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
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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)
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Total operating revenues..................... $ 1,453,585 $ 1,286,844 $ 1,312,078 13.0 (1.9)
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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)
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Total megawatt-hour sales.................... 25,258,044 23,842,157 24,370,200 5.9 (2.2)
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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
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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
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Total operating expenses..................... $1,182,447 $1,017,280 $ 996,281 16.2 2.1
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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
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Construction expenditures
including AFUDC................................. $128.4 $118.0 $118.0 $118.0
Maturities of long-term debt...................... 110.0 --- --- ---
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Total......................................... $238.4 $118.0 $118.0 $118.0
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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 i