SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2000 Commission File Number 1-1097
Oklahoma Gas and Electric Company meets the conditions set forth in general instruction I (1)(a) and (b) of Form 10-K and is therefore filing this form with the reduced disclosure format permitted by general instruction I (2).
OKLAHOMA GAS AND ELECTRIC COMPANY
(Exact name of registrant as specified in its charter)
Oklahoma
73-0382390
(State or other jurisdiction
of
(I.R.S. Employer
incorporation or
organization)
Identification No.)
321 North Harvey
P. O. Box 321
Oklahoma City, Oklahoma 73101-0321
(Address of principal executive offices)
(Zip Code)
Registrant's telephone number, including area code: 405-553-3000
Securities registered pursuant to Section 12(b) of the Act: None
Securities registered pursuant to Section 12(g) of the Act: None
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 deliquent
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 ]
As of February 28, 2001, the number of
outstanding shares of the Registrant's common stock, par value $2.50 per share,
was 40,378,745 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
TABLE OF CONTENTS
ITEM PAGE
- ---- ----
PART I
Item 1. Business......................................................... 1
The Company...................................................... 1
Introduction............................................ 1
General................................................. 1
Finance and Construction................................ 4
Regulation and Rates.................................... 4
Rate Structure, Load Growth and Related Matters......... 12
Fuel Supply............................................. 12
Environmental Matters............................................ 13
Item 2. Properties....................................................... 16
Item 3. Legal Proceedings................................................ 17
PART II
Item 5. Market for Registrant's Common Equity and Related
Stockholder Matters..................................... 24
Item 6. Selected Financial Data.......................................... 25
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations..................... 26
Item 8. Financial Statements and Supplementary Data...................... 35
Item 9. Changes in and Disagreements with Accountants
and Financial Disclosure ............................... 62
PART III
Item 10. Directors and Executive Officers of the Registrant............... 62
Item 11. Executive Compensation........................................... 62
Item 12. Security Ownership of Certain Beneficial
Owners and Management................................... 62
Item 13. Certain Relationships and Related Transactions................... 62
PART IV
Item 14. Exhibits, Financial Statement Schedules and
Reports on Form 8-K..................................... 62
i
PART I
Item 1. Business.
THE COMPANY
INTRODUCTION
Oklahoma Gas and Electric Company (the "Company") is a regulated public utility engaged in the generation, transmission and distribution of electricity to retail and wholesale customers. The Company is a wholly-owned subsidiary of OGE Energy Corp. ("Energy Corp.") which is a public utility holding company incorporated in the State of Oklahoma and located in Oklahoma City, Oklahoma. The Company's executive offices are located at 321 N. Harvey, P.O. Box 321, Oklahoma City, Oklahoma 73101-0321: telephone (405) 553-3000.
The Company was incorporated in 1902 under the laws of the Oklahoma Territory and is the largest electric utility in the State of Oklahoma. The Company sold its retail gas business in 1928 and now owns and operates an interconnected electric production, transmission and distribution system, which includes eight generating stations with a total capability of 5,781 megawatts. At the end of 2000, the Company had 1,996 members.
The Company's business has been and will continue to be affected by competitive changes to the utility industry. Significant changes already have occurred in the wholesale electric markets at the Federal level. In Oklahoma, legislation was passed in 1997 to provide for the orderly restructuring of the electric industry with the goal to provide retail customers with the ability to choose their electric suppliers by July 1, 2002. In April 1999, Arkansas became the 18th state to pass a law calling for restructuring of the electric utility industry at the retail level. The law initially targeted customer choice of electricity providers by January 1, 2002, but in February 2001, the law was amended to delay customer choice until October 1, 2003. It now appears that customer choice of electricity suppliers may also be delayed in Oklahoma beyond 2002. See "Regulation and Rates - Recent Regulatory Matters" for further discussion of these developments.
GENERAL
The Company furnishes retail electric service in 280 communities and their contiguous rural and suburban areas. During 2000, six 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 1.8 million, covers approximately 30,000 square miles in Oklahoma and western Arkansas; including Oklahoma City, the largest city in Oklahoma, and Ft. Smith, Arkansas, the second largest city in that state. Of the 286 communities served, 257 are located in Oklahoma and 29 in Arkansas. Approximately 91 percent of total electric operating revenues for the year ended December 31, 2000, were derived from sales in Oklahoma and the remainder from sales in Arkansas.
The Company's system control area peak demand as reported by the system dispatcher for the year was approximately 5,754 megawatts, and occurred on August 29, 2000. The Company's load responsibility peak demand was approximately 5,570 megawatts on August 29, 2000, resulting in a capacity margin of approximately 17.7 percent. As reflected in the table below and in the operating statistics on page 3, total kilowatt-hour sales increased 5.9 percent in 2000 as compared to a decrease of 2.2 percent in 1999 and a 4.2 percent increase in 1998. Kilowatt-hour sales to the Company's customers ("system sales") increased 6.5 percent due to more favorable weather in the last six months of 2000. Sales to other utilities and power marketers ("off-system sales") decreased 31.5 percent, 48.6 percent and 39.5 percent in 2000, 1999 and 1998, respectively. In 1999, total kilowatt-hour sales decreased due to a decrease in system sales and off-system sales, both of which were higher in 1998 because of the record heat experienced in the summer of 1998.
Variations in kilowatt-hour sales for the three years are reflected in the following table:
SALES (Millions of Kwh)
Inc/ Inc/ Inc/
2000 (Dec) 1999 (Dec) 1998 (Dec)
- -----------------------------------------------------------------------------------------------------------------
System Sales 25,002 6.5% 23,468 (0.7%) 23,642 6.6%
Off-system Sales 256 (31.5%) 374 (48.6%) 728 (39.5%)
-------------- --------------- ---------------
Total Sales 25,258 5.9% 23,842 (2.2%) 24,370 4.2%
============== =============== ===============
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. See Item 3 "Legal Proceedings" for a further discussion of this matter. 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 - - Recent Regulatory Matters" for a discussion of the potential impact on competition from federal and state legislation.
OKLAHOMA GAS AND ELECTRIC COMPANY
CERTAIN OPERATING STATISTICS
Year Ended December 31
2000 1999 1998
--------------- -------------- --------------
ELECTRIC ENERGY:
(Millions of Kwh)
Generation (exclusive of station use).............................. 23,327 21,788 22,565
Purchased.......................................................... 3,634 3,795 3,984
--------------- -------------- --------------
Total generated and purchased.................................. 26,961 25,583 26,549
Company use, free service and losses............................... (1,703) (1,741) (2,179)
--------------- -------------- --------------
Electric energy sold........................................... 25,258 23,842 24,370
--------------- -------------- --------------
ELECTRIC ENERGY SOLD:
(Millions of Kwh)
Residential........................................................ 7,974 7,509 7,959
Commercial and industrial.......................................... 12,729 11,985 11,912
Public street and highway lighting................................. 70 69 68
Other sales to public authorities.................................. 2,458 2,354 2,352
System sales for resale............................................ 1,771 1,551 1,351
--------------- -------------- --------------
Total system sales............................................. 25,002 23,468 23,642
Off-system sales................................................... 256 374 728
--------------- -------------- --------------
Total sales.................................................... 25,258 23,842 24,370
=============== ============== ==============
ELECTRIC OPERATING REVENUES:
(Thousands)
Electric Revenues:
Residential...................................................... $ 575,656 $ 515,299 $ 537,486
Commercial and industrial........................................ 643,576 557,884 554,589
Public street and highway lighting............................... 10,301 9,736 9,618
Other sales to public authorities................................ 124,217 108,159 110,522
System sales for resale.......................................... 58,117 42,918 38,763
--------------- -------------- --------------
Total system sales............................................. 1,411,867 1,233,996 1,250,978
Off-system sales................................................. 12,948 27,894 37,435
--------------- -------------- --------------
Total Electric Revenues........................................ 1,424,815 1,261,890 1,288,413
Miscellaneous.................................................... 28,770 24,954 23,665
--------------- -------------- --------------
Total Operating Revenues....................................... $ 1,453,585 $ 1,286,844 $ 1,312,078
=============== ============== ==============
NUMBER OF ELECTRIC CUSTOMERS:
(At end of period)
Residential........................................................ 603,826 599,702 598,378
Commercial and industrial.......................................... 86,659 86,837 86,251
Public street and highway lighting................................. 364 249 249
Other sales to public authorities.................................. 11,501 11,151 11,183
Sales for resale................................................... 52 56 39
--------------- -------------- --------------
Total.......................................................... 702,402 697,995 696,100
=============== ============== ==============
RESIDENTIAL ELECTRIC SERVICE:
Average annual use (Kwh)........................................... 13,264 12,546 13,342
Average annual revenue............................................. $ 957.54 $ 860.98 $ 900.94
Average price per Kwh (cents)...................................... 7.22 6.86 6.75
FINANCE AND CONSTRUCTION
The Company generally meets its cash needs through internally generated funds, short-term borrowings and permanent financing. Cash flows from operations have enabled the Company to internally generate the required funds to satisfy construction expenditures.
Management expects that internally generated funds will be adequate over the next three years to meet the Company's anticipated construction expenditures of approximately $118 million each year.
The three-year estimate includes expenditures for construction of new facilities to meet anticipated demand for service or to replace or expand existing facilities. Approximately $2.5 million of the Company's construction expenditures budgeted for 2001 are to comply with environmental laws and regulations. The Company's construction program was developed to support an anticipated peak demand growth of one to two percent annually and to maintain minimum capacity reserve margins as stipulated by the Southwest Power Pool. See "Rate Structure, Load Growth and Related Matters."
The Company intends to meet its customers' increased electricity needs during the foreseeable future primarily by maintaining the reliability and increasing the utilization of existing capacity, increasing demand-side management efforts and, if necessary, purchasing power from third parties. The Company will continue to evaluate these strategies against the construction of additional peaking units or another base-load generating unit. These evaluations will consider, among other things, the amount of capital requirements and the relative cost of fuel supply, compared to other alternatives.
The Company will continue to use short-term borrowings from Energy Corp. to meet its temporary cash requirements. At December 31, 2000, Energy Corp. had in place a line of credit for up to $300 million, with $200 million to expire on January 15, 2001, and the remaining $100 million to expire on January 15, 2004. In January 2001, Energy Corp.'s line of credit for $200 million was renewed, with an expiration date of January 15, 2002. The Company has the necessary approvals to incur up to $400 million in short-term borrowings at any one time. The Company had $39.2 million and $55.5 million in short-term debt outstanding at December 31, 2000 and 1999, respectively. The Company did not have any short-term debt outstanding at December 31, 1998.
The Company's financial results continue to depend to a large extent upon the rates it charges customers and the actions of the regulatory bodies that set those rates, the amount of energy used by its customers, the cost and availability of external financing and the cost of conforming to government regulations.
REGULATION AND RATES
The Company's retail electric tariffs in Oklahoma are regulated by the Oklahoma Corporation Commission ("OCC"), and in Arkansas by the Arkansas Public Service Commission ("APSC"). 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 Federal Energy Regulatory Commission ("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, 2000, approximately 88 percent of the Company's revenue was subject to the jurisdiction of the OCC, seven percent to the APSC, and five percent to the FERC.
Recent Regulatory Matters
On January 12, 2000, the OCC Staff (the "Staff") filed three applications to address various aspects of the Company's electric rates. The first application related to the completion on March 1, 2000, of the recovery of the amortization premium paid by the Company when it acquired Enogex Inc. ("Enogex") in 1986 and the resulting removal, pursuant to the Acquisition Premium Credit Rider ("APC Rider"), of $12.8 million ($10.7 million in the Oklahoma Jurisdiction) from the amount being recovered by the Company from its customers through currently authorized electric rates. The Company consented to this action and in March 2000, the OCC approved the APC Rider for $10.7 million annually.
The second application related to a review of the Generation Efficiency Performance Rider ("GEP Rider"), which, as part of the OCC's order issued in 1997 in connection with the Company's last general rate review (the "1997 Order"), was scheduled for review in March 2000. The Company collected approximately $9.9 million pursuant to the GEP Rider during 2000. The GEP Rider initially was designed so that when the Company's average annual cost of fuel per kwh was less than 96.261 percent of the average non-nuclear fuel cost per kwh of certain other investor-owned utilities in the region, the Company was allowed to collect, through the GEP Rider, one-third of the amount by which the Company's average annual cost of fuel was below 96.261 percent of the average of the other specified utilities. If the Company's fuel cost exceeded 103.739 percent of the stated average, the Company was not allowed to recover one-third of the fuel costs above that average from Oklahoma customers. In April 2000 testimony, the Staff stated that they continued to support incentive programs that reward superior performance, but in their view the existing GEP Rider was not functioning as they had originally envisioned it.
In June 2000, the OCC approved the collection of $6.6 million through the GEP Rider for the time period July 1, 2000 through June 30, 2001 and approved the following four modifications to the GEP Rider: (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. The GEP Rider is to be revised effective July 1 of each year to reflect changes in the relative annual cost of fuel reported for the preceding calendar year.
The final application, relating to fuel cost recoveries, was used by the Staff to address the competitive bid process of the Company's gas transportation needs. In the 1997 Order, the OCC approved a stipulation wherein the Company agreed to initiate a competitive bidding process for gas transportation service to its gas-fired plants with the competitive services commencing no later than April 30, 2000. The 1997 Order also set annual compensation for the Company's transportation services provided by Enogex, at $41.3 million annually until March 1, 2000, at which time the rate would drop to $28.5 million (reflecting removal of the APC Rider, upon the completion of the recovery from customers of the amortization premium paid by the Company when it acquired Enogex in 1986) and remain at that level until competitively-bid gas transportation began. Final firm bids were submitted by Enogex and other pipelines on April 15, 1999. In July 1999, the Company filed an application with the OCC requesting approval of a performance-based rate plan for its Oklahoma retail customers from April 2000 until the introduction of customer choice for electric power in July 2002. As part of this application, the Company stated that Enogex had submitted the only viable bid ($33.4 million per year) for gas transportation to the Company's six gas-fired power plants that were the subject of the competitive bid. As part of its application to the OCC, the Company offered to discount Enogex's bid from $33.4 million annually to $25.2 million annually. The Company has executed a gas transportation contract with Enogex under which Enogex continues to serve the needs of the Company's power plants at a price to be paid by the Company of $33.4 million annually and, if the Company's proposal had been approved by the OCC, the Company would have recovered a portion of such amount ($25.2 million) from its customers. The Company negotiated with the Staff, the Office of the Oklahoma Attorney General and a coalition of industrial customers in an effort to settle all issues (including the competitive bid process) associated with its application for a performance-based rate plan. When these negotiations failed, the Company withdrew its application, which withdrawal was approved by the OCC in December 1999.
