obligations hereunder shall not relieve any other Lender from any of its obligations hereunder. This Agreement shall not be construed so as to confer any right or benefit upon any Person other than the parties to this Agreement and their respective successors and assigns, provided, however, that the parties hereto expressly agree that the Arranger shall enjoy the benefits of the provisions of Sections 9.6, 9.10 and 10.11 to the extent specifically set forth therein and shall have the right to enforce such provisions on its own behalf and in its own name to the same extent as if it were a party to this Agreement.
8.6. Expenses; Indemnification. 99.02.1.3 The Borrower shall reimburse the Agent and the Arranger for any costs, internal charges and out-of-pocket expenses (including attorneys' and paralegals' fees and time charges of attorneys for the Agent, which attorneys may be employees of the Agent and expenses of and fees for other advisors and professionals engaged by the Agent or the Arranger) paid or incurred by the Agent or the Arranger in connection with the investigation, preparation, negotiation, documentation, execution, delivery, syndication, distribution (including, without limitation, via the internet), review, amendment, modification and administration of the Loan Documents. The Borrower also agrees to reimburse the Agent, the Syndication Agent, the Arranger and the Lenders for any costs, internal charges and out-of-pocket expenses (including attorneys' and paralegals' fees and time charges and expenses of attorneys and paralegals for the Agent, the Syndication Agent, the Arranger and the Lenders, which attorneys and paralegals may be employees of the Agent, the Syndication Agent, the Arranger or the Lenders) paid or incurred by the Agent, the Syndication Agent, the Arranger or any Lender in connection with the collection and enforcement of the Loan Documents.
The Borrower hereby further agrees to indemnify the Agent, the Syndication
Agent, the Arranger, each Lender, their respective affiliates, and
each of their directors, officers and employees against all losses,
claims, damages, penalties, judgments, liabilities and expenses
(including, without limitation, all expenses of litigation or
preparation therefor whether or not the Agent, the Syndication Agent,
the Arranger, any Lender or any affiliate is a party thereto, and all
attorneys’ and paralegals’ fees, time charges and expenses
of attorneys and paralegals of the party seeking indemnification,
which attorneys and paralegals may or may not be employees of such
party seeking indemnification) which any of them may pay or incur
arising out of or relating to this Agreement, the other Loan
Documents, the transactions contemplated hereby or the direct or
indirect application or proposed application of the proceeds of any
Loan hereunder except to the extent that they have resulted from the
gross negligence or willful misconduct of the party seeking
indemnification. The obligations of the Borrower under this Section
9.6 shall survive the termination of this Agreement.
8.7. Numbers of Documents. All statements, notices, closing documents, and requests hereunder shall be furnished to the Agent with sufficient counterparts so that the Agent may furnish one to each of the Lenders, to the extent that the Agent deems necessary.
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8.8. Accounting. Except as provided to the contrary herein, all accounting terms used in the calculation of any financial covenant or test shall be interpreted and all accounting determinations hereunder in the calculation of any financial covenant or test shall be made in accordance with Agreement Accounting Principles. If any changes in generally accepted accounting principles are hereafter required or permitted and are adopted by the Borrower or any of its Subsidiaries with the agreement of its independent certified public accountants and such changes result in a change in the method of calculation of any of the financial covenants, tests, restrictions or standards herein or in the related definitions or terms used therein ("Accounting Changes"), the parties hereto agree, at the Borrower's request, to enter into negotiations, in good faith, in order to amend such provisions in a credit neutral manner so as to reflect equitably such changes with the desired result that the criteria for evaluating the Borrower's and its Subsidiaries' financial condition shall be the same after such changes as if such changes had not been made; provided, however, until such provisions are amended in a manner reasonably satisfactory to the Agent and the Required Lenders, no Accounting Change shall be given effect in such calculations. In the event such amendment is entered into, all references in this Agreement to Agreement Accounting Principles shall mean generally accepted accounting principles as of the date of such amendment. Notwithstanding the foregoing, all financial statements to be delivered by the Borrower pursuant to Section 6.1 shall be prepared in accordance with generally accepted accounting principles in effect at such time.
8.9. Severability of Provisions. Any provision in any Loan Document that is held to be inoperative, unenforceable, or invalid in any jurisdiction shall, as to that jurisdiction, be inoperative, unenforceable, or invalid without affecting the remaining provisions in that jurisdiction or the operation, enforceability, or validity of that provision in any other jurisdiction, and to this end the provisions of all Loan Documents are declared to be severable.
8.10. Nonliability of Lenders. The relationship between the Borrower on the one hand and the Lenders and the Agent on the other hand shall be solely that of borrower and lender. Neither the Agent, the Arranger nor any Lender shall have any fiduciary responsibilities to the Borrower. Neither the Agent, the Arranger nor any Lender undertakes any responsibility to the Borrower to review or inform the Borrower of any matter in connection with any phase of the Borrower's business or operations. The Borrower agrees that neither the Agent, the Arranger nor any Lender shall have liability to the Borrower (whether sounding in tort, contract or otherwise) for losses suffered by the Borrower in connection with, arising out of, or in any way related to, the transactions contemplated and the relationship established by the Loan Documents, or any act, omission or event occurring in connection therewith, unless it is determined in a final non-appealable judgment by a court of competent jurisdiction that such losses resulted from the gross negligence or willful misconduct of the party from which recovery is sought. Neither the Agent, the Arranger nor any Lender shall have any liability with respect to, and the Borrower hereby waives, releases and agrees not to sue for, any special, indirect, consequential or punitive damages suffered by the Borrower in connection with, arising out of, or in any way related to the Loan Documents or the transactions contemplated thereby.
8.11. Confidentiality. Each Lender agrees to hold any confidential information which it may receive from the Borrower pursuant to this Agreement in confidence, except for disclosure (i) to its Affiliates and to other Lenders and their respective Affiliates, for use solely in
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connection with the transactions contemplated hereby, (ii) to legal counsel, accountants, and other professional advisors to such Lender or to a Transferee, in each case which have been informed as to the confidential nature of such information, (iii) to regulatory officials having jurisdiction over it, (iv) to any Person as required by law, regulation, or legal process, (v) to any Person in connection with any legal proceeding to which such Lender is a party, (vi) to such Lender's direct or indirect contractual counterparties in swap agreements or to legal counsel, accountants and other professional advisors to such counterparties, in each case which have been informed as to the confidential nature of such information, (vii) permitted by Section 12.4 and (viii) to rating agencies if requested or required by such agencies in connection with a rating relating to the Advances hereunder.
