Item 1. BUSINESS
GENERAL
Enron Corp. ("Enron"), a Delaware corporation organized in 1930, is an integrated natural gas company with headquarters in Houston, Texas. Essentially all of Enron's operations are conducted through its subsidiaries and affiliates which are principally engaged in the gathering, transportation and wholesale marketing of natural gas to markets throughout the United States and internationally through approximately 44,000 miles of natural gas pipelines; the exploration for and production of natural gas and crude oil in the United States and internationally; the production, purchase, transportation and worldwide marketing of natural gas liquids and refined petroleum products; the independent (i.e., non-utility) development, promotion, construction and operation of natural gas-fired power plants in the United States and internationally; and the non-price regulated purchasing and marketing of long-term energy related commitments. As of December 31, 1993, Enron employed approximately 7,100 persons.
As used herein, unless the context indicates otherwise, "Enron" refers to Enron Corp. and its subsidiaries.
BUSINESS SEGMENTS
Enron's operations are classified into the following business segments:
1) Transportation and Operation: Transmission of natural gas; construction, management and operation of natural gas and natural gas liquids pipelines, liquids plants and power facilities; crude oil transportation activities and investment in liquids pipeline operations.
2) Gas Services: Purchasing and marketing of natural gas, natural gas liquids and power; price risk management and financing arrangements in connection with natural gas, natural gas liquids and power transactions; intrastate natural gas pipelines; and development, acquisition and promotion of natural gas fired power plants in North America.
3) Gas Processing: Extraction of natural gas liquids in North America.
4) International Gas and Power Services: Independent (non- utility) development, acquisition and promotion of power plants, natural gas liquids facilities and pipelines outside of North America; and international marketing of natural gas liquids.
5) Exploration and Production: Natural gas and crude oil exploration and production primarily in the United States, Canada, and Trinidad.
Enron's business segment information has been reclassified from prior years to reflect Enron's realignment of its operations during 1993. For financial information by business segment for the fiscal years ended December 31, 1991 through December 31, 1993, please see Note 19 to the Consolidated Financial Statements on page.
TRANSPORTATION AND OPERATION
Interstate Pipelines
Enron and its subsidiaries operate domestic interstate pipelines extending from Texas to the Canadian border and across the southern United States from Florida to California. Included in Enron's domestic interstate natural gas pipeline operations are Northern Natural Gas Company ("Northern"), Transwestern Pipeline Company ("Transwestern"), and Florida Gas Transmission Company ("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; Florida Gas, the State of Florida; and Transwestern, principally the California market. In addition, Enron holds a 13% interest in Northern Border Partners, L.P. and operates the Northern Border Pipeline system, which gives Enron direct access to Canadian gas supplies. Also, Enron has a 15% interest in Enron Liquids Pipeline, L.P., which includes natural gas liquids, refined petroleum products and carbon dioxide pipeline businesses which are operated by a wholly owned subsidiary of Enron.
Northern Natural Gas Company. Through its approximately 23,500-mile natural gas pipeline system stretching from Texas to Michigan's Upper Peninsula and the Canadian Border, Northern transmits gas to points in its traditional market area of Illinois, Iowa, Kansas, Michigan, Minnesota, Nebraska, South Dakota and Wisconsin. Gas is transported to town borders for consumption and resale by non-affiliated gas utilities and municipalities and to other pipeline companies and end-users. Northern also gathers and transports gas at various points outside its traditional market area in the production areas of Colorado, Kansas, Montana, New Mexico, Oklahoma, Texas and Wyoming for utilities, end-users, and other pipeline and marketing companies.
In Northern's market area, natural gas is an energy source available for traditional residential, commercial and industrial uses. Northern's throughput totaled 1,943 trillion British thermal units ("Tbtu") in 1993, compared to 1,889 Tbtu in 1992. In its traditional market area, Northern's throughput increased to 788 Tbtu in 1993 from 706 Tbtu in 1992, an 11.6% increase. Northern's jurisdictional sales decreased from 66 Tbtu in 1992 to 61 Tbtu in 1993, evidencing a continuing shift from sales to transportation volumes due to the implementation of open access transportation service. Transportation of volumes in the traditional market area rose from 664 Tbtu in 1992 to 787 Tbtu in 1993. The volume of gas delivered by Northern in its non-traditional market area decreased to 1,155 Tbtu in 1993 from 1,183 Tbtu in 1992.
Order Nos. 636, 636-A and 636-B were promulgated by the FERC in 1992. The primary focus of the orders is to create equality of service between the traditional pipeline merchant sales service and open-market transportation service. Northern implemented the service restructuring required by Order Nos. 636, 636-A and 636-B on November 1, 1993, by unbundling its sales service, offering a limited market based merchant service and establishing a straight fixed variable rate design to recover all fixed costs, including return on equity, in the demand component of its rates. Northern's merchant role has been reduced to approximately 100 million cubic feet ("MMcf") per day. The FERC has indicated that Northern will be authorized to recover all prudently incurred costs associated with a reduced merchant role resulting from the implementation of Order Nos. 636, 636-A, and 636-B (See "Regulation - Natural Gas Rates and Regulations").
Northern competes with other interstate pipelines in the transportation and storage of gas. Northern competes with other pipelines, producers, gatherers and gas aggregators for gathering volumes. As noted above, recent FERC orders have been designed to introduce more competition into the natural gas industry, and have had the effect of increasing transportation volumes and decreasing or eliminating sales by pipelines.
Transwestern Pipeline Company. Transwestern is an open-access interstate pipeline engaged primarily in the transportation of natural gas. Through its approximately 4,500-mile pipeline system, Transwestern transports natural gas from West Texas, Oklahoma, eastern New Mexico and the San Juan Basin in northwest New Mexico primarily to the California market, with a developing transportation business of deliveries off the east end of its system. Substantially all of Transwestern's total of 1.06 billion cubic feet ("Bcf") per day of delivery capacity to California is currently on a firm basis. Transwestern has access to three significant gas basins for its gas supply: the Permian Basin in West Texas and eastern New Mexico, the San Juan Basin in northwestern New Mexico and southern Colorado, and the Anadarko Basin in the Texas and Oklahoma Panhandles.
In 1992, Transwestern expanded its mainline capacity and built a lateral pipeline to the San Juan Basin in northwestern New Mexico. The expansion project allowed Transwestern to (i) access the San Juan Basin for gas supply, (ii) begin service to northern California markets, (iii) access the central California enhanced oil recovery market and (iv) enhance its ability to deliver to markets east of California. Due to surplus pipeline capacity and a weak demand market in California, total throughput on Transwestern's system has not increased as much as anticipated following the completion of the fully subscribed expansion/extension. Total throughput volumes to California averaged approximately 757 MMcf per day in 1993, compared to 744 MMcf per day in 1992.
During 1993, Transwestern developed a new firm transportation service on the east end of its system to transport Permian and San Juan Basin supplies into Texas, Oklahoma and the midwestern United States. Transwestern transported an average of 312 MMcf per day off the east end of its system in 1993, as compared to 156 MMcf per day in 1992.
In response to federal regulatory changes, Transwestern has shifted from a merchant pipeline (buying and reselling gas) to a transporter of gas for third parties. Currently, substantially all Transwestern throughput consists of transportation for third parties.
Transwestern filed its Order No. 636 compliance filing in July 1992, and received FERC approval on February 1, 1993. Under its Order 636 program, Transwestern now has, among other things, a capacity release program and a straight fixed variable rate design. This rate design collects all fixed costs, including income taxes and return on equity, in monthly demand or reservation fees.
Transwestern is subject to competition from other transporters into the southern California market, including El Paso Natural Gas Company, Kern River Gas Transmission Company, Pacific Gas Transmission Company, and intrastate producers and affiliates of Southern California Gas Company.
Florida Gas Transmission Company. Enron 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. An Enron subsidiary operates the Florida Gas pipeline. Florida Gas transports natural gas to a variety of industrial customers, electric utilities and local distribution companies, supplying peninsular Florida through an approximately 4,400-mile pipeline system originating in South Texas and terminating near Miami, Florida.
Florida Gas' customer base has historically been grouped into three categories: sales for resale, transportation services and direct sales. Sales for resale customers (local gas distributors which resell gas to retail residential and small commercial and industrial businesses) and transportation customers (customers who directly contract for their own supply of gas which in turn is transported by Florida Gas) are jurisdictional activities. Rates for these customers are regulated by the FERC. The rates at which Florida Gas sells to direct sales customers (those sales made directly to end-use industrial and electric utility customers) are non-jurisdictional. Florida Gas' rates for these customers are negotiated with the individual customer and are not set by the FERC. On November 1, 1993, Florida Gas' services were restructured under Order No. 636, and virtually all volumes of gas now transported on the system are transportation-only volumes. Florida Gas currently makes unbundled sales (sales at the wellhead) only on an interruptible, month-to-month basis.
Florida Gas' daily deliveries for 1993 and 1992 averaged approximately 936 billion British Thermal Units ("Bbtu") and 973 Bbtu, respectively. Of Florida Gas' throughput volumes in 1993 and 1992, sales for resale contributed 3% and 8%, transportation services 96% and 87%, and direct sales 1% and 5%, respectively.
In the process of becoming an open access pipeline, Florida Gas has moved away from being primarily a major natural gas supplier with significant non-jurisdictional direct sales volumes and the related gas commodity price risk, to become primarily a jurisdictional transporter of gas. The majority of Enron's merchant sales function in Florida is now being conducted through 50%-owned Citrus Corp.'s non-regulated gas marketing companies. As a result of contract conversions, Florida Gas' primary source of net revenues has switched from direct sales and sales for resale services to transportation services. This switch has resulted in a reduction of total revenues, since transportation rates do not include the cost of the gas supplies purchased from third parties. At the same time, Florida Gas' cost of performing sales services has been reduced since the cost of gas shipped under transportation contracts is no longer included.
Florida Gas is the only major natural gas pipeline in peninsular Florida. From time to time, the construction of a major gas pipeline into peninsular Florida has been proposed; however, the construction of such a pipeline would require significant capital expenditures and would be subject to a stringent environmental review process. Certain pipeline competitors of Florida Gas are currently pursuing proposed pipelines to service the Florida market later in the decade.
In 1993, Florida Gas made its Order No. 636 restructuring filing with the FERC, which has been accepted. Florida Gas' Order 636 program established a straight fixed variable rate design, provided for the collection of Order No. 636-related gas supply realignment costs, unbundled Florida Gas' capacity services from sales services and established a capacity release program.
Florida Gas has received approval from the FERC to proceed with its Phase III expansion, which will increase Florida Gas' delivery capability into Florida from approximately 925 MMcf per day to approximately 1,455 MMcf per day. The expansion will serve approximately 29 customers, with Florida Power and Light as the primary customer. The capital cost of the expansion project is expected to be approximately $900 million (excluding allowance for funds used during construction) which will initially be financed by Enron and Sonat, Inc., Florida Gas' parent companies; however, Enron and Sonat, Inc. will seek outside financing for at least 65% of the project during late 1994.
Northern Border Pipeline Company. Northern Border Partners, L.P., a Delaware limited partnership (the "Partnership"), owns 70% of Northern Border Pipeline Company, a Texas general partnership ("Northern Border"). An Enron subsidiary holds a 13% interest in the Partnership, and serves as operator of the pipeline. Northern Border owns a 969-mile interstate pipeline system that transports natural gas from the Montana-Saskatchewan border near Port of Morgan, Montana to interconnecting pipelines in the State of Iowa, one of which is Northern. The pipeline system has access to natural gas reserves in the provinces of Alberta, British Columbia and Saskatchewan, as well as the Williston Basin and the Great Plains Coal Gasification Project in the United States. Interconnecting pipeline facilities provide access to markets in the Midwest, Mid-Atlantic, Northeast, Southwest and Southeast for the referenced Canadian and U.S. natural gas reserves. Therefore, Northern Border is strategically situated to transport significant quantities of natural gas to major gas consuming markets.
Northern Border has focused its efforts primarily on being a low cost transporter of Canadian gas exported to the United States. As of January 31, 1994, Northern Border has firm transportation service agreements, other than those under temporary release, with five interstate pipeline companies, including Northern, three domestic producers and marketers, including Enron Gas Marketing, Inc., eleven Canadian producers and marketers, and numerous interruptible service contracts. Since 1988, Northern Border has been transporting volumes at or near its maximum capacity. Based upon existing contracts and capacity, 100% of Northern Border's firm capacity (1.7 Bcf of natural gas per day) is contractually committed through October 1997, and 93% of such capacity is contractually committed through October 2001. At the present time, 15% of the capacity is contracted by interstate pipelines, with Northern accounting for 4% of such capacity. The remaining capacity is contracted to producers and marketers. Enron Gas Marketing, Inc., along with a marketing affiliate of a general partner in Northern Border, holds 12% of the contracted capacity. Northern Border competes with two other pipeline systems that transport gas from Canada to the Midwest.
Enron Liquids Pipeline Company. Enron owns approximately 15% of Enron Liquids Pipeline, L.P., a Delaware limited partnership formed in August 1992. An Enron subsidiary serves as general partner and operates the partnership's two interstate common carrier natural gas liquids ("NGL") pipeline systems, and one carbon dioxide pipeline system. The partnership also operates the Cora Terminal, a high speed, rail to barge coal transfer facility, and also owns a 25% interest in an NGL fractionator. The North System of Enron Liquids Pipeline, a 1,600-mile interstate common carrier NGL and refined petroleum products pipeline system, transports, stores and delivers a full range of NGLs and refined products from south central Kansas to markets in the Midwest and has interconnects, using third party pipelines, to the eastern United States. The Cypress Pipeline transports ethane from Mont Belvieu, Texas to the Lake Charles, Louisiana area. The Central Basin Pipeline transports carbon dioxide in West Texas for use in enhanced oil recovery operations in the Permian Basin of West Texas. The Cora Terminal stores coal and transfers coal mined in southern Illinois from railcars to barges that transport it to end users, principally for electricity generation.
The North System and the Cypress Pipeline are interstate common carrier pipelines, subject to regulation by the FERC. As an interstate common carrier, the partnership offers interstate transportation services by means of the North System and Cypress Pipeline to any shipper of NGLs who requests such services, provided that the products tendered for transportation satisfy the conditions and specifications contained in the applicable tariff. The Central Basin Pipeline is not subject to rate regulation.
Interstate Pipelines' Gas Supply. When Northern was a fully bundled merchant, it contracted for supply to meet its customers' full requirements. Northern is in the process of negotiating with its suppliers to balance its gas supply with its greatly reduced merchant function. Northern originally developed storage capabilities to meet its market area sales requirements prior to open access. Such storage is now offered to its customers on a contractual basis. In the 1992/1993 season, customers utilized 21.1 Bcf of Northern's capacity. For the 1993/1994 heating season, Northern utilized 35.4 Bcf for storage services to its customers. Northern's 56 Bcf of total capacity is held in three storage fields and two liquefied natural gas plants owned by Northern. All are located in or near Northern's market area to facilitate delivery for short notice swing capability and unexpected weather-related demand.
Since Northern and Transwestern are primarily transportation- only pipelines, it is no longer necessary for them to have significant gas supplies committed for sale to them. Of the gas supplies remaining under contract, the major portion under long- term contracts covers production in the Anadarko Basin area of the Texas Panhandle, northwestern Oklahoma and from the Permian Basin area of West Texas and southeastern New Mexico.
As of November 1, 1993, when its Order No. 636 restructured services were implemented, Florida Gas became essentially a transportation-only pipeline. It is thus no longer necessary for it to have significant gas supplies committed for sales to Florida Gas. All of Florida Gas' firm gas purchase contracts have now been either terminated or assigned; volumes required for balancing or pipeline operations (line pack) are purchased on the spot market. Of the total natural gas sold by Florida Gas during 1993, approximately 60% was purchased from non-affiliated entities.
Operation and Management of Power Facilities
Enron's subsidiary companies are involved in the independent power industry, both as an operator and as an equity partner. Enron, through its affiliated companies, is involved in the independent (i.e., non-utility) development, promotion, construction, acquisition and operation of natural gas-fired power plants, some of which use combined cycle and cogeneration technology to generate electricity and steam. Cogeneration is the simultaneous production of steam and electricity from a single fuel source, such as natural gas. A conventional electric power plant produces electricity and discharges resulting exhaust heat as waste. Cogeneration uses this previously wasted heat to create steam and electricity for industrial use, requiring less fuel than older methods using separate electric and thermal energy plants. This dual fuel use results in a more efficient utilization of energy and provides lower cost electricity and steam. In addition, Enron has developed diesel fired power plants for projects in developing countries, where the development, engineering design and construction are done on an accelerated basis in order to address severe power shortages in such countries. (See "International Gas and Power Services" for a general description of Enron's international power businesses).
Enron/Dominion Cogen Corp., an operation owned 50% by an Enron subsidiary and 50% by Dominion Resources, Inc., owns the 340 megawatt Clear Lake facility in Pasadena, Texas and the 450 megawatt Texas City, Texas plant. Enron owns a 50% interest in Richmond Power Enterprises, L.P., which owns a 250 megawatt combined cycle cogeneration facility in Richmond, Virginia. An Enron subsidiary owns a 50% interest in a 149 megawatt combined cycle power plant in Milford, Massachusetts, which became operational in 1993. Enron subsidiaries or affiliates also own a 50% interest in each of a 105 megawatt and a 116 megawatt facility located at Batangas and Subic Bay, respectively, in the Philippines; a 50% interest in a 110 megawatt facility at Puerto Quetzal, Guatemala; and a 50% interest in a 1,875 megawatt facility at Teesside, England.