In July 2000, the Company entered into a stipulation (the "Stipulation") with the Staff, the Office of the Attorney General and a coalition of industrial customers regarding the competitive bid process of the Company's gas transportation service. The Stipulation (which, with one exception, was signed by all parties to the proceeding) would permit the Company to recover $25.2 million annually for gas transportation services to be provided by Enogex pursuant to the competitive bid process. The Stipulation was presented for approval to an Administrative Law Judge ("ALJ") in September 2000, and the ALJ recommended its approval. However, at a hearing on September 28, 2000, the OCC chose to delay the decision concerning the Stipulation and two of the three commissioners expressed concern over the competitive bid process. The Company cannot predict what further action the OCC may take. The Company believes that the competitive bid process was appropriate and is currently collecting $28.5 million on an annual basis through its base rates and APC Rider for gas transportation services from Enogex for the power plant requirements covered by the competitive bid.
On February 13, 1998, the APSC Staff filed a motion for a show cause order to review the Company's electric rates in the State of Arkansas. The Staff recommended a $3.1 million annual rate reduction (based on a test year ended December 31, 1996). The Staff and the Company reached a settlement for a $2.3 million annual rate reduction, which was approved by the APSC in August 1999.
State Restructuring Initiatives
Oklahoma: As previously reported, Oklahoma enacted in April 1997 the Electric Restructuring Act of 1997 (the "Act") which is designed to provide for choice by retail customers of their electric supplier by July 1, 2002. In 1998 and 1999, various amendments to the Act were enacted. Additional implementing legislation needs to be adopted by the Oklahoma Legislature to address many specific issues associated with the Act and deregulation. If implemented as proposed, the Act will significantly affect the Company's future operations. The following summary of the Act does not purport to be complete and is subject to the specific provisions of the Act, which is codified at Sections 190.2 et. seq. of Title 17 of the Oklahoma Statutes.
The Act consists of eight sections, with Section 1 designating the name of the Act. Section 2 describes the purposes of the Act, which is generally to restructure the electric industry to provide for more competition and, in particular, to provide for the orderly restructuring of the electric utility industry in the State of Oklahoma in order to allow direct access by retail consumers to the competitive market for the generation of electricity while maintaining the safety and reliability of the electric system in the state.
The primary goals of a restructured electric utility industry, as set forth in Section 2 of the Act, are as follows:
Section 3 of the Act sets forth various definitions and exempts in large part several electric cooperatives and municipalities from the Act unless they choose to be governed by it.
Sections 4, 5 and 6 of the Act are designed to implement the goals of the Act and provide for various studies and task forces to assess the issues and consequences associated with the proposed restructuring of the electric utility industry. In Section 4, the Joint Electric Utility Task Force (the "Joint Task Force"), which is described below, was directed to undertake a study of all relevant issues relating to restructuring the electric utility industry in Oklahoma including, but not limited to, the issues set forth in Section 4, and to develop a proposed electric utility framework for Oklahoma. The OCC is prohibited from promulgating orders relating to the restructuring without prior authorization of the Oklahoma Legislature. Also, in developing a framework for a restructured electric utility industry, the OCC is to adhere to fourteen principles set forth in Section 4, including the following:
Subject to the principles set forth in Section 4, the Joint Task Force was directed to prepare a four-part study. This study, which was completed in 1999, addressed: (i) technical issues (including reliability, safety, unbundling of generation, transmission and distribution services, transition issues and market power); (ii) financial issues (including rates, charges, access fees, transition costs and stranded costs); (iii) consumer issues (such as the obligation to serve, service territories, consumer choices, competition and consumer safeguards); and (iv) tax issues (including sales and use taxes, ad valorem taxes and franchise fees).
Section 5 of the Act directed the Joint Task Force to study and submit a report on the impact of the restructuring of the electric utility industry on state tax revenues and all other facets of the current utility tax structure on the state and all political subdivisions of the state. This study also was completed in 1999. The Oklahoma Tax Commission and the OCC are precluded from issuing any rules on such matters without the approval of the Oklahoma Legislature. Also, the Act requires the establishment, on or before July 1, 2002, of a uniform tax policy that allows all competitors to be taxed on a fair and equitable basis.
Section 6 created the Joint Task Force, which consisted of seven members from the Oklahoma Senate and seven members from the Oklahoma House of Representatives. The Joint Task Force was directed to undertake the studies set forth in Sections 4 and 5 of the Act. The Joint Task Force is permitted to make final recommendations to the Governor and Oklahoma Legislature. The Joint Task Force is also empowered to retain consultants to study the creation of an Independent System Operator, which would coordinate the physical supply of electricity throughout Oklahoma and maintain reliability, security and stability of the bulk power system. In addition, such study shall assess the benefits of establishing a power exchange that would operate as a power pool allowing power producers to compete on common ground in Oklahoma. In fulfilling its tasks, the Joint Task Force can appoint advisory councils made up of electric utilities, regulators, residential customers and other constituencies.
Section 7 provides generally that, with respect to electric distribution providers, no customer switching will be allowed from the effective date of the Act until July 1, 2002, except by mutual consent. It also provides that any municipality that fails to become subject to the Act will be prohibited from selling power outside its municipal limits, except from lines owned on the effective date of the Act. Furthermore, this section provides generally that out-of-state suppliers of electricity and their affiliates who make retail sales of electricity in Oklahoma, through the use of transmission and distribution facilities of in-state suppliers, must provide equal access to their transmission and distribution facilities outside of Oklahoma. Section 8 sets forth the effective date of the Act as April 25, 1997.
The Act was modified during the 1999 session of the Oklahoma Legislature to clarify certain ambiguities by defining key terms in the Act.
Additional implementing legislation needs to be adopted by the Oklahoma Legislature to address many specific issues associated with the 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. The Company cannot predict what, if any, legislation will be adopted at the next legislative session. The Company intends to participate actively in the legislative process and expects the scheduled start date for customer choice of July 1, 2002 to be postponed.
Arkansas: In April 1999, Arkansas became the 18th state to pass a law ("the Restructuring Law") calling for restructuring of the electric utility industry at the retail level. The Restructuring Law, like the Oklahoma law, will significantly affect the Company's future operations. The Company's electric service area includes parts of western Arkansas, including Fort Smith, the second-largest metropolitan market in the state. The Restructuring Law initially targeted customer choice of electricity providers by January 1, 2002. In February 2001, the 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. The Restructuring Law also provides that utilities owning or controlling transmission assets must transfer control of such transmission assets to an independent system operator, independent transmission company or regional transmission group, if any such organization has been approved by the FERC. Other provisions of the Restructuring Law permit municipal electric systems to opt in or out, permit recovery of stranded costs and transition costs and require filing of unbundled rates for generation, transmission, distribution and customer service. The Company filed preliminary business separation plans with the APSC on August 8, 2000. The APSC has established a timetable to establish rules implementing the Arkansas restructuring statutes.
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 charged to substantially all of the Company's electric customers through automatic fuel adjustment clauses, which are subject to periodic review by the OCC, the APSC and the FERC. In March 2000, the OCC approved the APC Rider for $10.7 million annually. As previously discussed, the purpose of this rider is to credit the Oklahoma retail customers for the completion of the OCC authorized recovery of the premium paid by the Company when it acquired Enogex in 1986. The APC Rider is applicable to each Oklahoma retail rate schedule to which the Company's fuel cost adjustment clause applies.
National Energy Legislation
Federal law imposes numerous responsibilities and requirements on the Company. The Public Utility Regulatory Policies Act of 1978 requires electric utilities, such as the Company, to purchase electric power from, and sell electric power to, qualified cogeneration facilities and small power production facilities ("QFs"). Generally stated, electric utilities must purchase electric energy and production capacity made available by QFs 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 QFs 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 QFs to supplement or back up those facilities' own generation.
The Energy Policy Act of 1992 ("Energy Act"), among other things, authorized the FERC to order transmitting utilities to provide transmission services to any electric utility, Federal power marketing agency, or any other person generating electric energy for sale or resale, at transmission rates set by the FERC. The Energy Act also was designed to promote competition in the development of wholesale power generation in the electric industry.
Subsequently, FERC issued Order 888 and Order 889 to facilitate third-party utilization of the transmission grid as the vehicle for developing a more competitive wholesale bulk power market. Order 888 requires all transmission owners to (i) offer comparable open-access transmission service for wholesale transactions under a tariff of general applicability on file at FERC and (ii) take transmission service for their own wholesale sales under their open-access tariff. Order 889 requires electric utilities to functionally separate their transmission and reliability functions from their wholesale power marketing functions. Order 889 also required electric utilities to develop and maintain an Open Access Same-Time Information System ("OASIS") to ensure that transmission customers have access to transmission information, through electronic means, that will enable them to obtain open-access transmission service on a basis comparable to a transmitting utility's own use of its system.
In December 1999, FERC issued Order 2000 to advance the formation of Regional Transmission Organizations ("RTO"). The rule requires that each public utility that owns, operates or controls facilities for the transmission of electric energy in interstate commerce file by October 15, 2000, a proposal with respect to forming and participating in an RTO. The FERC also codified minimum characteristics and functions that a transmission entity must satisfy in order to be considered an RTO. 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 a RTO. The Company intends to meet its obligation under Order 2000 and under the restructuring law in Arkansas by joining the RTO being formed by the SPP. The transfer of operational control of the Company's transmission system to a FERC-approved RTO is not expected to significantly impact the Company's financial results. Yet, it is expected to increase the markets in which the Company can sell power at wholesale and, at the same time, to increase competition in such wholesale markets. As a low-cost producer of electricity with two of the most efficient power plants in the country, the Company expects to remain a competitive supplier of electricity.
Another impact of complying with FERC's Order 888 is a requirement for utilities to offer a transmission tariff that includes network transmission service ("NTS") to transmission customers. NTS allows transmission service customers to fully integrate load and resources on an instantaneous basis, in a manner similar to how the Company has historically integrated its load and resources. Under NTS, the Company and participating customers share the total annual transmission cost for their combined joint-use systems, net of related transmission revenues, based upon each company's share of the total system load. Management expects minimal annual expenses as a result of Orders 888 and 889.
Regulatory Assets and Liabilities
As discussed previously, Oklahoma and Arkansas enacted legislation that will restructure the electric utility industry in those states, assuming that all the conditions in the legislation are met. This legislation would deregulate the Company's electric generation assets and the continued use of Statement of Financial Accounting Standards ("SFAS") No. 71, "Accounting for the Effects of Certain Types of Regulation", with respect to the related regulatory assets may no longer be appropriate. 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 $29 million, depending on the transition mechanisms developed by the legislature for the recovery of all or a portion of these net regulatory assets.
The enacted Oklahoma and Arkansas legislation does 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 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.
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 Arkansas, and other factors are expected to significantly 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.
RATE STRUCTURE, LOAD GROWTH
AND RELATED MATTERS
Two of the Company's primary goals are: (i) to increase electric revenues by attracting and expanding job-producing businesses and industries; and (ii) to encourage the efficient use of electrical energy by all of the Company's customers. In order to meet these goals, the Company has reduced and restructured its rates to its customers. At the same time, the Company had implemented numerous energy efficiency programs and tariff schedules. In 2000, these programs and schedules included: (i) the "Surprise Free Guarantee" program, which guarantees residential customers comfort and annual energy consumption for heating, cooling and water heating for new homes built to energy efficient standards; (ii) a load curtailment rate for industrial and commercial customers who can demonstrate a load curtailment of at least 500 kilowatts; and (iii) the time-of-use rate schedules for various commercial, industrial and residential customers designed to shift energy usage from peak demand periods during the hot summer afternoon to non-peak hours.
The Company made it's pilot Real Time Pricing ("RTP") program permanent in 1999. The program was first implemented in 1996 for qualifying industrial and commercial customers. This tariff gives customers additional options on total kilowatt-hour growth and the control of growth of peak demand. RTP is a tariff option, which prices electricity so that the current price varies hourly with short notice to reflect current expected costs. The RTP technique will allow a measure of competitive pricing, a broadening of customer choice, the balancing of electricity usage and capacity in the short-and long-term, and assist customers in controlling their costs.
The Company's 2000 marketing efforts included geothermal heat pumps, electrotechnologies, electric food service promotion and a heat pump promotion in the residential, commercial and industrial markets. The Company works closely with individual customers to provide the best information on how current technologies can be combined with the Company's marketing programs to maximize the customer's benefit.
FUEL SUPPLY
During 2000, approximately 74 percent of the Company-generated energy was produced by coal-fired units and 26 percent by natural gas-fired units. A slight decline in the percentage of coal generation in future years is expected to result from increases in natural gas-fired generation required to meet growing energy needs while coal generation will remain fairly constant. Over the last five years, the average cost of fuel used, by type, per million Btu was as follows:
2000 1999 1998 1997 1996
- --------------------------------------------------------------------------------------------------------
Coal............................ $0.87 $0.85 $0.85 $0.84 $0.83
Natural Gas..................... $4.93 $3.14 $2.83 $3.60 $3.61
Weighted Avg.................... $1.96 $1.54 $1.48 $1.39 $1.45
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-Fired Units: All the Company coal units, with an aggregate capability of 2,531 megawatts, are designed to burn low sulfur western coal. The Company purchases coal primarily under long-term contracts. During 2000, the Company purchased 10.2 million tons of coal from the following Wyoming suppliers: Kennecott Energy Company, Thunder Basin Coal Company, Powder River Coal Company, and Triton Coal Company. The combination of all coal has a weighted average sulfur content of 0.3 percent and can be burned in these units under existing federal, state and local environmental standards (maximum of 1.2 pounds of sulfur dioxide per million Btu) without the addition of sulfur dioxide removal systems. Based upon the average sulfur content, the Company units have an approximate emission rate of 0.63 pounds of sulfur dioxide per million Btu. 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 by optimizing the boiler operations at both the Sooner and Muskogee generating plants. See "Environmental Matters" for a discussion of an environmental proposal that, if implemented as proposed, could inhibit the Company's ability to use coal as its primary boiler fuel.
Gas-Fired Units: For calendar year 2001, the Company utilized a Request for Bid (RFB) to acquire natural gas supplies through June 2002. Successful bids were accepted that are expected to supply approximately 38% of the Company's annual gas requirements. The Company will request bids for additional summer gas supplies. The additional gas requirements will be secured through monthly and day-to-day purchases as needed.
In 1993, the Company began utilizing a natural gas storage facility that allows the Company to optimize economic dispatch of its units. This allows the Company to attain a fuel mix that provides the lowest possible overall cost of fuel.
ENVIRONMENTAL MATTERS
The Company's management believes 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 $50.5 million during 2001, compared to approximately $47.1 million utilized in 2000. Approximately $2.5 million of the Company's construction expenditures budgeted for 2001 are to comply with environmental laws and regulations. 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.
As required by Title IV of the Clean Air Act Amendments of 1990 ("CAAA"), the Company has completed installation and certification of all required continuous emissions monitors ("CEMs") at its generating stations. The Company submits emissions data quarterly to the Environmental Protection Agency ("EPA") as required by the CAAA. Phase II sulfur dioxide ("SO2") emission requirements affected the Company beginning in the year 2000. The Company met the SO2 limits without additional capital expenditures through the purchase of low sulfur coal. In 2000, the Company's SO2 emissions were well below the allowable limits.
With respect to the nitrogen oxide ("NOx") regulations of Title IV of the CAAA, OG&E committed to meeting a 0.45 lbs/mmbtu NOx emission level in 1997 on all coal-fired boilers. As a result, 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 2000 was 0.37 lbs/mmbtu.
