8-K 1 h83271e8-k.txt EL PASO CORPORATION - DATED MARCH 23, 2001 1 -------------------------------------------------------------------------------- -------------------------------------------------------------------------------- UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 8-K CURRENT REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 DATE OF REPORT: MARCH 23, 2001 (DATE OF EARLIEST EVENT REPORTED: JANUARY 29, 2001) EL PASO CORPORATION (Exact name of registrant as specified in the charter)
DELAWARE 1-14365 76-0568816 (State or other jurisdiction (Commission File Number) (I.R.S. Employer of incorporation) Identification No.)
EL PASO BUILDING 1001 LOUISIANA STREET HOUSTON, TEXAS 77002 (Address of Principal Executive Offices)(Zip Code) Registrant's telephone number, including area code (713) 420-2131 -------------------------------------------------------------------------------- -------------------------------------------------------------------------------- 2 ITEM 5. OTHER EVENTS On January 29, 2001, we completed our merger with The Coastal Corporation. We accounted for this transaction as a pooling of interests. This report includes the following items, which have been restated to include Coastal's operations for all periods presented: - combined business and properties; - combined selected financial data; - combined management's discussion and analysis; - combined risk factors; - quantitative and qualitative disclosures about our combined market risks; and - audited supplemental combined financial statements, which include our combined results of operations, financial position and cash flows. These combined statements will become our historical consolidated financial statements after financial statements covering the date of our merger are issued. Included as an exhibit in this Current Report on Form 8-K is the Annual Report on Form 10-K of El Paso CGP Company (formerly The Coastal Corporation) for the year ended December 31, 2000. BUSINESS AND PROPERTIES GENERAL We are a global energy company originally founded in 1928 in El Paso, Texas. For many years, we served as a regional pipeline company conducting business mainly in the western United States. However, over the past five years, we have grown into a company whose operations span the wholesale energy value chain, from natural gas production and extraction to power generation. Our substantial growth during this period has been accomplished through a series of strategic acquisitions, transactions, and internal growth initiatives, each of which has enhanced and improved our competitive abilities in the U.S. and global energy markets. Significant milestones include:
YEAR TRANSACTION IMPACT ---- ----------- ------ 1995 Acquisition of Eastex Energy Inc. Signaled our entry into the wholesale energy marketing business. 1996 $4 billion acquisition of the energy businesses of Expanded our U.S. interstate pipeline system from Tenneco Inc. coast to coast and signaled our entry into the international energy market. 1998 Acquisition of DeepTech International, Inc. Expanded our U.S. onshore and offshore gathering capacity and capabilities. 1999 $6 billion merger with Sonat Inc. Expanded our pipeline operations into the southeast portion of the U.S. and signaled our entrance into the exploration and production business through the addition of 1.5 Tcfe of natural gas reserves. Creation of the $1.1 billion Electron Structure Provided the vehicle through which we have become a significant non-utility generator of power. 2000 Acquisition of PG&E's Texas Midstream operations Expanded our midstream operations to cover a majority of the metropolitan markets and industrial hubs in the state of Texas. 2001 Completion of our $24 billion merger with The This merger places us as a top tier participant in Coastal Corporation every aspect of the wholesale energy marketplace.
--------------- Below is a list of terms that are common to our industry and used throughout this document: /d = per day Bbl = barrels BBtu = billion British thermal units BBtue = billion British thermal unit equivalents Bcf = billion cubic feet MBbls = thousand barrels MMBbls = million barrels MMBtu = million British thermal units Mcf = thousand cubic feet Mcfe = thousand cubic feet of gas equivalents MMcf = million cubic feet MMcfe = million cubic feet of gas equivalents Mgal = thousand gallons MWh = megawatt hours MMWh = thousand megawatt hours Tcfe = trillion cubic feet of gas equivalents
When we refer to natural gas and oil in "equivalents," we are doing so to compare quantities of oil with quantities of natural gas or to express these different commodities in a common unit. In calculating equivalents, we use a generally recognized standard in which one Bbl of oil is equal to six Mcf of natural gas. Also, when we refer to cubic feet measurements, all measurements are at 14.73 pounds per square inch. 1 3 With each significant merger and acquisition, we have evaluated our processes and organizational structure to achieve cost savings and operating efficiencies. These actions have included restructuring our workforce and consolidating our operations. These activities occurred again following the completion of our merger with Coastal in January 2001. OPERATIONS Our principal operations include: - transportation, gathering, processing, and storage of natural gas; - marketing of energy and energy-related commodities and products; - generation of power; - refining of petroleum; - production of chemicals; - development and operation of energy infrastructure facilities; - exploration and production of natural gas and oil; and - mining of coal. Our Pipelines segment owns or has interests in approximately 60,000 miles of interstate natural gas pipelines in the U.S. and internationally. In the U.S., our systems connect the nation's principal natural gas supply regions to the five largest consuming regions in the United States: the Gulf Coast, California, the Northeast, the Midwest, and the Southeast. These operations represent one of the largest, and only, integrated coast-to-coast mainline natural gas transmission system in the U.S. Our U.S. pipeline systems also own or have interests in over 425 Bcf of storage capacity used to provide a variety of services to our customers. Our international pipeline operations include access from our U.S. based systems into Canada and Mexico as well as interests in three major operating natural gas transmission systems in Australia. Our Merchant Energy segment is involved in a broad range of activities in the energy marketplace including asset ownership, trading and risk management and financial services. We are one of North America's largest wholesale energy commodity marketers and traders, and buy, sell, and trade natural gas, power, crude oil, refined products, coal, and other energy commodities in the U.S. and internationally. We are also a significant non-utility owner of electric generating capacity with 84 facilities in 20 countries. Our four refineries have the capacity to process 538,000 barrels of crude oil per day and produce a variety of gasolines and other products. We also produce agricultural and industrial chemicals and petrochemicals at seven facilities in the U.S. and Canada. Our coal operations produce high-quality, bituminous coal with reserves in Kentucky, Virginia, and West Virginia. Most recently, we have announced our expansion into the liquefied natural gas business, capitalizing upon the U.S. and worldwide demand for natural gas. The financial services businesses of Merchant Energy invest in emerging businesses to facilitate growth in the U.S. and Canadian energy markets. As a global energy merchant, we evaluate and measure risks inherent in the markets we serve, and use sophisticated systems and integrated risk management techniques to manage those risks. Our Field Services segment provides natural gas gathering, products extraction, fractionation, dehydration, purification, compression and intrastate transmission services. These services include gathering of natural gas from more than 15,000 natural gas wells with approximately 24,000 miles of natural gas gathering and natural gas liquids pipelines, and 35 natural gas processing, treating, and fractionation facilities located in some of the most prolific and active production areas in the U.S., including the San Juan Basin, east and south Texas, Louisiana, the Gulf of Mexico, and the Rocky Mountains. We conduct our intrastate transmission operations through interests in six intrastate systems, which serve a majority of the metropolitan areas and industrial load centers in Texas as well as markets in Louisiana. Our primary vehicle for growth and development of midstream energy assets is El Paso Energy Partners, L.P., a publicly traded master limited 2 4 partnership of which our subsidiary is the general partner. Through Energy Partners, we provide natural gas and oil gathering and transportation, storage, and other related services, principally in the Gulf of Mexico. Our Production segment leases approximately 5 million net acres in 16 states, including Colorado, Kansas, Louisiana, New Mexico, Texas, Oklahoma, Utah, Wyoming, and Arkansas, as well as the Gulf of Mexico. We also have exploration and production rights in Australia, Brazil, Canada, Hungary, Indonesia, and Turkey. During 2000, daily equivalent natural gas production exceeded 1.6 Bcf/d, and our reserves at December 31, 2000, were approximately 6.4 Tcfe. In addition to our energy activities, we have announced a telecommunications strategy that will leverage our knowledge of the commodity and capital markets into the emerging telecommunications market. Our strategy involves: - accessing fiber deep within metropolitan markets to aggregate supply in major U.S. cities; - utilizing fiber rings and key points of interconnection of major carriers and service providers to allow for liquidity to develop in major markets; and - assembling a high capacity thin fiber national long-haul backbone. We will overlay against this asset base a merchant-based operating support system and valuation models that will allow us to apply the merchant skills developed in our core commodity business to the rapidly changing telecommunications markets. SEGMENTS Our business unit activities are segregated into four primary business segments: Pipelines, Merchant Energy, Field Services, and Production. These segments are strategic business units that provide a variety of energy products and services. We manage each segment separately, and each segment requires different technology and marketing strategies. Our telecommunications business is combined with our corporate and other activities. In the discussion of our business unit activities that follows, we have excluded entities and assets sold or in the process of being sold, as required by the Federal Trade Commission, as a result of our merger with Coastal and the acquisition of PG&E's Texas Midstream operations. PIPELINES Our Pipelines segment provides natural gas transmission services in the U.S. and internationally. In the U.S., we conduct our activities through seven wholly owned and four partially owned interstate systems along with a liquified natural gas terminalling facility and natural gas storage facilities. Our international pipeline operations include access from our U.S. based systems into Canada and Mexico as well as interests in three major operating natural gas transmission systems in Australia. Each of these systems is discussed below: The TGP system. The Tennessee Gas Pipeline system consists of approximately 14,700 miles of pipeline with a design capacity of 5,970 MMcf/d. During 2000, TGP transported natural gas volumes averaging approximately 73 percent of its capacity. This multiple-line system begins in the gas-producing regions of Louisiana, including the Gulf of Mexico, and south Texas and extends to the northeast section of the U.S., including the New York City and Boston metropolitan areas. TGP also has an interconnect at the U.S.