Crude Oil Transportation Services
Certain Enron subsidiary companies purchase at the lease site, transport, trade and market crude oil. Total North American crude oil lease volumes were approximately 292,000 barrels per day in 1993 and 280,000 barrels per day in 1992. Trading activities, including hedging, are bound by dollar exposure limits and credit controls. During 1993, North American crude oil trading volumes totaled approximately 208.7 million barrels. However, during October 1992, the Board of Directors of Enron approved a plan to divest all of the crude oil trading and transportation operations of Enron's wholly-owned subsidiary, EOTT Energy Corp. (EOTT), through a spin-off transaction to holders of Enron common stock. As a result, Enron classified these activities as discontinued operations for financial reporting purposes. During the fourth quarter of 1993, Enron's Board of Directors approved a revised plan to divest a substantial portion, but not all, of EOTT through a public offering of units of limited partnership interests in a master limited partnership, and thus reclassified these activities as continuing operations.
In January 1994, EOTT Energy Partners, L.P. filed a registration statement with the Securities and Exchange Commission to offer up to 11 million common units. Upon completion of this offering, Enron transferred substantially all of the business and assets of EOTT to EOTT Energy Partners, L.P., a newly formed limited partnership. EOTT Energy Corp. is the general partner and owns a substantial interest in EOTT Energy Partners, L.P.
GAS SERVICES
Enron Gas Services Corp. and its affiliated companies ("EGS") purchase natural gas, gas liquids and power through a variety of contractual arrangements, including both short and long term contracts, the arrangement of production payment and other financing transactions, and other contractual arrangements, and market these energy products to local distribution companies, electric utilities, cogenerators, and both commercial and industrial end-users. EGS also provides price risk management services to these customers through both physical delivery and financial arrangements.
EGS offers a broad range of non-price regulated natural gas merchant services by tailoring a variety of supply and marketing options to its customers' specific needs. EGS's strategy is to provide predictable pricing, reliable delivery and low cost capital to its customers. EGS provides these services through a variety of financial instruments, including forward contracts, swap agreements, options and other contractual commitments. EGS's services can be categorized into four business lines: Gas, Power, Finance and Liquids.
Gas. EGS's Gas operations include price risk management and origination activities as well as the physical natural gas trading and transportation activities of Enron Gas Marketing, Inc., Houston Pipe Line Company, Enron Access, Inc., Louisiana Resources Company and EGS's Canadian gas supply and marketing operations.
Enron Gas Marketing, Inc. ("EGM") was created in the mid- 1980's as natural gas pipelines began the conversion to open access transportation required by the FERC. EGM has a FERC blanket sales certificate allowing it authority to sell gas across the United States. EGM accomplishes the movement of gas throughout the country by buying and selling gas at various industry-specific locations ("index points"). Any required transportation of gas from these index points to the actual market is accomplished utilizing EGM's or its customers' transportation agreements with Enron's pipeline systems, as well as numerous other pipelines throughout the country. Enron Gas Marketing, Inc. Canada purchases gas supplies for markets in both the United States and Canada.
Houston Pipe Line Company ("HPL") operates an approximately 5,500-mile intrastate pipeline system in Texas which interconnects with Northern, Transwestern, Florida Gas and numerous other interstate and intrastate pipelines. HPL's pipeline operation now functions primarily as a gas gathering and transportation system, and EGS's natural gas sales in Texas are made primarily by non- regulated marketing companies to a variety of industrial customers in the Texas Gulf Coast area that use gas for fuel or raw material and to utilities and natural gas transmission companies that purchase gas for resale. HPL's intrastate natural gas sales, transportation and storage services are subject to seasonal variation because many of its customers have weather-sensitive gas requirements. The Railroad Commission of Texas has jurisdiction over intrastate gas pipeline rates, operations and transactions in Texas. See "Regulation--Natural Gas Rates and Regulations."
Enron Access, Inc. ("Access") was formed as a result of EGS's acquisition of Access Energy, Inc., an independent gas marketing company, in October 1992. Access markets natural gas under a variety of arrangements to local distribution companies and commercial customers (such as retail establishments, churches, hospitals, etc.), as well as industrial users in 38 states. This is a significant market area as gas pipelines and distribution companies make transportation services more available to third parties as contemplated by FERC Order No. 636 and other state and local regulations.
In April 1993, Enron acquired Louisiana Resources Company, which includes the rights to a 540-mile intrastate pipeline which spans the state of Louisiana and serves the industrial complex along the Mississippi River from Baton Rouge to New Orleans. The pipeline interconnects with the Henry Hub and has numerous interconnections with both interstate and intrastate pipelines.
EGS obtains its gas supply from a number of sources which have been discussed above. During 1993, EGS purchased approximately 91% of its gas from non-affiliated entities, and the balance was purchased from Enron affiliates. Not more than 3% of the gas purchased from non-affiliates was purchased from any single producer. EGS purchases gas under both short and long-term agreements at either fixed or market-sensitive prices.
During 1994, growth in the physical and financial trading activities of EGS's Gas operations is planned despite continued competition from financial and industrial companies, particularly in the derivative products area. Additional contract originations will be sought as the impact of FERC Order 636 becomes more evident. Enron's and other third parties' price- regulated, interstate pipeline companies are expected to continue their transition from the merchant function to primarily providing transportation services.
Power. EGS's Power business consists of various activities associated with the North American power market such as providing natural gas contract services through Enron Power Services Inc. ("Power Services"); managing, acquiring, developing and promoting power-related assets and joint ventures; and marketing and supplying electricity. Power Services markets natural gas to the electric power generation industry. Some non-utility electric power generators have had difficulty obtaining financing for the construction of gas-fired power plants without long-term natural gas supply contracts. Power Services offers these supplies under long-term firm contract commitments with both fixed-price or other innovative pricing terms. In 1993, Power Services signed a 12-year contract to supply approximately 182 Bcf of natural gas. Power Services 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.
Finance. Enron Finance Corp. ("EFC") secures natural gas supplies from independent producers through a variety of financial transactions, primarily volumetric production payments. EFC arranges these transactions through financial entities and provides related price risk management services. In 1993, EFC originated and/or arranged $413 million of funding, thereby gaining access to approximately 169.5 TBtu's of natural gas and 9.3 million barrels of crude oil through reserve-based production payments. In addition, EFC and its affiliates have arranged financing in the form of secured loans to producers and end-users and have made equity investments as partners in several limited partnerships. During 1993, Joint Energy Development Investments Limited Partnership was formed comprised of an EGS subsidiary as general partner and the California Public Employees Retirement System as limited partner. The partnership provides capital for energy investments.
Liquids. The Liquids business of EGS includes the North American natural gas liquids (NGL) marketing activities and the "clean fuels" business which consists of the methanol and methyl tertiary butyl ether (MTBE) businesses. EGS markets the output of Enron's NGL and clean fuels plants as well as product purchased from third parties. During 1994, EGS's Liquids business will attempt to expand its NGL and clean fuels marketing through derivative products offerings. Additionally, EGS plans to continue development of its merchant business by actively marketing long- term and fixed margin-based pricing arrangements.
GAS PROCESSING
Certain Enron subsidiaries are engaged domestically in the extraction of natural gas liquids ("NGLs") (ethane, propane, normal butane and isobutane and natural gasoline). NGLs are typically extracted from natural gas in liquid form under low temperature and high pressure conditions. Ethane, propane, normal butane, isobutane and natural gasoline are used as feedstocks for petrochemical plants in the production of plastics, synthetic rubber and other products. Normal butane and natural gasoline are used by refineries in the blending of motor gasoline. Isobutane is used in the alkylation process to enhance the octane content of motor gasoline and is also used in the production of MTBE, which is used to produce cleaner burning motor gasoline. Propane is used as fuel for home heating and cooking, crop drying and industrial facilities and as an engine fuel for vehicles, and ethane is used as a feedstock for synthetic fuels production. Enron's subsidiaries engaged in gas processing operations extracted as NGLs the equivalent of an estimated 43.1 Bcf of natural gas during 1993.
At December 31, 1993, Enron's gas processing businesses had an interest in 22 hydrocarbon extraction and fractionation facilities, 18 of which are operated by Enron, which generally are located along Enron's natural gas pipeline systems. During 1993, these plants extracted 1.3 billion gallons of NGLs. A total of .9 billion gallons of product were fractionated for affiliates and others. The income before interest and taxes of Enron's gas processing businesses declined in both 1992 and 1993 as compared to the applicable preceding years due primarily to lower processing margins, reflecting higher natural gas feedstock prices and lower product prices. These businesses' margins are sensitive to the relationship between NGL prices and the price of natural gas. In 1994, Enron will attempt to mitigate some of this market risk through hedging techniques.
INTERNATIONAL GAS AND POWER SERVICES
Enron's international activities principally involve the development, acquisition, promotion, and operation of natural gas and power projects and the marketing of natural gas liquids. As is the case in the United States, Enron's emphasis is on businesses in which natural gas or its components play a significant role. Development projects are focused on power plants, gas processing and terminaling facilities, and gas pipelines, while marketing activities center on fuels used by or transported through such facilities.
Enron's international activities include management of ownership interests and operation of power plants in England, Germany, Guatemala and the Philippines; a 3,800-mile pipeline system in southern Argentina; retail gas and propane sales in the Caribbean basin; processing of natural gas liquids at Teesside, England; and marketing of natural gas liquids worldwide.
During 1993 and the first quarter of 1994, commercial operations commenced on six Enron projects totaling over 2,300 megawatts in nominal capacity in England, Germany, the Philippines and Guatemala. Projects with power purchase or services agreements are in pre-construction phases in Turkey, Latvia and India, and under construction in Dominican Republic. In addition, Enron is evaluating potential power development projects in Colombia, Yemen, Puerto Rico, Indonesia, and China.
Teesside. Enron has a 50% ownership interest in an independent power facility with a capacity of approximately 1,875 megawatts at ICI Chemicals & Polymers Limited's Wilton Works Plant on Teesside in northeast England. The gas-fired combined cycle project was originated, developed, constructed and is operated by Enron subsidiaries. The remaining 50% ownership interest is held by four of the twelve regional electric companies operating in England and Wales. The Teesside plant has the capacity to supply approximately 4% of all the electricity consumed in the U.K., and 1,725 megawatts of this capacity is committed under long-term contracts.
In addition to the Teesside power plant, Enron also operates an adjacent 300 MMcf per day gas liquids processing facility. The first phase of the liquids plant is in place and producing in excess of 300,000 gallons of natural gas liquids per day, which is being sold in the European markets. A second phase of construction is expected to begin in 1994 in order to be operating by 1996 when additional natural gas volumes which Enron has purchased from the J-Block in the North Sea become available.
Enron has long-term contractual rights to 300 MMcf per day capacity on the Central Area Transmission System, a 1,400 MMcf per day capacity pipeline from the North Sea. Enron's capacity will be used to transport J-Block gas to Teesside when that gas becomes available in 1996. These new supplies will support Enron's future marketing programs.
Philippines. Enron has interests in three projects in the Philippines. The Batangas power project is an approximately 105 megawatt fuel-oil-fired diesel engine plant located at Pinamucan, Batangas, Luzon, which began commercial operation in 1993. The Subic power project is a 116 megawatt fuel-oil-fired diesel engine plant located at Subic Bay which began commercial operation in February 1994. Both projects were developed and are 50% owned by Enron, and sell power to the National Power Corporation ("NAPOCOR") of the Philippines. In addition, Enron leases and operates two plants located at the former Subic Naval Base, which together generate up to approximately 28 megawatts of power. Enron began operating these facilities in January 1993, and is selling power to NAPOCOR.
Guatemala. Enron has a 50% interest in an approximately 110 megawatt fuel-oil-fired diesel engine power plant mounted on floating platforms at Puerto Quetzal on Guatemala's Pacific Coast. The U.S. flag vessels built in Louisiana went into commercial operation in February 1993, and sell all of their power output under a long-term contract to a large Guatemalan electric utility, a majority interest in which is owned by Guatemala's national electric utility.
Germany. During 1993, Enron acquired an approximately 125 megawatt gas-fired plant in Bitterfeld, Germany. Enron is a 50/50 joint venture partner with the second largest regional utility company in Germany. The Bitterfeld project provides Enron with a presence in Germany as well as access to a site for possible expansion.
India. An Enron affiliate signed a 20-year power purchase agreement with Maharashtra State Electricity Board in December 1993. The contract supports the first phase of an approximately 2,015 megawatt gas-fired power plant and related facilities, which will ultimately include a liquefied natural gas (LNG) terminal and harbor development near Dabhol, which is approximately 100 miles south of Bombay. Enron's proposed partners in the two-phase project are affiliates of General Electric, which is supplying equipment and is expected to acquire a 10% equity interest, and affiliates of Bechtel, which is the contractor and also is expected to acquire a 10% equity interest. Enron plans to reduce its current 80% equity interest to a 50% interest at final closing, which equates to an equity investment of approximately $135 million. Construction of the 695 megawatt first phase is expected to begin in 1994 and includes harbor development, fuel facilities, housing and related activities necessary to complete this project. Once the LNG supply contracts are obtained, the 1,320 megawatt second phase addition will be constructed.
Argentina Gas Pipelines. As part of the privatization of Argentina's state-owned industries, in 1992 Enron acquired an indirect interest in Transportadora de Gas del Sur ("TGS"), the formerly state-owned natural gas pipeline in southern Argentina. Enron holds a net 17.5% interest and operates the 3,800-mile pipeline system, which has a capacity of approximately 1.7 Bcf per day. TGS serves four distribution companies under long-term firm transportation contracts. TGS is expanding its pipeline in 1994 by 240 MMcf per day through the addition of four compressor stations, in time for the winter season in Argentina. TGS has signed transportation contracts for 210 MMcf per day of additional capacity for ten years.
Caribbean Basin. Enron's operations in the Caribbean area are conducted through Enron Americas and its subsidiary companies. Enron Americas' subsidiary Industrias Ventane ("Ventane"), organized in 1953, operates the leading natural gas liquids transportation and distribution business in Venezuela. In Venezuela, Enron Americas is also engaged in the manufacture and distribution of appliances in a joint venture with General Electric and local investors. Enron Americas has a gas pipeline operation in Puerto Rico, and liquid fuels businesses in both Puerto Rico and Jamaica. Enron Americas plans to capitalize on its historic presence in the Caribbean area to take advantage of significant potential power generation opportunities in the area.
Liquids Marketing. In late 1993 Enron consolidated the management of its international liquids marketing business with the corresponding domestic activities, in order to take advantage of techniques to enhance profitability and manage risks that have proven effective for Enron in the U.S. International liquids marketing volumes declined from 1,180 million gallons in 1992 to 646 million gallons in 1993, reflecting a reduction in spot market transactions in 1993. However, since spot market transactions negatively impacted margin during 1992, margins earned by the international liquids marketing operations improved in 1993.
EXPLORATION AND PRODUCTION
Enron's natural gas and crude oil exploration and production operations are conducted by its subsidiary, Enron Oil & Gas Company ("EOG"). Enron currently owns 80% of the outstanding common stock of EOG.
EOG is one of the largest independent (non-integrated) oil and gas companies in the United States in terms of domestic proved reserves. EOG is engaged in the exploration for, and development and production of, natural gas and crude oil reserves primarily in major producing basins in the United States and, to a lesser extent, in Canada, Trinidad and selected other international areas. At December 31, 1993, EOG had estimated net proved natural gas reserves of 1,772 Bcf and estimated net proved crude oil, condensate and natural gas liquids reserves of 20.9 million barrels, and at such date, approximately 78% of EOG's reserves (on a natural gas equivalent basis) was located in the United States, 16% in Canada and 6% in Trinidad.
EOG's core areas are the Big Piney area in Wyoming, South Texas primarily centered in the Lobo Trend area, the Matagorda Trend area located in federal waters offshore Texas, and the Canyon Trend area located in West Texas. The company's other domestic natural gas and crude oil producing properties are located primarily in other areas of Texas, Utah, New Mexico, Oklahoma and California. At December 31, 1993, 95% of EOG's proved domestic reserves (on a natural gas equivalent basis) was natural gas and 5% was crude oil, condensate and natural gas liquids.
EOG's six principal U.S. producing areas are the Big Piney area, the South Texas area, Matagorda Trend area, the Canyon Trend area, the Pitchfork Ranch field and the Vernal area. Properties in these areas comprised approximately 76% of EOG's domestic reserves (on a natural gas equivalent basis) and 83% of EOG's maximum domestic net natural gas deliverability as of December 31, 1993 and are substantially all operated by EOG. EOG also has operations in Canada and in Trinidad and is conducting exploration in selected other international areas.
EOG is engaged in the exploration for and the development and production of natural gas and crude oil and the operation of natural gas processing plants in western Canada, principally in the provinces of Alberta, Saskatchewan, and Manitoba. EOG conducts operations from offices in Calgary. Effective December 31, 1992, EOG consummated the acquisition of a natural gas property located in the Sandhills field in Saskatchewan. The property was further developed in 1993 through the drilling of 150 wells resulting in deliverability net to EOG from the Sandhills property of approximately 36 MMcf per day at December 31, 1993. Maximum Canadian natural gas deliverability net to EOG at December 31, 1993 was approximately 76 MMcf per day, and EOG held approximately 324,000 net undeveloped acres in Canada.
In November 1992, EOG was awarded a 95% working interest concession in the South East Coast Consortium Block offshore Trinidad, previously held by three government-owned energy companies. Three undeveloped fields containing crude oil and natural gas, including significant condensate, are scheduled for development over the next three to five years. Existing surplus processing and transportation capacity at the Pelican Field facilities owned and operated by Trinidadian 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. At December 31, 1993, maximum natural gas deliverability net to EOG was approximately 40 MMcf per day and EOG held approximately 74,000 net undeveloped acres in Trinidad.
EOG continues to pursue other selected opportunities outside North America. In 1993, two unsuccessful wells were drilled in Malaysia and one in the United Kingdom North Sea area. During 1994, EOG will pursue other opportunities in countries where indigenous natural gas reserves have been identified, particularly where synergies in natural gas transportation, processing and power cogeneration can be optimized with other Enron affiliated companies. EOG currently is actively involved in an effort to obtain joint venture concessions involving two oil fields (Panna and Mukta) and one natural gas field (Tapti) offshore India in the Bombay High area.
