Annual Report (Form 10-K), fiscal year 1993

Item 1. Business. ------------------ THE COMPANY
Oklahoma Gas and Electric Company ("OG&E") is a regulated public utility engaged in the generation, transmission and distribution of electricity to retail and wholesale customers. Enogex Inc., a wholly-owned subsidiary of OG&E, and Enogex Inc.'s subsidiaries (collectively, "Enogex") are engaged in non-utility businesses, consisting of diverse natural gas activities. OG&E and Enogex are herein referred to collectively as the "Company." Financial information on the Company's two segments of business is included in Note 8 of the Notes to Consolidated Financial Statements.
OG&E, incorporated in 1902 under the laws of the Oklahoma Territory, is the largest electric utility in the State of Oklahoma. OG&E sold its retail gas business in 1928, and now owns and operates an interconnected electric production, transmission and distribution system which includes eight active generating stations with a total capability of 5,637,300 kilowatts. Enogex owns and operates over 3,000 miles of natural gas transmission and gathering pipelines, has interests in six gas processing plants, markets natural gas and natural gas products and invests in the exploration and production of natural gas. At the end of 1993, Enogex had 361 members and OG&E had 3,408 members working in three operating regions and in a corporate headquarters organization. OG&E's executive offices are located at 101 North Robinson, P.O. Box 321, Oklahoma City, Oklahoma 73101-0321; telephone (405) 272-3000.
OG&E's electric rates have been under review for the past three years by the Oklahoma Corporation Commission ("OCC"). On February 25, 1994, the OCC issued an order directing OG&E to reduce its electric rates to its Oklahoma retail customers prospectively by approximately $14 million annually (based on a test year ended June 30, 1991) and to refund approximately $41.3 million. The $14 million annual reduction in rates is expected to lower OG&E's rates to its Oklahoma customers by approximately $17 million in 1994. Due to the rate order and the ever- increasing competition in the utility industry, OG&E has commenced a complete review and redesign of its operations that could result in downsizing, debt refinancing or other cost- cutting measures. As a part of this redesign, OG&E anticipates offering an early retirement program. OG&E also froze salaries and hiring in February 1994. These actions are intended to offset some of the impact of the recent rate order and to make OG&E more competitive in the years ahead. See "Regulation and Rates" for a further discussion of the rate order.
ELECTRIC OPERATIONS
GENERAL
OG&E furnishes retail electric service in 270 communities and their contiguous rural and suburban areas. During 1993, six other communities and two rural electric cooperatives in Oklahoma and western Arkansas purchased electricity from OG&E for resale. The service area, with an estimated population of 1.4 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 276 communities served, 247 are located in Oklahoma and 29 in Arkansas. Approximately 91 percent of total electric operating revenues for the year ended December 31, 1993, were derived from sales in Oklahoma and the remainder from sales in Arkansas.
OG&E's system control area peak demand as reported by the system dispatcher for the year was approximately 5,010 megawatts, and occurred on August 16, 1993. Excluding wheeling, the net on system peak demand was about 4,700 megawatts. However, when firm sales were included, total load responsibility was approximately 4,740 megawatts, resulting in a capacity margin of approximately 22 percent. As reflected in the table below and the operating statistics on page 4, kilowatt-hour sales to OG&E customers ("system sales") increased 5.0 percent in 1993 compared to 1992. This increase in system sales was offset by a 25 percent decline in sales to other utilities ("off-system sales") which caused total kilowatt-hour sales to be down by 0.3 percent for 1993. However, off-system sales are at much lower prices per kilowatt- hour and have less impact on operating revenues and income than system sales. In 1992 and 1991, factors which resulted in an overall increase in total kilowatt-hour sales included: significant increases in off-system sales; increased total customer usage in 1992 and 1991, which was offset by decreased residential usage in 1992; and slight increases in customer growth. Variations in kilowatt-hour sales for the three years are reflected in the following table:
OG&E is subject to competition in some areas from government-owned electric systems, municipally-owned electric systems, rural electric cooperatives and, in certain respects, from other private utilities and cogenerators. Oklahoma law forbids the granting of an exclusive franchise to a utility for providing electricity.
Besides competition from other suppliers of electricity, OG&E competes with suppliers of other forms of energy. The degree of competition between suppliers may vary depending on relative costs and supplies of other forms of energy. The National Energy Policy Act of 1992 has increased competition in the wholesale market for electricity. Although management believes competitive pressures will continue to increase, it cannot predict the precise extent to which OG&E's business may be affected in the future by the supply, relative cost or promotion of other forms of energy, or by other suppliers of electricity. See "Regulation and Rates, National Energy Legislation" for further discussion.
Electric and magnetic fields ("EMF") surround electric wires or conductors of electricity such as electrical tools, household wiring and appliances and high voltage electric transmission lines such as those owned by OG&E. Some recent studies have pointed to a possible correlation between EMF and health effects, including various forms of cancer, while others have found no correlation. The nation's electric utilities, including OG&E, have participated with the Electric Power Research Institute in the sponsorship of more than $75 million in research to determine the possible effects of EMF. Beginning in fiscal year 1994, and in association with the National Energy Policy Act of 1992, Edison Electric Institute members will help fund $65 million for EMF studies over the next five years. One half of this amount will be funded by the federal government, and two-thirds of the non-federal funding is expected to be provided by the electric utility industry. Through its participation with the Electric Power Research Institute and the Edison Electric Institute, OG&E will continue its investigation and research with regard to possible health effects posed by exposure to electric and magnetic fields.
FINANCE AND CONSTRUCTION
Management expects that internally generated funds and short- term borrowings will be adequate over the next three years to meet the Company's capital requirements and to refund the $41.3 million ordered by the OCC in 1994. The primary capital require- ments for 1994 through 1996 are estimated as follows:
(dollars in millions) 1994 1995 1996 ---------------------------------------------------------------- Consolidated construction expenditures including AFUDC ........... $143 $116 $118 Maturities of long-term debt and sinking fund requirements .............. - 85 - ---- ---- ---- Total ............................... $143 $201 $118 ================================================================
The three-year estimate includes construction expenditures for rebuilding electric transmission lines, for upgrading electric distribution systems, to replace or expand existing facilities in both its electric and non-utility businesses, and to some extent, for satisfying maturing debt and sinking fund obligations. Approximately $6.9 million of the Company's construction expenditures budgeted for 1994 are to comply with environmental laws and regulations. OG&E's construction program was developed to support an anticipated peak demand growth of one to two percent annually and to maintain a minimum capacity margin of 15.25 percent as stipulated by the Southwest Power Pool. See "Rate Structure, Load Growth and Related Matters."
OG&E's ability to sell additional securities on satisfactory terms to meet its capital needs is dependent upon numerous factors, including general market conditions for utility securities, which will impact OG&E's ability to meet earnings tests for the issuance of additional first mortgage bonds and preferred stock. Based on earnings for the twelve months ended December 31, 1993, and assuming an annual interest rate of 7.6 percent, OG&E could issue approximately $870 million in principal amount of additional first mortgage bonds under the earnings test contained in OG&E's Trust Indenture (assuming adequate property additions were available). Under the earnings test contained in OG&E's Restated Certificate of Incorporation and assuming none of the foregoing first mortgage bonds are issued, about $800 million of additional preferred stock at an assumed annual dividend rate of 8.0 percent could be issued as of December 31, 1993.
The Company will continue to use short-term borrowings to meet temporary cash requirements. The Company has the necessary regulatory approvals to incur up to $300 million in short-term borrowings at any one time. The maximum amount of outstanding short-term borrowings during 1993 was $136.6 million.
As described below, OG&E intends to meet its customers' increased electricity needs during the foreseeable future by maintaining the reliability and increasing the utilization of existing capacity and increasing demand-side management efforts. OG&E is not currently constructing any new base-load generating plants and does not anticipate the need for another base-load plant in the foreseeable future.
As part of its Integrated Resource Plan ("IRP") for supplying energy through the next decade and beyond, OG&E is evaluating measures to keep its existing generating plants operating efficiently well past their traditional retirement dates. As long as the cost to keep existing plants operating reliably and efficiently is less than the cost of alternative sources of capacity, existing plants will be operated.
OG&E entered into an agreement with Conoco, Inc. to provide on-site cogeneration and supply steam to the Conoco Refinery in Ponca City, Oklahoma. This facility became operational in 1991.
In accordance with the requirements of the Public Utility Regulatory Policies Act of 1978 ("PURPA") (see "Regulation and Rates, National Energy Legislation"), OG&E is obligated to purchase 110 megawatts of capacity annually from Smith Cogeneration, Inc. and 320 megawatts annually from Applied Energy Services, Inc. ("AES"), another cogenerator. In 1986, a contract was signed with Sparks Regional Medical Center to purchase energy generated by its nominal seven megawatt cogeneration facility and not needed by the hospital. In 1987, OG&E signed a contract to purchase up to 100 megawatts of capacity from Mid-Continent Power Company, Inc., beginning no later than 1998. This purchase of capacity is currently planned to begin in 1998 and carries no obligation on the part of OG&E to purchase energy. The purchases under each of these cogeneration contracts were approved by the appropriate regulatory commissions at rates set in accordance with PURPA.
OG&E's financial results depend to a large extent upon the tariffs it charges customers and the actions of the regulatory bodies that set those tariffs, the amount of customer energy usage, the cost and availability of external financing and the cost of conforming to government regulations.
REGULATION AND RATES
OG&E's retail electric tariffs in Oklahoma are regulated by the OCC, and in Arkansas are regulated by the Arkansas Public Service Commission ("APSC"). The issuance of certain securities by OG&E is also regulated by the OCC and the APSC. OG&E's wholesale electric tariffs, short-term borrowing authorization and accounting practices are subject to the jurisdiction of the Federal Energy Regulatory Commission ("FERC"). The Secretary of the Department of Energy has jurisdiction over some of OG&E's facilities and operations.
For the year ended December 31, 1993, approximately 85 percent of OG&E's electric revenue was subject to the jurisdiction of the OCC, eight percent to the APSC, and seven percent to the FERC.
Recent Regulatory Matters: On February 25, 1994, the OCC issued an order that, among other things, required OG&E to lower its rates to its Oklahoma retail customers by approximately $14 million annually (based on a test year ended June 30, 1991) and to refund approximately $41.3 million. The $14 million annual reduction in rates is expected to lower OG&E's rates to its Oklahoma customers by approximately $17 million in 1994. With respect to the $41.3 million refund, $39.1 million is associated with revenues prior to January 1, 1994, while the remaining $2.2 million relates to 1994.
During the first half of 1992 the Company participated in settlement negotiations and offered a proposed refund and a reduction in rates in an effort to reach settlement and conclude the proceedings. As a result, the Company recorded an $18 million provision for a potential refund in 1992. After receiving the February 25, 1994 order, the Company recorded an additional provision for rate refund of approximately $21.1 million in 1993 (consisting of a $14.9 million reduction in revenue and $6.2 million in interest), which reduced net income by approximately $13 million or $0.32 per share.
Enogex transports natural gas to OG&E for use at its gas- fired generating units and performs related gas gathering activities for OG&E. The entire $41.3 million refund related to the OCC's disallowance of a portion of the fees paid by OG&E to Enogex for such services in the past. Of the approximately $17 million annual rate reduction, approximately $9.9 million reflects the OCC's reduction of the amount to be recovered by OG&E from its Oklahoma customers for the future performance of such services by Enogex for OG&E.
In accordance with the OCC's rate order and a stipulation approved by the OCC in July 1991, OG&E's electric rates for 1994 are designed to permit OG&E to earn a 12 percent return on equity and the OCC staff is precluded from initiating an investigation of OG&E's rates for three years from February 25, 1994, unless OG&E's return on equity exceeds 12.75 percent. As explained previously, OG&E has commenced a complete review and redesign of its operations that could result in downsizing, debt refinancing or other cost-cutting measures in response to the rate order and the ever-increasing competition in the utility industry. As a part of this redesign, OG&E anticipates offering an early retirement program. OG&E also froze salaries and hiring in February 1994. These actions are intended to offset some of the impact of the recent rate order and to make OG&E more competitive in the years ahead.
Pursuant to an Order from the APSC in July 1992, OG&E and other electric utilities serving customers in Arkansas were to submit a 20-year Integrated Resource Plan with the APSC by March 15, 1993. Subsequently, OG&E received extensions of the filing date to June 15, 1994. In its IRP, each utility must set forth a thoroughly documented plan to serve its customers' electric energy needs. The utility, in developing this approach, must use a planning process that evaluates the full range of alternatives, including new generating capacity, purchased power, energy conservation and efficiency, cogeneration and renewable energy sources, in order to provide adequate and reliable service to its electric customers at the lowest system cost. The process shall take into account system operation features such as diversity, reliability, dispatchability and other factors of risk, and shall treat customer load reduction and conservation alternatives on a consistent and integrated basis with new power supply alternatives.
The Company anticipates that a similar IRP process will be initiated by the OCC.
Automatic Fuel Adjustment Clauses: Variances in the actual cost of fuel used in electric generation and certain purchased power costs, as compared to that component in cost-of-service for ratemaking, are passed through to OG&E's electric customers through automatic fuel adjustment clauses. A lag of 45 to 60 days occurs between the time costs are incurred and the time such costs are reflected in bills to retail customers. OG&E records an accrual in the financial statements for these differences. The automatic fuel adjustment clauses are subject to periodic review by the OCC, the APSC and the FERC. OG&E's non-utility subsidiary, Enogex Inc., owns and operates a pipeline business that delivers natural gas to the generating stations of OG&E. The OCC, the APSC and the FERC have authority to examine the appropriateness of any transportation charges or other fees OG&E pays Enogex, which OG&E seeks to recover through the fuel adjustment clause or other tariffs. As indicated above, the OCC in its rate order of February 25, 1994, disallowed $41.3 million previously recovered by OG&E through its fuel adjustment clause for amounts Enogex has charged OG&E for transporting natural gas to OG&E's generating stations and reduced OG&E's future recovery of such charges by approximately $9.9 million annually.
PURPA requires that electric utilities purchase electric power from qualifying cogeneration facilities ("QFs"). The costs to OG&E in connection with the Oklahoma facilities for such purchased power are recovered from Oklahoma customers with the approval of the OCC.
National Energy Legislation: The National Energy Act of 1978 imposes numerous responsibilities and requirements on OG&E. PURPA requires electric utilities, such as OG&E, to purchase electric power from, and sell electric power to, QFs and small power production facilities. Generally stated, electric utilities must purchase electric energy and production capacity made available by QFs and small power producers at a rate reflecting the cost that the purchasing utility can avoid as a result of obtaining energy and production capacity from these sources; rather than generating an equivalent amount of energy itself or purchasing the energy or capacity from other suppliers. OG&E has entered into agreements with four such cogenerators. See "Finance and Construction." 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. In 1991, the OCC approved standby service rates to meet this need.
The National Energy Policy Act of 1992 (the "Act") is expected to make some significant changes in the operations of the electric utility industry and the federal policies governing the generation and sale of electric power. The Act, among other things, allows the FERC to order utilities to permit access to their electrical transmission systems and to transmit power produced by independent power producers at transmission rates set by the FERC. The Act also provides funds to study electric vehicle technology, the effects of electric and magnetic fields, and institutes a tax credit for generating electricity using renewable energy sources. The Act also is designed to promote competition in the development of wholesale power generation in the electric industry. It exempts a new class of independent power producers from regulation under the Public Utility Holding Company Act of 1935 and allows the FERC to order wholesale "wheeling" by public utilities to provide utility and non-utility generators access to public utility transmission facilities. The Act 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.