The Company has submitted all of its required Title V permit applications. As a result of the Title V Program, the Company paid approximately $0.4 million in fees in 2000.
Other potential air regulations have emerged that could impact the Company. On December 14, 2000, the EPA announced that it is appropriate and necessary to regulate mercury emissions from coal-fired utility boilers. If the EPA decides to regulate mercury emissions, limits on the amount of mercury emitted are expected to be finalized by December 2004 with the Company's compliance required by 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. However, the standards were challenged in court and the ozone standard was subsequently remanded back to the EPA for further consideration. The EPA appealed the decision to the U.S. Supreme Court and the Supreme Court issued its decision on February 27, 2001. In its decision, the Supreme Court remanded the case to the District of Columbia Court of Appeals, in part, to allow additional challenges to the standards. If the proposed standard is eventually upheld, then it is likely that Tulsa County will fail to meet the new standard for ozone. The EPA has already indicated that in addition to Tulsa County, Muskogee County will also be considered non-attainment because of its impact on Tulsa. If this occurs NOx reductions at the Company's Muskogee Generating Station could be required. In addition, the EPA projects that Muskogee, Kay, Tulsa and Comanche Counties in Oklahoma would fail to meet the standard for particulate matter. If reductions are required in Muskogee, Kay and Oklahoma Counties, significant capital expenditures could be required by the Company.
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 EPA 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 Sooner and Muskogee Generation Stations.
In December 1997, the United States was a signatory to the Kyoto Protocol for the reduction of greenhouse gases that contribute to global warming. The U.S. committed to a seven percent reduction from the 1990 levels. While it appears that the Senate will not ratify the Kyoto Protocol, momentum is gaining in the federal government for some type of reduction in the level of carbon dioxide emissions. If legislation is passed, it 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 2000, the Company obtained refunds of approximately $365,000 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 reuse of existing materials. Similar savings are anticipated in future years.
The Company has received approvals to renew its Oklahoma Pollution Discharge Elimination System ("OPDES") permits for all facilities except one, which is awaiting final regulatory action. All of the renewed permits issued to date offer greater operational flexibility than those in the past. In addition, the Company has made application for a new OPDES permit to cover gas turbine generating units that were constructed at one of its existing plants.
The Company requested that the State agency responsible for the development of Water Quality Standards remove the agriculture beneficial use classification from one of its cooling water reservoirs. Without removal of this classification, the Company facility could be subjected to costly treatment and/or facility reconfiguration requirements. Both the State and the EPA have now approved this request.
The Company remains a party to one action brought by the EPA concerning cleanup of a disposal site for hazardous and toxic waste. See Item 3 "Legal Proceedings."
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.
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 5,781 megawatts. The following table sets forth information with respect to electric generating facilities, all of which are located in Oklahoma:
Unit Station
Year Capability Capability
Station &Unit Fuel Installed (Megawatts) (Megawatts)
- -------------- ---- --------- ----------- -----------
Seminole 1 Gas 1971 517.0
2 Gas 1973 505.0
3 Gas 1975 496.0 1,518
Muskogee 3 Gas 1956 171.0
4 Coal 1977 503.0
5 Coal 1978 500.0
6 Coal 1984 516.0 1,690
Sooner 1 Coal 1979 500.0
2 Coal 1980 512.0 1,012
Horseshoe 6 Gas 1958 171.0
Lake 7 Gas 1963 234.0
8 Gas 1969 402.0
9 Gas 2000 45.0
10 Gas 2000 45.0 897
Mustang 1 Gas 1950 56.0
2 Gas 1951 53.0
3 Gas 1955 118.0
4 Gas 1959 258.0
5 Gas 1971 63.0 548
Conoco 1 Gas 1991 32.0
2 Gas 1991 31.0 63
Enid 1 Gas 1965 11.0
2 Gas 1965 8.0
3 Gas 1965 12.0
4 Gas 1965 12.0 43
Woodward 1 Gas 1963 10.0 10
-----------
Total Generating Capability (all stations) 5,781
===========
At December 31, 2000, the Company's transmission system included: (i) 64 substations with a total capacity of approximately 18 million kVA and approximately 3,996 structure miles of lines in Oklahoma; and (ii) six substations with a total capacity of approximately 2.3 million kVA and approximately 241 structure miles of lines in Arkansas. The Company's distribution system included: (i) 299 substations with a total capacity of approximately 4.4 million kVA, 22,326 structure miles of overhead lines, 1,739 miles of underground conduit and 7,076 miles of underground conductors in Oklahoma; and (ii) 31 substations with a total capacity of approximately 731,000 kVA, 1,861 structure miles of overhead lines, 198 miles of underground conduit and 411 miles of underground conductors in Arkansas.
During the three years ended December 31, 2000, the Company's gross property, plant and equipment additions approximated $334.8 million and gross retirements approximated $113.8 million. These additions were provided by internally generated funds from operating cash flows, permanent financing and short-term borrowings. The additions during this three-year period amounted to approximately 8.6 percent of total property, plant and equipment at December 31, 2000.
Item 3. Legal Proceedings.
1. On January 11, 1993, the Company received a Section 107 (a) Notice Letter from the EPA, Region VI, as authorized by the CERCLA, 42 USC Section 9607 (a), concerning the Double Eagle Refinery Superfund Site located at 1900 NE First Street in Oklahoma City, Oklahoma. The EPA has named the Company and 45 others as PRPs. Each PRP could be held jointly and severally liable for remediation of this site.
On February 15, 1996, the Company elected to participate in the de minimis settlement of EPA's Administrative Order on Consent. This would limit the Company's financial obligation and also would eliminate its involvement in the design and implementation of the site remedy. A third party is currently contesting the Company's participation as a de minimis party. Regardless of the outcome of this issue, the Company believes that its ultimate liability for this site will not be material primarily due to the limited volume of waste sent by the Company to the site.
2. As previously reported, on September 18, 1996, Trigen-Oklahoma City Energy Corporation ("Trigen") sued the Company in the United States District Court, Western District of Oklahoma, Case No. CIV-96-1595-M. Trigen alleged six causes of action: (i) monopolization in violation of Section 2 of the Sherman Act; (ii) attempt to monopolize in violation of Section 2 of the Sherman Act; (iii) acts in restraint of trade in violation of Oklahoma law, 79 O.S. 1991, § 1; (iv) discriminatory sales in violation of 79 O.S. 1991, § 4; (v) tortious interference with contract; and (vi) tortious interference with a prospective economic advantage. On December 21, 1998, the jury awarded Trigen in excess of $30 million in actual and punitive damages. On February 19, 1999, the trial court entered judgment in favor of Trigen as follows: (i) $6.8 million for various antitrust violations, (ii) $4 million for tortious interference with an existing contract, (iii) $7 million for tortious interference with a prospective economic advantage and (iv) $10 million in punitive damages. The trial judge, in a companion order, acknowledged that the portions of the judgment could be duplicative, that the antitrust amounts could be tripled and that parties should address these issues in their post-trial motions. On January 25, 2000, a trial judge rejected the Company's post-trial motions to reverse the jury verdict or to grant the Company a new trial. The judge did, however, reduce the original $30 million judgment against the Company to $20 million. On February 4, 2000, the Company filed a notice of appeal. In addition, Trigen has filed a motion seeking attorneys' fees and costs in an amount over $3 million. Trigen will not be entitled to attorneys' fees or costs unless it prevails on appeal. Oral argument was heard by the Tenth Circuit on January 22, 2001. A decision is not expected for several months. While the outcome of the appeal is uncertain, legal counsel and management believe that it is not probable that Trigen will ultimately succeed in preserving the verdicts or judgment. Accordingly, the Company has not accrued any loss associated with the damages awarded. The Company believes that the ultimate resolution of this case will not have a material adverse effect on the Company's financial position or results of operations.
3. 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, eighteen 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 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, OG&E filed a Motion to Dismiss Case No. CJ-97-829-01 for failure to state claims upon which relief may be granted. This motion is currently pending. While the Company cannot predict the precise outcome of this proceeding, the Company believes at the present time that this lawsuit is without merit and intends to vigorously defend this case.
4. United States of America ex rel., Jack J. Grynberg v. Enogex Inc., Enogex Services Corporation (now, Energy Resources) and Oklahoma Gas and Electric 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; (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 or any of the other Grynberg qui tam actions.
On November 16, 1999, the Multidistrict Litigation Panel ("MDL Panel") entered its order transferring and consolidating for pretrial purposes approximately 76 other similar actions filed in nine other Federal Courts. The consolidated cases are now before the United States District Court for the District of Wyoming.
On November 17, 1999, the Company filed a motion to dismiss, seeking: (i) a stay of discovery until after the dispositive motions are resolved; and (ii) dismissal of the complaint on various basis under the Federal Rules of Civil Procedure. A number of other defendants adopted the Company's pleadings or filed similar motions. On December 22, 1999, the Company joined a number of other Defendants in filing Defendants' Statement of Points and Authorities regarding discovery issues. Grynberg's responses to all motions to dismiss were filed on January 14, 2000, and the Company's reply and those of other defendants were filed on February 14, 2000. A hearing on the motions to dismiss was held on March 17, 2000. The Court has not yet ruled on the motions to dismiss.
On April 10, 2000, the MDL Panel transferred another qui tam case (Quinque Operating Company, et al. v. Enogex Services Corporation, Enogex, Inc., Transok LLC, Transok, Inc., and Oklahoma Gas & Electric Company, et al.) ("Quinque") to Judge Downes in Wyoming and the MDL Panel consolidated it with this case.
On July 27, 2000, the Department of Justice ("DOJ") filed a Motion to Dismiss certain of Grynberg's claims on the basis Grynberg was not the first to file such qui tam allegations. The DOJ's Motion to Dismiss was heard on February 22, 2001.
On October 6, 2000, the MDL Panel transferred two additional qui tam cases (Harold E. Wright, et al. v. AGIP Petroleum, et al., E.D. Texas, C.A. No. 9:98-30 and M. Glenn Ousterhaudt, III, et al. v. Amoco Production, et al., E.D. Texas, C.A. No. 9:98-101) to Judge Downes in Wyoming, and the MDL consolidated them with this case and the Quinque case. The Company has not been named as a party in either the Wright or Ousterhaudt cases; therefore, no information regarding these two cases is being provided at this time.
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.
5. On September 24, 1999, the Company was served with an Amended Class Action Petition filed in United States District Court, State of Kansas by Quinque Operating Company, on behalf of itself and others, alleging approximately 200 defendants, including the Company, Enogex and two subsidiaries of Enogex, including Transok, have improperly and intentionally mismeasured gas (both volume and Btu content) purchased from all lands in the United States except from federal and Indian lands. Plaintiffs claim (i) underpayment by the Company and all other Defendants of gas royalties claimed to be owed to the Plaintiffs and the punitive class; (ii) breach of contract; (iii) negligence or intentional misrepresentation; (iv) civil conspiracy; (v) fraud; and (vi) breach of fiduciary duty. Plaintiffs seek the following damages: (i) actual damages in excess of $75,000; (ii) punitive damages; (iii) certification of the class; and (iv) injunction to prevent mismeasurement in the future.
On October 5, 1999, the Company filed its Notice with the MDL Panel advising the MDL Panel of a possible tag-along action to the Grynberg qui tam actions discussed in Item 3, number 4 above. On March 30, 2000, the MDL Panel heard oral argument regarding the transfer of this action as a tag-along case; and on April 10, 2000, the MDL Panel transferred this case to Judge Downes in Wyoming and consolidated it with the Grynberg cases discussed above.
On September 8, 2000, Plaintiffs filed a Motion for Expedited Hearing on Motion to Remand. On January 12, 2001 the Court issued its oral order granting Plaintiff's Motion to Remand. The Court is currently reviewing a Motion to Reconsider before sending the Order to the Stevens County Clerk, effectively remanding the case back to the Kansas State Court.
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.
Executive Officers of the Registrant.
The following persons were Executive Officers of the Registrant as of March 15, 2001:
Name Age Title
- -------------------- --- --------------------------------
Steven E. Moore 54 Chairman of the Board, President
and Chief Executive Officer
Al M. Strecker 57 Executive Vice President and
Chief Operating Officer
James R. Hatfield 43 Senior Vice President and
Chief Financial Officer
Jack T. Coffman 57 Senior Vice President - Power
Supply
Melvin D. Bowen, Jr. 59 Vice President - Power Delivery
Michael G. Davis 51 Vice President - Marketing and
Customer Care
Irma B. Elliott 62 Vice President and
Corporate Secretary
Steven R. Gerdes 44 Vice President - Shared
Services
David J. Kurtz 39 Vice President - Business
Development
Donald R. Rowlett 43 Vice President and Controller
Don L. Young 60 Controller Corporate Audits
Eric B. Weekes 49 Treasurer
No family relationship exists between any of the Executive Officers of the Registrant. Messrs. Moore, Strecker, Hatfield, Davis, Gerdes, Kurtz, Rowlett, Young, Weekes and Ms. Elliott are also officers of Energy Corp. Each Officer is to hold office until the Board of Directors meeting following the next Annual Meeting of Shareowners, currently scheduled for May 24, 2001.
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 1996-Present: Chairman of the Board,
President and Chief
Executive Officer
Al M. Strecker 1998-Present: Executive Vice President and
Chief Operating Officer
1996-1998: 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
1997-1999: Vice President and Treasurer
1996-1997: Treasurer
Jack T. Coffman 1999-Present: Senior Vice President -
Power Supply
1996-1999: Vice President -
Power Supply
Melvin D. Bowen, Jr. 1996-Present: Vice President -
Power Delivery
Michael G. Davis 1998-Present: Vice President - Marketing
and Customer Care
1996-1998: Vice President -
Marketing and Customer
Services
Irma B. Elliott 1996-Present: Vice President and
Corporate Secretary
Steven R. Gerdes 1998-Present: Vice President - Shared
Services
1997-1998: Director - Shared Services
1997: Manager - Enterprise Support
1996-1997: Manager - Purchasing and
Material Management
David J. Kurtz 1999-Present: Vice President - Business
Development
1997-1999: Vice President - Business
Development -
Enogex Inc.
1996-1997: Director - Gas Supply -
Enogex Inc.
Donald R. Rowlett 1999-Present: Vice President and Controller
1996-1999: Controller Corporate
Accounting
Don L. Young 1996-Present: Controller Corporate
Audits
Eric B. Weekes 2000-Present: Treasurer
1997-2000: Treasurer - Illinois Power
and Light
1996-1997: Senior Financial Manager -
Kraft Foods Inc.
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.
Item 6. Selected Financial Data.