In 1993, EOG continued expansion of its international opportunity portfolio in the coalbed methane recovery arena. In September 1992, EOG entered into an operating agreement under which it is serving as operator with another partner in a venture in the Lorraine Basin in France and under which it exercised in March 1994 an option to acquire a 50% working interest in the concession. In addition, a 100% working interest concession has been obtained in the Galilee Basin in Queensland, Australia. Protocols have also been signed and joint venture agreements are in the government approval process in both Russia and Kazakhstan; joint feasibility studies are underway in China; and, several other high potential countries are under active investigation.
EOG actively competes for reserve acquisitions and exploration leases, licenses and concessions, frequently against companies with substantially larger financial and other resources. To the extent EOG's exploration budget is lower than that of certain of its competitors, EOG may be disadvantaged in effectively competing for certain reserves, leases, licenses and concessions. Competitive factors include price, contract terms and quality of service, including pipeline connection times and distribution efficiencies. In addition, EOG faces competition from other producers and suppliers, including increased competition from Canadian natural gas.
All of EOG's oil and gas activities are subject to the risks normally incident to the exploration for and development and production of natural gas and crude oil, including blowouts, cratering and fires, each of which could result in damage to life and property. Offshore operations are subject to usual marine perils, including hurricanes and other adverse weather conditions, and governmental regulations as well as interruption or termination by governmental authorities based on environmental and other considerations. In accordance with customary industry practices, insurance is maintained by EOG against some, but not all, of the risks. Losses and liabilities arising from such events could reduce revenues and increase costs to EOG to the extent not covered by insurance.
EOG's overseas operations are subject to certain risks, including expropriation of assets, risks of increases in taxes and government royalties, renegotiation of contracts with foreign governments, political instability, payment delays, limits on allowable levels of production and current exchange and repatriation losses, as well as changes in laws and policies governing operations of overseas-based companies generally.
The following table sets forth certain information regarding EOG's wellhead volumes of and average prices for natural gas per thousand cubic feet ("Mcf"), crude oil and condensate, and natural gas liquids per barrel ("Bbl"), and average lease and well expenses per thousand cubic feet equivalent ("Mcfe" - natural gas equivalents are determined using the ratio of 6.0 Mcf of natural gas to 1.0 barrel of crude oil and condensate or natural gas liquids) delivered during each of the three years in the period ended December 31, 1993:
The following table sets forth certain information regarding EOG's volumes of natural gas delivered under other marketing and volumetric production payment arrangements, and the resulting average of sale prices and per unit amortization of deferred revenues along with associated costs during each of the three years in the period ended December 31, 1993.
Year Ended December 31,
1993 1992 1991
Volumes (MMcf per day) . . . . . . 293.4(1) 254.9(1) 237.2 Average Gross Revenue ($Mcf) . . . $ 2.57(2) $ 2.62(2) $ 2.63 Associated Costs ($/Mcf) (4) . . . 2.32(3) 1.99(3) 1.75 Margin ($/Mcf) . . . . . . . . . . $ 0.25 $ 0.63 $ 0.88
___________________ (1) Includes 81.0 MMcf per day in 1993 and 27.6 MMcf per day in 1992 delivered under the terms of volumetric production payment and exchange agreements effective October 1, 1992, as amended. (2) Includes per unit deferred revenue amortization for the volumes detailed in note (1) at an equivalent of $2.50 per Mcf ($2.40 per million British thermal units) in 1993 and $2.51 per Mcf ($2.40 per million British thermal units) in 1992. (3) Includes an average value of $2.20 per Mcf in 1993 and $2.37 per Mcf in 1992, including average equivalent wellhead value, any applicable transportation costs and exchange differentials, for the volumes detailed in note (1). (4) Including transportation and exchange differentials.
REGULATION
General
Enron's interstate natural gas pipeline companies are subject to the regulatory jurisdiction of the FERC under the Natural Gas Act ("NGA") with respect to rates, accounts and records, addition of facilities, the extension of services in some cases, the abandonment of services and facilities, the curtailment of gas sales and other matters. Enron's intrastate pipeline companies are subject to state and some federal regulation. Enron's importation of natural gas from Canada is subject to approval by the Office of Fossil Energy of the Department of Energy. Certain activities of Enron are subject to the Natural Gas Policy Act of 1978 ("NGPA"). Enron's pipelines which carry natural gas liquids and refined petroleum products are subject to the regulatory jurisdiction of the FERC under the Interstate Commerce Act as to rates and conditions of service.
Domestic legislation affecting the oil and gas industry is under constant review for amendment or expansion. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue and have issued rules and regulations which, among other things, require permits for the drilling of wells, regulate the spacing of wells, prevent the waste of natural gas and crude oil resources through proration, require drilling bonds and regulate environmental and safety matters. The regulatory burden on the oil and gas industry increases its cost of doing business and, consequently, affects its profitability.
A substantial portion of EOG's oil and gas leases in the Big Piney area and in the Gulf of Mexico, as well as some in other areas, are granted by the federal government and administered by the Bureau of Land Management (the "BLM") and the Minerals Management Service (the "MMS") federal agencies. Operations conducted by EOG on federal oil and gas leases must comply with numerous statutory and regulatory restrictions. Certain operations must be conducted pursuant to appropriate permits issued by the BLM and the MMS.
Various federal, state and local laws and regulations covering the discharge of materials into the environment, or otherwise relating to the protection of the environment, may affect Enron's operations and costs through their effect on the oil and gas exploration, development and production operations as well as their effect on the construction, operation and maintenance of pipeline and terminaling facilities. It is not anticipated that Enron will be required in the near future to expend amounts that are material in relation to its total capital expenditures program by reason of environmental laws and regulations, but inasmuch as such laws and regulations are frequently changed, Enron is unable to predict the ultimate cost of compliance.
Enron's non-domestic businesses are subject to regulation by and the actions of the governments of the countries in which they operate.
Natural Gas Rates and Regulations
Northern, Transwestern, Florida Gas and Northern Border are "natural gas companies" under the NGA and, as such, are subject to the jurisdiction of the FERC. The FERC has jurisdiction over, among other things, the construction and operation of pipeline and related facilities used in the transportation, storage and sale of natural gas in interstate commerce, including the extension, expansion or abandonment of such facilities. The FERC also has jurisdiction over the rates and charges for the transportation of natural gas in interstate commerce and the sale by a natural gas company of natural gas in interstate commerce for resale. Northern, Transwestern, Florida Gas and Northern Border hold the required certificates of public convenience and necessity issued by the FERC authorizing them to construct and operate all of their pipelines, facilities and properties for which certificates are required in order to transport and sell natural gas for resale in interstate commerce. Enron Gas Marketing, a marketing company which sells gas on both a spot and long-term basis to markets both on and off the various Enron pipeline systems, holds a blanket sales certificate issued by the FERC which enables it to make sales for resale in interstate commerce of gas subject to the NGA.
As necessary, Northern, Florida Gas, Transwestern and Northern Border file applications with the FERC for changes in their rates and charges designed to allow them to recover fully their costs of providing service to resale and transportation customers, including a reasonable rate of return. These rates are normally allowed to become effective after a suspension period, subject to refund under applicable law, until such time as the FERC rules on the allowable level of rates. Although the FERC's jurisdiction extends to the regulation of gas transported in interstate commerce or sold in interstate commerce for resale, the price at which gas is sold to direct industrial customers by a natural gas company is not subject to the FERC's jurisdiction.
In June 1988, the FERC issued Order No. 497 ("Order 497") which imposes requirements on interstate pipelines with marketing affiliates, intended to eliminate an interstate pipeline's ability to give its affiliates preferential treatment. Among other things, Order 497 requires interstate pipelines to separate their operating personnel and facilities from those of their affiliates to the maximum extent practicable.
On September 18, 1991, the FERC issued Order No. 555 to revise its regulations governing authorizations to construct natural gas pipeline facilities and its environmental regulations. Order No. 555 proposed substantive revisions to the construction options and rate provisions for interstate pipelines. Although the Order was to become effective on November 19, 1991, pursuant to motions by various parties, including Enron, motions for stay and/or requests for rehearing, the FERC postponed the effective date of Order No. 555 until 30 days after publication in the Federal Register of an order on rehearing. The FERC has conducted technical conferences and received supplemental pleadings with respect to both environmental and non-environmental issues, but has not yet issued another rule. Enron cannot determine at this time what effect, if any, the ultimate action by the FERC on this matter will have.
Since 1985, the FERC has endeavored to make natural gas transportation more accessible to gas buyers and sellers on an open and non-discriminatory basis. These efforts have significantly altered the marketing and pricing of natural gas. The FERC's latest action in this area is Order No. 636, issued in April 1992, which mandates a fundamental restructuring of interstate pipeline sales and transportation services. Order No. 636 requires interstate natural gas pipelines to "unbundle" or segregate the sales, transportation, storage, and other components of their existing sales service, and to separately state the rates for each unbundled service. Under Order No. 636, unbundled pipeline sales can be made only in the production areas. Order No. 636 also requires interstate pipelines to assign capacity rights they have on upstream pipelines to such pipelines' former sales customers and provides for the recovery by interstate pipelines of costs associated with the transition from providing bundled sales services to providing unbundled transportation and storage services. The purpose of Order No. 636 is to further enhance competition in the natural gas industry by assuring the comparability of pipeline sales service and services offered by a pipelines' competitors. Various aspects of Order No. 636 were challenged, including alleged shifts of costs between pipeline customer groups and the continuing reliability of unbundled services. In two subsequent orders on rehearing of Order No. 636 (Order Nos. 636-A and 636-B), the FERC modified the original order in response to these and other concerns. Numerous parties have filed petitions for court review of Order Nos. 636, 636-A and 636- B, as well as orders in individual pipeline restructuring proceedings. Upon such judicial review, these orders may be reversed in whole or in part. With Order No. 636 only partially implemented and subject to court review, it is difficult to predict with precision its effects.
Enron believes that, overall, Order No. 636 will have a positive impact on Enron and the natural gas industry as a whole. The structural changes mandated by Order No. 636 will result in a more competitive industry. The straight fixed variable rate design included in Order No. 636 allows pipelines to recover in the demand component of their rates all fixed costs allocated to firm customers. Since a pipeline recovers demand costs regardless of whether gas is ever transported, the straight fixed variable rate design is expected to reduce the volatility of the revenue stream to pipelines.
Enron's interstate pipelines have all successfully completed their transitions under FERC Order No. 636, and have completely unbundled their sales services from their transportation services. As required by Order No. 636, Northern, Transwestern and Florida Gas each has implemented a straight fixed variable rate design which provides that all fixed costs allocated to firm customers, including income taxes and return on equity, are to be received through fixed monthly demand or capacity reservation charges which are not a function of volumes transported. Under their respective restructuring orders, Enron's interstate pipelines are entitled to recover FERC Order No. 636 transition costs from customers. Transition costs incurred of $168 million have been deferred pending recovery from customers over varying time periods, generally of up to five years. Future transition costs are subject to ongoing negotiations and market factors. Enron believes that the ultimate resolution of FERC Order No. 636 transition costs will not have a material impact on Enron's financial position or results of operations.
On October 28, 1993, the FERC issued a Notice of Public Conference in Docket No. RM94-4-000 in order for the FERC to explore issues such as the extent to which it should exercise NGA Sections 4 and 5 jurisdiction over the rates, terms and conditions for gathering services performed by interstate pipelines and their affiliates, production-area transportation rates and rate design, and the proper treatment of interstate pipeline profits from the sale of gathering systems to an affiliate or non-related entity. The FERC has received written comments as well as conducted the technical conference. Enron cannot determine at this time what effect, if any, the ultimate action by the FERC on this matter will have.
The rates at which natural gas is sold in Texas to gas utilities serving customers within an incorporated area and directly to customers in rural and unincorporated areas are subject to the original jurisdiction of the Railroad Commission of Texas. The rates set by city councils or commissions for gas sold within their jurisdiction may be appealed to the Railroad Commission. Regulation of intrastate gas sales and transportation by the Railroad Commission is governed by certain provisions of the Texas Gas Utility Regulatory Act of 1983. The Railroad Commission also regulates production activities and to some degree the operation of affiliated special marketing programs.
Oil Pipeline Rates and Regulations
The North System and Cypress Pipeline of Enron Liquids Pipeline Operating Limited Partnership (the "Partnership") are interstate common carrier pipelines, subject to regulation by the FERC under the Interstate Commerce Act ("ICA"). The ICA requires the Partnership to maintain tariffs on file with the FERC, which tariffs set forth the rates the Partnership charges for providing transportation services on the interstate common carrier pipelines, as well as the rules and regulations governing these services.
Environmental Regulations
Enron and its subsidiaries are subject to extensive federal, state and local laws and regulations covering the discharge of materials into the environment, or otherwise relating to the protection of the environment, and which require expenditures for remediation at various operating facilities and waste disposal sites, as well as expenditures in connection with the construction of new facilities. Enron believes that its operations and facilities are in general compliance with applicable environmental regulations. Environmental laws and regulations have changed substantially and rapidly over the last 20 years, and Enron anticipates that there will be continuing changes. The clear trend in environmental regulation is to place more restrictions and limitations on activities that may impact the environment, such as emissions of pollutants, generation and disposal of wastes and use and handling of chemical substances. Increasingly strict environmental restrictions and limitations have resulted in increased operating costs for Enron and other businesses throughout the United States, and it is possible that the costs of compliance with environmental laws and regulations will continue to increase. Enron will attempt to anticipate future regulatory requirements that might be imposed and to plan accordingly in order to remain in compliance with changing environmental laws and regulations and to minimize the costs of such compliance.
The Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA"), also known as the "Superfund" law, requires payments for cleanup of certain abandoned waste disposal sites, even though such waste disposal activities were undertaken in compliance with regulations applicable at the time of disposal. Under the Superfund legislation, one party may, under certain circumstances, be required to bear more than its proportional share of cleanup costs at a site where it has responsibility pursuant to the legislation, if payments cannot be obtained from other responsible parties. Other legislation mandates cleanup of certain wastes at facilities that are currently being operated. States also have regulatory programs that can mandate waste cleanup. CERCLA authorizes the Environmental Protection Agency ("EPA") and, in some cases, third parties to take actions in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. The scope of financial liability under these laws involves inherent uncertainties. Enron has entered into a consent decree with the EPA and other potentially responsible parties ("PRPs") with respect to the cleanup of one Superfund site. Enron has received requests for information from the EPA and state agencies concerning what wastes Enron may have sent to certain sites, and it has also received requests for contribution from other parties with respect to the cleanup of other sites. However, management does not believe that any costs incurred in connection with these sites (either individually or in the aggregate) will have a material impact on Enron's financial condition or results of operations. (See Item 3, "Legal Proceedings").
OPERATING STATISTICS
The following table presents selected statistical information for Enron's natural gas and liquid fuels business segments as well as revenue data for all of Enron's businesses. Natural gas volumes for the Gas Services Group exclude volumes delivered on the Enron pipeline system. Revenue amounts are in thousands of dollars.
CURRENT EXECUTIVE OFFICERS OF THE REGISTRANT
Name and Age Present Principal Position and Other Material Positions Held During Last Five Years
Kenneth L. Lay (51) Chairman of the Board and Chief Executive Officer since February 1986. President from February 1989 to October 1990.
Richard D. Kinder (49) President and Chief Operating Officer since October 1990. Vice Chairman of the Board from December 1988 to October 1990, and Chairman and Chief Executive Officer of Enron Gas Pipeline Group from January 1989 to October 1990. Executive Vice President and Chief of Staff from August 1987 to December 1988.
Ronald J. Burns (40) Chairman and Chief Executive Officer (Marketing and Supply), Enron Gas Services Corp., since June 1993. Chairman and Chief Executive Officer, Enron Pipeline and Liquids Group from 1992 to June 1993. Chairman and Chief Executive Officer, Enron Corp. Gas Pipeline Group from October 1990 to October 1992. President, Enron Corp. Interstate Pipeline Group from 1988 to October 1990.
Rodney L. Gray (41) Chairman and Chief Executive Officer, Enron International Inc. since June 1993. Senior Vice President, Finance and Treasurer from October 1992 to June 1993. Vice President, Finance and Treasurer from 1988 to October 1992.
Jeffrey K. Skilling (40) Chairman and Chief Executive Officer (Risk Management and Power), Enron Gas Services Corp., since June 1993. Chairman and Chief Executive Officer of Enron Gas Services Corp. from January 1991 to June 1993. Chairman and Chief Executive Officer of Enron Finance Corp. since August 1990; Partner, McKinsey & Company, Consultants, from 1979 to August 1990.
Thomas E. White (50) Chairman and Chief Executive Officer of Enron Operations Corp. since June 1993. Chairman and Chief Executive Officer of Enron Power Corp. since July 1991; Brigadier General, United States Army, from 1988 to 1990; Executive Assistant to Chairman of the Joint Chiefs of Staff from 1989 to 1990.
Robert C. Kelly (47) Executive Vice President and Chief Strategy Officer since July 1993. President of Enron Emerging Technologies, Inc. since January 1994. Chairman and Chief Executive Officer of Enron International Inc. from December 1992 to July 1993. Vice Chairman and Chief Development Officer of Enron Power Corp. from May 1989 to December 1992.
Edmund P. Segner,III (40) Executive Vice President and Chief of Staff since October 1992. Senior Vice President, Investor, Public & Government Relations from October 1990 to October 1992. Vice President, Public and Investor Relations from February 1988 until October 1990.
James V. Derrick, Jr.(49) Senior Vice President and General Counsel since June 1991. Partner, Vinson & Elkins from January 1977 until June 1991.
Jack I. Tompkins (48) Senior Vice President and Chief Information, Administrative and Accounting Officer since October 1992. Senior Vice President and Chief Financial Officer from January 1988 to October 1992. Partner, Arthur Andersen & Co. from September 1981 until January 1988.
