Item 1. BUSINESS
GENERAL
Enron Corp. ("Enron"), a Delaware corporation organized in 1930, is an integrated natural gas company with headquarters in Houston, Texas. Essentially all of Enron's operations are conducted through its subsidiaries and affiliates which are principally engaged in the gathering, transportation and wholesale marketing of natural gas to markets throughout the United States and internationally through approximately 44,000 miles of natural gas pipelines; the exploration for and production of natural gas and crude oil in the United States and internationally; the production, purchase, transportation and worldwide marketing of natural gas liquids and refined petroleum products; the independent (i.e., non-utility) development, promotion, construction and operation of power plants, natural gas liquids facilities and pipelines in the United States and internationally; and the non-price regulated purchasing and marketing of energy related commitments. As of December 31, 1994, Enron employed approximately 6,955 persons.
As used herein, unless the context indicates otherwise, "Enron" refers to Enron Corp. and its subsidiaries and affiliates.
BUSINESS SEGMENTS
Enron's operations are classified into the following four business segments:
1) Transportation and Operation: Interstate transmission of natural gas; construction, management and operation of natural gas and natural gas liquids pipelines, liquids plants, clean fuels plants and power facilities; and investment in crude oil transportation activities and liquids pipeline operations.
2) Domestic Gas and Power Services: Purchasing, marketing and financing of natural gas, natural gas liquids and electric power; price risk management in connection with natural gas, natural gas liquids and electric power transactions; intrastate natural gas pipelines; development, acquisition and promotion of natural gas-fired power plants in North America; and extraction of natural gas liquids in North America.
3) International Gas and Power Services: Independent (non-utility) development, acquisition and promotion of power plants, natural gas liquids facilities and pipelines outside of North America; and international marketing of natural gas liquids.
4) Exploration and Production: Natural gas and crude oil exploration and production and sale of reserves and related assets primarily in the United States, Canada, Trinidad and India.
For financial information by business segment for the fiscal years ended December 31, 1992 through December 31, 1994, please see Note 17 to the Consolidated Financial Statements on page.
TRANSPORTATION AND OPERATION
Interstate Pipelines
Enron and its subsidiaries operate domestic interstate pipelines extending from Texas to the Canadian border and across the southern United States from Florida to California. Included in Enron's domestic interstate natural gas pipeline operations are Northern Natural Gas Company ("Northern"), Transwestern Pipeline Company ("Transwestern") and Florida Gas Transmission Company ("FGT") (indirectly 50% owned by Enron). Northern, Transwestern and FGT are interstate pipelines and are subject to the regulatory jurisdiction of the Federal Energy Regulatory Commission (the "FERC"). Each pipeline serves customers in a specific geographical area: Northern, the upper Midwest; FGT, the State of Florida; and Transwestern, principally the California market. In addition, Enron holds a 13% interest in Northern Border Partners, L.P., which owns a 70% interest in the Northern Border Pipeline system. An Enron subsidiary operates the Northern Border Pipeline system, which transports gas from Western Canada to delivery points in the midwestern United States. Also, Enron has an approximately 15% interest in Enron Liquids Pipeline, L.P., which is engaged in pipeline transportation of natural gas liquids, refined petroleum products and carbon dioxide, operates coal terminalling, gas processing and natural gas liquids fractionation facilities, and is operated by a wholly-owned subsidiary of Enron.
Northern Natural Gas Company. Through its approximately 23,500-mile natural gas pipeline system stretching from Texas to Michigan's Upper Peninsula and the Canadian Border, Northern transports gas to points in its traditional market area of Illinois, Iowa, Kansas, Michigan, Minnesota, Nebraska, South Dakota and Wisconsin. Gas is transported to town borders for consumption and resale by non-affiliated gas utilities and municipalities and to other pipeline companies and end-users. Northern also gathers and transports gas at various points outside its traditional market area in the production areas of Colorado, Kansas, Montana, New Mexico, Oklahoma, Texas and Wyoming for utilities, end-users and other pipeline and marketing companies.
In Northern's market area, natural gas is an energy source available for traditional residential, commercial and industrial uses. Northern's throughput totaled 1,996 trillion British thermal units ("Tbtu") in 1994, compared to 1,943 Tbtu in 1993. In its traditional market area, Northern's throughput increased to 819 Tbtu in 1994 from 788 Tbtu in 1993. Northern's jurisdictional sales decreased from 61 Tbtu in 1993 to 33 Tbtu in 1994, evidencing a continuing shift from sales to transportation volumes due to the implementation of open access transportation service. Transportation of volumes in the traditional market area rose from 788 Tbtu in 1993 to 819 Tbtu in 1994. The volume of gas delivered by Northern in its non-traditional market area increased to 1,177 Tbtu in 1994 from 1,115 Tbtu in 1993.
Order Nos. 636, 636-A and 636-B were promulgated by the FERC in 1992. The primary intent of the orders was to create equality of service between the traditional pipeline merchant sales service and open-market transportation service, and the primary effect of which has been to substantially eliminate merchant sales by pipelines like Northern. The orders also mandate a rate design, known as straight fixed variable, which is designed to allow pipelines to recover substantially all fixed costs, a return on equity and income taxes in the capacity reservation component of their rates. (See "Regulation - Natural Gas Rates and Regulations"). Northern implemented the service restructuring required by Order Nos. 636, 636-A and 636-B on November 1, 1993, by unbundling its sales service, offering a limited market based merchant service and establishing a straight fixed variable rate design to recover all fixed costs, including return on equity, in the demand component of its rates. The FERC has indicated that Northern will be authorized to recover all prudently incurred costs associated with a reduced merchant role resulting from the implementation of Order Nos. 636, 636-A, and 636-B.
As a result of Northern's restructuring under Order 636, and as part of the unbundling of its services, Northern has ceased its function as a merchant of gas. Gas gathering is no longer an activity that is needed to support the former merchant service nor is it a means necessary to attach gas supplies to support Northern's other transportation and storage services. In 1994 Northern filed an application with the FERC requesting authority to abandon its gathering assets in the Anadarko, Permian, Hugoton and Rocky Mountain areas by sale to certain non-jurisdictional affiliates under Section 7(b) of the Natural Gas Act. On November 15, 1994, Enron executed an agreement with a third party pursuant to which Enron has agreed to sell its interests in Northern's Anadarko gas gathering assets.
On December 22, 1994, Northern filed an application with the FERC for authority to construct and operate five compressor stations and three town border stations in Iowa, Illinois and Wisconsin to expand capacity on Northern's system in those areas. These facilities will provide incremental firm capacity on a portion of Northern's mainline system extending east from the Ogden, Iowa compressor station through the Waterloo, Iowa and Galena, Illinois compressor stations terminating near Eagle, Wisconsin (Northern's "East Leg") in order to transport gas which is to be utilized for natural gas requirements in various shippers' market areas in Iowa, Illinois and Wisconsin. Northern's application proposes to increase the daily flow rate on the East Leg by approximately 72,200 million British thermal units per day ("MMBtu") for the 1995-1996 heating season markets and approximately 35,400 MMBtu per day for delivery to markets in 1996, for a total increase in capacity on the East Leg of 107,600 MMBtu per day.
Northern competes with other interstate pipelines in the transportation and storage of gas. Northern competes with other pipelines, producers, gatherers and gas aggregators for gathering volumes. As noted above, FERC orders have been designed to introduce more competition into the natural gas industry, and have had the effect of increasing transportation volumes and decreasing or eliminating sales of natural gas by pipelines.
Transwestern Pipeline Company. Transwestern is an open- access interstate pipeline engaged in the transportation of natural gas. Through its approximately 4,500-mile pipeline system, Transwestern transports natural gas from West Texas, Oklahoma, eastern New Mexico and the San Juan Basin in northwest New Mexico primarily to the California market, in addition to transportation off the east end of its system. Substantially all of Transwestern's total of 1.06 billion cubic feet ("Bcf") per day of delivery capacity to California is currently held by shippers on a firm basis. Transwestern has access to three significant gas basins for its gas supply: the Permian Basin in West Texas and eastern New Mexico, the San Juan Basin in northwestern New Mexico and southern Colorado, and the Anadarko Basin in the Texas and Oklahoma Panhandles.
Transwestern's mainline capacity includes a lateral pipeline to the San Juan Basin in northwestern New Mexico which allows Transwestern to (i) access the San Juan Basin for gas supply, (ii) service northern California markets, (iii) access the central California enhanced oil recovery market and (iv) enhance its ability to deliver to markets east of California. Total throughput volumes to California averaged approximately 706 million cubic feet ("MMcf") per day in 1994, compared to 757 MMcf per day in 1993.
During 1993, Transwestern developed its firm transportation service on the east end of its system to transport Permian and San Juan Basin supplies into Texas, Oklahoma and the midwestern United States. Transwestern transported an average of 388 MMcf per day off the east end of its system in 1994, as compared 312 MMcf per day in 1993 and 156 MMcf per day in 1992.
Transwestern filed its Order No. 636 compliance filing in July 1992, and received FERC approval on February 1, 1993. Under its Order 636 program, Transwestern now has, among other things, a capacity release program and a straight fixed variable rate design. This rate design collects all fixed costs, including income taxes and return on equity, in monthly demand or reservation fees.
In 1994, Transwestern filed an application with the FERC to spin-down its production and gathering facilities to Transwestern Gathering Company ("TGC"), a wholly-owned subsidiary of Transwestern. TGC intends to sell these production and gathering facilities to third parties. In November 1994, TGC entered into a sale agreement covering certain of these facilities subject to FERC approval of Transwestern's spin-down proceeding.
Transwestern is subject to competition from other transporters into the southern California market, including El Paso Natural Gas Company, Kern River Gas Transmission Company, Pacific Gas Transmission Company, and intrastate producers and affiliates of Southern California Gas Company.
Florida Gas Transmission Company. An Enron subsidiary owns a 50% interest in FGT by virtue of its 50% interest in Citrus Corp., which owns all of the capital stock of FGT. Another Enron subsidiary operates the FGT pipeline.
FGT is an open access interstate pipeline company that transports natural gas for third parties. Its approximately 5,300-mile dual pipeline system extends from South Texas to a point near Miami, Florida. FGT provides a high degree of gas supply flexibility for its customers because of its proximity to the Gulf of Mexico producing region and its interconnections with other interstate pipeline systems which provide access to virtually every major natural gas producing region in the United States.
FGT has periodically expanded its system capacity to keep pace with the growing demand for natural gas in Florida. In July 1987, FGT placed its Phase I expansion in service, increasing its firm average delivery capacity from 725 billion British thermal units ("BBtu") per day to 825 BBtu per day. In December 1991, FGT placed its Phase II expansion in service, increasing its firm average delivery capacity by 100 BBtu per day to a total of 925 BBtu per day. In response to continued growth in demand for natural gas, FGT placed its Phase III expansion in service on March 1, 1995, expanding its pipeline through a combination of the construction of new pipeline and compression facilities and the purchase of third-party facilities and transportation service. These measures were a continuation of FGT's efforts to meet increased natural gas demand in Florida through expansions of its system. The Phase III expansion increases FGT's firm average delivery capacity into Florida by 532 BBtu per day to 1,457 BBtu per day. The Phase III expansion includes approximately 800 miles of new FGT pipeline facilities, seven additional delivery points and approximately 106,000 additional horsepower of compression. As part of Phase III, FGT also purchased an interest in facilities that link its system to the Mobile Bay producing area and purchased 100 Bbtu per day of capacity on another interstate pipeline system to provide its customers with additional sources of supply.
Historically, FGT primarily sold natural gas to customers who resold such natural gas ("sales for resale") and sold natural gas directly to industrial and utility end users ("direct sales"). To a lesser extent, FGT also transported natural gas for others ("transportation services"), primarily under long-term contracts to firm customers.
As an open access pipeline and with the implementation of Order No. 636, commencing November 1, 1993, FGT began providing transportation services to any shipper of natural gas on a nondiscriminatory basis to the extent it has capacity available, subject to the terms of its FERC- approved tariff. These services are provided under long- term contracts to firm customers and under interruptible contracts with customers who purchase interruptible capacity. Interruptible capacity is scheduled according to the rate charged by FGT in the event that nominations exceed available capacity. As part of the transition to open access in 1990, all of FGT's sales for resale and direct sales customers were given the opportunity over time to convert their contractual sales entitlements to firm transportation service. Most major customers chose to do so, converting at least a part of their requirements to firm transportation. All remaining sales customers became transportation customers, effective on November 1, 1993 with the Order No. 636 restructuring. FGT's customers have reserved over 99% of the existing capacity on the FGT system pursuant to firm transportation service agreements.
FGT is the only interstate natural gas pipeline serving peninsular Florida. The construction of a new pipeline serving peninsular Florida would require significant capital expenditures and appropriate environmental and other regulatory approvals. While these hurdles are significant, FGT's market is attractive and will be sought by competitors. Because of the firm transportation agreements in effect for the existing capacity and the Phase III facilities, FGT does not believe that any proposed pipelines, if they are built, will affect usage of its existing capacity or the Phase III facilities in the near term. The proposed pipelines could have a negative effect on FGT's ability to expand beyond Phase III and could result in competition for the Phase III facilities when the Phase III transportation agreements begin to expire.
FGT also faces competition from residual fuel oil in the Florida market. A primary advantage of the straight fixed variable rate design is that FGT will recover substantially all of its fixed costs regardless of levels of usage by its customers.
While FGT has no definitive plans for a Phase IV expansion, it continues to measure the demand for increased service to Florida to determine if demand warrants further expansions.
Northern Border Partners, L.P. Northern Border Partners, L.P., a Delaware limited partnership, owns 70% of Northern Border Pipeline Company, a Texas general partnership ("Northern Border"). An Enron subsidiary holds a 13% interest in the limited partnership, and serves as operator of the pipeline. Northern Border owns a 969-mile interstate pipeline system that transports natural gas from the Montana-Saskatchewan border near Port of Morgan, Montana to interconnecting pipelines in the State of Iowa, one of which is Northern. The pipeline system has access to natural gas reserves in the provinces of Alberta, British Columbia and Saskatchewan, as well as the Williston Basin and the Great Plains Coal Gasification Project in the United States. Interconnecting pipeline facilities provide access to markets in the Midwest, as well as other markets throughout the United States by transportation, displacement and exchange agreements for the referenced Canadian and U.S. natural gas reserves. Therefore, Northern Border is strategically situated to transport significant quantities of natural gas to major gas consuming markets. Northern Border's revenues are derived from agreements for the receipt and delivery of gas at points along the pipeline system as specified in each shipper's individual transportation contract. Northern Border transports gas for shippers under a tariff regulated by the FERC that allows it to recover operations and maintenance costs of the pipeline system, taxes other than income taxes, interest, depreciation and amortization, an allowance for income taxes and a regulated equity return. Northern Border does not own the gas that it transports and therefore it does not assume any gas commodity price risk.
Northern Border has focused its efforts primarily on being a low cost transporter of Canadian gas exported to the United States. As of December 31, 1994, Northern Border had firm transportation service agreements, other than those under temporary release, with four interstate pipeline companies, 18 domestic and Canadian producers and marketers, including Enron Capital & Trade Resources Corp., and 11 local distribution companies. Since 1988, Northern Border has been transporting volumes at or near its maximum capacity. Based upon existing contracts and capacity, 100% of Northern Border's firm capacity (approximately 1.7 Bcf of natural gas per day) is contractually committed through October 1997, and 93% of such capacity is contractually committed through October 2001. At the present time, 6% of the capacity is contracted by interstate pipelines. The remaining capacity is contracted to producers, marketers and local distribution companies. Enron Capital & Trade Resources Corp., along with a marketing affiliate of a general partner in Northern Border, holds 8% of the contracted capacity. Northern Border competes with two other pipeline systems that transport gas from Canada to the Midwest.
Northern Border is currently evaluating opportunities to increase its capacity. In February 1995, Northern Border filed a certificate application with the FERC for a proposed project that would expand the current pipeline system and extend 263 miles of pipeline from Harper, Iowa, to Griffith, Indiana. The proposed project also includes seven new compressor stations. The proposed expansion would add approximately 213 MMcf per day of Canadian gas, and the extension would deliver approximately 263 MMcf per day into new markets. Both the expansion and extension, if approved as proposed, are expected to be in service by November 1997 at a cost of approximately $370 million.
Enron Liquids Pipeline, L.P. Enron owns approximately 15% of Enron Liquids Pipeline, L.P., a Delaware limited partnership formed in August 1992. An Enron subsidiary serves as general partner and operates the partnership's two interstate common carrier natural gas liquids ("NGL") pipeline systems, and one carbon dioxide pipeline system. The partnership also owns and operates a gas processing plant and the Cora Terminal, a high speed, rail to barge coal transfer facility, and also owns a 25% interest in an NGL fractionator. The North System of Enron Liquids Pipeline, a 1,600-mile interstate common carrier NGL and refined petroleum products pipeline system, transports, stores and delivers a full range of NGLs and refined products from south central Kansas to markets in the Midwest and has interconnects, using third party pipelines, to the eastern United States. The Cypress Pipeline transports ethane from Mont Belvieu, Texas to the Lake Charles, Louisiana area. The Central Basin Pipeline transports carbon dioxide in West Texas for use in enhanced oil recovery operations in the Permian Basin of West Texas. The Painter gas processing plant, located in southwestern Wyoming, processes natural gas for the extraction of natural gas liquids. The Cora Terminal stores coal and transfers coal mined in southern Illinois from railcars to barges that transport it to end users, principally for electricity generation.
The North System and the Cypress Pipeline are interstate common carrier pipelines, subject to regulation by the FERC. As an interstate common carrier, the partnership offers interstate transportation services by means of the North System and Cypress Pipeline to any shipper of NGLs who requests such services, provided that the products tendered for transportation satisfy the conditions and specifications contained in the applicable tariff. The Central Basin Pipeline is not subject to rate regulation.
Operation and Management of Power Facilities
Enron's subsidiary companies are involved in the independent power industry, both as an operator of and as an equity partner in independent (i.e., non-utility) natural gas-fired power plants, some of which use combined cycle and cogeneration technology to generate electricity and steam. Cogeneration is the simultaneous production of thermal energy (primarily steam) and electricity from a single fuel source, such as natural gas. A conventional electric power plant produces electricity and discharges resulting exhaust heat as waste. Cogeneration uses this previously wasted heat to create steam for industrial use and electricity, requiring less fuel than other methods using separate electric and thermal energy plants. In addition, Enron has developed diesel-fired power plants for projects in developing countries, where the development, engineering design and construction are done on an accelerated basis in order to address severe power shortages in such countries. (See "International Gas and Power Services" for a general description of Enron's international power businesses).
In North America, Enron subsidiary companies manage the physical operation of a 330-megawatt facility located in Pasadena, Texas, a 450-megawatt facility located in Texas City, Texas, a 250-megawatt facility located in Richmond, Virginia, and a 149-megawatt facility located in Milford, Massachusetts. Enron subsidiaries also manage the physical operations of several international power plants which are described herein under the caption "International Gas and Power Services."
Crude Oil Transportation Services
EOTT Energy Partners, L.P., a Delaware limited partnership formed in March 1994, owns and operates the business and assets of EOTT Energy Corp. ("EOTT"), an independent gatherer and marketer of crude oil. Enron owns an approximately 40% interest in EOTT Energy Partners, L.P. EOTT is engaged in the purchasing, gathering, transporting, processing, trading, storage and resale of crude oil and refined petroleum products, and related activities.
Through its North American crude oil gathering and marketing operations, EOTT purchases crude oil produced from approximately 23,000 leases in 18 states, principally in the Gulf Coast, Southwest, Rocky Mountain and Mid-Continent regions of the United States. In addition, EOTT is a purchaser of lease crude oil in Canada. Within the United States, EOTT transports most of the lease crude oil it purchases by means of a fleet of more than 300 owned or leased trucks, and by pipeline, including more than 1,000 miles of intrastate and interstate pipeline and gathering systems owned by EOTT and common carrier pipeline systems owned by third parties. In addition, to a limited degree, EOTT provides transportation and trading services for third party purchasers of crude oil. These pipeline systems and trucking operations cover 16 states. EOTT also purchases crude oil from integrated and independent producers in the United States and Canada. EOTT markets the crude oil to major integrated oil companies and independent refiners throughout the United States and Canada. In its North American crude oil gathering and marketing operations, EOTT purchased approximately 256,000 barrels per day of lease crude oil during 1994.
Through its West Coast operations, EOTT gathers crude oil from leases in the Los Angeles Basin and San Joaquin Valley in Southern California, acquires Alaskan crude oil delivered into onshore facilities in Los Angeles Harbor and acquires additional crude oil volumes from marketers and others. EOTT then blends and upgrades the crude oil, remarkets it to refiners and other parties, and/or delivers it to a refinery owned by a third party, where it may be processed for EOTT's account under a long-term processing agreement. Such processing arrangement allows EOTT to provide asphalts to the roofing and paving industries in the Southern California market. The profitability of EOTT's processing agreement is significantly influenced by the crack spread, which is the difference between the sales price of refined petroleum products and the cost of feedstocks (principally crude oil) delivered to the refinery for processing.
DOMESTIC GAS AND POWER SERVICES
The domestic gas and power services segment includes Enron Capital & Trade Resources Corp. and affiliated companies ("ECT") and the domestic gas processing operations. ECT includes the marketing, purchasing and financing of natural gas, natural gas liquids ("NGL") and electric power and the management of the portfolio of commitments arising from these activities. The domestic gas processing operations consist of the extraction and fractionation of NGLs.
Enron Capital & Trade Resources Corp.