HISTORICAL DATA
2000 1999 1998 1997 1996
----------------------------------------------------------------------------
SELECTED FINANCIAL DATA
(dollars in thousands except
for per share data)
Operating revenues..................... $ 1,453,585 $ 1,286,844 $ 1,312,078 $ 1,191,690 $ 1,200,337
Operating expenses..................... 1,182,447 1,017,280 996,281 945,652 952,811
------------ ------------ ------------ ------------ ------------
Operating income....................... 271,138 269,564 315,797 246,038 247,526
Other income and (deductions).......... (1,624) 381 (5) 3,627 (1,429)
Interest charges....................... 46,780 45,939 48,871 55,947 59,566
------------ ------------ ------------ ------------ ------------
Earnings before income taxes........... 222,734 224,006 266,921 193,718 186,531
Income tax expense..................... 80,342 84,965 106,583 72,724 69,662
------------ ------------ ------------ ------------ ------------
Net income............................. 142,392 139,041 160,338 120,994 116,869
Preferred dividend requirements........ --- --- 733 2,285 2,302
------------ ------------ ------------ ------------ ------------
Earnings available for common.......... $ 142,392 $ 139,041 $ 159,605 $ 118,709 $ 114,567
============ ============ ============ ============ ============
Long-term debt......................... $ 702,582 $ 593,045 $ 702,912 $ 691,924 $ 709,281
Total assets........................... $ 2,437,449 $ 2,320,660 $ 2,320,097 $ 2,350,782 $ 2,421,241
Earnings per average common share...... $ 3.53 $ 3.44 $ 3.95 $ 2.94 $ 2.84
CAPITALIZATION RATIOS
Common equity.......................... 56.91% 59.99% 54.84% 53.46% 52.57%
Cumulative preferred stock............. --- --- --- 3.09% 3.09%
Long-term debt......................... 43.09% 40.01% 45.16% 43.45% 44.34%
INTEREST COVERAGES
Before federal income taxes
(including AFUDC).................... 5.54X 5.80X 6.34X 4.43X 4.09X
(excluding AFUDC).................... 5.50X 5.79X 6.32X 4.42X 4.08X
After federal income taxes
(including AFUDC).................... 3.91X 3.98X 4.21X 3.14X 2.94X
(excluding AFUDC).................... 3.95X 3.96X 4.19X 3.13X 2.93X
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations.
Management's Discussion and Analysis.
Overview
Percent Change
From Prior Year
----------------
(thousands except per share amounts) 2000 1999 1998 2000 1999
===============================================================================================================
Operating revenues................................ $1,453,585 $1,286,844 $1,312,078 13.0 (1.9)
Earnings available for common stock............... $ 142,392 $ 139,041 $ 159,605 2.4 (12.9)
Average shares outstanding........................ 40,379 40,379 40,379 --- ---
Earnings per average common share................. $ 3.53 $ 3.44 $ 3.95 2.6 (12.9)
Dividends paid per share.......................... $ 2.56 $ 2.56 $ 3.90 --- (34.4)
===============================================================================================================
Earnings for 2000 increased 2.6 percent from $3.44 per share in 1999 to $3.53 per share in 2000. The increase was primarily the result of higher revenues from kilowatt-hour sales to Company customers ("system sales") due to more favorable weather in the last six months of 2000. Revenues also increased due to the recovery of higher fuel costs. The higher revenues were partially offset by lower recoveries under the GEP Rider and the APC Rider. The GEP Rider allows the Company to retain part of the fuel savings achieved through cost efficiencies and is discussed in more detail below. The APC Rider, which was implemented in March 2000, is discussed in more detail below. The 1999 decrease is primarily the result of lower revenues due to cooler weather, the GEP Rider and lower margin sales to other utilities and power marketers ("off-system sales").
The Company's business has been and will continue to be affected by competitive changes to the utility industry. Significant changes already have occurred in the wholesale electric markets at the Federal level. In Oklahoma, legislation was passed in 1997 to provide for the orderly restructuring of the electric industry with the goal to provide retail customers with the ability to choose their electric suppliers by July 1, 2002. In April 1999, Arkansas became the 18th state to pass a law calling for restructuring of the electric utility industry at the retail level. The law initially targeted customer choice of electricity providers by January 1, 2002, but in February 2001, the law was amended to delay customer choice until October 1, 2003. It now appears that customer choice of electricity suppliers may also be delayed in Oklahoma beyond 2002. See "Competition; Regulation" for further discussion of these developments. The Company's electric service area includes parts of western Arkansas, including Fort Smith, the second-largest metropolitan market in the state.
The following discussion and analysis presents factors which had a material effect on the Company's operations and financial position during the last three years and should be read in conjunction with the Financial Statements and Notes thereto. Trends and contingencies of a material nature are discussed to the extent known and considered relevant. Except for the historical statements contained herein, the matters discussed in the following discussion and analysis, 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", "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; 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 that affect cost and investment recovery, have an impact on rate structures and affect the speed and degree to which competition enters the Company's markets; and the other risk factors listed in the reports filed by the Company with the Securities and Exchange Commission.
Results of Operations
REVENUES
Percent Change
From Prior Year
----------------
(thousands) 2000 1999 1998 2000 1999
====================================================================================================================
Sales of electricity to Company customers......... $ 1,440,637 $ 1,258,950 $ 1,274,643 14.4 (1.2)
Off-system sales.................................. 12,948 27,894 37,435 (53.6) (25.5)
- -------------------------------------------------------------------------------------------------
Total operating revenues..................... $ 1,453,585 $ 1,286,844 $ 1,312,078 13.0 (1.9)
====================================================================================================================
System megawatt-hour sales........................ 25,001,686 23,468,130 23,642,599 6.5 (0.7)
Off-system megawatt-hour sales.................... 256,358 374,027 727,601 (31.5) (48.6)
- -------------------------------------------------------------------------------------------------
Total megawatt-hour sales.................... 25,258,044 23,842,157 24,370,200 5.9 (2.2)
====================================================================================================================
Revenues from sales of electricity are somewhat seasonal, with a large portion of the Company's annual electric revenues occurring during the summer months when the electricity needs of its customers increase. Actions of the regulatory commissions that set the Company's electric rates will continue to affect the Company's financial results. The commissions also have the authority to examine the appropriateness of the Company's recovery from its customers of fuel costs, which include the transportation fees that the Company pays Enogex for transporting natural gas to the Company's generating units. See "Competition; Regulation" and Note 9 of Notes to Financial Statements for a discussion of the impact of the OCC's February 11, 1997, rate order on these transportation fees.
Operating revenues increased $166.7 million or 13.0 percent during 2000. This increase was primarily due to an increase in system sales from more favorable weather and the recovery of higher fuel costs. The increased revenue from system sales was partially offset by a 53.6 percent decrease in off-system sales. The decline in revenue from off-system sales resulted from a reduction in both volumes and prices, however, off-system sales are generally priced much lower per kilowatt-hour and have less impact on operating revenues than system sales. Revenues were also unfavorably affected by lower recoveries under the GEP Rider and the APC Rider. During 1999, operating revenues decreased primarily due to a decrease in system sales and off-system sales both of which were higher in 1998 because of the record heat experienced in the summer of 1998. Lower recoveries under the GEP Rider also contributed to the decrease.
EXPENSES AND OTHER ITEMS
Percent Change
From Prior Year
----------------
(dollars in thousands) 2000 1999 1998 2000 1999
=================================================================================================================
Fuel.............................................. $ 489,049 $ 350,814 $ 356,781 39.4 (1.7)
Purchased power................................... 263,328 249,203 240,542 5.7 3.6
Other operation and maintenance................... 267,353 253,312 239,614 5.5 5.7
Depreciation and amortization..................... 117,257 119,059 116,214 (1.5) 2.4
Taxes other than income........................... 45,460 44,892 43,130 1.3 4.1
- ----------------------------------------------------------------------------------------------
Total operating expenses..................... $1,182,447 $1,017,280 $ 996,281 16.2 2.1
=================================================================================================================
Total operating expenses increased $165.2 million or 16.2 percent in 2000, primarily due to increases in fuel, purchased power costs and other operation and maintenance.
The Company's 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. Despite this flexibility in 2000, fuel costs increased $138.2 million or 39.4 percent primarily due to a 29.9 percent increase in the average cost of fuel burned for generation of electricity and a 7.1 percent increase in total energy generated. During 1999, fuel costs decreased $5.9 million or 1.7 percent primarily due to a 3.4 percent decrease in total energy generated which offset a 1.9 percent increase in the average cost of fuel burned for generation of electricity.
The Company's purchased power costs increased $14.1 million or 5.7 percent in 2000 primarily due to a 9.5 percent increase in the cost of purchased energy per kwh, which offset a 4.3 percent reduction in total energy purchased. During 1999, purchased power costs increased $8.7 million or 3.6 percent due in large part to emergency purchases in the aftermath of tornadoes, on May 3, 1999 and June 1, 1999, which inflicted heavy damage to the Company power supply, transmission and delivery systems. In 1999, the cost of purchased energy per kwh increased 8.7 percent. As required by the Public Utility Regulatory Policy Act ("PURPA"), the Company is currently purchasing power from qualified cogeneration facilities. See Note 8 of Notes to Financial Statements.
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 electric customers through automatic fuel adjustment clauses. The automatic fuel adjustment clauses are subject to periodic review by the OCC, the APSC and the FERC. The OCC, the APSC and the FERC have authority to review the appropriateness of gas transportation charges or other fees the Company pays Enogex, which the Company seeks to recover through the fuel adjustment clause or other tariffs. Also, as explained below, the OCC Staff recently filed an application to review various issues under the Company's fuel adjustment clause in Oklahoma.
The Company has initiated numerous ongoing programs that have helped reduce the cost of generating electricity over the last several years. These programs include: (i) utilizing a natural gas storage facility; (ii) spot market purchases of coal; (iii) renegotiated contracts for coal, gas, railcar maintenance and coal transportation; and (iv) a heat-rate awareness program to produce kilowatt-hours with less fuel. Reducing fuel costs helps the Company remain competitive, which in turn helps the Company's electric customers remain competitive in a global economy.
Other operation and maintenance increased $14 million or 5.5 percent in 2000 primarily due to higher employee benefit costs and higher labor costs. In 1999, other operation and maintenance increased $13.7 million or 5.7 percent primarily due to higher bad debt expense and expenses associated with the record number of tornadoes and severe thunderstorms that inflicted heavy damage to the Company's power supply and transmission and delivery systems.
In 2000, the decrease of $1.8 million or 1.5 percent in depreciation and amortization was due to certain power plant units becoming fully depreciated during the year. The increase of $2.8 million or 2.4 percent in 1999 was due to higher levels of depreciable plant.
In 2000 and 1999, the increase in taxes other than income is primarily attributable to higher ad valorem taxes.
Interest expense increased $0.1 million or 1.8 percent in 2000, primarily due to increased interest on variable rate long-term debt and increased levels of borrowings from Energy Corp. In 1999, interest expense decreased $2.9 million or 6.0 percent primarily due to lower levels of short-term borrowings.
Liquidity, Capital Resources and Contingencies
The primary capital requirements for 2000 and as estimated for 2001 through 2003 are as follows:
(dollars in millions) 2000 2001 2002 2003
=================================================================================================
Construction expenditures
including AFUDC................................. $128.4 $118.0 $118.0 $118.0
Maturities of long-term debt...................... 110.0 --- --- ---
- -------------------------------------------------------------------------------------------------
Total......................................... $238.4 $118.0 $118.0 $118.0
=================================================================================================
The Company's primary needs for capital are related to construction of new facilities to meet anticipated demand for utility service or to replace or expand existing facilities. The Company generally meets its cash needs through a combination of internally generated funds, short-term borrowings from Energy Corp. and permanent financing. The Company previously borrowed funds on a short-term basis, as necessary, by issuing commercial paper or by obtaining short-term bank loans. In 1997, these functions were transferred to Energy Corp. The Company now uses short-term borrowings from Energy Corp. to meet its temporary cash requirements. The Company had $39.2 million in short-term debt outstanding at December 31, 2000.
2000 CAPITAL REQUIREMENTS AND FINANCING ACTIVITIES
Capital requirements were $238.4 million in 2000. Approximately $4.4 million of the 2000 capital requirements were to comply with environmental regulations. This compares to capital requirements of $101.3 million in 1999, of which $1.7 million were to comply with environmental regulations.
During 2000, the Company's primary sources of capital were internally generated funds from operating cash flows and permanent financing. The permanent financing of $110 million was used to refinance a maturing debt issue, as discussed below. Operating cash flow remained strong in 2000 as internally generated funds provided financing for all of the Company's capital expenditures. Variations in accounts receivable and accounts payable are not generally significant indicators of the Company's liquidity, as such variations are primarily attributable to fluctuations in weather in the Company's service territory, which has a direct effect on sales of electricity.
On October 15, 2000, a $110 million series of the Company's 6.25 percent Senior Notes matured. The Company temporarily funded this transaction through short-term borrowings from Energy Corp. On October 23, 2000, the Company issued $110 million of 7.125 percent Senior Notes, Series due October 15, 2005. Net proceeds from this transaction were used to repay the temporary short-term borrowings from Energy Corp.
The Company acquired two gas turbine generators for use at its Horseshoe Lake Generating Stations. These two generators began operation on June 14 and July 16, 2000. Each generator can produce approximately 45 megawatts of additional peak-load generating capacity. The total cost of this project was approximately $45 million.
On July 21, 2000, the Company reactivated two of its generators (which had been idle for several years), at its Mustang Generating Station. These two generators together produce approximately 109 megawatts of additional peak-load generating capacity. The total cost of this reactivation project was approximately $5 million. Together, these four generators at Horseshoe Lake and Mustang increased the Company's generating capacity by approximately 4 percent.
FUTURE CAPITAL REQUIREMENTS
The Company intends to meet its customers' increased electricity needs during the foreseeable future primarily by maintaining the reliability and increasing the utilization of existing capacity, increasing demand-side management efforts and, if necessary, purchasing power from third parties. The Company will continue to evaluate these strategies against the construction of additional peaking units or another base-load generating unit. These evaluations will consider, among other things, the amount of capital requirements and the relative cost of fuel supply, compared to other alternatives. Approximately $2.5 million of the Company's construction expenditures budgeted for 2001 are to comply with environmental laws and regulations.
As discussed in Note 7 of Notes to Financial Statements, the Company recently made several changes to its pension plan, including the addition of a cash balance benefit feature. The cash balance plan may provide lower post-employment pension benefits to employees, which could result in less pension expense being recorded. Over the near term, the Company's cash requirements for the plan are not expected to be materially different than the requirements existing prior to the plan changes. However, as the population of employees included in the cash balance plan feature increases, the Company's cash requirements may be materially different than the requirements under the Company's prior pension plan.
Future financing requirements may be dependent, to varying degrees, upon numerous factors outside the Company's control such as general economic conditions, abnormal weather, load growth, inflation, changes in environmental laws or regulations, rate increases or decreases allowed by regulatory agencies, new legislation and market entry of competing electric power generators.
FUTURE SOURCES OF FINANCING
Management expects that internally generated funds will be adequate over the next three years to meet anticipated construction expenditures. Short-term borrowings will continue to be used to meet temporary cash requirements. At December 31, 2000, Energy Corp. had in place a line of credit for up to $300 million, with $200 million to expire on January 15, 2001, and the remaining $100 million to expire on January 15, 2004. In January 2001, Energy Corp.'s line of credit for $200 million was renewed, with an expiration date of January 15, 2002. The Company has the necessary approvals to incur up to $400 million in short-term borrowings at any one time.