Kurt S. Huneke (40) Vice President, Finance and Treasurer since July 1993; Executive Vice President, Finance and Administration, Enron International Inc., from July 1992 to July 1993; Senior Vice President and Chief Financial Officer, Enron Europe Limited, from January 1991 to July 1992; Assistant Treasurer, Enron Corp., from February 1989 to January 1991.
Item 2.
Item 2. PROPERTIES
Gas Transmission and Liquid Fuels
Enron's natural gas facilities include approximately 44,000 miles of transmission and gathering lines, 111 mainline compressor stations, four underground gas storage fields and two liquefied natural gas storage facilities. Other properties in which Enron and its subsidiaries have an ownership interest or lease include 22 natural gas liquids extraction plants in Texas, Louisiana, Wyoming, Kansas, Florida, New Mexico and North Dakota. A large number of railroad tank and hopper cars, truck transports and bulk vehicles are owned or leased and used for the delivery of liquids products. Enron also owns interests in pipeline and related facilities associated with its participation and investments in jointly-owned pipeline systems.
Substantially all the gathering and transmission lines of Enron are constructed on rights-of-way granted by the apparent record owners of such property. In many instances, lands over which rights-of-way have been obtained are subject to prior liens which have not been subordinated to the right-of-way grants. In some cases, not all of the apparent record owners have joined in the right-of-way grants, but in substantially all such cases, signatures of the owners of majority interests have been obtained. Permits have been obtained from public authorities to cross over or under, or to lay facilities in or along, water courses, county roads, municipal streets and state highways, and in some instances, such permits are revocable at the election of the grantor. Permits have also been obtained from railroad companies to cross over or under lands or rights-of-way, many of which are also revocable at the grantor's election. Some such permits require annual or other periodic payments. In a few minor cases, property for pipeline purposes was purchased in fee.
Most of Enron's transmission subsidiaries have the right of eminent domain to acquire rights-of-way and lands necessary for their pipelines and appurtenant facilities.
Enron's gas processing plants and regulator and compressor stations and offices are located on tracts of land owned by it in fee or leased from others.
In the case of oil and gas leases, definitive examination and curing of title defects are usually deferred until such time as funds are expended in connection with drilling of such properties.
Enron is of the opinion that it has generally satisfactory title to its rights-of-way and lands used in the conduct of its businesses, subject to liens for current taxes, liens incident to operating agreements and minor encumbrances, easements and restrictions which do not materially detract from the value of such property or the interest of Enron therein or the use of such properties in such businesses.
Oil and Gas Exploration and Production Properties and Reserves
Reserve Information
For estimates of EOG's net proved reserves and proved developed reserves of natural gas and crude oil, see Note 20 to the Consolidated Financial Statements.
Estimates of proved and proved developed reserves at December 31, 1991, 1992 and 1993 were based on studies performed by EOG's engineering staff for reserves in both the United States and Canada. Opinions by DeGolyer and MacNaughton, independent petroleum consultants, for the years ended December 31, 1991, 1992 and 1993 covering producing areas containing 73%, 69% and 65%, respectively, of proved reserves of EOG on a net-equivalent-cubic-feet-of-gas basis, indicate that the estimates of proved reserves prepared by EOG's engineering staff for the properties reviewed by DeGolyer and MacNaughton, when compared in total on a net-equivalent-cubic-feet-of-gas basis, do not differ materially from the estimates prepared by DeGolyer and MacNaughton. Such estimates by DeGolyer and MacNaughton in the aggregate varied by not more than 5% from those prepared by EOG's engineering staff. All reports by DeGolyer and MacNaughton were developed utilizing geological and engineering data provided by EOG.
There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond the control of the producer. The reserve data set forth in Note 20 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. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, estimates of different engineers often 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 20.
Producing Oil and Gas Wells
The following summary reflects EOG's ownership at December 31, 1993 in gas wells in 316 fields and oil wells in 75 fields located in Texas, offshore Texas and Louisiana in the Gulf of Mexico, Oklahoma, New Mexico, Utah, Wyoming, California and various other states, Canada and Trinidad. "Net" is obtained by multiplying "Gross" by EOG's working interests in the properties. Gross oil and gas wells include 229 with multiple completions.
Acreage
The following table summarizes EOG's developed and undeveloped acreage at December 31, 1993. 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, 1993, 1992 and 1991, EOG spent approximately $430.1 million, $395.7 million and $254.8 million, respectively, for exploratory and development drilling and acquisition of leases and producing properties. EOG drilled, participated in the drilling of or acquired wells as set out in the table below for the periods indicated:
All of EOG's drilling activities are conducted on a contract basis with independent drilling contractors. EOG owns no drilling equipment.
Item 3.
Item 3. LEGAL PROCEEDINGS
Enron is a party to various claims and litigation, the significant items of which are discussed below. Although no assurances can be given, Enron believes, based on its experience to date and after considering appropriate reserves that have been established, that the ultimate resolution of such items, individually or in the aggregate, will not have a materially adverse impact on Enron's financial position or results of operations.
Litigation
TransAmerican Natural Gas Corporation (TransAmerican) has filed a petition in the 93rd District Court, Hidalgo County, Texas, against Enron Corp. and EOG alleging breach of confidentiality agreements, misappropriation of trade secrets and unfair competition, with specific reference to four tracts in Webb County, Texas, which EOG leased for their oil and gas exploration and development potential. TransAmerican seeks actual damages of $100 million and exemplary damages of $300 million. EOG has filed claims against TransAmerican and its sole shareholder alleging fraud, negligent misrepresentation and breach of state antitrust laws. Trial is set for September 12, 1994. Although no assurances can be given, Enron believes that TransAmerican's claims are without merit and that the ultimate resolution of this matter will not have a materially adverse effect on its financial position or results of operations.
A pipeline company in which an Enron affiliate has a minority interest and for which an Enron affiliate has served as operator has filed a petition against Enron and certain affiliates alleging an unspecified amount of damages relating to the operation of such pipeline company. Based upon information currently available, it is not possible to predict the outcome of such litigation; however, Enron believes that the results will not have a materially adverse effect on Enron's financial position or results of operations.
Like other companies in the natural gas industry, Enron has certain gas purchase contracts which provide for take-or-pay obligations and fixed prices. Certain suppliers have made claims, either formally or informally, for payment under take-or-pay provisions. At December 31, 1993, amounts of pending take-or-pay claims and litigation are not material.
Peruvian Operations
During 1985, the Peruvian government unilaterally cancelled certain exploration and production agreements between the government- owned oil company and Belco Petroleum Corporation of Peru (BPCP), a wholly-owned subsidiary of Enron, and subsequently nationalized the operations of BPCP. Enron filed claims with its insurers in connection with the nationalization and in February 1989, the insurers paid Enron approximately $162 million. On September 21, 1993, the Peruvian government signed a settlement agreement with American International Group, Inc. and BPCP which will allow Enron to recover its remaining investment of approximately $33 million.
Environmental Matters
Enron is subject to extensive Federal, state and local environmental laws and regulations. These laws and regulations require expenditures in connection with the construction of new facilities, the operation of existing facilities and for remediation at various operating sites. The implementation of the Clean Air Act Amendments is expected to result in increased operating expenditures. The related future cost is indeterminable, as many of the rules implementing the Clean Air Act's requirements have not yet been finalized. However, any increased operating expenses are not expected to have a material impact on Enron's financial position or results of operations.
During May 1992, Enron entered into a Consent Decree with the EPA concerning the cleanup of the Peoples Natural Gas Superfund Site in Dubuque, Iowa, where a coal gasification plant had operated during the first half of this century. The EPA had claimed that Enron was a PRP because a predecessor company of Enron had purchased the site in the late 1950's after coal gas operations ceased, and had conducted surface operations there, including the dismantling of buildings. In the second quarter of 1992, Enron recorded the expense and related liability for these cleanup costs and under the Consent Decree agreed to make five equal, annual payments of $590,000. Two of such installments have been paid and the third installment is due and payable in June 1994.
In addition, Enron has received requests for information from the EPA and state environmental agencies inquiring whether Enron has disposed of materials at other waste disposal sites. Enron has also received requests for contribution from other parties with respect to the cleanup of other sites. Enron may be required to share in the costs of the cleanup of some of these sites. However, based upon the amounts claimed and the nature and volume of materials sent to sites at which Enron has an interest, management does not believe that any potential costs incurred in connection with these notices and third party claims, either taken individually or in the aggregate, will have a material impact on Enron's financial position or results of operations.
Item 4.
Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
There were no matters submitted to a vote of security holders during the fourth quarter of 1993.
Item 5.
Item 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
Common Stock
On August 16, 1993, Enron effected a two-for-one common stock split on all issued common stock in the form of a stock dividend. 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 (1992 sales prices and dividends paid per share have been restated to reflect the stock split). The common stock is also listed for trading on the Midwest Stock Exchange and the Pacific Stock Exchange, as well as the London Stock Exchange and Frankfurt Stock Exchange.
$10.50 Cumulative Second Preferred Convertible Stock
The following table indicates the high and low sales prices for the $10.50 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 Midwest Stock Exchange.
At December 31, 1993, there were approximately 27,000 record holders of common stock, and 276 record holders of Second Preferred Stock.
Other information required by this item is set forth on page 31 under Item 6
Item 6 SELECTED FINANCIAL DATA (UNAUDITED)
Item 7.
Item 7. Enron Corp. and Subsidiaries 			 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 subsidiaries (Enron) should be read in conjunction with the Consolidated Financial Statements.
Results of Operations
Consolidated Net Income Enron's net income for 1993 was $387 million, exclusive of a primarily non-cash charge of $54 million to adjust the deferred tax liability for the increase in the corporate Federal statutory income tax rate from 34% to 35%, compared to $306 million and $232 million for 1992 and 1991, respectively. Net income for all three years reflects improved income before interest, minority interest and income taxes as compared to the applicable preceding year. Net income for 1993 includes a $64 million pretax gain from the sale of limited partnership units in Northern Border Partners, L.P., substantially offset by the establishment of reserves for litigation and other contingencies. The net income for 1993 also includes $13 million in pretax gains from the sales of oil and gas properties and a $10 million net share of a deferred tax reduction at Enron Oil & Gas Company (EOG).
Net income for 1992 includes a $60 million nontaxable gain from the sale of stock by EOG, a $52 million pretax gain from the sale of Enron's remaining investment in Mobil Corporation common stock (Mobil stock), $6 million in pretax gains from the sales of oil and gas properties and an $11 million gain on the sale of investments. These amounts were partially offset by a $57 million pretax charge reflecting the establishment of reserves for litigation and other contingencies and a $23 million extraordinary charge relating to the early retirement of high coupon debt.
Net income for 1991 includes a $28 million pretax gain from the sale of a portion of Enron's investment in Mobil stock, a $24 million pretax gain from two favorable litigation settlements, $15 million in pretax gains from the sales of oil and gas properties and a $14 million pretax gain from the sale of certain gas processing assets.
Primary earnings per share of common stock was $1.32 in 1993, after a $0.23 per share charge applicable to the $54 million tax rate change adjustment, as compared to $1.29 and $1.03 in 1992 and 1991, respectively.
Income Before Interest, Minority Interest and Income Taxes The following table presents income before interest, minority interest and income taxes (IBIT) for each of Enron's operating segments:
Transportation and Operation
The transportation and operation segment includes Enron's regulated natural gas pipelines, construction, management and operation of pipelines, liquids plants and power facilities, Enron's crude oil marketing and transportation operations conducted by EOTT Energy Corp. (EOTT) and Enron's investment in liquids pipeline operations. The segment realized a $4 million increase in IBIT in 1993 as compared to 1992. The increase was due primarily to increases in IBIT realized by the regulated natural gas pipelines and the crude oil marketing and transportation operations, offset by declines in earnings from the liquids pipeline operations due to the sale of a significant portion of these operations in August 1992 and reduced revenues on completed construction projects. During 1992, the transportation and operations segment's IBIT increased 10% as compared to 1991 reflecting higher regulated natural gas pipeline earnings and increased revenues recognized in connection with the construction of various power projects. These increases were offset by lower earnings from EOTT and from liquids pipeline operations. The following discussion analyzes the significant changes in the various components of income before interest, minority interest and income taxes for the transportation and operation segment.
Revenues
Regulated Natural Gas Pipelines Revenues of the regulated natural gas pipelines increased approximately $60 million (5%) during 1993 after declining $120 million (9%) in 1992 as compared to the applicable preceding year. The increase in revenues reflects increased transportation revenues recognized by Northern Natural Gas Company (Northern) primarily as a result of higher commodity volumes and increased capacity utilization, combined with management fees earned in connection with the operation of the Argentina pipeline in which Enron owns a 17.5% interest. These increases were offset by reduced sales revenues for both Northern and Transwestern Pipeline Company (Transwestern) as those companies are now primarily transporters of natural gas.
During 1992, revenues of the regulated natural gas pipeline companies declined primarily as a result of lower sales revenues realized by Northern reflecting a 27% decline in sales volumes due to the shifting of customers from sales service to transport service and lower revenues earned by Transwestern. The decline in Transwestern's revenues reflects lower transport rates as a result of the completion by Transwestern of the recovery of certain transition costs in early 1992. These declines were partially offset by higher transportation volumes resulting from Transwestern's mainline expansion and San Juan extension which became operational at the end of the first quarter of 1992. In addition, Northern's transportation revenues increased 17% during 1992 as a result of higher volumes.
Sales and transportation volumes were as follows:
Construction and Management Revenues Revenues earned in connection with the construction and operation of power projects totaled $27 million in 1993 as compared to $52 million and $23 million during 1992 and 1991, respectively. The decline during 1993 reflects reduced construction revenues in connection with the Teesside power project in the United Kingdom as a result of the completion of that project in March 1993, offset by revenues earned in connection with the sales of fuel to a joint venture power project in Guatemala and fees earned in connection with the management and construction of the Milford power project in the United States.
Liquids Pipeline and EOTT Revenues earned in connection with the liquids pipeline operations declined in 1993 and 1992 primarily as a result of the sale of those assets to Enron Liquids Pipeline, L.P., a master limited partnership formed in August 1992. Net revenues from EOTT increased approximately 39% during 1993 as a result of higher product margins.
Cost of Gas and Other Products Sold The cost of gas and other products sold by the transportation and operation segment decreased by less than 1% during 1993 as compared to 1992 primarily as a result of higher average per unit gas purchase costs being offset by lower purchase volumes. During 1992, the cost of gas and other products sold by the transportation and operations segment declined 19% as compared to 1991 due primarily to a 27% decline in Northern's sales volumes combined with a 59% reduction in Transwestern's sales volumes. These declines were offset in part by higher average per unit gas purchase costs.
Operating Expenses Operating expenses in the transportation and operation segment declined 10% during 1993 as compared to 1992. The decline reflects lower expenses of the regulated natural gas pipelines as a result of efficiencies gained in connection with system modernization projects, combined with a decline in operating expenses due to the previously discussed sale of the liquids pipeline operations. During 1992, operating expenses of the transportation and operation segment declined by 10% as compared to 1991 primarily as a result of lower operating expenses of the regulated pipeline group as a result of lower transmission and compression expenses reflecting lower sales volumes and the sale of the liquids pipeline operations.
Amortization of deferred contract reformation costs declined by 12% during 1993 and 19% during 1992 as compared to the applicable preceding year primarily as a result of Transwestern's completion of the recovery of certain transition costs in early 1992.
Depreciation expense for the transportation and operation segment increased $5 million (4%) during 1993 as compared to 1992 primarily as a result of a 10% increase in depreciation expense recognized by the regulated natural gas pipeline group reflecting Northern's adjustment in 1993 of accumulated depreciation in accordance with a Federal Energy Regulatory Commission (FERC) ruling. The increase in depreciation by Northern was partially offset by a decline in depreciation recorded for the liquids pipeline operations.
Other Income and Deductions Equity in earnings of unconsolidated subsidiaries declined by $14 million (39%) during 1993 as compared to 1992 reflecting reduced earnings from Northern Border Pipeline Company (Northern Border) as a result of Enron's contribution of its investment in Northern Border to Northern Border Partners, L.P., a master limited partnership (the Partnership) and Enron's subsequent sale of a portion of its interest in the Partnership in an underwritten public offering (see Note 9 to the Consolidated Financial Statements). Additionally, during 1993 equity in earnings from Mojave Pipeline Company (Mojave) decreased as a result of the sale of Enron's investment in Mojave during 1993. Equity in earnings of unconsolidated subsidiaries of the transportation and operation segment remained virtually unchanged in 1992 as compared to 1991 as increased earnings from Northern Border were offset by lower earnings from Citrus Corp. and Mojave.
Outlook Transportation and Operation The transportation and operation segment should continue to provide stable earnings and cash flows during 1994. Full implementation of FERC Order 636 and the successful settlement of all significant regulatory issues by the regulated natural gas pipelines during 1993 should allow for a constant and reliable stream of cash flow. Additionally, the segment will actively promote engineering and construction services to provide incremental earnings and will seek to selectively monetize assets and reinvest proceeds in system modernization projects and reduce its overall cost structure. Expansion of the Florida Gas pipeline system should also provide growth opportunities for the transportation and operations segment.
In January 1994, Enron filed a registration statement with the Securities and Exchange Commission to sell units in a master limited partnership which will contain substantially all of the operations and assets of EOTT. EOTT will serve as general partner and own a substantial interest in the new limited partnership (see Note 3 to the Consolidated Financial Statements).
Gas Services Enron's Gas Services segment (EGS) had a $22 million (15%) increase in income before interest, minority interest and income taxes in 1993 as compared to 1992. The increase was due primarily to increased production payments arranged, successful long-term contracting efforts and the continued growth of the physical and financial risk management services provided to the natural gas business. Offsetting these increases were declines in earnings associated with EGS's North American power ventures and natural gas liquids (NGL) marketing activities. Each year's results also include earnings from the Sithe Energies contract (Sithe). The Sithe contract, which was signed in 1992, provides for Enron Power Services Inc. to deliver approximately 1.5 trillion cubic feet of gas over the next 20 years (five years on a fixed-price basis) to fuel Sithe's independent power project in upstate New York. Income before interest, minority interest and income taxes increased $76 million (107%) in 1992 as compared to 1991 due primarily to long- term contracting and production payment activities.