ECT is responsible for Enron's marketing activities in North America and provides financial services for producers and end-users of energy commodities. ECT offers a broad range of services to provide predictable pricing, reliable delivery and low cost capital to its customers. These services are provided through a variety of products including forward contracts, swap agreements and other contractual commitments. ECT's operations can be categorized into three business lines: cash and physical, risk management and finance.
Cash and Physical. The cash and physical operations include the marketing and transportation of physical natural gas, liquids and other commodities under contracts of one year or less and the management of ECT's contract portfolio. ECT's cash and physical business is augmented by its physical assets consisting of intrastate pipelines, numerous storage facilities, liquids assets and ownership interests in domestic power generation facilities.
The day-to-day buying, selling and transporting of commodities is facilitated by using the New York Mercantile Exchange. This allows ECT to manage its portfolio of contracts and to benefit from the relationship between the financial and physical prices for natural gas. Total physical and notional sales volumes for 1994 averaged 24 trillion British thermal units ("Tbtu") of natural gas equivalents per day. Included in this amount are physical volumes of approximately 7.5 Tbtu per day.
The intrastate pipelines included in ECT are Houston Pipe Line Company ("HPL") and Louisiana Resources Company. HPL owns an approximately 5,500-mile pipeline in Texas which interconnects with Northern, Transwestern, FGT and numerous other interstate and intrastate pipelines. HPL's intrastate natural gas sales, transportation and storage services are subject to seasonal variation because many of its customers have weather-sensitive gas requirements. The Railroad Commission of Texas has jurisdiction over intrastate gas pipeline rates, operations and transactions in Texas. See "Regulation--Natural Gas Rates and Regulations." In April 1993, Enron acquired Louisiana Resources Company, which includes rights to a 540-mile intrastate pipeline which spans the state of Louisiana and serves the industrial complex along the Mississippi River from Baton Rouge to New Orleans. The pipeline interconnects with the Henry Hub and has numerous interconnections with both interstate and intrastate pipelines.
ECT's Napoleonville natural gas storage facility located in Louisiana, which accesses the Louisiana Resources Company pipeline, provides approximately 4 Bcf of working capacity. This facility enhances the benefits of Louisiana Resources Company by improving ECT's ability to meet the firm requirements of industrial markets in Louisiana, and secondly, to provide the swing and peak capability required by local distribution companies and electric utilities along the Eastern seaboard.
ECT's electric power business consists of various activities associated with the North American power market, such as providing natural gas contract services to electric utilities; managing, acquiring, developing and promoting power-related assets and joint ventures; and marketing and supplying electricity. ECT markets natural gas to the electric power generation industry, offering firm contract commitments with both fixed-price and other innovative pricing terms (such contracts of greater than one year are included in ECT's risk management operations). ECT will continue marketing natural gas to independent power projects as well as electric utilities converting to natural gas in response to the Clean Air Act of 1990.
ECT's power business is responsible for the commercial management of the 330-megawatt facility located in Pasadena, Texas, the 450-megawatt facility located in Texas City, Texas, the 250-megawatt facility located in Richmond, Virginia, and the 149-megawatt facility located in Milford, Massachusetts. Enron has an indirect 50% ownership interest in each of these facilities.
ECT's operations also include the North American NGL marketing activities and the "clean fuels" business which consists of the methanol and methyl tertiary butyl ether (MTBE) businesses. ECT affiliates market the output of Enron's NGL and clean fuels plants as well as product purchased from third parties.
Risk Management. The risk management activities consist of market origination activity on new long-term contracts (transactions greater than one year) and restructuring of existing long-term contracts. ECT works closely with utilities, local distribution companies and independent power producers to restructure contracts for gas supply. ECT's fixed price contract originations were 6.6 Tbtu in 1994. The risk management activities also include the origination of liquids contracts associated with new product offerings. The risk management group also purchases and sells electrical energy to and from a variety of power generators and wholesalers including investor-owned utilities, rural electric cooperatives and municipal utilities.
Finance. ECT's finance operations provide capital to customers through various product offerings including volumetric production payments. The finance group offers debt and equity capital for the energy industry and develops capital funding vehicles that support its financial product offerings. It also manages ECT's relationship in the gas supply area. In 1994, ECT provided $503 million in funding. Joint Energy Development Investments Limited Partnership, a Delaware limited partnership formed in 1993, comprised of an ECT subsidiary as general partner and the California Public Employees Retirement System as limited partner, has provided approximately $316 million for energy investments.
Domestic Gas Processing
Certain Enron subsidiaries are engaged domestically in the extraction of NGLs (ethane, propane, normal butane, isobutane and natural gasoline). NGLs are typically extracted from natural gas in liquid form under low temperature and high pressure conditions. Ethane, propane, normal butane, isobutane and natural gasoline are used as feedstocks for petrochemical plants in the production of plastics, synthetic rubber and other products. Normal butane and natural gasoline are used by refineries in the blending of motor gasoline. Isobutane is used in the alkylation process to enhance the octane content of motor gasoline and is also used in the production of MTBE, which is used to produce cleaner burning motor gasoline. Propane is used as fuel for home heating and cooking, crop drying and industrial facilities and as an engine fuel for vehicles, and ethane is used as a feedstock for synthetic fuels production. Enron's subsidiaries engaged in gas processing operations extracted as NGLs the equivalent of an estimated 42 Bcf of natural gas during 1994.
At December 31, 1994, Enron's gas processing businesses had an interest in 17 hydrocarbon extraction and fractionation facilities, 13 of which are operated by Enron, which generally are located along Enron's natural gas pipeline systems. During 1994, Enron's plants extracted 1.2 billion gallons of NGLs. A total of .4 billion gallons of product were fractionated for affiliates and others. These businesses' margins are sensitive to the relationship between NGL prices and the price of natural gas. In 1995, Enron will attempt to mitigate some of this market risk through hedging techniques.
INTERNATIONAL GAS AND POWER SERVICES
Enron's international activities principally involve the development, acquisition, promotion, and operation of natural gas and power projects and the marketing of natural gas liquids. In addition, Enron has established commercial marketing offices in London and Buenos Aires to offer the same type of physical commodity products, financial services and risk management services currently available through ECT in North America. As is the case in the United States, Enron's emphasis is on businesses in which natural gas or its components play a significant role. Development projects are focused on power plants, gas processing and terminaling facilities, and gas pipelines, while marketing activities center on fuels used by or transported through such facilities.
Enron's international activities include management of direct and indirect ownership interests in and operation of power plants in England, Germany, Guatemala and the Philippines; a pipeline system in southern Argentina; retail gas and propane sales in the Caribbean basin; processing of natural gas liquids at Teesside, England; and marketing of natural gas liquids worldwide.
Enron Development Corp. ("EDC") is involved in power and pipeline projects in varying stages of development in India, China, the Dominican Republic, Colombia, Turkey, Bolivia and Brazil, Indonesia and elsewhere.
Enron Global Power & Pipelines L.L.C. In November 1994, Enron Global Power & Pipelines L.L.C., a Delaware limited liability company ("EPP"), was formed by Enron to own and manage Enron's operating power plant and natural gas pipeline business conducted outside the United States, Canada and Western Europe, and to expand such business through acquisitions. EPP's initial assets consist of interests contributed by Enron in two power plants in the Philippines, a power plant in Guatemala and a natural gas pipeline system in Argentina (see below). Upon completion of a public offering of 10 million Common Shares of EPP in November 1994, Enron owned approximately 52% of the Common Shares. Enron formed EPP to attract public equity capital to emerging market infrastructure projects, to enable public investors to better evaluate and participate directly in the growth of Enron's operating power plant and natural gas pipeline activities in emerging markets and to generate additional capital for Enron to reinvest in future development efforts and for other corporate purposes. Enron presently does not intend to reduce its ownership of EPP below 52%.
Enron and EPP have entered into a Purchase Right Agreement pursuant to which Enron has agreed to offer to sell to EPP, at prices lower than those available to third parties, all of Enron's ownership interests in any power plant and natural gas pipeline projects developed or acquired by Enron outside the United States, Canada and Western Europe, but only those projects that commence commercial operations prior to the year 2005, subject to certain exceptions.
EPP currently has interests in two power plants in the Philippines. The Batangas power project is an approximately 110-megawatt fuel-oil-fired diesel engine plant located at Pinamucan, Batangas, on Luzon Island, which began commercial operation in July 1993. The Subic Bay power project is an approximately 116-megawatt fuel-oil-fired diesel engine plant located at the Subic Bay Freeport complex on Luzon Island, which began commercial operation in February 1994. Both projects were developed by Enron, are 50% owned by EPP and sell power to the National Power Corporation of the Philippines.
EPP has a 50% interest in an approximately 110-megawatt fuel-oil-fired diesel engine power plant mounted on two movable barges at Puerto Quetzal on Guatemala's Pacific Coast. The U.S. flagged vessels built in Louisiana went into commercial operation in February 1993, and sell all of their power output under a long-term contract to a large Guatemalan electric utility, a majority interest in which is owned by Guatemala's national electric utility.
As part of the privatization of Argentina's state-owned industries, in 1992 Enron acquired an indirect interest in Transportadora de Gas del Sur ("TGS"), the formerly state- owned natural gas pipeline in southern Argentina. In November 1994, Enron sold its net 17.5% interest to EPP. The 4,069-mile pipeline system has a capacity of approximately 1.7 Bcf per day and serves four distribution companies under long-term firm transportation contracts. TGS expanded its pipeline in 1994 by 240 MMcf per day through the addition of four compressor stations. TGS has signed transportation contracts for 210 MMcf per day of additional capacity for ten years.
India. In December 1993, an Enron affiliate signed a 20- year power purchase agreement with Maharashtra State Electricity Board, the largest generator and distributor of power in the State of Maharashtra. The contract supports the first and second phases of an approximately 2,015 megawatt gas-fired power plant and related facilities, which will ultimately include a liquefied natural gas (LNG) terminal and harbor development near Dabhol, which is approximately 100 miles south of Bombay. Enron's partners in the two-phase project are affiliates of General Electric Company, which is supplying equipment and holds a 10% equity interest, and affiliates of Bechtel Enterprises, Inc., which is the contractor and also holds a 10% equity interest. Enron plans to reduce its current 80% equity interest to a 50% interest at or before the completion of the project. Construction of the 695-megawatt first phase is underway and includes harbor development, fuel facilities, housing and related activities necessary to complete this project. The first phase of the project is expected to begin commercial operations in 1997. The construction of the 1,320-megawatt second phase addition is subject to, among other things, financing and obtaining acceptable LNG supply contracts. Enron expects to offer its ownership interest in the project to EPP when it reaches commercial operation.
Teesside. At December 31, 1994, Enron had a 50% ownership interest in an independent power facility with a capacity of approximately 1,875 megawatts at ICI Chemicals & Polymers Limited's Wilton Works Plant on Teesside in northeast England. The gas-fired combined cycle project was originated, developed, constructed and is operated by Enron subsidiaries. The remaining ownership interest is held by four of the twelve regional electric companies operating in England and Wales. The Teesside plant has the capacity to supply approximately 4% of all the electricity consumed in the U.K., and 1,725 megawatts of this capacity is committed under long-term contracts.
In addition to the Teesside power plant, Enron also operates an adjacent 300 MMcf per day gas liquids processing facility. The first phase of the liquids plant is in place and producing in excess of 300,000 gallons of natural gas liquids per day, which is being sold in the European markets. A second phase of construction began in 1994 in order to be operating by 1996 when additional natural gas volumes which Enron has purchased from the J-Block in the North Sea become available.
Enron has long-term contractual rights to 300 MMcf per day capacity on the Central Area Transmission System, a 1,400 MMcf per day capacity pipeline from the North Sea. Enron's capacity will be used to transport J-Block gas to Teesside when that gas becomes available in 1996. These new supplies will support Enron's future marketing programs.
Germany. During 1993, Enron acquired an approximately 125 megawatt gas-fired plant in Bitterfeld, Germany. Enron is a 50/50 joint venture partner with the second largest regional utility company in Germany. The Bitterfeld project provides Enron with a presence in Germany as well as access to a site for possible expansion.
Other International Development Stage Projects. The following is a brief description of power and natural gas pipeline projects which, upon commencement of commercial operations and completion of financing arrangements, will be offered for sale to EPP subject to the terms of the Enron/EPP Purchase Right Agreement. These projects are in varying stages of development, thus the information set forth below is subject to change. In addition, these projects are, to varying degrees, subject to all the risks associated with project development, construction and financing in foreign countries, including without limitation, the receipt of permits and consents and the availability of project financing on acceptable terms. There can be no assurance that these projects will commence commercial operations.
China. Enron is developing a $135 million, 150- megawatt diesel or gas-fired combined cycle power plant on Hainan Island, an economic free trade zone off the southern coast of China. The independent power project is the first such project developed by a U.S. company in China. Enron will be operator, fuel manager and construction contractor. Full combined cycle operations are expected to begin in mid- 1996.
Dominican Republic. A limited partnership in which Enron affiliated companies have a 50% ownership interest has signed a 20-year power purchase agreement with the Dominican Republic government utility in connection with the development of an estimated $200 million, 185-megawatt barge-mounted combined cycle power plant on the north coast of the Dominican Republic. The partnership will serve as operator, fuel manager and construction manager of the plant. The project is expected to be in commercial operation by mid-1995.
Colombia. Construction is underway on Enron's approximately $215 million, 357-mile natural gas pipeline and related facilities project, which pipeline will run from the northern coast of Colombia to the central region of the country. Ecopetrol, the state-owned oil company of Colombia, has contracted to be the sole customer for 15 years. Commercial operations are expected to commence in 1996.
Turkey. Enron holds a 50% interest in a $545 million, 478-megawatt gas-fired power plant to be located in Marmara, Turkey. Enron will be operator and contractor of the plant. A power purchase agreement has been signed with the state power utility, and subject to financing, construction is expected to begin in mid-1995, with commercial operation expected by the fourth quarter of 1997.
Bolivia/Brazil. As a partner with the national gas company of Bolivia, Enron is developing, along with Petrobras, the national oil and gas company of Brazil, and others, a pipeline from Bolivia to Brazil. The pipeline project includes a $1.5 billion, 1,120-mile natural gas pipeline from Santa Cruz, Bolivia to Sao Paulo, Brazil. Enron is also negotiating the development of up to 1,600 megawatts of power projects with Sao Paulo utilities at an estimated cost of $1.5 billion. Enron will own 34% of the Bolivia segment of the pipeline, 8% of the Brazilian segment of the pipeline and will hold a significant interest in the power plants.
Indonesia. Enron has negotiated a 20-year power purchase agreement with the Indonesia state utility to build a $520 million, 500-megawatt gas-fired power project in East Java, subject to terms of a gas contract under negotiation. Enron will be the contractor, plant operator and will hold a 50% interest in the project. In East Kalimantan, Indonesia, Enron is developing a $138 million, 136-megawatt gas-fired power plant. A 20-year power purchase agreement has been negotiated with the state utility, also subject to terms of a gas contract. Enron will be the contractor and plant operator and hold a 50% interest. Enron expects the first project to be in commercial operation by mid-1997 and the second project in early 1998.
Caribbean Basin. Enron's operations in the Caribbean area are conducted through Enron Americas and its subsidiary companies. Enron Americas' subsidiary Industrias Ventane ("Ventane"), organized in 1953, operates the leading natural gas liquids transportation and distribution business in Venezuela. In Venezuela, Enron Americas is also engaged in the manufacture and distribution of appliances in a joint venture with General Electric and local investors. Enron Americas has a gas pipeline operation in Puerto Rico, and liquid fuels businesses in both Puerto Rico and Jamaica.
Liquids Marketing. In late 1993 Enron consolidated the management of its international liquids marketing business with the corresponding domestic activities, in order to take advantage of techniques to enhance profitability and manage risks that have proven effective for Enron in the U.S. International liquids marketing volumes declined from 646 million gallons in 1993 to 464 million gallons in 1994, reflecting a reduction in spot market transactions in 1994 to focus on higher value transactions.
EXPLORATION AND PRODUCTION
Enron's natural gas and crude oil exploration and production operations are conducted by its subsidiary, Enron Oil & Gas Company ("EOG"). Enron currently owns 80% of the outstanding common stock of EOG.
EOG is an independent (non-integrated) oil and gas company engaged in the exploration for, and development, production and marketing of, natural gas and crude oil primarily in major producing basins in the United States, as well as in Canada, Trinidad, India and to a lesser extent, selected other international areas. At December 31, 1994, EOG had estimated net proved natural gas reserves of 1,910 Bcf and estimated net proved crude oil, condensate and natural gas liquids reserves of 37 million barrels, and at such date, approximately 70% of EOG's reserves (on a natural gas equivalent basis) was located in the United States, 16% in Canada, 11% in Trinidad and 3% in India.
EOG's main producing areas are the Big Piney area in Wyoming, South Texas primarily centered in the Lobo Trend area, the Matagorda Trend area located in federal waters offshore Texas, the Canyon Trend area located in West Texas, the Pitchfork Ranch area in southwestern New Mexico and the Kiskadee area offshore Trinidad. EOG's other domestic natural gas and crude oil producing properties are located primarily in other areas of Texas, Utah, New Mexico and Oklahoma. At December 31, 1994, 93% of EOG's proved domestic reserves (on a natural gas equivalent basis) was natural gas and 7% was crude oil, condensate and natural gas liquids.
EOG's six principal U.S. producing areas are the Big Piney area, the South Texas area, Matagorda Trend area, the Canyon Trend area, the Pitchfork Ranch area and the Vernal area. Properties in these areas comprised approximately 76% of EOG's domestic reserves (on a natural gas equivalent basis) and 76% of EOG's maximum domestic net natural gas deliverability as of December 31, 1994 and are substantially all operated by EOG. EOG also has operations in Canada and in Trinidad and is conducting exploration in selected other international areas.
EOG is engaged in the exploration for and the development and production of natural gas and crude oil and the operation of natural gas processing plants in western Canada, principally in the provinces of Alberta, Saskatchewan, and Manitoba. EOG conducts operations from offices in Calgary. Maximum Canadian natural gas deliverability net to EOG at December 31, 1994 was approximately 85 MMcf per day, and EOG held approximately 354,000 net undeveloped acres in Canada.
EOG has operations in offshore Trinidad and India and is conducting exploration in selected other international areas. Properties in offshore Trinidad and India comprised 100% of EOG's reserves and production outside of North America.
In November 1992, EOG was awarded a 95% working interest concession in the South East Coast Consortium Block offshore Trinidad, encompassing three undeveloped fields, previously held by three government-owned energy companies. The Kiskadee field is currently being developed while the remaining two undeveloped fields are anticipated to be developed over the next three to five years. Natural gas is being sold into the local market under a take-or-pay agreement with the National Gas Company of Trinidad and Tobago. At December 31, 1994, maximum natural gas deliverability net to EOG was approximately 150 MMcf per day and EOG held approximately 71,000 net undeveloped acres in Trinidad.
In December 1994, EOG signed agreements covering profit sharing, joint operations and product sales and representing a 30% working interest in and was designated operator of the Tapti, Panna and Mukta Blocks located offshore Bombay, India. The blocks were previously operated by the Indian national oil company, Oil & Natural Gas Corporation Limited, which retains a 40% working interest. The 363,000 acre Tapti Block contains two major proved gas accumulations delineated by 22 expendable exploration wells that have been plugged. EOG intends to commence development of the Tapti Block accumulations in 1995. The 106,000 acre Panna Block and the 192,000 acre Mukta Block are partially developed with five producing platforms located in the Panna and Mukta fields. The fields were producing approximately 3,000 barrels per day of crude oil net to EOG as of December 31, 1994; all associated gas was being flared. EOG intends to continue development of the accumulations and to expand processing capacity to allow crude oil production at full deliverability as well as to permit natural gas sales.
EOG continues to pursue other selected conventional natural gas and crude oil opportunities outside North America. During 1995, EOG will pursue other opportunities in countries where indigenous natural gas reserves have been identified, particularly where synergies in natural gas transportation, processing and power cogeneration can be optimized with other Enron Corp. affiliated companies. In early 1995, EOG and the Qatar General Petroleum Corporation signed a non-binding letter of intent concerning the possible development of a liquefied natural gas project for natural gas to be produced from the North Dome Field.
In 1994, EOG continued evaluation and assessment of its international opportunity portfolio in the coalbed methane recovery arena, including projects in South Wales in the U.K., the Lorraine Basin in France, Galilee Basin in Queensland, Australia and in two basins in China. A similar project in Russia continues under evaluation.
EOG actively competes for reserve acquisitions and exploration leases, licenses and concessions, frequently against companies with substantially larger financial and other resources. To the extent EOG's exploration budget is lower than that of certain of its competitors, EOG may be disadvantaged in effectively competing for certain reserves, leases, licenses and concessions. Competitive factors include price, contract terms and quality of service, including pipeline connection times and distribution efficiencies. In addition, EOG faces competition from other producers and suppliers, including increased competition from Canadian natural gas.
All of EOG's oil and gas activities are subject to the risks normally incident to the exploration for and development and production of natural gas and crude oil, including blowouts, cratering and fires, each of which could result in damage to life and property. Offshore operations are subject to usual marine perils, including hurricanes and other adverse weather conditions, and governmental regulations as well as interruption or termination by governmental authorities based on environmental and other considerations. In accordance with customary industry practices, insurance is maintained by EOG against some, but not all, of the risks. Losses and liabilities arising from such events could reduce revenues and increase costs to EOG to the extent not covered by insurance.