CONTINGENCIES
The Company is defending various claims and legal actions, including environmental actions, which are common to its operations. For a further discussion of these actions, including a lawsuit involving Trigen-Oklahoma City Energy Corporation, see Note 8 of Notes to Financial Statements. As to environmental matters, the Company has been designated as a "potentially responsible party" ("PRP") with respect to two waste disposal sites to which the Company sent materials. Remediation and required monitoring of one of these sites has been completed. While it is not possible to determine the precise outcome of these matters, in the opinion of management, the Company's ultimate liability for these sites will not be material.
Besides the various existing contingencies herein described, and those described in Note 8 of Notes to Consolidated Financial Statements, the Company's ability to fund its future operational needs and to finance its construction program is dependent upon numerous other factors beyond its control, such as general economic conditions, abnormal weather, load growth, inflation, new environmental laws or regulations, and the cost and availability of external financing.
COMPETITION; REGULATION
As previously reported, Oklahoma enacted in April 1997 the Electric Restructuring Act of 1997 (the "Act") which is designed to provide for choice by retail customers of their electric supplier by July 1, 2002. Various amendments to the Act were enacted in 1998 and 1999. Additional implementing legislation needs to be adopted by the Oklahoma Legislature to address many specific issues associated with the Act and with deregulation. If implemented as proposed, the Act will significantly affect the Company's future operations.
The Act directed the Joint Electric Utility Task Force, composed of seven members from the Oklahoma Senate and seven members from the Oklahoma House of Representatives, to undertake a study of all relevant issues relating to restructuring the electric utility industry in Oklahoma and to develop a proposed electric utility framework for Oklahoma. The study was completed in 1999.
Neither the Oklahoma Tax Commission nor the OCC is authorized to issue any rules on such matters without the approval of the Oklahoma Legislature. Other provisions of the Act (i) prohibit customer switching prior to July 1, 2002, except by mutual consent, (ii) prohibit municipalities that do not become subject to the Act, from selling power outside their municipal limits, except from lines owned on April 25, 1997, (iii) require a uniform tax policy be established by July 1, 2002 and (iv) require out-of-state suppliers of electricity and their affiliates who make retail sales of electricity in Oklahoma through the use of transmission and distribution facilities of in-state suppliers to provide equal access to their transmission and distribution facilities outside of Oklahoma. The Act was modified during the 1999 session of the Oklahoma Legislature to clarify certain ambiguities by defining key terms in the act.
As discussed above, additional implementing legislation needs to be adopted by the Oklahoma Legislature to address many specific issues associated with the 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. The Company cannot predict what, if any, legislation will be adopted at the next legislative session. The Company intends to participate actively in the legislative process and expects the scheduled start date for customer choice of July 1, 2002 to be postponed.
In April 1999, Arkansas became the 18th state to pass a law ("the Restructuring Law") calling for restructuring of the electric utility industry at the retail level. The Restructuring Law, like the Oklahoma law, would significantly affect the Company's future operations. The Company's electric service area includes parts of western Arkansas, including Fort Smith, the second-largest metropolitan market in the state. The Restructuring Law initially targeted customer choice of electricity providers by January 1, 2002. In February 2001, the 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. The Restructuring Law also provides that utilities owning or controlling transmission assets must transfer control of such transmission assets to an independent system operator, independent transmission company or regional transmission group, if any such organization has been approved by the FERC. Other provisions of the Restructuring Law permit municipal electric systems to opt in or out, permit recovery of stranded costs and transition costs and require filing of unbundled rates for generation, transmission, distribution and customer service. The Company filed preliminary business separation plans with the APSC on August 8, 2000. The APSC has established a timetable to establish rules implementing the Arkansas restructuring statutes.
These efforts to increase competition in the electric industry at the state level in Oklahoma and Arkansas have been paralleled and even surpassed by efforts at the federal level to increase competition in the wholesale markets for electricity. In October 1992, the National Energy Policy Act of 1992 ("Energy Act") was enacted. The 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 facilitates third-party utilization of the transmission grid for sale 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 trade. 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. 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, 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 to discriminate in the operation of their transmission facilities in favor of their own or affiliated power marketing activities. Whereas FERC in the past only encouraged utilities to join and place their transmission systems under the operational control of independent system operators ("ISOs"), FERC, issued Order 2000 in December 1999, 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, FERC stressed that Order 2000 does not preclude it from requiring RTO participation. Order 2000 sets out a timetable for every jurisdictional utility (including the Company) to either join in an RTO filing, or, alternatively, to submit a filing by October 15, 2000 describing its efforts to join in 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 a RTO. The Company intends to meet its obligation under Order 2000 and under the restructuring law in Arkansas by joining the RTO being formed by the SPP. The transfer of operational control of the Company's transmission system to a FERC-approved RTO is not expected to significantly impact the Company's financial results. Yet, it is expected to increase the markets in which the Company can sell power at wholesale and, at the same time, to increase competition in such wholesale markets. As a low-cost producer of electricity with two of the most efficient power plants in the country, the Company expects to remain a competitive supplier of electricity.
As discussed previously, legislation was enacted in Oklahoma and Arkansas that will restructure the electric utility industry in those states, assuming that all the conditions in the legislation are met. This legislation would deregulate the Company's electric generation assets and the continued use of Statement of Financial Accounting Standards ("SFAS") No. 71, "Accounting for the Effects of Certain Types of Regulation" with respect to the related regulatory assets may no longer be appropriate. 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 $29 million, depending on the transition mechanisms developed by the legislature for the recovery of all or a portion of these net regulatory assets.
The enacted Oklahoma and Arkansas legislation does 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 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. 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.
On January 12, 2000, the OCC Staff (the "Staff") filed three applications to address various aspects of the Company's electric rates. See Note 9 of Notes to Consolidated Financial Statements for a discussion of these matters.
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 senior risk management committee has been established to review these risks on a regular basis. The Company's current market risk exposure relates primarily to 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. The fair value of long-term debt is estimated based on quoted market prices and management's estimate of current rates available for similar issues. The Company has no long-term debt maturing until 2005. The following table itemizes the Company's long-term debt maturities and the weighted-average interest rates by maturity date.
==============================================================================
2000
Year-end
(dollars in millions) 2005 Thereafter Total Fair Value
- ------------------------------------------------------------------------------
Fixed rate debt:
Principal amount......... $ 110.0 $ 460.0 $ 570.0 $ 552.3
Weighted-average
interest rate.......... 7.125% 6.73% 6.81% ---
Variable-rate debt:
Principal amount......... --- $ 135.4 $ 135.4 $ 135.4
Weighted-average
interest rate.......... --- 4.12% 4.12% ---
==============================================================================
Item 8. Financial Statements and Supplementary Data.
BALANCE SHEETS
December 31 (dollars in thousands) 2000 1999 1998
============================================================================================================
ASSETS
CURRENT ASSETS:
Cash and cash equivalents.................................... $ 422 $ 1,779 $ 312
Accounts receivable - customers, less reserve of $3,672,
$3,405 and $2,441, respectively............................ 130,920 96,212 91,434
Accrued unbilled revenues.................................... 49,000 40,200 22,500
Accounts receivable - other.................................. 14,092 8,074 7,723
Fuel inventories, at LIFO cost............................... 75,515 75,465 47,081
Materials and supplies, at average cost...................... 32,796 30,311 25,894
Prepayments and other........................................ 38,521 3,100 28,641
Accumulated deferred tax assets.............................. 8,454 7,681 6,889
- ------------------------------------------------------------------------------------------------------------
Total current assets....................................... 349,720 262,822 230,474
- ------------------------------------------------------------------------------------------------------------
OTHER PROPERTY AND INVESTMENTS, at cost........................ 15,396 12,731 17,454
- ------------------------------------------------------------------------------------------------------------
PROPERTY, PLANT AND EQUIPMENT:
In service................................................... 3,867,886 3,747,690 3,674,732
Construction work in progress................................ 14,889 15,575 28,439
- ------------------------------------------------------------------------------------------------------------
Total property, plant and equipment........................ 3,882,775 3,763,265 3,703,171
Less accumulated depreciation............................ 1,897,696 1,810,898 1,727,472
- ------------------------------------------------------------------------------------------------------------
Net property, plant and equipment............................ 1,985,079 1,952,367 1,975,699
DEFERRED CHARGES:
Advance payments for gas..................................... 12,500 11,800 15,000
Income taxes recoverable through future rates................ 38,654 39,692 40,731
Other........................................................ 36,100 41,248 40,739
- ------------------------------------------------------------------------------------------------------------
Total deferred charges..................................... 87,254 92,740 96,470
- ------------------------------------------------------------------------------------------------------------
TOTAL ASSETS................................................... $2,437,449 $2,320,660 $2,320,097
============================================================================================================
The Accompanying Notes To Financial Statements Are An Integral Part Hereof.
BALANCE SHEETS (Continued)
December 31 (dollars in thousands) 2000 1999 1998
============================================================================================================
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable - affiliates................................ $ 90,474 $ 75,674 $ 67,045
Accounts payable............................................. 107,416 36,231 45,536
Customers' deposits.......................................... 22,645 22,137 23,984
Accrued taxes................................................ 19,951 19,545 18,932
Accrued interest............................................. 14,535 14,573 15,931
Accrued vacation............................................. 11,386 11,437 12,484
Long-term debt due within one year........................... --- 110,000 ---
Other........................................................ 9,863 9,456 11,258
- ------------------------------------------------------------------------------------------------------------
Total current liabilities.................................. 276,270 299,053 195,170
- ------------------------------------------------------------------------------------------------------------
LONG-TERM DEBT................................................. 702,582 593,045 702,912
- ------------------------------------------------------------------------------------------------------------
DEFERRED CREDITS AND OTHER LIABILITIES:
Accrued pension and benefit obligation....................... 11,277 14,886 18,162
Accumulated deferred income taxes............................ 449,420 450,028 462,886
Accumulated deferred investment tax credits.................. 57,429 62,578 67,728
Other........................................................ 12,500 11,933 19,668
- ------------------------------------------------------------------------------------------------------------
Total deferred credits and other liabilities............... 530,626 539,425 568,444
- ------------------------------------------------------------------------------------------------------------
STOCKHOLDERS' EQUITY:
Common stockholders' equity.................................. 512,446 512,446 512,446
Retained earnings............................................ 415,525 376,691 341,125
- ------------------------------------------------------------------------------------------------------------
Total stockholder's equity................................. 927,971 889,137 853,571
- ------------------------------------------------------------------------------------------------------------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY..................... $2,437,449 $2,320,660 $2,320,097
============================================================================================================
The Accompanying Notes To Financial Statements Are An Integral Part Hereof.
STATEMENTS OF CAPITALIZATION
December 31 (dollars in thousands) 2000 1999 1998
==================================================================================================================
COMMON STOCK AND RETAINED EARNINGS:
Common stock, par value $2.50 per share;
authorized 100,000,000 shares; and
outstanding 40,378,745 shares.................................... $ 100,947 $ 100,947 $ 100,947
Premium on capital stock........................................... 411,499 411,499 411,499
Retained earnings.................................................. 415,525 376,691 341,125
- ------------------------------------------------------------------------------------------------------------------
Total common stock and retained earnings....................... 927,971 889,137 853,571
- ------------------------------------------------------------------------------------------------------------------
LONG-TERM DEBT:
SERIES DATE DUE
6.250% Senior Notes, Series Due October 15, 2000.............. --- 110,000 110,000
7.125% Senior Notes, Series Due October 15, 2005.............. 110,000 --- ---
6.500% Senior Notes, Series Due July 15, 2017................. 125,000 125,000 125,000
7.300% Senior Notes, Series Due October 15, 2025.............. 110,000 110,000 110,000
6.650% Senior Notes, Series Due July 15, 2027................. 125,000 125,000 125,000
6.500% Senior Notes, Series Due, April 15, 2028............... 100,000 100,000 100,000
Other bonds-
Var. % Garfield Industrial Authority, January 1, 2025......... 47,000 47,000 47,000
Var. % Muskogee Industrial Authority, January 1, 2025......... 32,400 32,400 32,400
Var. % Muskogee Industrial Authority, June 1, 2027............ 56,000 56,000 56,000
Unamortized premium and discount, net.............................. (2,818) (2,355) (2,488)
- ------------------------------------------------------------------------------------------------------------------
Total long-term debt........................................... 702,582 703,045 702,912
Less long-term debt due within one year...................... --- 110,000 ---
- ------------------------------------------------------------------------------------------------------------------
Total long-term debt (excluding long-term
debt due within one year).................................... 702,582 593,045 702,912
- ------------------------------------------------------------------------------------------------------------------
Total Capitalization................................................. $1,630,553 $1,482,182 $1,556,483
==================================================================================================================
The Accompanying Notes To Financial Statements Are An Integral Part Hereof.
STATEMENTS OF INCOME
Year ended December 31 (dollars in thousands except per share data) 2000 1999 1998
================================================================================================================
OPERATING REVENUES................................................. $1,453,585 $1,286,844 $1,312,078
- ----------------------------------------------------------------------------------------------------------------
OPERATING EXPENSES:
Fuel............................................................. 489,049 350,814 356,781
Purchased power.................................................. 263,328 249,203 240,542
Other operation and maintenance.................................. 267,353 253,312 239,614
Depreciation and amortization.................................... 117,257 119,059 116,214
Taxes other than income.......................................... 45,460 44,892 43,130
- ----------------------------------------------------------------------------------------------------------------
Total operating expenses....................................... 1,182,447 1,017,280 996,281
- ----------------------------------------------------------------------------------------------------------------
OPERATING INCOME................................................... 271,138 269,564 315,797
- ----------------------------------------------------------------------------------------------------------------
OTHER INCOME (EXPENSES), NET....................................... (2,745) (1,329) (2,320)
- ----------------------------------------------------------------------------------------------------------------
EARNINGS BEFORE INTEREST AND TAXES................................. 268,393 268,235 313,477
INTEREST INCOME (EXPENSES):
Interest income.................................................. 1,121 1,710 2,315
Interest on long-term debt....................................... (45,858) (44,813) (44,515)
Allowance for borrowed funds used during construction............ 2,229 719 1,071
Other interest charges........................................... (3,151) (1,845) (5,427)
- ----------------------------------------------------------------------------------------------------------------
Net interest income (expenses)................................. (45,659) (44,229) (46,556)
- ----------------------------------------------------------------------------------------------------------------
EARNINGS BEFORE INCOME TAXES....................................... 222,734 224,006 266,921
INCOME TAX EXPENSE................................................. 80,342 84,965 106,583
- ----------------------------------------------------------------------------------------------------------------
NET INCOME......................................................... 142,392 139,041 160,338
PREFERRED DIVIDEND REQUIREMENTS.................................... --- --- 733
- ----------------------------------------------------------------------------------------------------------------
EARNINGS AVAILABLE FOR COMMON STOCK................................ $ 142,392 $ 139,041 $ 159,605
================================================================================================================
AVERAGE COMMON SHARES OUTSTANDING (thousands)...................... 40,379 40,379 40,379
EARNINGS PER AVERAGE COMMON SHARE.................................. $ 3.53 $ 3.44 $ 3.95
AVERAGE COMMON SHARES OUTSTANDING ASSUMING DILUTION (thousands).... 40,379 40,379 40,379
EARNINGS PER AVERAGE COMMON SHARE ASSUMING DILUTION................ $ 3.53 $ 3.44 $ 2.95
================================================================================================================
The Accompanying Notes To Financial Statements Are An Integral Part Hereof.