8.12. Lenders Not Utilizing Plan Assets. Each Lender and Designated Lender represents and warrants that none of the consideration used by such Lender or Designated Lender to make its Loans constitutes for any purpose of ERISA or Section 4975 of the Code assets of any "plan" as defined in Section 3(3) of ERISA or Section 4975 of the Code and the rights and interests of such Lender or Designated Lender in and under the Loan Documents shall not constitute such "plan assets" under ERISA.
8.13. Nonreliance. Each Lender hereby represents that it is not relying on or looking to any margin stock (as defined in Regulation U of the Board of Governors of the Federal Reserve System) for the repayment of the Loans provided for herein.
8.14. Disclosure. The Borrower and each Lender hereby acknowledge and agree that Bank One and/or its Affiliates from time to time may hold investments in, make other loans to or have other relationships with the Borrower and its Affiliates.
THE AGENT
9.1. Appointment; Nature of Relationship. Bank One, NA is hereby appointed by each of the Lenders as its contractual representative (herein referred to as the "Agent") hereunder and under each other Loan Document, and each of the Lenders irrevocably authorizes the Agent to act as the contractual representative of such Lender with the rights and duties expressly set forth herein and in the other Loan Documents. The Agent agrees to act as such contractual representative upon the express conditions contained in this Article X. Notwithstanding the use of the defined term "Agent," it is expressly understood and agreed that the Agent shall not have any fiduciary responsibilities to any Lender by reason of this Agreement or any other Loan Document and that the Agent is merely acting as the contractual representative of the Lenders with only those duties as are expressly set forth in this Agreement and the other Loan Documents. In its capacity as the Lenders' contractual representative, the Agent (i) does not hereby assume any fiduciary duties to any of the Lenders, (ii) is a "representative" of the Lenders within the meaning of the term "secured party" as defined in the Illinois Uniform Commercial Code and (iii) is acting as an independent contractor, the rights and duties of which are limited to those expressly set forth in this Agreement and the other Loan Documents. Each of the Lenders
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hereby agrees to assert no claim against the Agent on any agency theory or any other theory of liability for breach of fiduciary duty, all of which claims each Lender hereby waives.
9.2. Powers. The Agent shall have and may exercise such powers under the Loan Documents as are specifically delegated to the Agent by the terms of each thereof, together with such powers as are reasonably incidental thereto. The Agent shall have no implied duties to the Lenders, or any obligation to the Lenders to take any action thereunder except any action specifically provided by the Loan Documents to be taken by the Agent.
9.3. General Immunity. Neither the Agent nor any of its directors, officers, agents or employees shall be liable to the Borrower, the Lenders or any Lender for any action taken or omitted to be taken by it or them hereunder or under any other Loan Document or in connection herewith or therewith except to the extent such action or inaction is determined in a final non-appealable judgment by a court of competent jurisdiction to have arisen from the gross negligence or willful misconduct of such Person.
9.4. No Responsibility for Loans, Recitals, etc. Neither the Agent nor any of its directors, officers, agents or employees shall be responsible for or have any duty to ascertain, inquire into, or verify (a) any statement, warranty or representation made in connection with any Loan Document or any borrowing hereunder; (b) the performance or observance of any of the covenants or agreements of any obligor under any Loan Document, including, without limitation, any agreement by an obligor to furnish information directly to each Lender; (c) the satisfaction of any condition specified in Article IV, except receipt of items required to be delivered solely to the Agent; (d) the existence or possible existence of any Default or Unmatured Default; (e) the validity, enforceability, effectiveness, sufficiency or genuineness of any Loan Document or any other instrument or writing furnished in connection therewith; (f) the value, sufficiency, creation, perfection or priority of any Lien in any collateral security; or (g) the financial condition of the Borrower or any guarantor of any of the Obligations or of any of the Borrower's or any such guarantor's respective Subsidiaries. The Agent shall have no duty to disclose to the Lenders information that is not required to be furnished by the Borrower to the Agent at such time, but is voluntarily furnished by the Borrower to the Agent (either in its capacity as Agent or in its individual capacity).
9.5. Action on Instructions of Lenders. The Agent shall in all cases be fully protected in acting, or in refraining from acting, hereunder and under any other Loan Document in accordance with written instructions signed by the Required Lenders, and such instructions and any action taken or failure to act pursuant thereto shall be binding on all of the Lenders. The Lenders hereby acknowledge that the Agent shall be under no duty to take any discretionary action permitted to be taken by it pursuant to the provisions of this Agreement or any other Loan Document unless it shall be requested in writing to do so by the Required Lenders. The Agent shall be fully justified in failing or refusing to take any action hereunder and under any other Loan Document unless it shall first be indemnified to its satisfaction by the Lenders pro rata against any and all liability, cost and expense that it may incur by reason of taking or continuing to take any such action.
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9.6. Employment of Agents and Counsel. The Agent may execute any of its duties as Agent hereunder and under any other Loan Document by or through employees, agents, and attorneys-in-fact and shall not be answerable to the Lenders, except as to money or securities received by it or its authorized agents, for the default or misconduct of any such agents or attorneys-in-fact selected by it with reasonable care. The Agent shall be entitled to advice of counsel concerning the contractual arrangement between the Agent and the Lenders and all matters pertaining to the Agent's duties hereunder and under any other Loan Document.
9.7. Reliance on Documents; Counsel. The Agent shall be entitled to rely upon any Note, notice, consent, certificate, affidavit, letter, telegram, statement, paper or document believed by it to be genuine and correct and to have been signed or sent by the proper person or persons, and, in respect to legal matters, upon the opinion of counsel selected by the Agent, which counsel may be employees of the Agent.