-Mexico border. Along its system, TGP has approximately 89 Bcf of underground working gas storage capacity. The ANR system. The ANR Pipeline system consists of approximately 10,600 miles of pipeline with a design capacity of 6,627 MMcf/d. During 2000, ANR transported natural gas volumes averaging approximately 71 percent of its capacity. This system's two interconnected, large diameter multiple pipeline systems transport gas from gas-producing fields in Texas, Oklahoma, Louisiana, the Gulf of Mexico, and Canada to markets in the Midwest and Northeast regions of the United States, including the metropolitan 3 5 areas of Detroit, Chicago, and Milwaukee. Along its system, ANR has approximately 202 Bcf of underground working gas storage capacity. The EPNG system. The El Paso Natural Gas system consists of approximately 9,800 miles of pipeline with a design capacity of 4,744 MMcf/d. During 2000, EPNG transported natural gas volumes averaging approximately 82 percent of its capacity. The EPNG system delivers natural gas from the San Juan Basin of northern New Mexico and southern Colorado and the Permian Basin and Anadarko Basin to California, which is its single largest market, as well as markets in Nevada, Arizona, New Mexico, Texas, Oklahoma, and northern Mexico. The SNG system. The Southern Natural Gas system consists of approximately 8,200 miles of pipeline with a design capacity of 2,834 MMcf/d. During 2000, SNG transported volumes averaging approximately 73 percent of its capacity. SNG's interstate pipeline system extends from gas fields in Texas, Louisiana, Mississippi, Alabama and the Gulf of Mexico to markets in Louisiana, Mississippi, Alabama, Florida, Georgia, South Carolina and Tennessee, including the metropolitan areas of Atlanta and Birmingham. SNG is the principal pipeline supplier to the growing southeastern markets of Alabama and Georgia. In August 2000, the South Georgia Natural Gas system was combined with the SNG system as part of SNG's rate case settlement. Along its system, SNG has approximately 60 Bcf of underground working gas storage capacity. The CIG system. The Colorado Interstate Gas system consists of approximately 4,400 miles of pipeline, with a design capacity of 2,290 MMcf/d. During 2000, CIG transported natural gas volumes averaging approximately 60 percent of its capacity. The CIG system is directly or indirectly connected to the major supply basins in the Rocky Mountain region and serves two major markets, one along the front range of the Rocky Mountains, and the second at various interconnects with pipeline systems transporting gas to California and the Midwest. Along its system, CIG has approximately 29 Bcf of underground working gas storage capacity. The WIC system. The Wyoming Interstate Company system consists of approximately 400 miles of pipeline with a total design capacity of 1,157 MMcf/d. During 2000, WIC transported natural gas volumes averaging approximately 75 percent of its capacity. The system has two large-diameter pipelines that come together in northern Colorado to feed into the CIG-Trailblazer interconnect on the 800-mile Trailblazer system and into other interstate and intrastate pipelines at that interconnect. The MPC system. The Mojave Pipeline Company system consists of approximately 400 miles of pipeline with a design capacity of approximately 400 MMcf/d. During 2000, MPC transported natural gas volumes approximating 100 percent of its capacity. The MPC system connects with the EPNG transmission system at Topock, Arizona and the Kern River Gas Transmission Company system in California and extends to customers in the vicinity of Bakersfield, California. Florida Gas Transmission system. We own a 50 percent interest in Citrus Corp., a holding company that owns 100 percent of Florida Gas Transmission Company. Florida Gas is the primary pipeline transporter of natural gas in the state of Florida and the sole pipeline transporter to peninsular Florida. The system consists of approximately 4,800 miles of interstate natural gas pipelines with a design capacity of 1,462 MMcf/d. During 2000, Florida Gas transported volumes averaging approximately 92 percent of its capacity. The system extends from south Texas to a point near Miami, Florida. Great Lakes. We own a 50 percent interest in Great Lakes Gas Transmission System. Great Lakes owns a 2,100-mile pipeline with a design capacity of 2,895 MMcf/d. The system extends from the Manitoba-Minnesota border to an interconnection on the Michigan-Ontario border at St. Clair, Michigan. During 2000, Great Lakes transported volumes averaging approximately 84 percent of its capacity. Alliance Pipeline. We own an approximate 14 percent interest in the Alliance pipeline project. Alliance consists of approximately 2,300 miles of pipeline with a design capacity of 1,325 MMcf/d and extends from supply fields in western Canada to the Chicago area market center. Alliance commenced service in late 2000. Portland Natural Gas Transmission. We own an approximate 19 percent interest in the Portland Natural Gas Transmission system. Portland consists of approximately 300 miles of interstate natural gas 4 6 pipeline with a design capacity of 215 MMcf/d extending from the Canadian border near Pittsburg, New Hampshire to Dracut, Massachusetts. During 2000, Portland transported volumes averaging approximately 51 percent of its capacity. Southern LNG, Inc. Southern LNG owns a liquefied natural gas receiving terminal, located on Elba Island, near Savannah, Georgia, capable of achieving a peak send out of 540 MMcf/d and a base load send out of 333 MMcf/d. Inactive since the early 1980s, Southern LNG received an order from the Federal Energy Regulatory Commission (FERC) in March 2000 granting it permission to reactivate the receiving terminal. We expect the terminal to be in service in the fourth quarter of 2001. ANR Storage. ANR Storage Company develops and operates underground natural gas storage facilities. ANR Storage owns four underground storage facilities in northern Michigan. These facilities have a working storage capacity of approximately 56 Bcf, of which 30 Bcf is contracted by ANR Pipeline Company. In addition, ANR Storage has joint ownership interests in three storage facilities located in Michigan and New York with a total working storage capacity of approximately 65 Bcf. All of ANR Storage's jointly owned capacity is under long-term contracts, including 45 Bcf contracted to ANR Pipeline Company. Bear Creek Storage. Bear Creek Storage Company owns and operates an underground natural gas storage facility located in Louisiana. The facility has a capacity of 50 Bcf of base gas and 58 Bcf of working storage. Bear Creek's working storage capacity is committed equally to the TGP and SNG systems under long-term contracts. Australian Pipelines. We own a 33 percent interest in the 488-mile Moomba-to-Adelaide pipeline system in southern Australia, the 470-mile Ballera to Wallumbilla pipeline system in southwestern Queensland, and the 925-mile Dampier-to-Bunbury natural gas pipeline in western Australia. Regulatory Environment Our interstate natural gas systems and storage operations are regulated by FERC under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. Each system operates under separate FERC approved tariffs that establish rates, terms, and conditions under which each system provides services to its customers. Generally, FERC's authority extends to: - transportation and storage of natural gas, rates, and charges; - certification and construction of new facilities; - extension or abandonment of services and facilities; - maintenance of accounts and records; - depreciation and amortization policies; - acquisition and disposition of facilities; - initiation and discontinuation of services; and - various other matters. Our wholly owned and investee domestic pipelines have tariffs established through filings with FERC that have a variety of terms and conditions, each of which affects its operations and its ability to recover fees for the services it provides. By and large, changes to these fees or terms can only be implemented upon approval by FERC. In Canada, our operating activities are regulated by the National Energy Board. Similar to FERC, the National Energy Board governs tariffs and rates, and the construction and operation of natural gas pipelines in Canada. In Australia, rates and other business issues are regulated by various regional and national agencies, which govern the operating activities of these pipelines. 