Item 1. BUSINESS GENERAL
Enron Corp., an Oregon corporation, is an integrated natural gas and electricity company with headquarters in Houston, Texas. Enron's operations are conducted through its subsidiaries and affiliates which are principally engaged in the exploration for and production of natural gas and crude oil in the United States and internationally; the transportation of natural gas through pipelines to markets throughout the United States; the generation and transmission of electricity to markets in the northwestern United States; the marketing of natural gas, electricity and other commodities and related risk management and finance services worldwide; and the development, construction and operation of power plants, pipelines and other energy related assets in international markets. As of December 31, 1997, Enron employed approximately 15,500 persons.
Effective July 1, 1997, Enron merged with Portland General Corporation ("PGC") in a stock-for-stock transaction. PGC, through its wholly-owned subsidiary Portland General Electric Company ("PGE"), serves retail electric customers in northwest Oregon as well as wholesale electricity customers throughout the western United States. Pursuant to the merger, Enron Corp., a Delaware corporation organized in 1930, reincorporated in Oregon.
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 business segments:
Exploration and Production - Natural gas and crude oil exploration and production primarily in the United States, Canada, Trinidad and India.
Transportation and Distribution - Interstate transmission of natural gas; management and operation of pipelines; electric utility operations.
Wholesale Energy Operations and Services - Energy commodity sales and services, risk management products and financial services to wholesale customers; development, acquisition and operation of power plants, natural gas pipelines and other energy related assets.
Retail Energy Services - Sale of natural gas and electricity directly to end-use customers, particularly in the commercial and light industrial sectors.
Corporate and Other - Includes operation of renewable energy businesses and methanol and MTBE plants, as well as Enron's investment in crude oil transportation activities.
Enron's business segment information has been reclassified from prior years to reflect the realignment of Enron's operations.
For financial information by business segment for the fiscal years ended December 31, 1995 through December 31, 1997, please see Note 17 to the Consolidated Financial Statements on page.
EXPLORATION AND PRODUCTION
Enron's natural gas and crude oil exploration and production operations are conducted by Enron Oil & Gas Company ("EOG"). Enron currently owns approximately 55% 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 and India. At December 31, 1997, EOG's estimated net proved natural gas reserves were 4,001 billion cubic feet ("Bcf"), and estimated net proved crude oil, condensate and natural gas liquids reserves were 78 million barrels, and at such date, approximately 67% of EOG's reserves (on a natural gas equivalent basis) were located in the United States, 10% in Canada, 8% in Trinidad and 15% in India.
EOG's eight principal U.S. producing areas are the Big Piney area in Wyoming, the South Texas area, the East Texas area, the offshore Gulf of Mexico area, the Canyon/Strawn Trend area in West Texas, the Sand Tank and Pitchfork Ranch areas in New Mexico, and the Vernal area in Utah. Properties in these areas comprised approximately 82% of EOG's U.S. reserves (on a natural gas equivalent basis) and 79% of EOG's U.S. net natural gas deliverability as of December 31, 1997. These properties are substantially all operated by EOG. EOG's other U.S. natural gas and crude oil producing properties are located primarily in other areas of Texas, Utah, New Mexico, Oklahoma, California, Mississippi and Kansas. At December 31, 1997, 94% of EOG's proved U.S. reserves (on a natural gas equivalent basis) were natural gas and 6% were crude oil, condensate and natural gas liquids. EOG's reserves include 1,180 Bcf of proved undeveloped methane reserves in the deep Paleozoic formations of the Big Piney area of Wyoming.
EOG is also engaged in the exploration for and the development, production and marketing 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 its Canadian operations from offices in Calgary. At December 31, 1997, Canadian natural gas deliverability net to EOG was approximately 100 million cubic feet ("MMcf") per day, and EOG held approximately 490,000 net undeveloped acres in Canada.
EOG also has producing operations offshore Trinidad and India and is conducting exploration in selected other international areas. Properties offshore Trinidad and India comprised almost all of EOG's proved reserves and production outside of North America at year-end 1997.
In November 1992, EOG was awarded a 95% working interest concession and operatorship in the South East Coast Consortium ("SECC") Block offshore Trinidad, encompassing three undeveloped fields, previously held by three government-owned energy companies. The Kiskadee field has been developed, the Ibis field is under development, and the Oil Bird field is anticipated to be developed over the next several years. Existing surplus processing and transportation capacity at the Pelican field facilities owned and operated by Trinidad and Tobago government-owned companies is being used to process and transport the production. Natural gas is being sold into the local market under a take-or-pay agreement with the National Gas Company of Trinidad and Tobago. In 1997, deliveries net to EOG averaged 113 MMcf per day of natural gas and 3.4 thousand barrels ("MBbl") per day of crude oil and condensate. At December 31, 1997, EOG held approximately 168,000 net undeveloped acres in Trinidad.
In 1995, EOG was awarded the right to develop the modified U(a) block adjacent to the SECC Block, and a production sharing contract with the Government of Trinidad and Tobago was signed in 1996. A 3-D seismic data gathering project has been completed and is being evaluated. Initial drilling is expected to commence in 1998.
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 the western coast of India. The blocks were previously operated by the Indian national oil company, Oil & Natural Gas Corporation Limited, which retained a 40% working interest. The 363,000 acre Tapti Block contains two major proved natural gas accumulations delineated by 22 expendable exploration wells that have been plugged. EOG has implemented a development plan for the Tapti Block accumulations, and production began in 1997. At December 31, 1997, production, net to EOG, from the Tapti Block was 48 MMcf per day. The 106,000 acre Panna Block and the 192,000 acre Mukta Block are partially developed with 29 wells producing from six production platforms located in the Panna and Mukta fields. The fields were producing approximately 4.3 MBbl per day of crude oil net to EOG as of December 31, 1997. Natural gas sales from the Panna field began in early 1998. EOG intends to continue development of the fields.
EOG was awarded exploration, exploitation and development rights for a block offshore the eastern State of Sucre, Venezuela in early 1996. EOG has signed agreements with the government of Venezuela and other participants associated with a concession awarded in the Gulf of Paria East. EOG holds an initial 90% working interest in the joint venture. A 3-D seismic data project is currently underway, and drilling is anticipated to begin in 1998.
In August 1997, EOG signed a 30-year production sharing contract with the China National Petroleum Corporation for the appraisal and potential development of oil and gas reserves within the Chuanzhong Block situated in the central Sichuan Province. EOG holds a 100% interest in the fields and is the operator. The contract provides for a two-year evaluation period during which EOG will perform work to improve productivity in existing wells and will drill three new wells in the areas of proven production. Further commitments, if any, would arise from entering into the development period as specified in the contract.
EOG continues to evaluate other selected natural gas and crude oil opportunities outside North America. EOG is also pursuing other opportunities in countries where natural gas and crude oil reserves have been identified, particularly where synergies in natural gas transportation, processing and power generation can be optimized with other Enron Corp. affiliated companies. In early 1995, EOG, an Enron affiliate and the Qatar General Petroleum Corporation signed a nonbinding letter of intent concerning the possible development of a liquefied natural gas project for natural gas to be produced from a block within the North Dome Field. EOG and the Enron affiliate may jointly hold up to a 35% equity interest in the project. EOG has also entered into a Memorandum of Understanding with Uzbekneftigaz covering the pursuit of joint development and marketing opportunities for proven hydrocarbon reserves in eleven fields in the Surhandarya and Bukhara regions of Uzbekistan. EOG is also participating in discussions concerning the potential for natural gas development opportunities in Mozambique, as well as other opportunities in Trinidad, India, Venezuela and Bangladesh.
EOG actively competes for reserve acquisitions and exploration leases, licenses and concessions, frequently against companies with substantially larger financial and other resources. EOG's ability to compete effectively for certain reserves, leases, licenses and concessions is, in part, dependent on EOG's exploration budget relative to its competitors. 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 competition from other world-wide energy supplies, such as natural gas from Canada.
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, 1997:
TRANSPORTATION AND DISTRIBUTION
Enron's Transportation and Distribution business is comprised of the company's North American interstate natural gas transportation systems and its electricity transmission and distribution operations in Oregon.
Interstate Transmission of Natural Gas
Enron and its subsidiaries operate domestic interstate natural gas 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 ("Florida Gas") (indirectly 50% owned by Enron). Northern, Transwestern and Florida Gas 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; Transwestern, principally the California market and pipeline interconnects on the east end of the Transwestern system; and Florida Gas, the State of Florida. In addition, Enron holds an 11.8% 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.
Northern Natural Gas Company. Through its approximately 17,000-mile natural gas pipeline system stretching from Texas to Michigan's Upper Peninsula, Northern transports natural 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 gas marketers. Northern also transports gas at various points outside its traditional market area in the production areas of Colorado, Kansas, 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 1,593 trillion British thermal units ("Tbtu") in 1997, compared to 1,675 Tbtu in 1996. This slight decrease was due primarily to (i) colder weather in 1996 than in 1997, and (ii) better price spreads in 1996 that resulted in more discretionary shippers using Northern.
In 1997, Northern maintained its existing customer base in an increasingly competitive market while initiating expansion projects to meet increased market demand and to increase Northern's market presence. Northern completed the first phase of a five-year, $113 million growth plan to expand incremental firm capacity into Iowa, Wisconsin and Minnesota by approximately 350 MMcf of natural gas per day. This expansion is fully subscribed with five-year to ten- year firm transportation contracts. In addition, Northern has an expansion of approximately 60 MMcf per day underway which is expected to be in service in late 1998.
Northern competes with other interstate pipelines in the transportation and storage of natural gas. In recent years, the FERC has issued orders designed to introduce more competition into the natural gas industry, having the effect of increasing transportation volumes and decreasing or eliminating sales of natural gas by pipelines. See "Regulation - Natural Gas Rates and Regulations".
Transwestern Pipeline Company. Transwestern is an interstate pipeline engaged in the transportation of natural gas. Through its approximately 2,700-mile pipeline system, Transwestern transports natural gas from West Texas, Oklahoma, eastern New Mexico and the San Juan Basin in northwestern New Mexico and southern Colorado primarily to the California market and to pipeline interconnects off the east end of its system. Transwestern has access to three significant gas basins for its gas supply: the San Juan Basin, the Permian Basin in West Texas and eastern New Mexico and the Anadarko Basin in the Texas and Oklahoma Panhandles. Transwestern peak delivery capacity of 1.5 Bcf per day in 1997 was primarily delivered to local distribution companies (approximately 65% of revenues) and gas marketers (approximately 35% of revenues). Substantially all of Transwestern's delivery capacity to California was held by shippers on a firm basis until November 1, 1996, when approximately 450 Mmcf per day of firm capacity was turned back to Transwestern by a major customer. Anticipating this turnback, Transwestern entered into a settlement agreement with its customers whereby the costs associated with this turnback are shared by Transwestern and its current firm customers. Transwestern is responsible for 70% of the risk of resubscribing the released capacity, and Transwestern's customers have the remaining 30% of such risk through 2001. In addition to this cost-sharing mechanism, Transwestern and its current firm customers also agreed to contract rates through 2006 and agreed that Transwestern would not be required to file a new rate case for rates to be effective prior to November 1, 2006.
Transwestern's mainline includes a lateral pipeline to the San Juan Basin which allows Transwestern to access San Juan Basin gas supplies. Via Transwestern's San Juan lateral pipeline, the San Juan Basin gas may be delivered to California markets as well as markets off the east end of Transwestern's system. Total throughput volumes to California averaged approximately 558 MMcf per day in 1997, compared to 414 MMcf per day in 1996. Transwestern has firm transportation service on the east end of its system and transports Permian, Anadarko and San Juan Basin supplies into Texas, Oklahoma and the midwestern United States. Transwestern has previously made certain modifications to its mainline system which increased the volumes flowing from the San Juan Basin to the east end of the Transwestern system. Transwestern transported an average of 657 MMcf per day off the east end of its system in 1997, as compared to 773 MMcf per day in 1996.
Transwestern is subject to competition from other transporters into the southern California market.
Florida Gas Transmission Company. An Enron subsidiary owns a 50% interest in Florida Gas by virtue of its 50% interest in Citrus Corp., which owns all of the capital stock of Florida Gas. Another Enron subsidiary operates the Florida Gas pipeline.
Florida Gas is an interstate pipeline company that transports natural gas for third parties. Its approximately 4,950-mile dual pipeline system extends from South Texas to a point near Miami, Florida. Florida Gas 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. Florida Gas serves a mix of customers anchored by utility generators.
Florida Gas has periodically expanded its system capacity to keep pace with the growing demand for natural gas in Florida. Florida Gas placed its Phase III expansion in service in 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. The Phase III expansion increased Florida Gas' firm average delivery capacity into Florida by 532 billion British thermal units ("BBtu") per day to 1,455 BBtu per day. Florida Gas also owns an interest in facilities that link its system to the Mobile Bay producing area. Florida Gas' customers have reserved over 99% of the existing capacity on the Florida Gas system pursuant to firm long-term transportation service agreements.
Florida Gas is the only interstate natural gas pipeline serving peninsular Florida. Florida Gas faces competition from residual fuel oil in the Florida market. A primary advantage of the straight fixed variable rate design (a FERC mandated rate design to allow pipelines to recover substantially all fixed costs, a return on equity and income taxes in the capacity reservation component of their rates) is that Florida Gas will recover substantially all of its fixed costs regardless of levels of usage by its customers. See "Regulation - Natural Gas Rates and Regulations".
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 an 11.8% interest in the limited partnership and serves as operator of the pipeline. Northern Border owns an approximately 970-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 in the U.S. The pipeline system also has access to production of synthetic gas from the Great Plains Coal Gasification Project in North Dakota. Interconnecting pipeline facilities provide access to markets in the Midwest, as well as other markets throughout the U.S. by transportation, displacement and exchange agreements. Therefore, Northern Border is strategically situated to transport significant quantities of natural gas to major gas consuming markets. 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 2001. Northern Border competes with two other interstate pipeline systems that transport gas from Canada to the Midwest.
Northern Border is currently constructing a project which will expand its existing system by delivering an additional 700 MMcf of natural gas per day from Canada, and will extend the pipeline 243 miles to Chicago. Northern Border's total system capacity will increase to approximately 2.4 Bcf of natural gas per day, with an expected in-service date of November 1998. The $840 million project is fully subscribed by over 20 shippers with 10-year minimum transportation contracts.
Electricity Transmission and Distribution Operations
Enron's electric utility operations are conducted through its wholly-owned subsidiary Portland General Electric Company ("PGE"). PGE, incorporated in 1930, is an electric utility engaged in the generation, purchase, transmission, distribution, and sale of electricity in the State of Oregon. PGE also sells energy to wholesale customers throughout the western U.S. PGE's Oregon service area is approximately 3,170 square miles, including 54 incorporated cities of which Portland and Salem are the largest, within a state-approved service area allocation of 4,070 square miles. At December 31, 1997 PGE served approximately 685,000 customers.
PGE serves a diverse retail customer base. Residential customers constitute the largest customer class and account for 44% of the of retail revenues. Residential demand is highly sensitive to the effects of weather. Commercial customers comprise 40% and industrial customers represent 16% of retail revenues. The commercial and industrial classes are not dominated by any single industry. While the 20 largest customers constitute 21% of retail demand, they represent 10 different industry groups including paper manufacturing, high technology, metal fabrication, transportation equipment and health services. No single customer represents more than 10% of PGE's retail load.
In late 1997, PGE filed a proposal before the Oregon Public Utility Commission ("OPUC") which would give all of its customers a choice of electricity providers. PGE's "Customer Choice Implementation Proposal" includes new tariffs and a new structure for PGE. If approved by the OPUC, PGE would become a regulated transmission and distribution company focused on delivering, but not selling, electricity. PGE would continue to operate and maintain the electricity delivery system and handle outage restoration, while other competitive companies would market power to customers over that system. To effect this restructuring, PGE is asking for OPUC approval to sell all its generating assets and power supply and purchase contracts.
Wholesale revenues continue to make a significant contribution to PGE revenues, providing over 35% of total operating revenues for 1997. During the past several years, PGE has actively marketed wholesale power throughout the western United States. A majority of PGE's wholesale sales were to its traditional customers comprised of investor owned utilities, federal agencies, municipalities and public utility districts. However, most of PGE's wholesale growth has come through sales to marketers and brokers. These sales are predominantly of a short-term nature. Long-term wholesale marketing activities have been transferred to Enron's non-regulated affiliates, and future revenues will be reflected in Enron's wholesale energy operations and services segment.
PGE operates within a state-approved service area, and under current regulation is substantially free from direct retail competition with other electric utilities. PGE's competitors within its Oregon service territory include other fuel suppliers, such as the local natural gas company, which compete with PGE for the residential and commercial space and water heating market. In addition, there is the potential of a loss of PGE service territory to the creation of public utility districts or municipal utilities by voters. In the future, PGE will focus on transitioning to a regulated transmission and distribution company.
WHOLESALE ENERGY OPERATIONS AND SERVICES
Enron's wholesale energy operations and services businesses operate in North America, Europe and evolving energy markets in developing countries, and such businesses are conducted primarily by Enron Capital & Trade Resources Corp. and Enron International Inc. These businesses provide integrated energy-related products and services to wholesale customers worldwide, including the development, construction and operation of power plants, natural gas pipelines and other energy-related assets, energy commodity sales and services, risk management products and financial services. Enron Engineering & Construction Company provides comprehensive engineering and construction expertise for power and pipeline projects, serving as turnkey contractor or project manager for such projects.