9.8. Agent's Reimbursement and Indemnification. The Lenders agree to reimburse and indemnify the Agent and the Syndication Agent ratably in proportion to the Lenders' Pro Rata Shares of the Aggregate Commitment (or, if the Aggregate Commitment has been terminated, of the Outstanding Credit Exposure) (i) for any amounts not reimbursed by the Borrower for which the Agent or the Syndication Agent is entitled to reimbursement by the Borrower under the Loan Documents, (ii) for any other expenses incurred by the Agent or the Syndication Agent on behalf of the Lenders, in connection with the preparation, execution, delivery, administration and enforcement of the Loan Documents (including, without limitation, for any expenses incurred by the Agent or the Syndication Agent in connection with any dispute between the Agent or the Syndication Agent and any Lender or between two or more of the Lenders) and (iii) for any liabilities, obligations, losses, damages, penalties, actions, judgments, suits, costs, expenses or disbursements of any kind and nature whatsoever which may be imposed on, incurred by or asserted against the Agent or the Syndication Agent in any way relating to or arising out of the Loan Documents or any other document delivered in connection therewith or the transactions contemplated thereby (including, without limitation, for any such amounts incurred by or asserted against the Agent or the Syndication Agent in connection with any dispute between the Agent or the Syndication Agent and any Lender or between two or more of the Lenders), or the enforcement of any of the terms of the Loan Documents or of any such other documents, provided that (i) no Lender shall be liable for any of the foregoing to the extent any of the foregoing is found in a final non-appealable judgment by a court of competent jurisdiction to have resulted from the gross negligence or willful misconduct of the party seeking indemnification and (ii) any indemnification required pursuant to Section 3.5(vii) shall, notwithstanding the provisions of this Section 10.8, be paid by the relevant Lender in accordance with the provisions thereof. The obligations of the Lenders under this Section 10.8 shall survive payment of the Obligations and termination of this Agreement.
9.9. Notice of Default. The Agent shall not be deemed to have knowledge or notice of the occurrence of any Default or Unmatured Default hereunder unless the Agent has received written notice from a Lender or the Borrower referring to this Agreement describing such Default or Unmatured Default and stating that such notice is a "notice of default". In the event that the Agent receives such a notice, the Agent shall give prompt notice thereof to the Lenders.
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9.10. Rights as a Lender. In the event the Agent is a Lender, the Agent shall have the same rights and powers hereunder and under any other Loan Document with respect to its Commitment and its Loans as any Lender and may exercise the same as though it were not the Agent, and the term "Lender" or "Lenders" shall, at any time when the Agent is a Lender, unless the context otherwise indicates, include the Agent in its individual capacity. The Agent and its Affiliates may accept deposits from, lend money to, and generally engage in any kind of trust, debt, equity or other transaction, in addition to those contemplated by this Agreement or any other Loan Document, with the Borrower or any of its Subsidiaries in which the Borrower or such Subsidiary is not restricted hereby from engaging with any other Person. The Agent, in its individual capacity, is not obligated to remain a Lender.
9.11. Lender Credit Decision. Each Lender acknowledges that it has, independently and without reliance upon the Agent, the Arranger or any other Lender and based on the financial statements prepared by the Borrower and such other documents and information as it has deemed appropriate, made its own credit analysis and decision to enter into this Agreement and the other Loan Documents. Each Lender also acknowledges that it will, independently and without reliance upon the Agent, the Arranger or any other Lender and based on such documents and information as it shall deem appropriate at the time, continue to make its own credit decisions in taking or not taking action under this Agreement and the other Loan Documents.
9.12. Successor Agent. The Agent may resign at any time by giving written notice thereof to the Lenders and the Borrower, such resignation to be effective upon the appointment of a successor Agent or, if no successor Agent has been appointed, forty-five days after the retiring Agent gives notice of its intention to resign. The Agent may be removed at any time with or without cause by written notice received by the Agent from the Required Lenders, such removal to be effective on the date specified by the Required Lenders. Upon any such resignation or removal, the Required Lenders shall have the right to appoint, on behalf of the Borrower and the Lenders, a successor Agent. If no successor Agent shall have been so appointed by the Required Lenders within thirty days after the resigning Agent's giving notice of its intention to resign, then the resigning Agent may appoint, on behalf of the Borrower and the Lenders, a successor Agent. Notwithstanding the previous sentence, the Agent may at any time without the consent of the Borrower or any Lender, appoint any of its Affiliates which is a commercial bank as a successor Agent hereunder. If the Agent has resigned or been removed and no successor Agent has been appointed, the Lenders may perform all the duties of the Agent hereunder and the Borrower shall make all payments in respect of the Obligations to the applicable Lender and for all other purposes shall deal directly with the Lenders. No successor Agent shall be deemed to be appointed hereunder until such successor Agent has accepted the appointment. Any such successor Agent shall be a commercial bank having capital and retained earnings of at least $100,000,000. Upon the acceptance of any appointment as Agent hereunder by a successor Agent, such successor Agent shall thereupon succeed to and become vested with all the rights, powers, privileges and duties of the resigning or removed Agent. Upon the effectiveness of the resignation or removal of the Agent, the resigning or removed Agent shall be discharged from its duties and obligations hereunder and under the Loan Documents. After the effectiveness of the resignation or removal of an Agent, the provisions of this Article X shall continue in effect for the benefit of such Agent in respect of any actions taken or omitted to be taken by it while it was acting as the Agent hereunder and under the other Loan Documents. In the event that there is a
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successor to the Agent by merger, or the Agent assigns its duties and obligations to an Affiliate pursuant to this Section 10.12, then the term "Prime Rate" as used in this Agreement shall mean the prime rate, base rate or other analogous rate of the new Agent.
9.13. Agent and Arranger Fees. The Borrower agrees to pay to the Agent and the Arranger, for their respective accounts, the fees agreed to by the Borrower, the Agent and the Arranger pursuant to that certain letter agreement dated April 23, 2002, or as otherwise agreed from time to time.
9.14. Delegation to Affiliates. The Borrower and the Lenders agree that the Agent may delegate any of its duties under this Agreement to any of its Affiliates. Any such Affiliate (and such Affiliate's directors, officers, agents and employees) which performs duties in connection with this Agreement shall be entitled to the same benefits of the indemnification, waiver and other protective provisions to which the Agent is entitled under Articles IX and X.
