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 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 four gas processing plants, markets natural gas and natural gas products and invests in the exploration and production of natural gas. At the end of 1994, Enogex had 314 members and OG&E had 2,494 members. OG&E's executive offices are located at 101 North Robinson, P.O. Box 321, Oklahoma City, Oklahoma 73101-0321; telephone (405) 553-3000.
On February 25, 1994, the Oklahoma Corporation Commission ("OCC") issued an order that, among other things, effectively lowered OG&E's rates to its Oklahoma retail customers by approximately $17 million annually and required OG&E to refund approximately $41.3 million. Of the $41.3 million refund, $39.1 million was associated with revenues prior to January 1, 1994, while the remaining $2.2 million related to 1994. See "Regulation and Rates - Recent Regulatory Matters" for a further discussion of this order.
In 1994, the Company restructured and redesigned its operations to reduce costs in order to more favorably position itself for the competitive electric utility environment. As part of this process, the Company implemented a Voluntary Early Retirement Package ("VERP") and a severance package in 1994. These two packages reduced the Company's workforce by approximately 900 employees.
In response to an application filed by OG&E on August 9, 1994, the OCC issued an order on October 26, 1994, that permitted OG&E to: (1) establish a regulatory asset in connection with the costs associated with the workforce reduction; (2) amortize the December 31, 1994, balance of the regulatory asset over 26 months; and (3) reduce OG&E's electric rates by approximately $15 million annually, effective January 1995. In 1995 and 1996, the labor savings are expected to substantially offset the amortization of the regulatory asset and the annual rate reduction of $15 million. See "Regulation and Rates - Recent Regulatory Matters" and Note 10 of Notes to Consolidated Financial Statements for a further discussion of the OCC's orders in February and October 1994.
ELECTRIC OPERATIONS
GENERAL
OG&E furnishes retail electric service in 270 communities and their contiguous rural and suburban areas. During 1994, 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, 1994, 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 5,060 megawatts, and occurred on June 27, 1994. Excluding wheeling, the net on system peak demand was about 4,700 megawatts. However, when firm sales were included, total load responsibility was approximately 4,722 megawatts, resulting in a capacity margin of approximately 22.56 percent. As reflected in the table below and the operating statistics on page 4, kilowatt-hour sales to OG&E customers ("system sales") increased 2.2 percent in 1994 compared to 1993. This increase in system sales was offset by an 82.1 percent decline in sales to other utilities ("off-system sales") which caused total kilowatt-hour sales to be down by 9.0 percent for 1994. 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 1993 and 1992, factors which resulted in variations in total kilowatt-hour sales included: (i) more normal weather in 1993, (ii) continued customer growth; and (iii) the high level of off-system sales in 1992.
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. 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. Also, numerous states are considering proposals to require "retail wheeling" which is the delivery of power generated by a third party to retail customers. The Energy Act, these proposals 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. See "Regulation and Rates - Recent Regulatory Matters" for a further discussion of this matter.
Electric and magnetic fields ("EMFs") surround all electric tools and appliances, internal home wiring, and external power lines such as those owned by OG&E. During the last several years considerable attention has focused on possible health effects from EMFs. While some recent studies indicate a possible correlation, other similar studies indicate no correlation between EMFs and health effects. 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 health effects of EMFs. Beginning in fiscal year 1994, and in association with the Energy Act, 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 Edison Electric Institute, OG&E will continue its support of the research with regard to the possible health effects of EMFs. OG&E is dedicated to delivering electric service in a safe, reliable, environmentally acceptable and economical manner.
OKLAHOMA GAS AND ELECTRIC COMPANY CERTAIN OPERATING STATISTICS
FINANCE AND CONSTRUCTION
The Company meets its cash needs through internally generated funds, short-term borrowings and permanent financing. Cash flows from operations remained strong, which enabled the Company to internally generate the required funds to satisfy construction expenditures during 1994 and 1993.
Management expects that internally generated funds will be adequate over the next three years to meet OG&E's capital requirements. The primary capital requirements for 1995 through 1997 are estimated as follows:
The three-year estimate includes expenditures for 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 $7.4 million of the Company's construction expenditures budgeted for 1995 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 minimum capacity reserve margins 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, 1994, and assuming an annual interest rate of 8.3 percent, OG&E could issue approximately $883 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 $864 million of additional preferred stock at an assumed annual dividend rate of 7.9 percent could be issued as of December 31, 1994.
The Company will continue to use short-term borrowings to meet temporary cash requirements and has the necessary regulatory approvals to incur up to $400 million in short-term borrowings at any one time. The maximum amount of outstanding short-term borrowings during 1994 was $220 million.
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 along with demand-side management. OG&E is not currently constructing new base-load generation 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.
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 not needed by the hospital from its nominal seven megawatt cogeneration facility. In 1987, OG&E signed a contract to purchase up to 100 megawatts of capacity from Mid-Continent Power Company, Inc. 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 energy used by its customers, 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, 1994, approximately 89 percent of OG&E's electric revenue was subject to the jurisdiction of the OCC, seven percent to the APSC, and four percent to the FERC.
RECENT REGULATORY MATTERS: On February 25, 1994, the OCC issued an -------------------------- order that, among other things, effectively lowered OG&E's rates to its Oklahoma retail customers by approximately $17 million annually and required OG&E to refund approximately $41.3 million. Of the $41.3 million refund, $39.1 million is associated with revenues prior to January 1, 1994, while the remaining $2.2 million related to 1994.
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 are designed to permit OG&E to earn a 12 percent regulatory 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 regulatory return on equity exceeds 12.75 percent.
In 1994, the Company underwent a significant restructuring effort and redesign of its operations to more favorably position itself for the competitive electric utility environment. The Company incurred $63.4 million of restructuring costs in 1994. Pending an OCC order, OG&E deferred the costs associated with a VERP and severance package in the third quarter of 1994. Between August 1, and December 31, 1994, the
amount deferred was reduced by approximately $14.5 million. In response to an application filed by OG&E on August 9, 1994, the OCC issued an order on October 26, 1994, that permitted OG&E to amortize the December 31, 1994, regulatory asset of $48.9 million over 26 months and reduced OG&E's electric rates by approximately $15 million annually, effective January 1995. Management anticipates that labor savings from the VERP and severance package will substantially offset the amortization of the regulatory asset and annual rate reduction of $15 million. Labor savings in 1994 approximated the amortization of the deferred amount and therefore, did not significantly impact 1994 results. However, approximately $6.5 million in other restructuring expenses reduced 1994 earnings by $0.10 per share. At December 31, 1994, the deferred amount was $48.9 million, which is included on the Consolidated Balance Sheets as Deferred Charges - Other.