Statistics for the gas services segment are as follows:
EGS's strategy is to provide predictable pricing, reliable delivery and low cost capital to its customers. EGS provides these services through a variety of financial instruments including forward contracts, swap agreements, options, futures and other contractual commitments.
These services can be categorized into four business lines: Gas, Power, Finance and Liquids. The following discussion analyzes the contributions to income before interest, minority interest and income taxes and the future outlook for each of the businesses.
Gas. The Gas operations include price risk management and origination activities as well as the physical natural gas trading and transportation activities of Enron Gas Marketing, Houston Pipe Line Company, Enron Access, the Louisiana Resources companies and the Canadian gas supply and marketing operations. The earnings from these activities increased 30% in 1993 primarily as a result of increases in sales volumes. The volume increase is primarily attributable to continued growth in the derivatives business, the September 1992 acquisition of Enron Access, the April 1993 acquisition of Louisiana Resources and expansion into the Canadian market. The 1993 results also include earnings from significant fixed and index-priced contract originations and management of the existing contract portfolio. Earnings during 1992 included fixed price originations and earnings from the marketing and trading activities and was virtually unchanged as compared to 1991.
During 1994, EGS anticipates continued strong performance from its gas business. Growth in the physical and financial trading activities is expected despite continued competition from financial and industry companies, particularly in the derivatives area. Additionally, contract originations should increase as the impact of FERC Order 636 becomes more evident.
Power. EGS's Power business includes activities in North America such as providing natural gas contract services to the power industry; managing, acquiring and developing power- related assets and joint ventures; and marketing and supplying electricity. Power's earnings declined 15% during 1993 due primarily to the inclusion in 1992 of earnings associated with the Richmond and Milford power projects. The 1993 and 1992 results also included earnings related to the gas forward sales contract with Sithe. Earnings in 1993 and 1992 also included significant contract originations involving sales of gas to other power generation facilities. The 1992 results were significantly higher than 1991 reflecting the initiation of contract origination activities.
The Power operations will benefit in 1994 from the opportunities being created in the power marketing area as a result of the continuing regulatory and economic changes in the electric industry. During 1994, EGS expects to compete as an independent marketer of electricity. Additionally, EGS will aggressively continue marketing of natural gas to independent power projects as well as electric utilities converting to natural gas in response to the Clean Air Act of 1990.
Finance. Enron Finance Corp. (EFC) secures natural gas supplies from independent producers through a variety of financial transactions, primarily volumetric production payments. EFC arranges these transactions through financial entities and provides related price risk management services. Additionally, EGS purchases the natural gas and crude oil associated with these transactions. EFC's earnings increased 50% in 1993 due primarily to increased non-affiliated production payments and financings arranged. EFC's earnings increased during 1992 as compared to 1991 due to increased production payment activities. From inception through December 31, 1993, production payments and financings arranged total over $1 billion.
In 1994, EFC expects continued growth in its business resulting primarily from offerings of innovative alternative financing to producers. This activity will include production payments, debt and equity financings, as well as other products. During 1993, Joint Energy Development Investments, a limited partnership, was formed comprised of an EGS subsidiary as general partner and the California Public Employees Retirement System (CalPERS) as limited partner. The partnership will provide significant capital for energy investments.
Liquids. The Liquids business of EGS includes the North American natural gas liquids (NGL) marketing activities and the Clean Fuels business which consists of the methanol and methyl tertiary butyl ether (MTBE) businesses. Liquids earnings were virtually unchanged from 1992 to 1993. Earnings from the Clean Fuels business increased as a result of higher MTBE volumes and the impact of reflecting contractual commitments at market value. The Clean Fuels increase was partially offset by a decrease in the NGL marketing results due to lower volumes and margins. Liquids earnings declined 40% from 1991 to 1992 due primarily to expenses associated with the start-up of the Clean Fuels business and the impact of lower NGL prices.
During 1994, EGS's Liquids business expects to improve its NGL marketing results by expanding to provide derivative products in that area. Additionally, in the MTBE business, EGS plans to continue development of its merchant business by actively marketing MTBE, including long-term and fixed margin-based pricing terms. Although current MTBE prices continue to be weak, market conditions are expected to improve as the Clean Air Act of 1990 mandates the increased use of reformulated gasoline (a primary market for MTBE).
Other. EGS's net unallocated expenses such as rent, systems expenses and other support group costs increased 27% in 1993 as compared to 1992 due primarily to continued expansion into new markets, system upgrades and the generally increased level of activity. Expenses increased 45% from 1991 to 1992 due also to increased activity and establishment of certain contingency reserves.
Gas Processing
The income before interest and taxes of the gas processing segment totaled $28 million in 1993 as compared to $56 million in 1992 and $94 million in 1991. The declines in both 1992 and 1993 as compared to the applicable preceding years were attributable primarily to lower processing margins reflecting higher natural gas feedstock prices and lower product prices. Volume and price statistics for the gas processing segment (including intercompany amounts) are detailed below:
Revenues Revenues of the gas processing segment increased 4% during 1993 after an increase of 8% during 1992 as compared to the applicable preceding year. In both 1993 and 1992, the increase in revenues was primarily caused by increased production volumes partially offset by reduced product prices.
Costs and Expenses The cost of products sold by the gas processing segment increased 22% in 1993 as compared to 1992 and 20% in 1992 as compared to 1991. The increases in both years were attributable to higher natural gas feedstock prices combined with higher production volumes. The increases in cost of products sold coupled with reduced product prices resulted in declines in gross margin of the domestic gas processing segment of 48% in 1993 and 18% in 1992.
Other Income and Deductions Other income increased $23 million during 1993 as compared to 1992 primarily as a result of gains realized on the sales of certain coal handling and NGL assets.
Outlook In 1994, Enron plans to mitigate the market risk inherent in the gas processing business through hedging techniques. Additionally, cost cutting and streamlining actions have recently been completed, positioning the business to maximize earnings opportunities.
International Gas and Power Services Enron's international gas and power services segment includes its international power, pipeline and natural gas liquids marketing operations. International power operations include the development and promotion of power and natural gas projects worldwide. Income before interest and taxes for the international gas and power services group totaled $132 million during 1993, $33 million in 1992 and $69 million in 1991. The increase in IBIT between 1992 and 1993 and the decline between 1991 and 1992 primarily reflects the promotion and development activities of its power operations. The 1993 increase also reflects earnings from the Argentina pipeline operations acquired in the fourth quarter of 1992.
Revenues Revenues of the international gas and power services segment declined 12% during 1993 as compared to 1992 primarily as a result of decreased revenues earned by the international gas liquids marketing operations. These declines were caused by a 45% decline in marketing volumes as compared to the prior year, reflecting reduced spot market activity. The decline in liquids marketing revenues was partially offset by a $102 million increase in revenues in the power operations. The increase reflects revenues earned in connection with the promotion and development of liquids and power projects of which approximately $55 million is related to revenues earned in connection with the promotion and sale of liquids processing facilities at Teesside.
During 1992, revenues of the international gas and power services segment declined 15% as compared to 1991 primarily as a result of lower liquids marketing and power revenues. Liquids marketing revenues declined by 13% reflecting a 14% decline in marketing volumes. Power revenues declined $46 million (87%) primarily as a result of promotion and development revenues earned in connection with the Teesside power project in 1991.
Costs and Expenses The cost of gas and other products sold by the international gas and power services segment declined by 24% in 1993 as compared to 1992 and reflected the previously mentioned decline in international liquids marketing volumes. Operating expenses increased $20 million (40%) during 1993 as compared to 1992 primarily as a result of higher operating expenses incurred in connection with increased activities in the power operations area.
Operating income for the segment increased $69 million during 1993 as compared to 1992 as a result of the previously mentioned successful power development and promotion activities and improved margins earned by the international liquids marketing operations reflecting a reduction in spot market transactions which negatively impact margin. Operating income declined by $45 million during 1992 as compared to 1991 primarily as a result of the recognition in 1991 of promotion and development revenues earned in connection with the Teesside power project.
Other Income and Deductions Equity in earnings of unconsolidated subsidiaries of the international gas and power services segment increased $36 million during 1993 as compared to 1992 primarily as a result of $23 million in earnings from the Argentina pipeline project and $12 million in earnings from the Teesside power project which was placed in commercial operation during the first quarter of 1993. Other income, net, declined $7 million during 1993 primarily as a result of lower interest income earned by the power operations in 1993 as compared with 1992 combined with gains on asset sales realized by Enron's operations in South America (Enron Americas) during 1992. Other income increased $8 million during 1992 as compared to 1991 primarily as a result of the gain on asset sales realized by Enron Americas.
Outlook The objective of the international gas and power services segment is to deliver Enron's extensive product line to the international marketplace including Enron's product concepts in the areas of marketing and risk management of natural gas based products. Growth opportunities in that market should result from the current and projected high demand for electrical power generation, the under utilization of natural gas reserves throughout the world and increased environmental awareness.
Exploration and Production Income before interest, minority interest and income taxes for EOG increased $20 million (20%) during 1993 and $27 million (36%) during 1992 as compared to the applicable preceding year due primarily to higher natural gas prices and volumes, and lower per unit operating costs.
Volume and price statistics are as follows (including intercompany amounts):
The following discussion further analyzes the significant changes in EOG's results.
Revenues EOG's gross revenues increased $133 million (24%) during 1993 and $84 million (18%) in 1992 as compared to the applicable preceding year. The increased revenues in 1993 are attributable to a 22% increase in average wellhead natural gas prices combined with a 26% increase in average wellhead natural gas volumes. The increased natural gas volumes primarily reflect the effects of exploration and development activities relating to tight gas sand formations. The increased revenues in 1992 are attributable to a 15% increase in average wellhead natural gas delivered volumes combined with a 15% increase in average wellhead natural gas prices. Although exploration and development efforts resulted in deliverability increases in certain core areas, the earnings in 1992 and 1991 were mitigated by voluntary curtailments initiated due to lower than acceptable prices during certain periods.
Costs and Expenses The cost of gas sold by the exploration and production segment in connection with other natural gas marketing activities increased 18% in 1993 as compared to 1992 and 23% in 1992 as compared to 1991. The increase in 1993 as compared to 1992 was due to 17% higher average associated costs per Mcf combined with a 15% increase in natural gas marketing volumes. The increase in 1992 was due to 14% higher average associated costs per Mcf combined with 8% higher other natural gas marketing volumes.
Operating expenses for the exploration and production segment increased $35 million (24%) in 1993 compared to 1992 and remained stable in 1992 as compared to 1991. The increase in 1993 relates to higher lease and well expenses and exploration expenses primarily due to expanded domestic and international operations. Depreciation, depletion and amortization expense increased 39% in 1993 and 12% in 1992 as compared to prior years. The increases in both years primarily reflect increased production volumes. On a per unit natural gas equivalent volumes delivered basis, depreciation, depletion and amortization expense increased to $0.89 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, condensate or natural gas liquids) in 1993 from $0.79 per Mcfe in 1992 and $0.81 per Mcfe in 1991 primarily due to higher costs associated with tight gas sand drilling activities.
Taxes, other than income taxes, increased $7 million (25%) from 1992 to 1993 due to increased production volumes and revenues, partially offset by continuing benefits associated with certain state severance tax exemptions allowed on high cost natural gas sales and a refund received in 1993 of franchise taxes paid in prior years. Taxes, other than income taxes, increased $10 million (56%) from 1991 to 1992 due to increased production volumes and revenues, increases in certain ad valorem and state franchise taxes in 1992, and earnings benefits realized in 1991 associated with the refund of certain state natural gas severance taxes resulting from overpayments in prior years. These increases were mitigated by Texas severance tax exemptions for high cost gas production that were in effect for the full year.
Total per unit operating costs for lease and well expense, DD&A, general and administrative expense, interest expense, and taxes other than income increased $0.03 Mcfe, averaging $1.43 per Mcfe during 1993 compared to $1.40 per Mcfe for 1992.
Other Income and Deductions The exploration and production segment's other income was $20 million in 1993 as compared to $3 million in 1992 and $12 million in 1991. Gains on property sales were the primary components of other income during each of the three years and totaled $13 million in 1993, $6 million in 1992 and $15 million in 1991.
Outlook While there still exists a good deal of uncertainty as to the direction of future natural gas price trends, some recent experiences may suggest a converging of the overall supply/demand relationship reflecting, at least partially, the significantly reduced level of drilling activity during recent years. EOG's management remains confident that continually increasing recognition of natural gas as a more environmentally friendly source of energy along with the availability of significant domestically sourced supplies will result in further increases in demand and a strengthening of the overall natural gas market over time. Being primarily a natural gas producer, EOG is more significantly impacted by changes in natural gas prices than by changes in crude oil and condensate prices. However, the use by the exploration and production segment from time to time of various commodity price hedging mechanisms will tend to mitigate this level of sensitivity. Enron has hedged the vast majority of its anticipated 1994 natural gas production by selling forward at recent prices.
EOG will continue to focus development and certain exploration expenditures in its core and other major producing areas, and include limited exploratory exposure in areas outside of North America. Expenditure plans for 1994 will continue to be focused toward certain areas that were not addressed as actively in the recent past due to the increased emphasis on tight gas sand drilling opportunities during 1991 and 1992. EOG will continue expenditures in new areas outside of North America, primarily for additional development operations in Trinidad, new development operations in other countries and the continued evaluation of coalbed methane recovery potential in France, Australia, China and certain other countries.
Corporate and Other The corporate and other segment's income before interest, minority interest and income taxes was an expense of $35 million in 1993 as compared to income of $51 million in 1992 and $63 million in 1991. During 1993, the segment recognized higher administrative and general expenses. Included in 1992 are the previously discussed gains from the sale of stock by EOG and sales of Mobil stock partially offset by charges related to the establishment of reserves for litigation and other contingencies. Included in 1991 are the previously discussed gains related to sales of Mobil stock, two favorable litigation settlements and the sale of certain gas processing assets.
Interest Expense and Income Taxes Interest and related charges, net, is shown on the Consolidated Income Statement net of interest capitalized. The net expense for 1993 decreased $30 million (9%) from 1992. The decrease is primarily due to lower interest rates. The net expense for 1992 decreased $43 million (12%) from 1991. The decrease is primarily due to a decrease in short-term interest rates and lower total obligations. Short- term borrowings averaged $591 million during 1993 as compared to $588 million during 1992 and $500 million during 1991 while the average interest rate on short-term debt fell to 3.3% in 1993 from 3.9% in 1992 and 6.3% in 1991.
Exclusive of the adjustment for the increase in the U.S. corporate Federal statutory income tax rate from 34% to 35%, income tax expense declined slightly during 1993 as compared to 1992 as increased pretax income was offset by utilization of increased tight gas sand tax credits. Although income before income taxes increased, income taxes decreased in 1992 as compared to 1991 primarily due to the inclusion of a nontaxable gain from the sale of stock by EOG and utilization of increased tight gas sand tax credits.
Extraordinary Items The extraordinary loss results primarily from the early retirement of $599 million principal amount of 10.625% senior subordinated debentures in September 1992.
Financial Condition Cash From Operating Activities Net cash provided by operating activities totaled $468 million during 1993 as compared to $330 million in 1992. The increase primarily reflects higher income levels in 1993 and the prepayment of $150 million made in 1992 for information technology services.
Cash From Investing Activities Cash used in investing activities totaled $639 million during 1993 as compared to $43 million during 1992. The change primarily reflects increased expenditures in connection with Enron's investment in Argentina pipeline operations, Teesside and other power projects. Additionally, during 1992, EOG recorded proceeds of $327 million under the terms of a volumetric production payment transaction (see Note 8 to the Consolidated Financial Statements). Proceeds from the sales of assets totaled $454 million during 1993 as compared to $388 million during 1992. The 1993 amounts include approximately $217 million in connection with the sale of Enron's interest in Northern Border Partners, L.P., $100 million from the sale of information technology assets and $42 million realized from the sale of exploration and production properties. Proceeds from the sale of assets during 1992 included $62 million from the sale of Mobil stock, $138 million, net, realized on the sale of certain liquids pipeline assets to Enron Liquids Pipeline, L.P., $121 million from the sale of certain pipeline assets by Enron Gas Services and $33 million realized from the sale of exploration and production properties.
Cash From Financing Activities Net cash provided by financing activities totaled $170 million during 1993 as compared to the use of $339 million in 1992. The difference in cash flow from financing activities between 1993 and 1992 was the retirement in 1992 of $1.1 billion of long-term debt primarily through the utilization of call provisions available on higher coupon debt issues. The repayments of long-term debt were partially funded by proceeds from the sales of common stock by Enron and EOG. During 1993, Enron issued $614 million of long-term debt while retiring $450 million principal amount of long-term borrowings. Other cash outflows during 1993 included $190 million of cash dividend payments on common and preferred stock and $23 million in repayments of other long-term obligations. In addition to the debt issuances discussed above, financing cash inflows during 1993 included $214 million from the issuance of preferred stock by a wholly-owned subsidiary of Enron (see Note 10 to the Consolidated Financial Statements).
Working Capital At December 31, 1993, Enron had a working capital deficit of $657 million. Enron is able to fund its deficit in working capital through the utilization of credit facilities which, at December 31, 1993, provided for up to $2.2 billion of committed and uncommitted credit. 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. At December 31, 1993, Enron had $144 million outstanding under the uncommitted agreements. In addition, Enron sells commercial paper and has agreements to sell up to $800 million of accounts receivable, thus providing short-term financing to meet seasonal working capital needs. Management believes that the sources of funding described above are sufficient to meet short- and long-term liquidity needs not met by cash flows from operations.