EOG's overseas operations are subject to certain risks, including expropriation of assets, risks of increases in taxes and government royalties, renegotiation of contracts with foreign governments, political instability, payment delays, limits on allowable levels of production and current exchange and repatriation losses, as well as changes in laws and policies governing operations of overseas-based companies generally.
The following table sets forth certain information regarding EOG's wellhead volumes of and average prices for natural gas per thousand cubic feet ("Mcf"), crude oil and condensate, and natural gas liquids per barrel ("Bbl"), and average lease and well expenses per thousand cubic feet equivalent ("Mcfe" - natural gas equivalents are determined using the ratio of 6.0 Mcf of natural gas to 1.0 barrel of crude oil and condensate or natural gas liquids) delivered during each of the three years in the period ended December 31, 1994:
The following table sets forth certain information regarding EOG's volumes of natural gas delivered under other marketing and volumetric production payment arrangements, and the resulting average per unit gross revenue and per unit amortization of deferred revenues along with associated costs during each of the three years in the period ended December 31, 1994.
REGULATION
General
Enron's interstate natural gas pipeline companies are subject to the regulatory jurisdiction of the FERC under the Natural Gas Act ("NGA") with respect to rates, accounts and records, addition of facilities, the extension of services in some cases, the abandonment of services and facilities, the curtailment of gas sales and other matters. Enron's intrastate pipeline companies are subject to state and some federal regulation. Enron's importation of natural gas from Canada is subject to approval by the Office of Fossil Energy of the Department of Energy. Certain activities of Enron are subject to the Natural Gas Policy Act of 1978 ("NGPA"). Enron's pipelines which carry natural gas liquids and refined petroleum products are subject to the regulatory jurisdiction of the FERC under the Interstate Commerce Act as to rates and conditions of service.
Domestic legislation affecting the oil and gas industry is under constant review for amendment or expansion. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue and have issued rules and regulations which, among other things, require permits for the drilling of wells, regulate the spacing of wells, prevent the waste of natural gas and crude oil resources through proration, require drilling bonds and regulate environmental and safety matters. The regulatory burden on the oil and gas industry increases its cost of doing business and, consequently, affects its profitability.
A substantial portion of EOG's oil and gas leases in the Big Piney area and in the Gulf of Mexico, as well as some in other areas, are granted by the federal government and administered by the Bureau of Land Management (the "BLM") and the Minerals Management Service (the "MMS") federal agencies. Operations conducted by EOG on federal oil and gas leases must comply with numerous statutory and regulatory restrictions. Certain operations must be conducted pursuant to appropriate permits issued by the BLM and the MMS.
Various federal, state and local laws and regulations covering the discharge of materials into the environment, or otherwise relating to the protection of the environment, may affect Enron's operations and costs through their effect on the oil and gas exploration, development and production operations as well as their effect on the construction, operation and maintenance of pipeline and terminaling facilities. It is not anticipated that Enron will be required in the near future to expend amounts that are material in relation to its total capital expenditures program by reason of environmental laws and regulations, but inasmuch as such laws and regulations are frequently changed, Enron is unable to predict the ultimate cost of compliance.
Enron's non-domestic operations are subject to the jurisdiction of numerous governmental agencies in the countries in which its projects are located with respect to environmental and other regulatory matters. Generally, many of the countries in which Enron does and will do business have recently developed or are in the process of developing new regulatory and legal structures to accommodate private and foreign-owned businesses. These regulatory and legal structures and their interpretation and application by administrative agencies are relatively new and sometimes limited. Many detailed rules and procedures are yet to be issued. The interpretation of existing rules can also be expected to evolve over time. Although Enron believes that its operations are in compliance in all material respects with all applicable environmental laws and regulations in the applicable foreign jurisdictions, Enron also believes that the operations of its projects eventually may be required to meet standards that are comparable in many respects to those in effect in the United States and in countries within the European Community. In addition, as Enron acquires additional projects in various countries, it will be affected by the environmental and other regulatory restrictions of such countries.
Natural Gas Rates and Regulations
Northern, Transwestern, Florida Gas and Northern Border are "natural gas companies" under the NGA and, as such, are subject to the jurisdiction of the FERC. The FERC has jurisdiction over, among other things, the construction and operation of pipeline and related facilities used in the transportation, storage and sale of natural gas in interstate commerce, including the extension, expansion or abandonment of such facilities. The FERC also has jurisdiction over the rates and charges for the transportation of natural gas in interstate commerce and the sale by a natural gas company of natural gas in interstate commerce for resale. Northern, Transwestern, Florida Gas and Northern Border hold the required certificates of public convenience and necessity issued by the FERC authorizing them to construct and operate all of their pipelines, facilities and properties for which certificates are required in order to transport and sell natural gas for resale in interstate commerce.
As necessary, Northern, Transwestern, Florida Gas and Northern Border file applications with the FERC for changes in their rates and charges designed to allow them to recover fully their costs of providing service to resale and transportation customers, including a reasonable rate of return. These rates are normally allowed to become effective after a suspension period, subject to refund under applicable law, until such time as the FERC rules on the allowable level of rates. Although the FERC's jurisdiction extends to the regulation of gas transported in interstate commerce or sold in interstate commerce for resale, the price at which gas is sold to direct industrial customers by a natural gas company is not subject to the FERC's jurisdiction.
In June 1988, the FERC issued Order No. 497 ("Order 497") which imposes requirements on interstate pipelines with marketing affiliates, intended to eliminate an interstate pipeline's ability to give its marketing affiliates preferential treatment. Among other things, Order 497 requires interstate pipelines to separate their operating personnel and facilities from those of their marketing affiliates to the maximum extent practicable. In 1994, the FERC issued Order Nos. 566, 566-A and 566-B, in which it extended indefinitely its Order No. 497 regulations governing relationships between interstate pipelines and their marketing affiliates, subject to revisions to delete an out of date standard and revise certain reporting and record keeping requirements. Among other matters, these new rules require pipelines to post on their electronic bulletin boards, within 24 hours of gas flow, information concerning discounted transportation provided to marketing affiliates to enable competing marketers to request comparable discounts. The rules retain existing standards, as revised by Order No. 497-E, requiring the contemporaneous disclosure to all shippers of transportation related information provided a marketing affiliate, and prohibiting disclosure of certain information to marketing affiliates.
Since 1985, the FERC has endeavored to make natural gas transportation more accessible to gas buyers and sellers on an open and non-discriminatory basis. These efforts have significantly altered the marketing and pricing of natural gas. The FERC's Order No. 636, issued in April 1992, mandates a fundamental restructuring of interstate pipeline sales and transportation services. Order No. 636 requires interstate natural gas pipelines to "unbundle" or segregate the sales, transportation, storage, and other components of their existing sales service, and to separately state the rates for each unbundled service. Under Order No. 636, unbundled pipeline sales can be made only in the production areas. Order No. 636 also requires interstate pipelines to assign capacity rights they have on upstream pipelines to such pipelines' former sales customers and provides for the recovery by interstate pipelines of costs associated with the transition from providing bundled sales services to providing unbundled transportation and storage services. The purpose of Order No. 636 is to further enhance competition in the natural gas industry by assuring the comparability of pipeline sales service and services offered by a pipelines' competitors. Various aspects of Order No. 636 were challenged, including alleged shifts of costs between pipeline customer groups and the continuing reliability of unbundled services. In two subsequent orders on rehearing of Order No. 636 (Order Nos. 636-A and 636-B), the FERC modified the original order in response to these and other concerns. Numerous parties have filed petitions for court review of Order Nos. 636, 636-A and 636-B, as well as orders in individual pipeline restructuring proceedings. Upon such judicial review, these orders may be reversed in whole or in part. With Order No. 636 subject to court review, it is difficult to predict with precision its effects.
Enron believes that, overall, Order No. 636 has had a positive impact on Enron and the natural gas industry as a whole. The structural changes mandated by Order No. 636 have resulted in a more competitive industry. The straight fixed variable rate design included in Order No. 636 allows pipelines to recover in the demand component of their rates all fixed costs allocated to firm customers. Since a pipeline recovers demand costs regardless of whether gas is ever transported, the straight fixed variable rate design is expected to reduce the volatility of the revenue stream to pipelines.
Regulatory issues and rates on Enron's regulated pipelines are subject to final determination by the FERC. Enron's regulated pipelines currently apply accounting standards that recognize the economic effects of regulation and, accordingly, have recorded regulatory assets and liabilities related to their operations. Enron evaluates the applicability of regulatory accounting and the recoverability of these assets through rate or other contractual mechanisms on an ongoing basis. Net regulatory assets at December 31, 1994 are approximately $305 million, which include transition costs incurred related to FERC Order 636 of approximately $158 million. Such regulatory assets are scheduled to be recovered from customers over varying time periods, generally up to five years.
Enron's regulated pipelines have all successfully completed their transitions under FERC Order 636 although future transition costs may be incurred subject to ongoing negotiations and market factors. Enron believes, based upon its experience to date and after considering appropriate reserves that have been established, that the ultimate resolution of pending regulatory matters will not have a material impact on Enron's financial position or results of operations.
Natural gas gathering may receive greater regulatory scrutiny at both the state and federal levels as the pipeline restructuring under Order No. 636 is implemented. In certain recent cases, the FERC has asserted ancillary NGA jurisdiction over gathering activities of interstate pipelines and their affiliates. In late 1993, the FERC convened a conference to consider issues relating to gathering services performed by interstate pipelines or their affiliates. Commencing in May 1994, the FERC issued a series of orders in individual cases that delineate its gathering policy as a result of the comments received. Among other matters, the FERC slightly narrowed its statutory tests for establishing gathering status and reaffirmed that, except in situations in which the gatherer acts in concert with an interstate pipeline affiliate to frustrate the FERC's transportation policies, it does not have jurisdiction over natural gas gathering facilities and services and that such facilities and services are properly regulated by state authorities. This FERC action may further encourage regulatory scrutiny of natural gas gathering by state agencies. In addition, the FERC has approved several transfers by interstate pipelines, including certain of Enron's pipeline subsidiaries, of gathering facilities to unregulated independent or affiliated gathering companies. This could increase competition among gatherers in the affected areas. Certain of the FERC's orders delineating its new gathering policy are subject to pending court appeals.
Enron cannot predict the effect that any of the aforementioned orders or the challenges to such orders will ultimately have on Enron's operations. Additional proposals and proceedings that might affect the natural gas industry are pending before Congress, the FERC and the courts. Enron cannot predict when or whether any such proposals or proceedings may become effective. It should also be noted that the natural gas industry historically has been very heavily regulated; therefore, there is no assurance that the less regulated approach currently being pursued by the FERC will continue indefinitely. Thus, Enron cannot predict the ultimate outcome or durability of the unbundled regulatory regime mandated by Order No. 636.
The rates at which natural gas is sold in Texas to gas utilities serving customers within an incorporated area and directly to customers in rural and unincorporated areas are subject to the original jurisdiction of the Railroad Commission of Texas. The rates set by city councils or commissions for gas sold within their jurisdiction may be appealed to the Railroad Commission. Regulation of intrastate gas sales and transportation by the Railroad Commission is governed by certain provisions of the Texas Gas Utility Regulatory Act of 1983. The Railroad Commission also regulates production activities and to some degree the operation of affiliated special marketing programs.
Oil Pipeline Rates and Regulations
The North System and Cypress Pipeline of Enron Liquids Pipeline Operating Limited Partnership (the "Partnership") are interstate common carrier pipelines, subject to regulation by the FERC under the Interstate Commerce Act ("ICA"). The ICA requires the Partnership to maintain tariffs on file with the FERC, which tariffs set forth the rates the Partnership charges for providing transportation services on the interstate common carrier pipelines, as well as the rules and regulations governing these services.
Environmental Regulations
Enron and its subsidiaries are subject to extensive federal, state and local laws and regulations covering the discharge of materials into the environment, or otherwise relating to the protection of the environment, and which require expenditures for remediation at various operating facilities and waste disposal sites, as well as expenditures in connection with the construction of new facilities. Enron believes that its operations and facilities are in general compliance with applicable environmental regulations. Environmental laws and regulations have changed substantially and rapidly over the last 20 years, and Enron anticipates that there will be continuing changes. The clear trend in environmental regulation is to place more restrictions and limitations on activities that may impact the environment, such as emissions of pollutants, generation and disposal of wastes and use and handling of chemical substances. Increasingly strict environmental restrictions and limitations have resulted in increased operating costs for Enron and other businesses throughout the United States, and it is possible that the costs of compliance with environmental laws and regulations will continue to increase. Enron will attempt to anticipate future regulatory requirements that might be imposed and to plan accordingly in order to remain in compliance with changing environmental laws and regulations and to minimize the costs of such compliance.
The Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA"), also known as the "Superfund" law, requires payments for cleanup of certain abandoned waste disposal sites, even though such waste disposal activities were undertaken in compliance with regulations applicable at the time of disposal. Under the Superfund legislation, one party may, under certain circumstances, be required to bear more than its proportional share of cleanup costs at a site where it has responsibility pursuant to the legislation, if payments cannot be obtained from other responsible parties. Other legislation mandates cleanup of certain wastes at facilities that are currently being operated. States also have regulatory programs that can mandate waste cleanup. CERCLA authorizes the Environmental Protection Agency ("EPA") and, in some cases, third parties to take actions in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. The scope of financial liability under these laws involves inherent uncertainties. Enron has entered into a consent decree with the EPA and other potentially responsible parties ("PRPs") with respect to the cleanup of one Superfund site. Enron has received requests for information from the EPA and state agencies concerning what wastes Enron may have sent to certain sites, and it has also received requests for contribution from other parties with respect to the cleanup of other sites. However, management does not believe that any costs incurred in connection with these sites (either individually or in the aggregate) will have a material impact on Enron's financial condition or results of operations. (See Item 3, "Legal Proceedings").
OPERATING STATISTICS
The following table presents selected statistical information for Enron's domestic gas and power services and transportation and operation business segments as well as revenue data for all of Enron's businesses. Revenue amounts are in thousands of dollars.
Revenues by Business Segment
CURRENT EXECUTIVE OFFICERS OF THE REGISTRANT
Name and Age Present Principal Position and Other Material Positions Held During Last Five Years
Kenneth L. Lay (52) Chairman of the Board and Chief Executive Officer since February 1986. President from February 1989 to October 1990.
Richard D. Kinder (50) President and Chief Operating Officer since October 1990. Vice Chairman of the Board from December 1988 to October 1990, and Chairman and Chief Executive Officer of Enron Gas Pipeline Group from January 1989 to October 1990. Executive Vice President and Chief of Staff from August 1987 to December 1988.
Ronald J. Burns (41) Managing Director, North American Operations, Enron Capital & Trade Resources Corp., since December 1994. Chairman and Chief Executive Officer (Marketing and Supply), Enron Gas Services Corp., from June 1993 to December 1994. Chairman and Chief Executive Officer, Enron Pipeline and Liquids Group from October 1992 to June 1993. Chairman and Chief Executive Officer, Enron Corp. Gas Pipeline Group from October 1990 to October 1992. President, Enron Corp. Interstate Pipeline Group from 1988 to October 1990.
Rodney L. Gray (42) President and Chief Executive Officer of Enron Global Power & Pipelines L.L.C. since October 1994. Managing Director, International Operations, Enron Capital & Trade Resources Corp., since December 1994. Chairman and Chief Executive Officer, Enron International Inc. since June 1993. Senior Vice President, Finance and Treasurer from October 1992 to June 1993. Vice President, Finance and Treasurer from 1988 to October 1992.
Jeffrey K. Skilling (41) Managing Director, Development, Enron Capital & Trade Resources Corp., since December 1994. Chairman and Chief Executive Officer (Risk Management and Power), Enron Gas Services Corp., from June 1993 to December 1994. Chairman and Chief Executive Officer of Enron Gas Services Corp. from January 1991 to June 1993. Chairman and Chief Executive Officer of Enron Finance Corp. since August 1990; Partner, McKinsey & Company, Consultants, from 1979 to August 1990.
Thomas E. White (51) Chairman and Chief Executive Officer of Enron Operations Corp. since June 1993. Chairman and Chief Executive Officer of Enron Power Corp. since July 1991. Brigadier General, United States Army, from 1988 to 1990. Executive Assistant to Chairman of the Joint Chiefs of Staff from 1989 to 1990.
Edmund P. Segner,III (41) Executive Vice President and Chief of Staff since October 1992. Senior Vice President, Investor, Public & Government Relations from October 1990 to October 1992. Vice President, Public and Investor Relations from February 1988 until October 1990.
James V. Derrick, Jr.(50) Senior Vice President and General Counsel since June 1991. Partner, Vinson & Elkins from January 1977 until June 1991.
Jack I. Tompkins (49) Senior Vice President and Chief Information, Administrative and Accounting Officer since October 1992. Senior Vice President and Chief Financial Officer from January 1988 to October 1992. Partner, Arthur Andersen & Co. from September 1981 until January 1988.
Kurt S. Huneke (41) Vice President, Finance and Treasurer since July 1993. Executive Vice President, Finance and Administration, Enron International Inc., from July 1992 to July 1993. Senior Vice President and Chief Financial Officer, Enron Europe Limited, from January 1991 to July 1992. Assistant Treasurer, Enron Corp., from February 1989 to January 1991.
Item 2.
Item 2. PROPERTIES
Gas Transmission and Liquid Fuels
Enron's natural gas facilities include approximately 44,000 miles of transmission and gathering lines, 111 mainline compressor stations, four underground gas storage fields and two liquefied natural gas storage facilities. Other properties in which Enron and its affiliates have an ownership interest or lease include 17 natural gas liquids extraction plants in Texas, Louisiana, Wyoming, Kansas, Florida, New Mexico and North Dakota. A large number of railroad tank and hopper cars, truck transports and bulk vehicles are owned or leased and used for the delivery of liquids products. Enron also owns interests in pipeline and related facilities associated with its participation and investments in jointly-owned pipeline systems.
Substantially all the gathering and transmission lines of Enron are constructed on rights-of-way granted by the apparent record owners of such property. In many instances, lands over which rights-of-way have been obtained are subject to prior liens which have not been subordinated to the right-of-way grants. In some cases, not all of the apparent record owners have joined in the right-of-way grants, but in substantially all such cases, signatures of the owners of majority interests have been obtained. Permits have been obtained from public authorities to cross over or under, or to lay facilities in or along, water courses, county roads, municipal streets and state highways, and in some instances, such permits are revocable at the election of the grantor. Permits have also been obtained from railroad companies to cross over or under lands or rights-of-way, many of which are also revocable at the grantor's election. Some such permits require annual or other periodic payments. In a few minor cases, property for pipeline purposes was purchased in fee.
Most of Enron's transmission subsidiaries have the right of eminent domain to acquire rights-of-way and lands necessary for their pipelines and appurtenant facilities.
Enron's gas processing plants, regulator and compressor stations, clean fuel facilities and offices are located on tracts of land owned by it in fee or leased from others.
In the case of oil and gas leases, definitive examination and curing of title defects are usually deferred until such time as funds are expended in connection with drilling of such properties.
Enron is of the opinion that it has generally satisfactory title to its rights-of-way and lands used in the conduct of its businesses, subject to liens for current taxes, liens incident to operating agreements and minor encumbrances, easements and restrictions which do not materially detract from the value of such property or the interest of Enron therein or the use of such properties in such businesses.
Oil and Gas Exploration and Production Properties and Reserves
Reserve Information
For estimates of EOG's net proved reserves and proved developed reserves of natural gas and liquids, including crude oil, condensate and natural gas liquids, see Note 18 to the Consolidated Financial Statements.
Estimates of proved and proved developed reserves at December 31, 1992, 1993 and 1994 were based on studies performed by EOG's engineering staff for reserves in both the United States, Canada, Trinidad and India. Opinions by DeGolyer and MacNaughton, independent petroleum consultants, for the years ended December 31, 1992, 1993 and 1994 covering producing areas containing 69%, 65% and 59%, respectively, of proved reserves of EOG on a net-equivalent- cubic-feet-of-gas basis, indicate that the estimates of proved reserves prepared by EOG's engineering staff for the properties reviewed by DeGolyer and MacNaughton, when compared in total on a net-equivalent-cubic-feet-of-gas basis, do not differ materially from the estimates prepared by DeGolyer and MacNaughton. Such estimates by DeGolyer and MacNaughton in the aggregate varied by not more than 5% from those prepared by EOG's engineering staff. All reports by DeGolyer and MacNaughton were developed utilizing geological and engineering data provided by EOG.
There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond the control of the producer. The reserve data set forth in Note 18 to the Consolidated Financial Statements represents only estimates. Reserve engineering is a subjective process of estimating underground accumulations of natural gas and liquids, including crude oil, condensate and natural gas liquids, that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the amount and quality of available data and of engineering and geological interpretation and judgment. As a result, estimates of different engineers normally vary. In addition, results of drilling, testing and production subsequent to the date of an estimate may justify revision of such estimate. Accordingly, reserve estimates are often different from the quantities ultimately recovered. The meaningfulness of such estimates is highly dependent upon the accuracy of the assumptions upon which they were based.
In general, the volume of production from oil and gas properties owned by EOG declines as reserves are depleted. Except to the extent EOG acquires additional properties containing proved reserves or conducts successful exploration and development activities, or both, the proved reserves of EOG will decline as reserves are produced. Volumes generated from future activities of EOG are therefore highly dependent upon the level of success in acquiring or finding additional reserves and the costs incurred in doing so.
EOG's estimates of reserves filed with other federal agencies agree with the information set forth in Note 18.