RATE STRUCTURE, LOAD GROWTH AND RELATED MATTERS
Two of OG&E's primary goals in its electric tariff designs are: (i) to increase electric revenues by attracting and holding job-producing businesses and industries; and (ii) to keep its peak demand growth rate one-half of one percent less than the kilowatt-hour growth rate annually, while providing a minimum capacity margin of 15.25 percent. In order to meet these goals,
OG&E has implemented numerous demand-side management programs and tariff schedules. These programs and schedules include: (i) residential energy audits promoting efficient energy use, and assistance programs that help residential customers live in comfortable homes with lower energy costs; (ii) the PEAKS program, which provides credit on a customer's bill for the installation of a device that periodically cycles off the customer's central air conditioner during peak summer periods; (iii) a load curtailment rate for industrial and commercial customers who can demonstrate a load curtailment of at least 300 kilowatts; (iv) 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 afternoons to non-peak hours; and (v) a thermal energy storage program that promotes the shifting of cooling loads to off-peak hours.
OG&E has developed the "ReSource" program for business and industry which utilizes a group of highly specialized business consultants that have worldwide reputations and preeminence in their particular fields. These fields include management, finance, marketing, power quality, pricing, plant modernization, environmental, process technologies and architect/engineers. Depending on the scope of the project, OG&E may pay a portion of the costs associated with these consulting services. ReSource is designed to answer needs in any phase of a business operation, from general business management, to leading edge technology for a manufacturing process, to the financing necessary to make expansion and modernization possible.
In 1993, OG&E's marketing efforts included thermal storage, electrotechnologies, an outdoor lighting promotion "Lite- Watchman," an electric food service promotion and a heat pump promotion in the residential, commercial and industrial markets. Educating customers to use available time-of-use rates to lower their energy costs was also pursued. These rates can make commercial and industrial heating and cooling especially economical if power is used with thermal storage systems which chill water at night for cooling the next day.
To meet customers' electric power needs for their sensitive electronic equipment, OG&E began the Power Quality program several years ago. Through this program, a trained Power Quality team works with the customer by performing a thorough survey of wiring and grounding, transient surge protection checks and power monitoring. The customer and the team then develop solutions and alternatives to power needs at the facility.
OG&E continues studying other programs to keep its electric tariffs attractive and to control peak demand growth. These programs include the use of high efficiency lighting and ballasts, high efficiency motors, high efficiency air conditioners or chillers, direct load control of large customers, use of home automation systems, high-tech refrigeration
equipment, adjustable speed drives on electric motors, high-tech electric water heating systems, heating and cooling demand controls and time scheduling of electric appliances, such as water heaters. OG&E has also expanded its Positive Energy Home finance programs for customers to include heat pump water heaters as well as high efficiency heat pumps.
OG&E currently does not anticipate the need for new base- load generating plants in the foreseeable future. For further discussion, see "Finance and Construction."
FUEL SUPPLY
During 1993, approximately 30 percent of the OG&E-generated energy was produced by natural gas-fired units and 70 percent by coal-fired units. It is estimated that the fuel mix for 1994 through 1998 based upon expected generation for these years, will be as follows:
1994 1995 1996 1997 1998 ---- ---- ---- ---- ---- Natural Gas 22% 26% 27% 29% 31% Coal 78% 74% 73% 71% 69%
The average cost of fuel used, by type, per million Btu for the periods shown was as follows:
1993 1992 1991 1990 1989 ----- ----- ----- ----- ----- Natural Gas $3.64 $3.48 $3.14 $3.06 $2.97 Coal $1.16 $1.18 $1.21 $1.38 $1.39 Total (Weighted Avg) $1.92 $1.88 $1.96 $2.08 $2.11
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."
OG&E is continuing its program to improve the heat rate in all of its power plants and has implemented changes which have resulted in greater fuel efficiency. The improvements result in savings in fuel costs and OG&E has budgeted approximately $5.5 million over the next three years to further improve its heat rate.
Gas-Fired Units: OG&E has approximately 900 natural gas purchase contracts covering approximately 550 wells and delivery points. These contracts cover an estimated 167 billion cubic feet of connected reserves.
OG&E acquires some natural gas at the wellhead under purchase contracts which contain provisions allowing the owners to require prepayments for gas if certain minimum quantities are not taken (see "Note 9 of Notes to Consolidated Financial Statements"). At December 31, 1993, outstanding prepayments for gas, including the amounts classified as current assets, under these contracts were approximately $22.2 million (including $16.2 million accrued but not yet paid). A contract with Oklahoma Natural Gas Company for additional peaking gas is in place and is renewed yearly.
To help lower fuel cost, the Company began utilizing a new natural gas storage facility in 1993. OG&E is now pumping gas into the storage reservoir, which will help OG&E get greater value out of its remaining take-or-pay gas contracts. By diverting natural gas into storage, for the first time OG&E will be able to use as much coal as possible to make electricity, and pull gas from storage only to meet increases in demand. In 1994, gas storage will give OG&E the flexibility to generate about 78 percent of its electricity with coal, the highest percentage in OG&E's history. With coal being approximately one-third the cost of natural gas, running coal units at full capacity is expected to cut fuel costs for OG&E's customers by about $90 million a year.
Coal-Fired Units: Muskogee Units 4 and 5, with 500 megawatts of capacity each, Sooner Units 1 and 2, with 505 and 510 megawatts of capacity, respectively, and Muskogee Unit 6, with 515 megawatts of capacity, are designed to burn low-sulfur western coal. OG&E purchases coal under a mix of long and short- term contracts. OG&E currently has a long-term, multiple option agreement with Atlantic Richfield Company to supply coal for these units. The combination of all coal has an average sulfur content of 0.4 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.
In 1993, approximately 26,600 tons of Oklahoma coal was blended with Wyoming coal and burned in OG&E's coal-fired generating stations. During 1993, OG&E burned a total of 9.1 million tons of coal. Based upon the average sulfur content of Wyoming and Oklahoma coal and the average heating value of the coal, OG&E's units have an approximate emission rate of 0.78 pounds of sulfur dioxide per million Btu. See related discussion in "Environmental Matters."
In 1993, OG&E negotiated new rail transportation contracts for coal beginning in 1994, which will result in lower transportation rates.
The Wyoming coal is transported to OG&E's generating stations, a distance of about 1,000 miles, by unit trains. In
1993, OG&E leased 1,523 coal cars, of which 946 were aluminum, at an approximate annual rental cost of $4.9 million. The efficiencies related to this newer design of high volume aluminum body railcar have reduced, by approximately six percent, the number of trips from Wyoming and reduced railcar maintenance expenses.
ENVIRONMENTAL MATTERS
OG&E management believes all of its operations are in substantial compliance with present Federal, state and local environmental standards. It is estimated that OG&E's capital, maintenance and other costs toward the preservation and enhancement of environmental quality will be approximately $58 million during 1994, compared to approximately $54 million in 1993. OG&E continues to evaluate its environmental programs to assure compliance with new and proposed environmental legislation and regulations and to position itself in a competitive market.
The Company continues to explore options to comply with the Clean Air Act Amendments of 1990 (CAAA). All of OG&E's coal- fired generating units currently burn low-sulfur coal and consequently, OG&E will not need to take any steps to comply with the new sulfur dioxide emission limits until January 1, 2000. However, as of December 31, 1993, the Company had expended approximately $3.0 million (of an estimated total cost of approximately $8.0 million) for installation of continuous emission monitors which must be installed on 12 units by January 1, 1995. The CAAA will also regulate emissions for nitrogen oxides and certain air toxic compounds. Although final regulations concerning all of these issues have not been written, additional capital expenditures may be necessary, but an estimate of cost can not be determined at this time. The Company will continue to examine all alternatives to comply with the CAAA as part of its Integrated Resource Planning process. This planning approach will assure the Company has the least cost option to comply with the CAAA and be in a competitive position to market its services. The Company will not be required to file its compliance plan with the Environmental Protection Agency (the "EPA") until January 1996.
As part of the Company's continuing effort to assure compliance with the annual report required by the Toxic Substance Control Act (TSCA) for 1991, a review of the report was undertaken beginning in 1992. The EPA was notified of discrepancies in operating practices and documentation, PCB handling and record-keeping requirements. See "Item 3. Legal Proceedings" for additional discussion of this matter.
The Company is a party to three separate actions brought by the EPA concerning cleanup of disposal sites for hazardous waste and is involved in three other matters with the EPA. See "Item 3. Legal Proceedings."
ENOGEX
OG&E's wholly-owned non-utility subsidiary, Enogex Inc., is the 36th largest pipeline in the nation in terms of miles of pipeline. Enogex Inc. is engaged in gathering and transporting natural gas for ultimate delivery to public utilities and other suppliers and end-users of natural gas in Oklahoma and throughout the nation. At December 31, 1993, Enogex Inc. had five wholly- owned subsidiaries, Enogex Products Corporation ("Products"), Enogex Services Corporation ("Services"), Enogex Exploration Corporation ("Exploration"), ENGL Corporation ("ENGL") and Clinton Gas Transmission, Inc. ("Clinton"). Products owns interests in and operates five natural gas processing plants and markets natural gas liquids. Services and Clinton are engaged in the marketing (buying and selling) of natural gas. Exploration is engaged in investing in the exploration and production of oil and natural gas and the purchase of oil and gas reserves. ENGL operates a natural gas processing plant and markets the natural gas liquids.
For the year ended December 31, 1993, and before elimination of intercompany items between OG&E and Enogex, Enogex's consolidated revenues and net income were approximately $219.4 million and $9.5 million, respectively, as indicated in the following table:
(dollars in millions) 1993 Revenues 1993 Net Income ------------- --------------- Enogex Inc. $ 65.1 $10.0 (a) Products 11.9 3.0 Services 108.6 0.1 Exploration 2.0 0.2 ENGL 0.8 (0.2) Clinton 37.0 - Eliminations within Enogex (6.0) (b) (3.6) ------ ----- Enogex consolidated amounts $219.4 $ 9.5 ====== =====
(a) Includes $3.6 million of net income from Products, Services, Exploration, ENGL and Clinton.
(b) Consists of intercompany natural gas transmission fees of $3.0 million and sales of natural gas products amounting to $3.0 million.
Enogex's natural gas transportation business in Oklahoma consists primarily of gathering and transporting natural gas for OG&E, Transok, Inc. (an affiliate of another electric utility) and on an interruptible basis, third-party-owned gas. Enogex's system consists of over 3,000 miles of pipeline, which extends from the Arkoma Basin in eastern Oklahoma to the Anadarko Basin in western Oklahoma. Since 1960, Enogex has had a gas transmission contract with OG&E under which Enogex transports OG&E's natural gas supply on a fee basis, and assists OG&E in the negotiation and administration of short and long-term gas purchase contracts with producers and other suppliers. Enogex also provides accounting services and assists in payments to producers and suppliers under the contract. Under the gas transmission contract, OG&E agrees to tender to Enogex and Enogex agrees to transport, on a firm, load-following basis, all of OG&E's natural gas requirements for boiler fuel for its seven gas-fired electric generating stations. In 1993, Enogex transported nearly 142 Bcf of natural gas; approximately 67 Bcf, or about 47 percent was delivered to OG&E's electric generating stations, which resulted in approximately 84 percent of Enogex Inc.'s revenue of $65.1 million for 1993. See "Regulation and Rates."
Enogex's pipeline system also gathers and transports natural gas destined for interstate markets through interconnections in Oklahoma with other pipeline companies. Among others, these interconnections include Panhandle Eastern Pipeline, Williams Natural Gas Pipeline, Natural Gas Pipeline Company of America, Northern Natural Gas Company, Arkla Energy Resources, Phillips Seagas Pipeline, ANR Pipeline Company and Ozark Gas Transmission Company.
The rates charged by Enogex for transporting natural gas on behalf of an interstate natural gas pipeline company or a local distribution company served by an interstate natural gas pipeline company are subject to the jurisdiction of FERC under Section 311 of the Natural Gas Policy Act. The statute entitles Enogex to charge a "fair and equitable" rate that is subject to review and approval by FERC. This rate review may involve an administrative-type trial and an administrative appellate review. In addition, Enogex has agreed to open its system to all interstate shippers that are interested in moving natural gas through its system. Enogex is required to conduct this transportation on a non-discriminatory basis, although this transportation is subordinate to that performed for OG&E. This decision does not increase appreciably the federal regulatory burden on Enogex, but does give Enogex the opportunity to utilize any unused capacity on an interruptible basis and thus increase its transportation revenues.
The fees charged by Enogex for transporting natural gas for OG&E and Transok, Inc. are not subject to FERC regulation, as this service is solely intrastate. With respect to state regulation, the fees charged by Enogex to OG&E and Transok, Inc.
have not been subject to direct state regulation by the OCC. Even though the intrastate pipeline business of Enogex is not directly regulated, the OCC, the APSC and the FERC have the authority to examine the appropriateness of any transportation charge or other fees paid by OG&E to Enogex, which OG&E seeks to recover from ratepayers. See "Regulation and Rates" for a further discussion of this matter and the OCC's ruling on the fees paid by OG&E to Enogex.
Products has been active since 1968 in the processing of natural gas and marketing of natural gas liquids. Products has a 50 percent interest in and operates a natural gas processing plant near Calumet, Oklahoma, which can process 250,000 Mcf of natural gas per day. Products also owns four other natural gas processing plants in Oklahoma, which have, in the aggregate, the capacity to process approximately 36,000 Mcf of natural gas per day. ENGL owns one natural gas processing plant in Oklahoma, which became operational in 1993, and has the capacity to process approximately 18,000 Mcf of natural gas per day. Products' natural gas processing plant operations consist of off-lease extraction of liquids from natural gas that is transported through the Enogex pipeline, while ENGL's natural gas processing operations consists of off-lease extraction of liquids from an unaffiliated pipeline. The raw gas stream is processed and converted into marketable ethane, propane, butane, and natural gasoline mix. The residue gas remaining after the liquid products have been extracted consists primarily of methane.
Commercial grade propane is sold on the local market and the marketing of all other natural gas liquids extracted by Products and ENGL is handled through independent brokers. The natural gas liquids are delivered to Conway, Kansas (which is one of the nation's largest wholesale markets for gas liquids), where they are sold on the spot market, commonly referred to as Group 140. Independent brokers continuously monitor the marketplace on behalf of Products and ENGL and recommend the time to sell. No transactions take place until approved by authorized personnel. Payments are made to Products and ENGL after sale of the natural gas liquids and the brokers retain a marketing fee from the settlement.
In processing and marketing natural gas liquids, Products and ENGL compete against virtually all other gas processors selling natural gas liquids. Products and ENGL believe that they will be able to continue to compete favorably against such companies. With respect to factors affecting the natural gas liquids industry generally, as the price of natural gas liquids fall without a corresponding decrease in the price of natural gas, it may become uneconomical to extract certain natural gas liquids. As to factors affecting Products and ENGL specifically, the volume of natural gas processed at its plants is dependent upon the volume of natural gas transported through the pipeline system located "behind the plants" (i.e. the Enogex pipeline for Products and an unaffiliated pipeline for ENGL). If the volume
of natural gas transported by such pipeline increases "behind the plants," then the volume of liquids extracted by Products and ENGL should normally increase.
Services is a natural gas marketing company serving both producers and consumers of natural gas by buying natural gas at the wellhead and from other sources in Oklahoma and other states, and reselling the gas to local distribution companies, utilities other than OG&E and industrial purchasers both within and outside Oklahoma.
Although the margin on sales by Services is relatively small, approximately 63 percent of the natural gas purchased and resold is transported through the Enogex Inc. pipeline to one or more interstate pipelines that deliver the gas to markets. Thus, in addition to purchasing and selling natural gas, Services seeks to use the space available in the Enogex Inc. pipeline and increase the amount of natural gas available for processing by Products. Clinton, which was acquired in 1993, is engaged in essentially the same business as Services.
Enogex Inc. is committed to expand the activities of Services in order to increase the amount of natural gas transported through the pipeline and the amount of natural gas processed by Products.
In its marketing and transportation services for third parties, Enogex Inc., Services and Clinton encounter competition from other natural gas transporters and marketers and from available alternative energy sources. The effect of competition from alternative energy sources is dependent upon the availability and cost of competing supply sources.