Pursuant to an order from the APSC in July 1992, OG&E and other electric utilities serving customers in Arkansas were required to submit 20-year Integrated Resource Plans with the APSC. The IRP process required the utilities to document their plans for serving their customers' electric energy needs, taking into account 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 their electric customers at the lowest system cost. On October 5, 1994, the APSC issued an Order initiating a Notice of Inquiry with respect to integrated resource planning and energy efficiency investments in power generation and supply for electric utilities, and suspending proceedings in OG&E's IRP Docket until further notice. In essence, the APSC Order stated that before the APSC proceeds further with the pending dockets on IRP, including OG&E's, the ASPC should look more closely at the relationship between the Federal IRP standard and the "...changes occurring in the electric utility industry..." particularly with respect to competition. Because of the changing utility industry, the APSC has determined it should examine more closely whether IRP is appropriate given the movement of the industry away from regulation.
On October 5, 1994, the OCC issued an order instructing the OCC staff of the Public Utility Division ("PUD") to move forward with the development of OCC rules to implement the mandates of Sections 111 and 115 of the National Energy Policy Act of 1992, requiring OG&E and other electric utilities to each submit 20-year IRPs. The order instructs OCC staff to carry out this development through a collaborative process involving all affected parties. The completion date is scheduled for mid-to late 1995.
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, which are subject to periodic review by the OCC, the APSC and the FERC.
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.
The National Energy Policy Act of 1992 ("Energy 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 Energy 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 Energy 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 Energy 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. Also, numerous states are considering proposals to require "retail wheeling". The Energy Act, these proposals 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. Past actions include the redesign and restructuring effort in 1994 and the actions to reduce fuel costs, both of which have resulted in lower retail rates, especially for industrial customers. In 1995, the Company intends to make a transmission open access filing before the FERC, in compliance with the Energy Act, and the Company intends to implement Real Time Pricing for a pilot group of its retail customers. See "Rate Structure, Load Growth and Related Matters."
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 expanding job-producing businesses and industries; and (ii) to encourage the efficient use of energy by all of its customers. In order to meet these goals, OG&E has reduced and restructured its rates to its key customers while at the same time implementing numerous energy efficiency 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.
In 1994, OG&E's marketing efforts included thermal storage, electrotechnologies, 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 programs such as Real Time Pricing to keep its electric tariffs attractive and to control peak demand growth. Real Time Pricing is a service option which prices electricity so that current price varies hourly with short notice to reflect current expected cost. The technique will allow a measure of competitive pricing, a broadening of customer choice, balancing of electricity usage and capacity in the short and long term, and help customers to control their costs. OG&E will implement a pilot program in 1995 with some industrial customers.
Other programs include the use of high efficiency lighting and ballasts, high efficiency motors, high efficiency air conditioners or chillers, 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 and ground source heat pumps.
OG&E currently does not anticipate the need for new baseload generating plants in the foreseeable future. For further discussion, see "Finance and Construction."
FUEL SUPPLY
During 1994, approximately 28 percent of the OG&E-generated energy was produced by natural gas-fired units and 72 percent by coal-fired units. It is estimated that the fuel mix for 1995 through 1999, based upon expected generation for these years, will be as follows:
The average cost of fuel used, by type, per million Btu for each of the 5 years was as follows:
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."
GAS-FIRED UNITS: OG&E has approximately 740 natural gas purchase ---------------- contracts covering approximately 430 wells and delivery points. These contracts cover an estimated 153 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, 1994, outstanding prepayments for gas, including the amounts classified as current assets, under these contracts were approximately $10.9 million (including $10 million accrued but not yet paid). A contract with Oklahoma Natural Gas Company for additional peaking gas is renewed yearly. The need for this peaking gas contract will be eliminated as soon as an 8.0 BCF gas storage facility becomes fully operational.
In 1993, OG&E began utilizing a natural gas storage facility which helps OG&E lower fuel costs and receive greater value from its remaining take-or-pay gas contracts. By diverting natural gas into storage, OG&E is able to use as much coal as possible to generate electricity, and use gas from storage when needed to meet increases in demand for electricity. In 1995, gas storage will give OG&E the flexibility to generate about 82 percent of its electricity with coal, the highest percentage in OG&E's history. This fuel mix change, along with fuel price reductions will allow OG&E to reduce its fuel costs in 1995 by an estimated $37 million compared to 1994.
COAL-FIRED UNITS: All of OG&E coal units, with an aggregate capacity ----------------- of 3,045 megawatts, 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.
During 1994, OG&E burned a total of 8.1 million tons of coal. Based upon the average sulfur content of Wyoming 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 resulted 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 1994, OG&E leased 1,930 coal cars, of which 1,367 were aluminum, at an approximate annual rental cost of $5.6 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. On July 1, 1994, the lease expired on 426 steel railcars and they were returned to the lessor.
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 the Company's expenditures for capital, operating, maintenance and other costs to preserve and enhance environmental quality will be approximately $46 million during 1995, compared to approximately $47 million in 1994. OG&E is continually evaluating its environmental programs to ensure compliance with existing 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"). Since all of OG&E's coal-fired generating units currently burn low-sulfur coal, OG&E will not need to take any steps to comply with the new sulfur dioxide emission limits until January 1, 2000. In compliance with Title IV of the CAAA, the Company has completed installation of continuous emission monitors ("CEMs") on each of its five coal-fired generating units and three of its 12 gas-fired generating units. Expenditures on CEMs in 1994 totalled approximately $6 million. The Environmental Protection Agency ("EPA") established a time extension for installation of CEMs on gas-fired units which allowed the Company to defer CEM installation on the remaining nine units subject to the requirements of Title IV. Completion of this project is expected to cost approximately $1 million during 1995. The CAAA Title V operating permits are expected to cost approximately $400,000 in 1995.
The CAAA will also regulate emissions of 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 in future years. 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 that the Company employs the least cost option to comply with the CAAA and be in a competitive position to market its services.
During 1992, OG&E disclosed to the EPA discrepancies in the 1991 annual report required by the Toxic Substance Control Act ("TSCA"). These discrepancies were administrative in nature and presented no harm to the environment and presented no health problems to our Company members or the public. However, the Company has instituted specific systems and measures to correct each of the reported discrepancies. On December 15, 1994, the Company was notified by the EPA that the EPA had commenced reviewing the matter, and a response from the EPA may be forthcoming in 1995. No actions were taken by the EPA on this matter during 1994. See "Item 3. Legal Proceedings" for additional discussion of this matter.