Capital Expenditures
Capital expenditures by operating segment are detailed as follows:
Capital expenditures by the transportation and operation segment increased $12 million during 1993 as compared to 1992. The decline during 1992 as compared to 1991 reflects the completion in early 1992 of Transwestern's pipeline expansion project and its San Juan lateral project which began during 1991.
Capital expenditures of the gas services segment increased $33 million during 1993 as compared to 1992 primarily as a result of the acquisition of gas storage assets and systems improvement costs.
The exploration and production segment's capital expenditures increased from $362 million in 1992 to $383 million in 1993. The increase was primarily attributable to increased domestic drilling activity with reduced emphasis on development drilling expenditures associated with tight gas sand formations. Enron also implemented its first development program outside of North America. The increase in capital spending by the exploration and production segment in 1992 compared to 1991 reflects development drilling expenditures associated with tight gas sand drilling activities and the acquisition in December 1992 of $40 million of producing properties in Canada.
Capital expenditures during 1994 are expected to total approximately $594 million. However, the overall level of capital spending as well as spending by individual business segments will vary depending upon conditions in the energy market and other related economic conditions. In addition, equity investments are expected to be approximately $387 million of which approximately $150 million for the Florida Gas Transmission Company expansion and approximately $160 million for various international power projects. Management believes that the capital expenditure program will be funded by a combination of internally generated funds and proceeds from dispositions of selected assets.
Capitalization Total capitalization at December 31, 1993 of $5.7 billion was comprised of total long-term debt of $2.7 billion, shareholders' equity of $2.6 billion, preferred stock of subsidiary company of $.2 billion and minority interests of $.2 billion. Debt as a percentage of total capitalization decreased to 46.7% at December 31, 1993 as compared to 47.7% at December 31, 1992. The improvement primarily reflects higher net income and the issuance of preferred stock by Enron Capital L.L.C., the proceeds of which were used to reduce debt and other corporate purposes. Additionally, the average cost of long-term debt declined to 8.2% at December 31, 1993 from 8.9% at December 31, 1992. The decline was accomplished primarily through the retirement of additional higher coupon long-term debt which was subject to call provisions during 1993.
Item 8.
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The information required hereunder is included in this report as set forth in the "Index to Financial Statements" on page.
Item 9.
Item 9. DISAGREEMENTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
PART III
Item 10.
Item 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The information required by Item 10 of Form 10-K relating to (i) directors who are nominees for election as directors at Enron's Annual Meeting of Stockholders to be held on May 3, 1994, and (ii) compliance by directors and executive officers with Section 16(a) of the Securities Exchange Act of 1934 is set forth, respectively, under the captions entitled "Election of Directors" and "Compensation of Directors and Executive Officers - Certain Transactions" in Enron's Proxy Statement, and is incorporated herein by reference.
The information required by Item 10 of Form 10-K with respect to executive officers is set forth in Part I of this Form 10-K under the heading "Current Executive Officers of the Registrant".
There are no family relationships among the officers listed, and there are no arrangements or understandings pursuant to which any of them were elected as officers. Officers are appointed or elected annually by the Board of Directors at its first meeting following the Annual Meeting of Stockholders, each to hold office until the corresponding meeting of the Board in the next year or until a successor shall have been elected, appointed or shall have qualified.
Item 11.
Item 11. EXECUTIVE COMPENSATION
The information regarding executive compensation is set forth in the Proxy Statement under the captions "Compensation of Directors and Executive Officers - Director Compensation; Executive Compensation; Stock Option Grants During 1993; Aggregated Stock Option/SAR Exercises During 1993 and Stock Option/SAR Values as of December 31, 1993; Long-Term Incentive Plans - Awards in 1993; Retirement and Severance Plans; Employment Contracts"; and "Compensation Committee Interlocks and Insider Participation", and is incorporated herein by reference.
Item 12.
Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
(a) Security ownership of certain beneficial owners
The information regarding security ownership of certain beneficial owners is set forth in the Proxy Statement under the caption "Election of Directors - Stock Ownership of Certain Beneficial Owners", and is incorporated herein by reference.
(b) Security ownership of management
The information regarding security ownership of management is set forth in the Proxy Statement under the caption "Election of Directors - Stock Ownership of Management and Board of Directors", and is incorporated herein by reference.
(c) Changes in control
None.
Item 13.
Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information regarding certain relationships and related transactions is set forth in the Proxy Statement under the caption "Compensation of Directors and Executive Officers - Certain Transactions"; and "Compensation Committee Interlocks and Insider Participation", and is incorporated herein by reference.
Item 14.
Item 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(a)(1) and (2) Financial Statements and Financial Statement Schedules. See "Index to Financial Statements" set forth on page.
(a)(3) Exhibits:
*3.01 - Restated Certificate of Incorporation of Enron Corp., as amended (Exhibit 4(d) to Registration Statement No. 33-50641, filed October 15, 1993).
*3.02 - Bylaws of Enron Corp. as currently in effect (Exhibit 3.02 to Enron Form 10-K for 1990, File No. 1-3423).
*4 - Indenture dated as of November 1, 1985, between Enron and Harris Trust and Savings Bank (Form T-3 Application for Qualification of Indentures under the Trust Indenture Act of 1939, File No. 22-14390, filed October 24, 1985). There have not been filed as exhibits to this Form 10-K other debt instruments defining the rights of holders of long-term debt of Enron, none of which relates to authorized indebtedness that exceeds 10% of the consolidated assets of Enron and its subsidiaries. Enron hereby agrees to furnish a copy of any such instrument to the Commission upon request.
Executive Compensation Plans and Arrangements (Exhibits 10.01 through 10.48)
*10.01 - Enron Executive Supplemental Survivor Benefits Plan, effective January 1, 1987 (Exhibit 10.01 to Enron Form 10-K for 1992, File No. 1-3423).
*10.02 - Enron Corp. 1988 Stock Plan (Exhibit 4.3 to Registration Statement No. 33-27893).
*10.03 - Enron Corp. 1984 Stock Option Plan (Exhibit 28-1 to Registration Statement No. 2-90992).
*10.04 - Enron Corp. 1986 Stock Option Plan with Stock Appreciation Rights (Exhibit 4.3 to Registration Statement No. 33-13498).
*10.05 - Executive Incentive Plan (Exhibit 10.13 to Enron Form 10-K for 1987, File No. 1-3423).
*10.06 - Enron Corp. 1988 Deferral Plan (Exhibit 10.19 to Enron Form 10-K for 1987, File No. 1-3423).
*10.07 - Enron Corp. 1991 Stock Plan (Exhibit 10.08 to Enron Form 10-K for 1991, File No. 1-3423).
*10.08 - Enron Corp. 1992 Deferral Plan (Exhibit 10.09 to Enron Form 10-K for 1991, File No. 1-3423).
*10.09 - Enron Corp. Directors' Deferred Income Plan (Exhibit 10.09 to Enron Form 10-K for 1992, File No. 1-3423).
*10.10 - Employment Agreement between Enron and Kenneth L. Lay dated as of September 1, 1989 (Exhibit 10.12 to Enron Form 10-K for 1989, File No. 1-3423).
10.11 - First Amendment to Employment Agreement between Enron and Kenneth L. Lay, dated August 21, 1990.
10.12 - Second Amendment to Employment Agreement between Enron and Kenneth L. Lay, dated March 5, 1992.
10.13 - Third Amendment to Employment Agreement between Enron and Kenneth L. Lay, dated August 10, 1993.
10.14 - Fourth Amendment to Employment Agreement between Enron and Kenneth L. Lay, dated October 15, 1993.
10.15 - Fifth Amendment to Employment Agreement between Enron and Kenneth L. Lay, dated February 28, 1994.
*10.16 - Employment Agreement between Enron and Richard D. Kinder dated as of September 1, 1989 (Exhibit 10.14 to Enron Form 10-K for 1989, File No. 1-3423).
*10.17 - First Amendment to Employment Agreement between Enron and Richard D. Kinder dated August 13, 1990 (Exhibit 10.17 to Enron Form 10-K for 1991, File No. 1-3423).
*10.18 - Second Amendment to Employment Agreement between Enron and Richard D. Kinder dated September 10, 1991 (Exhibit 10.18 to Enron Form 10-K for 1991, File No. 1-3423).
*10.19 - Third Amendment to Employment Agreement between Enron and Richard D. Kinder dated March 5, 1992 (Exhibit 10.19 to Enron Form 10-K for 1992, File No. 1-3423).
10.20 - Fourth Amendment to Employment Agreement between Enron and Richard D. Kinder dated August 16, 1993.
10.21 - Fifth Amendment to Employment Agreement between Enron and Richard D. Kinder, dated October 15, 1993.
10.22 - Sixth Amendment to Employment Agreement between Enron and Richard D. Kinder, dated February 28, 1994.
10.23 - Employment Agreement between Enron International Inc. and Rodney L. Gray, dated as of July 1, 1993.
*10.24 - Employment Agreement between Enron and Ronald J. Burns dated as of July 1, 1989 (Exhibit 10.15 to Enron Form 10-K for 1989, File No. 1-3423).
*10.25 - First Amendment to Employment Agreement between Enron and Ronald J. Burns dated June 21, 1990 (Exhibit 10.20 to Enron Form 10-K for 1991, File No. 1-3423).
*10.26 - Second Amendment to Employment Agreement between Enron and Ronald J. Burns dated August 19, 1991 (Exhibit 10.21 to Enron Form 10-K for 1991, File No. 1-3423).
*10.27 - Employment Agreement between Enron and Jack I. Tompkins dated October 1, 1991 (Exhibit 10.22 to Enron Form 10-K for 1991, File No. 1-3423).
*10.28 - 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).
*10.29 - 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).
*10.30 - 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).
*10.31 - Employment Agreement between Enron and Edmund P. Segner, III dated October 1, 1991 (Exhibit 10.24 to Enron Form 10-K for 1991, File No. 1-3423).
*10.32 - First Amendment to Employment Agreement between Enron and Edmund P. Segner, III dated February 12, 1993 (Exhibit 10.28 to Enron Form 10-K for 1992, File No. 1-3423).
*10.33 - Employment Agreement between Enron and Jeffrey K. Skilling, effective August 1, 1990 (Exhibit 10.18 to Enron Form 10-K for 1990, File No. 1-3423).
*10.34 - First Amendment to Employment Agreement between Enron and Jeffrey K. Skilling, dated August 1, 1990 (Exhibit 10.30 to Enron Form 10-K for 1992, File No. 1-3423).
*10.35 - Second Amendment to Employment Agreement between Enron and Jeffrey K. Skilling, dated June 1, 1991 (Exhibit 10.31 to Enron Form 10-K for 1992, File No. 1-3423).
*10.36 - Third Amendment to Employment Agreement between Enron and Jeffrey K. Skilling, dated February 10, 1992 (Exhibit 10.32 to Enron Form 10-K for 1992, File No. 1-3423).
*10.37 - Loan Commitment Agreement between Enron and Jeffrey K. Skilling, dated April 13, 1992 (Exhibit 10.33 to Enron Form 10-K for 1992, File No. 1-3423).
*10.38 - Fourth Amendment to Employment Agreement between Enron and Jeffrey K. Skilling, dated June 23, 1992 (Exhibit 10.34 to Enron Form 10-K for 1992, File No. 1-3423).
*10.39 - Fifth Amendment to Employment Agreement between Enron and Jeffrey K. Skilling, dated December 18, 1992 (Exhibit 10.35 to Enron Form 10-K for 1992, File No. 1-3423).
*10.40 - Buyout Agreement between Enron and Jeffrey K. Skilling, dated December 18, 1992 (Exhibit 10.36 to Enron Form 10-K for 1992, File No. 1-3423).
*10.41 - First Amendment to Buyout Agreement between Enron and Jeffrey K. Skilling, dated December 23, 1992 (Exhibit 10.37 to Enron Form 10-K for 1992, File No. 1-3423).
*10.42 - Loan Agreement between Enron and Jeffrey K. Skilling, dated January 1, 1993 (Exhibit 10.38 to Enron Form 10-K for 1992, File No. 1-3423).
*10.43 - Agreement among Enron Corp., Enron Power Corp., and Thomas E. White, dated December 9, 1992 (Exhibit 10.39 to Enron Form 10-K for 1992, File No. 1-3423).
*10.44 - 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).
*10.45 - Enron Gas Services Group Phantom Equity Plan (Exhibit 10.26 to Enron Form 10-K for 1991, File No. 1-3423).
*10.46 - Enron Power Corp. Executive Compensation Plan (Exhibit 10.42 to Enron Form 10-K for 1992, File No. 1-3423).
*10.47 - Enron Corp. Performance Unit Plan (Exhibit A to Enron Definitive Proxy Statement filed on March 25, 1994).
*10.48 - Enron Corp. Annual Incentive Plan (Exhibit B to Enron Definitive Proxy Statement filed on March 25, 1994).
11 - Statement re calculation of earnings per share.
12 - Statement re computation of ratios of earnings to fixed charges.
21 - Subsidiaries of registrant.
23.01 - Consent of Arthur Andersen & Co.
23.02 - Consent of DeGolyer and MacNaughton.
23.03 - Letter Report of DeGolyer and MacNaughton dated January 27, 1994.
24 - Powers of Attorney for the officers and directors signing this Form 10-K.
* Asterisk indicates exhibits incorporated by reference as indicated; all other exhibits are filed herewith.
(b) Reports on Form 8-K
(i) Form 8-K Current Report dated October 29, 1993 concerning financial information for the three months ended September 30, 1993.
(ii) Form 8-K Current Report dated November 12, 1993 concerning documents relating to Enron Capital LLC 8% Cumulative Guaranteed Monthly Income Preferred Shares.
ENRON CORP.
Page No.
Consolidated Financial Statements
Report of Independent Public Accountants
Consolidated Income Statement for the years ended December 31, 1993, 1992 and 1991
Consolidated Balance Sheet as of December 31, 1993 and 1992
Consolidated Statement of Cash Flows for the years ended December 31, 1993, 1992 and 1991
Consolidated Statement of Changes in Shareholders' Equity Accounts for the years ended December 31, 1993, 1992 and 1991
Notes to the Consolidated Financial Statements
Supplemental Financial Information (Unaudited)
Financial Statements Schedules
Report of Independent Public Accountants on Financial Statements Schedules S-1
Schedule II - Amounts Receivable from Related Parties, Underwriters, Promoters and Employees other than Related Parties S-2
Schedule V - Property, Plant and Equipment S-3
Schedule VI - Accumulated Depreciation, Depletion and Amortization of Property, Plant and Equipment S-4
Schedule VIII - Valuation and Qualifying Accounts S-5
Schedule X - Supplementary Income Statement Information S-6
Other financial statement schedules have been omitted because they are inapplicable or the information required therein is included elsewhere in the financial statements or notes thereto.
Report of Independent Public Accountants
To the Shareholders and Board of Directors of Enron Corp.:
We have audited the accompanying consolidated balance sheet of Enron Corp. (a Delaware corporation) and subsidiaries as of December 31, 1993 and 1992, and the related consolidated statements of income, cash flows and changes in shareholders' equity accounts for each of the three years in the period ended December 31, 1993. 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, 1993 and 1992, and the results of their operations, cash flows and changes in shareholders' equity accounts for each of the three years in the period ended December 31, 1993, in conformity with generally accepted accounting principles.
Arthur Andersen & Co. Houston, Texas February 18, 1994
Enron Corp. and Subsidiaries Notes to the Consolidated Financial Statements
1. Summary of Significant Accounting Policies A. Consolidation The consolidated financial statements include the accounts of all majority-owned subsidiaries of Enron Corp. after the elimination of significant intercompany accounts and transactions. Investments in unconsolidated subsidiaries are accounted for by the equity method.
"Enron" is used from time to time herein as a collective reference to Enron Corp. and its subsidiaries and affiliates. In material respects, the businesses of Enron are conducted by Enron Corp.'s subsidiaries and affiliates whose operations are managed by their respective officers.
Financial statements for prior periods have been restated to reflect the adoption of Statement of Financial Accounting Standards (SFAS) No. 109 (see E below) and the reclassification of EOTT Energy Corp.'s net assets and results of operations to continuing operations (see Note 3).
B. Cash Equivalents Enron records as cash equivalents all highly liquid short- term investments with original maturities of three months or less.
C. Inventories Inventories consisting primarily of natural gas in storage of $77.3 million and $116.2 million, crude oil and refined products of $75.5 million and $97.4 million and liquid petroleum products of $37.3 million and $71.7 million at December 31, 1993 and 1992, respectively, are priced at the lower of cost or market.
D. Depreciation, Depletion and Amortization The provision for depreciation and amortization with respect to operations other than oil and gas producing activities (see below) is computed using the straight-line or Federal Energy Regulatory Commission (FERC) mandated method based on estimated economic lives. Composite depreciation rates are applied to functional groups of property having similar economic characteristics.
Provisions for depreciation, depletion and amortization of proved oil and gas properties are calculated using the units- of-production method. Estimated future dismantlement, restoration and abandonment costs, net of salvage credits, are taken into account in determining depreciation, depletion and amortization.
E. Income Taxes Enron adopted the provisions of SFAS No. 109 - "Accounting for Income Taxes" effective January 1, 1993 and applied the provisions of the statement retroactively. Enron previously accounted for income taxes under the provisions of SFAS No. 96 which was superceded by SFAS No. 109. SFAS No. 109 retains the asset and liability approach for accounting for income taxes. Under this approach, deferred tax assets and liabilities are recognized based on anticipated future tax consequences attributable to differences between financial statement carrying amounts of assets and liabilities and their respective tax bases. The adoption of SFAS No. 109 did not have a material impact on Enron's results of operations or financial position.
F. Earnings Per Share Primary earnings per share is computed on the basis of the average number of common shares outstanding during the periods. Common shares held by the Enron Corp. Flexible Equity Trust are not included in the computation of earnings per share (see Note 11). Dilutive common stock equivalents are not material and are not included in the computation of primary earnings per share. Fully diluted earnings per share is computed based upon the average number of common stock and common stock equivalent shares outstanding plus the average number of common shares issuable upon the assumed conversion of convertible securities.