SETOFF; RATABLE PAYMENTS
10.1. Setoff. In addition to, and without limitation of, any rights of the Lenders under applicable law, if the Borrower becomes insolvent, however evidenced, or any Default occurs, any and all deposits (including all account balances, whether provisional or final and whether or not collected or available) and any other Indebtedness at any time held or owing by any Lender or any Affiliate of any Lender to or for the credit or account of the Borrower may be offset and applied toward the payment of the Obligations owing to such Lender, whether or not the Obligations, or any part thereof, shall then be due.
10.2. Ratable Payments. If any Lender, whether by setoff or otherwise, has payment made to it upon its Loans (other than payments received pursuant to Section 3.1, 3.2, 3.4 or 3.5) in a greater proportion than that received by any other Lender, such Lender agrees, promptly upon demand, to purchase a portion of the Loans held by the other Lenders so that after such purchase each Lender will hold its ratable proportion of Loans. If any Lender, whether in connection with setoff or amounts which might be subject to setoff or otherwise, receives collateral or other protection for its Obligations or such amounts which may be subject to setoff, such Lender agrees, promptly upon demand, to take such action necessary such that all Lenders share in the benefits of such collateral ratably in proportion to their Loans. In case any such payment is disturbed by legal process, or otherwise, appropriate further adjustments shall be made.
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BENEFIT OF AGREEMENT; ASSIGNMENTS; PARTICIPATIONS
Successors and Assigns; Designated Lenders.
11.1. Successors and Assigns. The terms and provisions of the Loan Documents shall be binding upon and inure to the benefit of the Borrower, the Agent and the Lenders and their respective successors and assigns permitted hereby, except that (i) the Borrower shall not have the right to assign its rights or obligations under the Loan Documents without the prior written consent of each Lender, (ii) any assignment by any Lender must be made in compliance with Section 12.3, and (iii) any transfer by Participation must be made in compliance with Section 12.2. Any attempted assignment or transfer by any party not made in compliance with this Section 12.1 shall be null and void, unless such attempted assignment or transfer is treated as a participation in accordance with Section 12.3.2. The parties to this Agreement acknowledge that clause (ii) of this Section 12.1 relates only to absolute assignments and this Section 12.1 does not prohibit assignments creating security interests, including, without limitation, (x) any pledge or assignment by any Lender of all or any portion of its rights under this Agreement and any Note to a Federal Reserve Bank, (y) in the case of a Lender which is a Fund, any pledge or assignment of all or any portion of its rights under this Agreement and any Note to its trustee in support of its obligations to its trustee or (z) any pledge or assignment by any Lender of all or any portion of its rights under this Agreement and any Note to direct or indirect contractual counterparties in swap agreements relating to the Loans; provided, however, that no such pledge or assignment creating a security interest shall release the transferor Lender from its obligations hereunder unless and until the parties thereto have complied with the provisions of Section 12.3. The Agent may treat the Person which made any Loan or which holds any Note as the owner thereof for all purposes hereof unless and until such Person complies with Section 12.3; provided, however, that the Agent may in its discretion (but shall not be required to) follow instructions from the Person which made any Loan or which holds any Note to direct payments relating to such Loan or Note to another Person. Any assignee of the rights to any Loan or any Note agrees by acceptance of such assignment to be bound by all the terms and provisions of the Loan Documents. Any request, authority or consent of any Person, who at the time of making such request or giving such authority or consent is the owner of the rights to any Loan (whether or not a Note has been issued in evidence thereof), shall be conclusive and binding on any subsequent holder or assignee of the rights to such Loan.
Designated Lenders.
Subject to the terms and conditions set forth in this Section 12.1.2, any
Lender may from time to time elect to designate an Eligible Designee
to provide all or any part of the Loans to be made by such Lender
pursuant to this Agreement; provided that the designation of an
Eligible Designee by any Lender for purposes of this Section
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12.1.2 shall be subject to the approval of the Agent (which consent shall
not be unreasonably withheld or delayed). Upon the execution by the
parties to each such designation of an agreement in the form of
Exhibit F hereto (a “Designation Agreement”) and the
acceptance thereof by the Agent, the Eligible Designee shall become a
Designated Lender for purposes of this Agreement. The Designating
Lender shall thereafter have the right to permit the Designated Lender
to provide all or a portion of the Loans to be made by the Designating
Lender pursuant to the terms of this Agreement and the making of the
Loans or portion thereof shall satisfy the obligations of the
Designating Lender to the same extent, and as if, such Loan was made
by the Designating Lender. As to any Loan made by it, each Designated
Lender shall have all the rights a Lender making such Loan would have
under this Agreement and otherwise; provided, (x) that all voting
rights under this Agreement shall be exercised solely by the
Designating Lender, (y) each Designating Lender shall remain solely
responsible to the other parties hereto for its obligations under this
Agreement, including the obligations of a Lender in respect of Loans
made by its Designated Lender and (z) no Designated Lender shall be
entitled to reimbursement under Article III hereof for any
amount which would exceed the amount that would have been payable by
the Borrower to the Lender from which the Designated Lender obtained
any interests hereunder. No additional Notes shall be required with
respect to Loans provided by a Designated Lender; provided,
however, to the extent any Designated Lender shall advance
funds, the Designating Lender shall be deemed to hold the Notes in its
possession as an agent for such Designated Lender to the extent of the
Loan funded by such Designated Lender. Such Designating Lender shall
act as administrative agent for its Designated Lender and give and
receive notices and communications hereunder. Any payments for the
account of any Designated Lender shall be paid to its Designating
Lender as administrative agent for such Designated Lender and neither
the Borrower nor the Agent shall be responsible for any Designating
Lender’s application of such payments. In addition, any
Designated Lender may (1) with notice to, but without the consent of
the Borrower or the Agent, assign all or portions of its interests in
any Loans to its Designating Lender or to any financial institution
consented to by the Agent providing liquidity and/or credit facilities
to or for the account of such Designated Lender and (2) subject to
advising any such Person that such information is to be treated as
confidential in accordance with Section 9.11, disclose on a
confidential basis any non-public information relating to its Loans to
any rating agency, commercial paper dealer or provider of any
guarantee, surety or credit or liquidity enhancement to such
Designated Lender.