Producing Oil and Gas Wells
The following summary reflects EOG's ownership at December 31, 1994 in gas wells in 390 fields and oil wells in 87 fields located in Texas, offshore Texas and Louisiana in the Gulf of Mexico, Oklahoma, New Mexico, Utah, Wyoming and various other states, Canada, Trinidad and India. "Net" is obtained by multiplying "Gross" by EOG's working interests in the properties. Gross oil and gas wells include 188 with multiple completions.
Acreage
The following table summarizes EOG's developed and undeveloped acreage at December 31, 1994. Excluded is acreage in which EOG's interest is limited to owned royalty, overriding royalty and other similar interests.
Drilling and Acquisition Activities
During each of the years ended December 31, 1994, 1993 and 1992, EOG spent approximately $493.9 million, $430.1 million, and $395.7 million, respectively, for exploratory and development drilling and acquisition of leases and producing properties. EOG drilled, participated in the drilling of or acquired wells as set out in the table below for the periods indicated:
All of EOG's drilling activities are conducted on a contract basis with independent drilling contractors. EOG owns no drilling equipment.
Item 3.
Item 3. LEGAL PROCEEDINGS
Enron is a party to various claims and litigation, the significant items of which are discussed below. Although no assurances can be given, Enron believes, based on its experience to date and after considering appropriate reserves that have been established, that the ultimate resolution of such items, individually or in the aggregate, will not have a materially adverse impact on Enron's financial position or results of operations.
Litigation
TransAmerican Natural Gas Corporation (TransAmerican) has filed a suit in the 93rd District Court, Hidalgo County, Texas, against Enron Corp. and EOG alleging breach of confidentiality agreements, misappropriation of trade secrets and unfair competition, with specific reference to four tracts in Webb County, Texas, which EOG leased for their oil and gas exploration and development potential. TransAmerican seeks actual damages of $100 million and exemplary damages of $300 million. EOG has filed claims against TransAmerican and its sole shareholder alleging common law fraud, negligent misrepresentation and breach of state antitrust laws. On April 6, 1994, Enron Corp. was granted summary judgment, wherein the court ordered that TransAmerican take nothing on its claims against Enron Corp. As to EOG, the trial date, which was most recently set for September 12, 1994, has been continued and there is no current setting. Although no assurances can be given, Enron believes that TransAmerican's claims are without merit and that the ultimate resolution of this matter will not have a materially adverse effect on its financial position or results of operations.
A pipeline company in which an Enron affiliate has a minority interest and for which an Enron affiliate has served as operator has filed a petition against Enron and certain affiliates alleging an unspecified amount of damages relating to the operation of such pipeline company. Based upon information currently available, Enron believes that the outcome of such litigation will not have a materially adverse effect on Enron's financial position or results of operations.
During October 1994, an explosion occurred at Enron's methanol plant in Pasadena, Texas. Before the explosion, the plant was producing approximately 420,000 gallons of methanol per day, approximately half of which was being used at Enron's MTBE plant. There were no fatalities or serious injuries as a result of the explosion. Enron is currently investigating the explosion to determine the full extent of any damages; however, based upon business interruption and casualty insurance coverages, Enron currently anticipates that the explosion will not have a material adverse effect on its financial position or results of operations.
Environmental Matters
Enron is subject to extensive Federal, state and local environmental laws and regulations. These laws and regulations require expenditures in connection with the construction of new facilities, the operation of existing facilities and for remediation at various operating sites. The implementation of the Clean Air Act Amendments is expected to result in increased operating expenditures. The related future cost is indeterminable, as many of the rules implementing the Clean Air Act's requirements have not yet been finalized. However, any increased operating expenses are not expected to have a material impact on Enron's financial position or results of operations.
In connection with FGT's Phase III pipeline expansion, on September 16, 1994, the Florida Department of Environmental Protection (FDEP) entered an order suspending FGT's construction activities in wetland areas in Florida alleging that certain construction activities failed to conform with permits previously issued by that agency. The FDEP also instituted administrative proceedings for the imposition of civil penalties for such alleged violations. On September 23, 1994, FGT and the FDEP entered into a consent order in which the FDEP lifted its suspension of construction south of Suwannee County, Florida and agreed to lift its suspension on northern Florida wetlands areas construction upon FGT's adoption of certain oversight, training and wetlands restoration and mitigation practices, payment of $210,000 into the FDEP's Pollution Recovery Fund and reimbursement of another $16,000 in administrative expenses. The consent order was effective as of September 23, 1994.
On October 7, 1994, the FDEP issued notice of its intention to assess FGT with an additional civil penalty of $365,400 for alleged violations of wetlands permits and regulations in northern Florida. FGT did not contest the alleged violations or civil penalties assessed by the FDEP, and FGT has paid such penalty. FGT subsequently retrained construction personnel and took other actions to increase its efforts to comply with all requirements for construction in wetlands areas. On November 23, 1994, the FDEP dissolved the September 16 suspension order, and FGT was authorized to recommence construction in northern Florida. The Phase III expansion was placed in-service on March 1, 1995.
During May 1992, Enron entered into a Consent Decree with the EPA concerning the cleanup of the Peoples Natural Gas Superfund Site in Dubuque, Iowa, where a coal gasification plant had operated during the first half of this century. The EPA had claimed that Enron was a PRP because a predecessor company of Enron had purchased the site in the late 1950's after coal gas operations ceased, and had conducted surface operations there, including the dismantling of buildings. In the second quarter of 1992, Enron recorded the expense and related liability for these cleanup costs and under the Consent Decree agreed to make five equal, annual payments of $590,000. Three of such installments have been paid and the fourth installment is due and payable in June 1995.
In addition, Enron has received requests for information from the EPA and state environmental agencies inquiring whether Enron has disposed of materials at other waste disposal sites. Enron has also received requests for contribution from other parties with respect to the cleanup of other sites. Enron may be required to share in the costs of the cleanup of some of these sites. However, based upon the amounts claimed and the nature and volume of materials sent to sites at which Enron has an interest, management does not believe that any potential costs incurred in connection with these notices and third party claims, either taken individually or in the aggregate, will have a material impact on Enron's financial position or results of operations.
Item 4.
Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
There were no matters submitted to a vote of security holders during the fourth quarter of 1994.
PART II
Item 5.
Item 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
Common Stock
The following table indicates the high and low sales prices for the common stock of Enron as reported on the New York Stock Exchange (consolidated transactions reporting system), the principal market in which the securities are traded, and dividends paid per share for the calendar quarters indicated. The common stock is also listed for trading on the Midwest Stock Exchange and the Pacific Stock Exchange, as well as The London Stock Exchange and Frankfurt Stock Exchange.
At December 31, 1994, there were approximately 26,775 record holders of common stock, and 272 record holders of Second Preferred Stock.
Other information required by this item is set forth on page 31 under Item 6
Item 6. SELECTED FINANCIAL DATA (UNAUDITED)
Item 7.
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
The following review of the results of operations and financial condition of Enron Corp. and its subsidiaries and affiliates (Enron) should be read in conjunction with the Consolidated Financial Statements.
Results of Operations
Consolidated Net Income Enron's net income for 1994 was $453 million compared to $387 million in 1993 (exclusive of a primarily non-cash charge of $54 million to adjust the deferred tax liability for the increase in the corporate Federal statutory income tax rate from 34% to 35%) and $306 million in 1992. Net income for all three years reflects improved income before interest, minority interest and income taxes as compared to the applicable preceding year. Primary earnings per share of common stock was $1.80 in 1994 as compared to $1.32 in 1993, after a $0.23 per share charge applicable to the $54 million tax rate change adjustment, and $1.29 in 1992.
Income Before Interest, Minority Interest and Income Taxes The following table presents income before interest, minority interest and income taxes (IBIT) for each of Enron's operating segments:
Transportation and Operation The transportation and operation segment includes Enron's regulated natural gas pipelines, construction, management and operation of pipelines, liquids and clean fuels plants and power facilities, Enron's investment in crude oil marketing and transportation operations conducted by EOTT Energy Corp. (EOTT) and Enron's investment in liquids pipeline operations. The segment realized a $21 million increase in IBIT in 1994 as compared to 1993 primarily due to increased IBIT from the regulated natural gas pipelines and the construction, management and operation of assets partially offset by lower earnings from EOTT due to reduced ownership interest as discussed below. In the first quarter of 1994, EOTT exchanged its crude oil trading and transportation operations for common and subordinated units and a 2% general partner interest in EOTT Energy Partners, L.P. (the EOTT Partnership). Enron continues to own approximately 40% of the EOTT Partnership. The transportation and operation segment realized a $4 million increase in IBIT in 1993 as compared to 1992. The increase was due primarily to increases in IBIT realized by the regulated natural gas pipelines and EOTT, offset by declines in earnings from the liquids pipeline operations due to the sale of a significant portion of these operations in August 1992 and reduced revenues on completed construction projects. The following discussion analyzes the significant changes in the various components of income before interest, minority interest and income taxes for the transportation and operation segment.
Revenues Regulated Natural Gas Pipelines. Revenues of the regulated natural gas pipelines declined approximately $398 million (30%) during 1994 after increasing $60 million (5%) in 1993 as compared to the applicable preceding year. The revenue decline reflects lower sales revenues of Northern Natural Gas Company (Northern) as Northern is now primarily a transporter of natural gas. Transport revenues declined slightly as higher volumes were offset by lower average transport rates. The increased revenues during 1993 reflect increased transportation revenues recognized by Northern primarily as a result of higher commodity volumes and increased capacity utilization, combined with management fees earned in connection with the operation of the Argentina pipeline. These increases were offset by reduced sales revenues for both Northern and Transwestern Pipeline Company (Transwestern) as those companies are now primarily transporters of natural gas. Sales and transportation volumes were as follows:
Construction, Management and Operation Revenues. Revenues earned in connection with the construction, management and operation of power and pipeline projects totaled $39 million in 1994 as compared to $27 million and $52 million during 1993 and 1992, respectively. The increase in 1994 reflects fees earned in connection with the operation of additional facilities offset by lower construction revenues as a result of project completions. The decline during 1993 reflects reduced construction revenues in connection with the Teesside power project in the United Kingdom as a result of the completion of that project in March 1993, offset by revenues earned, beginning in 1993, in connection with the sales of fuel to a joint venture power project in Guatemala and fees earned in connection with the management and construction of the Milford power project in the United States.
EOTT and Liquids Pipeline. During 1994, net revenues from EOTT decreased $95 million as a result of the reduced ownership interest. Net revenues from EOTT increased approximately 39% during 1993 as a result of higher product margins. Revenues earned in connection with the liquids pipeline operations declined in 1993 primarily as a result of the sale of those assets to Enron Liquids Pipeline, L.P., a master limited partnership formed in August 1992.
Cost of Gas and Other Products Sold The cost of gas and other products sold by the transportation and operation segment decreased 82% during 1994 as compared to 1993 as a result of lower sales volumes as discussed above combined with lower average cost per unit of natural gas sold. During 1993, the cost of gas and other products sold decreased by less than 1% as compared to 1992 primarily as a result of higher average per unit gas purchase costs being offset by lower purchase volumes.
Operating Expenses Operating expenses of the transportation and operation segment declined 24% primarily as a result of the decreased ownership interest in EOTT combined with lower operating expenses of the regulated natural gas pipelines reflecting system modernization and reduced expenses resulting from lower sales volumes transported on other pipelines.
Operating expenses in the transportation and operation segment declined 10% during 1993 as compared to 1992. The decline reflects lower expenses of the regulated natural gas pipelines as a result of efficiencies gained in connection with system modernization projects, combined with a decline in operating expenses due to the previously discussed sale of the liquids pipeline operations.
Amortization of deferred contract reformation costs increased 2% during 1994 after declining by 12% during 1993 as compared to the applicable preceding year. The increase during 1994 reflects additional transition costs being amortized by Transwestern while the decline in 1993 resulted primarily from Transwestern's completion of the recovery of certain transition costs in early 1992.
Depreciation expense for the transportation and operation segment decreased $28 million (24%) during 1994 as compared to 1993 primarily as a result of the decreased ownership interest in EOTT and the interstate pipelines' adjustment in 1993 of accumulated depreciation in accordance with a Federal Energy Regulatory Commission (FERC) ruling. Depreciation expense increased $5 million (4%) during 1993 as compared to 1992 primarily as a result of the previously mentioned adjustment of accumulated depreciation partially offset by a decline in depreciation recorded for the liquids pipeline operations.
Other Income and Deductions Equity in earnings of unconsolidated subsidiaries increased by $26 million during 1994 compared to 1993 reflecting a $36 million increase in earnings from the 50% owned Citrus Corp. (Citrus) and $5 million of equity earnings from the EOTT Partnership. The increased earnings of Citrus reflect improved sales margins as a result of the renegotiation of the pricing terms of Citrus' gas sales contract with its largest customer and allowance for funds used during construction related to Florida Gas Transmission's Phase III pipeline expansion. These increases were offset by reduced earnings resulting from the decreased ownership interest in Northern Border Pipeline Company (Northern Border) as a result of Enron's contribution of its investment in Northern Border to Northern Border Partners, L.P., a master limited partnership (the Northern Border Partnership) and Enron's subsequent sale of a portion of its interest in the Northern Border Partnership in an underwritten public offering in the fourth quarter of 1993. Other income increased in 1994 as compared to 1993 primarily as a result of the continued resolution of regulatory and contractual matters relating to the interstate natural gas pipelines.
Equity in earnings of unconsolidated subsidiaries declined by $14 million (39%) during 1993 as compared to 1992 primarily reflecting reduced earnings from Northern Border. Additionally, during 1993, equity in earnings from Mojave Pipeline Company (Mojave) decreased as a result of the sale of Enron's investment in Mojave.
Outlook The transportation and operation segment should continue to provide stable earnings and cash flows during 1995. Full implementation of FERC Order 636 and the successful settlement of all significant regulatory issues by the regulated natural gas pipelines should allow for a reliable stream of cash flow. Additionally, the segment will actively promote engineering and construction services to provide incremental earnings and will seek to selectively monetize assets and reduce its overall cost structure. During 1995, the transportation and operation segment expects to complete sales of certain natural gas gathering facilities as a result of the cessation of its gas merchant function following the implementation of FERC Order 636.
Domestic Gas and Power Services The domestic gas and power services segment includes Enron Capital & Trade Resources (ECT) and the domestic gas processing operations. ECT includes the marketing, purchasing and financing of natural gas, natural gas liquids and power and the management of the portfolio of commitments arising from these activities. The domestic gas processing operations consist of the earnings associated with extraction of natural gas liquids (NGL). The following reflects income (loss) before interest, minority interest and income taxes for these businesses:
Enron Capital & Trade Resources ECT's strategy is to provide predictable pricing, reliable delivery and low cost capital to its customers. ECT provides these services through a variety of products including forward contracts, swap agreements, options, futures and other contractual commitments. In providing these services, ECT manages a variety of risks, such as market risk, credit risk, legal risk and operational risk. ECT identifies, measures and monitors these risks through a comprehensive system of internal controls. ECT's Risk Control Group is a centralized, integrated and independent control function under the direction of ECT's Chief Control Officer. It evaluates the risk exposures of ECT's business activities and develops policies and methodologies to improve ECT's ability to assess risks and protect against significant losses in existing businesses. This group is independent, but works in conjunction with ECT's business units, which are primarily accountable for managing the risks taken at the transactional and business unit levels. The Risk Control Group monitors and assesses the risk management activities of the business units, independently reviews significant risk positions, and develops and enhances policies, procedures and tools that facilitate the identification, measurement and effective mitigation of ECT's risks.
ECT had a $56 million (33%) increase in income before interest, minority interest and income taxes in 1994 as compared to 1993. This increase was primarily due to significant risk management originations and increased earnings from ECT's cash and physical businesses. This increase in earnings was partially offset by a decrease in earnings from finance operations and an increase in ECT's unallocated overhead expenses. ECT's income before interest, minority interest and income taxes increased $22 million (15%) in 1993 as compared to 1992. The increase was due primarily to increased earnings from risk management origination and finance, while the results from the cash and physical operations were virtually unchanged.
ECT can be categorized into three business lines: cash and physical, risk management and finance. The combined earnings for these business lines before unallocated expenses were $350 million in 1994, $250 million in 1993 and $215 million in 1992. The following discussion analyzes the contributions to income before interest, minority interest and income taxes and the future outlook for each of the business lines.
Cash and Physical. The cash and physical operations include earnings from physical contracts of one year or less involving marketing and transportation of physical natural gas, liquids and other commodities, earnings from the management of ECT's contract portfolio and earnings related to the physical assets of ECT. Also included in this line of business are the effects of actual settlements of ECT's long-term physical and notional quantity based contracts. This business line accounted for 53% of ECT's earnings before unallocated expenses in 1994 and 51% and 60% in 1993 and 1992, respectively.
Statistics for ECT's cash and physical operations are as follows:
The earnings from cash and physical activities increased 44% in 1994 as compared to 1993. This increase resulted primarily from ECT's successful management in 1994 of its portfolio of contracts and the ability to benefit from the relationship between the financial and physical prices for natural gas (through exchange for physical transactions, as well as providing daily and hourly physical options or swing service to customers). Earnings from short-term marketing in the purely physical gas market decreased slightly due to lower margins reflecting the more competitive marketplace. The liquids marketing activities continued to experience lower product prices, however this did not have a significant impact on the overall cash and physical business. Earnings from ECT's physical assets declined slightly due to increased fees paid for operational asset management.
Earnings from the cash and physical business decreased 1% in 1993 compared to the prior year. For 1993, earnings from short-term gas marketing and the management of ECT's contract portfolio increased 16%. This increase was offset by a decline in NGL marketing earnings due to lower volumes and margins and decreased earnings from power related assets due primarily to the inclusion in 1992 of earnings associated with certain power projects.
During 1995, ECT expects continued growth in its cash and physical business as it continues to capitalize on its position as a significant marketer of natural gas on both a financial and physical basis. The existence of its substantial portfolio of contracts, as well as the capability to benefit from the relationship between the financial and physical marketplace provides substantial opportunity for earnings. Additionally, opportunities for growth in new markets, including electricity, should enhance 1995 results.
Risk Management. The risk management operations consist of market origination activity on new long-term contracts (transactions greater than one year) and restructuring of existing long-term contracts. In 1994, the earnings from risk management originations were 41% of ECT's earnings before unallocated expenses, while this segment contributed 38% and 32% in 1993 and 1992, respectively. Fixed price contract originations were 6,615 trillion British thermal unit equivalents (TBtue), 3,781 TBtue and 2,165 TBtue for 1994, 1993 and 1992, respectively.
The earnings from these activities increased 52% in 1994. This increase resulted from the execution of various new long-term gas contracts and the restructuring of existing long-term contracts with utilities, local distribution companies and independent power producers. Additionally, the origination of liquids contracts associated with new product offerings contributed to this increase.
Earnings from risk management originations increased 41% in 1993 primarily as a result of an increase in sales volumes particularly to independent power producers.
ECT expects continued growth from its risk management activities in 1995 as it continues to provide attractive pricing structures and solutions to its customers. Additionally, significant earnings are anticipated from the growth of the market for electricity during 1995 and beyond. The infrastructure for electricity marketing is in place at ECT and ECT's growth opportunities are based on its ability to capitalize on its existing customer base, skills and the emerging competitive marketplace.
Finance. ECT's finance operations provide capital to customers through various product offerings including volumetric production payments. The finance activities contributed 6% of ECT's earnings before unallocated expenses in 1994 and 11% and 8% in 1993 and 1992, respectively. Production payments and financings arranged were $503 million, $470 million and $516 million in 1994, 1993 and 1992, respectively. The 1992 amount included $327 million of volumetric production payments arranged for Enron Oil & Gas Company (EOG), an 80% owned subsidiary of Enron.
Although total production payments and financings arranged were greater in 1994 than 1993, the earnings from these operations decreased 23% in 1994 due to a difference in the types of transactions originated in each of these periods. During 1994, ECT's finance activities transitioned from purely "senior debt-like structures," such as production payments, to more "equity-like transactions" including subordinated loans and actual equity issuances. Earnings and returns associated with these equity-like transactions are expected to be equal to or greater than returns on debt-like instruments over the life of the transactions.
Earnings associated with the finance operations increased 56% in 1993 due primarily to increased non-affiliated production payments and financings arranged.
In 1995, ECT will be expanding its products and services in its finance operations to become a full-service provider of various types of capital. Additionally, opportunities will be pursued in the international marketplace.
Other. ECT's net unallocated expenses such as rent, systems expenses and other support group costs were 36% of ECT's earnings before unallocated expenses in 1994 and 32% in both 1993 and 1992. The costs increased in 1994 as compared to 1993 due to continued expansion into new markets. Expenses also increased in 1993 from 1992 due to increased activity. ECT expects its overall expenses to increase during 1995 as it continues to expand into new markets, such as electricity. However, certain process and information system enhancements will somewhat offset this increase.
Gas Processing The gas processing operations had a loss before interest and taxes of $23 million as compared to income of $28 million in 1993 and $56 million in 1992. The decline in 1994 reflects lower processing margins due to lower product prices. During 1994, Enron entered into hedges to minimize additional volatility in product and feedstock (natural gas) prices. The decline in 1993 as compared to 1992 was attributable primarily to lower processing margins reflecting higher natural gas feedstock prices and lower product prices. Earnings for 1993 also included gains realized on the sales of certain coal handling and NGL assets.
Volume and price statistics for the gas processing operations (including intercompany amounts) are detailed below:
In 1995, Enron will continue to mitigate the market risk inherent in the gas processing business through hedging transactions. Additionally, cost cutting and streamlining actions have recently been completed, positioning the business to maximize earnings opportunities.