G. Accounting for Price Risk Management Activities Enron, through its Gas Services Group (EGS), provides price risk management services in the energy sector (these services are further described in Note 2). Enron accounts for these activities using the mark-to-market method of accounting. Under mark-to-market accounting, forwards, swaps, options, futures contracts and other financial instruments with third parties are reflected at market value, net of future servicing costs, with resulting unrealized gains and losses recorded as assets and liabilities from price risk management activities in the Consolidated Balance Sheet. Terms regarding cash settlements of these contracts vary with respect to the actual timing of cash receipts and payments. The amounts shown in the Consolidated Balance Sheet related to price risk management activities also include assets or liabilities which arise as a result of the actual timing of settlements related to these contracts. Current period changes in the assets and liabilities from price risk management activities (resulting primarily from newly originated transactions and the impact of price movements) are recognized as revenues in the Consolidated Income Statement.
The market prices used to value these transactions reflect management's best estimate of market prices considering various factors including closing exchange and over-the- counter quotations, time value and volatility factors underlying the commitments. These market prices are adjusted to reflect the potential impact of liquidating Enron's position in an orderly manner over a reasonable period of time under present market conditions.
Periodically, Enron's other businesses also enter into forwards, futures and other contracts to hedge the impact of market fluctuations on inventories, production or other contractual commitments. Changes in the market value of these transactions are deferred until the gain or loss is recognized on the hedged inventory or commitment. Disclosures regarding the fair value of these financial instruments are included in Note 18.
H. Accounting for Oil and Gas Producing Activities Enron accounts for oil and gas exploration and production activities under the successful efforts method of accounting. Under such method, oil and gas lease acquisition costs are capitalized when incurred. Unproved properties with significant acquisition costs are assessed quarterly on a property-by-property basis, and any impairment in value is recognized. Unproved properties with acquisition costs that are not individually significant are aggregated, and the portion of such costs estimated to be unproductive based on historical experience and future expected abandonments, is amortized over the average holding period. If the unproved properties are determined to be productive, the appropriate related costs are transferred to proved oil and gas properties. Lease rentals are expensed as incurred.
Oil and gas exploration costs, other than the costs of drilling exploratory wells, are charged to expense as incurred. The costs of drilling exploratory wells are capitalized pending determination of whether the wells have discovered proved commercial reserves. If proved commercial reserves are not discovered, such drilling costs are expensed. The costs of all development wells and related equipment used in the production of crude oil and natural gas are capitalized.
I. Accounting for Sales of Stock by Subsidiary Companies Enron recognizes gains or losses on sales of stock by its subsidiary companies when such sales are not made as part of a larger plan of corporate reorganization. Such gains or losses are based upon the difference between the book value of Enron's investment in the subsidiary immediately after the sale and the historical book value of Enron's investment immediately prior to the sale.
During August 1992, Enron Oil & Gas Company (EOG) completed a public offering and sale of 4.1 million shares of its common stock, reducing Enron's ownership interest from 84% to 80%. The shares were priced to the public at $28.50 per share and net proceeds from the transaction after underwriting commissions and expenses totaled $111.9 million. A gain in the amount of $59.6 million was recognized by Enron on the transaction. No income tax expense was recorded related to this transaction, consistent with U.S. tax law.
J. Foreign Currency Translation For subsidiaries whose functional currency is deemed to be other than the U.S. dollar, asset and liability accounts are translated at year-end rates of exchange and revenue and expenses are translated at average exchange rates prevailing during the year. Translation adjustments are included as a separate component of shareholders' equity.
2. Price Risk Management Activities EGS provides price risk intermediation services to its customers. These services primarily relate to commodities associated with the energy sector (natural gas, crude oil, natural gas liquids), but in some instances also include financial products (interest rates and Canadian dollars). EGS provides these services through a variety of financial instruments including forward contracts involving physical delivery of an energy commodity, swap agreements, which require payments to (or receipt of payments from) counterparties based on the differential between a fixed and variable price for the commodities specified by the contract, options, futures and other contractual arrangements.
Market Risk EGS's price risk management activities involve offering fixed or known price commitments into the future. These transactions give rise to market risk, which represents the potential loss that can be caused by a change in the market value of a particular commitment. As discussed in Note 1, Enron accounts for these activities at market value. As a result, the impact of changes in market prices are reflected currently in the consolidated financial statements. It is Enron's policy to prohibit speculation on market fluctuations and EGS's objective to maintain a balanced portfolio. However, net open positions often result from the timing of the origination of new transactions. Accordingly, EGS closely monitors and manages its exposure to market risk. Policies are in place which limit the amount of total net exposure and net exposure during any twelve month period for each commodity traded and all traded commodities combined. Procedures exist which allow for real time monitoring of all commitments and positions with daily reporting of positions to senior Enron management. Additionally, sensitivities to changes in market prices of each commodity are examined on a daily basis. Accordingly, Enron does not anticipate a materially adverse effect on financial position or results of operations as a result of market fluctuations.
SFAS No. 105, - "Disclosures of Information about Financial Instruments with Off-Balance-Sheet Risk and Financial Instruments with Concentrations of Credit Risk," requires the disclosure, as set forth below, of the notional amounts of financial instruments that give rise to off-balance-sheet risk. The notional amounts and terms of these agreements, as well as volumetric information regarding EGS's future fixed price commitments, at December 31, 1993 are set forth below (volumes in billions of British thermal units (Bbtus), U.S. dollars in millions):
EGS also has sales and purchase commitments associated with contracts based on market prices totaling 4,900,000 Bbtus, with terms extending up to 21 years. The midpoint of EGS's entire portfolio of price risk management activities as of December 31, 1993 was approximately 4.5 years (based on the weighted average value of each transaction).
Credit Risk Credit risk relates to the risk of loss that Enron would incur as a result of nonperformance by counterparties pursuant to the terms of their contractual obligations. The counterparties associated with EGS's price risk management services as of December 31, 1993 are summarized as follows (amounts in millions):
This concentration of counterparties may impact EGS'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.
EGS maintains credit policies with regard to its counterparties that management believes significantly minimizes overall credit risk. These policies include a thorough review of potential counterparties' financial condition (including credit rating), collateral requirements under certain circumstances and the use of standardized agreements which allow for the netting of positive and negative exposures associated with a single counterparty.
EGS maintains a credit reserve which is based on management's evaluation of the credit risk of the overall portfolio. This reserve is objectively determined using an implied risk profile based on the difference between risk- free rates of return and each counterparty's cost of borrowing. This implied risk is then used to evaluate the exposure (based on current market value) to each counterparty adjusted for collateral provisions and overall concentration of exposure. Based on EGS's policies, its current exposures and the credit reserve, Enron does not anticipate a materially adverse effect on the financial position or results of operations as a result of counterparty nonperformance.
3. Discontinued Operations Subsequently Retained During October 1992, the Board of Directors approved a plan to divest all of the crude oil trading and transportation operations of Enron's wholly-owned subsidiary, EOTT Energy Corp. (EOTT), through a spin-off transaction to holders of Enron common stock . As a result, Enron classified these activities as discontinued operations for financial reporting purposes. During the fourth quarter of 1993, Enron's Board of Directors approved a revised plan to divest a majority, but not all, of EOTT through a public offering of limited partnership interests in a master limited partnership.
In January 1994, EOTT Energy Partners, L.P. filed a registration statement with the Securities and Exchange Commission (SEC) to offer common units. Under terms of this offering, Enron will sell substantially all of the business and assets of EOTT to EOTT Energy Partners, L.P., a newly formed limited partnership. Enron will be the general partner and own a substantial interest in EOTT Energy Partners, L.P. after completion of the transaction. Enron reclassified the net assets and results of operations of EOTT, from discontinued operations, for all periods presented. EOTT's total assets and total liabilities as of December 31, 1992, the year it was reported as discontinued operations, were $695.7 million and $598.4 million, respectively. The components of EOTT's net revenues are as follows:
4. Income Taxes In August 1993, the U.S. corporate Federal income tax rate increased from 34% to 35% retroactive to January 1, 1993. Under the provisions of SFAS No. 109, the effect of a change in the tax rate is recognized in income for the period of enactment. The principal components of Enron's net deferred income tax liability at December 31, 1993 and 1992 are as follows:
The components of income before income taxes and extraordinary items are as follows:
Total income tax expense is summarized as follows:
The differences between taxes computed at the U.S. Federal statutory rate and Enron's effective rate are as follows:
Enron has an alternative minimum tax (AMT) credit carryforward of approximately $219 million which can be used to offset regular income taxes payable in future years. The AMT credit has an indefinite carryforward period.
Foreign subsidiaries' cumulative undistributed earnings of approximately $185 million are considered to be indefinitely reinvested outside the U.S. and, accordingly, no U.S. Federal or state 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. Determination of any potential amount of unrecognized deferred income tax liability is not practicable.
5. Supplemental Cash Flow Information Cash paid for income taxes and interest expense is as follows:
Non-cash investing and financing activities during 1993 included the exchange of common stock for convertible preferred stock of $33.3 million.
Non-cash investing and financing activities during 1992 included the exchange of common stock for convertible subordinated debentures and convertible preferred stock in transactions valued at $90.5 million and $39.8 million, respectively, and the acquisition of retail gas marketing operations in exchange for common stock valued at $18.3 million. During 1991, non-cash investing and financing activities included the exchange of common stock for convertible subordinated debentures and convertible preferred stock in transactions valued at $10.5 million and $14.9 million, respectively.
Changes in components of working capital are as follows:
6. Credit Facilities, Short-Term Borrowings and Long-Term Debt Enron and EOG have credit facilities with domestic and foreign banks which at December 31, 1993 provided for an aggregate of $1.1 billion in long-term committed credit. Expiration dates of the committed facilities range from December 1994 to January 1997. 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 for Enron 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 1993, no amounts were borrowed under these facilities.
Enron and EOG have also entered into agreements which provide for uncommitted lines of credit totaling $1.06 billion at December 31, 1993. 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, 1993, Enron had outstanding $144 million under certain of the uncommitted lines at average interest rates of 3.6%. In addition to borrowing from banks on a short-term basis, Enron and certain of its subsidiaries sell commercial paper to provide short-term financing for various corporate purposes. As of December 31, 1993, 1992 and 1991, short-term borrowings of $143.8 million, $101.0 million, and $243.7 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, 1993, 1992 and 1991, $132.4 million, $292.3 million, and $289.8 million, respectively, of long-term debt due within one year remained classified as long-term.
Detailed information on short-term borrowings by Enron is as follows:
Detailed information on long-term debt is as follows:
The aggregate annual maturity requirements applicable to long-term debt outstanding at December 31, 1993 are $132.4 million, $153.4 million, $133.1 million, $22.9 million and $169.0 million for 1994 through 1998, respectively. In addition, based upon available committed credit facilities, $143.8 million of short-term debt which has been reclassified as long-term debt would be due in 1995.
During 1992, Enron retired, pursuant to call provisions, $836 million principal amount of long-term debt with interest rates ranging from 8.7% to 11.5%. The early retirement of debt resulted in extraordinary items of $22.6 million, net of tax.
7. Accounts Receivable Enron has entered into agreements which provide for the sale of up to $800.0 million of trade accounts receivable with limited recourse provisions. Included in this amount is a $300.0 million agreement which will expire in April 1994 with the remainder expiring in February 1995. At December 31, 1993 and 1992, $700.1 million and $700.0 million, respectively, of receivables were sold under these agreements.
The fees incurred on the sales of accounts receivables totaled $20.6 million, $23.5 million and $37.8 million for 1993, 1992 and 1991, respectively. Additionally, fees incurred in connection with other long-term obligations and the sales of rights to certain recoverable take-or-pay buyout and contract reformation costs totaled $5.1 million, $12.5 million and $30.7 million, respectively, for 1993, 1992 and 1991 and are included in "Interest and Related Charges, net", in the Consolidated Income Statement.
Enron affiliates have concentrations of customers in the electric and gas utility industries. These concentrations of customers may impact Enron's overall exposure to credit risk, either positively or negatively, in that the customers may be similarly affected by changes in economic or other conditions. However, Enron's management believes that the portfolio of receivables is well diversified and that such diversification minimizes any potential credit risk. Credit losses incurred on receivables in these industries compare favorably to losses experienced on Enron's receivables portfolio as a whole. Receivables are generally not collateralized.
8. Production Payment Agreement In September 1992, EOG entered into a transaction with a limited partnership under which EOG conveyed an interest in approximately 124 billion cubic feet equivalent (136 trillion British thermal units) of natural gas and other hydrocarbons in the Big Piney area of Wyoming for consideration of $326.8 million (the production payment agreement). The natural gas and other hydrocarbons were originally scheduled to be produced and delivered over a period of forty-five months, which period commenced October 1, 1992. Effective October 1, 1993, the agreement was amended providing for the extension of the original term of the volumetric production payment through March 31, 1999 based on a revised schedule of daily quantities of hydrocarbons to be delivered which is approximately one-half of the original schedule. EOG retains responsibility for its working interest share of the cost of operations. Proceeds from the sale were used to repay long-term debt and for other corporate purposes. Enron has accounted for the proceeds received in the transaction as deferred revenue which is being amortized into revenue as natural gas and other hydrocarbons are produced and delivered during the term of the amended agreement. Annual remaining amortization of deferred revenue, based on scheduled deliveries under the amended production payment agreement at December 31, 1993, is approximately $43.3 million per year through 1998 and $10.7 million for 1999. Reserves dedicated to the transaction are included in the estimate of proved oil and gas reserves (see Note 20).
9. Unconsolidated Subsidiaries Enron has investments in and advances to unconsolidated subsidiaries 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:
Northern Border Partners, L.P. During October 1993, Northern Plains Natural Gas Company, a wholly-owned subsidiary of Enron, along with two of the other three general partners in Northern Border Pipeline Company contributed all of their combined 70% interest in Northern Border to Northern Border Partners, L.P., a Delaware limited partnership (the Partnership), in exchange for general partner interests, subordinated units and common units in the Partnership. Northern Plains sold its common units in the Partnership in an underwritten public offering and received net proceeds of approximately $217 million resulting in a pretax gain of approximately $64 million. Northern Plains retained a 13% interest in the Partnership.
Teesside Power Limited (Teesside). Enron has a 50% ownership interest in Teesside, a joint venture cogeneration company which owns a 1,875 megawatt independent power facility in northeast England. The remaining 50% ownership interest is held by four of the twelve regional electric companies operating in England.
Under the terms of the Shareholder Agreement relating to Teesside, Enron made a capital investment of $151 million on April 1, 1993. An affiliate of Enron operates the facility which was placed in commercial operation on March 27, 1993. Construction revenue and profit have been recognized on the portion of the joint venture not owned by Enron using the percentage of completion method of accounting. Revenue and profit on that portion of the joint venture owned by Enron have been deferred and are being amortized.
Enron has guaranteed the payment of Teesside's obligation in connection with certain grid connection charges which could become due should the power plant terminate operations. Further, Enron has guaranteed the payment of its proportionate share of amounts which could become due in the event of default by Teesside under the terms of the power sales agreements (see Note 16).
Under the terms of certain gas supply agreements extending through 2008, Teesside is obligated to take-or-pay for an average of up to 240 billion British Thermal Units of natural gas per day at indexed prices. Enron has guaranteed 70% of Teesside's payment obligation under the gas supply agreements. However, Enron believes there are alternative markets for such gas should the gas not be taken by Teesside.
Joint Energy Development Investments. In 1993, Joint Energy Development Investments (JEDI), a limited partnership, was formed, comprised of an Enron Subsidiary as general partner and the California Public Employees Retirement System (CalPERS) as limited partner, to acquire energy investments. Enron and CalPERS each own a 50% interest and have each committed to invest $250 million of capital over the next three years in JEDI, $5 million of which has already been contributed as of December 31, 1993. Enron intends to meet its required capital commitments by contributing Enron common stock.
10. Preferred Stock Convertible Preferred Stock. Each share of the $10.50 Cumulative Second Preferred Convertible Stock is convertible at any time at the option of the holder thereof into 13.652 shares of Enron's common stock, subject to certain adjustments. The Convertible Preferred Stock is currently subject to call at Enron's option at a price of $100 per share plus accrued dividends. Upon involuntary liquidation, holders would be entitled to $100 per share. During 1993, 1992 and 1991, 332,964 shares, 397,710 shares and 148,497 shares, respectively, of the Convertible Preferred Stock were converted into common stock.
Preferred Stock of Subsidiary Company. During November 1993, Enron's wholly-owned subsidiary Enron Capital LLC issued 8.55 million shares of 8% Cumulative Guaranteed Monthly Income Preferred Shares (MIPS) at a price of $25 per share. Net proceeds of approximately $207 million were used by Enron to reduce indebtedness and for other corporate purposes. The MIPS are redeemable at the option of Enron in whole or in part beginning November 1998 at a redemption price of $25 per share plus accumulated and unpaid dividends. Upon liquidation of Enron Capital LLC, the holders of the MIPS are entitled to $25 per share.
11. Common Stock and Dividends On July 28, 1993, Enron increased the number of authorized shares of common stock from 300,000,000 to 600,000,000 shares and decreased the par value of such common stock from $10.00 to $0.10 per share. The reduced par value of $9.90 for each share outstanding, or $1.18 billion, was transferred to additional paid-in capital. On August 16, 1993, Enron effected, in the form of a stock dividend, a two- for-one common stock split on all issued common stock. The par value of $11.9 million for 119,486,623 additional shares was transferred from additional paid-in capital to common stock. Appropriate references in the financial statements and supplemental financial information to number of shares and related prices, per share amounts and stock option information reflect the stock split.