5 7 Our interstate pipeline systems are also subject to the Natural Gas Pipeline Safety Act of 1968 that establishes pipeline and liquefied natural gas plant safety requirements, the National Environmental Policy Act, and other environmental legislation. Each of our systems has a continuing program of inspection designed to keep all of our facilities in compliance with pollution control and pipeline safety requirements. We believe our systems are in substantial compliance with the applicable requirements. For a further discussion of our significant rate and regulatory matters, see Supplemental Combined Financial Statements, Note 10. Markets and Competition Our interstate systems face varying degrees of competition from alternative energy sources, such as electricity, hydroelectric power, coal, and fuel oil. Also, the potential consequences of proposed and ongoing restructuring and deregulation of the electric power industry are currently unclear. Restructuring and deregulation may benefit the natural gas industry by creating more demand for natural gas turbine generated electric power, or it may hamper demand by allowing a more effective use of surplus electric capacity through increased wheeling as a result of open access. TGP. TGP's customers include natural gas producers, marketers and end-users, as well as other gas transmission and distribution companies, none of which individually represents more than 10 percent of the revenues on TGP's system. Currently, over 70 percent of TGP's capacity is subject to firm contracts expiring after 2001. These contracts have an average term in excess of five years. TGP continues to pursue future markets and customers for the capacity that is not committed beyond 2001 and expects this capacity will be placed under a combination of long-term and short-term contracts. However, there can be no assurance that TGP will be able to replace these contracts or that the terms of new contracts will be as favorable to TGP as the existing ones. In a number of key markets, TGP faces competitive pressures from other major pipeline systems, which enable local distribution companies and end-users to choose a supplier or switch suppliers based on the short-term price of natural gas and the cost of transportation. Competition among pipelines is particularly intense in TGP's supply areas, Louisiana and Texas. In some instances, TGP has had to discount its transportation rates in order to maintain market share. The renegotiation of TGP's expiring contracts may be adversely affected by these competitive factors. ANR. In its historical market areas of Wisconsin and Michigan, ANR competes with other interstate and intrastate pipeline companies and local distribution companies in the transportation and storage of natural gas. ANR has been successful in restructuring the service portfolios of a number of its major Wisconsin customers. This restructuring has enabled ANR to extend contracts that were set to expire in 2003, with the restructured contracts providing for a combined winter maximum daily quantity of 674 MMcf/d that will expire in 2008 and 2010. ANR continues to work with its largest customer, Wisconsin Gas Company, to restructure and extend contracts that are set to expire in 2003. However, Wisconsin Gas is a sponsor of the proposed Guardian Pipeline, which received a FERC certificate on March 14, 2001, and that pipeline will directly compete for a portion of this expiring capacity. ANR also has 900 MMcf/d of capacity under contract with Michigan Consolidated Gas Company. Of that amount, 110 MMcf/d is due to expire in March 2002, another 175 MMcf/d will expire in 2003, and the remainder of the capacity will expire between 2006 and 2011. Extensions of these contracts are under negotiation. ANR also faces competition in the Northeast markets from other interstate pipelines serving electric generation and local distribution companies. EPNG. EPNG faces competition from other pipeline companies that transport natural gas to the California market. EPNG's current capacity to deliver natural gas to California is approximately 3.3 Bcf/d, and the combined capacity of all pipeline companies serving the California market is approximately 6.9 Bcf/d. In 2000, the demand for interstate pipeline capacity to California averaged 5.4 Bcf/d, equivalent to approximately 78 percent of the total interstate pipeline capacity serving that state. Natural gas shipped to California across the EPNG system represented approximately 35 percent of the natural gas consumed in the 6 8 state in 2000. EPNG's ability to remarket its capacity under expiring contracts may be adversely affected by excess capacity into California. The significant customers served by EPNG in California during 2000 included Southern California Gas Company, with capacity of 1,150 MMcf/d under contract until August 2006, and Merchant Energy, with capacity of 1,221 MMcf/d under contract through May 2001. In February 2001, EPNG completed its open season on the capacity held by Merchant Energy and all the available capacity was re-subscribed. Contracts were awarded to 30 different entities, including 271 MMcf/d to Merchant Energy, all at published tariff rates under contracts with durations from 17 months to 15 years. SNG. SNG's customers include distribution and industrial customers, electric generation companies, gas producers, other gas pipelines and gas marketing and trading companies. SNG provides transportation services in both its natural gas supply and market areas. SNG's contracts to provide firm transportation service for its customers are for varying amounts and periods of time. Substantially all of the firm transportation capacity currently available in SNG's two largest market areas is fully subscribed. The significant customers served by SNG include: - Atlanta Gas Light Company, with capacity of 770 MMcf/d under contracts that expire beginning in 2005 through 2007, with the majority expiring in 2005; - Alabama Gas Corporation, with capacity of 384 MMcf/d under contracts that expire beginning in 2005 through 2008, with the majority expiring in 2008; and - South Carolina Pipeline Corporation, with capacity of 188 MMcf/d under contract which expires primarily in 2005. Nearly all of SNG's firm transportation contracts automatically extend the term for additional months or years unless notice of termination is given by one of the parties. Competition among pipelines is strong in a number of SNG's key markets. Customers purchase natural gas supply from producers and natural gas marketing companies in unregulated transactions and contract with SNG for transportation services to deliver this supply to their markets. SNG's three largest customers are able to obtain a significant portion of their natural gas requirements through transportation from other pipelines. In addition, SNG competes with several pipelines for the transportation business of many of its other customers. The competition with these pipelines is intense, and SNG must, at times, discount its transportation rates in order to maintain market share. CIG. CIG serves two major markets, its "on-system" market, consisting of the utilities along the Front Range of the Rocky Mountains in Colorado and Wyoming, and its "off-system" market, consisting of the transportation of Rocky Mountain production from multiple supply basins to interconnections with other pipelines bound for the Midwest or California. CIG faces different types of competition in both markets. In the on-system market, competition comes from local supply in the Denver-Julesburg basin, from an intrastate pipeline directly serving Denver, and from off-system shippers who can deliver their gas in that market, supplanting CIG transportation for utility customers. The primary criterion for success in this market is the ability to serve a very volatile load reliably, at a competitive price. In the off-system market, CIG faces competition in its supply area from two major pipelines serving the California and Pacific Northwest markets. It also faces competition from competitors whose supply is produced in Texas, Oklahoma, and Kansas. These competitors can displace CIG deliveries into the pipelines serving the Midwestern markets. The primary criterion for success in this market is the strength of pricing differentials between Wyoming and Oklahoma. CIG's full capacity is contracted under firm transportation agreements, with the bulk of these agreements expiring within the next several years. The largest portion of these agreements is with Public Service Company of Colorado and will expire in the 2002 to 2005 timeframe. CIG is actively negotiating with all shippers for contract renewal and is optimistic that its ability to serve the Front Range market reliably and competitively, coupled with reasonably strong pricing differentials affecting off-system markets, will result in successful renewal of the expiring contracts. New firm transportation contracts have not yet been executed for the bulk of 7 9 the volumes involved, but CIG has reached agreement in principle with Public Service to renew its contracts at revenue levels close to historical levels. WIC. WIC's two lines are subject to different competitive forces. Both lines are currently fully contracted and are subject to take-away capacity constraints at their intersection in northern Colorado. Both of WIC's lines feed into the Trailblazer system going east, the CIG system going south and other interstate and intrastate pipelines connected at the CIG-Trailblazer interconnect. Due to the full capacity demand on the Trailblazer system and the near capacity demand on the CIG system, shippers on WIC's two lines must compete with each other for scarce capacity to the markets of choice. On WIC's main line, contracts for approximately 500 MMcf/d out of approximately 750 MMcf/d expire in 2003. Success in renewing or replacing these contracts will depend on the availability of eastbound capacity. WIC's contracts generally have between six and ten years remaining. MERCHANT ENERGY Our Merchant Energy segment is a market maker involved in a broad range of activities in the wholesale energy marketplace, including asset ownership, trading and risk management and financial services. Merchant Energy is organized into eight functional units, each with complementary activities that support our overall global merchant energy model. These units are: - Marketing and Origination; - Trading and Risk Management; - Power Generation; - LNG; - Refining, Marketing & Chemicals; - Coal; - Financial Services; and - Operations. Marketing and Origination. The Marketing and Origination unit provides energy solutions in natural gas, power, crude oil, refined products, coal, and other energy commodity markets. This unit also markets capacity from power, natural gas, and refining assets, and creates innovative structured transactions to enhance the value of Merchant Energy's assets. This unit is able to provide its customers with flexible solutions to meet their energy supply and financial risk management requirements by utilizing its knowledge of the marketplace, natural gas pipelines, storage, and power transmission infrastructures, supply aggregation, transportation management and valuation, and integrated price risk management. They also enter into short and long term energy supply and purchase contracts and perform total energy infrastructure outsourcing for customers. Trading and Risk Management. The Trading and Risk Management unit trades natural gas, power, crude oil, other energy commodities, and related financial instruments in North America and Europe and provides pricing and valuation analysis for the Marketing and Origination unit. Using the financial markets, this unit manages the inherent risk of Merchant Energy's asset and trading portfolios using value-at-risk limits set by our Board of Directors and optimizes the value inherent in the segment's asset portfolio. 8 10 During 2000, the Marketing and Origination and Trading and Risk Management units significantly grew their traded volumes across all commodity groups. Detailed below is the marketed and traded energy commodity volumes for the years ended December 31:
2000 1999 1998 -------- ------- ------- Physical natural gas marketed (Bbtu/d)................. 10,357 6,713 7,089 Crude oil and refined products (MBbls)................. 667,270 664,944 682,033 Power marketed (MMWh).................................. 115,836 79,858 55,575 Financial settled volumes (Bbtue/d).................... 103,098 68,678 31,783
Power Generation. Our Power Generation unit is one of the largest non-utility generators in the U.S., and currently owns or has interests in 84 power plants in 20 countries. These plants represent 22,042 gross megawatts of generating capacity. Of these facilities, 68 percent are natural gas fired, 12 percent are geothermal, and 20 percent are a combination of coal, natural gas liquids, and hydroelectric. During 2000, Merchant Energy continued acquiring domestic non-utility generation assets, especially those with above-market power purchase agreements. As part of these efforts, we used Chaparral Investors, L.L.C., (also referred to as Electron) to expand Merchant Energy's growth in the power generation business. Through Chaparral, Merchant Energy has invested in 27 U.S. power generation facilities with a total generating capacity of approximately 5,800 gross megawatts. A subsidiary of Merchant Energy serves as the manager of Chaparral and its wholly-owned subsidiary, Mesquite Investors, L.L.C., under a management agreement, which expires in 2006. As compensation for managing Chaparral, Merchant Energy is paid an annual performance-based management fee. Detailed below are brief descriptions, by region, of Merchant Energy's power generation projects that are either operational or in various stages of construction or development.
NUMBER OF GROSS REGION PROJECT STATUS FACILITIES MEGAWATTS ------ -------------- ---------- --------- North America East Coast................................ Operational 18 5,170 Under Construction 1 716 Under Development 3 1,664 Central................................... Operational 9 1,430 Under Development 2 1,088 West Coast................................ Operational 21 1,036 Central America............................. Operational 6 1,285 South America............................... Operational 6 3,959 Under Construction 1 470 Asia........................................ Operational 11 3,176 Under Construction 2 1,108 Europe...................................... Operational 3 544 Under Construction 1 396 -- ------ Total............................. 84 22,042 == ======
LNG. The LNG unit contracts for LNG terminalling and regasification capacity, coordinates short and long term LNG supply deliveries, and is developing an international LNG supply and marketing business. As of December 31, 2000, our LNG unit has contracted for over 280 Bcf per year of LNG regasification capacity at three locations along the Eastern Coast of the U.S. and one location in Louisiana. In the Caribbean, we have contracted for 105 Bcf per year of long term supplies of LNG with deliveries scheduled to begin in 2002. Refining, Marketing & Chemicals. Our Refining, Marketing and Chemicals unit owns four crude oil refineries, seven chemical production facilities, and has blending and packaging operations that produce and distribute a variety of lubricants and automotive related products. The refineries have a throughput capability of 538,000 barrels of crude oil per day to produce a variety of gasoline, diesel fuels, asphalt, industrial fuels, 9 11 and other products. The chemical facilities have a production capability of 3,800 tons per day and produce various industrial and agricultural products. Our refineries operated at 93 percent of average combined capacity in each of 2000 and 1999 and at 85 percent in 1998. The aggregate sales volumes of our wholly owned refineries were approximately 182 MMBls in 2000, 171 MMBls in 1999, and 154 MMBls in 1998. Of the total refinery sales in 2000, 27 percent was gasoline, 50 percent was middle distillates, like jet fuel, diesel fuel, and home heating oil, and 23 percent was heavy industrial fuels and other products. The following table presents average daily throughput and storage capacity at our wholly owned refineries at December 31, 2000:
AVERAGE AT DECEMBER 31, DAILY 2000 THROUGHPUT ------------------- ----------- DAILY STORAGE REFINERY LOCATION 2000 1999 CAPACITY CAPACITY -------- -------- ---- ---- -------- -------- (IN MBBLS) Aruba Aruba................................ 229 195 280 15,300 Corpus Christi Corpus Christi, Texas................ 99 100 100 7,100 Eagle Point Westville, New Jersey................ 143 143 140 9,300 Mobile Mobile, Alabama...................... 12 13 18 600 --- --- --- ------ Total....................................... 483 451 538 32,300 === === === ======
Our refineries produce a full range of petroleum products ranging from transportation fuels to paving asphalt. They are operated to produce the particular products required by customers within each refinery's geographic area. In 2000, the products emphasized included premium gasoline and products for specialty markets like petrochemical feed stocks, aviation fuels, and asphalt. Our chemical plants produce agricultural fertilizers, gasoline additives, and other industrial products from facilities in Wyoming, Nevada, Texas, and Oregon. The following table presents sales volumes from our chemical facilities for each of the three years ended December 31;
2000 1999 1998 ------ ------ ------ (IN THOUSANDS OF TONS) Agricultural................................................ 389 326 346 Industrial.................................................. 547 608 550 MTBE........................................................ 214 209 210 ----- ----- ----- Total............................................. 1,150 1,143 1,106 ===== ===== =====
Coal. Our Coal unit controls reserves totaling 536 million recoverable tons and produces a high-quality bituminous coal from reserves in Kentucky, Virginia, and West Virginia. The coal is primarily sold under long-term contracts to power generation facilities in the eastern United States. Financial Services. The Financial Services unit provides financing to the energy and power industries and provides institutional funds management. Merchant Energy owns EnCap, an institutional funds management firm specializing in financing independent oil and natural gas producers. EnCap manages three separate institutional oil and natural gas investment funds in the U.S., and serves as investment advisor to Energy Capital Investment Company PLC, a publicly traded investment company in the United Kingdom. During 2000, we acquired Enerplus Global Energy Management, Inc., an institutional and retail funds management firm in Canada. Combined, EnCap and Enerplus manage funds with a market value of approximately $2 billion. In addition to EnCap and Enerplus, Merchant Energy's Financial Services unit holds investments of approximately $82 million. Also in 2000, it began originating financing for North American power development projects. As of December 31, 2000, it had funded $5 million of loans with additional commitments for $68 million. 10 12 Operations. The Operations unit conducts the day-to-day operations of Merchant Energy's assets in close coordination with the Marketing and Origination and Trading and Risk Management units. Our Operations unit operates 17 generating facilities in the U.S. and seven facilities in seven foreign countries. Finance and Administration. In addition to its functional units, Merchant Energy has a Finance and Administration unit that implements financing strategies for its assets, and provides accounting and administrative services for the segment's activities. Regulatory Environment Merchant Energy's domestic power generation activities are regulated by FERC under the Federal Power Act with respect to its rates, terms and conditions of service and other reporting requirements. In addition, exports of electricity outside of the U.S. must be approved by the Department of Energy. Its cogeneration power production activities are regulated by FERC under the Public Utility Regulatory Policies Act with respect to rates, procurement and provision of services, and operating standards. All of its power generation are also subject to the U.S. Environmental Protection Agency (EPA) regulations. Merchant Energy's foreign operations are regulated by numerous governmental agencies in the countries in which these projects are located. Generally, many of the countries in which Merchant Energy conducts and will conduct business have recently developed or are developing new regulatory and legal structures to accommodate private and foreign-owned businesses. These regulatory and legal structures and their interpretation and application by administrative agencies are relatively new and sometimes limited. Many detailed rules and procedures are yet to be issued and we expect that the interpretation of existing rules in these jurisdictions will evolve over time. We believe that our operations are in compliance in all material respects with all applicable environmental laws and regulations in the applicable foreign jurisdictions. We also believe that the operations of our projects in many of these countries eventually may be required to meet standards that are comparable in many respects to those in effect in the U.S. and in countries within the European Community. Markets and Competition Merchant Energy maintains a diverse supplier and customer base. During 2000, Merchant Energy's activities served over 900 suppliers and over 1,500 sales customers around the world. Merchant Energy's trading, marketing, and power development businesses operate in a highly competitive environment. Its primary competitors include: - affiliates of major oil and natural gas producers; - multi-national energy infrastructure companies; - large domestic and foreign utility companies; - affiliates of large local distribution companies; - affiliates of other interstate and intrastate pipelines; and - independent energy marketers and power producers with varying scopes of operations and financial resources. 