Wholesale energy operations and services can be categorized into four business lines: Asset Development and Construction, Cash and Physical, Risk Management and Finance and Investing. Products and services related to these business lines are offered in varying degrees in North American, European and evolving international markets.
Asset Development and Construction. This business includes the development and construction of power plants, pipelines and other energy infrastructure.
Cash and Physical. The cash and physical operations include the day-to-day purchase, sale, marketing and delivery of physical natural gas, electricity, liquids and other commodities under contracts of one year or less and the management of Enron's contract portfolios. Enron's cash and physical business also includes the management of operating assets of this segment, including domestic intrastate pipelines, numerous storage facilities and power plants.
Risk Management. The risk management activities consist of long-term energy commodity contracts (transactions greater than one year) and restructuring of existing long-term contracts. Enron provides risk management products and services that hedge movements in price and location-based price differentials. Enron's risk management services are designed to provide stability in markets impacted by price volatility. Enron applies these concepts for a diverse group of customers in structuring a portfolio of products such as swap, option, and hybrid products; long-term, fixed price contracts; innovative pricing structures such as commodity prices tied to alternative fuels and energy supply prices indexed to output; and utility, local distribution company, and independent power producer contract restructuring alternatives. Enron originates new contracts for customers in the energy industry and evaluates and restructures its existing contracts on an ongoing basis to develop additional products and services to meet its customers' changing needs. The risk management activities also include the origination of liquid fuels 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 and Investing. Enron's financing and investing activities support independent exploration and production companies and other energy-related businesses seeking debt or equity financing. Enron provides a variety of capital products including volumetric production payments, loans and equity investments, either directly or through Enron affiliates. In addition to capital, Enron may integrate its marketing and risk management capabilities to help customers capitalize on growth opportunities while maximizing the value of their current assets.
The following table presents selected statistical information for Enron's wholesale energy operations and services businesses.
North American Markets
Enron's North American wholesale operations include cash and physical, risk management and finance and investing business lines.
Enron markets natural gas, electricity and other commodities in North America and provides risk management products and financial services to producers and end-users of energy commodities. Enron offers a broad range of services to provide predictable pricing, reliable delivery and low cost capital to its customers, including independent oil and gas producers, energy intensive industrials, public and investor owned utility power companies, small independent power producers and local distribution companies. These services are provided through a variety of products including forward contracts, swap agreements and other contractual commitments.
The day-to-day buying, selling and transporting of commodities is facilitated by using the New York Mercantile Exchange ("NYMEX"), allowing Enron to manage its portfolio of contracts and to benefit from the relationship between the financial and physical prices for natural gas. Total physical volumes, including volumes transported, averaged 12.7 Tbtu of natural gas equivalents per day in 1997 compared to 10.7 Tbtu of natural gas equivalents per day in 1996. In addition, financial settlements were approximately 49.1 Tbtu of natural gas equivalents per day in 1997 and 35.3 Tbtu of natural gas equivalents per day in 1996.
Enron's intrastate pipelines include Houston Pipe Line Company ("HPL") and Louisiana Resources Company. HPL owns an approximately 5,243-mile pipeline in Texas which interconnects with Northern, Transwestern, Florida Gas and numerous other interstate and intrastate pipelines. HPL's intrastate natural gas transportation and storage services are subject to seasonal variation because many of its customers have weather-sensitive natural 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." Louisiana Resources Company is 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, which is the NYMEX physical settlement location, and has numerous interconnections with both interstate and intrastate pipelines.
Enron'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 Enron's ability to meet the firm requirements of industrial markets in Louisiana, and provides the swing and peak capability required by local distribution companies and electric utilities along the Eastern seaboard.
Enron's North American electric power business consists of various activities, 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. Enron marketed 192.3 million megawatt hours and 60.1 million megawatt hours of electricity during 1997 and 1996, respectively. Enron also 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 Enron's risk management operations). Enron 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.
European Markets
Enron's European operations, headquartered in London, commenced in 1989 with the development of the Teesside power station described below. Since that time, Enron has continued to operate and develop power assets and provide a broad range of energy service capabilities similar to Enron's North American operations, such as the purchase and sale of physical commodities (natural gas, electricity and liquids), risk management and finance activities. Enron has expanded its business from the United Kingdom to continental Europe with regional offices in Oslo, Stockholm, Moscow and Frankfurt.
At December 31, 1997, Enron had an approximately 31% ownership interest in an independent power facility with a capacity of approximately 1,875 megawatts near Teesside in northeast England. The gas-fired combined-cycle project was developed and 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.
Enron and the second largest regional utility company in Germany jointly own an approximately 125 megawatt gas- fired plant in Bitterfeld, Germany. The Bitterfeld project provides Enron with a presence in Germany as well as access to a site for possible expansion.
Enron has a 25% ownership interest in an independent power facility under construction at Sutton Bridge in mid- east England, with the remaining ownership interest held by insurance companies and financial investors. Expected to commence commercial operation in March 1999, the plant will be a gas fired combined-cycle plant with a capacity of approximately 790 megawatts. The project was developed, and construction is being coordinated, by Enron subsidiaries. The capacity of the plant is contracted to another Enron subsidiary until May 2014 with a right to extend, at Enron's option, for up to an additional ten years in one-year increments.
Enron has a 45% interest in a 551-megawatt combined- cycle oil gasification power plant to be located on the island of Sardinia, Italy. The plant will employ technology to gasify low-quality residual fuel. Enron will provide technical services to the plant. A 20-year power purchase agreement has been signed with ENEL, the Italian government utility. Financing was completed and construction began in December 1996, with commercial operation anticipated in early 2000.
Enron has a 50% interest in a 478-megawatt gas-fired power plant to be located at Marmara, Turkey, near Istanbul. Enron will be operator and turnkey contractor of the plant. A 20-year power purchase agreement has been signed with the state power utility, financing has been completed, and construction began in September 1996, with commercial operation expected in 1999.
Enron's European operations include other power and pipeline projects in various stages of development in Poland, Greece, Italy, Turkey and Croatia.
Evolving International Markets
Enron is also involved in the development, acquisition, financing, promotion, and operation of natural gas pipeline and power projects in emerging markets and the marketing of natural gas liquids and other liquid fuels. Asset development activities are primarily focused on power plants, gas processing and terminaling facilities, and gas pipelines. Enron has expanded its international asset and infrastructure development business by also offering commodity marketing, finance and risk management products and services to third parties in emerging markets. Enron has established offices in Buenos Aires and Singapore to offer similar physical commodity products, financial services and risk management services currently available through Enron's operations in North America and Europe. In these markets, Enron's objective is to develop, finance, own and operate energy projects worldwide and to integrate additional energy related products and services into these developing markets.
Operating Assets
Enron has an approximately 35% indirect interest in Transportadora de Gas del Sur ("TGS"), the formerly state- owned natural gas pipeline in southern Argentina. The 4,104- mile pipeline system has a capacity of approximately 1.9 Bcf per day and primarily serves four distribution companies under long-term firm transportation contracts.
Enron 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 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.
Enron 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 Enron and sell power to the National Power Corporation of the Philippines.
Enron has a 50% interest in a 185-megawatt barge- mounted combined-cycle power plant at Puerto Plata on the north coast of the Dominican Republic. The plant began operation in January 1996. Power is sold pursuant to a 19- year power purchase agreement with the Dominican Republic government utility.
Enron has a 50% interest in an approximately 357-mile natural gas pipeline which runs from the northern coast of Colombia to the central region of the country. Ecopetrol, the state-owned oil company of Colombia, is the sole customer for the transportation services and has a 15-year contractual commitment to pay for all of the initial capacity.
Enron has a 50% interest in a 152-megawatt diesel combined-cycle power plant on Hainan Island, an economic free trade zone off the southeastern coast of China. The independent power project is the first such project developed by a U.S. company in China. An Enron affiliate is operator and fuel manager.
Enron has a 25% interest in Transredes Transporte de Hidrocarburos S.A. ("Transredes"), a 3,093-mile system of natural gas, crude oil and products pipelines located in Bolivia and connecting Bolivian oil and gas reserves to major markets in Bolivia. Enron is upgrading Transredes' existing pipeline operations and increasing the capacity of the pipeline system to 1.0 Bcf per day to supply Brazilian market needs.
Enron has recently acquired interests in the Rio de Janeiro municipal gas distribution company, in addition to the gas distribution company of the State of Rio de Janeiro and natural gas distribution systems in seven other Brazilian states. These systems encompass an area with a population of approximately 55 million people.
Certain of Enron's operations in the Caribbean area are conducted through Enron Americas, Inc. and its subsidiary companies. Enron Americas' subsidiary Industrias Ventane, organized in 1953, operates the leading natural gas liquids transportation and distribution business in Venezuela. Also in Venezuela, Enron is engaged in the manufacture and distribution of appliances in a joint venture with General Electric and local investors. Enron has a natural gas distribution system in Puerto Rico, and liquid fuels businesses in both Puerto Rico and Jamaica.
Projects Under Development
In the evolving international energy markets, Enron is developing and constructing energy infrastructure to establish an asset base for development of regional businesses. Primary areas of focus are in India and South America. The following is a brief description of certain of Enron's power and natural gas pipeline projects which are in varying stages of development, financing or construction. Because of this, the information set forth below is subject to change. 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, the availability of project financing on acceptable terms, expropriation of assets, renegotiation of contracts with foreign governments and political instability, as well as changes in laws and policies governing operations of foreign- based businesses generally. There can be no assurances that these projects will commence commercial operations.
India. In connection with a Power Purchase Agreement between Dabhol Power Company, Enron's 80%-owned subsidiary, and the Maharashtra State Electricity Board (the "MSEB"), Dabhol Power Company is constructing Phase I of an electricity generating power plant south of Bombay, State of Maharashtra, India. The power plant will have an initial capacity of 740-megawatts (or 826 megawatts gross) (Phase I), which is expected to begin commercial operations in late 1998. Enron will be the fuel manager and operator of the plant, which will provide electricity for the growing Maharashtra State economy. Enron is expected to finalize in 1998 a sale of 30% of the project to the MSEB.
Enron is currently developing Phase II of the Dabhol power project, a 1,624-megawatt combined-cycle power plant to be fueled by natural gas. A 20-year power purchase agreement has been signed with the MSEB. Financing of Phase II is targeted for 1998, with commercial operations expected to commence in late 2000.
South America. Enron is developing, along with Petrobras, the national oil and gas company of Brazil, and others, a pipeline which will connect with Transredes in Bolivia and transport natural gas to markets in Brazil. The pipeline project includes an approximately 1,864-mile natural gas pipeline from Santa Cruz, Bolivia to Porto Alegre, Brazil. Enron currently owns (including through its ownership interest in Transredes) 29.75% of the Bolivian segment of the pipeline and 7% of the Brazilian segment of the pipeline. Commercial operation of the first phase of the pipeline is expected in 1999.
Enron is developing a 480-megawatt combined-cycle power plant at Cuiaba in the State of Mato Grosso in western Brazil to feed power into the Brazilian energy grid at a strategic point which has few existing alternate generation sources. Construction is underway on Phase I of the project (150 megawatts), with commercial operations expected in late 1998. Commercial operations of Phase II (330 megawatts) are expected to commence in late 2000. As an additional part of this project, Enron is developing a 385-mile, 18-inch natural gas pipeline connecting to the Bolivia to Brazil pipeline in Bolivia. Including its ownership interest through Transredes, Enron owns 53% of the power plant and Brazilian segment of the pipeline and 35% of the Bolivian segment of the pipeline.
Other. Enron has a 50% interest in a 507-megawatt combined-cycle power plant, including a liquefied natural gas terminal and desalination facility, under construction in Penuelas, Puerto Rico. Enron is the turnkey contractor and will operate the project. A 22-year power purchase agreement has been signed with the Puerto Rico Electric Power Authority. Construction commenced in 1997, with commercial operation anticipated in late 1999.
Enron has a 50% interest in an 80-megawatt baseload diesel power plant to be located in Piti, Guam. A 20-year power purchase agreement has been signed with the Guam Power Authority, an agency of the Guam government. The project is on a fast track schedule to meet critical power needs, with operations targeted for year-end 1998.
In addition to the projects referenced above, Enron is involved in projects in varying stages of development in Vietnam, Europe, Mozambique, Qatar, China, Egypt and Saudi Arabia, and is pursuing projects elsewhere.
RETAIL ENERGY SERVICES
Enron Energy Services (EES) was formed in late 1996 to provide direct sales of energy products and services to end- use customers, particularly in the commercial and light industrial sectors. EES offers a range of energy-related products and services to commercial and light industrial customers in both regulated and deregulated markets. These products and services include energy information management, demand-side services, and financing. In deregulated markets such as California, products can include electricity and natural gas and related metering and billing. EES anticipates providing end-users with a broad range of energy products and services at competitive prices. EES has participated successfully in selected natural gas and electric retail marketing pilots and continues to make progress in expanding its customer base.
EES is creating products and services to help commercial and light industrial businesses understand how they can maximize total energy savings while meeting operational needs. With a focus on total energy savings, EES is designing and promoting innovative programs to not only supply electricity and natural gas to businesses, but also to reduce their energy consumption, delivery and billing costs. EES is also investing in technology to provide businesses with immediate feedback on energy usage through real-time metering systems and protection from power outages and surges. At the residential level, EES provides customers with new and innovative service options in some deregulated markets.
OTHER ENRON BUSINESSES
Clean Energy Businesses
Opportunities for "clean" energy are being driven by concerns about the environment and increasing cost competitiveness of renewable energy compared to other wholesale energy sources. Enron participates in the renewable energy market through the development and operation of solar and wind energy power plants and the manufacture and sale of solar and wind generation equipment. Enron is pursuing wind power projects in the U.S., the United Kingdom, Germany, Spain, Ireland, Greece and several Central and South American countries. Enron is constructing a 107-megawatt wind energy project in Minnesota and has contracts to supply additional wind generated electricity for projects in Minnesota (100 megawatts), Iowa (approximately 200 megawatts), California (approximately 80 megawatts) and Greece (15 megawatts). In addition, through a joint venture partnership, Enron is engaged in the manufacture of solar energy equipment, with development activities underway in the U.S., Greece, India and Japan.
Crude Oil Transportation Services
EOTT Energy Partners, L.P. ("EOTT"), a Delaware limited partnership formed in March 1994, is an independent gatherer and marketer of crude oil, and EOTT Energy Corp. (a wholly owned subsidiary of Enron) serves as the general partner of EOTT. Enron owns an approximately 49% interest in EOTT. EOTT is engaged in the purchasing, gathering, transporting, 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 25,000 leases in 17 states. In addition, EOTT is a purchaser of lease crude oil in Canada. EOTT provides transportation and trading services for third party purchasers of crude oil. In its North American crude oil gathering and marketing operations, EOTT purchased approximately 305,000 barrels per day of lease crude oil during 1997. EOTT is in competition with major oil companies and a number of smaller entities.
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, the addition of facilities, the extension of services in some cases, the abandonment of services and facilities, the curtailment of gas deliveries 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 ("DOE"). 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.
Enron's power marketing companies are subject to the FERC's regulatory jurisdiction under the Federal Power Act ("FPA") with respect to rates, terms and conditions of service and certain reporting requirements. Certain of the power marketing companies' exports of electricity are subject to approval by the DOE. Enron's affiliates involved in cogeneration and independent power production are subject to regulation by the FERC under the Public Utility Regulatory Policies Act ("PURPA") and the FPA with respect to rates, the procurement and provision of certain services and operating standards.
The regulatory structure that has historically applied to the natural gas and electric industry is in transition. Legislative and regulatory initiatives, at both federal and state levels, are designed to supplement regulation with increasing competition. Legislation to restructure the electric industry is under active consideration on both the federal and state levels. Proposed federal legislation would make the electric industry more competitive by providing retail electric customers with the right to choose their power suppliers. Modifications to PURPA and the Public Utility Holding Company Act of 1935 ("PUHCA") have also been proposed. In addition, new technology and interest in self-generation and cogeneration have provided opportunities for alternative sources and supplies of energy. Retention of existing customers and potential growth of Enron's customer base will depend, in part, upon the ability of Enron to respond to new customer expectations and changing economic and regulatory conditions.
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 ability to compete and 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 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 international 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, FGT 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, FGT 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, FGT 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, and in certain cases are subject to refund under applicable law, until such time as the FERC issues an order 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.
Since 1985, the FERC has made 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, mandated a fundamental restructuring of interstate pipeline sales and transportation services. Order No. 636 required 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. Order No. 636 also required 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. A key effect of Order No. 636 and its progeny has been to substantially eliminate merchant sales by pipelines like Northern, Transwestern and FGT. Numerous parties filed petitions for court review of FERC's Order No. 636 series, as well as orders in individual pipeline restructuring proceedings. Various aspects of Order No. 636 were challenged, including alleged shifts of costs between pipeline customer groups and the continuing reliability of unbundled services. There have been two subsequent orders on rehearing of Order No. 636 (Order Nos. 636-A and 636-B) and one subsequent order on remand from the D.C. Circuit Court of Appeals (Order No. 636-C) in which the FERC modified the original order in response to these and other concerns. Since the D.C. Circuit Court opinion has been appealed and further judicial review of FERC's new orders may result in such orders being reversed in whole or in part, it is not possible to predict with precision the ultimate effect of FERC's Order No. 636 series.
The series of 636 orders 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. Northern, Transwestern and FGT have implemented the service restructuring required by such orders by unbundling their 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 their rates. The FERC has indicated that Northern, Transwestern and FGT will be authorized to recover all prudently incurred costs associated with a reduced merchant role resulting from the implementation of such orders.