Each party to this Agreement hereby agrees that it shall not institute
against, or join any other Person in instituting against, any
Designated Lender any bankruptcy, reorganization, arrangement,
insolvency or liquidation proceeding or other proceedings under any
federal or state bankruptcy or similar law for one year and a day
after the payment in full of all outstanding senior indebtedness of
any Designated Lender; provided that the Designating Lender for
each Designated
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Lender hereby agrees to indemnify, save and hold harmless each other party
hereto for any loss, cost, damage and expense arising out of its
inability to institute any such proceeding against such Designated
Lender. This Section 12.1.2 shall survive the termination of this
Agreement.
11.2. Participations.
| Permitted Participants; Effect. Any Lender may, in the ordinary course of its business and in accordance with applicable law, at any time sell to one or more banks or other entities (“Participants”) participating interests in any Loan owing to such Lender, any Note held by such Lender, any Commitment of such Lender or any other interest of such Lender under the Loan Documents. In the event of any such sale by a Lender of participating interests to a Participant, such Lender’s obligations under the Loan Documents shall remain unchanged, such Lender shall remain solely responsible to the other parties hereto for the performance of such obligations, such Lender shall remain the owner of its Loans and the holder of any Note issued to it in evidence thereof for all purposes under the Loan Documents, all amounts payable by the Borrower under this Agreement shall be determined as if such Lender had not sold such participating interests, and the Borrower and the Agent shall continue to deal solely and directly with such Lender in connection with such Lender’s rights and obligations under the Loan Documents. |
| Voting Rights. Each Lender shall retain the sole right to approve, without the consent of any Participant, any amendment, modification or waiver of any provision of the Loan Documents other than any amendment, modification or waiver with respect to any Loan or Commitment in which such Participant has an interest which would require consent of all of the Lenders pursuant to the terms of Section 8.2. |
| Benefit of Certain Provisions. The Borrower agrees that each Participant shall be deemed to have the right of setoff provided in Section 11.1 in respect of its participating interest in amounts owing under the Loan Documents to the same extent as if the amount of its participating interest were owing directly to it as a Lender under the Loan Documents, provided that each Lender shall retain the right of setoff provided in Section 11.1 with respect to the amount of participating interests sold to each Participant. The Lenders agree to share with each Participant, and each Participant, by exercising the right of setoff provided in Section 11.1, agrees to share with each Lender, any amount received pursuant to the exercise of its right of setoff, such amounts to be shared in accordance with Section 11.2 as if each Participant were a Lender. The Borrower further agrees that each Participant shall be entitled to the benefits of Sections 3.1, 3.2, 3.4 and 3.5 to the same extent as if it were a Lender and had acquired its interest by assignment pursuant to Section 12.3, provided that (i) a Participant shall not be entitled to receive any greater payment under Section 3.1, 3.2 or 3.5 than the Lender who sold the participating interest to such Participant would have received had it retained such interest for its own account, unless the sale of such interest to such Participant is made with the prior written consent of the Borrower, and (ii) any Participant not incorporated under the laws of the United |
47
States of America or any State thereof agrees to comply with the provisions of Section 3.5 to the same extent as if it were a Lender.
11.3. Assignments.
| Permitted Assignments. Any Lender may at any time assign to one or more banks or other entities (“Purchasers”) all or any part of its rights and obligations under the Loan Documents. Such assignment shall be substantially in the form of Exhibit C or in such other form as may be agreed to by the parties thereto. Each such assignment with respect to a Purchaser which is not a Lender or an Affiliate of a Lender or an Approved Fund shall either be in an amount equal to the entire applicable Commitment and Loans of the assigning Lender or (unless each of the Borrower and the Agent otherwise consents) be in an aggregate amount not less than $2,500,000. The amount of the assignment shall be based on the Commitment or outstanding Loans (if the Commitment has been terminated) subject to the assignment, determined as of the date of such assignment or as of the “Trade Date,” if the “Trade Date” is specified in the assignment. |
| Consents. The consent of the Borrower shall be required prior to an assignment becoming effective unless the Purchaser is a Lender, an Affiliate of a Lender or an Approved Fund, provided that the consent of the Borrower shall not be required if (i) a Default has occurred and is continuing or (ii) if such assignment is in connection with the physical settlement of any Lender's obligations to direct or indirect contractual counterparties in swap agreements relating to the Loans; provided, that the assignment without the Borrower's consent pursuant to clause (ii) shall not increase the Borrower's liability under Section 3.5. The consent of the Agent shall be required prior to an assignment becoming effective unless the Purchaser is a Lender, an Affiliate of a Lender or an Approved Fund. Any consent required under this Section 12.3.2 shall not be unreasonably withheld or delayed. |
| Effect; Effective Date. Upon (i) delivery to the Agent of an assignment, together with any consents required by Sections 12.3.1 and 12.3.2, and (ii) payment of a $3,500 fee to the Agent for processing such assignment (unless such fee is waived by the Agent), such assignment shall become effective on the effective date specified in such assignment. The assignment shall contain a representation and warranty by the Purchaser to the effect that none of the funds, money, assets or other consideration used to make the purchase and assumption of the Commitment and Loans under the applicable assignment agreement constitutes “plan assets” as defined under ERISA and that the rights, benefits and interests of the Purchaser in and under the Loan Documents will not be “plan assets” under ERISA. On and after the effective date of such assignment, such Purchaser shall for all purposes be a Lender party to this Agreement and any other Loan Document executed by or on behalf of the Lenders and shall have all the rights, benefits and obligations of a Lender under the Loan Documents, to the same extent as if it were an original party thereto, and the transferor Lender shall be released with respect to the Commitment and Loans assigned to such Purchaser without any further consent or action by the Borrower, the Lenders or the Agent. In the case of an assignment covering all of the assigning Lender’s rights, benefits and obligations under this Agreement, such Lender |
48
| shall cease to be a Lender hereunder but shall continue to be entitled to the benefits of, and subject to, those provisions of this Agreement and the other Loan Documents which survive payment of the Obligations and termination of the Loan Documents. Any assignment or transfer by a Lender of rights or obligations under this Agreement that does not comply with this Section 12.3 shall be treated for purposes of this Agreement as a sale by such Lender of a participation in such rights and obligations in accordance with Section 12.2. Upon the consummation of any assignment to a Purchaser pursuant to this Section 12.3.3, the transferor Lender, the Agent and the Borrower shall, if the transferor Lender or the Purchaser desires that its Loans be evidenced by Notes, make appropriate arrangements so that, upon cancellation and surrender to the Borrower of the Notes (if any) held by the transferor Lender, new Notes or, as appropriate, replacement Notes are issued to such transferor Lender, if applicable, and new Notes or, as appropriate, replacement Notes, are issued to such Purchaser, in each case in principal amounts reflecting their respective Commitments, as adjusted pursuant to such assignment. |
| Register. The Agent, acting solely for this purpose as an agent of the Borrower (and the Borrower hereby designates the Agent to act in such capacity), shall maintain at one of its offices in Chicago, Illinois a copy of each Assignment and Assumption delivered to it and a register for the recordation of the names and addresses of the Lenders, and the Commitments of, and principal amounts of the Loans owing to, each Lender pursuant to the terms hereof from time to time (the "Register"). The entries in the Register shall be conclusive, and the Borrower, the Agent and the Lenders may treat each Person whose name is recorded in the Register pursuant to the terms hereof as a Lender hereunder for all purposes of this Agreement, notwithstanding notice to the contrary. The Register shall be available for inspection by the Borrower and any Lender, at any reasonable time and from time to time upon reasonable prior notice. |
11.4. Dissemination of Information. The Borrower authorizes each Lender to disclose to any Participant or Purchaser or any other Person acquiring an interest in the Loan Documents by operation of law (each a "Transferee") and any prospective Transferee any and all information in such Lender's possession concerning the creditworthiness of the Borrower and its Subsidiaries; provided that each Transferee and prospective Transferee agrees to be bound by Section 9.11 of this Agreement.