Volumes of natural gas transported by Enogex Inc. for third parties and the revenues derived from such activities increased from the previous year. The contributing factors for the increase were specific projects approved to strengthen Enogex's position, with other similar projects under consideration.
Services and Clinton compete with all major suppliers of natural gas in the geographic markets they serve, which are primarily the areas served by pipelines with which Enogex is interconnected. Although the price of the gas is an important factor to a buyer of natural gas from Services, the primary factor is the total cost (including transportation fees) that the buyer must pay. Natural gas transported for Services by Enogex Inc. is billed at the same rate Enogex Inc. charges for comparable third-party transportation. Exploration was formed in 1988 primarily to engage in the production and exploration of natural gas. Exploration has focused its drilling activity in the state of Michigan and also has interests in Oklahoma. As of December 31, 1993, Exploration had interests in 238 active wells.
Item 2.



Item 2. Properties. -------------------
OG&E owns and operates an interconnected electric production, transmission and distribution system, located in Oklahoma and western Arkansas, which includes eight active generating stations with an aggregate active capability of 5,637 megawatts. The following table sets forth information with respect to present electric generating facilities:
Unit Station Year Capability Capability Station & Unit Fuel Installed (Megawatts) (Megawatts) ------------------------------------------------------------ Seminole 1 Gas 1971 549 2 Gas 1973 507 3 Gas 1975 500 1,556
Muskogee 3 Gas 1956 184 4 Coal 1977 500 5 Coal 1978 500 6 Coal 1984 515 1,699
Sooner 1 Coal 1979 505 2 Coal 1980 510 1,015
Horseshoe 6 Gas 1958 178 Lake 7 Gas 1963 238 8 Gas 1969 394 810
Mustang 1 Gas 1950 58 Inactive 2 Gas 1951 57 Inactive 3 Gas 1955 122 4 Gas 1959 260 5 Gas 1971 64 446
Conoco 1 Gas 1991 26 2 Gas 1991 26 52
Arbuckle 1 Gas 1953 74 Inactive
Enid 1 Gas 1965 12 2 Gas 1965 12 3 Gas 1965 12 4 Gas 1965 12 48
Woodward 1 Gas 1963 11 11 ----- Total Active Generating Capability (all stations) 5,637 =====
At December 31, 1993, OG&E's transmission system included 65 substations with a total capacity of approximately 17.2 million kVA and approximately 4,289 structure miles of lines. The
distribution system included 345 substations with a total capacity of approximately 6.1 million kVA, 25,232 structure miles of overhead lines, 1,565 miles of underground conduit and 6,184 miles of underground conductor.
The Trust Indenture securing OG&E's first mortgage bonds constitutes a direct first mortgage lien on substantially all of its electric facilities.
Enogex owns: (i) over 3,000 miles of natural gas pipeline extending from the Arkoma Basin in eastern Oklahoma to the Anadarko Basin in western Oklahoma; (ii) a 50 percent interest in a natural gas processing plant near Calumet, Oklahoma, which has the capacity to process 250,000 Mcf of natural gas per day; and (iii) five other natural gas processing plants in Oklahoma, which have, in the aggregate, the capacity to process approximately 54,000 Mcf of natural gas per day.
During the three years ended December 31, 1993, the Company's gross property, plant and equipment additions approximated $384 million and gross retirements approximated $69 million. Over 90 percent of these additions were provided by internally generated funds. The additions during this three-year period amounted to approximately 10.4 percent of total property, plant and equipment at December 31, 1993.
Item 3.

Item 3. Legal Proceedings. --------------------------
1. In March 1991, the Director of the Public Utility Division of the OCC filed an application with the OCC challenging, among other things, OG&E's retail electric rates in Oklahoma. On February 25, 1994, the OCC issued an order that, among other things, lowered OG&E's rates to its Oklahoma retail customers by approximately $17 million and ordered a refund of approximately $41.3 million, including interest. See "Regulation and Rates" under Item 1 for a further discussion of this matter.
2. On June 30, 1986, the United States government filed suit against OG&E and 36 other defendants in case number CIV-86-1401 W, in the United States District Court ("USDC") for the Western District of Oklahoma. The complaint generally alleges that a total of 18 million gallons of hazardous and toxic waste are contained at the Hardage Criner site located approximately 30 miles south of Oklahoma City, and that the government has expended, as of the date of the filing of the complaint, $1.44 million related to the site. The 37 defendants are divided into three classes: 33 "generator" defendants, of which OG&E is one; three "transporter" defendants; and the owner of the site, Mr. Royal Hardage.
It is estimated that over 200 other entities, not presently named in the government's complaint, have also disposed of
materials at the site. OG&E has disposed of an estimated 130,000 gallons at the site, or less than 1 percent of the total volume of waste. OG&E, along with each other Potentially Responsible Party ("PRP"), could be held jointly and severally liable for the remediation of the site. In August 1990, the USDC issued its rulings on the appropriate method for cleanup of the site. The USDC selected the containment remedy proposed by the Hardage Criner Steering Committee Defendants (the "Committee"), of which OG&E is a member, with several modifications. The remedy ordered by the USDC is estimated to cost approximately $60 million. However, the actual costs are heavily dependent on the nature and volume of liquids that will be extracted from the Hardage site. It is possible that the remedy could cost substantially more than the current $60 million estimate.
The USDC awarded the United States all of its claimed "indirect" costs, and all of the costs incurred by the United States Department of Justice, a total of approximately $3.2 million. These amounts are in addition to the past response costs of approximately $5.4 million that the USDC awarded the United States in a pre-trial summary judgment entered on December 8, 1989. That summary judgment also granted the United States the right to recover future costs that are "not inconsistent with the EPA's National Contingency Plan regulations." The Committee estimates that the United States has obtained monetary judgments which will allow it to recover approximately $12 million.
In a related ruling on cost issues, the USDC held that the Committee had incurred recoverable response costs in the amount of approximately $3.7 million. It further held that the United States was obligated to pay 8.36 percent of the Committee's costs, or approximately $311,000.
The USDC ruled that the United States' share of the total cleanup costs should include 8.36 percent of the costs of the court-ordered remedy and 8.36 percent of the approximately $12 million in costs that the United States itself was awarded in the case, except for prejudgment interest and Department of Justice costs.
The Committee appealed the USDC's rulings on the government receiving 100 percent of its costs and the Committee receiving only a portion of its costs to the Tenth Circuit Court of Appeals. The Tenth Circuit Court of Appeals has not yet issued a ruling in this appeal.
Settlements have been reached with other parties for their share of costs incurred. The money collected through these settlements is being used by the Hardage Site Remedy Corporation (which was formed to implement the USDC-ordered remedy) to finance
the remedy and to reimburse the government for response costs it may ultimately be awarded in the pending appeal in the Tenth Circuit Court.
Even though the settlement funds, plus interest and the United States contribution will raise a substantial portion of the monies required, any remaining amounts that OG&E and the other Hardage Steering Committee members are likely to pay may still be substantial. A more accurate estimate of the amount of the remaining costs must be determined after the remedy design is completed.
The Hardage Steering Committee members have reached an Agreement to pay the costs based on each company's respective volume of waste sent to the site. OG&E's share of the total is 2.33 percent.
While it is not possible to determine the precise outcome of this matter, in the opinion of management, OG&E's ultimate liability for the cleanup costs of this site will not have a material adverse effect on OG&E's financial position or its results of operations. Management's opinion is based on the following: (1) the cleanup costs already paid by certain parties; (2) the financial viability of the other PRPs; and (3) the portion of the total waste disposed at this site attributable to OG&E. Management also believes that costs incurred in connection with this site, which are not recovered from insurance carriers or other parties, may be allowable costs for future ratemaking purposes.
3. OG&E is also involved, along with numerous other PRPs, in an EPA administrative action involving the facility in Holden, Missouri, of Martha C. Rose Chemicals, Inc. ("Rose"). Beginning in early 1983 through 1986, Rose was engaged in the business of brokerage of polychlorinated biphenyls ("PCBs") and PCB items, processing of PCB capacitors and transformers for disposal, and decontamination of mineral oil dielectric fluids containing PCBs. During this time period, various generators of PCBs ("Generators"), including OG&E, shipped materials containing PCBs to the facility. Contrary to its contractual obligation with OG&E and other Generators, it appears that Rose failed to manage, handle and dispose of the PCBs and the PCB items in accordance with the applicable law. Rose has been issued citations by both the EPA and the Occupational Safety and Health Administration. OG&E, along with the other PRPs, could be held jointly and severally liable for the remediation of the site.
In March 1986, Rose abandoned its facility in Holden, Missouri, and subsequently notified certain Generators of its unwillingness and/or inability to come into compliance with the PCB rules and regulations and to properly dispose of such PCBs
and PCB items at the facility. In addition to PCBs and PCB items at the Rose facility, the EPA believes that contaminated soils, sediments and/or sludge may be present off-site.
Several Generators, including OG&E, formed a Steering Committee to investigate and possibly clean up the Rose facility. On October 30, 1986, OG&E, along with other Generators, entered into a negotiated Administrative Order of Consent with the EPA for the first phase of the work which includes: (i) conducting an assessment to determine the location and extent of any release or immediate threat of release of PCBs which pose or may pose any immediate danger to human health or welfare or the environment at the Rose facility; (ii) depending upon the results of such assessment, taking such response actions as are necessary to address the releases of PCBs and to eliminate the threat of further immediate releases of PCBs; (iii) providing such action as necessary to restrict access to and secure the Rose facility; and (iv) determining the nature and extent of the threat to the public health or welfare or the environment by conducting such site surveys, samplings and analyses, inventories and data evaluations as necessary to support and determine potential intermediate and final response actions. Currently, OG&E management's estimate of the total cost for cleanup of the Rose facility is in the range of $23 to $31 million, of which $18.5 million has already been collected from certain parties.
A second Administrative Order has been entered into which provides that the Steering Committee: (1) develop a Statement of Work following the Toxic Substances Control Act's guidelines; (2) perform a Remedial Investigation/Feasibility Study ("RI/FS"); (3) be given by the EPA a Covenant Not to Sue for work at the site under certain conditions; and (4) with the EPA's agreement, not to sue non-participating PRPs.
A Buyout Agreement with other parties was entered into in 1988. Work is progressing under the second Administrative Order and the RI/FS. In 1989, the Steering Committee filed suit against certain PRPs for cleanup costs.
On September 2, 1992, the EPA, Region VII, issued an Administrative Order ("AO") for Remedial Design and Remedial Action pursuant to Section 106 (a) of the Comprehensive Environmental Response Compensation and Liability Act ("CERCLA"). The AO basically requires excavation, treatment and disposal of remaining soils and debris, dismantling of buildings and groundwater monitoring for a minimum of 10 years. The AO contains a provision for an opportunity to confer between the EPA and the Steering Committee. Such conference was held and a notice to comply was given to the EPA by the Steering Committee coupled with its concern over the issue of access to the property.
The Company estimates its share of the total hazardous wastes at the Rose facility to be less than six percent. Due to the present stage of this matter, the Company cannot predict its outcome or the precise amount that it may be required to pay. Nevertheless, management believes that OG&E's ultimate liability for the cleanup costs of this site will not have a material adverse effect on OG&E's financial position or its results of operations. Management's opinion is based on the following: (1) the cleanup costs already paid by certain parties; (2) the financial viability of the other PRPs; and (3) the portion of the total waste disposed at this site attributable to OG&E. Management also believes that costs incurred in connection with this site, which are not recovered from insurance carriers or other parties, may be allowable costs for future ratemaking purposes.
4. Reference is made to paragraph No. 4 under Item 3 of the Company's 1992 Form 10-K regarding the suit filed by Charles D. "Charley" Wilson against the Directors of OG&E seeking in excess of $2 billion in damages. On July 13, 1993, the Oklahoma Supreme Court held that the Plaintiff's lawsuit failed to state a claim upon which relief could be granted. The Supreme Court held that Oklahoma does not recognize a common law fiduciary duty on behalf of the Directors to the ratepayers of OG&E. The Supreme Court also found that any such cause of action, if recognized, would be preempted by the Public Utility Regulatory Policies Act of 1978 and the Federal Energy Regulatory Commission regulations under the facts of the case. Finally, because Wilson's lawsuit was essentially a rate refund case, the Supreme Court held that jurisdiction rested exclusively with the Oklahoma Corporation Commission. The Supreme Court remanded the case to the trial court with instructions to dismiss for lack of subject matter jurisdiction.
Wilson filed a petition for rehearing with the Oklahoma Supreme Court and a response was filed to that petition. On October 5, 1993, the Oklahoma Supreme Court denied Wilson's petition for rehearing. Wilson filed petition for a Writ of Certiorari with the Supreme Court of the United States, October term, 1993. On February 22, 1994, the United States Supreme Court denied certiorari in this case.
This case is now concluded in favor of the Directors and against Wilson in all respects.
5. In July 1989, OG&E, through various media reports, became aware of an asbestos problem at one of its former power plants known as the Osage Plant, which had been sold to Osage Properties, Inc. in December 1986.
Under the terms of the Real Estate Purchase Contract, Osage Properties, Inc., was informed of the presence of friable asbestos in the plant, with their agreement to accept all
liability for the friable asbestos and indemnify OG&E against any and all claims brought against OG&E for damages and/or injuries to property or persons resulting from the existence and/or removal of friable asbestos material from the property.
In September 1988, Osage Properties, Inc. apparently leased the property to ACS Laboratories, Inc. for the stated purposes of residential living, dismantling and workshop premises. Because OG&E had no interest in the property after December 1986, OG&E does not know what activities took place on the property after that date.
According to public reports and television accounts, people were living inside the building and dismantling equipment, etc., apparently disturbing the encapsulated asbestos. According to the public reports, the people did not have protective clothing or equipment for asbestos work and were not handling and/or disposing of the asbestos properly. Further, neither Osage Prop- erties, Inc. nor their Lessee had the proper licensing required for such work.
As a result, the Oklahoma State Departments of Labor and Health have closed the site and are investigating the situation for possible solutions. OG&E intends to cooperate with the agencies of the State of Oklahoma in resolving this matter and, although the amount, if any, to be expended by OG&E has not been determined, OG&E does not believe this matter will have a material adverse effect on its financial position or its results of operations.
6. In 1992, OG&E began a voluntary review of information contained in the annual report required under the Toxic Substance Control Act ("TSCA") for 1991. The initial result of the review revealed some discrepancies in procedures and documentation.
The EPA, Region VI, was notified of these initial discrepancies in December 1992. Because it was suspected that additional discrepancies might be discovered during the continuing review/audit, OG&E reached an agreement on January 12, 1993, with the EPA, Region VI, concerning the notification and reporting requirements of any newly discovered discrepancies. After further investigation, OG&E reported in September 1993 numerous additional discrepancies to the EPA, Region VI. Many of the discrepancies could be deemed violations of the regulations under TSCA. The discrepancies principally concerned the TSCA regulations relating to PCB handling and record keeping requirements. However, to the Company's knowledge, none of the activities involved releases of materials into the environment or caused harm to any individuals. Under the TSCA regulations, the EPA has the authority to assess a maximum fine of up to $25,000 per day, and to treat each day of violation as the basis for a separate fine. OG&E has taken and is taking corrective action to remedy the discrepancies.
The position of the EPA and OG&E is that they are currently in pre-settlement negotiations and no fines have been assessed as of this date. Since this matter is currently being negotiated, OG&E does not know the amount of fines that the EPA may seek. The amount of the fine is dependent upon numerous interpretive issues under the TSCA regulations and potentially could be in an amount material to the Company's results of operations. However, at the present time, the Company does not expect that the amount of the fine will have a material effect on its results of operations based primarily on having voluntarily reported the discrepancies to the EPA coupled with the Company's efforts to remedy the discrepancies and the lack of releases into the environment or harm to individuals.