International Gas and Power Services Enron's international gas and power services segment includes international development activities and its international power and pipeline operations. International development activities include the development and promotion of power and natural gas projects worldwide. Income before interest and taxes for the international gas and power services group totaled $148 million during 1994, $132 million in 1993 and $33 million in 1992. The increase in IBIT during 1994 primarily reflects increased promotion and development activities and increased earnings from power and pipeline projects. The increase in IBIT during 1993 primarily reflects promotion and development activities of the power operations and earnings from the Argentina pipeline operations acquired in the fourth quarter of 1992.
Revenues Revenues of the international gas and power services segment decreased 48% during 1994 primarily due to the transfer of certain gas liquids marketing operations to ECT during the second quarter of 1994. This decline was partially offset by $65 million of revenues earned in connection with the formation of Enron Global Power & Pipelines L.L.C. (EPP), $28 million of revenues earned on the promotion of liquids processing facilities at Teesside in northeast England and higher revenues earned in connection with liquids processing activities at Teesside.
Revenues of the international gas and power services segment declined 12% during 1993 as compared to 1992 primarily as a result of decreased revenues earned by the international gas liquids marketing operations. These declines were caused by a 45% decline in marketing volumes as compared to the prior year, reflecting reduced spot market activity. The decline in liquids marketing revenues was partially offset by a $102 million increase in revenues in the power operations. The increase reflects revenues earned in connection with the promotion and development of liquids and power projects of which approximately $55 million is related to revenues in connection with the liquids processing facilities at Teesside.
Costs and Expenses The cost of gas and other products sold by the international gas and power services segment declined 63% primarily as a result of the transfer of the liquids marketing activities to ECT offset in part by product costs incurred in connection with liquids processing activities at Teesside.
The cost of gas and other products sold by the international gas and power services segment declined by 24% in 1993 as compared to 1992 and reflected a decline in international liquids marketing volumes.
Operating expenses increased $7 million (10%) during 1994 and $20 million (40%) during 1993 as compared to the preceding years primarily as a result of higher operating expenses incurred in connection with increased activities in the power operations area. Depreciation expense of the international gas and power services segment increased $6 million (68%) during 1994 as compared to 1993 primarily as a result of increased investment in international natural gas liquids assets.
Other Income and Deductions Equity in earnings of unconsolidated subsidiaries of the international gas and power services segment increased $3 million (8%) during 1994 primarily as a result of earnings from two Philippine power projects which began operations in mid 1993 and early 1994, combined with increased earnings from the Argentina pipeline project. These increases were offset by lower earnings from certain Venezuelan operations.
Equity in earnings of unconsolidated subsidiaries of the international gas and power services segment increased $36 million during 1993 as compared to 1992 primarily as a result of $23 million in earnings from the Argentina pipeline project and $12 million in earnings from the Teesside power project which was placed in commercial operation during the first quarter of 1993. Other income, net, increased during 1994 primarily as a result of foreign currency gains. Other income, net, declined $7 million during 1993 primarily as a result of lower interest income earned by the power operations in 1993 as compared with 1992 combined with gains on asset sales during 1992.
Outlook The objective of the international gas and power services segment is to deliver energy solutions worldwide through the utilization of Enron's extensive product line. Growth opportunities in the international market should result from the current and projected demand for electrical power generation, the under-utilization of natural gas reserves throughout the world and increased environmental awareness.
During 1994, Enron formed EPP to attract public equity capital to emerging market infrastructure projects, to enable public investors to better evaluate and participate directly in the growth of Enron's operating power plant and natural gas pipeline activities in emerging markets and to generate additional capital for Enron to reinvest in future development efforts and for other corporate purposes. Enron retains a 52% ownership interest in EPP and does not intend to reduce its ownership below such level.
Exploration and Production Income before interest, minority interest and income taxes of the exploration and production segment totaled $198 million during 1994 as compared to $129 million during 1993 and $102 million during 1992. Enron+s exploration and production activities are conducted by EOG. Additionally, the exploration and production segment's 1994 and 1993 income before interest, minority interest and income taxes includes approximately $35 million and $7 million, respectively, of income related to hedges placed on open positions by Enron independent of EOG. The increase in IBIT realized by EOG during 1994 primarily reflects increased gains on sales of reserves and related assets combined with a reduction in per unit operating costs. The 1993 increase was due primarily to higher natural gas prices and volumes, lower per unit operating costs and increased gains on sales of reserves and related assets. Volume and price statistics are as follows (including intercompany amounts):
The following discussion analyzes the significant changes in the various components of IBIT for the exploration and production segment.
Revenues Gross revenues of the exploration and production segment increased $72 million (10%) during 1994 after increasing by $147 million (26%) in 1993. The increases primarily reflect gains on sales of reserves and related assets which totaled $54 million in 1994 as compared to $13 million in 1993. In continuing its strategy of fully utilizing its assets to optimize profitability, cash flow and return on investment, EOG expects to continue to periodically sell selected oil and gas reserves and related assets. The 1994 and 1993 revenues include hedges placed by Enron on open commodity positions not hedged by EOG.
During 1994, the effects of volume increases of 6% in wellhead natural gas volumes and 42% in crude oil and condensate volumes were largely offset by declines of 16% and 5% in wellhead natural gas prices and crude oil and condensate prices, respectively. The increase in wellhead natural gas volumes was achieved despite voluntary U.S. curtailments of up to 25% during portions of 1994. Such curtailments occurred in response to significantly lower U.S. natural gas prices during the second half of 1994. The increase in both wellhead natural gas volumes and crude oil and condensate volumes reflects increased production from operations in Trinidad and to a lesser extent, Canada. The increased revenues in 1993 are attributable to a 22% increase in average wellhead natural gas prices combined with a 26% increase in average wellhead natural gas volumes. The increased natural gas volumes primarily reflect the effects of exploration and development activities relating to tight gas sand formations.
Costs and Expenses The cost of natural gas sold by the exploration and production segment in connection with other natural gas marketing activities declined less than 2% in 1994 as compared to 1993 after increasing 18% in 1993 as compared to 1992. The decrease in 1994 as compared to 1993 reflects 11% lower average costs partially offset by 11% higher other natural gas marketing volumes. The increase in 1993 as compared to 1992 was due to 17% higher average associated costs combined with a 15% increase in natural gas marketing volumes.
Operating expenses for the exploration and production segment increased $15 million (9%) in 1994 compared to 1993 and $35 million (24%) in 1993 compared to 1992. The increase in 1994 reflects higher exploration expenses due primarily to an increased level of exploration activities, higher impairments associated with certain offshore Gulf of Mexico leases and increased general and administrative expenses associated with expanded operations. The increase in 1993 relates to higher lease and well expenses and exploration expenses primarily due to expanded domestic and international operations.
Depreciation, depletion and amortization (DD&A) expense declined 3% in 1994 after increasing 39% in 1993 as compared to the applicable prior year. The decline during 1994 reflects increased production from offshore Trinidad at an average DD&A rate significantly less than the North American operations rate and a $0.03 per thousand cubic feet equivalent (Mcfe - natural gas equivalents are determined using the ratio of 6 Mcf of natural gas to 1 barrel of crude oil condensate or natural gas liquids) decrease in the North American DD&A rate. The increases in 1993 primarily reflect increased production volumes. On a per unit natural gas equivalent volumes delivered basis, DD&A expense declined $0.09 per Mcfe in 1994 to $0.80 per Mcfe as compared to $0.89 per Mcfe in 1993 and $0.79 per Mcfe in 1992. The 1993 increase primarily reflects higher costs associated with tight gas sand drilling activities.
Taxes, other than income taxes, declined $7 million (20%) during 1994 primarily due to lower taxable United States wellhead volumes and prices and reductions related to revisions of production and franchise taxes applied in 1994. Taxes, other than income taxes, increased $7 million (25%) from 1992 to 1993 due to increased production volumes and revenues, partially offset by continuing benefits associated with certain state severance tax exemptions allowed on high cost natural gas sales and a refund received in 1993 of franchise taxes paid in prior years.
Total per unit operating costs for lease and well expense, DD&A, general and administrative expense, interest expense and taxes other than income decreased $0.14 per Mcfe, averaging $1.29 per Mcfe during 1994 compared to $1.43 per Mcfe for 1993.
Outlook There continues to exist a good deal of uncertainty as to the direction of future North American natural gas price trends and a rather wide divergence in the opinions held by some in the industry. EOG's management remains optimistic that continually increasing recognition of natural gas as a more environmentally friendly source of energy along with the availability of significant domestically sourced supplies will result in increases in demand and a strengthening of the overall natural gas market over time. Being primarily a natural gas producer, EOG is more significantly impacted by changes in natural gas prices than by changes in crude oil and condensate prices. However, the use of various commodity price hedging mechanisms will tend to mitigate this level of sensitivity. Enron has hedged a substantial portion of its anticipated 1995 natural gas production at prices above those currently available.
EOG plans to continue to focus a substantial portion of its development and certain exploration expenditures in its major producing areas in North America. However, based on the continuing uncertainty associated with North American natural gas prices and the current weakness in that market and, as a result of the recent success realized in Trinidad and opportunities available to EOG in connection with the recent signing of agreements in India, EOG anticipates spending an increasing part of its available funds in the further development of those opportunities. In addition, EOG will continue limited exploratory expenditures in new areas outside of North America, including the continued evaluation of coalbed methane recovery potential in China, France, Australia and certain other countries.
Corporate and Other The corporate and other segment's income before interest, minority interest and income taxes was an expense of $7 million in 1994 as compared to an expense of $42 million in 1993 and income of $51 million in 1992. The improvement during 1994 primarily reflects a $15 million pretax gain realized on the formation of EOTT Energy Partners, L.P. Included in 1992 are gains from the sale of stock by EOG and sales of Mobil Corporation common stock partially offset by charges related to the establishment of reserves for litigation and other contingencies.
Interest and Related Charges, net Interest and related charges, net, is shown on the Consolidated Income Statement net of interest capitalized. The net expense decreased $27 million during 1994 and $30 million during 1993 primarily because of lower overall interest costs on Enron's floating rate obligations as a result of lower rates achieved through hedging activities. Enron periodically enters into certain interest rate swaps to manage its overall interest costs.
Dividends on Preferred Stock of Subsidiary Companies Dividends on preferred stock of subsidiary companies relate to the issuance of 8.55 million shares of 8% Cumulative Guaranteed Monthly Income Preferred Shares by Enron Capital L.L.C. in November 1993 and the issuance by Enron Capital Resources, L.P. of 3 million shares of 9% Cumulative Preferred Securities, Series A in August 1994. Additionally, during December 1994, Enron Equity Corp. issued 880 shares of 8.57% Preferred Stock, $0.001 par value, in a private transaction (see Note 9 to the Consolidated Financial Statements).
Income Tax Expense Income tax expense increased during 1994 compared to 1993 due to increased pretax income and a decrease in tight gas sand Federal tax credits. Exclusive of the adjustment for the increase in the U.S. corporate Federal statutory income tax rate from 34% to 35%, income tax expense declined slightly during 1993 as compared to 1992 as increased pretax income was offset by increased tight gas sand Federal tax credits.
Extraordinary Items The extraordinary loss recognized during 1992 results primarily from the early retirement of $599 million principal amount of 10.625% senior subordinated debentures in September 1992.
Financial Condition
Cash From Operating Activities Net cash provided by operating activities totaled $504 million during 1994 as compared to $468 million during 1993. The increase primarily reflects higher net income and reduced deferred contract reformation costs partially offset by increased working capital requirements.
Cash From Investing Activities Cash used in investing activities totaled $604 million during 1994 as compared to $639 million during 1993. Proceeds from asset sales totaled $440 million during 1994 as compared to $454 million during 1993. The 1994 amount primarily reflects proceeds realized on the formation of Enron Global Power & Pipelines L.L.C. and the sale of Enron's crude oil trading and transportation operations to EOTT Energy Partners, L.P. The 1993 amount includes proceeds received in connection with the sale of Enron's interest in Northern Border Partners, L.P. and the sale of information technology assets. As more fully discussed below, capital expenditures (property additions and other capital expenditures) declined to $669 million in 1994 as compared to $695 million in 1993. Equity investments totaled $273 million in 1994 as compared to $267 million in 1993. The 1994 amount primarily reflects investments in connection with Florida Gas Transmission's Phase III pipeline expansion and investments in Joint Energy Development Investments Limited Partnership and in various international projects. Equity investments during 1993 primarily reflect investments in Teesside Power Ltd. and the Argentina pipeline project.
Cash From Financing Activities Net cash provided by financing activities totaled $92 million during 1994 as compared to $170 million in 1993. During 1994, Enron issued $190 million of long-term debt while retiring $162 million principal amount of long-term borrowings. Other cash outflows during 1994 included $231 million of cash dividend payments on common and preferred stock and $50 million for net repurchases of Enron Corp. common stock under Enron's stock repurchase authorization. In addition to the debt issuances discussed above, financing cash inflows during 1994 included $161 million from the issuance of preferred stock by wholly-owned subsidiaries of Enron (see Note 9 to the Consolidated Financial Statements), a $115 million increase in short-term borrowings and $66 million in proceeds from common stock issuances.
Working Capital At December 31, 1994, Enron had a working capital deficit of $388 million. Enron is able to fund its deficit in working capital through the utilization of credit facilities which, at December 31, 1994, provided for up to $2.05 billion of committed and uncommitted credit of which $53 million was outstanding. Certain of the credit agreements contain prefunding covenants. However, such covenants are not expected to materially restrict Enron's access to funds under these agreements. In addition, Enron sells commercial paper and has agreements to sell up to $600 million of trade accounts receivable, thus providing financing to meet seasonal working capital needs. Management believes that the sources of funding described above are sufficient to meet short- and long-term liquidity needs not met by cash flows from operations.
Capital Expenditures Capital expenditures by operating segment are detailed as follows:
Capital expenditures during 1994 declined slightly as compared to 1993. Reduced capital expenditures by the transportation and operation, domestic gas and power services and international gas and power services segments were partially offset by higher capital spending by the exploration and production segment. The increase in capital expenditure by the exploration and production segment reflects the acquisition of selected properties to complement existing North American producing areas and the addition of new international activities in India.
The increase in capital expenditures during 1993 as compared to 1992 reflects increased expenditures by ECT as a result of the acquisition of gas storage assets and system improvement costs combined with increased capital expenditures in the exploration and production segment. The exploration and production segment's capital expenditures increased as a result of increased domestic drilling activity and the implementation of Enron's first development program outside of North America.
Capital expenditures during 1995 are expected to total approximately $672 million. However, the overall level of capital spending as well as spending by individual business segments will vary depending upon conditions in the energy market and other related economic conditions. In addition, equity investments are expected to be approximately $213 million. Management believes that the capital spending program will be funded by a combination of internally generated funds, proceeds from dispositions of selected assets and long- and short-term borrowings.
Capitalization Total capitalization at December 31, 1994 was $6.4 billion. Debt as a percentage of total capitalization decreased to 44.2% at December 31, 1994 as compared to 46.7% at December 31, 1993. The improvement primarily reflects increased retained earnings and the issuance of $163 million of preferred securities, partially offset by a net increase of $144 million in long-term debt.
Item 8.
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The information required hereunder is included in this report as set forth in the "Index to Financial Statements" on page.
Item 9.
Item 9. DISAGREEMENTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
PART III
Item 10.
Item 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The information required by Item 10 of Form 10-K relating to (i) directors who are nominees for election as directors at Enron's Annual Meeting of Stockholders to be held on May 2, 1995, and (ii) compliance by directors and executive officers with Section 16(a) of the Securities Exchange Act of 1934 is set forth, respectively, under the captions entitled "Election of Directors" and "Compensation of Directors and Executive Officers - Certain Transactions" in Enron's Proxy Statement, and is incorporated herein by reference.
The information required by Item 10 of Form 10-K with respect to executive officers is set forth in Part I of this Form 10-K under the heading "Current Executive Officers of the Registrant".
There are no family relationships among the officers listed, and there are no arrangements or understandings pursuant to which any of them were elected as officers. Officers are appointed or elected annually by the Board of Directors at its first meeting following the Annual Meeting of Stockholders, each to hold office until the corresponding meeting of the Board in the next year or until a successor shall have been elected, appointed or shall have qualified.
Item 11.
Item 11. EXECUTIVE COMPENSATION
The information regarding executive compensation is set forth in the Proxy Statement under the captions "Compensation of Directors and Executive Officers -Director Compensation; Executive Compensation; Stock Option Grants During 1994; Aggregated Stock Option/SAR Exercises During 1994 and Stock Option/SAR Values as of December 31, 1994; Long-Term Incentive Plan - Awards in 1994; Retirement and Severance Plans; Enron's Severance Pay Plan; Employment Contracts; Certain Transactions; and Compensation Committee Interlocks and Insider Participation", and is incorporated herein by reference.
Item 12.
Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
(a) Security ownership of certain beneficial owners
The information regarding security ownership of certain beneficial owners is set forth in the Proxy Statement under the caption "Election of Directors - Stock Ownership of Certain Beneficial Owners", and is incorporated herein by reference.
(b) Security ownership of management
The information regarding security ownership of management is set forth in the Proxy Statement under the caption "Election of Directors - Stock Ownership of Management and Board of Directors as of January 31, 1995", and is incorporated herein by reference.
(c) Changes in control
None.
Item 13.
Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information regarding certain relationships and related transactions is set forth in the Proxy Statement under the caption "Compensation of Directors and Executive Officers - Certain Transactions"; and "Compensation Committee Interlocks and Insider Participation", and is incorporated herein by reference.
PART IV
Item 14.
Item 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(a)(1) and (2) Financial Statements and Financial Statement Schedules. See "Index to Financial Statements" set forth on page.
(a)(3) Exhibits:
3.01 - Restated Certificate of Incorporation of Enron Corp., as amended.
*3.02 - Bylaws of Enron Corp. as currently in effect (Exhibit 3.02 to Enron Form 10-K for 1990, File No. 1-3423).
*4.01 - Indenture dated as of November 1, 1985, between Enron and Harris Trust and Savings Bank (Form T-3 Application for Qualification of Indentures under the Trust Indenture Act of 1939, File No. 22-14390, filed October 24, 1985). There have not been filed as exhibits to this Form 10-K other debt instruments defining the rights of holders of long-term debt of Enron, none of which relates to authorized indebtedness that exceeds 10% of the consolidated assets of Enron and its subsidiaries. Enron hereby agrees to furnish a copy of any such instrument to the Commission upon request.
*4.02 - Form of Amended and Restated Agreement of Limited Partnership of Enron Capital Resources, L.P. (Exhibit 3.1 to Enron Form 8-K dated August 2, 1994).
*4.03 - Form of Payment and Guarantee Agreement dated as of August 3, 1994, executed by Enron Corp. for the benefit of the holders of Enron Capital Resources, L.P. 9% Cumulative Preferred Securities, Series A (Exhibit 4.1 to Enron Form 8-K dated August 2, 1994).
*4.04 - Form of Loan Agreement, dated as of August 3, 1994, between Enron Corp. and Enron Capital Resources, L.P. (Exhibit 4.2 to Enron Form 8-K dated August 2, 1994).
*4.05 - Articles of Association of Enron Capital LLC (Exhibit 9 to Enron Corp. Form 8-K dated November 12, 1993).
*4.06 - Form of Payment and Guarantee Agreement of Enron Corp., dated as of November 15, 1993, in favor of the holders of Enron Capital LLC 8% Cumulative Guaranteed Monthly Income Preferred Shares (Exhibit 2 to Enron Form 8-K dated November 12, 1993).
*4.07 - Form of Loan Agreement, dated as of November 15, 1993, between Enron Corp. and Enron Capital LLC (Exhibit 3 to Enron Form 8-K dated November 12, 1993).
Executive Compensation Plans and Arrangements Filed as Exhibits Pursuant to Item 14(c) of Form 10-K: Exhibits 10.01 through 10.59
*10.01 - Enron Executive Supplemental Survivor Benefits Plan, effective January 1, 1987 (Exhibit 10.01 to Enron Form 10-K for 1992, File No. 1-3423).
*10.02 - Enron Corp. 1988 Stock Plan (Exhibit 4.3 to Registration Statement No. 33-27893).
*10.04 - Enron Corp. 1986 Stock Option Plan with Stock Appreciation Rights (Exhibit 4.3 to Registration Statement No. 33-13498).
*10.05 - Executive Incentive Plan (Exhibit 10.13 to Enron Form 10-K for 1987, File No. 1-3423).
*10.06 - Enron Corp. 1988 Deferral Plan (Exhibit 10.19 to Enron Form 10-K for 1987, File No. 1-3423).
*10.07 - Enron Corp. 1991 Stock Plan (Exhibit 10.08 to Enron Form 10-K for 1991, File No. 1-3423).
*10.08 - Enron Corp. 1992 Deferral Plan (Exhibit 10.09 to Enron Form 10-K for 1991, File No. 1-3423).
*10.09 - Enron Corp. Directors' Deferred Income Plan (Exhibit 10.09 to Enron Form 10-K for 1992, File No. 1-3423).
*10.10 - Employment Agreement between Enron and Kenneth L. Lay dated as of September 1, 1989 (Exhibit 10.12 to Enron Form 10-K for 1989, File No. 1-3423).
*10.11 - First Amendment to Employment Agreement between Enron and Kenneth L. Lay, dated August 21, 1990 (Exhibit 10.11 to Enron Form 10-K for 1993).