11.5. Tax Certifications. If any interest in any Loan Document is transferred to any Transferee which is not incorporated under the laws of the United States or any State thereof, the transferor Lender shall cause such Transferee, concurrently with the effectiveness of such transfer, to comply with the provisions of Section 3.5(iv).
NOTICES
12.1. Notices. Except as otherwise permitted by Section 2.14 with respect to borrowing notices, all notices, requests and other communications to any party hereunder shall be in writing (including electronic transmission, facsimile transmission or similar writing) and shall be given
49
to such party: (x) in the case of the Borrower, the Lenders or the Agent, at its address or facsimile number set forth on the signature pages hereof or, (y) in the case of any party, at such other address or facsimile number as such party may hereafter specify for the purpose by notice to the Agent and the Borrower in accordance with the provisions of this Section 13.1. Each such notice, request or other communication shall be effective (i) if given by facsimile transmission, when transmitted to the facsimile number specified in this Section and confirmation of receipt is received, (ii) if given by mail, 72 hours after such communication is deposited in the mails with first class postage prepaid, addressed as aforesaid, or (iii) if given by any other means, when delivered (or, in the case of electronic transmission, received) at the address specified in this Section; provided that notices to the Agent under Article II shall not be effective until received.
12.2. Change of Address. The Borrower, the Agent and any Lender may each change the address for service of notice upon it by a notice in writing to the other parties hereto.
50
COUNTERPARTS
This Agreement may be executed in any number of counterparts, all of which taken together shall constitute one agreement, and any of the parties hereto may execute this Agreement by signing any such counterpart. This Agreement shall be effective when it has been executed by the Borrower, the Agent and the Lenders and each party has notified the Agent by facsimile transmission or telephone that it has taken such action.
CHOICE OF LAW; CONSENT TO JURISDICTION; WAIVER OF JURY TRIAL
15.1 CHOICE OF LAW. THE LOAN DOCUMENTS (OTHER THAN THOSE CONTAINING A CONTRARY EXPRESS CHOICE OF LAW PROVISION) SHALL BE GOVERNED BY AND CONSTRUED IN ACCORDANCE WITH THE INTERNAL LAWS (INCLUDING, WITHOUT LIMITATION, 735 ILCS SECTION 105/5-1 ET SEQ, BUT OTHERWISE WITHOUT REGARD TO THE CONFLICT OF LAWS PROVISIONS) OF THE STATE OF ILLINOIS, BUT GIVING EFFECT TO FEDERAL LAWS APPLICABLE TO NATIONAL BANKS.
15.2 CONSENT TO JURISDICTION. THE BORROWER HEREBY IRREVOCABLY SUBMITS TO THE NON-EXCLUSIVE JURISDICTION OF ANY UNITED STATES FEDERAL OR ILLINOIS STATE COURT SITTING IN CHICAGO, ILLINOIS IN ANY ACTION OR PROCEEDING ARISING OUT OF OR RELATING TO ANY LOAN DOCUMENTS AND THE BORROWER HEREBY IRREVOCABLY AGREES THAT ALL CLAIMS IN RESPECT OF SUCH ACTION OR PROCEEDING MAY BE HEARD AND DETERMINED IN ANY SUCH COURT AND IRREVOCABLY WAIVES ANY OBJECTION IT MAY NOW OR HEREAFTER HAVE AS TO THE VENUE OF ANY SUCH SUIT, ACTION OR PROCEEDING BROUGHT IN SUCH A COURT OR THAT SUCH COURT IS AN INCONVENIENT FORUM. NOTHING HEREIN SHALL LIMIT THE RIGHT OF THE AGENT OR ANY LENDER TO BRING PROCEEDINGS AGAINST THE BORROWER IN THE COURTS OF ANY OTHER JURISDICTION. ANY JUDICIAL PROCEEDING BY THE BORROWER AGAINST THE AGENT OR ANY LENDER OR ANY AFFILIATE OF THE AGENT OR ANY LENDER INVOLVING, DIRECTLY OR INDIRECTLY, ANY MATTER IN ANY WAY ARISING OUT OF, RELATED TO, OR CONNECTED WITH ANY LOAN DOCUMENT SHALL BE BROUGHT ONLY IN A COURT IN CHICAGO, ILLINOIS.
15.3 WAIVER OF JURY TRIAL. THE BORROWER, THE AGENT AND EACH LENDER HEREBY WAIVE TRIAL BY JURY IN ANY JUDICIAL PROCEEDING INVOLVING, DIRECTLY OR INDIRECTLY, ANY MATTER (WHETHER SOUNDING IN TORT, CONTRACT OR OTHERWISE) IN ANY WAY ARISING OUT OF, RELATED TO, OR CONNECTED WITH ANY LOAN DOCUMENT OR THE RELATIONSHIP ESTABLISHED THEREUNDER.