7. On January 11, 1993, OG&E 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 OG&E and 45 others as PRPs. Each PRP could be held jointly and severally liable for remediation of this site.
The Notice Letter, a formal demand for reimbursement of past and future incurred costs (past costs are approximately $1.3 million), provided for a negotiation period of 60 days and encouraged the PRPs to perform or finance the response activities as set forth in the Record of Decision ("ROD") and the Draft Statement of Work ("SOW").
The ROD addresses the source of contamination both on and off the site and is divided into two operable units: 1) Source Control Operable Unit, the remedy of which is addressed with the SOW and has an estimated cost of $6.4 million; and 2) Groundwater Operable Unit, which is still being evaluated to assess the extent of contamination in the groundwater and any plumes. The cost of remediation for this Unit cannot be estimated at this time.
As to the Source Control Operable Unit and as a result of the EPA's Notice Letter, companies listed as PRPs (including OG&E) held several meetings to determine whether or not they should form a Steering Committee, whether additional research into volumetric shares should be conducted and a response, if any, to be sent to the EPA. Several but not all of the 46 companies have signed a very limited Participation Agreement, the purpose of which is to negotiate with the EPA.
On March 31, 1993, OG&E joined with the signatories to the limited Participation Agreement in making a settlement offer to the EPA. The EPA met with representatives of the PRPs group on June 11, 1993, to discuss the current developments taking place. The EPA is currently considering a modification of the remedy for the Source Control Operable Unit because the remedy was
apparently selected without giving consideration to the presence of listed hazardous waste, although the presence of this waste was documented in the Record of Decision. The EPA explained at the meeting that it will likely not make a decision in the near future concerning the remedy for the Source Control Operable Unit. The EPA informed the participating PRPs that it would not pursue them through the issuance of a unilateral administrative order relating to the Special Notice Letters.
As to the Groundwater Operable Unit, OG&E declined to either participate in conducting or financing any remedial activities. No further action on the Groundwater Operable Unit has been taken by the EPA.
On February 1, 1994, OG&E received a Section 104 Letter from the EPA, Region VI, which asked for either participation in or financing of a Removal Action calling for netting of 2.5 acre on- site sludge lagoon to preclude access to wildlife. The PRP Group, for various reasons, declined on February 10, 1994, to participate or finance the Removal Action.
Due to the present stage of this matter, the total cost of the cleanup of the site and the Company's ultimate liability cannot be estimated. Nevertheless, management believes that OG&E's ultimate liability for the cleanup costs of this site will not have a material adverse effect on OG&E's financial position or its results of operations. Management's opinion is based on the financial viability of the other PRPs and the portion of the total waste disposed at this site attributable to OG&E. Management also believes that costs incurred in connection with this site, which are not recovered from insurance carriers or other parties, may be allowable costs for future ratemaking purposes.
8. OG&E has been requested by the EPA to permit the inspection of two separate properties owned by OG&E for possible hazardous substances, pollutants or contaminants. These sites were used many years ago by OG&E or certain companies acquired by OG&E for manufacturing gas from coal. In connection with manufacturing gas, various by-products were produced (including coal-tar and other potentially harmful materials), which could remain on the sites. At the present time, OG&E does not know whether any harmful materials remain at the sites and intends to cooperate fully with the EPA in its investigation.
9. Puritan Oil and Gas Corp., and other Plaintiffs, filed an amendment to a petition on February 19, 1993, to an action previously filed in the District Court of Oklahoma County, involving an alleged breach of an oil and gas contract by OG&E. Enogex Inc. was also joined as a Defendant in the action. Plaintiff alleges that OG&E and Enogex were in violation of the Federal Racket Influenced and Corrupt Organizations Act ("RICO"). The case was removed to the United States District Court for the
Western District of Oklahoma. Plaintiff alleges the Defendants refused to honor contractual obligations in certain gas purchase contracts. The underlying dispute on the gas purchase contracts arises in the ordinary course of OG&E's business and involves whether OG&E must purchase gas thereunder, where the contract provides for certain requirements be maintained by the well. Actual damages under the RICO claim are sought in an amount of $2,000,000. RICO provides that these damages be trebled in the event of an adverse verdict. Punitive damages under the RICO claim are also sought in the amount of $1,000,000.
A Motion to Dismiss the RICO claim was filed by OG&E and Enogex. On January 4, 1994, the Court dismissed the RICO claim and remanded the breach of contract action to the state court. Plaintiffs filed a Motion to Amend the RICO claim. It was denied by the court. Plaintiffs filed a Notice of Appeal on March 1, 1994, to perfect an appeal of the dismissal of the RICO claims to the Tenth Circuit Court of Appeals.
Management believes the outcome of this proceeding will not have a material adverse effect on the Company's financial position or its results of operations for numerous reasons, which include punitive damages do not appear to be available to the Plaintiffs under RICO and the underlying dispute between the parties of a gas purchase contract. Management intends to vigorously pursue the defense of this matter.
In the normal course of business, other lawsuits, claims, environmental actions and other governmental proceedings may arise against the Company. Management, after consultation with legal counsel, does not anticipate that liabilities arising out of such other currently pending or threatened lawsuits and claims will have a material adverse effect on the Company's financial position or its results of operations.
Item 4.

Item 4. Submission of Matters to a Vote of Security Holders. -------------------------------------------------------------
Not applicable.
Executive Officers of the Registrant
The following persons were Executive Officers of the Regis- trant as of March 15, 1994:
Name Age Title ----------------------------------------------------------------- James G. Harlow, Jr. 59 Chairman of the Board, President and Chief Executive Officer
Patrick J. Ryan 55 Executive Vice President and Chief Operating Officer
Bob G. Bunce 62 Senior Vice President-Accounting and Administration
Kenneth J. Baltes 58 Vice President and Manager Eastern Region
H. Leon Grover 57 Vice President and Manager Western Region
James R. Helton 51 Vice President and Manager Metro Region
Steven E. Moore 47 Vice President-Law and Public Affairs
Al M. Strecker 50 Vice President and Treasurer
Don L. Young 53 Controller
Irma B. Elliott 55 Secretary
No family relationship exists between any of the Executive Officers of the Registrant. Each Officer is to hold office until the Board of Directors meeting following the next Annual Meeting of Shareowners, currently scheduled for May 19, 1994.
The business experience of each of the Executive Officers of the Registrant for the past five years is as follows:
Name Business Experience ----------------------------------------------------------------- James G. Harlow, Jr. 1989-Present: Chairman of the Board, President and Chief Executive Officer
Patrick J. Ryan 1989-Present: Executive Vice President and Chief Operating Officer
Bob G. Bunce 1989-Present: Senior Vice President- Accounting and Administration
Kenneth J. Baltes 1989-Present: Vice President and Manager Eastern Region
H. Leon Grover 1989-Present: Vice President and Manager Western Region
James R. Helton 1989-Present: Vice President and Manager Metro Region
Steven E. Moore 1989-Present: Vice President-Law and Public Affairs
Al M. Strecker 1991-Present: Vice President and Treasurer
1989-1991: Vice President, Secretary and Treasurer
Don L. Young 1989-Present: Controller
Irma B. Elliott 1991-Present: Secretary
1989-1991: Assistant Secretary
Part II
Item 5.

Item 5. Market for Registrant's Common Equity and Related Stockholder Matters. ---------------------------------------------------------
The Company's Common Stock is listed for trading on the New York and Pacific Stock Exchanges under the ticker symbol "OGE". Quotes may be obtained in daily newspapers where the common stock is listed as "OklaGE" in the New York Stock Exchange listing table. The following table gives information with respect to price ranges, as reported in The Wall Street Journal as New York Stock Exchange Composite Transactions, and dividends paid for the periods shown.
1993 1992 ------------------------- ------------------------- Dividend Dividend Paid High Low Paid High Low -------- ---- --- -------- ---- --- First Quarter $0.66-1/2 $35-7/8 $33 $0.66-1/2 $44 $37-5/8 Second Quarter 0.66-1/2 37-5/8 33-3/4 0.66-1/2 38-7/8 30-1/8 Third Quarter 0.66-1/2 38-5/8 34 0.66-1/2 34-7/8 31 Fourth Quarter 0.66-1/2 38-3/8 32-7/8 0.66-1/2 34-3/4 32-1/8
The number of record holders of Common Stock at December 31, 1993, was 36,201. The book value of the Company's Common Stock at December 31, 1993, was $22.48.
Item 6.

Item 6. Selected Financial Data. --------------------------------
Item 7.

Item 7. Management's Discussion and Analysis of Results of Operations and Financial Condition. -----------------------------------------------------------
Management's Discussion and Analysis.
Overview
Earnings for 1993 increased to $2.78 per share from $2.42 in 1992, despite the recent rate order of February 25, 1994, from the Oklahoma Corporation Commission (the "Commission"). The Commission's order requires OG&E to reduce its electric rates to its Oklahoma retail customers prospectively by approximately $14 million annually (based on a test year ended June 30, 1991) and to refund approximately $41.3 million. The $14 million annual reduction in rates is expected to lower OG&E's rates to its Oklahoma customers by approximately $17 million in 1994. With respect to the $41.3 million refund, $2.2 million will pertain to 1994, while the balance relates to prior periods which reduced 1993 earnings by $0.32 per share. Partially offsetting the impact of the refund for 1993 was an $18 million provision for rate refund established by the Company in 1992, which, in turn, reduced 1992 earnings by $0.28 per share.
Due to the rate order and the ever-increasing competition in the utility industry, OG&E has commenced a complete review and redesign of its operations that could result in downsizing or other cost-cutting measures. OG&E also froze salaries and hiring in February 1994. These actions are intended to offset some of the impact of the recent rate order and to make OG&E more competitive in the years ahead.
The following discussion and analysis presents factors (including the recent rate order of the Commission) 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 Consolidated Financial Statements and Notes thereto. Trends and contingencies of a material nature are discussed to the extent known and considered relevant.
EARNINGS
The 1993 increase in earnings was attributable almost in its entirety to increased retail electric sales from more normal weather in the Company's service territory, which more than offset the $0.32 reduction in earnings for 1993 related to the Commission's recent refund order. Earnings in 1992 were lower than 1991 due to the $18 million provision for refund recorded in 1992 ($0.28 per share), lower electric retail sales due to unusually mild weather and reduced subsidiary earnings.
Results of Operations REVENUES
* Not meaningful
Approximately 89 percent of the Company's revenues consist of regulated sales of electricity as a public utility, while the remaining 11 percent is provided by the non-utility operations of the Company's wholly-owned subsidiary, Enogex Inc. and its subsidiaries (collectively "Enogex"). Enogex's primary operations consist of transporting natural gas through its intra-state pipeline to various customers (including OG&E), buying and selling natural gas to third parties, selling natural gas liquids extracted by its natural gas processing plants and investing in exploration activities. Actions of the regulatory commissions
that set OG&E's electric rates will continue to affect the Company's financial results. The commissions also have the authority to examine the appropriateness of OG&E's recovery from its customers of fuel costs, which include the transportation fees that OG&E pays Enogex for transporting natural gas through Enogex's pipeline to OG&E's generating units.
During 1993, operating revenues increased 10.1 percent to $1.45 billion compared to $1.31 billion in 1992 and 1991. Increased kilowatt-hour sales to OG&E customers ("system sales"), the recovery of higher purchased power costs and increased Enogex revenues accounted for the improvement in revenues. These increases were only partially offset by the Commission's recent rate order, which reduced 1993 operating revenues by approximately $15 million. See Note 10 of Notes to Consolidated Financial Statements for a further discussion of the Commission's recent rate order.
A return to near normal weather and continued slight customer growth contributed to the increase in system sales for 1993. This increase in system sales was partially offset by a 25.0 percent decrease in sales to other utilities; causing total kilowatt-hour sales to be down by 0.3 percent for 1993. However, sales to other utilities are at much lower prices per kilowatt- hour and have less impact on operating revenues and income than system sales.
Enogex's 1993 revenues increased due to higher prices on natural gas sales and increased sales of petroleum products. The increased sales of petroleum products were primarily due to gas sales to third parties by Enogex's newest subsidiary, Clinton Gas Transmission, Inc., which was acquired early in 1993.
Operating revenues in 1992 were adversely affected by a decrease in sales of electricity to OG&E customers, due to the unusually mild weather in the Company's service territory and the $18 million provision for rate refund recorded in 1992. These factors were offset by increased sales of electricity to other utilities and increased revenues by Enogex. Enogex's revenue reflects increased volumes and prices for natural gas sales to third parties.
The higher levels of sales to other utilities in 1992 were due to the unusually mild weather and the significant amount of power that the Company must purchase from cogenerators under Federal law, which resulted in OG&E having surplus, relatively- inexpensive power for sale to other utilities. Yet, as noted above, sales to other utilities are at much lower prices per kilowatt-hour and have less impact on operating revenues and income than system sales. The Company's 1992 system kilowatt-hour sales were down by approximately 1.5 percent compared to 1991 due to decreased customer usage, while sales to other utilities increased 62.1 percent from 1991 levels.
The Company's 1994 revenues will be affected by the Commission's recent rate order, which will lower OG&E's rates to its Oklahoma customers by approximately $17 million and result in a charge of approximately $2.2 million relating to the portion of the $41.3 million refund to be recognized in 1994.
EXPENSES AND OTHER ITEMS
Total operating expenses rose 10.0 percent to $1.25 billion during 1993 compared to an increase of 3.1 percent to $1.14 billion during 1992.
The Company's generating capability is almost evenly divided between coal and natural gas and provides the flexibility to use either fuel to the best economic advantage for the Company and its customers. During 1993, the cost associated with coal decreased $3.8 million or 2.0 percent. The cost associated with natural gas, on the other hand, increased by $9.4 million or 3.9 percent. The total increase in fuel expense for 1993 was $5.6 million or 1.5 percent which compares to a total fuel expense increase of $8.6 million or 2.3 percent for 1992. The consumption of natural gas in 1993 was actually 3.5 percent less than in 1992, however, due to price fluctuations, natural gas expense on a Btu basis increased 4.4 percent.
The cost of fuel in the generation of electricity (which includes Enogex's charges to OG&E for transporting natural gas to OG&E's gas-fired generating units) and the cost of purchased power are recovered from customers pursuant to fuel adjustment clauses or other tariffs, subject to periodic review by the Oklahoma Corporation Commission, the Arkansas Public Service Commission and the Federal Energy Regulatory Commission ("FERC"). See Note 10 of Notes to Consolidated Financial Statements.
Purchased power costs amounted to $218.7 million in 1993, $182.2 million in 1992 and $173.8 million in 1991. As required by
the Public Utility Regulatory Policy Act of 1978 ("PURPA"), the Company must currently purchase power from qualified cogeneration facilities. Purchased power costs increased by more than $36 million in 1993 due to price escalation provisions contained in certain cogeneration contracts. In 1998, another cogeneration facility is scheduled to become operational. Under PURPA, the Company is obligated to purchase capacity from this facility as well. See Note 9 of Notes to Consolidated Financial Statements.
In 1992, the Company increased its electric sales to other utilities. This increased volume caused fuel expense to exceed 1991 levels, despite the Company's various programs which, overall, reduced fuel expense on a per kilowatt-hour basis.
To help lower fuel cost, the Company began utilizing a new natural gas storage facility in 1993. OG&E is now pumping gas into the storage reservoir, which will help OG&E get greater value out of its remaining take-or-pay gas contracts. By diverting natural gas into storage, for the first time OG&E will be able to use as much coal as possible to make electricity, and pull gas from storage only to meet increases in demand.
In 1994, gas storage will give OG&E the flexibility to generate about 78 percent of its electricity with coal, the highest percentage in OG&E's history. With coal being approximately one-third the cost of gas, running coal units at full capacity is expected to cut fuel costs for OG&E's customers by about $90 million a year.