The Company remains 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 37th largest pipeline in the nation in terms of miles of pipeline. Enogex Inc.'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 natural gas exploration and production activities. At December 31, 1994, 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"). Enogex also owns an 80% interest in Centoma Gas Systems, Inc. ("Centoma"). Products owns interests in and operates three natural gas processing plants and marketed natural gas liquids through the end of 1994. Exploration is engaged in investing in the exploration and production of oil and natural gas and the purchase of oil and gas reserves. ENGL owns and operates a natural gas processing plant and marketed the natural gas liquids through the end of 1994. Services and Clinton are engaged in the marketing (buying and selling) of natural gas and beginning in 1995, Services will also market natural gas liquids of Products and ENGL. Centoma both purchases and gathers gas for subsequent processing at one of three processing plants, two of which are owned by Products. The residue gas is then sold under a combination of contract and spot market prices.
For the year ended December 31, 1994, and before elimination of intercompany items between OG&E and Enogex, Enogex's consolidated revenues and net income were approximately $203.1 million and $10.0 million, respectively, as indicated in the following table:
(a) Includes $7.1 million of net income from Products, Services, Exploration, ENGL, Clinton and Centoma.
(b) Consists of intercompany natural gas transmission fees of $1.8 million and sales of natural gas products amounting to $11.3 million.
Enogex's natural gas transportation business in Oklahoma consists primarily of gathering and transporting natural gas for OG&E 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. 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 1994, Enogex transported 132 Bcf of natural gas; of which approximately 61 Bcf, or about 46 percent, was delivered to OG&E's electric generating stations and storage facility, which resulted in approximately 78 percent of Enogex Inc.'s revenue of $57.7 million for 1994. 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 the Enogex 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 other intrastate shippers are not subject to FERC regulation. With respect to state regulation, the fees charged by Enogex for any intrastate transportation service 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 Mmcf of natural gas per day. Products also owns two other natural gas processing plants in Oklahoma, which have, in the aggregate, the capacity to process approximately 23 Mmcf of natural gas per day. ENGL owns one natural gas processing plant in Oklahoma, which has the capacity to process approximately 18 Mmcf 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 was handled through independent brokers. Beginning in 1995, the natural gas liquids will be marketed by Services. 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.
In processing and marketing natural gas liquids, the Enogex companies compete against virtually all other gas processors selling natural gas liquids. The Enogex companies believe 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 the Enogex companies specifically, the volume of natural gas processed at their 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 and natural gas liquids 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. It also serves Products and ENGL by purchasing and marketing the natural gas liquids they produce.
Although the margin on gas sales by Services is relatively small, approximately 50 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 is engaged in essentially the same business as Services.
Enogex Inc. is committed to continue 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 1993. The contributing factors for the increase were specific projects implemented to strengthen Enogex's position, with other similar projects under consideration.
Services and Clinton compete with all major suppliers of natural gas and natural gas liquids in the geographic markets they serve. For natural gas, those geographic markets 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 exploration and production of natural gas. Exploration has focused its drilling activity in the Antrim Devonian shale trend in the state of Michigan and also has interests in Oklahoma. As of December 31, 1994, Exploration had interests in 273 active wells and total assets, including such interests, of approximately $38 million.
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:
At December 31, 1994, OG&E's transmission system included 71 substations with a total capacity of approximately 17.2 million kVA and approximately 4,283 structure miles of lines. The distribution system included 338 substations with a total capacity of approximately 6.1 million kVA, 21,113 structure miles of overhead lines, 1,626 miles of underground conduit and 6,394 miles of underground conductor.
Substantially all of OG&E's electric facilities are subject to a direct first mortgage lien under the Trust Indenture securing OG&E's first mortgage bonds.
Enogex owns: (1) over 3,000 miles of natural gas pipeline extending from the Arkoma Basin in eastern Oklahoma to the Anadarko Basin in western Oklahoma; (2) a 50 percent interest in a natural gas processing plant near Calumet, Oklahoma, which has the capacity to process 250 Mmcf of natural gas per day; (3) three other natural gas processing plants in Oklahoma, which have, in the aggregate, the capacity to process approximately 41 Mmcf of natural gas per day; and (4) an 80 percent interest in approximately 110 miles of gas gathering pipeline owned by Centoma.
During the three years ended December 31, 1994, the Company's gross property, plant and equipment additions approximated $405 million and gross retirements approximated $67 million. Over 95 percent of these additions were provided by internally generated funds. The additions during this three-year period amounted to approximately 10.6 percent of total property, plant and equipment at December 31, 1994.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS. --------------------------
1. 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 oil and gas contract by OG&E. This case was removed to the United States District Court for the Western District of Oklahoma. Enogex Inc. was also joined as a Defendant in the action. Plaintiffs allege that OG&E and Enogex were in violation of the Federal Racket Influenced and Corrupt Act ("RICO"). OG&E filed its Motion to Dismiss the RICO claim on March 26, 1993. Plaintiffs allege 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 to 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.
On January 4, 1994, the United States District Court for the Western District of Oklahoma entered its Order and dismissed Plaintiffs' RICO claim as well as Plaintiffs' claim for punitive damages under RICO. On January 14, 1994, Plaintiffs filed a Motion to Alter or Amend Judgment seeking leave of Court to file its Amended Complaint asserting different allegations under RICO. On January 31, 1994, the Court denied Plaintiffs' motion.
Plaintiffs filed their Appeal with the United States Court of Appeals for the 10th Circuit. In addition, the United States District for the Western District of Oklahoma remanded the breach of contract claim to the District Court of Oklahoma County, Oklahoma. By Order filed January 11, 1995, the Court dismissed the appeal pursuant to a stipulation of the parties. The RICO case is now dismissed.
Management believes the outcome of this proceeding will not have a material adverse effect on the Company's consolidated financial position or its results of operations for numerous reasons, which include that the underlying dispute between the parties is a contractual dispute under a gas purchase contract. Management intends to vigorously pursue the defense of this matter.
2. On July 8, 1994, an employee of OG&E filed a lawsuit in state court against OG&E in connection with OG&E's voluntary early retirement package. The case has been removed to the U.S. District Court in Tulsa, Oklahoma. The lawsuit purports to be a class action and alleges violation of Title VII, ERISA, intentional infliction of emotional distress and other issues.