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, including income taxes and return on equity, 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, 1997 were approximately $283 million, which included transition costs incurred related to FERC Order No. 636 of approximately $41 million. The regulatory assets related to the FERC Order No. 636 transition costs are scheduled to be primarily recovered from customers by the end of 1998, while the remaining assets are expected to be recovered over varying time periods.
Enron's regulated pipelines have all successfully completed their transitions under FERC Order No. 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.
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.
The rates at which natural gas is sold in Texas to gas utilities serving customers within an incorporated area 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.
Electric Industry Regulation
Historically, the electric industry has been subject to comprehensive regulation at the federal and state levels. The FERC regulated sales of electric power at wholesale and the transmission of electric energy in interstate commerce pursuant to the FPA. The FERC subjected public utilities under the FPA to rate and tariff regulation, accounting and reporting requirements, as well as oversight of mergers and acquisitions, securities issuances and dispositions of facilities. States or local authorities have historically regulated the distribution and retail sale of electricity, as well as the construction of generating facilities.
Enacted in 1978, PURPA created opportunities for independent power producers, including cogenerators. If a generating project obtained the status of a "Qualifying Facility," it was exempted by PURPA from most provisions of the FPA and certain state laws relating to securities, rate and financial regulation. PURPA also required electric utilities (i) to purchase electricity generated by Qualifying Facilities at a price based on the utility's avoided cost of purchasing electricity or generating electricity itself, and (ii) to sell supplementary, back-up, maintenance and interruptible power to Qualifying Facilities on a just and reasonable and non-discriminatory basis.
PUHCA subjects certain entities that directly or indirectly own, control or hold the power to vote 10% of the outstanding voting securities of a "public utility company" or a company which is a "holding company" of a public utility company to registration requirements of the Securities and Exchange Commission ("SEC") and regulation under PUHCA, unless the entity is eligible for an exemption or has been granted an SEC order declaring the entity not to be a holding company. Affiliates, or direct or indirect holders of 5% of the voting securities of such companies, are also subject to regulation under PUHCA unless so eligible for an exemption or SEC order. PUHCA requires registration for a holding company of a public utility company, and requires a public utility holding company to limit its operations to a single integrated utility system and to divest any other operations not functionally related to the operation of the utility system. A public utility company which is a subsidiary of a registered holding company under PUHCA is subject to financial and organizational regulation, including SEC approval of its financing transactions.
The Energy Policy Act of 1992 ("EP Act") exempted from some traditional federal utility regulation generators selling power at wholesale in an effort to enhance competition in the wholesale generation market. The EP Act also authorized FERC to require utilities to transport and deliver or "wheel" energy for the supply of bulk power to wholesale customers.
Recent FERC regulatory initiatives are changing the electric power industry. In April 1996, FERC paved the way for the transition to more competitive electric markets by issuing its Order Nos. 888 and 889. Order No. 888 required utilities to provide third parties wholesale open access to transmission facilities on terms comparable to those that apply when utilities use their own systems. Utilities were required by the order to file open access tariffs in July 1996. Power pools, which are associations of interconnected electric transmission and distribution systems that have an agreement for integrated and coordinated operations, were directed to file their open access tariffs by the end of 1996. These tariffs enable eligible parties to obtain wholesale transmission service over utilities' transmission systems. In Order No. 888, FERC stated its intention to permit utilities to recover legitimate, verifiable and prudently incurred costs that are rendered uneconomic or "stranded" as a result of customers taking advantage of wholesale open access to meet their power needs from others. In Order No. 889, FERC required utilities owning transmission facilities to adopt procedures for an open access same-time information system ("OASIS") that will make available, on a real-time basis, pertinent information concerning each transmission utility's services. The order also promulgated standards of conduct to ensure that utilities separate their transmission functions from their wholesale power merchant functions and to prevent the misuse of commercially valuable information. In March 1997 FERC issued its orders on rehearing of Order Nos. 888 and 889. In these orders FERC upheld the basic open access and OASIS regulatory framework established in Order Nos. 888 and 889, while making certain modifications to its open access and stranded cost recovery rules.
Congress is considering legislation to modify federal laws affecting the electric industry. Bills have been introduced in the Senate and the House of Representatives that would, among other things, provide retail electric customers with the right to choose their power suppliers. Modifications to PURPA and PUHCA have also been proposed. In addition, various states have either enacted or are considering legislation designed to deregulate the production and sale of electricity. Deregulation is expected to result in a shift from cost-based rates to market-based rates for electric energy and related services. Although the legislation and regulatory initiatives vary, common themes include the availability of market pricing, retail customer choice, recovery of stranded costs, and separation of generation assets from transmission, distribution and other assets. It is unclear whether or when all power customers will obtain open access to power supplies. Decisions by regulatory agencies may have a significant impact on the future economics of the power marketing business.
The Oregon Public Utility Commission ("OPUC"), a three- member commission appointed by the Governor of Oregon, approves PGE's retail rates and establishes conditions of utility service. The OPUC ensures that prices are fair and equitable and provides PGE an opportunity to earn a fair return on its investment. In addition, the OPUC regulates the issuance of securities and prescribes the system of accounts to be kept by Oregon utilities. PGE is also subject to the jurisdiction of the FERC with regard to the transmission and sale of wholesale electric energy, licensing of hydroelectric projects and certain other matters. Construction of new generating facilities requires a permit from Oregon Energy Facility Siting Counsel.
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 with respect to the cleanup of one Superfund site. Enron has received requests for information from the EPA andc 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 position or results of operations. (See Item 3, "Legal Proceedings").
PGE's current and historical operations are subject to a wide range of environmental protection laws covering air and water quality, noise, waste disposal, and other environmental issues. PGE is also subject to the Federal Rivers and Harbors Act of 1899 and similar Oregon laws under which it must obtain permits from the U.S. Army Corps of Engineers or the Oregon Division of State Lands to construct facilities or perform activities in navigable waters of the State. State agencies or departments which have direct jurisdiction over environmental matters include the Environmental Quality Commission, the Oregon Department of Environmental Quality, the Oregon Department of Energy and Oregon Energy Facility Siting Counsel. Environmental matters regulated by these agencies include the siting and operation of generating facilities and the accumulation, cleanup and disposal of toxic and hazardous wastes.
Other
PGE is a 67.5% owner of the Trojan Nuclear Plant ("Trojan"). The Nuclear Regulatory Commission ("NRC") regulates the licensing and decommissioning of nuclear power plants. In 1993 the NRC issued a possession-only license amendment to PGE's Trojan operating license and in early 1996 approved the Trojan Decommissioning Plan. Approval of the Trojan Decommissioning Plan by the NRC and Oregon Energy Facility Siting Counsel has allowed PGE to commence decommissioning activities. Trojan will be subject to NRC regulation until Trojan is fully decommissioned, all nuclear fuel is removed from the site and the license is terminated. The Oregon Department of Energy also monitors Trojan.
CURRENT EXECUTIVE OFFICERS OF THE REGISTRANT
Name and Age Present Principal Position and Other Material Positions Held During Last Five Years
Kenneth L. Lay (55) Chairman of the Board and Chief Executive Officer, Enron Corp., since February 1986.
Jeffrey K. Skilling (44) President and Chief Operating Officer, Enron Corp., since January 1997. Chief Executive Officer and Managing Director of Enron Capital & Trade Resources Corp. ("ECT") from June 1995 to December 1996. From August 1990 to June 1995, Mr. Skilling served ECT in a variety of executive managerial positions.
Ken L. Harrison (55) Vice Chairman, Enron Corp., since July 1997. Chairman of the Board and Chief Executive Officer of Portland General Electric Company since 1987.
John A. Urquhart (69) Vice Chairman, Enron Corp., since August 1991.
Stanley C. Horton (48) Chairman and Chief Executive Officer, Enron Gas Pipeline Group, since January 1997. Co-Chairman and Chief Executive Officer of Enron Operations Corp. from February 1996 to January 1997. President and Chief Operating Officer of Enron Operations Corp. from June 1993 to February 1996. President of Northern Natural Gas Company from June 1991 to June 1993. President of Florida Gas Transmission Company from 1988 to May 1991.
Rebecca P. Mark (43) Chairman and Chief Executive Officer, Enron International Inc., since January 1997. Chairman and Chief Executive Officer of Enron Development Corp. since July 1993. Vice President and Chief Development Officer of Enron Power Corp. from July 1991 to July 1993.
Thomas E. White (54) Chairman and Chief Executive Officer, Enron Ventures Corp., since January 1997. Co-Chairman and Chief Executive Officer of Enron Operations Corp. from February 1996 to January 1997. Chairman and Chief Executive Officer of Enron Operations Corp. from June 1993 to February 1996. Chairman and Chief Executive Officer of Enron Power Corp. from July 1991 to June 1993. Brigadier General, United States Army, from 1988 to 1990. Executive Assistant to Chairman of the Joint Chiefs of Staff from 1989 to 1990.
J. Clifford Baxter (39) Senior Vice President, Corporate Development, Enron Corp., since January 1997. Managing Director, ECT, 1996; Vice President, Corporate Development, ECT, 1995-1996; Managing Director, Koch Equities, 1995; Director, Corporate Development, ECT, 1992-1994.
Richard A. Causey (38) Senior Vice President and Chief Accounting and Information Officer, Enron Corp., since January 1997. Managing Director, ECT, from June 1996 to January 1997; Vice President, ECT, from January 1992 to June 1996.
James V. Derrick, Jr.(53) Senior Vice President and General Counsel, Enron Corp., since June 1991. Partner, Vinson & Elkins from January 1977 until June 1991.
Andrew S. Fastow (36) Senior Vice President and Chief Financial Officer since March 1998. Senior Vice President, Finance, Enron Corp., from January 1997 to March 1998. Managing Director, Retail and Treasury, ECT, from May 1995 to January 1997. Vice President, ECT, from January 1993 to May 1995. Account Director, ECT, from 1990 to 1993.
Item 2.
Item 2. PROPERTIES
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, 1997, 1996 and 1995 were based on studies performed by EOG'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, 1997, 1996 and 1995 covering producing areas containing 54%, 64% and 60%, respectively, of proved reserves (excluding deep Paleozoic methane 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. The deep Paleozoic methane reserves were covered by the opinion of DeGolyer and MacNaughton for the year ended December 31, 1995. 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 to the Consolidated Financial Statements.
Producing Oil and Gas Wells
The following table reflects EOG's ownership at December 31, 1997 in gas and oil wells located in Texas, 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 gas and oil wells include 279 with multiple completions.
Acreage
The following table summarizes EOG's developed and undeveloped acreage at December 31, 1997. 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, 1997, 1996 and 1995, EOG spent approximately $693 million, $599 million and $514 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.
Gas Transmission
Enron's domestic natural gas facilities include approximately 25,500 miles of transmission lines, 105 mainline compressor stations, five underground gas storage fields and two liquefied natural gas storage facilities. Enron also owns interests in pipeline and related facilities associated with its participation and investments in jointly- owned pipeline systems.
Substantially all the 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.
In most cases, 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 regulator and compressor stations, clean fuel facilities and offices are located on tracts of land owned by it in fee or leased from others.
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.
International Power Plants and Pipelines
Enron's principal international operating power plants and pipelines and appurtenant facilities are (i) situated on land owned by Enron in fee or land under the control of Enron pursuant to valid existing leases, licenses, easements or other agreements, or (ii) in the case of certain power plants, barge-mounted on vessels owned by Enron. Power plants and pipelines in which Enron owns an interest are set forth in the following table:
Facility Location Fuel Size/Capacity Enron Interest
Power Plants: Puerto Guatemala Gas 110 MW 50% Quetzel Teesside U.K. Gas 1,875 MW 31% Batangas Philippines Fuel oil 110 MW 50% Subic Bay Philippines Fuel oil 116 MW 50% Bitterfeld Germany Gas 125 MW 50% Puerto Plata Dominican Fuel oil 185 MW 50% Republic Hainan Island China Diesel 154 MW 50%
Pipelines: TGS Argentina - 1.9 Bcf/d; 35% 4,104 miles Centragas Colombia - 110 MMcf/d; 50% 357 miles Transredes Bolivia - 320 MMcf/d; 25% 35 MMb/d; 3,093 miles
Electric Utility Properties
PGE's principal plants and appurtenant generating facilities and storage reservoirs are situated on land owned by PGE in fee or land under the control of PGE pursuant to valid existing leases, federal or state licenses, easements, or other agreements. In some cases meters and transformers are located upon the premises of customers. The indenture securing PGE's first mortgage bonds constitutes a direct first mortgage lien on substantially all utility property and franchises, other than expressly excepted property.
Generating facilities owned by PGE are set forth in the following table:
PGE Net MW Facility Location Fuel Capability Wholly Owned: Faraday Estacada, OR Hydro 44 North Fork Estacada, OR Hydro 54 Oak Grove Three Lynx, OR Hydro 44 River Mill Estacada, OR Hydro 23 Pelton Madras, OR Hydro 108 Round Butte Madras, OR Hydro 300 Bull Run Bull Run, OR Hydro 22 Sullivan West Linn, OR Hydro 16 Beaver Clatskanie, OR Gas/Oil 500 Bethel Salem, OR Gas/Oil 116 Coyote Springs Boardman, OR Gas/Oil 241
PGE Jointly Interest Owned:
Boardman Boardman, OR Coal 331 65.0% Centralia Centralia, WA Coal 33 2.5% Colstrip 3 & 4 Colstrip, MT Coal 288 20.0% Trojan Rainier, OR Nuclear - 67.5% 2,120
PGE holds licenses under the Federal Power Act for its hydroelectric generating plants. All of its licenses expire during the years 2001 to 2006. The FERC requires that a notice of intent to relicense these projects be filed approximately five years prior to expiration of the license. PGE is actively pursuing the renewal of these licenses. The State of Oregon also has licensed all or portions of five hydro plants.
Following the 1993 Trojan closure, PGE was granted a possession-only license amendment by the NRC. In early 1996 PGE received NRC approval of its Trojan decommissioning plan.
Combustion turbine generators at the Bethel Combustion Turbine Plant and the Beaver Combustion Turbine Plant are leased by PGE. These leases expire in 1998 and 1999. PGE is currently evaluating its renewal options. PGE leases its headquarters complex in downtown Portland and the coal- handling facilities and certain railroad cars for the Boardman coal plant.
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 it's 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 its results of operations.
Litigation. In 1995, several parties (the Plaintiffs) filed suit in Harris County District Court in Houston, Texas, against Intratex Gas Company (Intratex), Houston Pipe Line Company and Panhandle Gas Company (collectively, the Enron Defendants), each of which is a wholly-owned subsidiary of Enron. The Plaintiffs were either sellers or royalty owners under numerous gas purchase contracts with Intratex, many of which have terminated. Early in 1996, the case was severed by the Court into two matters to be tried (or otherwise resolved) separately. In the first matter, the Plaintiffs alleged that the Enron Defendants committed fraud and negligent misrepresentation in connection with the "Panhandle program," a special marketing program established in the early 1980s. This case was tried in October 1996 and resulted in a verdict for the Enron Defendants. In the second matter, the Plaintiffs allege that the Enron Defendants violated state regulatory requirements and certain gas purchase contracts by failing to take the Plaintiffs' gas ratably with other producers' gas at certain times between 1978 and 1988. The court has certified a class action with respect to ratability claims. The Court of Appeals has affirmed the trial court's order granting class certification. An appeal to the Texas Supreme Court will be pursued. The Enron Defendants deny the Plaintiffs' claims and have asserted various affirmative defenses, including the statute of limitations. The Enron Defendants believe that they have strong legal and factual defenses, and intend to vigorously contest the claims. Although no assurances can be given, Enron believes that the ultimate resolution of these matters will not have a materially adverse effect on its financial position or results of operations.
On June 2, 1997, Enron announced the resolution of all contractual issues involving the J-Block contract in the U.K. North Sea with the J-Block producers, Phillips Petroleum Company United Kingdom Limited, BG Exploration & Production Limited and Agip (U.K.) Limited. The J-Block contracts are long-term gas contracts that an Enron subsidiary entered into in March 1993 with the J-Block producers. As consideration for amending the contract, Enron made a cash payment of approximately $440 million to the producers. Enron recorded a second quarter non- recurring contract restructuring charge of $675 million ($463 million after tax), primarily reflecting the impact of the amended contract. Such resolution concluded all J-Block litigation between Enron and the J-Block producers.
On June 3, 1997, the London Commercial Court ruled in favor of the "CATS" parties in their dispute over the availability of the CATS (Central Area Transmission System) transportation facilities. The CATS parties sued Teesside Gas Transportation Limited (TGTL), an Enron subsidiary, and Enron (on the basis of its guarantee of TGTL's obligations under the transportation agreement between TGTL and the CATS parties) for allegedly failing to make quarterly "send-or- pay" payments under the transportation agreement. TGTL had refused to make these payments based upon its position that the transportation facilities were not available as required by the contract. The effect of the Court's decision is that TGTL has released withheld "send-or-pay" payments to the CATS parties in the amount of approximately 81 million Pounds Sterling, plus interest and costs. The judgment has no effect on the above referenced settlement of the J-Block gas sales agreements. Enron is appealing the decision of the London Commercial Court in the CATS litigation. Enron believes that the ultimate resolution of this matter will not have a materially adverse effect on its financial position or results of operations.