11 13 Merchant Energy competes on the basis of price, access to production, understanding of pipeline and transmission networks, imbalance management, experience in the marketplace, and counterparty credit. Many of Merchant Energy's generation facilities sell power pursuant to long-term agreements with investor-owned utilities in the U.S. Because of the terms of its power purchase agreements for its facilities, Merchant Energy's revenues are not significantly impacted by competition from other sources of generation for these facilities. The power generation industry is rapidly evolving, and regulatory initiatives have been adopted at the federal and state level aimed at increasing competition in the power generation business. As a result, it is likely that when the power purchase agreements expire, these facilities will be required to compete in a significantly different market in which operating efficiency and other economic factors will determine success. Merchant Energy is likely to face intense competition from generation companies as well as from the wholesale power markets. The successful acquisition of new business opportunities is dependent upon Merchant Energy's ability to respond to requests to provide new services, mitigate potential risks, and maintain strong business development, legal, financial and operational support teams with experience in the respective marketplace. FIELD SERVICES Our Field Services segment provides customers with wellhead-to-mainline services, including natural gas gathering, storage, products extraction, fractionation, dehydration, purification, compression, transportation of natural gas and natural gas liquids, and intrastate natural gas transmission services. It also provides well-ties and offers real-time information services, including electronic wellhead gas flow measurement, and works with Merchant Energy to provide fully bundled natural gas services with a broad range of pricing options as well as financial risk management products. Field Services' assets include natural gas gathering and natural gas liquids pipelines, treating, processing, and fractionation facilities in the San Juan Basin, the producing regions of east and south Texas, Louisiana, and the Rocky Mountains. Through our subsidiaries, we own a one percent general partner interest in Energy Partners and a one percent non-managing interest in many of its subsidiaries. We also own 27.8 percent of the partnership's common units and $170 million of its preferred units. Energy Partners is our primary vehicle for the acquisition and development of midstream energy infrastructure assets. Energy Partners' assets provide gathering, transportation, storage, and other related activities for producers of natural gas and oil. Energy Partners owns or has interests in six natural gas and oil pipeline systems, six offshore platforms, two natural gas storage facilities, five producing oil and natural gas properties, and an overriding royalty interest in a non-producing oil and natural gas property. In December 2000, Field Services purchased PG&E's Texas Midstream operations. The acquired assets consisted of 7,500 miles of natural gas transmission and natural gas liquids pipelines that transport approximately 2.8 Bcf/d, nine natural gas processing and fractionation plants that process 1.5 Bcf/d, and rights to 7.2 Bcf of natural gas storage capacity. These assets serve a majority of the metropolitan areas and the largest industrial load centers in Texas, as well as numerous natural gas trading hubs. These assets also create a physical link between our EPNG and TGP systems. In the first quarter of 2001, Field Services sold some of these acquired natural gas liquids transportation and fractionation assets to Energy Partners. The assets sold include more than 600 miles of natural gas liquids gathering and transportation pipelines and three fractionation plants located in south Texas. 12 14 The following tables provide information concerning Field Services' natural gas gathering and transportation facilities, its processing facilities, and its facilities accounted for under the equity method as of and for each of the three years ended December 31:
AVERAGE THROUGHPUT THROUGHPUT (BBTUE/D) PERCENT OF MILES OF CAPACITY ----------------------- OWNERSHIP GATHERING & TREATING PIPELINE(1) (MMCFE/D)(2) 2000 1999 1998(2) INTEREST -------------------- ----------- ------------ ----- ----- ------- ---------- Central Division(3).................................... 9,890 6,760 1,425 1,528 1,771 100 Western Division....................................... 9,035 1,798 1,896 1,868 1,943 100 Eastern Division(4).................................... 2,230 1,065 443 514 534 100 Energy Partners(5)..................................... 1,251 1,003 533 421 365 30 Dauphin Island......................................... 250 39 43 56 60 15 Viosca Knoll(5)........................................ 125 10 6 142 287 --
AVERAGE NATURAL GAS AVERAGE INLET VOLUME LIQUIDS SALES (BBTU/D)(2) (MGAL/D)(2) PERCENT OF INLET CAPACITY ---------------------- ------------------- OWNERSHIP PROCESSING PLANTS (MMCF/D)(2) 2000 1999 1998 2000 1999 1998 INTEREST ----------------- -------------- ------ ----- ----- ----- ---- ---- ---------- Eastern Division(4)............................... 2,480 1,832 337 334 1,710 535 565 100 Central Division(3)............................... 1,883 309 242 269 307 202 208 100 Western Division.................................. 964 916 901 848 1,006 878 886 100 Blue Water........................................ 780 623 -- -- 680 -- -- 24 Mobile Bay........................................ 600 338 115 -- 547 77 -- 42 Coyote Gulch...................................... 120 87 97 69 -- -- -- 50
--------------- (1) Mileage amounts are approximate for the total systems and have not been reduced to reflect Field Services' net ownership. (2) All volumetric information reflects Field Services' net interest and is subject to increases or decreases depending on operating pressures and point of delivery into or out of the system. (3) Reflects the acquisition of PG&E's Texas Midstream operations in December 2000. (4) Reflects the acquisition of TransCanada Gas Processing U.S.A. in December 1999. (5) Field Services sold its 49 percent interest in Viosca Knoll to Energy Partners in June 1999 and its remaining one percent interest in September 2000. Regulatory Environment Some of Field Services' and Energy Partners' operations are subject to regulation by FERC in accordance with the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. Each pipeline subject to regulation operates under separate FERC approved tariffs with established rates, terms and conditions under which the pipeline provides services. In addition, some of Field Services' and Energy Partners' operations, directly owned or owned through equity investments, are subject to the Natural Gas Pipeline Safety Act of 1968, the Hazardous Liquid Pipeline Safety Act, and the National Environmental Policy Act. Each of the pipelines has a continuing program of inspection designed to keep all of the facilities in compliance with pollution control and pipeline safety requirements and Field Services and Energy Partners believe that these systems are in substantial compliance with applicable requirements. Markets and Competition Field Services competes with, among others, major interstate and intrastate pipeline companies in the transportation of natural gas and natural gas liquids. Field Services also competes with major integrated energy companies, independent natural gas gathering and processing companies, natural gas marketers, and oil and natural gas producers in gathering and processing natural gas and natural gas liquids. Competition for throughput and natural gas supplies is based on a number of factors, including price, efficiency of facilities, gathering system line pressures, availability of facilities near drilling activity, service, and access to favorable downstream markets. 13 15 PRODUCTION Our Production segment is engaged in the exploration for and the acquisition, development, and production of natural gas, oil, and natural gas liquids. In the United States, Production has onshore and coal seam operations and properties in 16 states and offshore operations and properties in federal and state waters in the Gulf of Mexico. Internationally, it has exploration and production rights in Australia, Brazil, Canada, Hungary, Indonesia, and Turkey. Production sells its natural gas primarily at spot-market prices. It sells its natural gas liquids at market prices under monthly or long-term contracts and its oil production at posted prices, subject to adjustments for gravity and transportation. Production engages in hedging activities on its natural gas and oil production in order to stabilize cash flows and reduce the risk of downward commodity price movements on sales of its production. A significant portion of the segment's 2000 production was hedged by entering into third-party contracts and forward sales. Strategically, Production emphasizes disciplined investment criteria and manages its existing production portfolio to maximize volumes and minimize costs. Production expects to continue an active onshore and offshore drilling program to capitalize on its land and seismic holdings. Production is also pursuing strategic acquisitions of producing properties and the development of coal seam projects. In 2000, Production replaced 288 percent of the reserves it produced. Natural Gas and Oil Reserves The following table details Production's proved reserves at December 31, 2000. Information in the table is based upon the combination of the reserve report prepared by Production dated January 1, 2001, and the report prepared by Coastal and reviewed by Huddleston. This information agrees with estimates of reserves filed with other federal agencies except for differences of less than 5 percent resulting from actual production, acquisitions, property sales, and necessary reserve revisions and additions to reflect actual experience.