The Company has initiated numerous other ongoing programs that have helped reduce the cost of generating electricity over the last several years. These programs include: 1) spot market purchases of coal; 2) renegotiated contracts for coal, gas, railcar maintenance, and coal transportation; and 3) a heat rate awareness program to produce kilowatt-hours with less fuel. Together, these fuel management efforts help OG&E remain competitive by cutting fuel costs with the savings being passed on to OG&E's electric customers, which in turn allows them to remain competitive in a global economy.
Enogex's gas purchased for resale increased $42.8 million or 43.9 percent for 1993 compared to $20.1 million or 26.0 percent for 1992. The 1993 increase was due to higher gas prices and increased volumes of natural gas purchased for resale by Clinton Gas Transmission, Inc. The 1992 increase in gas purchased for resale resulted from larger volumes and increased cost of natural gas purchased by Enogex.
The increase in other operation and maintenance expenses for 1993 resulted from major overhauls at two generating plants and increased labor costs. The 1992 increase in other operation and
maintenance expenses was primarily due to increased medical and labor costs, higher expenses associated with the Company's Oklahoma rate cases, rent expense for the corporate headquarters and tree trimming activity along transmission and distribution rights-of-way.
The increases in depreciation for 1993 and 1992 reflect higher levels of depreciable plant. Also, the adoption of Statement of Financial Accounting Standards No. 109, "Accounting for Income Taxes," during 1993 and its effect on Enogex contributed to the increase in depreciation. See Note 2 of Notes to Consolidated Financial Statements.
Income taxes during 1993 increased primarily due to higher pre-tax earnings and a one percent increase in the federal income tax rate to 35 percent. Current income taxes decreased in 1992 primarily due to lower pre-tax earnings. The 1992 decrease in current income taxes was partially offset by the tax effect of the $18 million provision for a potential refund which increased current income taxes by approximately $6.8 million and decreased the provision for deferred income taxes by a like amount.
The increase in interest expense for 1993 resulted from approximately $6.2 million of interest associated with the refund ordered by the Commission. See Note 10 of Notes to Consolidated Financial Statements.
Liquidity, Capital Resources and Contingencies
The primary capital requirements for 1993 and as estimated for 1994 through 1996 are as follows:
(dollars in millions) 1993 1994 1995 1996 ---------------------------------------------------------------------- Construction expenditures including AFUDC ................ $128 $143 $116 $118 Maturities of long-term debt and sinking fund requirements .. 15 - 85 - ---------------------------------------------------------------------- Total ...................... $143 $143 $201 $118 ======================================================================
CONSTRUCTION
The Company's need for capital is related to construction of new facilities to meet anticipated demand for service, to replace or expand existing facilities in both its electric and non-
utility businesses, and to some extent, for satisfying maturing debt and sinking fund obligations. Approximately $6.9 million of the Company's construction expenditures budgeted for 1994 are to comply with environmental laws and regulations.
The construction program for the next several years does not include any additional base-load generating units. Rather, to meet the increased electricity needs of its customers during the balance of this century, the Company will concentrate on maintaining the reliability and increasing the utilization of existing capacity and increasing demand-side management efforts.
FINANCE
The Company meets its cash needs through internally generated funds, short-term borrowings and permanent financing. The Company internally generated substantially all of its funds for construction expenditures during 1993. Management expects that internally generated funds will be adequate over the next three years to meet these capital requirements and to refund the $41.3 million ordered by the Commission in 1994. Short-term borrowings will continue to be used to meet temporary cash requirements. The maximum amount of outstanding short-term borrowings during 1993 was $136.6 million. The Company has the necessary regulatory approvals to incur up to $300 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. As to environmental matters, the Company has been designated as a "potentially responsible party" ("PRP") with respect to three waste disposal sites to which the Company sent materials. Under applicable law, the Company along with each PRP, could be held jointly and severally liable for site remediation. Neither the amount of cleanup costs nor the final method of their allocation among all designated PRPs at any of these sites has been determined. While it is not possible to determine the precise outcome of these matters, in the opinion of management, the Company's ultimate liability for the clean-up costs of these sites will not have a material effect on the Company's financial position or results of operations. Management's opinion is based on the following: 1) the clean-up costs already paid by certain parties, 2) the financial viability of the other PRPs, and 3) the portion of the total wastes disposed at the sites attributable to the Company. Management also believes that costs incurred in connection with the sites, which are not recovered from insurance carriers or other parties, may be allowable costs for future ratemaking purposes.
The Clean Air Act Amendments of 1990 (CAAA) among other things, limit the emission of sulfur dioxide and nitrogen oxides. All of OG&E's coal-fired generating units currently burn low- sulfur coal and, consequently, OG&E will not need to take any steps to comply with the new sulfur dioxide emission limits until January 1, 2000. The Company has made a capital investment for installation of continuous emission monitors on 12 units by January 1, 1995. The CAAA will also regulate emissions for nitrogen oxides and certain air toxic compounds. Although final regulations concerning all of these issues have not been written, some capital expenditures may be necessary, but an estimate of cost can not be determined at this time. The Company will continue to examine all alternatives to comply with the CAAA as part of its Integrated Resource Planning process. This planning approach will assure the Company has the least-cost option to comply with the CAAA and be in a competitive position to market its services. The Company will not be required to file its compliance plan with the Environmental Protection Agency ("EPA") until January 1996.
OG&E's review of its annual report for 1991 under the Toxic Substance Control Act ("TSCA") revealed numerous discrepancies in OG&E's operating practices and documentation, which have been reported to the EPA. Many of the discrepancies could be deemed violations of TSCA regulations. See Note 9 of Notes to Consolidated Financial Statements for a further discussion of this matter.
In October 1992, the National Energy Policy Act of 1992 ("Energy Act") was enacted. Among many other provisions, the Energy Act is designed to promote competition in the development of wholesale power generation in the electric utility industry. It exempts a new class of independent power producers from regulation under the Public Utility Holding Company Act of 1935 and allows the FERC to order wholesale "wheeling" by public utilities to provide utility and non-utility generators access to public utility transmission facilities. The Energy Act 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.
Besides the existing contingencies described above, and those described in Note 9 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.
Item 8.


Item 8. Financial Statements and Supplementary Data. ----------------------------------------------------
Notes To Consolidated Financial Statements.
1. Summary of Significant Accounting Policies
PRINCIPLES OF CONSOLIDATION
The consolidated financial statements include the accounts of Oklahoma Gas and Electric Company ("OG&E"), its wholly-owned non-utility subsidiary Enogex Inc. and its subsidiaries ("Enogex") (collectively, the "Company"). All significant intercompany transactions have been eliminated in consolidation.
ACCOUNTING RECORDS
The accounting records of OG&E are maintained in accordance with the Uniform System of Accounts prescribed by the Federal Energy Regulatory Commission ("FERC") and adopted by the Oklahoma Corporation Commission (the "Oklahoma Commission") and the Arkansas Public Service Commission (the "Arkansas Commission"). Additionally, OG&E is subject to the accounting principles prescribed by Statement of Financial Accounting Standards ("SFAS") No. 71, "Accounting for the Effects of Certain Types of Regulation".
PROPERTY, PLANT AND EQUIPMENT
All property, plant and equipment is recorded at cost. Electric utility plant is recorded at its original cost. Newly constructed plant is added to plant balances at costs which include contracted services, direct labor, materials, overhead, and allowance for funds used during construction. Replacement of major units of property are capitalized as plant. The replaced plant is removed from plant balances and the cost of such property together with the cost of removal less salvage is charged to accumulated depreciation. Repair and replacement of minor items of property are included in the Consolidated Statements of Income as maintenance expense.
DEPRECIATION
The provision for depreciation, which was approximately 3.2% of the average depreciable utility plant, for each of the years 1993, 1992 and 1991, is provided on a straight-line method over the estimated service life of the property. Depreciation is provided at the unit level for production plant and at the account or sub-account level for all other plant, and is based on the average life group procedure.
Enogex's gas pipeline and gas processing plants are depreci- ated on a straight-line method over a period of 20 to 48 years.
ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION
Allowance for funds used during construction ("AFUDC") is calculated according to FERC pronouncements for the imputed cost of equity and borrowed funds. AFUDC, a non-cash item, is reflected as a credit on the Consolidated Statements of Income and a charge to construction work in progress.
AFUDC rates, compounded semi-annually, were 3.60%, 4.30% and 7.48% for the years 1993, 1992 and 1991, respectively.
OPERATING REVENUES
OG&E accrues estimated revenues for services provided but not yet billed. The cost of providing service is recognized as incur- red.
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 estimated cost-of-service for ratemaking, are charged to substantially all of the Company's electric customers through automatic fuel adjustment clauses. A lag of 45 to 60 days occurs between the time costs are incurred and the time such costs are reflected in bills to retail customers. OG&E records an accrual in the financial statements for these differences. The automatic fuel adjustment clauses are subject to periodic review by the Oklahoma Commission, the Arkansas Commission and FERC.
FUEL INVENTORIES
Fuel inventories for the generation of electricity consist of coal, oil and natural gas. These inventories are accounted for under the last-in, first-out ("LIFO") cost method. Based on the average cost of fuel purchased in late 1993, the estimated replacement cost of fuel inventories at December 31, 1993, exceeded the stated LIFO cost by approximately $2.3 million. Natural gas products inventory are held for resale and accounted for based on the weighted average cost of production.
2. Income Taxes
The items comprising tax expense are as follows:
(dollars in thousands) Year ended December 31 1993 1992 1991 ------------------------------------------------------------------ Current Income Taxes Provision for current taxes: Federal . . . . . . . . . . . $ 61,406 $ 52,191 $ 68,960 State . . . . . . . . . . . . 10,597 9,134 10,879 ------------------------------------------------------------------ Total Current Income Taxes . 72,003 61,325 79,839 ------------------------------------------------------------------ Deferred Income Taxes, net Provision (benefit) for deferred taxes: Federal Depreciation . . . . . . . 9,673 6,185 7,086 Repair allowance . . . . . 1,306 1,908 (5,136) Removal costs . . . . . . . 1,026 635 425 Provision for rate refund . (6,972) (5,774) - Other . . . . . . . . . . . (225) 1,059 395 State . . . . . . . . . . . 424 333 1,278 ------------------------------------------------------------------ Total Deferred Income Taxes, net 5,286 4,346 4,048 ------------------------------------------------------------------ Deferred Investment Tax Credits, net . . . . . . . . . . . . . (5,150) (5,465) (6,173) Income Taxes Relating to Other Income and Deductions . . . . (538) (1,006) (1,158) ------------------------------------------------------------------ Total Income Tax Expense . . $ 71,601 $ 59,200 $ 76,556 ------------------------------------------------------------------ Pretax Income . . . . . . . . . $185,878 $158,912 $210,472 ------------------------------------------------------------------
The following schedule reconciles the statutory federal tax rate to the effective income tax rate:
Year ended December 31 1993 1992 1991 ---------------------------------------------------------------- Statutory federal tax rate . . 35.0% 34.0% 34.0% State income taxes, net of federal income tax benefit . . 3.9 3.9 4.0
Investment tax credits, net . . (2.8) (3.4) (2.9) Change in federal tax rate. . . 0.9 - - Other, net . . . . . . . . . . 1.5 2.8 1.3
Effective income tax rate as reported . . . . . . . 38.5% 37.3% 36.4%
The Company files consolidated income tax returns. Income taxes are allocated to each company based on its separate taxable income or loss.
Investment tax credits on electric utility property have been deferred and are being amortized to income over the life of the related property.
For 1992 and 1991, provisions for deferred income taxes were recorded primarily as a result of the use of income tax law provisions which allowed for the deduction or addition of items to taxable income in the tax return prior to or after their being recorded on the books of the Company.
Effective January 1, 1993, the Company adopted SFAS No. 109, "Accounting for Income Taxes," which requires an asset and liability approach to accounting for income taxes. Under SFAS No. 109, deferred tax assets or liabilities are computed based on the difference between the financial statement and income tax bases of assets and liabilities ("temporary differences") using the enacted marginal tax rate. Deferred income tax expenses or benefits are based on the changes in the asset or liability from period to period. The Company elected not to restate the financial statements for years ending before January 1, 1993. When adopted, SFAS No. 109 had no effect on net income.
The deferred tax provisions, set forth above, are recognized as costs in the ratemaking process by the commissions having jurisdiction over the rates charged by OG&E.
The components of Accumulated Deferred Income Taxes adjusted to reflect the impact of the increase in the federal income tax rate, are as follows:
(dollars in thousands) Jan 1, 1993 Dec 31, 1993 Current Deferred Tax Assets: Accrued vacation..................... $ 3,359 $ 4,177 Provision for rate refund............ - 14,965 Customer deposits.................... 1,102 - Uncollectible accounts............... 3,669 4,946
Accumulated deferred tax assets...... $ 8,130 $ 24,088
Deferred Tax Liabilities: Accelerated depreciation and other property-related differences....... $438,419 $439,253 Allowance for funds used during construction................ 61,346 57,074 Income taxes recoverable through future rates....................... 61,829 62,441
Total.............................. 561,594 558,768
Deferred Tax Assets: Deferred investment tax credits...... (32,850) (30,616) Income taxes refundable through future rates....................... (49,100) (44,022) Provision for rate refund............ (7,074) - Other................................ (411) (127)
Total.............................. (89,435) (74,765)
Accumulated Deferred Income Taxes...... $472,159 $484,003
The effect of adopting SFAS No. 109 at January 1, 1993, before adjusting for the new tax rate, resulted in a net increase in property, plant and equipment of approximately $73.9 million, a net decrease in income taxes recoverable through future rates of approximately $12.0 million and a net increase in accumulated deferred income taxes of approximately $61.9 million. Also at January 1, 1993, approximately $8.1 million of deferred tax assets which were previously netted with accumulated deferred income taxes, were reclassified as current assets as a result of adopting SFAS No. 109.
At December 31, 1992, the Company had recorded $44.4 million as unfunded deferred income taxes recoverable from customers. A corresponding amount was reflected as a component of accumulated deferred income taxes which represented amounts refundable to customers. As a result of the adoption of SFAS No. 109, the $44.4 million amount that was recorded as a component of accumulated deferred income taxes at December 31, 1992, was reclassified January 1, 1993, as a regulatory liability and netted against the regulatory asset. This reclassification combined with the $12.0 million net decrease in income taxes recoverable through future rates discussed above, resulted in a $32.4 million net increase in the amount recognized as income taxes to be recovered through future rates.
The Omnibus Reconciliation Act of 1993, signed into law on August 10, 1993, increased the top federal corporate tax rate from 34 to 35 percent. The 35 percent rate was retroactively made effective January 1, 1993.
For the temporary differences that existed at January 1, 1993, the change in the federal income tax rate increased the provision for income taxes and accumulated deferred income taxes approximately $1.6 and $18.0 million, respectively. Approximately $16.4 million of the increase which was applicable to utility operations was recorded as income taxes recoverable from customers through future rates and therefore had no impact on results of operations for the year ended December 31, 1993.
3. Common Stock and Retained Earnings
There were no new shares of common stock issued during 1993, 1992 or 1991. The changes in premium on capital stock as presented on the Consolidated Statements of Capitalization represents the gains and losses associated with the issuance of common stock pursuant to the Restricted Stock Plan. Changes in common stock were:
(thousands) 1993 1992 1991 ------------------------------------------------------------------------- Shares outstanding January 1............ 40,329 40,310 40,298 Issued/reacquired under the Restricted Stock Plan, net............ 17 19 12 ------------------------------------------------------------------------- Shares outstanding December 31.......... 40,346 40,329 40,310 =========================================================================
There were 4,009,021 shares of unissued common stock reserved for the various employee and Company stock plans at December 31, 1993.
The Company's Restated Certificate of Incorporation and its Trust Indenture, as supplemented, relating to the First Mortgage Bonds, contained provisions which, under specific conditions, limit the amount of dividends (other than in shares of common stock) and/or other distributions which may be made to common shareowners.