On August 23, 1994, the trial court sustained OG&E's Motion to Dismiss Plaintiffs' Complaint, in its entirety. On September 12, 1994, Plaintiffs filed an Amended Complaint alleging substantially the same allegations which were in the original Complaint. On October 10, 1994, Defendants filed a Motion to Dismiss Counts II, IV, V, VI and VII of Plaintiffs Amended Complaint and filed responsive pleadings to Counts I and III. With regard to those two Counts, additional investigation will be required to determine whether or not Plaintiffs can successfully pursue those claims. While the Company cannot predict the precise outcome of the proceeding, the Company continues to believe that the lawsuit is without merit and will not have a material adverse effect on its consolidated results of operations or financial condition.
3. On June 30, l986, the United States government filed suit against OG&E and 36 other defendants in case number CIV-86-l40l W, in the United States District Court ("USDC") for the Western District of Oklahoma. The Complaint generally alleged that a total of l8 million gallons of hazardous and toxic waste were contained at the Hardage Criner site located approximately 30 miles south of Oklahoma City, and that the government had expended, as of the date of the filing of the Complaint, $l.44 million related to the site. The 37 defendants are divided into three classes: 33 "generator" defendants, of which the Company is one; three "transporter" defendants; and the owner of the site, Mr. Royal Hardage.
It is estimated that over 200 other entities, not named in the government's Complaint, also disposed of materials at the site. OG&E 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 was estimated to cost approximately $60 million.
The design and construction of the remedy is 99% complete. On December 1, 1994, a tour of the remedy facilities was conducted; present were representatives of PRPs, EPA and the State agencies.
Settlements have been reached with numerous parties that were not members of the Committee for their share of costs incurred. The money collected through these settlements is being used to finance the remedy and to reimburse the government for response costs.
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 Committee members are likely to pay may still be substantial due to maintenance of the remedy over time.
The Committee members have reached an Agreement to pay the on-going maintenance 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, or approximately $1.4 million.
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; (3) the portion of the total waste disposed at this site attributable to OG&E; and (4) the remedy construction is substantially complete. 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. 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 brokering 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. 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.
The Company estimates its share of the total hazardous wastes at the Rose facility to be less than six percent. A Settlement Agreement between AEGIS Insurance Company and OG&E was reached in 1994. Although the Company cannot predict the precise outcome of this matter, 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; (3) the portion of the total waste disposed at this site attributable to OG&E and (4) the Company's settlement agreement with its insurer. 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.
5. During the Third Quarter of 1992 OG&E began a voluntary review of information contained in the 1991 annual report required under the Toxic Substance Control Act ("TSCA"). The initial result of the review revealed some discrepancies in operating practices and documentation.
EPA, Region VI, was notified of these initial discrepancies in December, 1992. Because it 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 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 significant 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 adverse effect on its consolidated financial position or 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. On December 15, 1994, the Company was notified by the EPA that the EPA had commenced reviewing the matter, and a response from the EPA may be forthcoming in 1995.
6. 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 of 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 a 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.
On December 16, 1994, OG&E received a letter from EPA stating that it was waiving the Special Notice procedures under Section 122(e) in regard to the Remedial Design/Remedial Action for the second operable unit. This is based on the fact that (1) an offer for both operable units is presently being negotiated and (2) there is a strong indication that the PRPs will not perform the remedy. EPA hopes to conclude de minimis settlement negotiations and have a signed settlement document by April 28, 1995. It is believed at this time that OG&E is a de minimis party, in which case its liability would not be significant.
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 the Company's consolidated 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.
7. As previously reported, OG&E was aware of an asbestos problem at its former Osage Plant. During 1994, the Company determined that it had no material liability with respect to this matter.
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. During 1994, the Company determined that it had no material liability with respect to these sites.
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 Registrant as of March 15, 1995:
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 18, 1995.
The business experience of each of the Executive Officers of the Registrant for the past five years is as follows:
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.
The number of record holders of Common Stock at December 31, 1994, was 44,464. The book value of the Company's Common Stock at December 31, 1994, was $22.83.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA. --------------------------------
HISTORICAL 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 1994 increased significantly from $2.78 per share in 1993 to $3.01 per share in 1994. This improvement in earnings occurred despite the order in February 1994 from the Oklahoma Corporation Commission (the "Commission"), which effectively reduced OG&E's rates to its Oklahoma customers by approximately $17 million annually. The Commission's order also required OG&E to refund $41.3 million to its customers. The refund had only a slight impact on 1994 results as approximately $39.1 million of the refund had been recorded in 1993 and 1992.
In 1994, the Company restructured and redesigned its operations to reduce costs in order to more favorably position itself for the competitive electric utility environment. As part of this process, the Company implemented a Voluntary Early Retirement Package ("VERP") and a severance package in 1994. Those two programs reduced the Company's workforce by more than 900 employees.
In the third quarter of 1994, OG&E deferred the costs associated with the VERP and severance package, pending a Commission order. Labor savings in 1994 approximated the amortization of the deferred amount and therefore, did not significantly impact 1994 results. However, approximately $6.5 million in other restructuring expenses reduced 1994 earnings by $0.10 per share. At December 31, 1994, the deferred amount was $48.9 million, which is included on the Consolidated Balance Sheets as Deferred Charges - Other. In response to an application filed by OG&E on August 9, 1994, the Commission issued an order on October 26, 1994, that permitted the Company to amortize the December 31, 1994, balance of the regulatory asset over 26 months and reduced OG&E's electric rates by approximately $15 million annually, effective January 1995. In 1995 and 1996, the labor savings are expected to substantially offset the amortization of the regulatory asset and the annual rate reduction of $15 million. See Note 10 of Notes to Consolidated Financial Statements for a further discussion of the Commission's orders in February and October 1994.
The dividend payout ratio (expressed as a percentage of earnings available for common) improved in 1994 to 88 percent as compared to 96 percent for 1993. The Company's long-term goal is to achieve a dividend payout ratio of 75 percent based on long-term earnings expectations.
The following discussion and analysis presents factors which had a material effect on the Company's operations and financial position during the last three years and should be read in conjunction with the Consolidated Financial Statements and Notes thereto. Trends and contingencies of a material nature are discussed to the extent known and considered relevant.
EARNINGS
In 1994, earnings per share increased $0.23, or 8.3 percent from those reported in 1993. The increase resulted primarily from increased retail electric kilowatt-hour sales in 1994 and less impact than in 1993 from the Commission's February 1994 rate order. 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 provision for rate refund recorded in 1993 ($0.32 per share) related to the Commission's refund order in February 1994.