STATEMENTS OF RETAINED EARNINGS
Year ended December 31 (dollars in thousands) 2000 1999 1998
============================================================================================================
BALANCE AT BEGINNING OF PERIOD................................. $ 376,691 $ 341,125 $ 338,946
ADD - net income............................................... 142,392 139,041 160,338
- ------------------------------------------------------------------------------------------------------------
Total........................................................ 519,083 480,166 449,284
DEDUCT:
Cash dividends declared on preferred stock................... --- --- 733
Cash dividends declared on common stock...................... 103,558 103,475 157,426
- ------------------------------------------------------------------------------------------------------------
Total...................................................... 103,558 103,475 158,159
- ------------------------------------------------------------------------------------------------------------
BALANCE AT END OF PERIOD....................................... $ 415,525 $ 376,691 $ 341,125
============================================================================================================
The Accompanying Notes To Financial Statements Are An Integral Part Hereof.
STATEMENTS OF CASH FLOWS
Year ended December 31 (dollars in thousands) 2000 1999 1998
============================================================================================================
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income................................................... $ 142,392 $ 139,041 $ 160,338
Adjustments to Reconcile Net Income to Net Cash Provided
from Operating Activities:
Depreciation and amortization.............................. 117,257 119,059 116,214
Deferred income taxes and investment tax credits, net...... (4,677) (16,945) 19,047
Change in Certain Current Assets and Liabilities:
Accounts receivable - customers.......................... (34,708) (4,778) 945
Accrued unbilled revenues................................ (8,800) (17,700) 14,400
Fuel, materials and supplies inventories................. (2,535) (32,801) (4,917)
Accumulated deferred tax assets.......................... (773) (792) (841)
Other current assets..................................... (41,439) 25,190 (11,120)
Accounts payable......................................... 102,248 (56,137) 49,793
Accrued taxes............................................ 406 613 (31)
Accrued interest......................................... (38) (1,358) 185
Other current liabilities................................ 865 (4,696) 2,823
Other operating activities................................... (23,323) 2,047 (30,149)
- ------------------------------------------------------------------------------------------------------------
Net cash provided from operating activities............ 246,875 150,743 316,687
- ------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures......................................... (128,410) (101,263) (96,678)
- ------------------------------------------------------------------------------------------------------------
Net cash used in investing activities.................. (128,410) (101,263) (96,678)
- ------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Retirement of long-term debt................................. (110,000) --- (112,500)
Proceeds from long-term debt................................. 110,000 --- 100,000
Short-term debt, net......................................... (16,264) 55,462 ---
Redemption of preferred stock................................ --- --- (49,266)
Cash dividends declared on preferred stock................... --- --- (733)
Cash dividends declared on common stock...................... (103,558) (103,475) (157,426)
- ------------------------------------------------------------------------------------------------------------
Net cash used in financing activities.................. (119,822) (48,013) (219,925)
- ------------------------------------------------------------------------------------------------------------
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS........... (1,357) 1,467 84
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD............... 1,779 312 228
- ------------------------------------------------------------------------------------------------------------
CASH AND CASH EQUIVALENTS AT END OF PERIOD..................... $ 422 $ 1,779 $ 312
============================================================================================================
SUPPLEMENTAL DISCLOSURE OF CASH FLOW
INFORMATION CASH PAID DURING THE PERIOD FOR:
Interest (net of amount capitalized)....................... $ 47,162 $ 46,257 $ 47,814
Income taxes............................................... $ 99,100 $ 51,557 $ 76,625
- ------------------------------------------------------------------------------------------------------------
DISCLOSURE OF ACCOUNTING POLICY:
For purposes of these statements, the Company considers all highly liquid debt instruments purchased with
a maturity of three months or less to be cash equivalents. These investments are carried at cost which
approximates market.
============================================================================================================
The Accompanying Notes To Financial Statements Are An Integral Part Hereof.
Notes To Financial Statements
1. Summary of Significant Accounting Policies
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 expected recovery from customers in future rates. Likewise, certain credits that would otherwise reduce expense are deferred as regulatory liabilities based on 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, 2000, regulatory assets and regulatory liabilities are being amortized and reflected in rates charged to customers over periods up to 20 years.
The components of deferred charges - other, on the Balance Sheets included the following, as of December 31:
Deferred Charges - Other
(dollars in thousands) 2000 1999 1998
==========================================================================================
Regulated Deferred Charges:
Unamortized debt expense........................ $ 5,565 $ 5,196 $ 5,611
Unamortized loss on reacquired debt............. 25,644 27,281 29,072
Miscellaneous................................... 475 1,317 2,217
- -------------------------------------------------- --------- --------- ---------
Total regulated deferred charges.............. 31,684 33,794 36,900
- -------------------------------------------------- --------- --------- ---------
Miscellaneous Non-Regulated Deferred Charges...... 4,416 7,454 3,839
- -------------------------------------------------- --------- --------- --------
Total Deferred Charges............................ $ 36,100 $ 41,248 $ 40,739
==========================================================================================
Regulatory Assets and Liabilities
(dollars in thousands) 2000 1999 1998
==========================================================================================
Regulatory Assets:
Income taxes recoverable from customers......... $ 83,617 $ 93,888 $104,160
Unamortized loss on reacquired debt............. 25,644 27,281 29,072
Miscellaneous................................... 475 1,317 2,217
- -------------------------------------------------- --------- --------- ---------
Total Regulatory Assets....................... 109,736 122,486 135,449
Regulatory Liabilities:
Income taxes refundable to customers............ (44,963) (54,196) (63,429)
- -------------------------------------------------- --------- --------- ---------
Net Regulatory Assets............................. $ 64,773 $ 68,290 $ 72,020
==========================================================================================
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
In June 1998, the FASB issued SFAS No. 133, "Accounting for Derivative Instruments and for Hedging Activities", with an effective date for periods beginning after June 15, 1999. In July 1999, the FASB issued SFAS No. 137, "Accounting for Derivative Instruments and Hedging Activities - Deferral of the Effective Date of FASB Statement No. 133". As a result of SFAS No. 137, adoption of SFAS No. 133 is now required for financial statements for periods beginning after June 15, 2000. In June 2000, the FASB issued SFAS No. 138, "Accounting for Certain Derivative Instruments and Certain Hedging Activities", which amends the accounting and reporting standards of SFAS No. 133 for certain derivative instruments and hedging activities. SFAS No. 133 sweeps in a broad population of transactions and changes the previous accounting definition of a derivative instrument. Under SFAS No. 133, every derivative instrument is recorded in the balance sheet as either an asset or liability measured at its fair value. SFAS No. 133 requires that changes in the derivative's fair value be recognized currently in earnings unless specific hedge accounting criteria are met. During 2000, the Company established SFAS No. 133 implementation team that reviewed contracts throughout the Company to identify both freestanding and embedded derivatives which met the criteria set forth in SFAS No. 133 and SFAS No. 138. As of January 1, 2001, management had not identified any contracts that qualified as derivatives under these new standards.
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. Actual results could differ from those estimates.
PROPERTY, PLANT AND EQUIPMENT
All property, plant and equipment is recorded at its original cost. Newly constructed plant is added to plant balances at costs which include contracted services, direct labor, materials, overhead and allowance for funds used during construction. Replacement of major units of property are capitalized as plant. The replaced plant is removed from plant balances and the cost of such property together with the cost of removal less salvage is charged to accumulated depreciation. Repair and replacement of minor items of property are included in the Statements of Income as maintenance expense.
DEPRECIATION
The provision for depreciation, which was approximately 3.1 percent of the average depreciable utility plant for 2000, and 3.2 percent for 1999 and 1998, 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
Allowance for funds used during construction ("AFUDC") is calculated according to FERC pronouncements for the imputed cost of equity and borrowed funds. AFUDC, a non-cash item, is reflected as a credit on the Statements of Income and a charge to construction work in progress.
AFUDC rates, compounded semi-annually, were 6.68, 5.36 and 5.75 percent for the years 2000, 1999 and 1998, respectively.
FAIR VALUE OF FINANCIAL INSTRUMENTS
The carrying value of the financial instruments on the Balance Sheets not otherwise discussed in these notes approximate fair value.
CASH AND CASH EQUIVALENTS
For purposes of these statements, the Company considers all highly liquid debt instruments purchased with a maturity of three months or less to be cash equivalents. These investments are carried at cost, which approximates market.
The Company's cash management program utilizes controlled disbursement banking arrangements. Outstanding checks in excess of cash balances totaled $19.9 million, zero and $17.8 million at December 31, 2000, 1999 and 1998, 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 from a minimum of $1,500 to a maximum of $13,000 with a term of 6 months to 72 months. The finance rate is based upon short-term loan rates and is reviewed and updated periodically. The interest rates were 10.99 percent, 8.99 percent and 8.25 percent at December 31, 2000, 1999 and 1998, respectively.
The current portion of these loans totaled $1.5 million, $0.6 million and $1.0 million at December 31, 2000, 1999 and 1998, respectively, and are classified as accounts receivable - customers in the accompanying Balance Sheets. The noncurrent portion of these loans totaled $5.9 million, $2.3 million and $4.0 million at December 31, 2000, 1999 and 1998, respectively, and are classified as other property and investments in the accompanying Balance Sheets. The Company sold approximately $12.7 million and $25.0 million of its heat pump loans in 1999 and 1998, respectively.
REVENUE RECOGNITION
The Company's customers are billed monthly on a cycle basis. The Company accrues estimated revenues for services provided but not yet billed, as the cost of providing service is recognized as incurred.
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 charged to substantially all of the Company's electric customers through automatic fuel adjustment clauses, which are subject to periodic review by the OCC, the APSC and the FERC. In March 2000, the OCC approved the Acquisition Premium Credit Rider ("APC Rider") for $10.7 million annually. The purpose of this rider is to credit the Oklahoma retail customers for the completion of the OCC authorized recovery of the premium paid by the Company when it acquired Enogex in 1986. The APC Rider is applicable to each Oklahoma retail rate schedule to which the Company's fuel cost adjustment clause applies.
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 $11.6 million for 2000 and lower than the stated LIFO cost by approximately $0.9 million for 1999, and $4.4 million for 1998, 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. The accrued vacation totaled $11.4 million, $11.4 million and $12.5 million at December 31, 2000, 1999 and 1998, respectively, and is classified as other current liabilities in the accompanying Balance Sheets.
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 $84.8 million, $81.9 million and $48.7 million during 2000, 1999 and 1998, respectively. Energy Corp. distributes operating costs to its affiliates based on several factors. Operating costs directly related to specific affiliates are assigned to those affiliates. Where more than one affiliate benefits from certain expenditures, the costs are shared between those affiliates receiving the benefits. Operating costs incurred for the benefit of all affiliates are allocated among the affiliates, based primarily upon head-count, occupancy, usage or the "Distragas" method. The Distragas method is a three-factor formula that uses an equal weighting of payroll, operating income and assets. The Company believes this method provides a reasonable basis for allocating common expenses.
In 2000, 1999 and 1998, the Company paid Enogex approximately $37.4 million, $41.5 million and $41.6 million, respectively, for transporting gas to the Company's gas-fired generating stations. In 1997, the Company began purchasing a significant portion of its natural gas generation fuel supply through a subsidiary of Enogex. 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 $5.5 million, $6.6 million and $13.9 million was recorded at December 31, 2000, 1999 and 1998, respectively, and is included in accounts payable - affiliates in the accompanying Balance Sheets for these activities.
RECLASSIFICATIONS
Certain amounts have been reclassified on the financial statements to conform to the 2000 presentation.
2. Income Taxes
The items comprising tax expense are as follows:
Year ended December 31 (dollars in thousands) 2000 1999 1998
=======================================================================================================================
Provision For Current Income Taxes:
Federal.......................................................... $ 71,056 $ 86,749 $ 73,964
State............................................................ 14,591 15,016 12,563
- ---------------------------------------------------------------------- ---------- ---------- ----------
Total Provision For Current Income Taxes..................... 85,647 101,765 86,527
- ---------------------------------------------------------------------- ---------- ---------- ----------
Provisions (Benefit) For Deferred Income Taxes, net:
Federal
Depreciation................................................. 10,452 (9,028) (1,418)
Repair allowance............................................. 1,711 1,978 1,200
Removal costs 2,710 3,461 (220)
Salvage...................................................... (1,718) (3,131) ---
Software development costs................................... (3,162) --- ---
Casualty losses.............................................. (5,439) 5,167 ---
Contributions in aid of construction......................... (2,689) --- ---
Company restructuring........................................ 67 100 22
Pension expense.............................................. 662 (2,486) 13,733
Bond redemption-unamortized costs............................ (1,064) 249 8,458
Other........................................................ (506) (6,297) (171)
State............................................................ (552) (1,809) 2,593
- ---------------------------------------------------------------------- ---------- ---------- ----------
Total Provision (Benefit) For Deferred Income Taxes, net.... 472 (11,796) 24,197
- ---------------------------------------------------------------------- ---------- ---------- ----------
Deferred Investment Tax Credits, net.................................. (5,150) (5,150) (5,150)
Income Taxes Relating to Other Income and Deductions.................. (627) 146 1,009
- ---------------------------------------------------------------------- ---------- ---------- ----------
Total Income Tax Expense..................................... $ 80,342 $ 84,965 $ 106,583
- ---------------------------------------------------------------------- ---------- ---------- ----------
Pretax Income $ 222,734 $ 224,006 $ 266,921
====================================================================== ========== ========== ==========
The following schedule reconciles the statutory federal tax rate to the effective income tax rate:
Year ended December 31 2000 1999 1998
======================================================================================================================
Statutory federal tax rate............................................ 35.0% 35.0% 35.0%
State income taxes, net of federal income tax benefit................. 4.1 3.8 3.7
Tax credits, net...................................................... (2.3) (2.3) (1.9)
Other, net............................................................ (0.7) 1.4 3.1
- ---------------------------------------------------------------------- ---------- ---------- ----------
Effective income tax rate as reported............................ 36.1% 37.9% 39.9%
====================================================================== ========== ========== ==========
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 ("temporary differences") 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 Income Taxes are as follows:
Year ended December 31 (dollars in thousands) 2000 1999 1998
================================================================================================================
Current Deferred Tax Assets:
Accrued vacation ............................................. $ 4,105 $ 5,005 $ 4,656
Uncollectible accounts........................................ 3,090 1,428 945
Capitalization of indirect costs.............................. 318 249 172
RAR interest ................................................. 774 774 774
Provision for Worker's Compensation claims.................... 167 225 342
- ------------------------------------------------------------------- ---------- ---------- ----------
Current Deferred Tax Assets............................... $ 8,454 $ 7,681 $ 6,889
================================================================================================================
Deferred Tax Liabilities:
Accelerated depreciation and other property-related
differences............................................... $ 416,558 $ 415,213 $ 423,527
Allowance for funds used during construction.................. 34,093 37,152 38,575
Income taxes recoverable through future rates................. 32,365 36,335 40,310
- ------------------------------------------------------------------- ---------- ---------- ----------
Total..................................................... 483,016 488,700 502,412
- ------------------------------------------------------------------- ---------- ---------- ----------
Deferred Tax Assets:
Deferred investment tax credits............................... (18,388) (20,130) (21,875)
Income taxes refundable through future rates.................. (17,404) (20,974) (24,547)
Postemployment medical and life insurance benefits............ 548 (290) (1,811)
Company pension plan.......................................... (6,125) (5,892) (1,447)
Bond redemption-unamortized costs............................. 8,964 9,640 9,353
Other......................................................... (1,191) (1,026) 801
- ------------------------------------------------------------------- ---------- ---------- ----------
Total..................................................... (33,596) (38,672) (39,526)
- ------------------------------------------------------------------- ---------- ---------- ----------
Accumulated Deferred Income Tax Liabilities........................ $ 449,420 $ 450,028 $ 462,886
================================================================================================================
3. Common Stock and Retained Earnings
There were no new shares of common stock issued during 2000, 1999 or 1998.