In December 1991, holders of the Company's First Mortgage Bonds approved a series of amendments to the Company's Trust Indenture. The amendments eliminated the cumulative amount of the previous restrictions on retained earnings related to the payment of dividends and provided management with the flexibility to repurchase its common stock, when appropriate, in order to maintain desired capitalization ratios and to achieve other business needs. The Company is amortizing approximately $14
million of costs relating to obtaining such amendments over the remaining life of the respective bond issues. At the end of 1993, there was approximately $11.6 million in unamortized costs associated with obtaining these amendments.
RESTRICTED STOCK PLAN
The Company has a Restricted Stock Plan whereby certain employees may periodically receive shares of the Company's common stock at the discretion of the Board of Directors. The Company distributed 18,687, 18,631 and 12,200 shares of common stock during 1993, 1992 and 1991, respectively, pursuant to this plan. The shares distributed in the reported periods were issued from treasury stock.
SHAREOWNERS RIGHTS PLAN
In December 1990, the Company adopted a Shareowners Rights Plan designed to protect shareowners' interests in the event that the Company is ever confronted with an unfair or inadequate acquisition proposal. Pursuant to the plan, the Company declared a dividend distribution of one "right" for each share of Company common stock. Each right entitles the holder to purchase from the Company one one-hundredth of a share of new preferred stock of the Company under certain circumstances. The rights may be exercised if a person or group announces its intention to acquire, or does acquire, 20 percent or more of the Company's common stock. Under certain circumstances, the holders of the rights will be entitled to purchase either shares of common stock of the Company or common stock of the aquirer at a reduced percentage of market value. The rights will expire on December 11, 2000.
4. Cumulative Preferred Stock
Preferred stock is redeemable at the option of OG&E at the following amounts per share plus accrued dividends: the 4% Cumulative Preferred Stock at the par value of $20 per share; the Cumulative Preferred Stock, par value $100 per share, as follows: 4.20% series-$102; 4.24% series-$102.875; 4.44% series-$102; 4.80% series-$102; and 5.34% series-$101.
As approved by shareowners on May 16, 1991, the Restated Certificate of Incorporation was amended to permit the issuance of new series of preferred stock with dividends payable other than quarterly.
5. Long-Term Debt
OG&E's Trust Indenture, as supplemented, relating to the First Mortgage Bonds, requires OG&E to pay to the trustee annually, an amount sufficient to redeem, for sinking fund purposes, 1-1/4 % of the highest amount outstanding at any time. This requirement has been satisfied by pledging permanent additions to property to the extent of 166-2/3 % of principal amounts of bonds otherwise required to be redeemed. Through Dec- ember 31, 1993, gross property additions pledged totaled approxi- mately $341 million.
Annual sinking fund requirements for each of the five years subsequent to December 31, 1993, are as follows:
Year Amount ---------------------------------------- 1994 ............ $15,114,583 1995 ............ 14,593,750 1996 ............ 14,593,750 1997 ............ 14,281,250 1998 ............ 13,760,417 ----------------------------------------
As in prior years, OG&E expects to meet these requirements by pledging permanent additions to property.
The 6-3/4 % Series, $33 million Muskogee Industrial Trust Pollution Control Revenue Bonds of 1976, are subject to mandatory annual cash sinking fund requirements, which began March 1, 1992. Cash sinking fund payments for the next five years are as follows: $350,000 in 1994 and 1995; and $500,000 in 1996, 1997 and 1998. The annual amount escalates to $900,000 due March 1, 2005, with the balance of $24,750,000 due March 1, 2006. These amounts are not included in the above schedule.
Enogex debt consists of the following notes payable: $60 million, with interest rates between 9.88%-10.03%, maturing December 21, 1995; and $30 million, with interest rates between 9.96%-10.11%, maturing December 21, 1998.
Maturities of First Mortgage Bonds during the next five years consist of $25 million in 1995, $15 million in 1997 and $25 million in 1998.
Unamortized debt expense and unamortized premium and discount on long-term debt are being amortized over the life of the respective debt.
Substantially all electric plant was subject to lien of the Trust Indenture at December 31, 1993.
6. Short-Term Debt
The Company borrows on a short-term basis, as necessary, by the issuance of commercial paper and by obtaining short-term bank loans. The maximum and average amounts of short-term borrowings during 1993 were $136.6 million and $62.5 million, respectively, at a weighted average interest rate of 3.60%. The Company has an agreement for a flexible line of credit, up to $200 million, through December 31, 1996. The line of credit which was nominated by the Company at $160 million at year-end is maintained on a fee basis of 1/8 of 1%, per year, on the unused balance. Short-term debt in the amount of $47.0 million was outstanding at December 31, 1993.
7. Postemployment Benefit Plans
PENSION PLAN
All eligible employees of the Company are covered by a non-contributory defined benefit pension plan. Under the plan, retirement benefits are primarily a function of both the years of service and the highest average monthly compensation for 60 consecutive months out of the last 120 months of service.
It is the Company's policy to fund the plan on a current basis to comply with the minimum required contributions under existing tax regulations. Such contributions are intended to provide not only for benefits attributed to service to date, but also for those expected to be earned in the future.
Net periodic pension cost is computed in accordance with provisions of SFAS No. 87, "Employers' Accounting for Pensions," and is recorded as other operation expense in the accompanying Consolidated Statements of Income.
In determining the projected benefit obligation, the weighted average discount rate used was 7.25% in 1993 and 8.5% in 1992 and 1991, while the assumed rate of increase in future salary levels was 4.5% in 1993 and 5.5% in 1992 and 1991. The expected long-term rate of return on assets used in determining net periodic pension cost was 9.0% for the reported periods.
The plan's assets consist primarily of U. S. Government securities, listed common stocks and corporate debt.
Net periodic pension costs for 1993, 1992 and 1991 included the following:
(dollars in thousands) 1993 1992 1991 ---------------------------------------------------------------------- Service costs-benefits earned during year.......................... $ 7,630 $ 7,266 $ 6,518 Interest cost on projected benefit obligation................... 14,557 13,657 13,242 Return on plan assets................... (15,697) (14,761) (13,047) Net amortization and deferral........... (1,263) (1,263) (1,353) Amortization of unrecognized prior service cost................... 671 671 552 Settlement gain......................... - - (88) ---------------------------------------------------------------------- Net periodic pension cost............... $ 5,898 $ 5,570 $5,824 ======================================================================
The following table sets forth the plan's funded status at December 31, 1993, 1992 and 1991:
POSTRETIREMENT HEALTH CARE AND LIFE INSURANCE BENEFITS
In addition to providing pension benefits, the Company provides certain health care and life insurance benefits for retired members ("postretirement benefits"). Employees retiring from the Company on or after attaining age 55 who have met certain length of service requirements are entitled to these benefits. The benefits are subject to deductibles, co-payment provisions and other limitations. Prior to January 1, 1993, the costs of retiree health care and life insurance benefits were recognized as expense when claims were paid ("pay-as-you-go"). Pay-as-you-go costs totaled approximately $3,804,000, $3,443,000 and $3,272,000 for 1993, 1992 and 1991, respectively.
In December 1990, the Financial Accounting Standards Board ("FASB") issued SFAS No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions." The Company adopted the provisions of SFAS No. 106 beginning January 1, 1993. This standard requires that employers accrue the cost of postretirement benefits during the active service periods of employees until the date they attain full eligibility for the benefits.
In the February 25, 1994 order from the Oklahoma Commission, OG&E was directed to recover postretirement benefit costs following the pay-as-you-go method and to defer the incremental cost associated with accrual recognition of SFAS No. 106 related costs following a "phase-in" plan proposed by the Commission staff. In accordance with this phase-in plan, OG&E may defer the amortization of the transition obligation for up to five years or until OG&E's next general rate case, whichever occurs first. The phase-in plan also provides for OG&E to defer 100% of the incremental cost associated with accrual recognition of SFAS No. 106 related costs, exclusive of the amortization of OG&E's transition obligation, in 1993. The percentage of these incremental costs that may be deferred is reduced 25% each year beginning in 1994. OG&E deferred approximately $8.9 million of postretirement costs in 1993.
The Company will record a regulatory asset for the difference between any amounts using the pay-as-you-go method and those required by SFAS No. 106 in accordance with the phase-in plan. However, until the Oklahoma Commission issues an order approving recovery for this difference, there can be no assurance that the Company will be able to recover such costs in rates. Consequently, the Company is unable to determine the final impact of implementation of SFAS No. 106.
On March 25, 1993, the Arkansas Commission issued an order adopting accrual accounting and deferral of the differential between "pay-as-you-go" and accrued postretirement benefit costs for those companies requesting such deferral. In 1993, the Federal Energy Regulatory Commission issued its final agency action for SFAS No. 106, approving accrual accounting and deferral of the
differential. Recovery is expected for the amounts deferred in both of these jurisdictions.
The Company currently does not have a plan to fund postretire- ment benefits. Any decisions on funding will be considered along with requirements established by the commission in each jurisdic- tion.
Net postretirement benefit expense for the year ended December 31, 1993, included the following components:
(dollars in thousands) ------------------------------------------------ Service cost............................$ 2,812 Interest cost........................... 6,158 Amortization of transition obligation... 3,687 Net amount capitalized or deferred...... (8,853) ------------------------------------------------ Net postretirement benefit expense....$ 3,804 ================================================
The following table sets forth the funded status of the plans and amounts recognized in the Company's Consolidated Balance Sheets as of December 31, 1993:
The discount rate used in determining the accumulated postretirement benefit obligation was 8.5 percent and 7.25 percent for January 1, 1993 and December 31, 1993, respectively. The rate of increase in future compensation levels used in measuring the life insurance accumulated postretirement benefit obligation was 5.5 percent and 4.5 percent for January 1, 1993 and December 31, 1993, respectively. A 14.0 percent annual rate of increase in the per capita cost of covered health care benefits was assumed for 1993; the rate is assumed to decrease gradually to 5.5 percent by the year 2005 and remain at that level thereafter. A one- percentage-point increase in the assumed health care cost trend rates would increase the accumulated postretirement benefit
obligation as of December 31, 1993, by approximately $6.8 million, and the aggregate of the service and interest cost components of net postretirement health care cost for 1993 by approximately $1.5 million.
POSTEMPLOYMENT BENEFITS
In November 1992, the FASB issued SFAS No. 112, "Employers' Accounting for Postemployment Benefits," which will require the Company to accrue the estimated cost of benefits provided to former or inactive employees after employment but before retirement. Adoption of SFAS No. 112 is required for fiscal years beginning after December 15, 1993, with earlier application permitted for which annual financial statements have not previously been issued. The Company will adopt this new standard effective January 1, 1994, and believes these costs will not have a material impact on its consolidated financial position or results of operations.
8. Report of Business Segments
The Company's electric utility segment is an operating public utility engaged in the generation, transmission, distribution, and sale of electric energy. The non-utility subsidiary segment is engaged in the gathering and transmission of natural gas, and through its subsidiaries, is engaged in the processing of natural gas and the marketing of natural gas liquids, in the buying and selling of natural gas to third parties, and in the exploration for and production of natural gas and related products.
(dollars in thousands) 1993 1992 1991 ------------------------------------------------------------------- Operating information: Operating Revenues Electric utility......... $1,282,816 $1,193,993 $1,210,726 Non-utility subsidiary... 219,376 189,574 170,490 Intersegment revenues (A) (54,940) (68,583) (66,446) ------------------------------------------------------------------- Total................ $1,447,252 $1,314,984 $1,314,770 ------------------------------------------------------------------- Pre-tax Operating Income Electric utility......... $ 238,761 $ 206,350 $ 249,559 Non-utility subsidiary... 28,531 30,860 39,242 ------------------------------------------------------------------- Total................ $ 267,292 $ 237,210 $ 288,801 ------------------------------------------------------------------- Net Income Electric utility ........ $ 104,730 $ 88,293 $ 116,531 Non-utility subsidiary... 9,547 11,419 17,385 ------------------------------------------------------------------- Total................ $ 114,277 $ 99,712 $ 133,916 ------------------------------------------------------------------- Investment Information: Identifiable Assets as of December 31 Electric utility......... $2,443,651 $2,358,661 $2,356,712 Non-utility subsidiary... 287,773 231,422 209,377 ------------------------------------------------------------------- Total................ $2,731,424 $2,590,083 $2,566,089 ------------------------------------------------------------------- Other Information: Depreciation Electric utility......... $ 104,343 $ 100,531 $ 97,950 Non-utility subsidiary... 15,200 10,169 9,764 ------------------------------------------------------------------- Total................ $ 119,543 $ 110,700 $ 107,714 ------------------------------------------------------------------- Construction Expenditures Electric utility......... $ 105,746 $ 109,650 $ 107,500 Non-utility subsidiary... 22,396 30,601 7,842 ------------------------------------------------------------------- Total................ $ 128,142 $ 140,251 $ 115,342 -------------------------------------------------------------------
(A) Intersegment revenues are recorded at prices comparable to those of unaffiliated customers and are affected by regulatory considerations.
9. Commitments and Contingencies
The Company has entered into purchase commitments in connection with its construction program and the purchase of necessary fuel supplies of coal and natural gas for its generating units. The Company's construction expenditures for 1994 are estimated at $143 million.
The Company acquires natural gas for boiler fuel under approximately 900 individual contracts, some of which contain provisions allowing the owners to require prepayments for gas if certain minimum quantities are not taken. At December 31, 1993, 1992 and 1991, outstanding prepayments for gas, including the amounts classified as current assets, under these contracts were approximately $22,165,000, $24,543,000 and $20,851,000, respectively. The Company may be required to make additional prepayments in subsequent years. The Company expects to recover these prepayments as fuel costs if unable to take the gas prior to the expiration of the contracts.
At December 31, 1993, the Company held non-cancelable operating leases covering approximately 1,523 coal hopper railcars. Rental payments are charged to fuel expense and recovered through the Company's tariffs and automatic fuel adjustment clauses. The leases have purchase and renewal options. Future minimum lease payments due under the railcar leases, assuming the leases are renewed under the renewal option are as follows:
(dollars in thousands) 1994................ $4,749 1997................ $ 3,391 1995................ 3,850 1998................ 3,333 1996................ 3,508 1999 and beyond..... 78,703
Rental payments under operating leases were approximately $4.9 million in 1993, $3.6 million in 1992 and $3.0 million in 1991.
OG&E is required to maintain the railcars it has under lease to transport coal from Wyoming and has entered into an agreement with Railcar Maintenance Company, a non-affiliated company, to furnish this maintenance.
The Company has entered into an agreement with an unrelated third party to develop a natural gas storage facility. According to that agreement, the Company made cash advances to the developer amounting to approximately $24.4 million, as of December 31, 1993, which is included in "Prepayments and other" in the accompanying Balance Sheets.
The Company has entered into agreements with four qualifying cogeneration facilities having initial terms of 3 to 32 years. These contracts were entered into pursuant to the Public Utility Regulatory Policy Act of 1978 ("PURPA"). Stated generally, PURPA and the regulations thereunder promulgated by FERC require the
Company to purchase power generated in a manufacturing process from a qualified cogeneration facility ("QF"). The rate for such power to be paid by the Company was approved by the Oklahoma Commission. The rate generally consists of two components: one is a rate for actual electricity purchased from the QF by the Company; the other is a capacity charge which the Company must pay the QF for having the capacity available. However, if no electrical power is made available to the Company for a period of time (generally three months), the Company's obligation to pay the capacity charge is suspended. The total cost of cogeneration payments is currently recoverable in rates from Oklahoma customers.
During 1993, 1992 and 1991, OG&E made total payments to cogenerators of approximately $213.0 million, $179.4 million and $170.5 million, of which $165.5 million, $101.6 million and $97.3 million, respectively, represented capacity payments. All payments for purchased power, including cogeneration, are included in the Consolidated Statements of Income as purchased power. The future minimum capacity payments under the contracts for the next five years are approximately: 1994 - $173 million, 1995 - $174 million, 1996 - $175 million, 1997 - $177 million and 1998 - $180 million.