The dividend history during each of the three years in the period ended December 31, 1993 is as follows: Enron paid quarterly cash dividends on common stock of $.155 per share ($.62 per share annually) until the final quarter of 1991 at which time the dividend was increased to $.1625 per share ($.65 per share annually). The dividend was increased to $.175 per share ($.70 per share annually) for the final quarter of 1992 and was further increased to $.1875 per share ($.75 per share annually) for the final quarter of 1993. Enron's debt agreements do not limit the payment of cash dividends on common stock. Common stock information is as follows:
Treasury stock information is as follows:
During 1993, Enron issued 130,329,224 shares of its common stock in connection with certain transactions including the two-for-one stock split, the conversion of preferred stock and employee benefit plans.
Enron has various stock option plans (the Plans) under which options for shares of Enron's common stock have been or may be granted to officers, key employees and non-employee members of the Board of Directors. Under the Plans, options granted may be either incentive stock options or nonqualified stock options and are granted at not less than the fair market value of the stock at the time of grant. Expiration dates of the options outstanding at December 31, 1993 range from July 9, 1994 to September 23, 2003. The Plans provide for options to be granted with stock appreciation rights (SAR); however, Enron does not presently intend to issue additional options with an SAR feature. Summarized information for the Plans is as follows:
Under the Plans, participants may be granted stock without cost to the participant (restricted stock). The shares issued under the Plans vest to the participants at various times ranging from immediate vesting to vesting at the end of a five year period. The following is an analysis of shares of restricted stock:
Flexible Equity Trust (the Trust). In December 1993, Enron established the Trust to fund a portion of its obligations arising from its various employee compensation and benefit plans. Enron issued 7.5 million shares of common stock to the Trust in exchange for cash and an interest bearing promissory note. The note held by Enron is reflected as a reduction of "Other" shareholders' equity. Common shares held by the Trust are not included in the computation of earnings per share.
12. 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. Participants in the Enron Plan with five years or more of service are entitled to retirement benefits based on a formula that uses a percentage of final average pay and years of service. Enron maintains a noncontributory employee stock ownership plan (ESOP) which covers all eligible employees. Allocations to individual employees' retirement accounts within the ESOP offset a portion of benefits earned under the Enron Plan. To the extent allocations to the individual employees retirement account within the ESOP exceed accrued benefits under the Enron Plan at the date of retirement, the individual employees receive the additional shares.
The components of pension expense are as follows:
The valuation date of the Enron Plan and the ESOP is September 30. The funded status as of the valuation date of the Enron Plan and the ESOP reconciles with the amount detailed below which is included in other assets on the Consolidated Balance Sheet at December 31, 1993 and 1992. Assets of the ESOP offset retirement benefits accrued under the Enron Plan only to the extent allocated to individual employee retirement accounts.
Assets of the Enron Plan are comprised primarily of equity securities, fixed income securities and temporary cash investments. It is Enron's policy to fund all pension costs accrued to the minimum amount required by federal tax regulations.
13. Postretirement Benefits Other Than Pensions Enron provides certain medical, life insurance and dental benefits to eligible employees who retire under the Enron Retirement Plan and their eligible surviving spouses. Benefits are provided under the provisions of a contributory defined dollar benefit plan. Enron is currently funding that portion of its obligations under its postretirement benefit plan which is expected to be recoverable through rates by its regulated pipelines.
Effective January 1, 1993, Enron adopted the provisions of SFAS No. 106 - "Employers Accounting for Postretirement Benefits Other Than Pensions". SFAS No. 106 requires that employers providing postretirement benefits accrue those costs over the service lives of the employees expected to be eligible to receive such benefits. Enron has elected the prospective transition approach and is amortizing the transition obligation which existed at January 1, 1993 over a period of approximately 19 years.
The following table sets forth the plan's funded status reconciled with the amounts reported in the Consolidated Balance Sheet.
The components of net periodic postretirement benefit expenses are as follows:
The measurement of the APBO assumes a 7% discount rate and a health care cost trend rate of 13% in 1993 decreasing to 5% by the year 2005 and beyond. A 1% increase in the health care cost trend rate would have the effect of increasing the APBO and the net periodic expense by approximately $9.7 million and $0.6 million, respectively.
14. Natural Gas Rates and Regulatory Issues Regulatory issues on Enron's regulated pipelines are subject to final determination by the FERC. Enron has provided a reserve related to pending regulatory issues and believes that the ultimate resolution of such issues will not have a materially adverse impact on Enron's financial position or results of operations.
The regulated pipelines have all successfully completed their transitions under FERC Order 636 (currently under appeal before the U.S. Court of Appeals for the 11th Circuit), and have completely unbundled their sales services from their transportation services. As required by Order 636, each of the regulated pipelines has implemented a straight fixed variable rate design which provides that all fixed costs to firm customers including return on equity, are to be received through fixed monthly demand or capacity reservation charges which are not a function of volumes transported.
Under their respective restructuring orders, the regulated pipelines are entitled to recover FERC Order 636 transition costs from customers. Transition costs incurred of $168 million have been deferred pending recovery from customers over varying time periods, generally of up to five years. Future transition costs are subject to ongoing negotiations and market factors. Enron believes that the ultimate resolution of FERC Order 636 transition costs will not have a material impact on Enron's financial position or results of operations.
15. Litigation and Other Contingencies Enron is party to various claims and litigation, the significant items of which are discussed below. Although no assurances can be given, Enron believes, based on its experience to date and after considering appropriate reserves that have been established, that the ultimate resolution of such items, individually or in the aggregate, will not have a materially adverse impact on Enron's financial position or results of operations.
Litigation TransAmerican Natural Gas Corporation (TransAmerican) has filed a petition against Enron Corp. and EOG alleging breach of confidentiality agreements, misappropriation of trade secrets and unfair competition, with specific reference to four tracts in Webb County, Texas, which EOG leased for their oil and gas exploration and development potential. TransAmerican seeks actual damages of $100 million and exemplary damages of $300 million. EOG has filed claims against TransAmerican and its sole shareholder alleging fraud, land fraud, negligent misrepresentation and breach of state antitrust laws. Trial is set for May 2, 1994. Although no assurances can be given, Enron believes that TransAmerican's claims are without merit and that the ultimate resolution of this matter will not have a materially adverse effect on its financial position or results of operations.
A pipeline company in which an Enron affiliate has a minority interest and for which an Enron affiliate has served as operator, has filed a petition against Enron and certain affiliates alleging an unspecified amount of damages relating to the operation of such pipeline company. Based upon information currently available, it is not possible to predict the outcome of such litigation; however, Enron believes that the results will not have a materially adverse effect on Enron's financial position or results of operations.
Like other companies in the natural gas industry, Enron has certain gas purchase contracts which provide for take-or-pay obligations and fixed prices. Certain suppliers have made claims, either formally or informally, for payment under take-or-pay provisions. At December 31, 1993, amounts of pending take-or-pay claims and litigation are not material.
Peruvian Operations During 1985, the Peruvian government unilaterally cancelled certain exploration and production agreements between the government-owned oil company and Belco Petroleum Corporation of Peru (BPCP), a wholly-owned subsidiary of Enron, and subsequently nationalized the operations of BPCP. Enron filed claims with its insurers in connection with the nationalization and in February 1989, the insurers paid Enron approximately $162 million. On September 21, 1993, the Peruvian government signed a settlement agreement with American International Group, Inc. and BPCP which will allow Enron to recover its remaining investment of approximately $33 million.
Environmental Matters Enron is subject to extensive Federal, state and local environmental laws and regulations. These laws and regulations require expenditures in connection with the construction of new facilities, the operation of existing facilities and for remediation at various operating sites. The implementation of the Clean Air Act Amendments is expected to result in increased operating expenditures. These increased operating expenses are not expected to have a material impact on Enron's financial position or results of operations.
In addition, Enron received requests for information from the Environmental Protection Agency (EPA) and state environmental agencies inquiring whether Enron has disposed of materials at certain waste disposal sites. Enron has received notices from EPA and state agencies that it is a "potentially responsible party" (PRP) under the Comprehensive Environmental Response, Compensation and Liability Act and analogous state statutes, and may be required to share in the costs of the cleanup of other, similar sites. However, management does not believe that any potential assessments in connection with these PRP 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.
16. Commitments Firm Transportation Obligations Enron has firm transportation agreements with various joint ventures. Under these agreements, Enron must make specified minimum payments each month. The estimated aggregate amounts of such required future payments at December 31, 1993, were:
The costs incurred under these agreements, including commodity charges on actual quantities shipped, totaled $38.2 million, $42.7 million and $53.8 million in 1993, 1992 and 1991, respectively. Enron has assigned a firm transportation contract with one of its joint venture pipelines to a third party and guaranteed minimum payments under the contract averaging approximately $43 million annually through 2001.
Other Commitments Enron leases property, operating facilities and equipment under various operating leases, certain of which contain renewal and purchase options and residual value guarantees. Guarantees under the leases total $955 million at December 31, 1993.
During July 1992, Enron modified and extended an agreement entered into in 1988 for a substantial amount of data processing facilities management services. The modification extends the original 10 year agreement for a period of three years through 2001. As part of the agreement, Enron prepaid $150 million for certain services to be performed over the life of the agreement.
Future commitments related to these items at December 31, 1993 are as follows:
Total rent expense incurred during 1993, 1992 and 1991 was $104.1 million, $64.7 million and $85.9 million, respectively.
Enron guarantees certain long-term contracts for the sale of electrical power and steam from the Texas City 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 subsidiaries in connection with letters of credit issued on behalf of those subsidiaries. At December 31, 1993, a total of $124 million of such guarantees were outstanding. Management does not expect to incur any material liabilities as a result of these obligations. In addition, Enron is a guarantor on certain debt of unconsolidated joint ventures and unconsolidated subsidiaries and other companies totaling approximately $305 million. Management does not consider it likely that there would be any losses associated with these guarantees. In addition, certain commitments have been made related to 1994 planned capital expenditures.
17. Other Income, Net The components of Other Income, Net are as follows:
18. Financial Instruments The following disclosures on the estimated fair value of financial instruments are presented in accordance with the requirements of SFAS No. 107 - "Disclosures About Fair Value of Financial Instruments." Fair value as used in SFAS No. 107 represents the amount at which the instrument could be exchanged in a current transaction between willing parties. The estimated fair value amounts have been determined by Enron using available market data and valuation methodologies. Judgement 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 amounts disclosed below exclude Enron's price risk management activities discussed in Notes 1 and 2.
Long-Term Debt. The fair market value of long-term debt is the estimated cost to acquire the debt, including a premium or discount for the differential between the issue rate and the year-end market rate. The fair value of long-term debt is based upon quoted market prices and, where such prices are not available, upon interest rates available to Enron.
Interest Rate Swap Agreements. Enron and EOG have entered into various interest rate swap transactions to hedge certain floating interest rate exposure in 1993 and 1994. This floating interest rate exposure arises primarily from short-term interest bearing debt as well as certain operating lease obligations and accounts receivable sales for which payments are subject to floating interest rates (see Notes 6, 7 and 16).
At December 31, 1993, Enron and EOG had outstanding interest rate swap agreements with a notional principal amount of $3.6 billion. During January 1994, Enron executed additional swap agreements with notional principal amounts totaling $700 million. Included in the $4.3 billion total swap agreements is $2.1 billion notional principal amount of interest rate swap agreements which expired subsequent to December 31, 1993 and which were executed to hedge anticipated floating rate exposure in 1993. Also included are approximately $2.1 billion notional principal amount of interest rate swap agreements executed to hedge anticipated floating rate exposure in 1994. The remaining notional principal amounts include swap agreements extending beyond 1994. The fair value of interest rate swap agreements is based upon termination values obtained from third parties.
Credit Risk. While notional contract amounts are used to express the volume of interest rate swap agreements, the amounts potentially subject to credit risk, in the event of nonperformance by the third parties, are substantially smaller. Enron does not anticipate any material impact to its financial position or results of operations as a result of nonperformance by the third parties.
Price Risk Management. Enron entered into certain price swap agreements to, in effect, hedge the market risk caused by fluctuations in the price of natural gas. The agreements call for Enron to make payments to (or receive payments from) the other party based upon the differential between a fixed and a variable price for natural gas as specified by the contract. The current swap agreements run for periods of ten years and have a notional contract amount of approximately $299 million at December 31, 1993.
Foreign Currency Contracts. Foreign currency contracts are entered into to hedge currency exposure from commercial transactions. At December 31, 1993, foreign currency contracts with a principal amount of $38.3 million were outstanding. Fair value of such contracts are based upon year-end fair market values.
Guarantees. As more fully discussed in Notes 9 and 16, Enron is a guarantor on certain debt and lease obligations. The fair value of such guarantees is based upon Enron's estimation of the cost of securing third party letters of credit equal to Enron's obligations under such guarantees.
19. Business and Geographic Segment Information Enron's operations are classified into five business segments:
Transportation and Operation - Transmission of natural gas. Construction, management and operation of pipelines, liquids plants and power facilities. Crude oil transportation activities and investment in liquids pipeline operations.
Gas Services - Purchasing, marketing and financing of natural gas, natural gas liquids and power. Price risk management in connection with natural gas and natural gas liquids transactions. Intrastate natural gas pipelines. Development, acquisition and promotion of natural gas fired power plants in North America.
Gas Processing - Extraction of natural gas liquids in North America.
International Gas and Power Services - Independent (non- utility) development, acquisition and promotion of natural gas-fired power plants, natural gas liquids facilities and pipelines outside of North America. International marketing of natural gas liquids.
Exploration and Production - Natural gas and crude oil exploration and production primarily in the United States, Canada and Trinidad.
Enron's business segment information has been reclassified from prior years to reflect the realignment of Enron's operations. Financial information by business and geographic segment for each of the three years in the period ended December 31, 1993, is presented below.
Operations In Business and Geographic Segments Business Segments
Geographic Segments
20. Oil and Gas Producing Activities The following information regarding Enron's oil and gas producing activities should be read in conjunction with Note 1. Capitalized Costs Relating to Oil and Gas Producing Activities
Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities(a)
Results of Operations for Oil and Gas Producing Activities(a)
The following tables set forth results of operations for oil and gas producing activities for the three years in the period ended December 31, 1993:
Oil and Gas Reserve Information (Unaudited) 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, 1993, 1992 and 1991 were based on studies performed by Enron's engineering staff for reserves in the United States, Canada and Trinidad. Opinions by DeGolyer and MacNaughton, independent petroleum consultants, for the years ended December 31, 1993, 1992 and 1991 covering producing areas containing 65%, 69% and 73%, respectively, of proved reserves of Enron on a net-equivalent-cubic-feet- of-gas basis, indicate that the estimates of proved reserves prepared by Enron's engineering staff for the properties reviewed by DeGolyer and MacNaughton, when compared in total on a net-equivalent-cubic-feet-of-gas basis, do not differ by more than 5% from those prepared by DeGolyer and MacNaughton's engineering staff. All reports by DeGolyer and MacNaughton were developed utilizing geological and engineering data provided by Enron.
The standardized measure of discounted future net cash flows does not purport, nor should it be interpreted, to present the fair market value of Enron's crude oil and natural gas reserves. An estimate of fair value would also take into account, among other things, the recovery of reserves not presently classified as proved reserves, anticipated future changes in prices and costs and a discount factor more representative of the time value of money and the risks inherent in reserve estimates.
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves(a)
Changes in Standardized Measure of Discounted Future Net Cash Flows
Reserve Quantity Information Enron's estimates of net proved and proved developed reserves of crude oil, condensate, natural gas liquids and natural gas and of changes in net proved reserves were as follows:
Enron Corp. and Subsidiaries Supplemental Financial Information (unaudited) Quarterly Results(b)
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS ON FINANCIAL STATEMENT SCHEDULES
To Enron Corp.:
We have audited in accordance with generally accepted auditing standards, the consolidated financial statements included in this Form 10-K, and have issued our report thereon dated February 18, 1994. Our audits were made for the purpose of forming an opinion on the basic financial statements taken as a whole. The schedules listed in Item 14(a)2 are the responsibility of Enron Corp.'s management. These schedules are presented for purposes of complying with the Securities and Exchange Commission's rules and are not part of the basic financial statements. These schedules have been subjected to the auditing procedures applied in the audits of the basic financial statements and, in our opinion, fairly state in all material respects the financial data required to be set forth therein in relation to the basic financial statements taken as a whole.
ARTHUR ANDERSEN & CO.
Houston, Texas February 18, 1994
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S-2
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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 28th day of March, 1994.
ENRON CORP. (Registrant)
By: JACK I. TOMPKINS (Jack I. Tompkins) Senior Vice President and Chief Information, Administrative and Accounting Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been signed below on March 28, 1994 by the following persons on behalf of the Registrant and in the capacities indicated.
Signature Title
KENNETH L. LAY Chairman of the Board, Chief Executive (Kenneth L. Lay) Officer and Director (Principal Executive Officer)
JACK I. TOMPKINS Senior Vice President and Chief (Jack I. Tompkins) Information, Administrative and Accounting Officer (Principal Accounting Officer)
KURT S. HUNEKE Vice President, Finance and Treasurer (Kurt S. Huneke) (Principal Financial Officer)
WILLIAM A. ANDERS* Director (William A. Anders)
ROBERT A. BELFER* Director (Robert A. Belfer)
NORMAN P. BLAKE, JR. Director (Norman P. Blake, Jr.)
JOHN H. DUNCAN* Director (John H. Duncan)
JOE H. FOY* Director (Joe H. Foy)
WENDY L. GRAMM* Director (Wendy L. Gramm)
ROBERT K. JAEDICKE* Director (Robert K. Jaedicke)
RICHARD D. KINDER* Director and President and Chief (Richard D. Kinder) Operating Officer
CHARLES A. LEMAISTRE* Director (Charles A. LeMaistre)
JOHN A. URQUHART* Director (John A. Urquhart)
CHARLS E. WALKER* Director (Charls E. Walker)
HERBERT S. WINOKUR, JR.* Director (Herbert S. Winokur, Jr.)
*By: PEGGY B. MENCHACA (Peggy B. Menchaca) (Attorney-in-fact for persons indicated)