In November 1996, an explosion occurred in or around the Humerto Vidal Building in San Juan, Puerto Rico. The explosion resulted in fatalities, bodily injuries and damage to the building and surrounding property. San Juan Gas Company, Inc. (San Juan), an Enron subsidiary, operates a natural gas distribution system in the vicinity. Although San Juan did not provide gas service to the building, the investigation report of the National Transportation Safety Board (NTSB) has tentatively concluded that the incident was caused by gas leaking from San Juan's distribution system. San Juan and Enron strongly disagree with the NTSB findings principally because the NTSB investigation (i) found no path of migration of gas from San Juan's system to the building, and (ii) discovered no scientific evidence that propane gas was the explosive fuel. Enron and San Juan have been named as defendants in a number of lawsuits filed in U.S. District Court for the district of Puerto Rico and Commonwealth courts of Puerto Rico. These suits, which seek damages for wrongful death, personal injury, business interruption and property damage, allege that negligence of Enron and San Juan caused the explosion. Enron and San Juan are vigorously contesting the claims. Although no assurances can be given, Enron believes that the ultimate resolution of these matters will not have a materially adverse effect on its financial position or results of operations.
Trojan Nuclear Plant. In early 1993, PGE ceased commercial operation of Trojan. Since plant closure, PGE has committed itself to a safe and economical transition toward a decommissioned plant. PGE has received approval of its decommissioning plan submitted to the Nuclear Regulatory Commission and Oregon Energy Facilities Siting Council. PGE's remaining cost to decommission and close Trojan of $313 million has been reflected in "Other Liabilities" in the Consolidated Balance Sheet.
Trojan Investment Recovery. In April 1996 a circuit court judge in Marion County, Oregon found that the OPUC could not authorize PGE to collect a return on its undepreciated investment in Trojan, contradicting a November 1994 ruling from the same court. The ruling was the result of an appeal of PGE's 1995 general rate order which granted PGE recovery of, and a return on, 87% of its remaining investment in Trojan.
The 1994 ruling was appealed to the Oregon Court of Appeals and stayed pending the appeal of the OPUC's March 1995 order. Both PGE and the OPUC have separately appealed the April 1996 ruling which was combined with the appeal of the November 1994 ruling at the Oregon Court of Appeals.
Enron believes that the authorized recovery of and return on the Trojan investment and decommissioning costs will be upheld and that these legal challenges will not have a materially adverse impact 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 expenses. These increased operating expenses are not expected to have a materially adverse effect on Enron's financial position or results of operations.
The EPA has informed Enron that it is a potentially responsible party at the Decorah Former Manufactured Gas Plant Site (the Decorah Site) in Decorah, Iowa, pursuant to the provisions of CERCLA. The manufactured gas plant in Decorah ceased operations in 1951. A predecessor company of Enron purchased the Decorah Site in 1963. Enron's predecessor did not operate the gas plant and sold the Decorah Site in 1965. The EPA alleges that hazardous substances were released to the environment during the period in which Enron's predecessor owned the site, and that Enron's predecessor assumed the liabilities of the company that operated the plant. Enron contests these allegations. The EPA is interested in determining whether materials from the plant have adversely affected subsurface soils at the Decorah Site. Enron has entered into a consent order with the EPA by which it has agreed, although admitting no liability, to replace affected topsoil and remove impacted subsurface soils in certain areas of the tract where the plant was formerly located. To date, the EPA has identified no other potentially responsible parties with respect to this site. Enron believes that expenses incurred in connection with this matter will not have a materially adverse effect on its financial position or results of operations.
By order dated June 27, 1995, the Florida Department of Environmental Protection approved a remedial action plan for the Enron Gas Processing Company Brooker Plant in Bradford County, Florida. Soil and groundwater at the plant site had been impacted by historical releases of hydrocarbons from the now inactive liquids extraction plant. Site remedial work commenced in 1996 and is expected to continue for several years at a total cost of approximately $5 million.
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
None.
PART II
Item 5.
Item 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED SHAREHOLDER 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 Chicago Stock Exchange and the Pacific Stock Exchange, as well as The London Stock Exchange and Frankfurt Stock Exchange.
Cumulative Second Preferred Convertible Stock
The following table indicates the high and low sales prices for the Cumulative Second Preferred Convertible Stock ("Second Preferred 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 Second Preferred Stock is also listed for trading on the Chicago Stock Exchange.
At December 31, 1997, there were approximately 58,041 record holders of common stock and 209 record holders of Second Preferred Stock.
Other information required by this item is set forth 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 1997 was $105 million compared to $584 million in 1996 and $520 million in 1995. The results of operations discussion focuses on core businesses, the new retail energy services business (primarily serving commercial and light industrial end-use customers) and items impacting comparability of operations. Core businesses include Exploration and Production (Enron Oil & Gas Company), Transportation and Distribution (Gas Pipeline Group and Portland General) and Wholesale Energy Operations and Services (Enron Capital & Trade Resources, Enron International and Enron Engineering & Construction). The results of Portland General have been included in Enron's Consolidated Financial Statements beginning July 1, 1997. See Note 2 to the Consolidated Financial Statements. Items impacting comparability are discussed in the respective segment results. Net income includes the following:
Basic and diluted earnings per share of common stock were as follows:
Income Before Interest, Minority Interests and Income Taxes The following table presents income before interest, minority interests and income taxes (IBIT) for each of Enron's operating segments (see Note 17 to the Consolidated Financial Statements):
Exploration and Production Enron's exploration and production operations are conducted by Enron Oil & Gas Company (EOG). IBIT of Exploration and Production totaled $183 million, $200 million and $241 million for 1997, 1996 and 1995, respectively.
Wellhead volume and price statistics (including intercompany amounts) are as follows:
The following analyzes the significant changes in the various components of IBIT for Exploration and Production:
Net Revenues Exploration and Production's revenues, net of gas sold in connection with natural gas marketing, increased $53 million (7%) in 1997 and $82 million (13%) in 1996. The 1997 and 1996 increases reflected both increased average wellhead natural gas prices and increased production volumes. The 1996 volumes increased from 1995 primarily from the elimination of voluntary curtailments in the United States in 1996 due to significant increases in wellhead natural gas prices. Other marketing activities, which include hedging, trading and natural gas marketing transactions by EOG, reduced net revenues by $61 million in 1997, compared with increases of $4 million in 1996 and $105 million in 1995. Net revenues also include gains on sales of crude oil and gas reserves and related assets of $9 million in 1997, $20 million in 1996 and $63 million in 1995.
Costs and Expenses Operating expenses, depreciation, depletion and amortization and taxes other than income taxes increased in 1997 and 1996 due primarily to the increased production activity.
Exploration expenses increased 15% in 1997 and 13% in 1996 as compared to the prior year, primarily as a result of increased exploratory drilling activities and lease acquisitions in North America.
Outlook EOG plans to continue its significant investments in development and certain exploration expenditures in its major producing areas in North America. In addition, EOG anticipates increased spending for the continued development of its significant international projects in India, Venezuela, Trinidad and China. Enron has hedged its net exposure to EOG's natural gas prices for 1998 production and will continue to assess opportunities for hedging future production.
Transportation and Distribution Transportation and Distribution consists of Gas Pipeline Group and Portland General. Gas Pipeline Group includes Enron's interstate natural gas pipelines, primarily Northern Natural Gas Company (Northern), Transwestern Pipeline Company (Transwestern) and Enron's 50% interest in Florida Gas Transmission Company (Florida Gas). Portland General primarily reflects the results of Portland General Electric Company (PGE) since the July 1, 1997 merger (see Note 2 to the Consolidated Financial Statements).
Gas Pipeline Group. Significant components of IBIT are as follows:
Net Revenues Revenues, net of cost of sales, of Gas Pipeline Group declined $54 million (8%) during 1997 and $26 million (3%) during 1996 as compared to the applicable preceding year. The decrease in net revenues in 1997 compared to 1996 was primarily due to the sale of natural gas liquids assets in early 1997 and the turnback of capacity at Transwestern, resulting in reduced transportation revenues beginning in November 1996. The decrease in net revenues from 1995 to 1996 was primarily a result of the sale of gathering facilities in 1995 and the first quarter of 1996. In addition, revenues decreased at Northern in 1996 as a result of a planned reduction of transition cost recoveries related to the termination of its merchant function pursuant to the Federal Energy Regulatory Commission's (FERC) Order 636.
Operating Expenses Operating expenses of Gas Pipeline Group declined $6 million (2%) during 1997, primarily due to a reduction of transition costs to be recovered in regulatory surcharges at Northern. Gas Pipeline Group's operating expenses declined $27 million (8%) in 1996 compared with 1995 due primarily to the favorable resolution of environmental contingencies previously accrued, combined with reduced expenses related to the gathering facilities sold in 1995 and early 1996 and a decrease in amortization of deferred contract reformation costs by Northern.
Depreciation and amortization declined $16 million (20%) in 1996 compared with 1995 due primarily to the sale of gathering facilities in 1995 and the first quarter of 1996.
Equity in Earnings Equity in earnings of unconsolidated subsidiaries increased $5 million (14%) during 1997 as compared to 1996 after decreasing $11 million (24%) during 1996 as compared to 1995. The increase in 1997 was primarily due to increased equity earnings related to Enron's interest in Citrus Corp., which holds Enron's 50% interest in Florida Gas. The decrease in equity earnings in 1996 was primarily due to lower earnings from Enron's interest in Trailblazer Pipeline Company due to the recognition in 1995 of income from a settlement with a transportation customer.
Items Impacting Comparability During 1997, gains of $102 million were recognized related to the sales of liquids assets, including processing plants and Enron's interest in the Enron Liquids Pipeline L.P. Gains of $90 million related to the disposition of non-strategic natural gas gathering facilities were recognized in 1996, and gains of $67 million were recorded from the sale of gathering assets and a processing facility in 1995. In 1996, reported IBIT included $18 million as a result of favorable resolution of litigation. Regulatory and contingency adjustments totaling $83 million were recorded in 1995.
Portland General. Results for Portland General have been included in Enron's Consolidated Financial Statements beginning July 1, 1997. Since that date, Portland General realized IBIT of $114 million, as follows:
Statistics for PGE for the period from July 1 through December 31, 1997 and 1996 (including amounts for 1996 for comparative purposes only) are as follows:
Outlook Transportation and Distribution should continue to provide stable earnings and cash flows during 1998, including steady growth over 1997 levels.
Various expansion projects underway or proposed by Gas Pipeline Group should contribute future earnings when completed. Over the next three years, Northern is planning expansions which would add 300-400 million cubic feet of gas per day (MMcf/d) of incremental capacity. Transwestern plans to expand its pipeline capacity and access new gas supplies by approximately 200-300 MMcf/d. Florida Gas also plans to expand its capacity by 150 MMcf/d to serve its growing markets by the year 2000. Additionally, Gas Pipeline Group will continue to monitor its overall cost structure.
PGE anticipates continuing retail customer growth in one of the fastest growing service territories in the U.S. In late 1997, PGE filed a Customer Choice Plan proposal with the Oregon Public Utility Commission (OPUC) which would give all of its customers a choice of electricity providers as early as December 1998. Under the proposed Customer Choice Plan, PGE will separate its generation business from its transmission and distribution businesses and PGE will become a regulated transmission and distribution company focused on delivering, but not selling, electricity. The separation of the generation business is proposed to be accomplished by selling PGE's generating assets, either to an Enron affiliate or third parties. In preparation for electric deregulation, PGE has begun to leverage from the operational experiences of Enron's Gas Pipeline Group which has previously transitioned from providing merchant services to providing transportation services.
Enron is unable to predict what changes may be required by the OPUC for approval or when the OPUC will approve a Customer Choice Plan.
Wholesale Energy Operations and Services Enron's Wholesale Energy Operations and Services businesses are conducted primarily by Enron Capital & Trade Resources (ECT) and Enron International (EI). These businesses provide integrated energy-related products and services to wholesale customers worldwide, including the development, construction and operation of power plants, natural gas pipelines and other energy related assets, energy commodity sales and services, risk management products and financial services. This segment also includes results of Enron Engineering & Construction (EE&C), Enron Global Power and Pipelines L.L.C. (EPP) and Enron Americas, Inc. Enron acquired the minority interest in EPP in November 1997 (see Note 2 to the Consolidated Financial Statements).
Wholesale Energy Operations and Services (Wholesale) can be categorized into four business lines: Asset Development and Construction, Cash and Physical, Risk Management and Finance and Investing. The following table reflects IBIT for each business line:
The following discussion analyzes the contributions to IBIT and the outlook for each of the business lines.
Asset Development and Construction. This line of business includes the development and construction of power plants, pipelines and other energy infrastructure, including the results of EE&C.
At December 31, 1997, the following projects were under construction:
Estimated Commercial Size/Capacity Operations Date
Pipeline Bolivia/Brazil (Phase I) 1,180 miles 1Q 1999
Power Plants Cuiaba - Brazil (Phase I) 150 MW(a) 3Q 1998 Dabhol - India (Phase I) 826 MW 4Q 1998 Piti - Guam 80 MW 1Q 1999 Sutton Bridge - U.K. 790 MW 1Q 1999 Trakya - Turkey 478 MW 1Q 1999 EcoElectrica - Puerto Rico 507 MW 4Q 1999 Nowa Sarzyna - Poland 116 MW 4Q 1999 Sarlux - Italy 551 MW 1Q 2000
(a) Megawatts.
Earnings from the asset development and construction business increased 28% in 1997 from 1996, primarily as a result of fees earned on projects in the U.K. and Puerto Rico in 1997. The earnings from this business increased 62% in 1996 compared with 1995 primarily due to increased earnings on capital employed related to development projects.
Cash and Physical. The cash and physical operations include earnings from physical contracts of one year or less involving marketing and transportation of natural gas, liquids, electricity and other commodities, earnings from the management of Enron's contract portfolio and earnings related to the operating assets of this segment, including EPP operations. Also included are the effects of actual settlements of long-term physical and notional quantity-based contracts.
Wholesale markets and transports a substantial quantity of energy commodities as reflected in the following table (including intercompany amounts):
The cash and physical business includes Enron's interest in the following operating assets:
Acquisition/ Size/Capacity Operations Date
Pipelines Houston Pipe Line - U.S. 5,243 mi/2.5 Bcf/d 2Q 1985 Transportadora de Gas del Sur - Argentina 4,104 mi/1.9 Bcf/d 4Q 1992 Louisiana Resources - U.S. 540 mi/750 MMcf/d 2Q 1993 Centragas - Colombia 357 mi/110 MMcf/d 1Q 1996 Transredes - Bolivia 3,093 mi/320 MMcf/d(a) 2Q 1997
Power Plants Puerto Quetzel - Guatemala 110 MW 1Q 1993 Teesside - U.K. 1,875 MW 1Q 1993 Batangas - Philippines 110 MW 3Q 1993 Bitterfeld - Germany 125 MW 4Q 1993 Subic Bay - Philippines 116 MW 1Q 1994 Puerto Plata - Dominican Republic 185 MW 3Q 1994, 1Q 1996 Hainan Island - China 154 MW 3Q 1996
Local Distribution Companies CEG - Brazil N/A 3Q 1997 Riogas - Brazil N/A 3Q 1997 GasPart - Brazil N/A 4Q 1997
(a) Capacity also includes 35 MB/d of liquids.
The earnings from cash and physical operations decreased 4% in 1997 as compared to 1996 primarily due to lower domestic gas and power margins in 1997 compared with 1996. Although volumes were higher in 1997, greater seasonal volatility of domestic natural gas prices provided higher margins in 1996. Domestic liquids marketing activity was also lower in 1997 compared with 1996. These decreases were partially offset by increased activity in the European markets related to natural gas and power contracts. Increased earnings from the operation of international power plants and pipelines and domestic natural gas assets also contributed to the results.
The earnings from this business increased 57% in 1996 as compared to 1995 primarily due to earnings from higher natural gas volumes and margins and increased earnings from the management of Wholesale's commodity portfolio. Earnings from the marketing and processing of natural gas liquids also increased in 1996. These increases were partially offset by a decrease in earnings from natural gas assets. Electricity volumes substantially increased as Enron continued to expand its role as an electricity marketer.
Risk Management. Wholesale's 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, including development activity related to such contracts.
Earnings from risk management increased 36% in 1997 as compared to 1996 primarily due to strong originations and related activities with utilities and independent power producers (IPPs) in the European market. This increase was partially offset by lower originations from long-term contracts in North America for both natural gas and power.
Earnings from this business decreased 46% in 1996 as compared to 1995 primarily due to lower originations from long-term contracts with domestic utilities and IPPs. Earnings from the restructuring of existing long-term contracts were also lower in 1996 as compared to 1995. These decreases were partially offset by increased originations with IPPs in the European market.
Finance and Investing. The finance and investing operations provide a variety of capital products to its worldwide customers, including volumetric production payments, loans and equity investments. These products are offered directly or through joint ventures. Financings arranged and production payments were $561 million, $755 million and $382 million in 1997, 1996 and 1995, respectively.
Additionally, the finance and investing business includes the management of Wholesale's capital investments, both operating and financial, as well as certain of Enron's equity investments. Accordingly, the results of this business include earnings from changes in the composition and market value of these investments. Market value changes result from both underlying operating strengths and favorable conditions in the equity markets. Exposures related to these investments are managed through certain hedging transactions as well as through the overall diversity of the investments.
Earnings from the finance and investing operations increased 133% in 1997 compared with 1996 due primarily to a significant increase in the market value of its investments, including the positive impact of a change in the structure of a joint venture investment, as well as increased earnings from originations.
Earnings from the finance and investing operations increased 18% in 1996 compared to 1995 primarily due to increases in the market value of its investments.