*10.12 - Second Amendment to Employment Agreement between Enron and Kenneth L. Lay, dated March 5, 1992 (Exhibit 10.12 to Enron Form 10-K for 1993).
*10.13 - Third Amendment to Employment Agreement between Enron and Kenneth L. Lay, dated August 10, 1993 (Exhibit 10.13 to Enron Form 10-K for 1993).
*10.14 - Fourth Amendment to Employment Agreement between Enron and Kenneth L. Lay, dated October 15, 1993 (Exhibit 10.14 to Enron Form 10-K for 1993).
*10.15 - Fifth Amendment to Employment Agreement between Enron and Kenneth L. Lay, dated February 28, 1994 (Exhibit 10.15 to Enron Form 10-K for 1993).
10.16 - Sixth Amendment to Employment Agreement between Enron and Kenneth L. Lay, dated April 27, 1994.
10.17 - Split Dollar Life Insurance Agreement between Enron and the KLL and LPL Family Partnership, Ltd., dated April 22, 1994.
*10.18 - Employment Agreement between Enron and Richard D. Kinder dated as of September 1, 1989 (Exhibit 10.14 to Enron Form 10-K for 1989, File No. 1-3423).
*10.19 - First Amendment to Employment Agreement between Enron and Richard D. Kinder dated August 13, 1990 (Exhibit 10.17 to Enron Form 10-K for 1991, File No. 1-3423).
*10.20 - Second Amendment to Employment Agreement between Enron and Richard D. Kinder dated September 10, 1991 (Exhibit 10.18 to Enron Form 10-K for 1991, File No. 1-3423).
*10.21 - Third Amendment to Employment Agreement between Enron and Richard D. Kinder dated March 5, 1992 (Exhibit 10.19 to Enron Form 10-K for 1992, File No. 1-3423).
*10.22 - Fourth Amendment to Employment Agreement between Enron and Richard D. Kinder dated August 16, 1993 (Exhibit 10.20 to Enron Form 10-K for 1993).
*10.23 - Fifth Amendment to Employment Agreement between Enron and Richard D. Kinder, dated October 15, 1993 (Exhibit 10.21 to Enron Form 10-K for 1993).
*10.24 - Sixth Amendment to Employment Agreement between Enron and Richard D. Kinder, dated February 28, 1994 (Exhibit 10.22 to Enron Form 10-K for 1993).
10.25 - Seventh Amendment to Employment Agreement between Enron and Richard D. Kinder, dated November 30, 1994.
*10.26 - Employment Agreement between Enron International Inc. and Rodney L. Gray, dated as of July 1, 1993 (Exhibit 10.23 to Enron Form 10-K for 1993).
10.27 - First Amendment to Employment Agreement between Enron International Inc. and Rodney L. Gray, dated May 2, 1994.
*10.28 - Employment Agreement between Enron and Ronald J. Burns dated as of July 1, 1989 (Exhibit 10.15 to Enron Form 10-K for 1989, File No. 1-3423).
*10.29 - First Amendment to Employment Agreement between Enron and Ronald J. Burns dated June 21, 1990 (Exhibit 10.20 to Enron Form 10-K for 1991, File No. 1-3423).
*10.30 - Second Amendment to Employment Agreement between Enron and Ronald J. Burns dated August 19, 1991 (Exhibit 10.21 to Enron Form 10-K for 1991, File No. 1-3423).
10.31 - Third Amendment to Employment Agreement between Enron and Ronald J. Burns, dated May 2, 1994.
*10.32 - Employment Agreement between Enron and Jack I. Tompkins dated October 1, 1991 (Exhibit 10.22 to Enron Form 10-K for 1991, File No. 1-3423).
10.33 - First Amendment to Employment Agreement between Enron and Jack I. Tompkins, dated May 2, 1994.
*10.34 - Consulting Services Agreement between Enron and John A. Urquhart dated August 1, 1991 (Exhibit 10.23 to Enron Form 10-K for 1991, File No. 1-3423).
*10.35 - First Amendment to Consulting Services Agreement between Enron and John A. Urquhart, dated August 27, 1992 (Exhibit 10.25 to Enron Form 10-K for 1992, File No. 1-3423).
*10.36 - Second and Third Amendments to Consulting Services Agreement between Enron and John A. Urquhart, dated November 24, 1992 and February 26, 1993, respectively (Exhibit 10.26 to Enron Form 10-K for 1992, File No. 1- 3423).
*10.37 - Employment Agreement between Enron and Edmund P. Segner, III dated October 1, 1991 (Exhibit 10.24 to Enron Form 10-K for 1991, File No. 1-3423).
*10.38 - First Amendment to Employment Agreement between Enron and Edmund P. Segner, III dated February 12, 1993 (Exhibit 10.28 to Enron Form 10-K for 1992, File No. 1- 3423).
10.39 - Second Amendment to Employment Agreement between Enron and Edmund P. Segner, III, dated May 2, 1994.
*10.40 - Employment Agreement between Enron and Jeffrey K. Skilling, effective August 1, 1990 (Exhibit 10.18 to Enron Form 10-K for 1990, File No. 1-3423).
*10.41 - First Amendment to Employment Agreement between Enron and Jeffrey K. Skilling, dated August 1, 1990 (Exhibit 10.30 to Enron Form 10-K for 1992, File No. 1-3423).
*10.42 - Second Amendment to Employment Agreement between Enron and Jeffrey K. Skilling, dated June 1, 1991 (Exhibit 10.31 to Enron Form 10-K for 1992, File No. 1-3423).
*10.43 - Third Amendment to Employment Agreement between Enron and Jeffrey K. Skilling, dated February 10, 1992 (Exhibit 10.32 to Enron Form 10-K for 1992, File No. 1- 3423).
*10.44 - Loan Commitment Agreement between Enron and Jeffrey K. Skilling, dated April 13, 1992 (Exhibit 10.33 to Enron Form 10-K for 1992, File No. 1-3423).
*10.45 - Fourth Amendment to Employment Agreement between Enron and Jeffrey K. Skilling, dated June 23, 1992 (Exhibit 10.34 to Enron Form 10-K for 1992, File No. 1-3423).
*10.46 - Fifth Amendment to Employment Agreement between Enron and Jeffrey K. Skilling, dated December 18, 1992 (Exhibit 10.35 to Enron Form 10-K for 1992, File No. 1- 3423).
*10.47 - Buyout Agreement between Enron and Jeffrey K. Skilling, dated December 18, 1992 (Exhibit 10.36 to Enron Form 10-K for 1992, File No. 1-3423).
*10.48 - First Amendment to Buyout Agreement between Enron and Jeffrey K. Skilling, dated December 23, 1992 (Exhibit 10.37 to Enron Form 10-K for 1992, File No. 1-3423).
*10.49 - Loan Agreement between Enron and Jeffrey K. Skilling, dated January 1, 1993 (Exhibit 10.38 to Enron Form 10-K for 1992, File No. 1-3423).
*10.50 - Employment Agreement among Enron Corp., Enron Power Corp., and Thomas E. White, dated December 9, 1992 (Exhibit 10.39 to Enron Form 10-K for 1992, File No. 1- 3423).
10.51 - Second Amendment to Employment Agreement between Enron Corp., Enron Power Corp., and Tom White, dated May 2, 1994.
*10.52 - Employment Agreement between Enron and James V. Derrick, Jr., dated June 11, 1991 (Exhibit 10.40 to Enron Form 10-K for 1992, File No. 1-3423).
10.53 - First Amendment to Employment Agreement between Enron and James V. Derrick, Jr., dated May 2, 1994.
*10.54 - Enron Gas Services Group Phantom Equity Plan (Exhibit 10.26 to Enron Form 10-K for 1991, File No. 1-3423).
*10.55 - Enron Power Corp. Executive Compensation Plan (Exhibit 10.42 to Enron Form 10-K for 1992, File No. 1-3423).
*10.56 - Enron Corp. Performance Unit Plan (Exhibit A to Enron Proxy Statement filed pursuant to Section 14(a) on March 25, 1994).
*10.57 - Enron Corp. Annual Incentive Plan (Exhibit B to Enron Proxy Statement filed pursuant to Section 14(a) on March 25, 1994).
*10.58 - Enron Corp. Performance Unit Plan (as amended and restated effective May 2, 1995) (Exhibit A to Enron Proxy Statement filed pursuant to Section 14(a) on March 27, 1994).
10.59 - Form of Enron Corp. 1994 Deferral Plan.
11 - Statement re calculation of earnings per share.
12 - Statement re computation of ratios of earnings to fixed charges.
21 - Subsidiaries of registrant.
23.01 - Consent of Arthur Andersen LLP.
23.02 - Consent of DeGolyer and MacNaughton.
23.03 - Letter Report of DeGolyer and MacNaughton dated January 13, 1995.
24 - Powers of Attorney for the officers and directors signing this Form 10-K.
27 - Financial Data Schedule.
* Asterisk indicates exhibits incorporated by reference as indicated; all other exhibits are filed herewith.
(b) Reports on Form 8-K
Current Report on Form 8-K filed on August 3, 1994 containing certain documentation in connection with the sale by Enron Capital Resources, L.P. of its 9% Cumulative Preferred Securities, Series A.
ENRON CORP.
Page No.
Consolidated Financial Statements
Report of Independent Public Accountants
Consolidated Income Statement for the years ended December 31, 1994, 1993 and 1992
Consolidated Balance Sheet as of December 31, 1994 and 1993
Consolidated Statement of Cash Flows for the years ended December 31, 1994, 1993 and 1992
Consolidated Statement of Changes in Shareholders' Equity Accounts for the years ended December 31, 1994, 1993 and 1992
Notes to the Consolidated Financial Statements
Supplemental Financial Information (Unaudited)
Financial Statements Schedules
Report of Independent Public Accountants on Financial Statements Schedules S-1
Schedule II - Valuation and Qualifying Accounts S-2
Other financial statement schedules have been omitted because they are inapplicable or the information required therein is included elsewhere in the financial statements or notes thereto.
Report of Independent Public Accountants
To the Shareholders and Board of Directors of Enron Corp.:
We have audited the accompanying consolidated balance sheet of Enron Corp. (a Delaware corporation) and subsidiaries as of December 31, 1994 and 1993, and the related consolidated statements of income, cash flows and changes in shareholders' equity accounts for each of the three years in the period ended December 31, 1994. These financial statements are the responsibility of Enron Corp.'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 Enron Corp. and subsidiaries as of December 31, 1994 and 1993, and the results of their operations, cash flows and changes in shareholders' equity accounts for each of the three years in the period ended December 31, 1994, in conformity with generally accepted accounting principles.
Arthur Andersen LLP
Houston, Texas February 17, 1995
Enron Corp. and Subsidiaries Notes to the Consolidated Financial Statements
1 Summary of SignIficant Accounting Policies
A. Consolidation The consolidated financial statements include the accounts of all majority-owned subsidiaries of Enron Corp. after the elimination of significant intercompany accounts and transactions. Investments in unconsolidated subsidiaries are accounted for by the equity method. "Enron" is used from time to time herein as a collective reference to Enron Corp. and its subsidiaries and affiliates. In material respects, the businesses of Enron are conducted by Enron Corp.'s subsidiaries and affiliates whose operations are managed by their respective officers.
B. Cash Equivalents Enron records as cash equivalents all highly liquid short-term investments with original maturities of three months or less.
C. Inventories Inventories consisting primarily of natural gas in storage of $79.1 million and $77.3 million, crude oil and refined products of $.5 million and $75.5 million and liquid petroleum products of $54.3 million and $37.3 million at December 31, 1994 and 1993, respectively, are priced at the lower of cost or market.
D. Depreciation, Depletion and Amortization The provision for depreciation and amortization with respect to operations other than oil and gas producing activities (see below) is computed using the straight- line or Federal Energy Regulatory Commission (FERC) mandated method based on estimated economic lives. Composite depreciation rates are applied to functional groups of property having similar economic characteristics.
Provisions for depreciation, depletion and amortization of proved oil and gas properties are calculated using the units-of-production method. Estimated future dismantlement, restoration and abandonment costs, net of salvage credits, are taken into account in determining depreciation, depletion and amortization.
E. Income Taxes Enron accounts for income taxes under the provisions of Statement of Financial Accounting Standards (SFAS) No. 109. SFAS No. 109 provides for an asset and liability approach for accounting for income taxes. Under this approach, deferred tax assets and liabilities are recognized based on anticipated future tax consequences attributable to differences between financial statement carrying amounts of assets and liabilities and their respective tax bases (see Note 3).
F. Earnings Per Share Primary earnings per share is computed on the basis of the average number of common shares outstanding during the periods. Common shares held by the Enron Corp. Flexible Equity Trust are not included in the computation of earnings per share (see Note 10). Dilutive common stock equivalents are not material and are not included in the computation of primary earnings per share. Fully diluted earnings per share is computed based upon the average number of common stock and common stock equivalent shares outstanding plus the average number of common shares issuable upon the assumed conversion of convertible securities.
G. Accounting for Price Risk Management Enron engages in price risk management activities for both trading and non-trading purposes. Activities for trading purposes, generally consisting of services provided to the energy sector through Enron Capital & Trade Resources (ECT), are accounted for using the mark- to-market method. Under such method, changes in the market value of outstanding financial instruments are recognized as gain or loss in the period of change. The market prices used to value these transactions reflect management's best estimate considering various factors including closing exchange and over-the-counter quotations, time value and volatility factors underlying the commitments. These market prices are adjusted to reflect the potential impact of liquidating Enron's position in an orderly manner over a reasonable period of time under present market conditions.
Activities for non-trading purposes consist of transactions entered into by Enron's other business units to hedge the impact of market fluctuations on assets, liabilities, production or other contractual commitments. Changes in the market value of these transactions are deferred until the gain or loss on the hedged item is recognized. See Note 2 for further discussion of Enron's price risk management activities.
H. Accounting for Oil and Gas Producing Activities Enron accounts for oil and gas exploration and production activities under the successful efforts method of accounting. Under such method, oil and gas lease acquisition costs are capitalized when incurred. Unproved properties with significant acquisition costs are assessed for any impairment quarterly and on a property- by-property basis and any impairment in value is recognized. Amortization of the costs of individually significant leases begins twenty-four to thirty-six months prior to expiration for five year and ten year leases, respectively, if no drilling has been initiated on the property. Unproved properties with acquisition costs that are not individually significant are aggregated, and the portion of such costs estimated to be unproductive based on historical experience and future expected abandonments is amortized over the average holding period. If the unproved properties are determined to be productive, the appropriate related costs are transferred to proved oil and gas properties. Lease rentals are expensed as incurred.
Oil and gas exploration costs, other than the costs of drilling exploratory wells, are charged to expense as incurred. The costs of drilling exploratory wells are capitalized pending determination of whether the wells have discovered proved commercial reserves. If proved commercial reserves are not discovered, such drilling costs are expensed. The costs of all development wells and related equipment used in the production of crude oil and natural gas are capitalized.
Based on Enron's strategy of maximizing the economic value of its oil and gas assets through a combination of both developing and producing, over time, crude oil and natural gas reserves and the sale of such reserves in place with related assets; gains and losses associated with such sales in place are classified as other revenues in the consolidated income statement.
I. Accounting for Development Activity Enron's project development costs consist of fees, licenses and permits, site testing, bid costs and other charges, including salaries and employee expenses, incurred in developing domestic and international projects. These costs may be recovered through development cost reimbursements from joint venture partners or other third parties, written off against development fees received, or may be included as part of an investment in those ventures where Enron continues to participate. Accumulated costs of project development are otherwise expensed in the period that it becomes probable that the costs will not be recovered.
Development revenue results from Enron's participation in the development, construction, operation and ownership of various projects. Revenue from development fees is recognized when realizable under the development agreement. Revenue from long-term construction contracts is recognized using the percentage-of-completion method and is based on the percentage relationship of incurred costs to total estimated costs. Development and construction revenues earned from joint ventures in which Enron holds an equity interest are deferred to the extent of Enron's ownership interest and recognized over the life of the facility owned by the joint venture on a straight-line basis. Proceeds from the sale of all or part of Enron's investment in development projects are recognized as revenues at the time of sale to the extent that such sales proceeds exceed the proportionate carrying amount of the investment. Total revenues recognized from the sale of development projects for the years ended December 31, 1994, 1993 and 1992, exclusive of amounts discussed below, were $28 million, $65 million and $8 million, respectively.
During November 1994, Enron sold an approximately 48% interest in Enron Global Power & Pipelines L.L.C. (EPP) for net proceeds totaling approximately $225 million. In connection with the sale, Enron recognized revenues of $65 million while deferring $48 million pending the expected 1995 expiration of certain contingent obligations. Pursuant to a Purchase Right Agreement, Enron has agreed to offer to sell to EPP Enron's ownership interests in any power plant and natural gas pipeline projects developed or acquired outside the United States, Canada and Western Europe, prior to 2005, subject to certain exceptions.
J. Accounting for Sales of Stock by Subsidiary Companies Enron recognizes gains or losses on sales of stock by its subsidiary companies when such sales are not made as part of a larger plan of corporate reorganization. Such gains or losses are based upon the difference between the book value of Enron's investment in the subsidiary immediately after the sale and the historical book value of Enron's investment immediately prior to the sale.
During August 1992, Enron Oil & Gas Company (EOG) completed a public offering, reducing Enron's ownership interest from 84% to 80%. Enron recognized a gain of $59.6 million on net proceeds totaling $111.9 million. No income tax expense was recorded related to this transaction, consistent with U.S. tax law.
K. Foreign Currency Translation For subsidiaries whose functional currency is deemed to be other than the U.S. dollar, asset and liability accounts are translated at year-end rates of exchange and revenue and expenses are translated at average exchange rates prevailing during the year. Translation adjustments are included as a separate component of shareholders' equity.
L. Reclassifications Certain reclassifications have been made to the consolidated financial statements for prior years to conform with the current presentation.
2 Price Risk Management
Trading Activities Enron, through ECT, offers price risk management services to the energy sector. These services primarily relate to commodities associated with the energy sector (natural gas, crude oil, natural gas liquids and electricity), but in some instances also include financial products (interest rate swaps and foreign currency contracts). ECT provides these services through a variety of financial instruments including forward contracts involving physical delivery of an energy commodity, swap agreements, which require payments to (or receipt of payments from) counterparties based on the differential between a fixed and variable price for the commodities specified by the options, futures and other contractual arrangements.
ECT accounts for these activities using the mark-to- market method of accounting. Under mark-to-market accounting, forwards, swaps, options, futures, certain equity investments and other financial instruments with third parties are reflected at market value, net of future servicing costs, with resulting unrealized gains and losses recorded as "Assets and Liabilities From Price Risk Management Activities" in the Consolidated Balance Sheet. Terms regarding cash settlements of these contracts vary with respect to the actual timing of cash receipts and payments. The amounts shown in the Consolidated Balance Sheet related to price risk management activities also include assets or liabilities which arise as a result of the actual timing of settlements related to these contracts. Current period changes in the assets and liabilities from price risk management activities (resulting primarily from newly originated transactions and the impact of price movements) are recognized as net gains or losses in "Other Revenues."
Notional Amounts and Terms. The notional amounts and terms of these financial instruments at December 31, 1994 are set forth below (volumes in trillions of British thermal units (TBtus), U.S. dollars in millions):
ECT also has sales and purchase commitments associated with contracts based on market prices totaling 3,850 TBtus, with terms extending up to 20 years.
Notional amounts reflect the volume of transactions but do not represent the amounts exchanged by the parties to the financial instruments. Accordingly, notional amounts do not accurately measure ECT's exposure to market or credit risks. The maximum terms in years detailed above are not indicative of likely future cash flows as these instruments may be traded in the markets at any time in response to the company's risk management needs.
The midpoint of ECT's entire portfolio of price risk management activities as of December 31, 1994 and 1993 was approximately 6.7 years and 4.5 years, respectively (based on the weighted average life of each transaction).
Fair Value. The fair value of the financial instruments as of December 31, 1994 and the average fair value of those instruments held during the year are set forth below (amounts in millions):
Market Risk. ECT's price risk management activities involve offering fixed or known price commitments into the future. These transactions give rise to market risk, which represents the potential loss that can be caused by a change in the market value of a particular commitment. Market risks are actively monitored by an independent risk control group to ensure compliance with Enron's stated risk management policies at both the corporate and subsidiary levels. These policies, including related risk limits, are regularly assessed to ensure their appropriateness given the corporation's objectives, strategies and current market conditions. It is Enron's policy to prohibit speculation on market fluctuations. Although ECT's objective is to maintain a balanced portfolio, net open positions often result from the timing of the origination of new transactions. Accordingly, ECT closely monitors and manages its exposure to market risk through a variety of risk management techniques. Policies are in place which limit the amount of total net exposure and net exposure during any twelve month period for each commodity traded and all traded commodities combined. Procedures exist which allow for real time monitoring of all commitments and positions with daily reporting of positions to senior Enron management. Additionally, sensitivities to changes in market prices of each commodity and exposure to interest rate shifts are examined on a daily basis.
The market risks of ECT's financial asset and liability positions are also assessed using value-at-risk analysis methods. Value-at-risk represents the potential loss exposure from adverse changes in market factors over a specified time period, with a given confidence level. Based on application of this risk measurement technique utilizing a probability of 95%, ECT's value-at-risk on a one day basis as of December 31, 1994 for its price risk management activities was less than 2% (unaudited) of Enron's total income before interest, minority interest and income taxes. Based upon the ongoing policies and controls discussed above, Enron does not anticipate a materially adverse effect on financial position or results of operations as a result of market fluctuations.