RESULTS OF OPERATIONS
* Not meaningful
In 1994, approximately 88 percent of the Company's revenues consisted of regulated sales of electricity as a public utility, while the remaining 12 percent was provided by the non-utility operations of the Company's wholly-owned subsidiary, Enogex Inc. and its subsidiaries (collectively "Enogex"). Revenues from sales of electricity are somewhat seasonal, with a large portion of the Company's annual electric revenues being derived during the summer months when the electricity needs of its customers increase. 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 natural gas exploration and production 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 to OG&E's generating units.
Overall, 1994 operating revenues decreased $92.1 million, or 6.4 percent, primarily due to recovery of substantially reduced fuel costs, a significant reduction in kilowatt-hour sales to other utilities, milder weather and lower revenue from Enogex businesses. Partially offsetting the impact of these reductions was a 2.2 percent growth in kilowatt-hour sales to OG&E customers ("system sales"). The 1994 rate reduction did not significantly affect 1994 revenues when compared to 1993, due to the increased system sales in 1994, and since 1993 revenues reflected a $15 million provision for rate refund.
Enogex revenues decreased 3.7 percent in 1994. Primary factors for the decreases were lower natural gas prices, slightly lower volumes of natural gas sold by Enogex and lower transportation fees on gas transported for OG&E. These decreases were only partially offset by increased sales of natural gas liquids.
During 1993, operating revenues increased $132.3 million or 10.1 percent compared to 1992. Increased system sales, the recovery of higher purchased power costs and Enogex accounted for the increased revenues. These increases were only partially offset by the Commission's rate order in February 1994, which reduced 1993 operating revenues by approximately $15 million.
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.
* Not meaningful
Total operating expenses decreased $97.4 million, or 7.8 percent in 1994, due to reduced fuel costs for the production of electricity and decreases in both quantities and prices of gas purchased for resale by Enogex. These reductions were partially offset by the cost of restructuring and increases in purchased power and depreciation.
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 1994, fuel costs decreased approximately $120.0 million, or 31.3 percent, due to renegotiated coal and transportation contracts, lower natural gas usage and a 15.9 percent reduction in the volume of kilowatt-hours generated (due to economic purchases of power from other utilities and a reduction in sales to other utilities). In 1993, fuel expense increased approximately $5.6 million, or 1.5 percent, primarily due to increased prices of gas used in the generation of electricity, which more than offset a 3.5 percent reduction in consumption of natural gas used to generate electricity.
Purchased power costs amounted to $228.7 million in 1994, up from $218.7 million and $182.2 million, in 1993 and 1992, respectively. The $10.0 million increase in 1994 resulted from economic purchases of power from other utilities, while the $36.5 million increase in 1993 resulted from price escalation provisions contained in certain cogeneration contracts. As required by the Public Utility Regulatory Policy Act of 1978 ("PURPA"), the Company must currently purchase power from qualified cogeneration facilities. In 1998, another qualified cogeneration facility is scheduled to become operational and the Company is obligated to purchase up to 100 megawatts of capacity from this facility as well. See related discussion of purchased power in Note 9 of Notes to Consolidated Financial Statements.
Variances in the actual cost of fuel used in electric generation and certain purchased power costs, as compared to that component in cost-of-service for ratemaking, are passed through to OG&E's electric customers through automatic fuel adjustment clauses. The automatic fuel adjustment clauses are subject to periodic review by the Commission, the Arkansas Public Service Commission and the Federal Energy Regulatory Commission ("FERC").
Even though increases and decreases are passed through to customers, in 1993 the Company began utilizing a natural gas storage facility which helps OG&E lower fuel costs and receive greater value from its remaining take-or-pay gas contracts. By diverting natural gas into storage, OG&E is able to use as much coal as possible to generate electricity, and use gas from storage when needed to meet increases in demand for electricity. The higher level of fuel inventories at the end of 1994 was attributable to increased usage of the natural gas storage facility and the relatively low level of fuel inventories at the end of 1993 was due to significant kilowatt-hour sales to other utilities.
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. Reducing fuel costs helps OG&E remain competitive, which in turn helps OG&E's electric customers remain competitive in a global economy.
Enogex's gas purchased for resale decreased $26.3 million or 18.7 percent for 1994 compared to an increase of $42.8 million or 43.9 percent for 1993. The 1994 decrease was due to reduced volumes and lower natural gas prices, while the 1993 increase
resulted from higher gas prices and increased volumes compared to 1992.
Other operation and maintenance increased by approximately $9.2 million and $8.9 million in 1994 and 1993, respectively. A $5.4 million decrease in production maintenance in 1994, net of labor savings, was more than offset by: (i) expensing $8.4 million of previously deferred costs associated with Statement of Financial Accounting Standards ("SFAS") No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions;" (ii) current recognition of SFAS No. 106 costs; and (iii) increased costs of producing natural gas liquids at Enogex. The 1993 increase in other operation and maintenance expenses resulted from major overhauls at two generating plants and increased labor costs.
The Company offered a Voluntary Early Retirement Package ("VERP") and more than 730 employees elected to retire in July, at a cost of approximately $58.5 million. The Company also incurred approximately $4.9 million of costs related to a severance package. The costs of the VERP and severance package were deferred, pending a Commission order. Between August 1, and December 31, 1994, the amount deferred was reduced by approximately $14.5 million, which is the approximate amount of labor savings during that same period. In response to an application filed by the Company, the Commission issued an order in October 1994 approving the Company's proposed accounting treatment of certain restructuring costs. At December 31, 1994, the unamortized balance of the regulatory asset was $48.9 million, which is included on the Consolidated Balance Sheets as Deferred Charges - Other. This regulatory asset will be amortized over 26 months, as permitted by the Commission's order. Restructuring expenses, which resulted from a complete review and redesign of the Company's operations, were approximately $21.0 million in 1994 (including amortization of the deferred charge). Restructuring expenses included only costs that were actually incurred in 1994. See Note 7 of Notes to Consolidated Financial Statements.
The increases in depreciation for 1994 and 1993 reflect higher levels of depreciable plant. Also, the adoption of SFAS 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.
In 1994, income taxes increased primarily due to higher pre-tax earnings. 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.
The variances in interest expense for 1994 and 1993 were primarily attributable to the approximate $6.2 million of interest in 1993, associated with the refund ordered by the Commission in February 1994. See Note 10 of Notes to Consolidated Financial Statements.
LIQUIDITY, CAPITAL RESOURCES AND CONTINGENCIES
The primary capital requirements for 1994 and as estimated for 1995 through 1997 are as follows:
CONSTRUCTION
The Company's primary needs for capital are 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 $7.4 million of the Company's construction expenditures budgeted for 1995 are to comply with environmental laws and regulations. Because of the continuing trend toward greater environmental awareness and increasingly stringent regulation, the Company has been experiencing a trend towards increasing environmental costs. This trend has caused and may continue to cause slightly higher operating expenditures and capital expenditures for environmental matters.