NET PROVED RESERVES(1) ------------------------------------ NATURAL GAS LIQUIDS(2) TOTAL ----------- ---------- --------- (MMCF) (MBBLS) (MMCFE) PRODUCTION United States Producing......................................... 2,273,664 38,206 2,502,900 Non-Producing..................................... 603,352 16,839 704,386 Undeveloped....................................... 2,695,650 40,257 2,937,192 --------- ------ --------- Total proved reserves.......................... 5,572,666 95,302 6,144,478 ========= ====== ========= Canada Producing......................................... 41,478 1,007 47,520 Non-Producing..................................... 70,363 1,672 80,395 Undeveloped....................................... 54,670 1,244 62,134 --------- ------ --------- Total proved reserves.......................... 166,511 3,923 190,049 ========= ====== ========= Brazil Undeveloped....................................... 90,862 4,862 120,034 --------- ------ --------- Total proved reserves.......................... 90,862 4,862 120,034 ========= ====== ========= NATURAL GAS SYSTEMS(3) Producing........................................... 175,353 231 176,739 --------- ------ --------- Total proved reserves.......................... 175,353 231 176,739 ========= ====== =========
--------------- (1) Net proved reserves exclude royalties and interests owned by others and reflects contractual arrangements and royalty obligations in effect at the time of the estimate. (2) Includes oil, condensate, and natural gas liquids. (3) Includes regulated natural gas and oil properties owned by Colorado Interstate Gas Company. 14 16 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 Production. The reserve data represents only estimates. Reservoir engineering is a subjective process of estimating underground accumulations of natural gas and oil that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretations 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. Reserve estimates are often different from the quantities of natural gas and oil that are ultimately recovered. The meaningfulness of reserve estimates is highly dependent upon the accuracy of the assumptions upon which they were based. In general, the volume of production from natural gas and oil properties owned by Production declines as reserves are depleted. Except to the extent Production conducts successful exploration and development activities or acquires additional properties containing proved reserves, or both, the proved reserves of Production will decline as reserves are produced. For further discussion of our reserves, see Supplemental Combined Financial Statements, Note 19. Wells and Acreage The following table details Production's gross and net interest in developed and undeveloped onshore, offshore, coal seam, and international acreage at December 31, 2000. Any acreage in which Production's interest is limited to owned royalty, overriding royalty, and other similar interests is excluded.
DEVELOPED UNDEVELOPED TOTAL --------------------- ---------------------- ----------------------- GROSS NET GROSS NET GROSS NET --------- --------- ---------- --------- ---------- ---------- PRODUCTION United States Onshore.................... 1,809,132 823,831 2,397,904 1,684,557 4,207,036 2,508,388 Offshore................... 710,205 471,386 1,620,818 1,496,295 2,331,023 1,967,681 Coal seam.................. 32,634 26,666 581,045 437,493 613,679 464,159 --------- --------- ---------- --------- ---------- ---------- Total United States..... 2,551,971 1,321,883 4,599,767 3,618,345 7,151,738 4,940,228 --------- --------- ---------- --------- ---------- ---------- International Australia.................. -- -- 1,770,364 613,600 1,770,364 613,600 Brazil..................... -- -- 4,245,495 3,320,744 4,245,495 3,320,744 Canada..................... 11,520 9,158 246,034 182,030 257,554 191,188 Hungary.................... -- -- 568,100 568,100 568,100 568,100 Indonesia.................. -- -- 1,373,691 442,606 1,373,691 442,606 --------- --------- ---------- --------- ---------- ---------- Total International..... 11,520 9,158 8,203,684 5,127,080 8,215,204 5,136,238 --------- --------- ---------- --------- ---------- ---------- NATURAL GAS SYSTEMS Domestic Onshore............. 262,474 259,276 -- -- 262,474 259,276 --------- --------- ---------- --------- ---------- ---------- Total................... 2,825,965 1,590,317 12,803,451 8,745,425 15,629,416 10,335,742 ========= ========= ========== ========= ========== ==========
The U.S. net developed acreage is concentrated primarily in the Gulf of Mexico (30 percent), Texas (28 percent), Utah (20 percent), Oklahoma (7 percent), Colorado (6 percent) and Louisiana (6 percent). Approximately 17 percent, 14 percent, and 13 percent of our total U.S. net undeveloped acreage is under leases that have minimum remaining primary terms expiring in 2001, 2002 and 2003. 15 17 The following table details Production's working interests in onshore, offshore, coal seam, and international natural gas and oil wells at December 31, 2000. Gross wells include 79 multiple completions.
NUMBER OF PRODUCTIVE NATURAL PRODUCTIVE OIL TOTAL PRODUCTIVE WELLS BEING GAS WELLS WELLS WELLS DRILLED ------------------- --------------- ----------------- ----------- GROSS NET GROSS NET GROSS NET GROSS NET -------- -------- ------- ----- ------- ------- ----- --- PRODUCTION United States Onshore............................ 4,045 2,946 471 337 4,516 3,283 70 55 Offshore........................... 490 312 39 29 529 341 14 10 Coal seam.......................... 1,086 663 -- -- 1,086 663 57 41 ----- ----- --- --- ----- ----- --- --- Total........................... 5,621 3,921 510 366 6,131 4,287 141 106 ----- ----- --- --- ----- ----- --- --- International Australia.......................... -- -- -- -- -- -- 1 1 Canada............................. 26 21 -- -- 26 21 38 36 Indonesia.......................... -- -- -- -- -- -- 1 1 ----- ----- --- --- ----- ----- --- --- Total........................... 26 21 -- -- 26 21 40 38 ----- ----- --- --- ----- ----- --- --- NATURAL GAS SYSTEMS.................. 809 789 9 8 818 797 -- -- ----- ----- --- --- ----- ----- --- --- Total........................... 6,456 4,731 519 374 6,975 5,105 181 144 ===== ===== === === ===== ===== === ===
The following table details Production's exploratory and development wells drilled during the years 1998 through 2000.