Credit Risk. Credit risk relates to the risk of loss that Enron would incur as a result of nonperformance by counterparties pursuant to the terms of their contractual obligations. The counterparties associated with ECT's assets from price risk management activities as of December 31, 1994 and 1993 are summarized as follows (amounts in millions):
This concentration of counterparties may impact ECT's overall exposure to credit risk, either positively or negatively, in that the counterparties may be similarly affected by changes in economic, regulatory or other conditions.
ECT maintains credit policies with regard to its counterparties that management believes significantly minimizes overall credit risk. These policies include a thorough review of potential counterparties' financial condition (including credit rating), collateral requirements under certain circumstances and the use of standardized agreements which allow for the netting of positive and negative exposures associated with a single counterparty.
ECT maintains a credit reserve which is based on management's evaluation of the credit risk of the overall portfolio. This reserve is objectively determined using an implied risk profile based on the difference between risk-free rates of return and each counterparty's cost of borrowing. This implied risk is then used to evaluate the exposure (based on current market value) to each counterparty adjusted for collateral provisions and overall concentration of exposure. Based on ECT's policies, its current exposures and the credit reserve, Enron does not anticipate a materially adverse effect on the financial position or results of operations as a result of counterparty nonperformance.
Non-Trading Activities Enron's other businesses also enter into forwards, futures and other contracts to hedge the impact of market fluctuations on assets, liabilities, production or other contractual commitments. Changes in the market value of these transactions are deferred until the gain or loss is recognized on the hedged item.
Interest Rate Swaps. At December 31, 1994, Enron and EOG had entered into interest rate swap agreements primarily to hedge floating rate exposure with a notional principal amount of $1.275 billion. Swap agreements relating to notional amounts of $875 million, $325 million and $75 million are scheduled to terminate in 1995, 1996 and thereafter, respectively. Subsequent to December 31, 1994, Enron entered into additional interest rate swap agreements with a notional principal amount of $1.150 billion. Such swap agreements with notional amounts of $650 million, $350 million and $150 million are scheduled to terminate in 1995, 1996 and 2000, respectively.
Energy Commodity Price Swaps. At December 31, 1994, Enron was a party to energy commodity price swaps covering approximately 128 Bcf, 87 Bcf and 241 Bcf of natural gas for the years 1995, 1996 and the period 1997 through 2004, respectively, and 2 million, 6 million and 3 million barrels of crude oil for the years 1995, 1996 and the period 1997 through 1999, respectively.
Foreign Currency Contracts. At December 31, 1994, foreign currency contracts with a notional principal amount of $32.8 million were outstanding. Such contracts will substantially expire in 1995.
The following table summarizes the carrying amount and estimated fair value of financial instruments held for non-trading activities as of December 31, 1994.
Credit Risk. While notional amounts are used to express the volume of various derivative financial instruments, the amounts potentially subject to credit risk, in the event of nonperformance by the third parties, are substantially smaller. Counterparties to the forwards, futures and other contracts discussed above are investment grade financial institutions. Accordingly, Enron does not anticipate any material impact to its financial position or results of operations as a result of nonperformance by the third parties on financial instruments related to non-trading activities.
3 Income Taxes
The principal components of Enron's net deferred income tax liability at December 31, 1994 and 1993 are as follows:
The components of income before income taxes and extraordinary items are as follows:
Total income tax expense is summarized as follows:
The differences between taxes computed at the U.S. Federal statutory tax rate and Enron's effective rate are as follows:
Enron has an alternative minimum tax (AMT) credit carryforward of approximately $236 million which can be used to offset regular income taxes payable in future years. The AMT credit has an indefinite carryforward period.
U.S. and foreign taxes have been provided for earnings of subsidiary companies that are expected to be remitted to the parent company. Foreign subsidiaries' cumulative undistributed earnings of approximately $188 million are considered to be indefinitely reinvested outside the U.S. and, accordingly, no U.S. income taxes have been provided thereon. In the event of a distribution of those earnings in the form of dividends, Enron may be subject to both foreign withholding taxes and U.S. income taxes, net of allowable foreign tax credits.
4 Supplemental Cash Flow Information
Cash paid for income taxes and interest expense, including fees incurred on sales of accounts receivable, is as follows:
Non-cash investing and financing activities during 1994 and 1993 included the exchange of common stock for convertible preferred stock in transactions valued at $9.2 million and $33.3 million, respectively.
Non-cash investing and financing activities during 1992 included the exchange of common stock for convertible subordinated debentures and convertible preferred stock in transactions valued at $90.5 million and $39.8 million, respectively, and the acquisition of retail gas marketing operations in exchange for common stock valued at $18.3 million.
Changes in components of working capital are as follows:
5 Credit Facilities, Short-Term Borrowings and Long-Term Debt
Enron and EOG have credit facilities with domestic and foreign banks which provided for an aggregate of $1.0 billion in long-term committed credit. Expiration dates of the committed facilities range from May 1995 to January 1998. Interest rates on borrowings are based upon the London Interbank Offered Rate, certificate of deposit rates or other short-term interest rates. Certain credit facilities contain covenants which must be met to borrow funds. Such debt covenants are not anticipated to materially restrict Enron's ability to borrow funds under such facilities. Compensating balances are not required, but Enron is required to pay a commitment or facility fee. During 1994, no amounts were borrowed under these facilities.
Enron and EOG have also entered into agreements which provide for uncommitted lines of credit totaling $1.05 billion at December 31, 1994. The uncommitted lines have no stated expiration dates. Neither compensating balances nor commitment fees are required as borrowings under the uncommitted credit lines are available subject to agreement by the participating banks. At December 31, 1994, Enron had outstanding $53.0 million under certain of the uncommitted lines at average interest rates of 5.2%. In addition to borrowing from banks on a short- term basis, Enron and certain of its subsidiaries sell commercial paper to provide financing for various corporate purposes. As of December 31, 1994, 1993 and 1992, short-term borrowings of $259.1 million, $143.8 million and $101.0 million, respectively, have been reclassified as long-term debt based upon the availability of committed credit facilities with expiration dates exceeding one year and management's intent to maintain such amounts in excess of one year subject to overall reductions in debt levels. Similarly, at December 31, 1994, 1993 and 1992, $171.1 million, $132.4 million and $292.3 million, respectively, of long- term debt due within one year remained classified as long- term.
Detailed information on short-term borrowings by Enron is as follows:
Detailed information on long-term debt is as follows:
The aggregate annual maturities of long-term debt outstanding at December 31, 1994 are $171.1 million, $283.1 million, $22.9 million, $126.2 million and $255.2 million for 1995 through 1999, respectively. In addition, based upon available committed credit facilities, $259.1 million of short-term debt which has been reclassified as long-term debt would be due in 1995.
During 1992, Enron retired, pursuant to call provisions, $836 million principal amount of long-term debt with interest rates ranging from 8.7% to 11.5%. The early retirement of debt resulted in extraordinary items of $22.6 million, net of tax.
The estimated fair value of the long-term debt at December 31, 1994 and 1993 was approximately $2.8 billion and $2.9 billion, respectively, which is the estimated cost to acquire the debt, including a premium or discount for the differential between the issue rate and the year- end market rate. The fair value of long-term debt is based upon quoted market prices and, where such prices are not available, upon interest rates available to Enron.
6 Accounts Receivable
In September 1994, Enron entered into an agreement which provides for the sale of up to $600.0 million of trade accounts receivable with limited recourse provisions and the rights to certain recoverable pipeline transition surcharges expiring January 31, 1999. At December 31, 1994, $327.7 million of receivables were sold under this agreement. At December 31, 1993, $700.1 million of receivables were sold under similar agreements which were replaced by the current agreement.
The fees incurred on the sales of accounts receivable totaled $20.8 million, $20.6 million and $23.5 million for 1994, 1993 and 1992, respectively, and are included in "Interest and Related Charges, net."
Enron affiliates have concentrations of customers in the electric and gas utility industries. These concentrations of customers may impact Enron's overall exposure to credit risk, either positively or negatively, in that the customers may be similarly affected by changes in economic or other conditions. However, Enron's management believes that the portfolio of receivables is well diversified and that such diversification minimizes any potential credit risk. Receivables are generally not collateralized.
7 Production Payment Agreement
In September 1992, EOG entered into a transaction with a limited partnership under which EOG conveyed an interest in approximately 124 billion cubic feet equivalent (136 trillion British thermal units) of natural gas and other hydrocarbons for consideration of $326.8 million (the production payment agreement). The natural gas and other hydrocarbons are scheduled to be produced and delivered through March 31, 1999. EOG retains responsibility for its working interest share of the cost of operations. Enron has accounted for the proceeds received in the transaction as deferred revenue which is being amortized into revenue as natural gas and other hydrocarbons are produced and delivered during the term of the amended agreement. Annual amortization of remaining deferred revenue, based on scheduled deliveries under the production payment agreement, as amended, is approximately $43.3 million per year through 1998 and $10.7 million for 1999. Reserves dedicated to the transaction are included in the estimate of proved oil and gas reserves (see Note 18).
8 Unconsolidated Subsidiaries
Enron has investments in and advances to unconsolidated subsidiaries as follows:
Enrons equity in earnings (losses) of unconsolidated subsidiaries is as follows:
Summarized combined financial information of Enron's unconsolidated subsidiaries is presented below:
Citrus Corp. Enron has a 50% indirect ownership interest in and operates Citrus Corp. (Citrus), a joint venture to transport and market natural gas to Florida. Effective March 1, 1995, Citrus' wholly-owned subsidiary, Florida Gas Transmission (Florida Gas), placed into service its Phase III pipeline expansion. The Phase III expansion increased Florida Gas' firm average delivery capacity by 530 MMcf/day to 1.5 Bcf/day.
Teesside Power Limited (Teesside). Enron has a 50% ownership interest in Teesside, a joint venture cogeneration company which owns a 1,875 megawatt independent power facility in northeast England. An affiliate of Enron operates the facility which was placed in commercial operation on March 27, 1993. Enron has guaranteed Teesside's obligation for certain grid charges and other amounts which could become due under certain power sales agreements. The value of such guarantees is included in Footnote 15. Transportadora de Gas del Sur S.A. In December 1992, Enron acquired a 25% interest in Compania de Inversiones de Energia S.A., an Argentine corporation which owns 70% of Transportadora de Gas del Sur S.A. (TGS). TGS is the owner and operator of a 4,000 mile natural gas pipeline system in Argentina which connects major gas fields in southern and western Argentina with distributors of gas in those areas and in the greater Buenos Aires area, the principal population center of Argentina. TGS is one of two transmission systems in Argentina.
Northern Border Partners, L.P. During October 1993, Northern Plains Natural Gas Company (Northern Plains), a wholly-owned subsidiary of Enron, along with two of the other three general partners in Northern Border Pipeline Company contributed all of their combined 70% interest in Northern Border to Northern Border Partners, L.P., a Delaware limited partnership (the Northern Border Partnership), in exchange for general partner interests, subordinated units and common units in the Northern Border Partnership. Northern Plains sold its common units in the Northern Border Partnership in an underwritten public offering for net proceeds of approximately $217 million resulting in a pretax gain of approximately $64 million. Northern Plains retains a 13% interest in the Northern Border Partnership.
EOTT Energy Partners, L.P. During March 1994, EOTT Energy Corp., a wholly-owned subsidiary of Enron, exchanged its crude oil marketing and transportation operations with EOTT Energy Partners, L.P. (the EOTT Partnership) for common and subordinated units and a 2% general partnership interest. The common units were subsequently sold in an underwritten public offering resulting in net proceeds to Enron of approximately $186 million and a pretax gain of approximately $15 million. Enron retained 40% ownership of the EOTT Partnership through its seven million subordinated units and general partnership interest.
Joint Energy Development Investments (JEDI). An Enron subsidiary and the California Public Employee Retirement System (CalPERS) each own a 50% interest in JEDI, a limited partnership which acquires and owns energy investments. The Enron subsidiary, as general partner, and CalPERS as limited partner, have each committed to invest $250 million of capital in JEDI through 1996, $70 million of which has already been contributed by Enron as of December 31, 1994. Enron intends to meet its required capital commitments by contributing Enron common stock.
9 Preferred Stock
Second Preferred Stock. The Cumulative Second Preferred Convertible Stock, $1 par value, pays dividends at an amount equal to the higher of $10.50 per share or the equivalent dividend that would be paid if shares of the Cumulative Second Preferred Convertible Stock were converted to Common Stock. The dividend for the fourth quarter of 1994 was $ 2.7304 per share. All previous quarterly dividends had been $2.625 per share. Each share of the Cumulative Second Preferred Convertible Stock is convertible at any time at the option of the holder thereof into 13.652 shares of Enron's common stock, subject to certain adjustments. The Convertible Preferred Stock is currently subject to redemption at Enron's option at a price of $100 per share plus accrued dividends. During 1994, 1993 and 1992, 91,694 shares, 332,964 shares and 397,710 shares, respectively, of the Convertible Preferred Stock were converted into common stock. During 1994, Enron authorized and issued to a wholly-owned subsidiary 35.568509 shares of 9.142% Perpetual Second Preferred Stock (a new series of the Second Preferred Stock).
Preferred Stock of Subsidiary Company. During December 1994, Enron's wholly-owned subsidiary, Enron Equity Corp., issued 880 shares of 8.57% Preferred Stock, par value $0.001 per share, liquidation preference $100,000 per share, in a private transaction at a price of $100,000 per share with net proceeds of approximately $88 million. The Preferred Stock is redeemable at Enron's option after December 1999 at a price of $100,000 per share plus accumulated and unpaid dividends.
During August 1994, Enron Capital Resources, L.P., a Delaware limited partnership in which Enron is the sole general partner, issued 3 million shares of 9% Cumulative Preferred Securities, Series A, at a price to the public of $25 per share with net proceeds of approximately $73 million.
During November 1993, Enron's wholly-owned subsidiary Enron Capital LLC issued 8.55 million shares of 8% Cumulative Guaranteed Monthly Income Preferred Shares (MIPS) at a price of $25 per share with net proceeds of approximately $207 million.
The Series A Preferred Securities and the MIPS are redeemable at the option of Enron in whole or in part beginning August 31, 1999 and November 30, 1998, respectively, at a redemption price of $25 per share plus accumulated and unpaid dividends. The liquidation preference of each of the Series A Preferred Securities and the MIPS is $25 per share.
10 Common Stock and Dividends
On July 28, 1993, Enron increased the number of authorized shares of common stock from 300,000,000 to 600,000,000 shares and decreased the par value of such common stock from $10.00 to $0.10 per share. The reduced par value of $9.90 for each share outstanding, or $1.18 billion, was transferred to additional paid-in capital. On August 16, 1993, Enron effected, in the form of a stock dividend, a two-for-one common stock split on all issued common stock. The par value of $11.9 million for 119,486,623 additional shares was transferred from additional paid-in capital to common stock. Appropriate references in the financial statements and supplemental financial information to number of shares and related prices, per share amounts and stock option information reflect the stock split.
Enron paid quarterly cash dividends on common stock of $.1625 per share ($.65 per share annually) until the final quarter of 1992. The dividend was increased to $.175 per share ($.70 per share annually) for the final quarter of 1992 and was increased to $.1875 per share ($.75 per share annually) for the final quarter of 1993. The dividend was further increased to $.20 per share ($.80 per share annually) for the final quarter of 1994. Enron's debt agreements do not limit the payment of cash dividends on common stock. Common stock information is as follows:
Treasury stock information is as follows:
Enron has various stock plans (the Plans) under which options for shares of Enron's common stock have been or may be granted to officers, employees and non-employee members of the Board of Directors. Under the Plans, options granted may be either incentive stock options or nonqualified stock options and are granted at not less than the fair market value of the stock at the time of grant. Expiration dates of the options outstanding at December 31, 1994 range from July 8, 1995 to December 30, 2004. The Plans provide for options to be granted with stock appreciation rights (SAR); however, Enron does not presently intend to issue additional options with an SAR feature. Summarized information for the Plans is as follows:
Under the Plans, participants may be granted stock without cost to the participant (restricted stock). The shares issued under the Plans vest to the participants at various times ranging from immediate vesting to vesting at the end of a five year period. The following is an analysis of shares of restricted stock:
Flexible Equity Trust (the Trust). In December 1993, Enron established the Trust to fund a portion of its obligations arising from its various employee compensation and benefit plans. Enron issued 7.5 million shares of common stock to the Trust in exchange for cash and an interest bearing promissory note. The note held by Enron is reflected as a reduction of shareholders' equity. Common shares held by the Trust are not included in the computation of earnings per share until such shares are released to fund employee benefits. No such shares were released at December 31, 1994.
11 Retirement Benefits Plan and ESOP
Enron maintains a retirement plan (the Enron Plan) which is a noncontributory defined benefit plan covering substantially all employees in the United States and certain employees in foreign countries. Through December 31, 1994, participants in the Enron Plan with five years or more of service are entitled to retirement benefits based on a formula that uses a percentage of final average pay and years of service.
In connection with a contemplated change to the retirement benefit formula, Enron amended the Enron Plan providing, among other things, that all employees become fully vested in retirement benefits earned through December 31, 1994. The contemplated change to the benefit formula is not expected to have a material effect on Enron's projected benefit obligation.
Enron also maintains a noncontributory employee stock ownership plan (ESOP) which covers all eligible employees. Allocations to individual employees' retirement accounts within the ESOP offset a portion of benefits earned under the Enron Plan. To the extent allocations to the individual employees retirement account within the ESOP exceed accrued benefits under the Enron Plan at the date of retirement, the individual employees receive the additional shares.
The components of pension expense are as follows:
The valuation date of the Enron Plan and the ESOP is September 30. The funded status as of the valuation date of the Enron Plan and the ESOP reconciles with the amount detailed below which is included in "Other Assets" on the Consolidated Balance Sheet. Assets of the ESOP offset retirement benefits accrued under the Enron Plan only to the extent allocated to individual employee retirement accounts.
Assets of the Enron Plan are comprised primarily of equity securities, fixed income securities and temporary cash investments. It is Enron's policy to fund all pension costs accrued to the minimum amount required by Federal tax regulations.
12 Benefits Other Than Pensions
Enron provides certain medical, life insurance and dental benefits to eligible employees who retire under the Enron Retirement Plan and their eligible surviving spouses. Benefits are provided under the provisions of a contributory defined dollar benefit plan. Enron is currently funding that portion of its obligations under its postretirement benefit plan which is expected to be recoverable through rates by its regulated pipelines.
Enron accrues these postretirement benefit costs over the service lives of the employees expected to be eligible to receive such benefits. Enron is amortizing the transition obligation which existed at January 1, 1993 over a period of approximately 19 years.
The following table sets forth the plan's funded status reconciled with the amounts reported in the Consolidated Balance Sheet.
The components of net periodic postretirement benefit expenses are as follows:
The measurement of the APBO assumes an 8% discount rate and a health care cost trend rate of 12.3% in 1994 decreasing to 5% by the year 2006 and beyond. A 1% increase in the health care cost trend rate would have the effect of increasing the APBO and the net periodic expense by approximately $7.9 million and $0.8 million, respectively.
Effective January 1, 1994, Enron adopted the provisions of SFAS 112 - "Employers' Accounting for Postemployment Benefits." The effects of adopting SFAS 112 were not material.
13 Natural Gas Rates and Regulatory Issues
Regulatory issues and rates on Enron's regulated pipelines are subject to final determination by the FERC. Enron's regulated pipelines currently apply accounting standards that recognize the economic effects of regulation and, accordingly, have recorded regulatory assets and liabilities related to their operations. Enron evaluates the applicability of regulatory accounting and the recoverability of these assets through rate or other contractual mechanisms on an ongoing basis. Net regulatory assets at December 31, 1994 are approximately $305 million, which include transition costs incurred related to FERC Order 636 of approximately $158 million. Such regulatory assets are scheduled to be recovered from customers over varying time periods, generally up to five years.
Enron's regulated pipelines have all successfully completed their transitions under FERC Order 636 although future transition costs may be incurred subject to ongoing negotiations and market factors. Enron believes, based upon its experience to date and after considering appropriate reserves that have been established, that the ultimate resolution of pending regulatory matters will not have a material impact on Enron's financial position or results of operations.
14 Litigation and Other Contingencies
Enron is party to various claims and litigation, the significant items of which are discussed below. Although no assurances can be given, Enron believes, based on its experience to date and after considering appropriate reserves that have been established, that the ultimate resolution of such items, individually or in the aggregate, will not have a materially adverse impact on Enron's financial position or results of operations.
Litigation TransAmerican Natural Gas Corporation (TransAmerican) has filed a suit against Enron Corp. and EOG alleging breach of confidentiality agreements, misappropriation of trade secrets and unfair competition, with specific reference to four tracts in Webb County, Texas, which EOG leased for their oil and gas exploration and development potential. TransAmerican seeks actual damages of $100 million and exemplary damages of $300 million. EOG has filed claims against TransAmerican and its sole shareholder alleging common law fraud, negligent misrepresentation and breach of state antitrust laws. On April 6, 1994, Enron Corp. was granted summary judgment, wherein the court ordered that TransAmerican take nothing on its claims against Enron Corp. As to EOG, the trial date, which was most recently set for September 12, 1994, has been continued and there is no current setting. Although no assurances can be given, Enron believes that TransAmerican's claims are without merit. Enron believes that the ultimate resolution of this matter will not have a materially adverse effect on its financial position or results of operations.