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. Cash flows from operations remained strong, which enabled the Company to internally generate the required funds to satisfy construction expenditures during 1994 and 1993. Management expects that internally generated funds will be adequate over the next three years to meet anticipated capital requirements. Short-term borrowings will continue to be used to meet temporary cash requirements. The maximum amount of outstanding short-term borrowings during 1994 was $220 million. The Company has the necessary regulatory approvals to incur up to $400 million in short-term borrowings at any one time.
The Company continues to evaluate opportunities to enhance shareowner returns and achieve long-term financial objectives through acquisitions of non-utility businesses. Permanent financing could be required for such acquisitions.
In August 1994, Enogex redeemed its $90 million of outstanding medium-term notes, with interest rates ranging from 9.88% to 10.11%. Enogex anticipates issuing long-term debt in 1995 to replace short-term borrowings in connection with such redemption.
In January 1995, OG&E refinanced its obligations with respect to $47,000,000 of 5 7/8% Pollution Control Revenue Bonds due December 1, 2007 and $32,050,000 of 6 3/4% Pollution Control Revenue Bonds due March 1, 2006 through the issuance of two new series of pollution control bonds bearing interest at variable, tax-exempt rates. These refinancings are expected to result in lower long-term interest rates during 1995.
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 and 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 adverse effect on the Company's consolidated 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 Company continues to explore options to comply with the Clean Air Act Amendments of 1990 ("CAAA"). Since all of OG&E's coal-fired generating units currently burn low-sulfur coal, OG&E will not need to take any steps to comply with the new sulfur dioxide emission limits until January 1, 2000. In compliance with Title IV of the CAAA, the Company has completed installation of continuous emission monitors ("CEMs") on each of its five coal-fired generating units and three of its 12 gas-fired generating units. Expenditures on CEMs in 1994 totalled approximately $6 million. The Environmental Protection Agency ("EPA") established a time extension for installation of CEMs on gas-fired units which allowed the Company to defer CEM installation on the remaining nine units subject to the requirements of Title IV. Completion of this project is expected to cost approximately $1 million during 1995. The CAAA Title V operating permits are expected to cost approximately $400,000 in 1995.
The CAAA will also regulate emissions of 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 in future years. 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 employs the least cost option to comply with the CAAA and be in a competitive position to market its services.
During 1992, OG&E disclosed to the EPA discrepancies in the 1991 annual report required by the Toxic Substance Control Act ("TSCA"). These discrepancies were administrative in nature and presented no harm to the environment and presented no health problems to our Company members or the public. However, the Company has instituted specific systems and measures to correct each of the reported discrepancies. No actions were taken by the EPA on this matter during 1994. 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. Also, numerous states are considering proposals to require "retail wheeling" which is the delivery of power generated by a third party to retail customers. In 1995, the Company intends to make a transmission open access filing before the FERC, in compliance with the Energy Act, and the Company intends to implement Real Time Pricing for a pilot group of its retail customers. The Energy Act, these proposals 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. Past actions include the redesign and restructuring effort in 1994 and the actions to reduce fuel costs, both of which have resulted in lower retail rates, especially for industrial customers.
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 ---------------------------------------------------
CONSOLIDATED STATEMENTS OF INCOME
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
The accompanying Notes to Consolidated Financial Statements are an integral part hereof.
CONSOLIDATED BALANCE SHEETS
The accompanying Notes to Consolidated Financial Statements are an integral part hereof.
The accompanying Notes to Consolidated Financial Statements are an integral part hereof.
CONSOLIDATED STATEMENTS OF CAPITALIZATION
The accompanying Notes to Consolidated Financial Statements are an integral part hereof.
CONSOLIDATED STATEMENTS OF CASH FLOWS
The accompanying Notes to Consolidated Financial Statements are an integral part hereof.
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." SFAS No. 71 provides that, based upon the expectation to recover from, or flowback to, future customers, certain costs can be deferred as regulatory assets, rather than expensed and certain credits can be recognized as regulatory liabilities, rather than treated as income. Management's expected recovery of deferred costs and flowback of deferred credits generally results from specific decisions by regulators granting such ratemaking treatment. Management continuously monitors the future recoverability of regulatory assets. When, in management's judgment, future recovery becomes impaired, the amount of the regulatory asset is reduced or written-off, as appropriate. See Notes 7 and 10 of Notes to Consolidated Financial Statements for related discussion.
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 1994, 1993 and 1992, 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 depreciated 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 4.58%, 3.60% and 4.30% for the years 1994, 1993 and 1992, respectively.
UNBILLED REVENUE
OG&E accrues estimated revenues for services provided but not yet billed. The cost of providing service is recognized as incurred.
AUTOMATIC FUEL ADJUSTMENT CLAUSES
Variances in the actual cost of fuel used in electric generation and certain purchased power costs, as compared to that component in estimated cost-of-service for ratemaking, are charged to substantially all of the Company's electric customers through automatic fuel adjustment clauses, which are subject to periodic review by the Oklahoma Commission, the Arkansas Commission and the 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. The estimated replacement cost of fuel inventories exceeded the stated LIFO cost by approximately $2.5 million, $2.3 million and $4.8 million for 1994, 1993 and 1992, respectively, based on the average cost of fuel purchased late in the respective years. LIFO liquidation gains and losses (no gains or losses in 1994, approximately $0.5 million gain in 1993 and approximately $1.3 million loss in 1992) reduced or increased the Company's recovery under its automatic fuel adjustment clauses, with no impact on net income. Natural gas products inventories are held for sale and accounted for based on the weighted average cost of production.
-------------------------------------------------------------------------------- 2. INCOME TAXES
The items comprising tax expense are as follows:
The following schedule reconciles the statutory federal tax rate to the effective income tax rate:
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.
Payment of the rate refund in 1994 resulted in lower current income tax expense. The provisions for rate refund accrued in 1992 and 1993 were not deductible for income tax purposes until the refund was paid in 1994, resulting in higher current income tax expense in 1992 and 1993.
The Company follows the provisions of SFAS No. 109, "Accounting for Income Taxes," which it adopted effective January 1, 1993. SFAS No. 109 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 are as follows:
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.
For 1992, the provision for deferred income taxes was 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.
-------------------------------------------------------------------------------- 3. COMMON STOCK AND RETAINED EARNINGS
There were no new shares of common stock issued during 1994, 1993 or 1992. The $37,000 decrease in 1994 and $21,000 increase in 1993 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.