NET EXPLORATORY NET DEVELOPMENT WELLS DRILLED WELLS DRILLED ------------------ ------------------ 2000 1999 1998 2000 1999 1998 ---- ---- ---- ---- ---- ---- PRODUCTION United States Productive........................................... 16 19 20 424 297 347 Dry.................................................. 17 19 22 18 3 19 -- -- -- --- --- --- Total............................................. 33 38 42 442 300 366 -- -- -- --- --- --- Canada Productive........................................... 3 5 -- 10 2 -- Dry.................................................. 3 -- -- 1 2 -- -- -- -- --- --- --- Total............................................. 6 5 -- 11 4 -- -- -- -- --- --- --- Other Countries Productive........................................... -- -- -- -- -- -- Dry.................................................. 1 -- 1 -- -- -- -- -- -- --- --- --- Total............................................. 1 -- 1 -- -- -- -- -- -- --- --- --- NATURAL GAS SYSTEMS Productive........................................... -- -- -- 1 13 6 Dry.................................................. -- -- -- -- -- -- -- -- -- --- --- --- Total............................................. -- -- -- 1 13 6 -- -- -- --- --- --- Total wells drilled.......................... 40 43 43 454 317 372 == == == === === ===
The information above should not be considered indicative of future drilling performance, nor should it be assumed that there is any correlation between the number of productive wells drilled and the amount of natural gas and oil that may ultimately be recovered. 16 18 Net Production, Unit Prices, and Production Costs The following table details Production's net production volumes, average sales prices received, and average production costs associated with the sale of natural gas and oil for each of the years ended December 31:
2000 1999 1998 ------ ------ ------ PRODUCTION Net Production: Natural Gas (Bcf)........................................ 517 416 411 Oil, Condensate, and Liquids (MMBbls).................... 12 10 14 Total (Bcfe)............................................. 587 478 495 Average Realized Sales Price: Natural Gas ($/Mcf)...................................... $ 2.61 $ 2.11 $ 1.98 Oil, Condensate, and Liquids ($/Bbl)..................... $21.82 $15.03 $12.29 Average Production Cost ($/Mcfe)(1)........................ $ 0.41 $ 0.42 $ 0.36 NATURAL GAS SYSTEMS Net Production: Natural Gas (Bcf)........................................ 33 36 39
--------------- (1) Includes direct lifting costs (labor, repairs and maintenance, materials, and supplies) and the administrative costs of production offices, insurance, and property and severance taxes. Acquisition, Development, and Exploration Expenditures The following table details information regarding Production's costs incurred in its development, exploration, and acquisition activities during each of the years ended December 31:
2000 1999 1998 ------ ------ ------ (IN MILLIONS) Acquisition Costs: Proved................................................... $ 204 $ 157 $ 131 Unproved................................................. 177 197 181 Development Costs.......................................... 1,298 771 915 Exploration Costs: Delay Rentals............................................ 12 11 14 Seismic Acquisition and Reprocessing..................... 92 118 111 Drilling................................................. 263 178 154 ------ ------ ------ Total Capital Expenditures....................... $2,046 $1,432 $1,506 ====== ====== ======
Regulatory and Operating Environment The federal government and the states in which Production operates or owns interests in producing properties regulate various matters affecting natural gas and oil production, including drilling and spacing of wells, conservation, forced pooling, and protection of correlative rights among interest owners. Production is also subject to governmental safety regulations in the jurisdictions in which it operates. Production's operations under federal natural gas and oil leases are regulated by the statutes and regulations of the United States Department of the Interior that currently impose liability upon lessees for the cost of pollution resulting from their operations. Royalty obligations on all federal leases are regulated by the Minerals Management Service, which has promulgated valuation guidelines for the payment of royalties by producers. Other federal, state, and local laws and regulations relating to the protection of the environment affect Production's natural gas and oil operations through their effect on the construction and operation of 17 19 facilities, drilling operations, production, or the delay or prevention of future offshore lease sales. We maintain substantial insurance on behalf of Production for sudden and accidental spills and oil pollution liability. Production's business has operating risks normally associated with the exploration for and production of natural gas and oil, including blowouts, cratering, pollution, and fires, each of which could result in damage to life or property. Offshore operations may encounter the 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. Customary with industry practices, we maintain broad insurance coverage on behalf of Production with respect to potential losses resulting from these operating hazards. Markets and Competition The natural gas and oil business is highly competitive in the search for and acquisition of additional reserves and in the sale of natural gas, oil, and natural gas liquids. Production's competitors include the major and intermediate sized oil and natural gas companies, independent oil and natural gas operations, and individual producers or operators with varying scopes of operations and financial resources. Competitive factors include price, contract terms, and quality of service. To some degree, price competition is mitigated by Production's hedging activities. CORPORATE AND OTHER OPERATIONS Through our corporate group, we perform management, legal, financial, tax, consulting, administrative and other services for our operating business segments. The costs of providing these services are allocated to our business segments. Our other operations include the assets and operations of our telecommunication business and our retail marketing and fleet fueling activities. Through Coastal Mart, Inc. and branded marketers, we conduct retail marketing, using the C-MART(R), C and Design and/or COASTAL(R) trademarks, in 34 states and Aruba through 1,529 Coastal branded outlets, of which we operate 374 outlets. Fleet fueling operations include 23 outlets in Texas and six in Florida. In December 2000, we entered into agreements to sell approximately 100 company-operated outlets in New Jersey, Pennsylvania, Virginia, West Virginia, Tennessee, North Carolina, and South Carolina and approximately 100 company-operated outlets in Colorado, Iowa, Kansas, Nebraska, Oklahoma, South Dakota, and Wyoming. The sale of the outlets in the northeastern and eastern states was completed in February 2001, and the sale of the outlets in the Midwest is expected to be completed in the second quarter 2001. The agreements also include the sale of branded marketer and contract dealer accounts covering 355 locations in 19 states. After completion of the proposed sales, the Company's retail marketing operations will be conducted in 23 states and Aruba through 973 Coastal-branded outlets, of which 176 will be company operated. 18 20 SELECTED FINANCIAL DATA We derived the operating results data for the years ended December 31, 2000, 1999, and 1998 and the financial position data as of December 31, 2000 and 1999 from our audited supplemental combined financial statements for the year ended December 31, 2000. We derived the remaining financial data by combining selected financial data from the separate historical consolidated financial information of El Paso and Coastal to give effect to the Coastal merger. For a further discussion of the information presented and discussed below for each of the three years ended December 31, 2000, see the Supplemental Combined Financial Statements beginning on page 43.
YEAR ENDED DECEMBER 31, ----------------------------------------------- 2000 1999 1998 1997 1996 ------- ------- ------- ------- ------- (IN MILLIONS, EXCEPT PER COMMON SHARE AMOUNTS) Operating Results Data:(1) Operating revenues(2)(3)........................ $49,268 $27,332 $23,773 $27,819 $25,168 Merger-related costs and asset impairment charges...................................... 125 557 15 50 99 Ceiling test charges(4)......................... -- 352 1,035 -- -- Income from continuing operations before preferred stock dividends.................... 1,236 257 176 804 802 Income from continuing operations available to common stockholders.......................... 1,236 257 170 787 785 Basic earnings per common share from continuing operations................................... 2.50 0.52 0.35 1.60 1.77 Diluted earnings per common share from continuing operations........................ 2.43 0.52 0.34 1.58 1.75 Cash dividends declared per common share(5)..... 0.82 0.80 0.76 0.73 0.70 Basic average common shares outstanding......... 494 490 487 492 443 Diluted average common shares outstanding....... 513 497 495 497 448
AS OF DECEMBER 31, ----------------------------------------------- 2000 1999 1998 1997 1996 ------- ------- ------- ------- ------- (IN MILLIONS) Financial Position Data:(1) Total assets(3)................................. $46,014 $31,790 $26,759 $26,424 $24,826 Long-term debt, less current maturities......... 10,902 10,021 7,691 7,067 6,777 Non-current notes payable to unconsolidated affiliates................................... 343 -- -- -- -- Company-obligated preferred securities of consolidated trusts.......................... 925 625 625 -- -- Minority interest............................... 2,782 1,819 374 380 347 Stockholders' equity............................ 8,119 6,884 6,913 7,203 6,551