Unallocated Expenses. Net unallocated expenses such as rent, systems expenses and other support group costs increased in both 1997 and 1996 due to continued expansion into new markets and system upgrades.
Outlook Enron anticipates continued growth in Wholesale during 1998. Asset development and construction earnings are expected to increase as a result of Enron's extensive portfolio of projects in various stages of development. In the cash and physical business, volumes are expected to continue to increase. In addition, the existence of a substantial portfolio of contracts as well as the ability to benefit from the relationships between the financial and physical markets and the natural gas and electricity markets provide substantial opportunities for earnings. Earnings from risk management are expected to increase as Enron continues to pursue opportunities in the European marketplace and continues to increase integration of financial products and its energy commodity portfolio worldwide. In the finance and investing business, Enron will continue to expand its products and services in its role as a full-service provider of various types of capital. Further expansion into new products and international markets is expected to increase results in all of these businesses.
Earnings from Wholesale are dependent on the completion of transactions, some of which are individually significant, which are impacted by market conditions, the regulatory environment and customer relations. Wholesale's transactions have historically been based on a diverse product portfolio, providing a solid base of earnings. The outlook for potential future transactions is currently very favorable. Enron's strengths, including its ability to identify and respond to customer needs, access to extensive physical assets and its integrated approach to international business, are expected to result in continued earnings growth. In addition, earnings are expected from Wholesale's commodity portfolio and investments, which are subject to market fluctuations; risk related to these activities is managed using hedge transactions. See "Financial Risk Management" for a discussion of market risk related to Wholesale.
Retail Energy Services Enron Energy Services (EES) was formed in late 1996 to provide direct energy sales and services to end-use customers in the U.S. natural gas and electricity markets, particularly in the commercial and light industrial sectors. EES has participated successfully in selected natural gas and electric retail marketing pilots and continues to make significant progress in expanding its customer base and contracting activities. EES reported losses before interest, minority interests and taxes of $107 million in 1997 related to significant investments in building its sales force, developing products and services, establishing a support system to service its contracts and supporting EES's regulatory efforts.
In late 1997, Enron sold approximately 7% of its ownership of EES for $130 million, to defray startup costs and establish a valuation for this new business. The transaction resulted in a gain of $61 million, which has been reflected in Corporate and Other. This sale of EES ownership was based on a total enterprise value of $1.9 billion.
Outlook During 1998, EES will continue its focus on commercial and light industrial customers in the energy market, while developing new energy products and expanding its customer base. EES also plans to continue its efforts to improve the regulatory environment for retail gas and electricity, both on state and federal levels, strengthen its marketing and sales organization and continue to enhance its transaction support capabilities. EES expects that 1998 losses will approximate those incurred in 1997.
Corporate and Other Corporate and Other includes results of Enron Renewable Energy Corp., EOTT Energy Corp. (EOTT) and the operations of Enron's methanol and MTBE plants. Significant components of IBIT are as follows:
During 1997, Enron recorded a non-recurring charge of $675 million, primarily reflecting the impact of Enron's amended J- Block gas contract in the U.K. (see Note 14 to the Consolidated Financial Statements), and a $100 million charge primarily to reflect depressed MTBE margins on committed production. In 1996 and 1995, respectively, gains of $178 million and $367 million were recognized, primarily related to the sale of 12 million and 31 million outstanding shares of EOG stock held by Enron. The 1996 results included an $83 million reserve related to the required disposition of certain assets in connection with the merger with Portland General. The 1995 results included a $75 million charge to reflect depressed MTBE margins on committed production and $74 million of charges primarily related to the conversion of a compensation plan to more closely align employees' interests to Enron common stock.
Enron continues to assess and modify its computer systems to ensure they will operate properly in the year 2000. Enron management anticipates that these Year 2000 costs, which will be incurred over the next two years, will not have a material impact on Enron's financial position or results of operations.
Interest and Related Charges, net Interest and related charges, net, is reported net of interest capitalized of $18 million, $12 million and $10 million for 1997, 1996 and 1995, respectively. The net expense increased $127 million in 1997 after decreasing $10 million in 1996. The 1997 increase was primarily due to higher debt levels, including debt of $1.1 billion from PGE following the merger on July 1, 1997 (see Note 2 to the Consolidated Financial Statements). The 1996 decrease was primarily due to lower average interest rates combined with lower average debt balances.
Dividends on Company-Obligated Preferred Securities of Subsidiaries Dividends on company-obligated preferred securities of subsidiaries increased from $32 million in 1995 to $34 million in 1996 and $69 million in 1997, primarily due to the issuance of $215 million and $372 million of additional preferred securities by Enron subsidiaries during 1996 and 1997, respectively. Company-obligated preferred securities of subsidiaries also increased by $29 million at July 1, 1997 for securities of PGE. See Notes 2 and 9 to the Consolidated Financial Statements.
Minority Interests Minority interests increased $31 million to $75 million in 1996 compared to 1995, primarily due to the reduction of Enron's interest in EOG following the sales in 1996 and December 1995 of an aggregate 43 million shares of EOG common stock held by Enron.
Income Tax Expense Income tax expense decreased for 1997 as compared to 1996 primarily as a result of pretax losses due to the non-recurring charges for the restructuring of Enron's J-Block contract and for depressed MTBE margins on committed production. In addition, the 1997 tax provision was reduced for differences between the book and tax basis of certain asset and stock sales. Income tax expense decreased in 1996 compared with 1995 as a result of benefits from the reduction of the deferred tax liability due to the reevaluation of federal and state deferred tax requirements.
FINANCIAL CONDITION
Net cash provided by operating activities decreased $539 million in 1997 primarily as a result of a cash payment of $440 million made in connection with the resolution of the J-Block gas contract. Cash provided by operating activities increased in 1996 primarily as a result of reduced working capital requirements reflecting increased trade payables combined with an increase in the sale of trade receivables under Enron's receivables sales program at year-end 1996 as compared to 1995.
Net cash used in investing activities in 1997 primarily reflects increased capital expenditures, which total $1,413 million. See "Capital Expenditures and Equity Investments" below. Equity investments of $944 million in 1997 primarily include investments in international power and pipeline projects. Partially offsetting these uses of cash were proceeds of $473 million from the sales of assets, primarily from the sales of liquids assets. Net cash used in investing activities in 1996 reflects equity investments of $761 million and capital expenditures of $878 million. Equity investments in 1996 primarily include investments in international power and pipeline projects, EOTT and Joint Energy Development Investments, L.P. (JEDI). These uses of cash were offset by proceeds of $477 million from sales of assets, including 12 million shares of EOG common stock held by Enron and non-strategic gathering and processing assets.
Cash provided by financing activities in 1997 was generated from net issuances of $1,674 million of short- and long-term debt, $372 million of preferred securities by subsidiary companies and $555 million of subsidiary equity (see Note 7 to the Consolidated Financial Statements). These inflows were partially offset by payments of $354 million for cash dividends and $422 million for the purchase of treasury stock. Primary cash inflows from financing activities during 1996 included $282 million from the net issuance of short- and long-term debt, $215 million from the issuance of preferred securities by subsidiary companies and $102 million from the issuance of Enron common stock. Cash outflows included cash dividend payments of $281 million.
Working Capital At December 31, 1997, Enron had working capital of $257 million. If a working capital deficit should occur, Enron has credit facilities in place to fund working capital requirements. At December 31, 1997, those credit lines provided for up to $3.7 billion of committed and uncommitted credit, of which $35 million was outstanding at December 31, 1997. 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 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 and Equity Investments Capital expenditures by operating segment are as follows:
Capital expenditures increased $535 million during 1997 as compared to 1996. Increased expenditures in Exploration and Production reflect increased development expenditures in the United States and increased property acquisitions in Canada. Transportation and Distribution expenditures increased due to expansion projects by the interstate natural gas pipelines. Included in 1997 in Wholesale were send-or-pay payments totaling $167 million related to a transportation agreement in the United Kingdom.
Equity investments by the operating segments are as follows:
Equity investments increased $183 million in 1997 compared with 1996 primarily due to investments by Wholesale in Brazilian gas distribution companies.
The level of spending for capital expenditures and equity investments will vary depending upon conditions in the energy markets, related economic conditions and identified opportunities. Management expects that the capital spending program will be funded by a combination of internally generated funds, proceeds from dispositions of selected assets and short- and long-term borrowings.
FINANCIAL RISK MANAGEMENT
Wholesale offers price risk management services primarily related to commodities associated with the energy sector (natural gas, crude oil, natural gas liquids and electricity). These services are provided through a variety of financial instruments including forward contracts, which may involve physical delivery of an energy commodity, swap agreements, which may require payments to (or receipt of payments from) counterparties based on the differential between a fixed and variable price for the commodity, options and other contractual arrangements. Interest rate risks and foreign currency risks associated with the fair value of its energy commodities portfolio are managed in this segment using a variety of financial instruments, including financial futures, swaps and options.
Enron's other businesses also enter into forwards, swaps and other contracts primarily for the purpose of hedging the impact of market fluctuations on assets, liabilities, production or other contractual commitments. Changes in the market value of these hedge transactions are deferred until the gain or loss is recognized on the hedged item.
Management of the market risks associated with its portfolio of transactions is critical to the success of Enron. Therefore, comprehensive risk management processes, policies and procedures have been established to monitor and control these market risks.
Enron manages market risk on a portfolio basis, subject to parameters established by its Board of Directors. Market risks are monitored by an independent risk control group operating separately from the units that create or actively manage these risk exposures to ensure compliance with Enron's stated risk management policies. Enron's fixed price commodity contract portfolio is typically balanced to within an annual average of 1% of the total notional physical and financial transaction volumes marketed.
Enron measures the market risk in its portfolios on a daily basis utilizing value at risk and other methodologies. The quantification of market risk using value at risk provides a consistent measure of risk across diverse energy markets and products. The use of these methodologies requires a number of key assumptions including the selection of a confidence level for expected losses, the holding period for liquidation and the treatment of risks outside the value at risk methodologies, including liquidity risk and event risk. Value at risk represents an estimate of reasonably possible net losses in earnings that would be recognized on its portfolios assuming hypothetical movements in future market rates and is not necessarily indicative of actual results which may occur.
In addition to using value at risk measures, Enron performs regular scenario analyses to estimate the economic impact of a sudden market movement on the value of its portfolios (stress testing). The results of the stress testing, along with the professional judgments of experienced business and risk managers, are used to supplement the value at risk methodology and capture additional market-related risks, including liquidity, event, concentration and correlation reliance risk.
Market Risk The use of financial instruments by Enron's businesses may expose Enron to market and credit risks resulting from adverse changes in commodity and equity prices, interest rates and foreign exchange rates. For Enron's price risk management portfolio, the major market risks are discussed below:
Commodity Price Risk. Commodity price risk is a consequence of providing price risk management services to customers as well as owning and operating production facilities. As discussed above, Enron actively manages this risk on a portfolio basis to ensure compliance with Enron's stated risk management policies. Forwards, futures, swaps and options are utilized to alter Enron's consolidated exposure to price fluctuations related to production from its production facilities.
Interest Rate Risk. Interest rate risk is also a consequence of providing price risk management services to customers and having variable rate debt obligations, as changing interest rates impact the discounted value of future cash flows. Enron utilizes swaps, forwards, futures and options to minimize its interest rate risk.
Foreign Currency Exchange Rate Risk. Foreign currency exchange rate risk is the result of Enron's international operations and price risk management services provided to its worldwide customer base. The primary purpose of Enron's foreign currency hedging activities is to protect against the volatility associated with foreign currency purchase and sale transactions. Enron primarily utilizes forward exchange contracts, futures and purchased options to reduce Enron's risk profile.
Equity Risk. Equity risk arises from the finance and investing operations of Wholesale, which provides capital to customers through equity participations in various investment activities. Enron manages this risk on an overall basis, including the use of futures, forwards, swaps and options, to ensure compliance with Enron's stated risk management policies.
Accounting Policies Accounting policies for price risk management and hedging activities are described in Note 1 to the Consolidated Financial Statements.
Value at Risk Enron has performed an entity-wide value at risk analysis of virtually all of Enron's financial assets and liabilities. The value at risk for commodity, interest rate and foreign currency exposures described above is calculated using a "Monte Carlo" simulation of delta/gamma positions which captures a significant portion of the exposure related to option positions. The value at risk for equity exposure discussed above is based on J.P. Morgan's RiskMetrics(TM) approach utilizing historical estimates of volatility and correlation. Both value at risk methods utilize a one-day holding period and a 95% confidence level. Cross- commodity correlations are used as appropriate.
The following table illustrates the value at risk for each component of market risk at December 31, 1997:
CAPITALIZATION
Total capitalization at December 31, 1997 was $14.0 billion. Debt as a percentage of total capitalization increased to 44.6% at December 31, 1997 as compared to 39.8% at December 31, 1996. The increase primarily reflects increased debt, partially offset by the issuance during 1997 of approximately 50.5 million and 11.5 million shares of common stock in connection with the acquisitions of Portland General Corporation and the minority interest in EPP, respectively (see Note 2 to the Consolidated Financial Statements). Assuming the conversion in late 1998 of 10.5 million Exchangeable Notes into EOG shares held by Enron, the pro-forma debt to capitalization percentage would be approximately 43.5% at December 31, 1997.
INFORMATION REGARDING FORWARD LOOKING STATEMENTS
This Annual Report includes forward looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Although Enron believes that its expectations are based on reasonable assumptions, it can give no assurance that its goals will be achieved. Important factors that could cause actual results to differ materially from those in the forward looking statements herein include political developments in foreign countries, the ability to penetrate new retail natural gas and electricity markets in the United States and Europe, the timing and extent of changes in commodity prices for crude oil, natural gas, electricity and interest rates, the extent of EOG's success in acquiring oil and gas properties and in discovering, developing and producing reserves, the timing and success of Enron's efforts to develop international power, pipeline and other infrastructure projects and conditions of the capital markets and equity markets during the periods covered by the forward looking statements.
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 directors who are nominees for election as directors at Enron's Annual Meeting of Shareholders to be held on May 5, 1998 is set forth under the caption entitled "Election of Directors" 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".
Section 16(a) of the Securities Exchange Act of 1934 requires Enron's executive officers and directors, and persons who own more than 10% of a registered class of Enron's equity securities, to file reports of ownership and changes in ownership with the SEC and the New York Stock Exchange. Based solely on its review of the copies of such reports received by it, or written representations from certain reporting persons that no Forms 5 were required for those persons, Enron believes that during 1997, its executive officers, directors and greater than 10% shareholders complied with all applicable filing requirements, with the exception of one 10% shareholder who did not timely file one report containing one transaction.
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 Shareholders, 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 1997; Aggregated Stock Option/SAR Exercises During 1997 and Stock Option/SAR Values as of December 31, 1997; Long-Term Incentive Plan - Awards in 1997; Retirement and Supplemental Benefit Plans; Severance Plans; 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 - Security 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 February 15, 1998", 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 "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 - Amended and Restated Articles of Incorporation of Enron (Annex E to the Proxy Statement/Prospectus included in Enron's Registration Statement on Form S-4 - File No. 333-13791).
*3.02 - Articles of Merger of Enron Oregon Corp., an Oregon corporation, and Enron Corp., a Delaware corporation (Exhibit 3.02 to Post-Effective Amendment No. 1 to Enron's Registration Statement on Form S-3 - File No. 33-60417).
*3.03 - Articles of Merger of Enron Corp., an Oregon corporation, and Portland General Corporation, an Oregon corporation (Exhibit 3.03 to Post-Effective Amendment No. 1 to Enron's Registration Statement on Form S-3 - File No. 33-60417).
*3.04 - Bylaws of Enron (Exhibit 3.04 to Post-Effective Amendment No. 1 to Enron's Registration Statement on Form S-3 - File No. 33-60417).
*3.05 - Form of Series Designation for the Enron Convertible Preferred Stock (Annex F to the Proxy Statement/Prospectus included in Enron's Registration Statement on Form S-4 - File No. 333-13791).
*3.06 - Form of Series Designation for the Enron 9.142% Preferred Stock (Annex G to the Proxy Statement/Prospectus included in Enron's Registration Statement on Form S-4 - File No. 333-13791).
*3.07 - Statement of Resolutions Establishing Series A Junior Voting Convertible Preferred Stock (Exhibit 3.07 to Enron's Registration Statement on Form S-3 - File No. 333-44133).
*4.01 - Indenture dated as of November 1, 1985, between Enron and Harris Trust and Savings Bank, as supplemented and amended by the First Supplemental Indenture dated as of December 1, 1995 (Form T-3 Application for Qualification of Indentures under the Trust Indenture Act of 1939, File No. 22-14390, filed October 24, 1985; Exhibit 4(b) to Form S-3 Registration Statement No. 33-64057 filed on November 8, 1995). 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 - Supplemental Indenture, dated as of May 8, 1997, by and among Enron Corp., Enron Oregon Corp. and Harris Trust and Savings Bank, as Trustee (Exhibit 4.02 to Post-Effective Amendment No. 1 to Enron's Registration Statement on Form S-3, File No. 33-60417).
*4.03 - Form of Supplemental Indenture, dated as of September 1, 1997, between Enron Corp. and Harris Trust and Savings Bank, as Trustee (Exhibit 4.03 to Enron Registration Statement on Form S-3, File No. 333-35549).
*4.04 - 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).
*4.05 - 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).
*4.06 - 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).
*4.07 - Articles of Association of Enron Capital LLC (Exhibit 9 to Enron Corp. Form 8-K dated November 12, 1993).
*4.08 - 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).