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 18,950, 18,687 and 18,631 shares of common stock during 1994, 1993 and 1992, respectively. The Company also reacquired 11,040 and 1,235 shares in 1994 and 1993, respectively. The shares distributed/reacquired in the reported periods were recorded as treasury stock.
Changes in common stock were:
There were 4,009,021 shares of unissued common stock reserved for the various employee and Company stock plans at December 31, 1994. With the exception of the Restricted Stock Plan, the common stock requirements, pursuant to those plans, are currently being satisfied with stock purchased on the open market.
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 $14.0 million of costs relating to obtaining such amendments over the remaining life of the respective bond issues. At the end of 1994, there was approximately $10.4 million in unamortized costs associated with obtaining these amendments.
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 acquirer 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 December 31, 1994, gross property additions pledged totaled approximately $355 million.
Annual sinking fund requirements for each of the five years subsequent to December 31, 1994, are as follows:
As in prior years, OG&E expects to meet these requirements by pledging permanent additions to property.
In January 1995, OG&E refinanced its obligations with respect to $47,000,000 of 5 7/8% Pollution Control Revenue Bonds due December 1, 2007 and $32,050,000 of 6 3/4% Pollution Control Revenue Bonds due March 1, 2006 through the issuance of two new series of pollution control bonds bearing interest at variable, tax-exempt rates and are due January 1, 2025. The 5 7/8% Series and the 6 3/4% Series Bonds will be called March 1, 1995.
In August 1994, Enogex redeemed its $90 million of outstanding medium-term notes, with interest rates ranging from 9.88% to 10.11%. As of December 31, 1994, Enogex long-term debt consisted of a $6.9 million, variable interest rate note, maturing July 31, 2001. At December 31, 1994, the interest rate was 8 1/4%.
Maturities of First Mortgage Bonds during the next five years consist of $25 million in 1995, $15 million in 1997, $25 million in 1998 and $12.5 million in 1999.
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, 1994.
-------------------------------------------------------------------------------- 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 1994 were $220.0 million and $130.6 million, respectively, at a weighted average interest rate of 4.76%. The weighted average interest rates for 1993 and 1992 were 3.60% and 4.30%, respectively. OG&E has an agreement for a flexible line of credit, up to $200 million, through December 31, 1997. The line of credit which was nominated by OG&E at $160 million at year-end is maintained on a fee basis of 1/8 of 1%, per year, on the unused balance. Enogex has a line of credit, up to $90 million, through July 31, 1995. The Enogex line of credit is maintained on a fee basis of LIBOR plus 1/2 of 1%, and a facility fee of 1/8 of 1% per year. Short-term debt in the amount of $182.8 million was outstanding at December 31, 1994, of which approximately $90 million pertained to debt incurred in connection with Enogex's refinancing of its medium-term notes.
-------------------------------------------------------------------------------- 7. POSTEMPLOYMENT BENEFIT PLANS
During 1994, the Company restructured its operations, reducing its workforce by approximately 24 percent. This was accomplished through a Voluntary Early Retirement Package ("VERP") and an enhanced severance package. The VERP included enhanced pension benefits as well as postemployment medical and life insurance benefits.
As a result of the postemployment benefits provided in connection with this workforce reduction, the Company incurred severance costs and certain one-time costs computed in accordance with SFAS No. 88, "Employers' Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits" and SFAS No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions." In response to an application filed by the Company, the Oklahoma Commission directed the Company to defer the one-time costs which had not been offset by labor savings through December 31, 1994. The remaining balance of the one-time costs will be amortized over 26 months. The components of the severance and VERP costs and the amount deferred are as follows:
The restructuring charges reflected above, include only costs that were actually incurred in 1994.
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 in the accompanying Consolidated Statements of Income as Other operation.
In determining the projected benefit obligation, the weighted average discount rate used was 8.25%, 7.25% and 8.5% for 1994, 1993 and 1992, respectively. The assumed rate of increase in future salary levels was 4.5% in 1994 and 1993 and 5.5% in 1992. 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 1994, 1993 and 1992 included the following:
The following table sets forth the plan's funded status at December 31, 1994, 1993 and 1992:
POSTRETIREMENT MEDICAL AND LIFE INSURANCE BENEFITS
In addition to providing pension benefits, the Company provides certain medical 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 medical and life insurance benefits were recognized as expense when claims were paid ("pay-as-you-go"). Pay-as-you-go costs totaled approximately $4,621,000, $3,804,000 and $3,443,000 for 1994, 1993 and 1992, respectively.
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.
During 1993, OG&E expensed "pay-as-you-go" postretirement benefits and recorded a deferral for the difference between pay-as-you-go and SFAS No. 106 requirements. The February 25, 1994, Oklahoma Commission rate order directed OG&E 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. Accordingly, OG&E recorded a regulatory asset for the difference between the amounts using the pay-as-you-go method (adjusted for the phase-in plan) and those required by SFAS No. 106.
A decision was made in the second quarter of 1994 to discontinue deferral of the differential and to charge to expense $8.4 million of postretirement benefits that had been recorded as a regulatory asset. Although OG&E continues to believe that it could have recovered these costs in future rate proceedings before the Oklahoma Commission, OG&E decided to recognize these expenses currently, due to its strategy to reduce its cost-structure, which minimizes future revenue requirements. OG&E expects to continue charging to expense the SFAS No. 106 costs and to include an annual amount as a component of cost-of-service in future ratemaking proceedings.
Net postretirement benefit expense for the years ended December 31, 1994 and December 31, 1993, included the following components:
The discount rate used in determining the accumulated postretirement benefit obligation was 8.25%, 7.25% and 8.5% for December 31, 1994, December 31, 1993 and January 1, 1993, respectively. The rate of increase in future compensation levels used in measuring the life insurance accumulated postretirement benefit obligation was 4.5% for December 31, 1994 and December 31, 1993 and 5.5% for January 1, 1993. A 12.0 percent annual rate of increase in the per capita cost of covered health care benefits was assumed for 1994; the rate is assumed to decrease gradually to 4.5% by the year 2006 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, 1994 by approximately $7.3 million, and the aggregate of the service and interest cost components of net postretirement health care cost for 1994 by approximately $1.0 million.
The following table sets forth the funded status of the postretirement benefits and amounts recognized in the Company's Consolidated Balance Sheets as of December 31, 1994 and December 31, 1993:
POSTEMPLOYMENT BENEFITS
In November 1992, the FASB issued SFAS No. 112, "Employers' Accounting for Postemployment Benefits," which requires the accrual of the estimated cost of benefits provided to former or inactive employees after employment but before retirement. The Company adopted this new standard effective January 1, 1994, recording $4.7 million of postemployment benefits cost for the year.