[Signature Pages Follow]
51
IN WITNESS WHEREOF, the Borrower, the Lenders and the Agent have executed this Agreement as of the date first above written.
OKLAHOMA GAS AND ELECTRIC COMPANY
By: /s/
--------------------------------------------
Title:
-------------------------------------------
(address)
--------------------------------------------
--------------------------------------------
Attention:
-------------------------------------
Telephone: ( )
FAX: ( )
BANK ONE, NA,
Individually and as Agent
By: /s/
--------------------------------------------
Title:
-------------------------------------------
1 Bank One Plaza
Chicago, Illinois 60670
Attention:
-------------------------------------
Telephone: (312)
FAX: (312)
SIGNATURE PAGE TO
OKLAHOMA GAS AND ELECTRIC COMPANY CREDIT AGREEMENT
WACHOVIA BANK, NATIONAL ASSOCIATION, Individually
and as Syndication Agent
By: /s/
--------------------------------------------
Title:
-------------------------------------------
-------------------------------------
-------------------------------------
Attention:
-------------------------------------
Telephone: ( )
FAX: ( )
SIGNATURE PAGE TO
OKLAHOMA GAS AND ELECTRIC COMPANY CREDIT AGREEMENT
U.S. BANK NATIONAL ASSOCIATION, as a Lender
By: /s/
--------------------------------------------
Title:
-------------------------------------------
-------------------------------------
-------------------------------------
Attention:
-------------------------------------
Telephone: ( )
FAX: ( )
SIGNATURE PAGE TO
OKLAHOMA GAS AND ELECTRIC COMPANY CREDIT AGREEMENT
UNION BANK OF CALIFORNIA, N.A., as a Lender
By: /s/
--------------------------------------------
Title:
-------------------------------------------
-------------------------------------
-------------------------------------
Attention:
-------------------------------------
Telephone: ( )
FAX: ( )
SIGNATURE PAGE TO
OKLAHOMA GAS AND ELECTRIC COMPANY CREDIT AGREEMENT
BANK HAPOALIM B.M., as a Lender
By: /s/
--------------------------------------------
Title:
-------------------------------------------
By:
--------------------------------------------
Title:
-------------------------------------------
-------------------------------------
-------------------------------------
Attention:
-------------------------------------
Telephone: ( )
FAX: ( )
SIGNATURE PAGE TO
OKLAHOMA GAS AND ELECTRIC COMPANY CREDIT AGREEMENT
COMMITMENT SCHEDULE
LENDER COMMITMENT
---------------------------------------------------------------- ------------------------
Bank One, NA $ 30,000,000
Wachovia Bank, National Association $ 25,000,000
U.S. Bank National Association $ 15,000,000
Union Bank of California, N.A. $ 15,000,000
Bank Hapoalim B.M. $ 15,000,000
AGGREGATE COMMITMENT $100,000,000
PRICING SCHEDULE
====================== ========== ========== ============ ========== ========== =========== ============
APPLICABLE LEVEL I LEVEL II LEVEL III LEVEL IV LEVEL V LEVEL VI LEVEL VII
MARGIN STATUS STATUS STATUS STATUS STATUS STATUS STATUS
- ---------------------- ---------- ---------- ------------ ---------- ---------- ----------- ------------
Eurodollar Rate 0.285% 0.40% 0.50% 0.60% 0.70% 0.80% 1.125%
- ---------------------- ---------- ---------- ------------ ---------- ---------- ----------- ------------
Floating Rate 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.25%
====================== ========== ========== ============ ========== ========== =========== ============
====================== ========== ========== ============ ========== ========== =========== ============
APPLICABLE LEVEL I LEVEL II LEVEL III LEVEL IV LEVEL V LEVEL VI LEVEL VII
FEE RATE STATUS STATUS STATUS STATUS STATUS STATUS STATUS
====================== ========== ========== ============ ========== ========== =========== ============
Facility Fee 0.09% 0.10% 0.125% 0.15% 0.175% 0.20% 0.375%
- ---------------------- ---------- ---------- ------------ ---------- ---------- ----------- ------------
Utilization Fee (when 0.10% 0.125% 0.125% 0.125% 0.125% 0.25% 0.25%
usage exceeds 33 1/3%)
====================== ========== ========== ============ ========== ========== =========== ============
For the purposes of this Schedule, the following terms have the following meanings, subject to the final paragraph of this Schedule:
“Level I Status” exists at any date if, on such date, the Borrower’s Moody’s Rating is A1 or better or the Borrower’s S&P Rating is A+ or better.
“Level II Status” exists at any date if, on such date, (i) the Borrower has not qualified for Level I Status and (ii) the Borrower’s Moody’s Rating is A2 or better or the Borrower’s S&P Rating is A or better.
“Level III Status” exists at any date if, on such date, (i) the Borrower has not qualified for Level I Status or Level II Status and (ii) the Borrower’s Moody’s Rating is A3 or better or the Borrower’s S&P Rating is A- or better.
“Level IV Status” exists at any date if, on such date, (i) the Borrower has not qualified for Level I Status, Level II Status or Level III Status and (ii) the Borrower’s Moody’s Rating is Baa1 or better or the Borrower’s S&P Rating is BBB+ or better.
“Level V Status” exists at any date if, on such date, (i) the Borrower has not qualified for Level I Status, Level II Status, Level III Status or Level IV Status and (ii) the Borrower’s Moody’s Rating is Baa2 or better or the Borrower’s S&P Rating is BBB or better.
“Level VI Status” exists at any date if, on such date, (i) the Borrower has not qualified for Level I Status, Level II Status, Level III Status, Level IV Status or Level V Status and (ii) the Borrower’s Moody’s Rating is Baa3 or better or the Borrower’s S&P Rating is BBB- or better.
“Level VII Status” exists at any date if, on such date, the Borrower has not qualified for Level I Status, Level II Status, Level III Status, Level IV Status, Level V Status or Level VI Status.
“Moody’s Rating” means, at any time, the rating issued by Moody’s and then in effect with respect to the Borrower’s senior unsecured long-term debt securities without third-party credit enhancement.
“S&P Rating” means, at any time, the rating issued by S&P and then in effect with respect to the Borrower’s senior unsecured long-term debt securities without third-party credit enhancement.