*4.09 - 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 10.45
*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 - First Amendment to Enron Executive Supplemental Survivor Benefits Plan (Exhibit 10.02 to Enron Form 10-K for 1995, File No. 1-3423).
*10.03 - Enron Corp. 1988 Stock Plan (Exhibit 4.3 to Form S-8 Registration Statement No. 33-27893).
*10.04 - Second Amendment to Enron Corp. 1988 Stock Plan (Exhibit 10.04 to Enron Corp. Form 10-K for 1996, File No. 1-3423).
*10.05 - Enron Corp. 1988 Deferral Plan (Exhibit 10.19 to Enron Form 10-K for 1987, File No. 1-3423).
*10.06 - First Amendment to Enron Corp. 1988 Deferral Plan (Exhibit 10.06 to Enron Form 10-K for 1995, File No. 1-3423).
*10.07 - Second Amendment to Enron Corp. 1988 Deferral Plan (Exhibit 10.07 to Enron Form 10-K for 1995, File No. 1-3423).
*10.08 - Third Amendment to Enron Corp. 1988 Deferral Plan (Exhibit 10.09 to Enron Form 10-K for 1996, File No. 1-3423).
*10.09 - Fourth Amendment to Enron Corp. 1988 Deferral Plan (Exhibit 10.10 to Enron Form 10-K for 1996, File No. 1-3423).
*10.10 - Fifth Amendment to Enron Corp. 1988 Deferral Plan (Exhibit 10.11 to Enron Form 10-K for 1996, File No. 1-3423).
*10.11 - Enron Corp. 1991 Stock Plan (Exhibit 10.08 to Enron Form 10-K for 1991, File No. 1-3423).
*10.12 - Amended and Restated Enron Corp. 1991 Stock Plan (Exhibit A to Enron Proxy Statement filed pursuant to Section 14(a) on March 24, 1997).
10.13 - First Amendment to Enron Corp. Amended and Restated 1991 Stock Plan.
10.14 - Second Amendment to Enron Corp. Amended and Restated 1991 Stock Plan.
*10.15 - Enron Corp. 1992 Deferral Plan (Exhibit 10.09 to Enron Form 10-K for 1991, File No. 1-3423).
*10.16 - First Amendment to Enron Corp. 1992 Deferral Plan (Exhibit 10.10 to Enron Form 10-K for 1995, File No. 1-3423).
*10.17 - Second Amendment to Enron Corp. 1992 Deferral Plan (Exhibit 10.11 to Enron Form 10-K for 1995, File No. 1-3423).
*10.18 - Enron Corp. Directors' Deferred Income Plan (Exhibit 10.09 to Enron Form 10-K for 1992, File No. 1-3423).
*10.19 - Split Dollar Life Insurance Agreement between Enron and the KLL and LPL Family Partnership, Ltd., dated April 22, 1994 (Exhibit 10.17 to Enron Form 10-K for 1994, File No. 1-3423).
*10.20 - Employment Agreement between Enron Corp. and Kenneth L. Lay, executed December 18, 1996 (Exhibit 10.25 to Enron Form 10-K for 1996, File No. 1-3423).
*10.21 - 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).
*10.22 - 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).
*10.23 - 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).
*10.24 - Fourth Amendment to Consulting Services Agreement between Enron and John A. Urquhart dated as of May 9, 1994 (Exhibit 10.35 to Enron Form 10-K for 1995, File No. 1-3423).
*10.25 - Fifth Amendment to Consulting Services Agreement between Enron and John A. Urquhart (Exhibit 10.36 to Enron Form 10-K for 1995, File No. 1-3423).
*10.26 - Sixth Amendment to Consulting Services Agreement between Enron and John A. Urquhart (Exhibit 10.37 to Enron Form 10-K for 1995, File No. 1-3423).
10.27 - Seventh Amendment to Consulting Services Agreement between Enron and John A. Urquhart, dated October 27, 1997.
*10.28 - 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).
*10.29 - First Amendment to Employment Agreement between Enron and James V. Derrick, Jr., dated May 2, 1994 (Exhibit 10.53 to Enron Form 10-K for 1994, File No. 1-3423).
*10.30 - Enron Corp. Performance Unit Plan (Exhibit A to Enron Proxy Statement filed pursuant to Section 14(a) on March 25, 1994).
*10.31 - Enron Corp. Annual Incentive Plan (Exhibit B to Enron Proxy Statement filed pursuant to Section 14(a) on March 25, 1994).
*10.32 - 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).
*10.33 - First Amendment to Enron Corp. Performance Unit Plan (Exhibit 10.46 to Enron Form 10-K for 1995, File No. 1-3423).
*10.34 - Enron Corp. Restated 1994 Deferral Plan (Exhibit 4.3 to Enron Form S-8 Registration Statement, File No. 333-48193).
*10.35 - Employment Agreement between Enron Power Corp. and Thomas E. White dated July 1, 1990 (Exhibit 10.59 to Enron Form 10-K for 1996, File No. 1-3423).
*10.36 - First Amendment, dated September 9, 1991, to Employment Agreement between Enron Power Corp. and Thomas E. White dated July 1, 1990 (Exhibit 10.60 to Enron Form 10-K for 1996, File No. 1-3423).
*10.37 - Second Amendment, dated May 2, 1994, to Employment Agreement between Enron Power Corp. and Thomas E. White dated July 1, 1990 (Exhibit 10.61 to Enron Form 10-K for 1996, File No. 1-3423).
*10.38 - Third Amendment, dated January 3, 1997, to Employment Agreement between Enron Power Corp. and Thomas E. White dated July 1, 1990 (Exhibit 10.62 to Enron Form 10-K for 1996, File No. 1-3423).
*10.39 - Employment Agreement between Enron Capital Trade & Resources Corp. and Jeffrey K. Skilling, dated January 1, 1996 (Exhibit 10.63 to Enron Form 10-K for 1996, File No. 1- 3423).
*10.40 - First Amendment effective January 1, 1997, by and among Enron Corp., Enron Capital & Trade Resources Corp., and Jeffrey K. Skilling, amending Employment Agreement between Enron Capital & Trade Resources Corp. and Jeffrey K. Skilling dated January 1, 1996 (Exhibit 10.64 to Enron Form 10-K for 1996, File No. 1-3423).
10.41 - Split Dollar Agreement between Enron and Jeffrey K. Skilling dated May 23, 1997.
10.42 - Second Amendment effective October 13, 1997, to Employment Agreement between Enron Corp. and Jeffrey K. Skilling.
10.43 - Loan Agreement effective October 13, 1997, between Enron Corp. and Jeffrey K. Skilling.
*10.44 - Employment Agreement dated July 20, 1996 (effective July 1, 1997) between Enron and Ken L. Harrison (Exhibit 10.1 to Post- Effective Amendment No. 1 to Enron's Registration Statement on Form S-4, File No. 333-13791).
10.45 - Executive Employment Agreement between Stanley C. Horton and Enron Operations Corp., effective as of October 1, 1996.
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, 1998.
24 - Powers of Attorney for the directors signing this Form 10-K.
27 - Financial Data Schedule.
* Asterisk indicates exhibits incorporated by reference.
(b) Reports on Form 8-K
No reports on Form 8-K were filed by Enron during the last quarter of 1997.
ENRON CORP.
Page No.
Consolidated Financial Statements
Report of Independent Public Accountants
Consolidated Income Statement for the years ended December 31, 1997, 1996 and 1995
Consolidated Balance Sheet as of December 31, 1997 and 1996
Consolidated Statement of Cash Flows for the years ended December 31, 1997, 1996 and 1995
Consolidated Statement of Changes in Shareholders' Equity Accounts for the years ended December 31, 1997, 1996 and 1995
Notes to the Consolidated Financial Statements
Financial Statements Schedule
Report of Independent Public Accountants on Financial Statements Schedule 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. (an Oregon corporation) and subsidiaries as of December 31, 1997 and 1996, and the related consolidated statements of income, cash flows and changes in shareholders' equity for each of the three years in the period ended December 31, 1997. 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, 1997 and 1996, and the results of their operations, cash flows and changes in shareholders' equity for each of the three years in the period ended December 31, 1997, in conformity with generally accepted accounting principles.
Arthur Andersen LLP
Houston, Texas February 23, 1998
ENRON CORP. AND SUBSIDIARIES NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
1 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Consolidation Policy and Use of Estimates. The accounting and financial reporting policies of Enron Corp. and its subsidiaries conform to generally accepted accounting principles and prevailing industry practices. The consolidated financial statements include the accounts of all majority-owned subsidiaries of Enron Corp. after the elimination of significant intercompany accounts and transactions.
The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
"Enron" is used from time to time herein as a collective reference to Enron Corp. and its subsidiaries and affiliates. The businesses of Enron are conducted by Enron Corp.'s subsidiaries and affiliates whose operations are managed by their respective officers.
Cash Equivalents. Enron records as cash equivalents all highly liquid short-term investments with original maturities of three months or less.
Depreciation, Depletion and Amortization. The provision for depreciation and amortization with respect to operations other than oil and gas producing activities is computed using the straight-line or regulatorily mandated method, based on estimated economic lives. Composite depreciation rates are applied to functional groups of property having similar economic characteristics. The cost of utility property units retired, other than land, is charged to accumulated depreciation.
Provisions for depreciation, depletion and amortization of proved oil and gas properties are calculated using the units-of- production method.
Income Taxes. Enron accounts for income taxes using an asset and liability approach under which 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 4).
Earnings Per Share. In accordance with Statement of Financial Accounting Standards (SFAS) No. 128 - "Earnings per Share," basic earnings per share is computed based upon the weighted-average number of common shares outstanding during the periods. Diluted earnings per share is computed based upon the weighted-average number of common shares plus the assumed issuance of common shares for all potentially dilutive securities. Common shares held by the Enron Corp. Flexible Equity Trust are not included in the computation of earnings per share until such shares are released to fund employee benefits. See Note 10 for additional information and a reconciliation of the basic and diluted earnings per share computations.
Accounting for Price Risk Management. Enron engages in price risk management activities for both trading and non-trading purposes. Financial instruments utilized in connection with trading activities are accounted for using the mark-to-market method. Under the mark-to-market method of accounting, forwards, swaps, options 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, restructuring and the impact of price movements) are recognized as net gains or losses in "Other Revenues." 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. The values 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. Prepaid transportation costs are included in "Other Assets" in the Consolidated Balance Sheet.
Financial instruments are also utilized for non-trading purposes to hedge the impact of market fluctuations on assets, liabilities, production and other contractual commitments. Hedge accounting is utilized in non-trading activities when there is a high degree of correlation between price movements in the derivative and the item designated as being hedged. In instances where the anticipated correlation of price movements does not occur, hedge accounting is terminated and future changes in the value of the financial instruments are recognized as gains or losses. If the hedged item is sold, the value of the financial instrument is recognized in income. Gains and losses on financial instruments used for hedging purposes are recognized in the Consolidated Income Statement in the same manner as the hedged item and are recognized in the Consolidated Balance Sheet as "Other Assets" or "Other Liabilities".
The cash flow impact of financial instruments is reflected as cash flows from operating activities in the Consolidated Statement of Cash Flows. See Note 3 for further discussion of Enron's price risk management activities.
Accounting for Oil and Gas Producing Activities. Enron accounts for oil and gas exploration and production activities under the successful efforts method of accounting. All development wells and related production equipment and lease acquisition costs are capitalized when incurred. Unproved properties are assessed regularly and any impairment in value is recognized as appropriate. Lease rentals and exploration costs, other than the costs of drilling exploratory wells, are expensed as incurred. Unsuccessful exploratory wells are expensed when determined to be non-productive.
Gains and losses associated with the sale of natural gas and crude oil reserves in place with related assets are classified as "Other Revenues" in the Consolidated Income Statement.
Accounting for Development Activity. Enron capitalizes project development costs which may be recovered through development cost reimbursements from joint venture partners or other third parties, written off against development fees received or included as part of an investment in those ventures in which Enron continues to participate. Accumulated project development costs are otherwise expensed in the period that management determines it is probable that the costs will not be recovered.
Development revenue results from development fees, recognized when realizable under the development agreement; long-term construction contracts, recognized using the percentage-of- completion method; and the operation and ownership of various projects. 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.
Investments in Unconsolidated Subsidiaries. Investments in unconsolidated subsidiaries are accounted for by the equity method, except for certain equity investments resulting from Enron's merchant banking activities which are included at market value in "Other Investments" in the Consolidated Balance Sheet. The valuation methodologies utilize market values of publicly- traded securities, independent appraisals and cash flow analyses.
Reclassifications. Certain reclassifications have been made to the consolidated financial statements for prior years to conform with the current presentation.
2 BUSINESS ACQUISITIONS
Effective July 1, 1997, Enron merged with Portland General Corporation (PGC) in a stock-for-stock transaction. PGC, through its wholly-owned subsidiary Portland General Electric Company (PGE), serves retail electric customers in northwest Oregon as well as wholesale electricity customers throughout the western United States. Enron issued approximately 50.5 million common shares, valued at $36.88 per share, to shareholders of PGC in a ratio of 0.9825 share of Enron common stock for each share of PGC common stock and assumed PGC's outstanding debt of approximately $1.1 billion. In connection with the merger, Enron reincorporated in Oregon and reissued its capital stock without par value.
On November 18, 1997, Enron acquired the minority interest in Enron Global Power & Pipelines L.L.C. (EPP) in a stock-for-stock transaction. Enron issued approximately 11.5 million common shares, valued at $36.09 per share, to shareholders of EPP in a ratio of 0.9189 share of Enron common stock for each EPP share held. Additionally, during 1997, Enron acquired renewable energy, telecommunications and energy management businesses for cash, Enron and subsidiary stock and notes.
Enron has accounted for these acquisitions using the purchase method of accounting as of the effective date of each transaction. Accordingly, the purchase price of each transaction has been allocated to the assets and liabilities acquired based upon the estimated fair value of those assets and liabilities as of the acquisition date. The excess of the aggregate purchase price over estimated fair value of the net assets acquired, approximately $1.8 billion, has been reflected as goodwill in the Consolidated Financial Statements and is being amortized on a straight-line basis over 30 to 40 years. Assets acquired, liabilities assumed and consideration paid as a result of businesses acquired were as follows:
The allocation of purchase price related to the determination of reserves for certain contractual and legal contingencies for the PGC merger is preliminary pending completion of Enron's final studies and evaluations. Enron does not anticipate that the final evaluation of these issues will materially affect the allocation of the purchase price.
The following summary presents unaudited pro forma consolidated results of operations as if the business acquisitions had occurred at the beginning of each period presented. The pro forma results are for illustrative purposes only and are not necessarily indicative of the operating results that would have occurred had the business acquisitions been consummated at that date, nor are they necessarily indicative of future operating results.
3 PRICE RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
Trading Activities. Enron, through its Wholesale Energy Operations and Services segment (Wholesale), offers price risk management services to the energy sector through a variety of financial and other 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 commodity, options and other contractual arrangements. Interest rate risks and foreign currency risks associated with the fair value of the energy commodities portfolio are managed using a variety of financial instruments, including financial futures.
Notional Amounts and Terms. The notional amounts and terms of these financial instruments at December 31, 1997 are shown below (volumes in trillions of British thermal units equivalent (TBtue), dollars in millions):
Wholesale includes sales and purchase commitments associated with contracts based on market prices totaling 3,725 TBtue, with terms extending up to 18 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 Enron's exposure to market or credit risks. The maximum terms in years detailed above are not indicative of likely future cash flows as these positions may be offset in the markets at any time in response to the company's risk management needs.
The volumetric weighted average maturity of Enron's fixed price portfolio as of December 31, 1997 was approximately 2.7 years.
Fair Value. The fair value of the financial instruments related to price risk management activities as of December 31, 1997, which include energy commodities and the related foreign currency and interest rate instruments, and the average fair value of those instruments held during the year are set forth below:
The net gain arising from price risk management activities for 1997 was $360 million.
Credit Risk. In conjunction with the valuation of its financial instruments, Enron provides reserves for risks associated with such activity, including 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. Enron maintains credit policies with regard to its counterparties that management believes significantly minimize overall credit risk. These policies include an evaluation 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. The counterparties associated with assets from price risk management activities as of December 31, 1997 and 1996 are summarized as follows:
This concentration of counterparties may impact Enron'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. Based on Enron's policies, its exposures and its credit and other reserves, Enron does not anticipate a materially adverse effect on financial position or results of operations as a result of counterparty nonperformance.
Non-Trading Activities. Enron's other businesses also enter into swaps and other contracts primarily for the purpose of hedging the impact of market fluctuations on assets, liabilities, production or other contractual commitments.
Interest Rate Swaps. At December 31, 1997, Enron had entered into interest rate swap agreements with a notional principal amount of $2.8 billion to manage interest rate exposure. Swap agreements relating to notional amounts of $1.0 billion and $1.8 billion are scheduled to terminate in 1998 and thereafter, respectively.
Energy Commodity Price Swaps. At December 31, 1997, Enron was a party to energy commodity price swaps covering 141 TBtu, 4 TBtu and 42 TBtu of natural gas for the years 1998, 1999 and the period 2000 through 2005, respectively, and 2 million and 1 million barrels of crude oil for the years 1998 and 1999, respectively.
Credit Risk. While notional amounts are used to express the volume of various financial instruments, the amounts potentially subject to credit risk, in the event of nonperformance by the third parties, are substantially smaller. Counterparties to forwards, futures and other contracts are equivalent to 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.