The Company is a party to three separate actions brought by the Environmental Protection Agency ("EPA") concerning cleanup of disposal sites for hazardous waste. The Company was not the owner or operator of those sites. Rather, the Company along with many others, shipped materials to the owners or operators of the sites who failed to dispose of the materials in an appropriate manner. The Company has calculated that its portion of total waste disposed at the sites is relatively minor. The cost of complying with the EPA sanctions at these sites is difficult to estimate. However, based on the relative percentage attributed to the Company and other considerations, management believes the ultimate outcome of these matters will not have a material adverse effect on the Company's consolidated financial position or results of operations.
The Clean Air Act Amendments of 1990 among other things, limits the amount of sulfur dioxide and nitrogen oxides that may be released into the air. The Company will not be required to file its compliance plan with the EPA until January 1996.
In 1992, OG&E began a voluntary review of information contained in the annual report required under the Toxic Substance Control Act ("TSCA") for 1991. The initial result of the review revealed some discrepancies in operating practices and documentation. The EPA was notified of these initial discrepancies in December 1992. Because it was suspected that additional discrepancies might be discovered during the continuing review/audit, OG&E reached an agreement on January 12, 1993, with the EPA, Region VI, concerning the notification and reporting requirements of any newly discovered discrepancies.
After further investigation, OG&E reported in September 1993 numerous additional discrepancies to the EPA, Region VI. Many of the discrepancies could be deemed violations of the regulations under TSCA. Under the TSCA regulations, the EPA has the authority to assess a maximum fine of up to $25,000 per day, and to treat each day of violation as the basis for a separate fine. OG&E has taken and is taking corrective action to remedy the discrepancies.
The position of the EPA and OG&E is that they are currently in pre-settlement negotiations. No fines have been assessed as of this date. Since this matter is currently being negotiated, OG&E does not know the amount of fines that the EPA may seek. The amount of the fine is dependent upon numerous interpretative issues under the TSCA regulations and potentially could be in an amount material to the Company's results of operations. However, at the present time, the Company does not expect that the amount of the fine will have a material effect on its results of operations based primarily on having voluntarily reported the discrepancies to the EPA coupled with the Company's efforts to remedy the discrepancies and the lack of releases into the environment or harm to individuals.
In the normal course of business, other lawsuits, claims, environmental actions, and other governmental proceedings arise against the Company. Management, after consultation with legal counsel, does not anticipate that liabilities arising out of other currently pending or threatened lawsuits and claims will have a material adverse effect on the Company's consolidated financial position or results of operations.
10. Rate Matters And Regulation
On February 25, 1994, the Oklahoma Commission issued an order that, among other things, effectively lowered OG&E's rates to its Oklahoma retail customers by approximately $14 million annually (based on a test year ended June 30, 1991) and to refund approximately $41.3 million. The $14 million annual reduction in rates is expected to lower OG&E's rates to its Oklahoma customers by approximately $17 million in 1994. With respect to the $41.3 million refund, $39.1 million is associated with revenues prior to January 1, 1994, while the remaining $2.2 million relates to 1994.
During the first half of 1992 the Company participated in settlement negotiations and offered a proposed refund and a reduction in rates in an effort to reach settlement and conclude the proceedings. As a result, the Company recorded an $18 million provision for a potential refund in 1992. After receiving the February 25, 1994 order, the Company recorded an additional provision for rate refund of approximately $21.1 million in 1993, (consisting of a $14.9 million reduction in revenue and $6.2 million in interest) which reduced net income by some $13 million or $0.32 per share.
Enogex transports natural gas to OG&E for use at its gas-fired generating units and performs related gas gathering activities for OG&E. The entire $41.3 million refund relates to the Oklahoma Commission's disallowance of a portion of the fees paid by OG&E to Enogex for such services in the past. Of the approximately $17 million annual rate reduction, approximately $9.9 million reflects the Oklahoma Commission's reduction of the amount to be recovered by OG&E from its Oklahoma customers for the future performance of such services by Enogex for OG&E.
11. Disclosures about Fair Value of Financial Instruments
The following methods and assumptions were used to estimate the fair value of each class of financial instruments:
Cash and Cash Equivalents and Customer Deposits The fair value of cash and cash equivalents and customer deposits approximate the carrying amount due to their short maturity.
Capitalization The fair value of Long-term Debt and Preferred Stocks is estimated based on quoted market prices and management's estimate of current rates available for similar issues. The fair value of Medium-term Notes is based on management's estimate of current rates available for similar issues with the same remaining maturities.
Indicated below are the carrying amounts and estimated fair values of the Company's financial instruments as of December 31:
In May 1993, the Financial Accounting Standards Board issued SFAS No. 115, "Accounting for Certain Investments in Debt and Equity Securities." This statement addresses the accounting and reporting for investments in equity securities that have readily determinable fair values and for all investments in debt securities. Adoption of SFAS No. 115 is required for fiscal years beginning after December 15, 1993, with earlier application permitted for which annual financial statements have not previously been issued. The Company will adopt this new standard effective January 1, 1994, and believes these costs will not have a material impact on its consolidated financial position or results of operations.
Report of Independent Public Accountants ----------------------------------------
To the Shareowners of Oklahoma Gas and Electric Company:
We have audited the accompanying consolidated balance sheets and statements of capitalization of Oklahoma Gas and Electric Company (an Oklahoma corporation) and its subsidiaries as of December 31, 1993, 1992 and 1991, and the related consolidated statements of income, retained earnings and cash flows for the years then ended. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Oklahoma Gas and Electric Company and its subsidiaries as of December 31, 1993, 1992 and 1991, and the results of their operations and their cash flows for the years then ended in conformity with generally accepted accounting principles.
Arthur Andersen & Co.
Oklahoma City, Oklahoma, February 28, 1994
Report of Management --------------------
To Our Shareowners:
The management of Oklahoma Gas and Electric Company and its subsidiaries has prepared, and is responsible for the integrity and objectivity of the financial and operating information contained in this Annual Report. The consolidated financial statements have been prepared in accordance with generally accepted accounting principles and include certain amounts that are based on the best estimates and judgments of management.
To meet its responsibility for the reliability of the consolidated financial statements and related financial data, the Company's management has established and maintains an internal control structure. This structure provides management with reasonable assurance in a cost-effective manner that, among other things, assets are properly safeguarded and transactions are executed and recorded in accordance with its authorizations so as to permit preparation of financial statements in accordance with generally accepted accounting principles. The Company's internal auditors assess the effectiveness of this internal control structure and recommend possible improvements thereto on an ongoing basis.
The Company maintains high standards in selecting, training and developing its members. This, combined with Company policies and procedures, provides reasonable assurance that operations are conducted in conformity with applicable laws and with its commitment to the highest standards of business conduct.
Supplementary Data ------------------
INTERIM CONSOLIDATED FINANCIAL INFORMATION (UNAUDITED) In the opinion of the Company, the following quarterly information includes all adjustments, consisting of normal recurring adjustments, necessary for a fair statement of the results of operations for such periods:
Dec 31 Sep 30 Jun 30 Mar 31 Quarter ended (dollars in thousands except per share data) ------------------------------------------------------------------------- Operating revenues..... 1993 $301,392 $500,639 $341,799 $303,422 1992 304,093 443,327 306,341 261,223 1991 284,619 426,580 329,375 274,196 ------------------------------------------------------------------------- Operating income....... 1993 $ 18,899 $111,576 $ 39,457 $ 25,221 1992 32,043 94,319 36,072 14,570 1991 30,870 93,646 55,968 30,603 ------------------------------------------------------------------------- Net income (loss)...... 1993 $ (3,619) $ 90,810 $ 20,396 $ 6,690 1992 10,629 76,035 17,015 (3,967) 1991 12,260 75,255 33,474 12,927 ------------------------------------------------------------------------- Earnings (loss) available for common.. 1993 $ (4,199) $ 90,231 $ 19,817 $ 6,111 1992 10,050 75,456 16,436 (4,547) 1991 11,680 74,676 32,895 12,348 ------------------------------------------------------------------------- Earnings (loss) per average common share.. 1993 $ (0.10) $ 2.24 $ 0.49 $ 0.15 1992 0.25 1.87 0.41 (0.11) 1991 0.29 1.85 0.82 0.31 -------------------------------------------------------------------------
Item 9.

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure. ---------------------------------------------------------
Not applicable.
Part III
Item 10.



Item 10. Directors and Executive Officers of the Registrant. ------------------------------------------------------------
Item 11.

Item 11. Executive Compensation. --------------------------------
Item 12.

Item 12. Security Ownership of Certain Beneficial Owners and Management. -------------------------------------------------
Item 13.

Item 13. Certain Relationships and Related Transactions. --------------------------------------------------------
Items 10, 11, 12 and 13 are omitted pursuant to General Instruction G of Form 10-K, since OG&E filed copies of a definitive proxy statement with the Securities and Exchange Commission on or about March 28, 1994. Such proxy statement is incorporated herein by reference. In accordance with Instruction G of Form 10-K, the information required by Item 10 relating to Executive Officers has been included in Part I, Item 4, of this Form 10-K.
Part IV
Item 14.

Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K. ----------------------------------------------------
(a) 1. Financial Statements
The following consolidated financial statements and supplementary data are included in Part II, Item 8 of this Report:
Consolidated Balance Sheets at December 31, 1993, 1992 and Consolidated Statements of Income for the years ended December 31, 1993, 1992 and 1991 Consolidated Statements of Retained Earnings for the years ended December 31, 1993, 1992 and 1991 Consolidated Statements of Capitalization at December 31, 1993, 1992 and 1991 Consolidated Statements of Cash Flows for the years ended December 31, 1993, 1992 and 1991 Notes to Consolidated Financial Statements Report of Independent Public Accountants Report of Management
Supplementary Data ------------------
Interim Consolidated Financial Information
2. Financial Statement Schedules (included in Part IV) Page ------------------------------------------------------ ----
Schedule V - Property, plant and equipment 75 Schedule VI - Accumulated depreciation, depletion, and amortization of property, plant, and equipment 76 Schedule VIII - Valuation and qualifying accounts 77 Schedule IX - Short-term borrowings 78 Schedule X - Supplementary income statement information 79 Report of Independent Public Accountants 80
All other schedules have been omitted since the required information is not applicable or is not material, or because the information required is included in the respective financial statements or notes thereto.
3. Exhibits ------------
Exhibit No. Description ----------- -----------
3.01 Copy of Restated Certificate of Incorporation. (Filed as Exhibit 4.01 to the Company's Post- Effective Amendment No. Two to Registration Statement No. 2-94973, and incorporated by reference herein)
3.02 By-laws. (Filed as Exhibit 4.02 to Post-Effective Amendment No. Two to Registration Statement No. 2-94973 and incorporated by reference herein)
4.01 Copy of Trust Indenture, dated February 1, 1945, from OG&E to The First National Bank and Trust Company of Oklahoma City, Trustee. (Filed as Exhibit 7-A to Registration Statement No. 2-5566 and incorporated by reference herein)
4.02 Copy of Supplemental Trust Indenture, dated December 1, 1948, being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 7.03 to Registration Statement No. 2-7744 and incorporated by reference herein)
4.03 Copy of Supplemental Trust Indenture, dated June 1, 1949, being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 7.03 to Registration Statement No. 2-7964 and incorporated by reference herein)
4.04 Copy of Supplemental Trust Indenture, dated May 1, 1950, being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 7.04 to Registration Statement No. 2-8421 and incorporated by reference herein)
4.05 Copy of Supplemental Trust Indenture, dated March 1, 1952, a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 4.08 to Registration Statement No. 2-9415 and incorporated by reference herein)
4.06 Copy of Supplemental Trust Indenture, dated June 1, 1955, being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 4.07 to Registration Statement No. 2-12274 and incorporated by reference herein)
4.07 Copy of Supplemental Trust Indenture, dated January 1, 1957, being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 2.07 to Registration Statement No. 2-14115 and incorporated by reference herein)
4.08 Copy of Supplemental Trust Indenture, dated June 1, 1958, being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 4.09 to Registration Statement No. 2-19757 and incorporated by reference herein)
4.09 Copy of Supplemental Trust Indenture, dated March 1, 1963, being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 2.09 to Registration Statement No. 2-23127 and incorporated by reference herein)
4.10 Copy of Supplemental Trust Indenture, dated March 1, 1965, being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 4.10 to Registration Statement No. 2-25808 and incorporated by reference herein)
4.11 Copy of Supplemental Trust Indenture, dated January 1, 1967, being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 2.11 to Registration Statement No. 2-27854 and incorporated by reference herein)
4.12 Copy of Supplemental Trust Indenture, dated January 1, 1968, being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 2.12 to Registration Statement No. 2-31010 and incorporated by reference herein)
4.13 Copy of Supplemental Trust Indenture, dated January 1, 1969, being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 2.13 to Registration Statement No. 2-35419 and incorporated by reference herein)
4.14 Copy of Supplemental Trust Indenture, dated January 1, 1970, being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 2.14 to Registration Statement No. 2-42393 and incorporated by reference herein)
4.15 Copy of Supplemental Trust Indenture, dated January 1, 1972, being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 2.15 to Registration Statement No. 2-49612 and incorporated by reference herein)
4.16 Copy of Supplemental Trust Indenture, dated January 1, 1974, being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 2.16 to Registration Statement No. 2-52417 and incorporated by reference herein)
4.17 Copy of Supplemental Trust Indenture, dated January 1, 1975, being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 2.17 to Registration Statement No. 2-55085 and incorporated by reference herein)
4.18 Copy of Supplemental Trust Indenture, dated January 1, 1976, being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 2.18 to Registration Statement No. 2-57730 and incorporated by reference herein)
4.19 Copy of Supplemental Trust Indenture, dated September 14, 1976, being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 2.19 to Registration Statement No. 2-59887 and incorporated by reference herein)
4.20 Copy of Supplemental Trust Indenture, dated January 1, 1977, being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 2.20 to Registration Statement No. 2-59887 and incorporated by reference herein)
4.21 Copy of Supplemental Trust Indenture, dated November 1, 1977, being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 4.21 to Registration Statement No. 2-70539 and incorporated by reference herein)
4.22 Copy of Supplemental Trust Indenture, dated December 1, 1977, being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 4.22 to Registration Statement No. 2-70539 and incorporated by reference herein)
4.23 Copy of Supplemental Trust Indenture, dated February 1, 1980, being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 4.23 to Registration Statement No. 2-70539 and incorporated by reference herein)
4.24 Copy of Supplemental Trust Indenture, dated April 15, 1982, being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 4.24 to the Company's Form 10-K Report, File No. 1-1097, for the year ended December 31, 1982, and incorporated by reference herein)
4.25 Copy of Supplemental Trust Indenture, dated August 15, 1986, being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 4.25 to the Company's Form 10-K Report, File No. 1-1097, for the year ended December 31, 1986 and incorporated by reference herein)
4.26 Copy of Supplemental Trust Indenture, dated March 1, 1987, being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 4.26 to the Company's Form 10-K Report for the year ended December 31, 1987, File No. 1-1097, and incorporated by reference herein)
4.27 Copy of form of Medium-Term Note of Enogex Inc. due December 21, 1995, and December 21, 1998. (Filed as Exhibit 4.27 to the Company's Form 10-K Report for the year ended December 31, 1988, File No. 1-1097, and incorporated by reference herein)
4.28 Copy of Supplemental Trust Indenture, dated November 15, 1990, being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 4.28 to the Company's Form 10-K Report for the year ended December 31, 1990, File No. 1-1097, and incorporated by reference herein)
4.29 Copy of Supplemental Trust Indenture, dated December 9, 1991, being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 4.29 to the Company's Form 10-K Report for the year ended December 31, 1991, File No. 1-1097, and incorporated by reference herein)
10.01 Coal Supply Agreement dated March 1, 1973, between OG&E and Atlantic Richfield Company. (Filed as Exhibit 5.19 to Registration Statement No.2-59887 and incorporated by reference herein)
10.02 Amendment dated April 1, 1976, to Coal Supply Agreement dated March 1, 1973, between OG&E and Atlantic Richfield Company (Exhibit 10.10 hereto), together with related correspondence. (Filed as Exhibit 5.21 to Registration Statement No. 2-59887 and incorporated by reference herein)
10.03 Second Amendment dated March 1, 1978, to Coal Supply Agreement dated March 1, 1973, between OG&E and Atlantic Richfield Company (Exhibit 10.04 hereto). (Filed as Exhibit 5.28 to Registration Statement No. 2-62208 and incorporated by reference herein)
10.04 Lease of Railroad Equipment dated February 1, 1979, between Mercantile-Safe Deposit and Trust Company and OG&E. (Filed as Exhibit 5.30 to Registration Statement No.2-64965 and incorporated by reference herein)
10.05 Participation Agreement dated as of January 1, 1980, among First National Bank and Trust Company of Oklahoma City, Thrall Car Manufacturing Company, OG&E and other parties, including Lease of Railroad Equipment dated January 1, 1980, between Mercantile-Safe Deposit and Trust Company and OG&E. (Filed as Exhibit 10.32 to the Company's Form 10-K Report for the year ended December 31, 1980, File No. 1-1097, and incorporated by reference herein)
10.06 Participation Agreement dated January 1, 1981, among The First National Bank and Trust Company of Oklahoma City, Thrall Car Manufacturing Company, OG&E and other parties, including Lease for Railroad Equipment dated January 1, 1981, between Wells Fargo Equipment Leasing Corporation and OG&E. (Filed as Exhibit 20.01 to the Company's Form 10-Q for June 30, 1981, File No. 1-1097, and incorporated by reference herein)
10.07 Agreement for Guaranty, dated November 30, 1982, between OG&E and Railcar Maintenance Company. (Filed as Exhibit 10.34 to OG&E's Form 10-K Report for the year ended December 31, 1982, File No. 1-1097, and incorporated by reference herein)
10.08 Form of Deferred Compensation Agreement for Directors, as amended. (Filed as Exhibit 10.08 to the Company's Form 10-K Report for the year ended December 31, 1992, File No. 1-1097, and incorporated by reference herein)
10.09 Restricted Stock Plan of the Company. (Filed as Exhibit 10.36 to the Company's Form 10-K Report for the year ended December 31, 1986, File No. 1-1097, and incorporated by reference herein)
10.10 Agreement and Plan of Reorganization, dated May 14, 1986, between OG&E and Mustang Fuel Corporation. (Attached as Appendix A to Registration Statement No. 33-7472 and incorporated by reference herein)
10.11 Gas Service Agreement dated January 1, 1988, between OG&E and Oklahoma Natural Gas Company. (Filed as Exhibit 10.26 to the Company's Form 10-K Report for the year ended December 31, 1987, File No. 1-1097, and incorporated by reference herein)