“Status” means either Level I Status, Level II Status, Level III Status, Level IV Status, Level V Status, Level VI Status or Level VII Status.
The Applicable Margin and Applicable Fee Rate shall be determined in accordance with the foregoing table based on the Borrower’s Status as determined from its then-current Moody’s and S&P Ratings. The credit rating in effect on any date for the purposes of this Schedule is that in effect at the close of business on such date. If at any time the Borrower has no Moody’s Rating or no S&P Rating, Level VII Status shall exist.
If the Borrower is split-rated and the ratings differential is one level, the higher rating will apply. If the Borrower is split-rated and the ratings differential is two levels or more, the intermediate rating at the midpoint will apply. If there is no midpoint, the higher of the two intermediate ratings will apply.
Exhibit 23.01
CONSENT OF INDEPENDENT AUDITORS
We consent to the incorporation by reference in the Post-Effective Amendment No. 1-B to Registration Statement (No. 33-61699) pertaining to the dividend reinvestment plan, the Post-Effective Amendment No. 2-B to Registration Statement (No. 33-61699) pertaining to the retirement savings plan, the Registration Statement (Form S-8 No. 333-71327) pertaining to the stock incentive plan, and Registration Statement (Form S-8 No. 333-92423) pertaining to the deferred compensation plan, of our report dated January 24, 2003, with respect to the financial statements and schedule of Oklahoma Gas and Electric Company in this Annual Report ( Form 10-K) for the year ended December 31, 2002.
/s/ Ernst
and Young LLP
Ernst and Young LLP
Oklahoma City, Oklahoma,
March 24, 2003
Exhibit 24.01
POWER OF ATTORNEY
WHEREAS, OKLAHOMA GAS AND ELECTRIC COMPANY, an Oklahoma corporation (herein referred to as the “Company”), is about to file with the Securities and Exchange Commission, under the provisions of the Securities Exchange Act of 1934, as amended, its annual report on Form 10-K for the year ended December 31, 2002; and
WHEREAS, each of the undersigned holds the office or offices in the Company herein-below set opposite his or her name, respectively;
NOW, THEREFORE, each of the undersigned hereby constitutes and appoints STEVEN E. MOORE, JAMES R. HATFIELD and DONALD R. ROWLETT and each of them individually, his or her attorney with full power to act for him or her and in his or her name, place and stead, to sign his name in the capacity or capacities set forth below to said Form 10-K and to any and all amendments thereto, and hereby ratifies and confirms all that said attorney may or shall lawfully do or cause to be done by virtue hereof.
IN WITNESS WHEREOF, the undersigned have hereunto set their hands this 15th day of January 2003.
Steven E. Moore, Chairman, Principal
Executive Officer and Director / s / Steven E. Moore
---------------------------------------------
Herbert H. Champlin, Director / s / Herbert H. Champlin
---------------------------------------------
Luke R. Corbett, Director / s / Luke R. Corbett
---------------------------------------------
William E. Durrett, Director / s / William E. Durrett
---------------------------------------------
Martha W. Griffin, Director / s / Martha W. Griffin
---------------------------------------------
John D. Groendyke, Director / s / John D. Groendyke
---------------------------------------------
Hugh L. Hembree, III, Director / s / Hugh L. Hembree, III
---------------------------------------------
Robert Kelley, Director / s / Robert Kelley
---------------------------------------------
Ronald H. White, M.D., Director / s / Ronald H. White, M.D.
---------------------------------------------
J. D. Williams, Director / s / J. D. Williams
---------------------------------------------
James R. Hatfield, Principal Financial Officer / s / James R. Hatfield
---------------------------------------------
Donald R. Rowlett, Principal Accounting Officer / s / Donald R. Rowlett
---------------------------------------------
STATE OF OKLAHOMA )
)SS
COUNTY OF CANADIAN )
On the date indicated above, before me, Debra Peters, Notary Public in and for said County and State, personally appeared the above named directors and officers of OKLAHOMA GAS AND ELECTRIC COMPANY, an Oklahoma corporation, and known to me to be the persons whose names are subscribed to the foregoing instrument, and they severally acknowledged to me that they executed the same as their own free act and deed.
IN WITNESS WHEREOF, I have hereunto set my hand and affixed my official seal on the 15th day of January, 2003.
/s/
Debra Peters
Debra
Peters
Notary Public in and for the
County
of Canadian, State of Oklahoma
My Commission Expires:
May 3, 2003
Exhibit 99.01
Oklahoma Gas and Electric Company Cautionary Factors
The Private Securities Litigation Reform Act of 1995 provides a “safe harbor” for forward-looking statements to encourage such disclosures without the threat of litigation providing those statements are identified as forward-looking and are accompanied by meaningful, cautionary statements identifying important factors that could cause the actual results to differ materially from those projected in the statement. Forward-looking statements have been and will be made in written documents and oral presentations of Oklahoma Gas and Electric Company (the “Company”). Such statements are based on management’s beliefs as well as assumptions made by and information currently available to management. When used in the Company’s documents or oral presentations, the words “anticipate”, “estimate”, “expect”, “objective” and similar expressions are intended to identify forward-looking statements. In addition to any assumptions and other factors referred to specifically in connection with such forward-looking statements, factors that could cause the Company’s actual results to differ materially from those contemplated in any forward-looking statements include, among others, the following:
regulate natural gas transmission, gathering and processing and similar entities with regulatory oversight;
The Company undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.
Exhibit 99.02
Certification Pursuant to 18 U.S.C. Section 1350
As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act
of 2002
In connection with the Annual Report of Oklahoma Gas and Electric Company (the “Company”) on Form 10-K for the period ended December 31, 2002, as filed with the Securities and Exchange Commission (the “Report”), each of the undersigned does hereby certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:
1) The Report fully complies with the requirements of Section 13(a)
or 15(d) of the Securities Exchange Act of 1934; and
2) The information contained in the Report fairly presents, in all
material respects, the financial condition and results of operations
of the Company.
March 25, 2003
/s/ Steven E. Moore
---------------------------------------------
Steven E. Moore
Chairman of the Board, President
and Chief Executive Officer
/s/ James R. Hatfield
--------------------------------------------
James R. Hatfield
Senior Vice President and
Chief Financial Officer