Enron has concentrations of customers in the electric and gas utility and oil and gas exploration and production 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 its portfolio of receivables is well diversified and that such diversification minimizes any potential credit risk. Receivables are generally not collateralized.
Financial Instruments. The carrying amounts and estimated fair values of Enron's financial instruments, excluding trading activities which are marked to market, at December 31, 1997 and 1996 were as follows:
Enron uses the following methods and assumptions in estimating fair values: (a) long-term debt - the carrying amount of variable- rate debt approximates fair value, the fair value of marketable debt is based on quoted market prices, and the fair value of other debt is based on the discounted present value of cash flows using Enron's current borrowing rates; (b) Company-obligated preferred securities of subsidiaries - the fair value is based on quoted market prices; and (c) interest rate swaps and energy commodity price swaps - estimated fair values have been determined using available market data and valuation methodologies. Judgment is necessarily required in interpreting market data and the use of different market assumptions or estimation methodologies may affect the estimated fair value amounts.
The fair market value of cash and cash equivalents, trade and other receivables, accounts payable, equity investments accounted for at fair value and equity swaps are not materially different from their carrying amounts.
Guarantees of liabilities of unconsolidated entities and residual value guarantees have no carrying value and fair values which are not readily determinable (see Note 15).
4 INCOME TAXES
The components of income before income taxes are as follows:
Total income tax expense (benefit) is summarized as follows:
The differences between taxes computed at the U.S. federal statutory tax rate and Enron's effective income tax rate are as follows:
The principal components of Enron's net deferred income tax liability are as follows:
Enron has an alternative minimum tax (AMT) credit carryforward of approximately $247 million which can be used to offset regular income taxes payable in future years. The AMT credit has an indefinite carryforward period.
Enron has a consolidated net operating loss carryforward for federal tax purposes of approximately $745 million which will begin to expire in 2011. Enron has a net operating loss carryforward applicable to non-U.S. subsidiaries of approximately $300 million that can be carried forward indefinitely. The benefits of these net operating losses have been recognized as a deferred tax asset.
U.S. and foreign income taxes have been provided for earnings of foreign subsidiary companies that are expected to be remitted to the U.S. Foreign subsidiaries' cumulative undistributed earnings of approximately $300 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.
5 SUPPLEMENTAL CASH FLOW INFORMATION
Cash paid for income taxes and interest expense, including fees incurred on sales of accounts receivable, is as follows:
During 1997, Enron issued common stock in connection with business acquisitions. See Note 2.
In March 1995, a subsidiary of Enron Oil & Gas Company (EOG) issued redeemable preferred stock with a liquidation/redemption value of $19 million in exchange for certain oil and gas properties. These preferred shares were exchanged in 1995 for 633,333 shares of Enron's common stock.
6 CREDIT FACILITIES AND DEBT
Enron has credit facilities with domestic and foreign banks which provide for an aggregate of $1.5 billion in long-term committed credit and $1.4 billion in short-term committed credit. Expiration dates of the committed facilities range from May 1998 to June 2002. 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 1997, $25 million was outstanding under these facilities.
Enron has also entered into agreements which provide for uncommitted lines of credit totaling $817 million at December 31, 1997. 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, 1997, $10 million was outstanding under the uncommitted lines.
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, 1997 and 1996, short-term borrowings of $825 million and $298 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, 1997 and 1996, $462 million and $175 million, respectively, of long-term debt due within one year remained classified as long-term. Weighted average interest rates on short-term debt outstanding at December 31, 1997 and 1996 were 6.0% and 7.0%, respectively.
Detailed information on long-term debt is as follows:
The indenture securing PGE's First Mortgage Bonds constitutes a direct first mortgage lien on substantially all electric utility property and franchises, other than expressly excepted property.
The Enron 6.25% Exchangeable Notes are mandatorily exchangeable in December 1998 into shares of EOG common stock at a specified exchange rate or, at Enron's option, for cash with an equal value. Enron currently intends to satisfy the exchange obligation with shares of EOG common stock.
The aggregate annual maturities of long-term debt outstanding at December 31, 1997 were $462 million, $508 million, $161 million, $664 million and $180 million for 1998 through 2002, respectively.
7 MINORITY INTEREST
Enron's minority interest primarily includes EOG and EPP prior to Enron's acquisition of the EPP minority interest in November 1997 (see Note 2).
Also in 1997, Enron and a third-party investor contributed approximately $579 million and $500 million, respectively, for interests in an Enron-controlled joint venture. The joint venture purchased 250,000 shares of junior convertible preferred stock from Enron and made demand loans to Enron. Each share of junior convertible preferred stock has a cumulative, market-based dividend, is convertible at the option of the holder (currently the Enron-controlled joint venture) initially into 100 shares of Enron stock, subject to certain adjustments, and has a liquidation value of $4,000 per share, subject to certain adjustments. The joint venture is a separate legal entity from Enron and has separate assets and liabilities. Absent certain defaults or other specified events, Enron has the option to acquire the investor's interest in the joint venture. If Enron does not acquire the investor's interest before December 2002, or earlier upon certain specified events, the joint venture will liquidate its assets and dissolve. The joint venture is included in Enron's consolidated financial statements and the third-party investor's investment in the joint venture is included in minority interest.
8 UNCONSOLIDATED SUBSIDIARIES
Enron's investment in and advances to unconsolidated subsidiaries which are accounted for by the equity method is as follows:
Enron's equity in earnings (losses) of unconsolidated subsidiaries is as follows:
Summarized combined financial information of Enron's unconsolidated subsidiaries is presented below:
9 PREFERRED STOCK
Preferred Stock. Following Enron's reincorporation in Oregon on July 1, 1997, Enron has authorized 16,500,000 shares of preferred stock, no par value. At December 31, 1997, Enron had outstanding 1,337,645 shares of Cumulative Second Preferred Convertible Stock (the Convertible Preferred Stock), no par value. The Convertible Preferred Stock 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 Convertible Preferred Stock were converted to common stock. Each share of the Convertible Preferred 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 1997, 1996 and 1995, 33,069 shares, 4,780 shares and 29,489 shares, respectively, of the Convertible Preferred Stock were converted into common stock.
Company-Obligated Preferred Securities of Subsidiaries. Summar ized information for Enron's Company-Obligated Preferred Securities of Subsidiaries is as follows:
10 COMMON STOCK
Earnings Per Share. The computation of basic and diluted earnings per share is as follows:
Forward Contracts and Options. At December 31, 1997, Enron had forward contracts to purchase 6.7 million shares of Enron Corp. common stock at an average price of $42.00 per share. Enron may settle the forward contracts in cash or an equivalent value of Enron common stock until April 2001. Shares potentially deliverable to the counterparty under the contracts are assumed to be outstanding in calculating diluted earnings per share.
In 1997, Enron granted options to EOG to purchase 3.2 million shares of Enron common stock (exercise price of $39.1875) in connection with certain agreements between Enron and EOG. The options vested 25% immediately with 15% vesting in 1998 and the remainder vesting equally in 1999 through 2004.
Stock Option Plans. Enron applies Accounting Principles Board (APB) Opinion 25 and related interpretations in accounting for its stock option plans. In accordance with APB Opinion 25, no compensation expense has been recognized for the fixed stock option plans. Compensation expense charged against income for the restricted stock plan for 1997, 1996 and 1995 was $14 million, $4 million and $2 million, respectively. Had compensation cost for Enron's stock option compensation plans been determined based on the fair value at the grant dates for awards under those plans consistent with SFAS No. 123 - "Accounting for Stock-Based Compensation," Enron's net income and earnings per share would have been $66 million ($0.18 per share basic, $0.18 per share diluted) in 1997, $562 million ($2.22 per share basic, $2.07 per share diluted) in 1996 and $514 million ($2.05 per share basic, $1.92 per share diluted) in 1995.
Because the SFAS No. 123 method of accounting has not been applied to options granted prior to January 1, 1995, the resulting pro forma compensation cost may not be representative of the pro forma amounts to be expected in future years.
The fair value of each option grant is estimated on the date of grant using the Black-Scholes option-pricing model with weighted-average assumptions for grants in 1997, 1996 and 1995, respectively: (i) dividend yield of 2.5%, 2.3% and 2.4%; (ii) expected volatility of 17.4%, 23.8% and 24.3%; (iii) risk-free interest rates of 5.9%, 5.9% and 6.4%; and (iv) expected lives of 3.7 years, 4.0 years and 3.7 years.
Enron has four fixed option 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. 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. The Plans provide for options to be granted with a stock appreciation rights feature; however, Enron does not presently intend to issue options with this feature. Under the Plans, Enron may grant options with a maximum term of 10 years. Options vest under varying schedules.
Summarized information for Enron's Plans is as follows:
The following table summarizes information about stock options outstanding at December 31, 1997 (shares in thousands):
Restricted Stock Plan. Under Enron's Restricted Stock Plan, participants may be granted stock without cost to the participant. The shares issued under this plan vest to the participants at various times ranging from immediate vesting to vesting at the end of a five-year period. The following summarizes shares of restricted stock under this plan:
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. During 1997, 1996 and 1995, respectively, 258,658 shares, 2,233,867 shares and 1,049,403 shares were released to fund employee benefits.
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. The benefit accrual is in the form of a cash balance of 5% of annual base pay beginning January 1, 1996. Prior to 1996, the benefit formula was based on final average pay and years of service.
Portland General has a noncontributory defined benefit pension plan (the Portland General Plan) covering substantially all of its employees. Benefits under the Plan are based on years of service, final average pay and covered compensation.
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. All shares included in the ESOP have been allocated to the employee accounts. At December 31, 1997 and 1996, 13,508,794 shares and 15,976,195 shares, respectively, of Enron common stock were held by the ESOP, a portion of which may be used to offset benefits under the Enron Plan.
The components of pension expense are as follows:
The measurement date of the Enron Plan and the ESOP is September 30, and the measurement date of the Portland General Plan is December 31. The funded status as of the valuation date of the Enron Plan, the Portland General Plan and the ESOP reconciles with the amount detailed below which is included in "Other Assets" on the Consolidated Balance Sheet.
Assets of the Enron Plan and the Portland General 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 extent required by federal tax regulations.
12 BENEFITS OTHER THAN PENSIONS
Enron provides certain medical, life insurance and dental benefits to eligible employees and their eligible dependents. Benefits are provided under the provisions of contributory defined dollar benefit plans. Enron is currently funding that portion of its obligations under its postretirement benefit plans which are expected to be recoverable through rates by its regulated pipelines and electric utility operations.
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 expense are as follows:
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 $9 million and $1 million, respectively.
Additionally, Enron maintains various incentive based compensation plans for which participants may receive a combination of cash, restricted stock or stock options based upon the achievement of certain performance goals.
13 RATES AND REGULATORY ISSUES
Rates and regulatory issues related to certain of Enron's natural gas pipelines and its electric utility operations are subject to final determination by various regulatory agencies. The domestic interstate pipeline operations are regulated by the Federal Energy Regulatory Commission (FERC) and the electric utility operations are regulated by the FERC and the Oregon Public Utilities Commission (OPUC). As a result, these operations are subject to the provisions of SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation," which recognizes the economic effects of regulation and, accordingly, Enron has recorded regulatory assets and liabilities related to such operations.
The regulated pipelines operations' net regulatory assets at December 31, 1997 and 1996, respectively, were $283 million and $312 million, which included transition costs incurred related to FERC Order 636 of $41 million and $86 million. The regulatory assets related to the FERC Order 636 transition costs are scheduled to be primarily recovered from customers by the end of 1998, while the remaining assets are expected to be recovered over varying time periods.
The electric utility operations' net regulatory assets at December 31, 1997, were $561 million. Based on rates in place at December 31, 1997, Enron estimates that it will collect the majority of these regulatory assets within the next 10 years and substantially all of these regulatory assets within the next 20 years.
Pipeline Operations. Enron's regulated pipelines have all successfully completed their transitions under FERC Order 636. Any future transition costs not recoverable through the pipelines' FERC tariffs are not expected to be substantial.
Electric Utility Operations. On September 2, 1997 and December 1, 1997, pursuant to the OPUC's condition to its approval of the Enron/PGC merger, PGE submitted to the OPUC a Customer Choice Plan and rate case to open its service territory to competition. This plan will separate PGE's potentially competitive businesses, primarily the generation of electricity, from its regulated businesses and allow customers to choose their energy provider. The separation of the generation business is proposed to be accomplished by selling PGE's generating assets, either to an Enron affiliate or third parties. Enron is unable to predict what changes may be required by the OPUC for approval or when the OPUC will approve a Customer Choice Plan.
PGE is a 67.5% owner of the Trojan Nuclear Plant (Trojan). In March 1995, the OPUC issued an order authorizing PGE to recover all of the estimated costs of decommissioning Trojan and 87% of its remaining investment in the plant. At December 31, 1997, PGE's regulatory asset related to recovery of Trojan costs from customers was $488 million. Amounts are to be collected over Trojan's original license period ending in 2011. As discussed in Note 14, the OPUC's order and the agency's authority to grant recovery of the Trojan investment under Oregon law are being challenged in state courts.
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 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 its results of operations.
Litigation. In 1995, several parties (the Plaintiffs) filed suit in Harris County District Court in Houston, Texas, against Intratex Gas Company (Intratex), Houston Pipe Line Company and Panhandle Gas Company (collectively, the Enron Defendants), each of which is a wholly-owned subsidiary of Enron. The Plaintiffs were either sellers or royalty owners under numerous gas purchase contracts with Intratex, many of which have terminated. Early in 1996, the case was severed by the Court into two matters to be tried (or otherwise resolved) separately. In the first matter, the Plaintiffs alleged that the Enron Defendants committed fraud and negligent misrepresentation in connection with the "Panhandle program," a special marketing program established in the early 1980s. This case was tried in October 1996 and resulted in a verdict for the Enron Defendants. In the second matter, the Plaintiffs allege that the Enron Defendants violated state regulatory requirements and certain gas purchase contracts by failing to take the Plaintiffs' gas ratably with other producers' gas at certain times between 1978 and 1988. The court has certified a class action with respect to ratability claims. The Court of Appeals has affirmed the trial court's order granting class certification. An appeal to the Texas Supreme Court will be pursued. The Enron Defendants deny the Plaintiffs' claims and have asserted various affirmative defenses, including the statute of limitations. The Enron Defendants believe that they have strong legal and factual defenses, and intend to vigorously contest the claims. Although no assurances can be given, Enron believes that the ultimate resolution of these matters will not have a materially adverse effect on its financial position or results of operations.
On June 2, 1997, Enron announced the resolution of all contractual issues involving the J-Block contract in the U.K. North Sea with the J-Block producers, Phillips Petroleum Company United Kingdom Limited, BG Exploration & Production Limited and Agip (U.K.) Limited. The J-Block contracts are long-term gas contracts that an Enron subsidiary entered into in March 1993 with the J-Block producers. As consideration for amending the contract, Enron made a cash payment of approximately $440 million to the producers. Enron recorded a second quarter non-recurring contract restructuring charge of $675 million ($463 million after tax), primarily reflecting the impact of the amended contract. Such resolution concluded all J-Block litigation between Enron and the J-Block producers.
On June 3, 1997, the London Commercial Court ruled in favor of the "CATS" parties in their dispute over the availability of the CATS (Central Area Transmission System) transportation facilities. The CATS parties sued Teesside Gas Transportation Limited (TGTL), an Enron subsidiary, and Enron (on the basis of its guarantee of TGTL's obligations under the transportation agreement between TGTL and the CATS parties) for allegedly failing to make quarterly "send-or-pay" payments under the transportation agreement. TGTL had refused to make these payments based upon its position that the transportation facilities were not available as required by the contract. The effect of the Court's decision is that TGTL has released withheld "send-or-pay" payments to the CATS parties in the amount of approximately 81 million Pounds Sterling, plus interest and costs. The judgment has no effect on the above referenced settlement of the J-Block gas sales agreements. Enron is appealing the decision of the London Commercial Court in the CATS litigation. Enron believes that the ultimate resolution of this matter will not have a materially adverse effect on its financial position or results of operations.
On November 21, 1996, an explosion occurred in or around the Humberto Vidal Building in San Juan, Puerto Rico. The explosion resulted in fatalities, bodily injuries and damage to the building and surrounding property. San Juan Gas Company, Inc. (San Juan), an Enron subsidiary, operates a natural gas distribution system in the vicinity. Although San Juan did not provide gas service to the building, the investigation report of the National Transportation Safety Board (NTSB) has tentatively concluded that the incident was caused by gas leaking from San Juan's distribution system. San Juan and Enron strongly disagree with the NTSB findings principally because the NTSB investigation (i) found no path of migration of gas from San Juan's system to the building and (ii) discovered no scientific evidence that propane gas was the explosive fuel. Enron and San Juan have been named as defendants in a number of lawsuits filed in U.S. District Court for the district of Puerto Rico and Commonwealth courts of Puerto Rico. These suits, which seek damages for wrongful death, personal injury, business interruption and property damage, allege that negligence of Enron and San Juan caused the explosion. Enron and San Juan are vigorously contesting the claims. Although no assurances can be given, Enron believes that the ultimate resolution of these matters will not have a material adverse effect on its financial position or results of operations.
Trojan Nuclear Plant. In early 1993, PGE ceased commercial operation of Trojan. Since plant closure, PGE has committed itself to a safe and economical transition toward a decommissioned plant. PGE has received approval of its decommissioning plan submitted to the Nuclear Regulatory Commission and Oregon Energy Facilities Siting Council. PGE's remaining cost to decommission and close Trojan of $313 million has been reflected in "Other Liabilities" in the Consolidated Balance Sheet.