4. Cumulative Preferred Stock
On January 15, 1998, all outstanding shares of the Company's 4% Cumulative Preferred Stock were redeemed at the par value of $20 per share plus accrued dividends. On January 20, 1998, all outstanding shares of the Company's Cumulative Preferred Stock, par value $100 per share, were redeemed at the following amounts per share plus accrued dividends: 4.20% series-$102; 4.24% series-$102.875; 4.44% series-$102; 4.80% series-$102; and 5.34% series-$101.
The Company's Restated Certificate of Incorporation permits the issuance of new series of preferred stock with dividends payable other than quarterly.
5. Long-Term Debt
On October 15, 2000, a $110 million series of the Company's 6.25 percent Senior Notes matured. The Company temporarily funded this transaction through short-term borrowings from Energy Corp. On October 23, 2000, the Company issued $110 million of 7.125 percent Senior Notes, Series due October 15, 2005. Net proceeds from this transaction were used to repay the temporary short-term borrowings from Energy Corp.
On April 15, 1998, the Company issued $100.0 million in Senior Notes at 6.50 percent due April 15, 2028. The proceeds from the sale of this new debt were applied to the redemption on April 21, 1998 of $12.5 million principal amount of the Company's 7.125 percent First Mortgage Bonds due January 1, 1999, $40.0 million principal amount of the Company's 7.125 percent First Mortgage Bonds due January 1, 2002 and $35.0 million principal amount of the Company's 8.625 percent First Mortgage Bonds due November 1, 2007 and for general corporate purposes.
The $112.5 million principal amount of the Company's First Mortgage Bonds redeemed or retired in 1998 were the last First Mortgage Bonds issued under the First Mortgage Bond Trust Indenture dated February 1, 1945, as supplemented and amended. Therefore, no electric plant of the Company is now subject to the lien and sinking fund requirements of the Trust Indenture and the lien and sinking fund requirements have been discharged.
Maturities of long-term debt during the next five years consist of $110 million in 2005.
The Company has previously incurred costs related to debt refinancings. Unamortized debt expense and unamortized loss on reacquired debt, and unamortized premium and discount on long-term debt are being amortized over the life of the respective debt and are classified as deferred charges -- other and long-term debt, respectively, in the accompanying Balance Sheets.
6. Short-Term Debt
The Company previously borrowed funds on a short-term basis, as necessary, by issuing commercial paper or by obtaining short-term bank loans. In 1997, these functions were transferred to Energy Corp. At December 31, 2000, Energy Corp. had in place a line of credit for up to $300 million, with $200 million to expire on January 15, 2001, and the remaining $100 million to expire on January 15, 2004. In January 2001, Energy Corp.'s line of credit for $200 million was renewed, with an expiration date of January 15, 2002. The Company has the necessary approvals to incur up to $400 million in short-term borrowings at any one time. The Company had $39.2 and $55.5 million in short-term debt outstanding at December 31, 2000 and 1999, respectively. The Company did not have any short-term debt outstanding at December 31, 1998.
7. Pension and Postemployment 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. Under the existing plan, benefits were based primarily on years of service and the average of the five highest consecutive years of compensation during an employee's last ten 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 to the existing plan 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 for an employee retiring prior to age 62, which alternative method is based on years of service and age with an employee whose age and years of service total or exceed 80 at the time of retirement receiving no reduction in the benefits payable under the plan, and (iii) the ability of an employee at time of retirement to receive, in lieu of an annuity, a lump sum payment equal to the present value of the annuity. Also, for employees hired after January 31, 2000, the pension plan will be a cash balance plan, under which the Company annually will contribute to the employee's account an amount equal to 5 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. The Company made contributions of $12.2 million during 2000 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.
The plan's assets consist primarily of 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 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 who have attained age 55 with 10 years of service at the time of retirement are entitled to these benefits. Employees hired after January 31, 2000, are not entitled to the medical benefits. The benefits are subject to deductibles, co-payment provisions and other limitations. The Company charges to expense the SFAS No. 106 costs and includes an annual amount as a component of cost-of-service in future ratemaking proceedings.
A reconciliation of funded status of the plans and the amounts included in the Company's Balance Sheets follows:
Projected Benefit Obligations:
===============================================================================================================================
Postretirement
Pension Plan Benefit Plans
- -------------------------------------------------------------------------------------------------------------------------------
(dollars in thousands) 2000 1999 1998 2000 1999 1998
- -------------------------------------------------------------------------------------------------------------------------------
Beginning obligations.............. $(266,674) $(303,925) $(311,017) $ (74,409) $ (81,495) $ (87,557)
Service cost....................... (7,402) (6,018) (6,082) (1,452) (2,007) (1,600)
Interest cost...................... (24,068) (19,095) (19,488) (6,417) (5,419) (5,286)
Participant contributions.......... --- --- --- (1,093) (1,142) (1,051)
Plan changes....................... (17,061) --- (2,888) (14,011) --- ---
Actuarial gains (losses)........... (63,247) 44,347 (6,759) (1,503) 6,692 6,283
Benefits paid...................... 35,745 17,309 19,934 8,837 8,962 7,716
Expenses .......................... 662 708 206 --- --- ---
Transfer to affiliate.............. --- --- 22,169 --- --- ---
- -------------------------------------------------------------------------------------------------------------------------------
Ending obligations................. $(342,045) $(266,674) $(303,925) $ (90,048) $ (74,409) $ (81,495)
===============================================================================================================================
Fair Value of Plans' Assets:
===============================================================================================================================
Postretirement
Pension Plan Benefit Plans
- -------------------------------------------------------------------------------------------------------------------------------
(dollars in thousands) 2000 1999 1998 2000 1999 1998
- -------------------------------------------------------------------------------------------------------------------------------
Beginning fair value............... $ 270,071 $ 265,649 $ 234,971 $ 53,727 $ 50,588 $ 45,619
Actual return on plans' assets..... 8,272 19,582 27,560 41 3,139 4,968
Employer contributions............. 12,177 2,857 40,006 6,184 6,307 5,474
Participants' contributions........ --- --- --- 943 980 915
Benefits paid...................... (35,745) (17,309) (19,934) (7,127) (7,287) (6,388)
Expenses........................... (662) (708) (206) --- --- ---
Transfer to affiliate.............. --- --- (16,748) --- --- ---
- -------------------------------------------------------------------------------------------------------------------------------
Ending fair value.................. $ 254,113 $ 270,071 $ 265,649 $ 53,768 $ 53,727 $ 50,588
===============================================================================================================================
Funded Status of Plans:
===============================================================================================================================
Postretirement
Pension Plan Benefit Plans
- -------------------------------------------------------------------------------------------------------------------------------
(dollars in thousands) 2000 1999 1998 2000 1999 1998
- -------------------------------------------------------------------------------------------------------------------------------
Funded status of the plans......... $ (87,932) $ 3,397 $ (38,276) $ (36,280) $ (20,682) $ (30,907)
Unrecognized net (gain) loss....... 37,950 (40,225) (104) (14,520) (22,321) (17,360)
Unrecognized prior service
cost............................ 47,175 34,242 37,147 12,991 --- ---
Unrecognized transition
obligation...................... (1,174) (2,347) (3,520) 30,495 33,037 35,578
- -------------------------------------------------------------------------------------------------------------------------------
Net balance sheet asset
(liability)..................... $ (3,981) $ (4,933) $ (4,753) $ (7,314) $ (9,966) $ (12,689)
===============================================================================================================================
Net Periodic Benefit Cost:
===============================================================================================================================
Postretirement
Pension Plan Benefit Plans
- -------------------------------------------------------------------------------------------------------------------------------
(dollars in thousands) 2000 1999 1998 2000 1999 1998
- -------------------------------------------------------------------------------------------------------------------------------
Service cost....................... $ 7,402 $ 6,018 $ 6,082 $ 1,452 $ 2,007 $ 1,600
Interest cost...................... 24,068 19,095 19,488 6,417 5,419 5,286
Return on plan assets.............. (20,605) (23,809) (19,173) (4,825) (3,844) (4,309)
Amortization of transition
obligation...................... (1,173) (1,173) (1,173) 2,541 2,541 2,541
Amortization of net gain........... (350) --- --- (1,514) (1,196) (2,129)
Net amount capitalized or
deferred........................ (2,245) (880) --- --- (1,086) (613)
Amortization of unrecognized
prior service cost.............. 4,128 2,906 2,905 1,021 --- ---
- -------------------------------------------------------------------------------------------------------------------------------
Net periodic benefit costs......... $ 11,225 $ 2,157 $ 8,129 $ 5,092 $ 3,841 $ 2,376
===============================================================================================================================
Rate Assumptions:
===============================================================================================================================
Postretirement
Pension Plan Benefit Plans
- -------------------------------------------------------------------------------------------------------------------------------
2000 1999 1998 2000 1999 1998
- -------------------------------------------------------------------------------------------------------------------------------
Discount rate...................... 8.00% 8.00% 6.75% 8.00% 8.00% 6.75%
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 7.00% 7.00% 7.50%
Ultimate trend rate............. N/A N/A N/A 4.50% 4.50% 4.50%
Ultimate trend year............. N/A N/A N/A 2007 2007 2007
===============================================================================================================================
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 approximately $0.9 million, $0.8 million and $0.8 million at December 31, 2000, 1999 and 1998, 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 $0.7 million, $0.7 million and $0.6 million at December 31, 2000, 1999 and 1998, respectively.
The effects of a one-percentage point increase on the aggregate of accumulated postretirement benefit obligation for health care benefits would be approximately $9.4 million, $6.1 million and $7.2 million at December 31, 2000, 1999 and 1998, respectively. The effects of a one-percentage point decrease on the aggregate of accumulated postretirement benefit obligation for health care benefits would be decreases of approximately $7.8 million, $5.2 million and $6.1 million at December 31, 2000, 1999 and 1998, respectively.
8. Commitments and Contingencies
The Company has entered into purchase commitments in connection with its construction program and the purchase of necessary fuel supplies of coal and natural gas for its generating units. The Company's construction expenditures for 2001 are estimated at $118.0 million.
The Company acquires some of its natural gas for boiler fuel under a well-head contract, which contains provisions allowing the owners to require prepayments for gas if certain minimum quantities are not taken. At December 31, 2000, 1999 and 1998, outstanding prepayments for gas, including the amounts classified as current assets, under this and other similar contracts were approximately $15.0 million, $14.9 million and $15.2 million respectively.
At December 31, 2000, the Company held non-cancelable operating leases covering 1,481 coal hopper railcars. Rental payments are charged to fuel expense and recovered through the Company's tariffs and automatic fuel adjustment clauses. The leases have purchase and renewal options. Future minimum lease payments due under the railcar leases, assuming the leases are renewed under the renewal option are as follows:
(dollars in thousands)
2001.................... $ 5,541 2004.................... $ 5,203
2002.................... 5,429 2005.................... 5,091
2003.................... 5,316 2006 and beyond......... 44,710
--------
Total Minimum Lease Payments..................................... $71,290
========
Rental payments under operating leases were approximately $5.4 million in 2000, $4.9 million in 1999, and $5.3 million in 1998. The Company is currently in the process of replacing these leases. Management does not anticipate the terms of the new leases will differ significantly from the existing leases.
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.
The Company had entered into an agreement with Central Oklahoma Oil and Gas Corp. ("COOG"), an unrelated third-party to develop a natural gas storage facility. Operation of the gas storage facility proved beneficial by allowing the Company to lower fuel costs by base loading coal generation, a less costly fuel supply. 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 amounting to approximately $46.8 million. The Company also entered into a bridge financing agreement as guarantor for COOG. In 1997, COOG obtained permanent financing and issued a note in the amount of $49.5 million. The proceeds from the permanent financing were applied to repay the outstanding bridge financing. In connection with the permanent financing, Energy Corp. entered into a note purchase agreement, where it has agreed, upon the occurrence of a monetary default by COOG on its permanent financing, to purchase COOG's note at a price equal to the unpaid principal and interest under the COOG note.
The Company has entered into agreements with four qualifying cogeneration facilities having initial terms of 3 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 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 2000, 1999, and 1998, the Company made total payments to cogenerators of approximately $227.6 million, $229.3 million, and $226.5 million, of which $189.6 million, $188.8 million, and $185.5 million, respectively, represented capacity payments. All payments for purchased power, including cogeneration, are included in the Statements of Income as purchased power. The future minimum capacity payments under the contracts for the next five years are approximately: 2001 - $191 million, 2002 - $192 million, 2003 - $163 million, 2004 - $151 million and 2005 - $88 million.
Approximately $2.5 million of the Company's construction expenditures budgeted for 2001 are to comply with environmental laws and regulations.
The Company's management believes 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 $50.5 million during 2001, compared to approximately $47.1 million in 2000. 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.
Beginning in 2000, the Company became subject to more stringent limits on sulfur dioxide emissions. These lower limits had no significant financial impact due to the Company's earlier decision to burn low sulfur coal. In 2000, the Company's sulfur dioxide emissions were well below the allowable limits. With respect to nitrogen oxides, the Company continues to meet the current emission standard. However, further reductions in nitrogen oxides could be required if, among other things, a study currently being conducted by the state of Oklahoma determines that such nitrogen oxides are contributing to regional haze, the United States Supreme Court decides to uphold new ozone standards, or if the Company fails to meet the new fine particulate standards. Any of these scenarios would require significant capital expenditures and increased operating and maintenance costs.
In 1997, the United States was a signatory to the Kyoto Protocol on global warming. While the Protocol is not likely to be ratified by the U.S. Senate, some form of carbon dioxide legislation may occur. If legislation is passed, it 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 Oklahoma Department of Environmental Quality's CAAA 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, 2000, the Company had received Title V permits for all but three of its generating stations. Since the Company submitted all 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 $0.4 million in 2000 and are estimated to be about the same in 2001.
On December 14, 2000, the EPA announced that it is appropriate and necessary to regulate mercury emissions from coal-fired utility boilers. If the EPA decides to regulate mercury emissions, limits on the amount of mercury emitted are expected to be finalized by December 2004 with the Company's compliance required by 2008. Depending upon the final regulations implemented, this could result in significant capital and operating expenditures.