A pipeline company in which an Enron affiliate has a minority interest and for which an Enron affiliate has served as operator, has filed a petition against Enron and certain affiliates alleging an unspecified amount of damages relating to the operation of such pipeline company. Based upon information currently available, it is not possible to predict the outcome of such litigation; however, Enron believes that the results will not have a materially adverse effect on Enron's financial position or results of operations.
Environmental Matters Enron is subject to extensive Federal, state and local environmental laws and regulations. These laws and regulations require expenditures in connection with the construction of new facilities, the operation of existing facilities and for remediation at various operating sites. The implementation of the Clean Air Act Amendments is expected to result in increased operating expenses. These increased operating expenses are not expected to have a material impact on Enron's financial position or results of operations.
In addition, Enron received requests for information from the Environmental Protection Agency (EPA) and state environmental agencies inquiring whether Enron has disposed of materials at certain waste disposal sites. Enron has received notices from EPA and state agencies that it is a "potentially responsible party" (PRP) under the Comprehensive Environmental Response, Compensation and Liability Act and analogous state statutes, and may be required to share in the costs of the cleanup of other, similar sites. However, Enron believes that any potential assessments in connection with these PRP notices and third party claims, either taken individually or in the aggregate, will not have a material impact on Enron's financial position or results of operations.
Other During October 1994, an explosion occurred at Enron's methanol plant in Pasadena, Texas. The plant produces approximately 420,000 gallons of methanol per day, approximately half of which is used at Enron's MTBE plant. Enron is currently investigating the explosion to determine the full extent of any damages; however, based upon business interruption and casualty insurance coverages, Enron currently anticipates that the explosion will not have a material adverse effect on its financial position or results of operations.
15 Commitments
Firm Transportation Obligations Enron has firm transportation agreements with various joint venture pipelines. Under these agreements, Enron must make specified minimum payments each month. The estimated aggregate amounts of such required future payments at December 31, 1994, were:
The costs incurred under these agreements, including commodity charges on actual quantities shipped, totaled $20.8 million, $42.4 million and $45.1 million in 1994, 1993 and 1992, respectively. Enron has assigned a firm transportation contract with one of its joint ventures to a third party and guaranteed minimum payments under the contract averaging approximately $43.6 million annually through 2001.
Other Commitments Enron leases property, operating facilities and equipment under various operating leases, certain of which contain renewal and purchase options and residual value guarantees. Guarantees under the leases total $1.03 billion at December 31, 1994.
During November 1994, Enron modified its prior agreement for a substantial amount of data processing facilities management services. The modification reduces the aggregate and required annual minimum services to be purchased by Enron. Enron prepaid $150 million in 1992 and $40 million in early 1995 for certain services to be performed under the terms of the agreement.
Future commitments related to these items at December 31, 1994 are as follows:
Total rent expense incurred during 1994, 1993 and 1992 was $125.6 million, $103.7 million and $64.7 million, respectively.
Enron guarantees certain long-term contracts for the sale of electrical power and steam from a cogeneration facility owned by one of Enron's equity investees. Under terms of the contracts, which initially extend through June 1999, Enron could be liable for penalties should, under certain conditions, the contracts be terminated early. Enron also guarantees the performance of certain of its unconsolidated subsidiaries in connection with letters of credit issued on behalf of those unconsolidated subsidiaries. At December 31, 1994, a total of $118.6 million of such guarantees were outstanding. In addition, Enron is a guarantor on certain debt of unconsolidated joint ventures and unconsolidated subsidiaries and other companies totaling approximately $267.9 million. The fair value of guarantees at December 31, 1994 and 1993, based upon Enron's estimation of the cost of securing third party letters of credit equal to Enron's obligations under such guarantees, was $2.4 million and $2.7 million, respectively. Management does not consider it likely that they would be required to perform or otherwise incur any losses associated with these guarantees. In addition, certain commitments have been made related to 1995 planned capital expenditures.
16 Other Income, Net
The components of Other Income, Net are as follows:
17 Geographic and business Segment Information
Enron's operations are classified into four business segments:
Transportation and Operation - Interstate transmission of natural gas. Construction, management and operation of pipelines, liquids, clean fuel plants and power facilities. Investment in crude oil transportation activities and liquids pipeline operations.
Domestic Gas and Power Services - Purchasing, marketing and financing of natural gas, natural gas liquids and power. Price risk management in connection with natural gas, natural gas liquids and power transactions. Intrastate natural gas pipelines. Development, acquisition and promotion of natural gas fired power plants in North America. Extraction of natural gas liquids.
International Gas and Power Services - Independent (non-utility) development, acquisition and promotion of natural gas fired power plants, natural gas liquids facilities and pipelines outside of North America. International marketing of natural gas liquids.
Exploration and Production - Natural gas and crude oil exploration and production primarily in the United States, Canada, Trinidad and India.
Financial information by geographic and business segment for each of the three years in the period ended December 31, 1994, follows.
Geographic Segments
Operations In Business and Geographic Segments Business Segments
18 Oil and Gas Producing Activities (Unaudited except for Results of Operations for Oil and Gas Producing Activities)
The following information regarding Enron's oil and gas producing activities should be read in conjunction with Note 1.
Capitalized Costs Relating to Oil and Gas Producing Activities
Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities(a)
Results of Operations for Oil and Gas Producing Activities(a)
The following tables set forth results of operations for oil and gas producing activities for the three years in the period ended December 31, 1994:
Oil and Gas Reserve Information
The following summarizes the policies used by Enron in preparing the accompanying oil and gas supplemental reserve disclosures, Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves and reconciliation of such standardized measure from period to period.
Estimates of proved and proved developed reserves at December 31, 1994, 1993 and 1992 were based on studies performed by Enron's engineering staff for reserves in the United States, Canada, Trinidad and India. Opinions by DeGolyer and MacNaughton, independent petroleum consultants, for the years ended December 31, 1994, 1993 and 1992 covering producing areas, in the United States and Canada, containing 59%, 65% and 69%, respectively, of proved reserves of Enron on a net-equivalent-cubic-feet- of-gas basis, indicate that the estimates of proved reserves prepared by Enron's engineering staff for the properties reviewed by DeGolyer and MacNaughton, when compared in total on a net-equivalent-cubic-feet-of-gas basis, do not differ by more than 5% from those prepared by DeGolyer and MacNaughton's engineering staff. All reports by DeGolyer and MacNaughton were developed utilizing geological and engineering data provided by Enron.
The standardized measure of discounted future net cash flows does not purport, nor should it be interpreted, to present the fair market value of Enron's crude oil and natural gas reserves. An estimate of fair value would also take into account, among other things, the recovery of reserves not presently classified as proved reserves, anticipated future changes in prices and costs and a discount factor more representative of the time value of money and the risks inherent in reserve estimates.
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves(a)
Changes in Standardized Measure of Discounted Future Net Cash Flows
Reserve Quantity Information
Enrons estimates of proved developed and net proved reserves of crude oil, condensate, natural gas liquids and natural gas and of changes in net proved reserves were as follows:
Enron Corp. and Subsidiaries Supplemental Financial Information (UNAUDITED)
Quarterly Results
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS ON FINANCIAL STATEMENT SCHEDULE
To Enron Corp.:
We have audited in accordance with generally accepted auditing standards, the consolidated financial statements included in this Form 10-K, and have issued our report thereon dated February 17, 1995. Our audits were made for the purpose of forming an opinion on the basic financial statements taken as a whole. The schedule listed in Item 14(a)2 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 audit 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.
ARTHUR ANDERSEN LLP
Houston, Texas February 17, 1995
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized, on this 29th day of March, 1995.
ENRON CORP. (Registrant)
By: JACK I. TOMPKINS (Jack I. Tompkins) Senior Vice President and Chief Information, Administrative and Accounting Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been signed below on March 29, 1995 by the following persons on behalf of the Registrant and in the capacities indicated.
Signature Title
KENNETH L. LAY Chairman of the Board, Chief (Kenneth L. Lay) Executive Officer and Director (Principal Executive Officer)
JACK I. TOMPKINS Senior Vice President and (Jack I. Tompkins) Chief Information, Administrative and Accounting Officer (Principal Accounting Officer)
KURT S. HUNEKE Vice President, Finance and (Kurt S. Huneke) Treasurer (Principal Financial Officer)
ROBERT A. BELFER* Director (Robert A. Belfer)
NORMAN P. BLAKE, JR.* Director (Norman P. Blake, Jr.)
JOHN H. DUNCAN* Director (John H. Duncan)
JOE H. FOY* Director (Joe H. Foy)
WENDY L. GRAMM* Director (Wendy L. Gramm)
ROBERT K. JAEDICKE* Director (Robert K. Jaedicke)
RICHARD D. KINDER* Director and President and (Richard D. Kinder) Chief Operating Officer
CHARLES A. LEMAISTRE* Director (Charles A. LeMaistre)
JOHN A. URQUHART* Director (John A. Urquhart)
JOHN WAKEHAM* Director (John Wakeham)
CHARLS E. WALKER* Director (Charls E. Walker)
HERBERT S. WINOKUR, JR.* Director (Herbert S. Winokur, Jr.)
*By: PEGGY B. MENCHACA (Peggy B. Menchaca) (Attorney-in-fact for persons indicated)
EXHIBIT INDEX
Exhibit Number Description
3.01 - Restated Certificate of Incorporation of Enron Corp., as amended.
*3.02 - Bylaws of Enron Corp. as currently in effect (Exhibit 3.02 to Enron Form 10-K for 1990, File No. 1-3423).
*4.01 - Indenture dated as of November 1, 1985, between Enron and Harris Trust and Savings Bank (Form T-3 Application for Qualification of Indentures under the Trust Indenture Act of 1939, File No. 22- 14390, filed October 24, 1985). There have not been filed as exhibits to this Form 10-K other debt instruments defining the rights of holders of long-term debt of Enron, none of which relates to authorized indebtedness that exceeds 10% of the consolidated assets of Enron and its subsidiaries. Enron hereby agrees to furnish a copy of any such instrument to the Commission upon request.
*4.02 - Form of Amended and Restated Agreement of Limited Partnership of Enron Capital Resources, L.P. (Exhibit 3.1 to Enron Form 8-K dated August 2, 1994).
*4.03 - Form of Payment and Guarantee Agreement dated as of August 3, 1994, executed by Enron Corp. for the benefit of the holders of Enron Capital Resources, L.P. 9% Cumulative Preferred Securities, Series A (Exhibit 4.1 to Enron Form 8-K dated August 2, 1994).
*4.04 - Form of Loan Agreement, dated as of August 3, 1994, between Enron Corp. and Enron Capital Resources, L.P. (Exhibit 4.2 to Enron Form 8-K dated August 2, 1994).
*4.05 - Articles of Association of Enron Capital LLC (Exhibit 9 to Enron Corp. Form 8-K dated November 12, 1993).
*4.06 - Form of Payment and Guarantee Agreement of Enron Corp., dated as of November 15, 1993, in favor of the holders of Enron Capital LLC 8% Cumulative Guaranteed Monthly Income Preferred Shares (Exhibit 2 to Enron Form 8-K dated November 12, 1993).
*4.07 - Form of Loan Agreement, dated as of November 15, 1993, between Enron Corp. and Enron Capital LLC (Exhibit 3 to Enron Form 8-K dated November 12, 1993).
Executive Compensation Plans and Arrangements Filed as Exhibits Pursuant to Item 14(c) of Form 10-K: Exhibits 10.01 through 10.59
*10.01 - Enron Executive Supplemental Survivor Benefits Plan, effective January 1, 1987 (Exhibit 10.01 to Enron Form 10-K for 1992, File No. 1-3423).
*10.02 - Enron Corp. 1988 Stock Plan (Exhibit 4.3 to Registration Statement No. 33-27893).
*10.04 - Enron Corp. 1986 Stock Option Plan with Stock Appreciation Rights (Exhibit 4.3 to Registration Statement No. 33-13498).
*10.05 - Executive Incentive Plan (Exhibit 10.13 to Enron Form 10-K for 1987, File No. 1-3423).
*10.06 - Enron Corp. 1988 Deferral Plan (Exhibit 10.19 to Enron Form 10-K for 1987, File No. 1-3423).
*10.07 - Enron Corp. 1991 Stock Plan (Exhibit 10.08 to Enron Form 10-K for 1991, File No. 1-3423).
*10.08 - Enron Corp. 1992 Deferral Plan (Exhibit 10.09 to Enron Form 10-K for 1991, File No. 1-3423).
*10.09 - Enron Corp. Directors' Deferred Income Plan (Exhibit 10.09 to Enron Form 10-K for 1992, File No. 1-3423).
*10.10 - Employment Agreement between Enron and Kenneth L. Lay dated as of September 1, 1989 (Exhibit 10.12 to Enron Form 10-K for 1989, File No. 1-3423).
*10.11 - First Amendment to Employment Agreement between Enron and Kenneth L. Lay, dated August 21, 1990 (Exhibit 10.11 to Enron Form 10-K for 1993).
*10.12 - Second Amendment to Employment Agreement between Enron and Kenneth L. Lay, dated March 5, 1992 (Exhibit 10.12 to Enron Form 10-K for 1993).
*10.13 - Third Amendment to Employment Agreement between Enron and Kenneth L. Lay, dated August 10, 1993 (Exhibit 10.13 to Enron Form 10-K for 1993).
*10.14 - Fourth Amendment to Employment Agreement between Enron and Kenneth L. Lay, dated October 15, 1993 (Exhibit 10.14 to Enron Form 10-K for 1993).
*10.15 - Fifth Amendment to Employment Agreement between Enron and Kenneth L. Lay, dated February 28, 1994 (Exhibit 10.15 to Enron Form 10-K for 1993).
10.16 - Sixth Amendment to Employment Agreement between Enron and Kenneth L. Lay, dated April 27, 1994.
10.17 - Split Dollar Life Insurance Agreement between Enron and the KLL and LPL Family Partnership, Ltd., dated April 22, 1994.
*10.18 - Employment Agreement between Enron and Richard D. Kinder dated as of September 1, 1989 (Exhibit 10.14 to Enron Form 10-K for 1989, File No. 1- 3423).
*10.19 - First Amendment to Employment Agreement between Enron and Richard D. Kinder dated August 13, 1990 (Exhibit 10.17 to Enron Form 10-K for 1991, File No. 1-3423).
*10.20 - Second Amendment to Employment Agreement between Enron and Richard D. Kinder dated September 10, 1991 (Exhibit 10.18 to Enron Form 10-K for 1991, File No. 1-3423).
*10.21 - Third Amendment to Employment Agreement between Enron and Richard D. Kinder dated March 5, 1992 (Exhibit 10.19 to Enron Form 10-K for 1992, File No. 1-3423).
*10.22 - Fourth Amendment to Employment Agreement between Enron and Richard D. Kinder dated August 16, 1993 (Exhibit 10.20 to Enron Form 10-K for 1993).
*10.23 - Fifth Amendment to Employment Agreement between Enron and Richard D. Kinder, dated October 15, 1993 (Exhibit 10.21 to Enron Form 10-K for 1993).
*10.24 - Sixth Amendment to Employment Agreement between Enron and Richard D. Kinder, dated February 28, 1994 (Exhibit 10.22 to Enron Form 10-K for 1993).
10.25 - Seventh Amendment to Employment Agreement between Enron and Richard D. Kinder, dated November 30, 1994.
*10.26 - Employment Agreement between Enron International Inc. and Rodney L. Gray, dated as of July 1, 1993 (Exhibit 10.23 to Enron Form 10-K for 1993).
10.27 - First Amendment to Employment Agreement between Enron International Inc. and Rodney L. Gray, dated May 2, 1994.
*10.28 - Employment Agreement between Enron and Ronald J. Burns dated as of July 1, 1989 (Exhibit 10.15 to Enron Form 10-K for 1989, File No. 1-3423).
*10.29 - First Amendment to Employment Agreement between Enron and Ronald J. Burns dated June 21, 1990 (Exhibit 10.20 to Enron Form 10-K for 1991, File No. 1-3423).
*10.30 - Second Amendment to Employment Agreement between Enron and Ronald J. Burns dated August 19, 1991 (Exhibit 10.21 to Enron Form 10-K for 1991, File No. 1-3423).
10.31 - Third Amendment to Employment Agreement between Enron and Ronald J. Burns, dated May 2, 1994.
*10.32 - Employment Agreement between Enron and Jack I. Tompkins dated October 1, 1991 (Exhibit 10.22 to Enron Form 10-K for 1991, File No. 1-3423).
10.33 - First Amendment to Employment Agreement between Enron and Jack I. Tompkins, dated May 2, 1994.
*10.34 - Consulting Services Agreement between Enron and John A. Urquhart dated August 1, 1991 (Exhibit 10.23 to Enron Form 10-K for 1991, File No. 1- 3423).
*10.35 - First Amendment to Consulting Services Agreement between Enron and John A. Urquhart, dated August 27, 1992 (Exhibit 10.25 to Enron Form 10-K for 1992, File No. 1-3423).
*10.36 - Second and Third Amendments to Consulting Services Agreement between Enron and John A. Urquhart, dated November 24, 1992 and February 26, 1993, respectively (Exhibit 10.26 to Enron Form 10-K for 1992, File No. 1-3423).
*10.37 - Employment Agreement between Enron and Edmund P. Segner, III dated October 1, 1991 (Exhibit 10.24 to Enron Form 10-K for 1991, File No. 1-3423).
*10.38 - First Amendment to Employment Agreement between Enron and Edmund P. Segner, III dated February 12, 1993 (Exhibit 10.28 to Enron Form 10-K for 1992, File No. 1-3423).
10.39 - Second Amendment to Employment Agreement between Enron and Edmund P. Segner, III, dated May 2, 1994.
*10.40 - Employment Agreement between Enron and Jeffrey K. Skilling, effective August 1, 1990 (Exhibit 10.18 to Enron Form 10-K for 1990, File No. 1-3423).
*10.41 - First Amendment to Employment Agreement between Enron and Jeffrey K. Skilling, dated August 1, 1990 (Exhibit 10.30 to Enron Form 10-K for 1992, File No. 1-3423).
*10.42 - Second Amendment to Employment Agreement between Enron and Jeffrey K. Skilling, dated June 1, 1991 (Exhibit 10.31 to Enron Form 10-K for 1992, File No. 1-3423).
*10.43 - Third Amendment to Employment Agreement between Enron and Jeffrey K. Skilling, dated February 10, 1992 (Exhibit 10.32 to Enron Form 10-K for 1992, File No. 1-3423).
*10.44 - Loan Commitment Agreement between Enron and Jeffrey K. Skilling, dated April 13, 1992 (Exhibit 10.33 to Enron Form 10-K for 1992, File No. 1- 3423).
*10.45 - Fourth Amendment to Employment Agreement between Enron and Jeffrey K. Skilling, dated June 23, 1992 (Exhibit 10.34 to Enron Form 10-K for 1992, File No. 1-3423).
*10.46 - Fifth Amendment to Employment Agreement between Enron and Jeffrey K. Skilling, dated December 18, 1992 (Exhibit 10.35 to Enron Form 10-K for 1992, File No. 1-3423).
*10.47 - Buyout Agreement between Enron and Jeffrey K. Skilling, dated December 18, 1992 (Exhibit 10.36 to Enron Form 10-K for 1992, File No. 1-3423).
*10.48 - First Amendment to Buyout Agreement between Enron and Jeffrey K. Skilling, dated December 23, 1992 (Exhibit 10.37 to Enron Form 10-K for 1992, File No. 1-3423).
*10.49 - Loan Agreement between Enron and Jeffrey K. Skilling, dated January 1, 1993 (Exhibit 10.38 to Enron Form 10-K for 1992, File No. 1-3423).
*10.50 - Employment Agreement among Enron Corp., Enron Power Corp., and Thomas E. White, dated December 9, 1992 (Exhibit 10.39 to Enron Form 10-K for 1992, File No. 1-3423).
10.51 - Second Amendment to Employment Agreement between Enron Corp., Enron Power Corp., and Tom White, dated May 2, 1994.
*10.52 - Employment Agreement between Enron and James V. Derrick, Jr., dated June 11, 1991 (Exhibit 10.40 to Enron Form 10-K for 1992, File No. 1-3423).
10.53 - First Amendment to Employment Agreement between Enron and James V. Derrick, Jr., dated May 2, 1994.
*10.54 - Enron Gas Services Group Phantom Equity Plan (Exhibit 10.26 to Enron Form 10-K for 1991, File No. 1-3423).
*10.55 - Enron Power Corp. Executive Compensation Plan (Exhibit 10.42 to Enron Form 10-K for 1992, File No. 1-3423).
*10.56 - Enron Corp. Performance Unit Plan (Exhibit A to Enron Proxy Statement filed pursuant to Section 14(a) on March 25, 1994).
*10.57 - Enron Corp. Annual Incentive Plan (Exhibit B to Enron Proxy Statement filed pursuant to Section 14(a) on March 25, 1994).
*10.58 - Enron Corp. Performance Unit Plan (as amended and Restated effective May 2, 1995) (Exhibit A to Enron Proxy Statement filed pursuant to Section 14(a) on March 27, 1995).
10.59 - Form of Enron Corp. 1994 Deferral Plan.
11 - Statement re calculation of earnings per share.
12 - Statement re computation of ratios of earnings to fixed charges.
21 - Subsidiaries of registrant.
23.01 - Consent of Arthur Andersen LLP.
23.02 - Consent of DeGolyer and MacNaughton.
23.03 - Letter Report of DeGolyer and MacNaughton dated January 13, 1995.
24 - Powers of Attorney for the officers and directors signing this Form 10-K.
27 - Financial Data Schedule.
* Asterisk indicates exhibits incorporated by reference as indicated; all other exhibits are filed herewith.