Trojan Investment Recovery. In April 1996 a circuit court judge in Marion County, Oregon, found that the OPUC could not authorize PGE to collect a return on its undepreciated investment in Trojan, contradicting a November 1994 ruling from the same court. The ruling was the result of an appeal of PGE's 1995 general rate order which granted PGE recovery of, and a return on, 87% of its remaining investment in Trojan.
The 1994 ruling was appealed to the Oregon Court of Appeals and stayed pending the appeal of the Commission's March 1995 order. Both PGE and the OPUC have separately appealed the April 1996 ruling, which appeals were combined with the appeal of the November 1994 ruling at the Oregon Court of Appeals.
Enron believes that the authorized recovery of and return on the Trojan investment and decommissioning costs will be upheld and that these legal challenges will not have a materially adverse impact 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 expenses. These increased operating expenses are not expected to have a material impact on Enron's financial position or results of operations.
The Environmental Protection Agency (EPA) has informed Enron that it is a potentially responsible party at the Decorah Former Manufactured Gas Plant Site (the Decorah Site) in Decorah, Iowa, pursuant to the provisions of the Comprehensive Environmental Response, Compensation and Liability Act (CERCLA, also commonly known as Superfund). The manufactured gas plant in Decorah ceased operations in 1951. A predecessor company of Enron purchased the Decorah Site in 1963. Enron's predecessor did not operate the gas plant and sold the Decorah Site in 1965. The EPA alleges that hazardous substances were released to the environment during the period in which Enron's predecessor owned the site, and that Enron's predecessor assumed the liabilities of the company that operated the plant. Enron contests these allegations. The EPA is interested in determining whether materials from the plant have adversely affected subsurface soils at the Decorah Site. Enron has entered into a consent order with the EPA by which it has agreed, although admitting no liability, to replace affected topsoil and remove impacted subsurface soils in certain areas of the tract where the plant was formerly located. To date, the EPA has identified no other potentially responsible parties with respect to this site. Enron believes that expenses incurred in connection with this matter will not have a materially 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. At December 31, 1997, the estimated aggregate amounts of such required future payments were $100 million, $114 million, $118 million, $122 million and $133 million for 1998 through 2002, respectively, and $942 million for later years.
The costs recognized under firm transportation agreements, including commodity charges on actual quantities shipped, totaled $27 million, $25 million and $18 million in 1997, 1996 and 1995, respectively. Enron has assigned firm transportation contracts with two of its joint ventures to third parties and guaranteed minimum payments under the contracts averaging approximately $36 million annually through 2001 and $3 million in 2002.
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. Future commitments related to these items at December 31, 1997 were $142 million, $117 million, $114 million, $63 million and $46 million for 1998 through 2002, respectively, and $228 million for later years. Guarantees under the leases total $1,029 million at December 31, 1997.
Total rent expense incurred during 1997, 1996 and 1995 was $156 million, $149 million and $147 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, 1997, a total of $278 million of such guarantees were outstanding, including $92 million on behalf of EOTT. In addition, Enron is a guarantor on certain liabilities of unconsolidated subsidiaries and other companies totaling approximately $873 million, including $402 million related to EOTT trade obligations. The EOTT letters of credit and guarantees of trade obligations are fully secured by the assets of EOTT. Enron has also guaranteed $486 million in lease obligations for which it has been indemnified by an "Investment Grade" company. Management does not consider it likely that Enron would be required to perform or otherwise incur any losses associated with the above guarantees. In addition, certain commitments have been made related to 1998 planned capital expenditures and equity investments.
16 QUARTERLY FINANCIAL DATA (Unaudited)
17 GEOGRAPHIC AND BUSINESS SEGMENT INFORMATION
Enron's operations are classified into the following business segments:
Exploration and Production - Natural gas and crude oil exploration and production primarily in the United States, Canada, Trinidad and India.
Transportation and Distribution - Interstate transmission of natural gas. Management and operation of pipelines. Electric utility operations.
Wholesale Energy Operations and Services - Energy commodity sales and services, risk management products and financial services to wholesale customers. Development, acquisition and operation of power plants, natural gas pipelines and other energy related assets.
Retail Energy Services - Sale of natural gas and electricity directly to end-use customers, particularly in the commercial and light industrial sectors.
Corporate and Other - Includes operation of renewable energy businesses and clean fuels plants, as well as Enron's investment in crude oil transportation activities.
Enron's business segment information has been reclassified from prior years to reflect the realignment of Enron's operations. Financial information by geographic and business segment follows for each of the three years in the period ended December 31, 1997.
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. This information includes amounts attributable to a minority interest of 45%, 47%, 39% and 20% at December 31, 1997, 1996, 1995 and 1994, respectively.
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, 1997:
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, 1997, 1996 and 1995 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, 1997, 1996 and 1995 covering producing areas, in the United States and Canada, containing 54%, 64% and 60%, respectively, of proved reserves, excluding deep Paleozoic 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. In addition, the deep Paleozoic reserves were covered by the opinion of DeGolyer and MacNaughton at December 31, 1995. 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.
Enron's presentation of estimated proved oil and gas reserves excludes, for each of the years presented, those quantities attributable to future deliveries required under a volumetric production payment. In order to calculate such amounts, Enron has assumed that deliveries under the volumetric production payment are made as scheduled at expected British thermal unit factors, and that delivery commitments are satisfied through delivery of actual volumes as opposed to cash settlements.
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
Changes in Standardized Measure of Discounted Future Net Cash Flows
Reserve Quantity Information
Enron's 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:
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 of Enron Corp. and subsidiaries included in this Form 10-K and have issued our report thereon dated February 23, 1998. 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 23, 1998
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 27th day of March, 1998.
ENRON CORP. (Registrant)
By: RICHARD A. CAUSEY (Richard A. Causey) Senior Vice President and Chief Accounting and Information Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been signed below on March 27, 1998 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)
RICHARD A. CAUSEY Senior Vice President and (Richard A. Causey) Chief Accounting and Information Officer (Principal Accounting Officer)
ANDREW S. FASTOW Senior Vice President and (Andrew S. Fastow) Chief Financial Officer (Principal Financial Officer)
ROBERT A. BELFER* Director (Robert A. Belfer)
NORMAN P. BLAKE, JR.* Director (Norman P. Blake, Jr.)
RONNIE C. CHAN* Director (Ronnie C. Chan)
JOHN H. DUNCAN* Director (John H. Duncan)
JOE H. FOY* Director (Joe H. Foy)
WENDY L. GRAMM* Director (Wendy L. Gramm)
KEN L. HARRISON* Director (Ken L. Harrison)
ROBERT K. JAEDICKE* Director (Robert K. Jaedicke)
CHARLES A. LeMAISTRE* Director (Charles A. LeMaistre)
JEROME J. MEYER* Director (Jerome J. Meyer)
JEFFREY K. SKILLING* Director and President and (Jeffrey K. Skilling) Chief Operating Officer
JOHN A. URQUHART* Director (John A. Urquhart)
JOHN WAKEHAM* Director (John Wakeham)
CHARLS E. WALKER* Director (Charls E. Walker)
BRUCE G. WILLISON* Director (Bruce G. Willison)
HERBERT S. WINOKUR, JR.* Director (Herbert S. Winokur, Jr.)
*By: PEGGY B. MENCHACA (Peggy B. Menchaca) (Attorney-in-fact for persons indicated)
SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 ______________________
EXHIBITS TO FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 1997 Commission File Number 1-13159
ENRON CORP. (Exact name of Registrant as specified in its charter)
OREGON 47-0255140 (State or other jurisdiction of (IRS Employer incorporation or organization) Identification No.)
1400 Smith Street Houston, Texas 77002 (Address of principal executive offices) Registrant's Telephone Number, Including Area Code (713) 853-6161 _____________________________
EXHIBIT INDEX
Exhibit Number Description
*3.01 - Amended and Restated Articles of Incorporation of Enron (Annex E to the Proxy Statement/Prospectus included in Enron's Registration Statement on Form S-4 - File No. 333-13791).
*3.02 - Articles of Merger of Enron Oregon Corp., an Oregon corporation, and Enron Corp., a Delaware corporation (Exhibit 3.02 to Post-Effective Amendment No. 1 to Enron's Registration Statement on Form S-3 - File No. 33-60417).
*3.03 - Articles of Merger of Enron Corp., an Oregon corporation, and Portland General Corporation, an Oregon corporation (Exhibit 3.03 to Post-Effective Amendment No. 1 to Enron's Registration Statement on Form S-3 - File No. 33-60417).
*3.04 - Bylaws of Enron (Exhibit 3.04 to Post- Effective Amendment No. 1 to Enron's Registration Statement on Form S-3 - File No. 33-60417).
*3.05 - Form of Series Designation for the Enron Convertible Preferred Stock (Annex F to the Proxy Statement/Prospectus included in Enron's Registration Statement on Form S-4 - File No. 333-13791).
*3.06 - Form of Series Designation for the Enron 9.142% Preferred Stock (Annex G to the Proxy Statement/Prospectus included in Enron's Registration Statement on Form S-4 - File No. 333-13791).
*3.07 - Statement of Resolutions Establishing Series A Junior Voting Convertible Preferred Stock (Exhibit 3.07 to Enron's Registration Statement on Form S-3 - File No. 333-44133).
*4.01 - Indenture dated as of November 1, 1985, between Enron and Harris Trust and Savings Bank, as supplemented and amended by the First Supplemental Indenture dated as of December 1, 1995 (Form T-3 Application for Qualification of Indentures under the Trust Indenture Act of 1939, File No. 22-14390, filed October 24, 1985; Exhibit 4(b) to Form S-3 Registration Statement No. 33-64057 filed on November 8, 1995). 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 - Supplemental Indenture, dated as of May 8, 1997, by and among Enron Corp., Enron Oregon Corp. and Harris Trust and Savings Bank, as Trustee (Exhibit 4.02 to Post- Effective Amendment No. 1 to Enron's Registration Statement on Form S-3, File No. 33-60417).
*4.03 - Form of Supplemental Indenture, dated as of September 1, 1997, between Enron Corp. and Harris Trust and Savings Bank, as Trustee (Exhibit 4.03 to Enron Registration Statement on Form S-3, File No. 333-35549).
*4.04 - 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).
*4.05 - 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).
*4.06 - 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).
*4.07 - Articles of Association of Enron Capital LLC (Exhibit 9 to Enron Corp. Form 8-K dated November 12, 1993).
*4.08 - 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).
*4.09 - 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 10.45
*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 - First Amendment to Enron Executive Supplemental Survivor Benefits Plan (Exhibit 10.02 to Enron Form 10-K for 1995, File No. 1-3423).
*10.03 - Enron Corp. 1988 Stock Plan (Exhibit 4.3 to Form S-8 Registration Statement No. 33-27893).
*10.04 - Second Amendment to Enron Corp. 1988 Stock Plan (Exhibit 10.04 to Enron Corp. Form 10-K for 1996, File No. 1-3423).
*10.05 - Enron Corp. 1988 Deferral Plan (Exhibit 10.19 to Enron Form 10-K for 1987, File No. 1-3423).
*10.06 - First Amendment to Enron Corp. 1988 Deferral Plan (Exhibit 10.06 to Enron Form 10-K for 1995, File No. 1-3423).
*10.07 - Second Amendment to Enron Corp. 1988 Deferral Plan (Exhibit 10.07 to Enron Form 10-K for 1995, File No. 1-3423).
*10.08 - Third Amendment to Enron Corp. 1988 Deferral Plan (Exhibit 10.09 to Enron Form 10-K for 1996, File No. 1-3423).
*10.09 - Fourth Amendment to Enron Corp. 1988 Deferral Plan (Exhibit 10.10 to Enron Form 10-K for 1996, File No. 1-3423).
*10.10 - Fifth Amendment to Enron Corp. 1988 Deferral Plan (Exhibit 10.11 to Enron Form 10-K for 1996, File No. 1-3423).
*10.11 - Enron Corp. 1991 Stock Plan (Exhibit 10.08 to Enron Form 10-K for 1991, File No. 1- 3423).
*10.12 - Amended and Restated Enron Corp. 1991 Stock Plan (Exhibit A to Enron Proxy Statement filed pursuant to Section 14(a) on March 24, 1997).
10.13 - First Amendment to Enron Corp. Amended and Restated 1991 Stock Plan.
10.14 - Second Amendment to Enron Corp. Amended and Restated 1991 Stock Plan.
*10.15 - Enron Corp. 1992 Deferral Plan (Exhibit 10.09 to Enron Form 10-K for 1991, File No. 1-3423).
*10.16 - First Amendment to Enron Corp. 1992 Deferral Plan (Exhibit 10.10 to Enron Form 10-K for 1995, File No. 1-3423).
*10.17 - Second Amendment to Enron Corp. 1992 Deferral Plan (Exhibit 10.11 to Enron Form 10-K for 1995, File No. 1-3423).
*10.18 - Enron Corp. Directors' Deferred Income Plan (Exhibit 10.09 to Enron Form 10-K for 1992, File No. 1-3423).
*10.19 - Split Dollar Life Insurance Agreement between Enron and the KLL and LPL Family Partnership, Ltd., dated April 22, 1994 (Exhibit 10.17 to Enron Form 10-K for 1994, File No. 1-3423).
*10.20 - Employment Agreement between Enron Corp. and Kenneth L. Lay, executed December 18, 1996 (Exhibit 10.25 to Enron Form 10-K for 1996, File No. 1-3423).
*10.21 - 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).
*10.22 - 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).
*10.23 - 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).
*10.24 - Fourth Amendment to Consulting Services Agreement between Enron and John A. Urquhart dated as of May 9, 1994 (Exhibit 10.35 to Enron Form 10-K for 1995, File No. 1-3423).
*10.25 - Fifth Amendment to Consulting Services Agreement between Enron and John A. Urquhart (Exhibit 10.36 to Enron Form 10-K for 1995, File No. 1-3423).
*10.26 - Sixth Amendment to Consulting Services Agreement between Enron and John A. Urquhart (Exhibit 10.37 to Enron Form 10-K for 1995, File No. 1-3423).
10.27 - Seventh Amendment to Consulting Services Agreement between Enron and John A. Urquhart, dated October 27, 1997.
*10.28 - 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).
*10.29 - First Amendment to Employment Agreement between Enron and James V. Derrick, Jr., dated May 2, 1994 (Exhibit 10.53 to Enron Form 10-K for 1994, File No. 1-3423).
*10.30 - Enron Corp. Performance Unit Plan (Exhibit A to Enron Proxy Statement filed pursuant to Section 14(a) on March 25, 1994).
*10.31 - Enron Corp. Annual Incentive Plan (Exhibit B to Enron Proxy Statement filed pursuant to Section 14(a) on March 25, 1994).
*10.32 - 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).
*10.33 - First Amendment to Enron Corp. Performance Unit Plan (Exhibit 10.46 to Enron Form 10-K for 1995, File No. 1-3423).
*10.34 - Enron Corp. Restated 1994 Deferral Plan (Exhibit 4.3 to Enron Form S-8 Registration Statement, File No. 333-48193).
*10.35 - Employment Agreement between Enron Power Corp. and Thomas E. White dated July 1, 1990 (Exhibit 10.59 to Enron Form 10-K for 1996, File No. 1-3423).
*10.36 - First Amendment, dated September 9, 1991, to Employment Agreement between Enron Power Corp. and Thomas E. White dated July 1, 1990 (Exhibit 10.60 to Enron Form 10-K for 1996, File No. 1-3423).
*10.37 - Second Amendment, dated May 2, 1994, to Employment Agreement between Enron Power Corp. and Thomas E. White dated July 1, 1990 (Exhibit 10.61 to Enron Form 10-K for 1996, File No. 1-3423).
*10.38 - Third Amendment, dated January 3, 1997, to Employment Agreement between Enron Power Corp. and Thomas E. White dated July 1, 1990 (Exhibit 10.62 to Enron Form 10-K for 1996, File No. 1-3423).
*10.39 - Employment Agreement between Enron Capital Trade & Resources Corp. and Jeffrey K. Skilling, dated January 1, 1996 (Exhibit 10.63 to Enron Form 10-K for 1996, File No. 1-3423).
*10.40 - First Amendment effective January 1, 1997, by and among Enron Corp., Enron Capital & Trade Resources Corp., and Jeffrey K. Skilling, amending Employment Agreement between Enron Capital & Trade Resources Corp. and Jeffrey K. Skilling dated January 1, 1996 (Exhibit 10.64 to Enron Form 10-K for 1996, File No. 1-3423).
10.41 - Split Dollar Agreement between Enron and Jeffrey K. Skilling dated May 23, 1997.
10.42 - Second Amendment effective October 13, 1997, to Employment Agreement between Enron Corp. and Jeffrey K. Skilling.
10.43 - Loan Agreement effective October 13, 1997, between Enron Corp. and Jeffrey K. Skilling.
*10.44 - Employment Agreement dated July 20, 1996 (effective July 1, 1997) between Enron and Ken L. Harrison (Exhibit 10.1 to Post- Effective Amendment No. 1 to Enron's Registration Statement on Form S-4, File No. 333-13791).
10.45 - Executive Employment Agreement between Stanley C. Horton and Enron Operations Corp., effective as of October 1, 1996.
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, 1998.
24 - Powers of Attorney for the directors signing this Form 10-K.
27 - Financial Data Schedule.
* Asterisk indicates exhibits incorporated by reference.
(b) Reports on Form 8-K
No reports on Form 8-K were filed by Enron during the last quarter of 1997.