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, are to be published in February 2002 and final rules are to be promulgated in August 2003. Based 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 is a party to an action brought by the EPA concerning cleanup of a disposal site. The Company was not the owner or operator of this site, rather the Company, along with many others, shipped materials to the owner or operator of the site who disposed of the materials. The Company's total waste disposed at this site is minimal and on February 15, 1996, the Company elected to participate in the de minimis settlement offered by the EPA. One of the other potentially responsible parties is currently contesting the Company's participation as a de minimis party. Regardless of the outcome of this issue, the Company believes its ultimate liability for this site is minimal.
Trigen-Oklahoma City Energy Corp. ("Trigen") sued the Company in the United States District Court, Western District of Oklahoma, alleging numerous causes of action, including monopolization of cooling services in violation of the Sherman Act. On December 21, 1998, the jury awarded Trigen in excess of $30 million in actual and punitive damages. On February 19, 1999, the trial court entered judgment in favor of Trigen as follows: (i) $6.8 million for various antitrust violations, (ii) $4 million for tortuous interference with an existing contract, (iii) $7 million for tortuous interference with a prospective economic advantage and (iv) $10 million in punitive damages. The trial judge, in a companion order, acknowledged that portions of the judgment could be duplicative, that the antitrust amounts could be tripled and that parties should address these issues in their post-trial motions. On January 25, 2000, a trial judge rejected the Company's post-trial motions to reverse the jury verdict or to grant the Company a new trial. The judge did, however, reduce the original $30 million judgment against the Company to $20 million. The Company appealed the trial court's ruling. Oral argument was heard by the Tenth Circuit on January 22, 2001. A decision is not expected for several months. While the outcome of the appeal is uncertain, legal counsel and management believe it is not probable that Trigen will ultimately succeed in preserving the verdicts. Accordingly, the Company has not accrued any loss associated with the damages awarded. The Company believes that the ultimate resolution of this case will not have a material adverse effect on the Company's financial position or results of operations.
In the normal course of business, other lawsuits, claims, environmental actions and other governmental proceedings arise against the Company. 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 or results of operations.
9. Rate Matters and Regulation
On January 12, 2000, the OCC Staff (the "Staff") filed three applications to address various aspects of the Company's electric rates. The first application related to the completion on March 1, 2000, of the recovery of the amortization premium paid by the Company when it acquired Enogex in 1986 and the resulting removal, pursuant to the APC Rider, of $12.8 million ($10.7 million in the Oklahoma Jurisdiction) from the amount being recovered by the Company from its customers through currently authorized electric rates. OG&E consented to this action and in March 2000, the OCC approved the APC Rider for $10.7 million annually.
The second application related to a review of the GEP Rider, which, as part of the OCC's order issued in 1997 in connection with the Company's last general rate review (the "1997 Order"), was scheduled for review in March 2000. The Company collected approximately $9.9 million pursuant to the GEP Rider during 2000. The GEP Rider initially was designed so that when the Company's average annual cost of fuel per kwh was less than 96.261 percent of the average non-nuclear fuel cost per kwh of certain other investor-owned utilities in the region, the Company was allowed to collect, through the GEP Rider, one-third of the amount by which the Company's average annual cost of fuel was below 96.261 percent of the average of the other specified utilities. If the Company's fuel cost exceeded 103.739 percent of the stated average, the Company was not allowed to recover one-third of the fuel costs above that average from Oklahoma customers. In April 2000 testimony, the Staff stated that they continued to support incentive programs that reward superior performance, but in their view the existing GEP Rider was not functioning as they had originally envisioned it.
In June 2000, the OCC approved the collection of $6.6 million through the GEP Rider for the time period July 1, 2000 through June 30, 2001 and approved the following four modifications to the GEP Rider: (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. The GEP Rider is to be revised effective July 1 of each year to reflect changes in the relative annual cost of fuel reported for the preceding calendar year.
The final application, relating to fuel cost recoveries, was used by the Staff to address the competitive bid process of the Company's gas transportation needs. In the 1997 order, the OCC approved a stipulation wherein the Company agreed to initiate a competitive bidding process for gas transportation service to its gas-fired plants with the competitive services commencing no later than April 30, 2000. The order also set annual compensation for the transportation services provided by Enogex to the Company at $41.3 million annually until March 1, 2000, at which time the rate would drop to $28.5 million (reflecting removal of the APC Rider, upon the completion of the recovery from customers of the amortization premium paid by the Company when it acquired Enogex in 1986) and remain at that level until competitively-bid gas transportation began. Final firm bids were submitted by Enogex and other pipelines on April 15, 1999. In July 1999, the Company filed an application with the OCC requesting approval of a performance-based rate plan for its Oklahoma retail customers from April 2000 until the introduction of customer choice for electric power in July 2002. As part of this application, the Company stated that Enogex had submitted the only viable bid ($33.4 million per year) for gas transportation to the Company's six gas-fired power plants that were the subject of the competitive bid. As part of its application to the OCC, the Company offered to discount Enogex's bid from $33.4 million annually to $25.2 million annually. The Company has executed a gas transportation contract with Enogex under which Enogex continues to serve the needs of the Company's power plants at a price to be paid by the Company of $33.4 million annually and, if the Company's proposal had been approved by the OCC, the Company would have recovered a portion of such amount ($25.2 million) from its customers. The Company negotiated with the Staff, the Office of the Oklahoma Attorney General and a coalition of industrial customers in an effort to settle all issued (including the competitive bid process) associated with its application for a performance-based rate plan. When these negotiations failed, the Company withdrew its application, which withdrawal was approved by the OCC in December 1999.
In July 2000, the Company entered into a stipulation (the "Stipulation") with the Staff, the Office of the Attorney General and a coalition of industrial customers regarding the competitive bid process of the Company's gas transportation service. The Stipulation (which, with one exception, was signed by all parties to the proceeding) would permit the Company to recover $25.2 million annually for gas transportation services to be provided by Enogex pursuant to the competitive bid process. The Stipulation was presented for approval to an Administrative Law Judge ("ALJ") in September 2000, and the ALJ recommended its approval. However, at a hearing on September 28, 2000, the OCC chose to delay the decision concerning the Stipulation and two of the three commissioners expressed concern over the competitive bid process. The Company cannot predict what further action the OCC may take. The Company believes that the competitive bid process was appropriate and is currently collecting $28.5 million on an annual basis through its base rates and APC Rider for gas transportation services from Enogex for the power plant requirements covered by the competitive bid.
On February 13, 1998, the APSC Staff filed a motion for a show cause order to review the Company's electric rates in the State of Arkansas. The Staff recommended a $3.1 million annual rate reduction (based on a test year ended December 31, 1996). The Staff and the Company reached a settlement for a $2.3 million annual rate reduction, which was approved by the APSC in August 1999.
10. Disclosures about Fair Value of Financial Instruments
The fair value of Long-Term Debt and Preferred Stock is estimated based on quoted market prices and management's estimate of current rates available for similar issues.
Indicated below are the carrying amounts and estimated fair values of the Company's financial instruments as of December 31:
2000 1999 1998
-------------------- -------------------- ---------------------
Carrying Fair Carrying Fair Carrying Fair
(dollars in thousands) Amount Value Amount Value Amount Value
=========================================================================================================================
Long-Term Debt and Preferred Stock:
Senior Notes.......................... $567,182 $552,256 $457,645 $422,181 $567,512 $593,313
Industrial Authority Bonds............ 135,400 135,400 135,400 135,400 135,400 135,400
=========================================================================================================================
Report of Independent Public Accountants
To the Shareowner of
Oklahoma Gas and Electric Company:
We have audited the accompanying balance sheets and statements of capitalization of Oklahoma Gas and Electric Company (an Oklahoma corporation) as of December 31, 2000, 1999 and 1998, and the related statements of income, retained earnings and cash flows for the years then ended. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements 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 as of December 31, 2000, 1999 and 1998, and the results of its operations and its cash flows for the years then ended in conformity with accounting principles generally accepted in the United States.
/s/ Arthur Andersen LLP
Arthur Andersen LLP
Oklahoma City, Oklahoma,
January 18, 2001
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 certified public accountants 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, 2000, 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 certified public accountants to review matters relating to financial reporting, auditing and internal control. To ensure auditor independence, both the internal auditors and independent certified public accountants have full and free access to the Audit Committee.
The independent certified public accounting firm of Arthur Andersen LLP is engaged to audit, in accordance with auditing standards generally accepted in the United States, the financial statements of the Company and its subsidiaries and to issue their report thereon.
/s/ Steven E. Moore /s/ Al M. Strecker
---------------------------------------------------- -------------------------------------------------
Steven E. Moore, Chairman of the Board, Al M. Strecker, Executive Vice President
President and Chief Executive Officer and Chief Operating Officer
/s/ James R. Hatfield /s/ Donald R. Rowlett
---------------------------------------------------- -------------------------------------------------
James R. Hatfield, Sr. Vice President and Donald R. Rowlett, Vice President
Chief Financial Officer and Controller
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 (dollars in thousands except Dec 31 Sep 30 Jun 30 Mar 31
per share data)
- ---------------------------------------------------------------------------------------------------------------------
Operating revenues.............................. 2000 $343,687 $528,993 $335,573 $245,332
1999 257,616 464,982 314,102 250,144
1998 265,207 474,209 336,017 236,645
- ---------------------------------------------------------------------------------------------------------------------
Operating income................................ 2000 $ 24,640 $185,049 $ 55,681 $ 5,768
1999 18,300 163,268 60,697 27,299
1998 29,336 193,695 85,886 6,880
- ---------------------------------------------------------------------------------------------------------------------
Net income (loss)............................... 2000 $ 8,730 $107,327 $ 29,561 $ (3,226)
1999 7,370 87,753 33,729 10,189
1998 10,607 105,931 45,879 (2,079)
- ---------------------------------------------------------------------------------------------------------------------
Earnings (loss) available for common stock...... 2000 $ 8,730 $107,327 $ 29,561 $ (3,226)
1999 7,370 87,753 33,729 10,189
1998 10,607 105,931 45,879 (2,812)
- ---------------------------------------------------------------------------------------------------------------------
Earnings (loss) per average common share........ 2000 $ 0.22 $ 2.66 $ 0.73 $ (0.08)
1999 0.18 2.17 0.84 0.25
1998 0.26 2.62 1.14 (0.07)
- ---------------------------------------------------------------------------------------------------------------------
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.
Not Applicable.
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.
Item 13. Certain Relationships and Related Transactions.
Items 10, 11, 12 and 13 are omitted pursuant to General Instruction I of Form 10-K, since the conditions set forth in General Instruction I (1)(a) and (b) with respect to wholly owned subsidiaries have been met.
PART IV
Item 14. 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 67
Report of Independent Public Accountants 68
All other schedules have been omitted since the required information is not applicable or is not material, or because the information required is included in the respective financial statements or notes thereto.
3. Exhibits
Exhibit No. Description
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)
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. Directors' Deferred Compensation Plan. (Filed as
Exhibit 10.06 to Energy Corp.'s Form 10-K Report for
the year ended December 31, 1999 (File No. 1-12579)
and incorporated by reference herein)
10.07 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)
10.08 Company's Restoration of Retirement Income Plan, as amended.
(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)
10.09 Company's 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)
10.10 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)
10.11 Energy Corp.'s Deferred Compensation Plan. (Filed as Exhibit 4
to Energy Corp.'s Form S-8 Registration Statement
No. 333-92423 and incorporated by reference herein)
10.12 Amendment No. 3 to OG&E's 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)
10.13 Amendment No. 4 to OGE Energy's 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)
23.01 Consent of Arthur Andersen 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
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. Directors' Deferred Compensation Plan.
(Filed as Exhibit 10.06 to Energy Corp.'s Form 10-K Report
for the year ended December 31, 1999 (File No. 1-12579) and
incorporated by reference herein)
10.07 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)
10.08 Company's Restoration of Retirement Income Plan, as amended.
(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)
10.09 Company's 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)
10.10 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)
10.11 Energy Corp.'s Deferred Compensation Plan. (Filed as Exhibit 4
to Energy Corp.'s Form S-8 Registration Statement
No. 333-92423 and incorporated by reference herein)
10.12 Amendment No. 3 to OG&E's 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)
10.13 Amendment No. 4 to OGE Energy's 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)
(b) Reports on Form 8-K
Item 5 Other Events, dated October 20, 2000.
OKLAHOMA GAS AND ELECTRIC COMPANY
SCHEDULE II - Valuation and Qualifying Accounts
Column A Column B Column C Column D Column E
Balance Charged to Charged to Balance
Beginning Costs and Other End of
Description of Year Expenses Accounts Deductions Year
- ----------- --------- -------------------------- ---------- ---------
2000 (Thousands)
Reserve for Uncollectible Accounts $ 3,405 $5,095 - $ 4,828 $ 3,672
1999
Reserve for Uncollectible Accounts $ 2,441 $ 8,596 - $ 7,632 $ 3,405
1998
Reserve for Uncollectible Accounts $ 3,583 $11,507 - $12,649 $ 2,441
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To Oklahoma Gas and Electric Company:
We have audited in accordance with auditing standards generally accepted in the United States, the financial statements of Oklahoma Gas and Electric Company included in this Form 10-K, and have issued our report thereon dated January 18, 2001. Our audits were made for the purpose of forming an opinion on those statements taken as a whole. The schedule listed on Page 63, Item 14 (a) 2. is the responsibility of the Company's management and is presented for purposes of complying with the Securities and Exchange Commission's rules and is not part of the basic financial statements. This schedule has been subjected to the auditing procedures applied in the audits of the basic financial statements and, in our opinion, fairly states in all material respects the financial data required to be set forth therein in relation to the basic financial statements taken as a whole.
/s/ Arthur Andersen LLP
Arthur Andersen LLP
Oklahoma City, Oklahoma,
January 18, 2001
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 26th day of March, 2001.
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 26, 2001
/ s / James R. Hatfield
James R. Hatfield Principal Financial Officer; and March 26, 2001
/ s / Donald R. Rowlett
Donald R. Rowlett Principal Accounting Officer. March 26, 2001
Herbert H. Champlin Director;
Luke R. Corbett Director;
William E. Durrett Director;
Martha W. Griffin Director;
Hugh L. Hembree, III Director;
Robert Kelley Director;
Bill Swisher Director; and
Ronald H. White, M.D. Director.
/ s / Steven E. Moore
By Steven E. Moore (attorney-in-fact) March 26, 2001
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)
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. Directors' Deferred Compensation Plan. (Filed as
Exhibit 10.06 to Energy Corp.'s Form 10-K Report for
the year ended December 31, 1999 (File No. 1-12579)
and incorporated by reference herein)
10.07 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)
10.08 Company's Restoration of Retirement Income Plan, as amended.
(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)
10.09 Company's 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)
10.10 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)
10.11 Energy Corp.'s Deferred Compensation Plan. (Filed as Exhibit 4
to the Company's Form S-8 Registration Statement
No. 333-92423 and incorporated by reference herein)
10.12 Amendment No. 3 to OG&E's 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)
10.13 Amendment No. 4 to OGE Energy's 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)
23.01 Consent of Arthur Andersen 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