10.12 Company's Restoration of Retirement Income Plan, as amended.
10.13 Company's Restoration of Retirement Savings Plan.
10.14 Gas Service Agreement dated July 23, 1987, between OG&E and Arkla Services Company. (Filed as Exhibit 10.29 to the Company's Form 10-K Report for the year ended December 31, 1987, File No. 1-1097, and incorporated by reference herein)
10.15 Company's Supplemental Executive Retirement Plan.
10.16 Company's Annual Incentive Compensation Plan.
23.01 Consent of Arthur Andersen & Co.
24.01 Power of Attorney.
99.01 1993 Form 11-K Annual Report for Oklahoma Gas and Electric Company Employees' Retirement Savings Plan.
Executive Compensation Plans and Arrangements ---------------------------------------------
10.08 Form of Deferred Compensation Agreement for Directors, as amended. (Filed as Exhibit 10.08 to the Company's Form 10-K Report for the year ended December 31, 1992, File No. 1-1097, and incorporated by reference herein)
10.09 Restricted Stock Plan of the Company. (Filed as Exhibit 10.36 to the Company's Form 10-K Report for the year ended December 31, 1986, File No. 1-1097, and incorporated by reference herein)
10.12 Company's Restoration of Retirement Income Plan, as amended.
10.13 Company's Restoration of Retirement Savings Plan.
10.15 Company's Supplemental Executive Retirement Plan.
10.16 Company's Annual Incentive Compensation Plan.
(b) Reports on Form 8-K ------------------------
Item 5. Other Events, dated October 1, 1993.
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To Oklahoma Gas and Electric Company:
We have audited in accordance with generally accepted auditing standards, the consolidated financial statements of Oklahoma Gas and Electric Company included in this Form 10-K, and have issued our report thereon dated February 28, 1994. Our audits were made for the purpose of forming an opinion on those statements taken as a whole. The schedules listed on Page 68, Item 14 (a) 2. are the responsibility of the Company's management and are presented for purposes of complying with the Securities and Exchange Commission's rules and are not part of the basic financial statements. These schedules have been subjected to the auditing procedures applied in the audits of the basic financial state- ments and, in our opinion, fairly state in all material respects the financial data required to be set forth therein in relation to the basic financial statements taken as a whole.
ARTHUR ANDERSEN & CO.
Oklahoma City, Oklahoma, February 28, 1994
SIGNATURES
Pursuant to the requirements of the Securities and Exchange Act of 1934, as amended, the Registrant has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Oklahoma City, and State of Oklahoma on the 28th day of March, 1994.
OKLAHOMA GAS & ELECTRIC COMPANY (REGISTRANT)
/s/ J. G. Harlow, Jr.
By J. G. Harlow, Jr. Chairman of the Board and President
Pursuant to the requirements of the Securities and Exchange Act of 1934, as amended, this Report has been signed below by the following persons in the capacities and on the dates indicated.
Signature Title Date
/s/ J. G. Harlow, Jr. J. G. Harlow, Jr. Principal Executive Officer and Director; March 28, 1994
/s/ A. M. Strecker A. M. Strecker Principal Financial Officer; and March 28, 1994
/s/ B. G. Bunce B. G. Bunce Principal Accounting Officer. March 28, 1994
Herbert H. Champlin Director;
William E. Durrett Director;
Martha W. Griffin Director;
Hugh L. Hembree, III Director;
John F. Snodgrass Director;
Bill Swisher Director;
John A. Taylor Director; and
Ronald H. White, M.D. Director.
/s/ J. G. Harlow, Jr. By J. G. Harlow, Jr. (attorney-in-fact) March 28, 1994
E X H I B I T I N D E X
Exhibit No. Description ----------- -----------
3.01 Copy of Restated Certificate of Incorporation. (Filed as Exhibit 4.01 to the Company's Post- Effective Amendment No. Two to Registration Statement No. 2-94973, and incorporated by reference herein)
3.02 By-laws. (Filed as Exhibit 4.02 to Post-Effective Amendment No. Two to Registration Statement No. 2-94973 and incorporated by reference herein)
4.01 Copy of Trust Indenture, dated February 1, 1945, from OG&E to The First National Bank and Trust Company of Oklahoma City, Trustee. (Filed as Exhibit 7-A to Registration Statement No. 2-5566 and incorporated by reference herein)
4.02 Copy of Supplemental Trust Indenture, dated December 1, 1948, being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 7.03 to Registration Statement No. 2-7744 and incorporated by reference herein)
4.03 Copy of Supplemental Trust Indenture, dated June 1, 1949, being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 7.03 to Registration Statement No. 2-7964 and incorporated by reference herein)
4.04 Copy of Supplemental Trust Indenture, dated May 1, 1950, being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 7.04 to Registration Statement No. 2-8421 and incorporated by reference herein)
4.05 Copy of Supplemental Trust Indenture, dated March 1, 1952, a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 4.08 to Registration Statement No. 2-9415 and incorporated by reference herein)
4.06 Copy of Supplemental Trust Indenture, dated June 1, 1955, being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 4.07 to Registration Statement No. 2-12274 and incorporated by reference herein)
4.07 Copy of Supplemental Trust Indenture, dated January 1, 1957, being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 2.07 to Registration Statement No. 2-14115 and incorporated by reference herein)
4.08 Copy of Supplemental Trust Indenture, dated June 1, 1958, being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 4.09 to Registration Statement No. 2-19757 and incorporated by reference herein)
4.09 Copy of Supplemental Trust Indenture, dated March 1, 1963, being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 2.09 to Registration Statement No. 2-23127 and incorporated by reference herein)
4.10 Copy of Supplemental Trust Indenture, dated March 1, 1965, being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 4.10 to Registration Statement No. 2-25808 and incorporated by reference herein)
4.11 Copy of Supplemental Trust Indenture, dated January 1, 1967, being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 2.11 to Registration Statement No. 2-27854 and incorporated by reference herein)
4.12 Copy of Supplemental Trust Indenture, dated January 1, 1968, being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 2.12 to Registration Statement No. 2-31010 and incorporated by reference herein)
4.13 Copy of Supplemental Trust Indenture, dated January 1, 1969, being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 2.13 to Registration Statement No. 2-35419 and incorporated by reference herein)
4.14 Copy of Supplemental Trust Indenture, dated January 1, 1970, being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 2.14 to Registration Statement No. 2-42393 and incorporated by reference herein)
4.15 Copy of Supplemental Trust Indenture, dated January 1, 1972, being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 2.15 to Registration Statement No. 2-49612 and incorporated by reference herein)
4.16 Copy of Supplemental Trust Indenture, dated January 1, 1974, being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 2.16 to Registration Statement No. 2-52417 and incorporated by reference herein)
4.17 Copy of Supplemental Trust Indenture, dated January 1, 1975, being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 2.17 to Registration Statement No. 2-55085 and incorporated by reference herein)
4.18 Copy of Supplemental Trust Indenture, dated January 1, 1976, being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 2.18 to Registration Statement No. 2-57730 and incorporated by reference herein)
4.19 Copy of Supplemental Trust Indenture, dated September 14, 1976, being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 2.19 to Registration Statement No. 2-59887 and incorporated by reference herein)
4.20 Copy of Supplemental Trust Indenture, dated January 1, 1977, being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 2.20 to Registration Statement No. 2-59887 and incorporated by reference herein)
4.21 Copy of Supplemental Trust Indenture, dated November 1, 1977, being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 4.21 to Registration Statement No. 2-70539 and incorporated by reference herein)
4.22 Copy of Supplemental Trust Indenture, dated December 1, 1977, being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 4.22 to Registration Statement No. 2-70539 and incorporated by reference herein)
4.23 Copy of Supplemental Trust Indenture, dated February 1, 1980, being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 4.23 to Registration Statement No. 2-70539 and incorporated by reference herein)
4.24 Copy of Supplemental Trust Indenture, dated April 15, 1982, being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 4.24 to the Company's Form 10-K Report, File No. 1-1097, for the year ended December 31, 1982, and incorporated by reference herein)
4.25 Copy of Supplemental Trust Indenture, dated August 15, 1986, being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 4.25 to the Company's Form 10-K Report, File No. 1-1097, for the year ended December 31, 1986 and incorporated by reference herein)
4.26 Copy of Supplemental Trust Indenture, dated March 1, 1987, being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 4.26 to the Company's Form 10-K Report for the year ended December 31, 1987, File No. 1-1097, and incorporated by reference herein)
4.27 Copy of form of Medium-Term Note of Enogex Inc. due December 21, 1995, and December 21, 1998. (Filed as Exhibit 4.27 to the Company's Form 10-K Report for the year ended December 31, 1988, File No. 1-1097, and incorporated by reference herein)
4.28 Copy of Supplemental Trust Indenture, dated November 15, 1990, being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 4.28 to the Company's Form 10-K Report for the year ended December 31, 1990, File No. 1-1097, and incorporated by reference herein)
4.29 Copy of Supplemental Trust Indenture, dated December 9, 1991, being a supplemental instrument to Exhibit 4.01 hereto. (Filed as Exhibit 4.29 to the Company's Form 10-K Report for the year ended December 31, 1991, File No. 1-1097, and incorporated by reference herein)
10.01 Coal Supply Agreement dated March 1, 1973, between OG&E and Atlantic Richfield Company. (Filed as Exhibit 5.19 to Registration Statement No.2-59887 and incorporated by reference herein)
10.02 Amendment dated April 1, 1976, to Coal Supply Agreement dated March 1, 1973, between OG&E and Atlantic Richfield Company (Exhibit 10.10 hereto), together with related correspondence. (Filed as Exhibit 5.21 to Registration Statement No. 2-59887 and incorporated by reference herein)
10.03 Second Amendment dated March 1, 1978, to Coal Supply Agreement dated March 1, 1973, between OG&E and Atlantic Richfield Company (Exhibit 10.04 hereto). (Filed as Exhibit 5.28 to Registration Statement No. 2-62208 and incorporated by reference herein)
10.04 Lease of Railroad Equipment dated February 1, 1979, between Mercantile-Safe Deposit and Trust Company and OG&E. (Filed as Exhibit 5.30 to Registration Statement No.2-64965 and incorporated by reference herein)
10.05 Participation Agreement dated as of January 1, 1980, among First National Bank and Trust Company of Oklahoma City, Thrall Car Manufacturing Company, OG&E and other parties, including Lease of Railroad Equipment dated January 1, 1980, between Mercantile-Safe Deposit and Trust Company and OG&E. (Filed as Exhibit 10.32 to the Company's Form 10-K Report for the year ended December 31, 1980, File No. 1-1097, and incorporated by reference herein)
10.06 Participation Agreement dated January 1, 1981, among The First National Bank and Trust Company of Oklahoma City, Thrall Car Manufacturing Company, OG&E and other parties, including Lease for Railroad Equipment dated January 1, 1981, between Wells Fargo Equipment Leasing Corporation and OG&E. (Filed as Exhibit 20.01 to the Company's Form 10-Q for June 30, 1981, File No. 1-1097, and incorporated by reference herein)
10.07 Agreement for Guaranty, dated November 30, 1982, between OG&E and Railcar Maintenance Company. (Filed as Exhibit 10.34 to OG&E's Form 10-K Report for the year ended December 31, 1982, File No. 1-1097, and incorporated by reference herein)
10.08 Form of Deferred Compensation Agreement for Directors, as amended. (Filed as Exhibit 10.08 to the Company's Form 10-K Report for the year ended December 31, 1992, File No. 1-1097, and incorporated by reference herein)
10.09 Restricted Stock Plan of the Company. (Filed as Exhibit 10.36 to the Company's Form 10-K Report for the year ended December 31, 1986, File No. 1-1097, and incorporated by reference herein)
10.10 Agreement and Plan of Reorganization, dated May 14, 1986, between OG&E and Mustang Fuel Corporation. (Attached as Appendix A to Registration Statement No. 33-7472 and incorporated by reference herein)
10.11 Gas Service Agreement dated January 1, 1988, between OG&E and Oklahoma Natural Gas Company. (Filed as Exhibit 10.26 to the Company's Form 10-K Report for the year ended December 31, 1987, File No. 1-1097, and incorporated by reference herein)
10.12 Company's Restoration of Retirement Income Plan, as amended.
10.13 Company's Restoration of Retirement Savings Plan.
10.14 Gas Service Agreement dated July 23, 1987, between OG&E and Arkla Services Company. (Filed as Exhibit 10.29 to the Company's Form 10-K Report for the year ended December 31, 1987, File No. 1-1097, and incorporated by reference herein)
10.15 Company's Supplemental Executive Retirement Plan.
10.16 Company's Annual Incentive Compensation Plan.
23.01 Consent of Arthur Andersen & Co.
24.01 Power of Attorney.
99.01 1993 Form 11-K Annual Report for Oklahoma Gas and Electric Company Employees' Retirement Savings Plan.