-------------------------------------------------------------------------------- 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.
(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 1995 are estimated at $89 million.
The Company acquires natural gas for boiler fuel under 738 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, 1994, 1993 and 1992, outstanding prepayments for gas, including the amounts classified as current assets, under these contracts were approximately $10,879,000, $22,165,000 and $24,543,000, 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, 1994, the Company held non-cancelable operating leases covering approximately 1,500 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:
Rental payments under operating leases were approximately $5.6 million in 1994, $4.9 million in 1993 and $3.6 million in 1992.
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. Pursuant to that agreement, the Company made cash advances to the developer amounting to approximately $38.8 million, as of December 31, 1994, which is included in Prepayments and other on the accompanying Consolidated Balance Sheets. Upon completion of the storage facility, it is anticipated that the developer will obtain alternative financing for the project and repay the cash advances. OG&E will utilize the facility on a fee basis.
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 1994, 1993 and 1992, OG&E made total payments to cogenerators of approximately $210.3 million, $213.0 million and $179.4 million, of which $173.2 million, $165.5 million and $101.6 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: 1995 - $174 million, 1996 - $175 million, 1997 - $176 million, 1998 - $184 million and 1999 - $189 million.
Approximately $7.4 million of the Company's construction expenditures budgeted for 1995 are to comply with environmental laws and regulations.
The Company continues to explore options to comply with the Clean Air Act Amendments of 1990 ("CAAA"). Since all of OG&E's coal-fired generating units currently burn low-sulfur coal, OG&E will not need to take any steps to comply with the new sulfur dioxide emission limits until January 1, 2000. In compliance with Title IV of the CAAA, the Company has completed installation of continuous emission monitors ("CEMs") on each of its five coal-fired generating units and three of its 12 gas-fired generating units. Expenditures on CEMs in 1994 totaled approximately $6 million. The Environmental Protection Agency ("EPA") established a time extension for installation of CEMs on gas-fired
units which allowed the Company to defer CEM installation on the remaining nine units subject to the requirements of Title IV. Completion of this project is expected to cost approximately $1million during 1995. The CAAA Title V operating permits are expected to cost approximately $400,000 in 1995.
The CAAA will also regulate emissions of 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 in future years. 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 employs the least cost option to comply with the CAAA and be in a competitive position to market its services.
The Company is a party to three separate actions brought by the 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.
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. 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 significant 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, 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 required OG&E to refund approximately $41.3 million. The $14 million annual reduction in rates was expected to lower OG&E's rates to its Oklahoma customers by approximately $17 million annually. With respect to the $41.3 million refund, $39.1 million was associated with revenues prior to January 1, 1994, while the remaining $2.2 million related 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.
As discussed in Note 7 of Notes to Consolidated Financial Statements, during the third quarter of 1994, the Company incurred $63.4 million of costs related to the Voluntary Early Retirement Package ("VERP") and enhanced severance package. Pending an Oklahoma Commission order, OG&E deferred these costs; however, between August 1, and December 31, 1994, the amount deferred was reduced by approximately $14.5 million. In response to an application filed by OG&E on August 9, 1994, the Oklahoma Commission issued an order on October 26, 1994, that permitted the Company to amortize the December 31, 1994, regulatory asset of $48.9 million over 26 months and reduced OG&E's electric rates by approximately $15 million annually, effective January 1995. The Company anticipates that labor savings from the VERP and severance package will substantially offset the amortization of the regulatory asset and annual rate reduction of $15 million.
The components of Deferred Charges - Other, on the Consolidated Balance Sheets included the following, as of December 31:
Regulatory Assets and Liabilities consisted of the following as of December 31:
While the Company does not expect to cease meeting the criteria for application of SFAS No. 71 in the foreseeable future, if the Company were required to discontinue the application of SFAS No. 71 for some or all of its operations, it would result in writing off the related regulatory assets; the financial effects of which could be significant.
-------------------------------------------------------------------------------- 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 the Enogex 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:
On January 1, 1994, SFAS No. 115, "Accounting for Certain Investments in Debt and Equity Securities," became effective. This did not have a material adverse impact on the Company's 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, 1994, 1993 and 1992, 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, 1994, 1993 and 1992, and the results of their operations and their cash flows for the years then ended in conformity with generally accepted accounting principles.
/s/ ARTHUR ANDERSEN LLP
Oklahoma City, Oklahoma, January 26, 1995
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:
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 29, 1995. 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:
o Consolidated Balance Sheets at December 31, 1994, 1993 and 1992
o Consolidated Statements of Income for the years ended December 31, 1994, 1993 and 1992
o Consolidated Statements of Retained Earnings for the years ended December 31, 1994, 1993 and 1992
o Consolidated Statements of Capitalization at December 31, 1994, 1993 and
o Consolidated Statements of Cash Flows for the years ended December 31, 1994, 1993 and 1992
o Notes to Consolidated Financial Statements
o Report of Independent Public Accountants
o Report of Management
SUPPLEMENTARY DATA
o Interim Consolidated Financial Information
2. FINANCIAL STATEMENT SCHEDULE (INCLUDED IN PART IV) PAGE ---- Schedule II - Valuation and qualifying accounts 59
Report of Independent Public Accountants 60
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
(B) REPORTS ON FORM 8-K
Item 5. Other Events, dated February 28, 1994. Item 5. Other Events, dated April 29, 1994. Item 5. Other Events, dated October 28, 1994.
OKLAHOMA GAS AND ELECTRIC COMPANY
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
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 January 26, 1995. Our audits were made for the purpose of forming an opinion on those statements taken as a whole. The schedule listed on Page 51, Item 14 (a) 2. is the responsibility of the Company's management and is presented for purposes of complying with the Securities and Exchange Commission's rules and is not part of the basic financial statements. This schedule has been subjected to the auditing procedures applied in the audits of the basic financial statements and, in our opinion, fairly states in all material respects the financial data required to be set forth therein in relation to the basic financial statements taken as a whole.
/s/ ARTHUR ANDERSEN LLP ARTHUR ANDERSEN LLP
Oklahoma City, Oklahoma, January 26, 1995
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, as amended, the Registrant has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Oklahoma City, and State of Oklahoma on the 29th day of March, 1995.
OKLAHOMA GAS AND 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 Exchange Act of 1934, as amended, this Report has been signed below by the following persons in the capacities and on the dates indicated.
EXHIBIT INDEX