--------------- (1) Our operating results and financial position reflect the acquisitions in June 1996 of Cornerstone Natural Gas, in December 1996 of El Paso Tennessee Pipeline (formerly Tenneco Inc.), in August 1998 of DeepTech International, and in December 2000 of PG&E's Texas Midstream operations. These acquisitions were accounted for as purchases and therefore operating results are included in our results prospectively from the purchase date. (2) We restated historical operating revenues due to the implementation in 2000 of Emerging Issues Task Force Issue No. 99-19, Reporting Revenue Gross as a Principal versus Net as an Agent, which provides guidance on the gross versus net presentation of revenues and expenses and to adjust Coastal's presentation of its petroleum marketing and trading activities to our manner of presentation. These reclassifications impacted operating revenues and expenses, but had no impact on net income or earnings per share. See Supplemental Combined Financial Statements, Notes 2 and 18. (3) Reflects the consolidation of the U.S. operations of Coastal Merchant Energy in September 2000 as well as the significant growth in our Merchant Energy operations in 2000. (4) Ceiling test charges are reductions in earnings that result when capitalized costs of natural gas and oil properties exceed the upper limit, or ceiling, on the value of these properties. (5) We have assumed that cash dividends declared per share of common stock are the same as the historical dividends declared by El Paso during the periods presented. 19 21 MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS GENERAL Over the past several years, our business activities and operations have changed dramatically as a result of significant acquisitions, transactions, and internal growth initiatives, designed to enhance our ability to compete effectively in the global energy industry. These changes have significantly expanded our operating scope, our ability to generate operating cash flows and our needs for cash for investment opportunities. Consequently, we have substantially expanded our credit facilities and created other financing structures and facilities to meet our needs during this period. The more significant changes are discussed below. Merger with The Coastal Corporation In January 2001, we merged with The Coastal Corporation. We accounted for the merger as a pooling of interests and converted each share of Coastal common stock and Class A common stock on a tax-free basis into 1.23 shares of our common stock. We also exchanged Coastal's outstanding convertible preferred stock for our common stock on the same basis as if the preferred stock had been converted into Coastal common stock immediately prior to the merger. We issued a total of 271 million shares, including 4 million shares issued to holders of Coastal stock options. The total value of the transaction was approximately $24 billion, including $7 billion of assumed debt and preferred equity. The management discussion and analysis of financial condition and results of operations presented herein reflects the combined information of our two companies for all periods presented. Purchase of Texas Midstream Operations In late December 2000, we completed our purchase of PG&E's Texas Midstream operations for $887 million, including the assumption of $527 million of debt. We accounted for this acquisition as a purchase. The assets acquired consist of 7,500 miles of natural gas transmission and natural gas liquids pipelines that transport approximately 2.8 Bcf/d, nine natural gas processing plants that process 1.5 Bcf/d, and rights to 7.2 Bcf of natural gas storage capacity. These assets serve a majority of the metropolitan areas and the largest industrial load centers in Texas, as well as numerous natural gas trading hubs. These assets also create a physical link between our EPNG and TGP systems. In March 2001, Field Services sold some of these acquired natural gas liquids transportation and fractionation assets to Energy Partners. The assets sold include more than 600 miles of natural gas liquids gathering and transportation pipelines and three fractionation plants located in South Texas. In December 2000, to comply with a Federal Trade Commission order, we sold our interest in Oasis Pipeline Company. Proceeds from the sale were $22 million and we recognized an extraordinary loss of $19 million, net of income taxes of $9 million. Merger with Sonat Inc. In October 1999, we completed our merger with Sonat. In the merger, we issued one share of our common stock for each share of Sonat common stock. Total shares issued were approximately 110 million shares. In connection with a Federal Trade Commission order related to this merger, we sold our East Tennessee Natural Gas Company and Sea Robin Pipeline Company as well as our one-third interest in Destin Pipeline Company. Proceeds from the sales were approximately $616 million and we recognized an extraordinary gain of $89 million, net of income taxes of $60 million. We accounted for the merger as a pooling of interests. Merger-Related Costs and Asset Impairment Charges As we have integrated the activities and operations of our mergers and acquisitions, we have incurred, and will continue to incur, charges that will have a significant impact on our results of operations, financial position, and cash flows. These costs will include employee severance, retention, and transition charges; 20 22 write-offs or write-downs of duplicate assets; charges to relocate assets and employees; contract termination charges; and charges to align accounting policies and practices. During the three year period ended December 31, 2000, we incurred charges related to the mergers with Coastal, Sonat, and Zilkha Energy. In September 2000, we announced a plan to geographically consolidate our pipeline operations with Coastal's following the completion of our Coastal merger. Under the consolidation plan, El Paso Natural Gas Company's operations will be relocated from El Paso, Texas to Colorado Springs, Colorado, and ANR Pipeline Company's operations, will be relocated from Detroit, Michigan, to Houston, Texas. Along with this consolidation, we will also conduct numerous relocations among our various operating sites. All relocations under these plans are expected to be completed by mid-year 2001. Upon our merger with Coastal, we issued approximately 4 million shares of our common stock in exchange for Coastal employee, former employee, and outside director stock options. The total charge in connection with this exchange was approximately $278 million and will be included in our combined operations during the first quarter of 2001. As a result of our merger with Coastal, we were required to sell our ownership in the Gulfstream pipeline system and our 50 percent ownership in the Stingray and U-T Offshore Pipeline systems. Proceeds from the sales were approximately $70 million and we will record, in the first quarter of 2001, a loss on these sales of approximately $29 million, net of income taxes. Additionally, in the first quarter of 2001, Energy Partners sold its interest in several offshore assets. These sales consisted of interests in seven natural gas pipeline systems, a dehydration facility, and two offshore platforms. Proceeds from the sales of Energy Partners' assets were approximately $135 million resulting in a loss to the partnership of approximately $23 million. As additional consideration for these sales, we committed to pay Energy Partners a series of payments totaling $29 million. These payments will be recorded as a charge in our income statement in the first quarter of 2001. We will also be required to sell our Midwestern pipeline system, and our investments in the Iroquois Gas Pipeline and Empire Gas Pipeline systems. We expect to complete these sales in the first half of 2001. We do not anticipate the impact of our sales or the transactions by or with Energy Partners to have a material effect on our ongoing financial position, operating results, or cash flows. On January 30, 2001, we completed an employee restructuring, which resulted in the reduction of 3,285 full-time positions through a combination of early retirements and terminations. These reductions occurred across all locations and business segments. These actions resulted in severance and termination charges, retention payments for employees retained in the combined organization, and the acceleration of employee benefits under existing benefit plans. Total charges in connection with these actions are estimated to be approximately $890 million with a majority being recorded in the first quarter of 2001. The total cost of our merger-related activities, as well as additional charges we will incur as we complete our evaluations of the contracts, operating assets, and accounting policies of the combined organization could range between $1.6 billion and $2 billion. This estimate is based on the costs we expect to record in the first quarter of 2001 and our preliminary estimates of additional costs we will incur in subsequent periods. We expect that most, if not all, of these charges will be recorded in 2001. Also during the three year period ended December 31, 2000, we incurred a variety of asset impairment charges ranging from those as a result of rate filings within our regulated pipelines to write-downs of operating plants and contracts that were determined to be impaired. We also recorded write-downs of capitalized costs of our natural gas and oil properties under the full cost method of accounting in both 1998 and 1999. 21 23 Our merger-related costs and asset impairment charges are reflected in the results of operations discussed below for each of our segments. The table below provides a summary of our merger-related costs and asset impairment charges by each of our business segments, and in total, for each of the three years ended December 31:
2000 1999 1998 ---- ---- ------ (IN MILLIONS) Merger-related costs and asset impairment charges Pipelines................................................. $ -- $ 90 $ -- Merchant Energy........................................... 21 67 -- Field Services............................................ 11 8 -- Production................................................ -- 31 15 ---- ---- ------ Segment total.......................................... 32 196 15 Corporate and other....................................... 93 361 -- ---- ---- ------ Consolidated total..................................... $125 $557 $ 15 ==== ==== ====== Ceiling test charges--Production............................ $ -- $352 $1,035 ==== ==== ======
SEGMENT RESULTS OF OPERATIONS Our business activities are segregated into four segments: Pipelines, Merchant Energy, Field Services and Production. These segments are strategic business units that offer a variety of different energy products and services and each requires different technology and marketing strategies. Since earnings of equity investments can be a significant component in earnings for several of our segments, we evaluate segment performance based on earnings before interest expense and taxes, or EBIT. These segments are consistent with those reported by us prior to our merger with Coastal. Coastal's historical segments (natural gas systems; refining, marketing, and chemicals; exploration and production; power; and coal) have been included in the segments in which these businesses will be operated in the future, and all prior periods have been restated to reflect this presentation. The results presented in this analysis are not necessarily indicative of the results that would have been achieved had the revised business segment structure been in effect during those periods. Operating revenues and expenses by segment include intersegment revenues and expenses which are eliminated in consolidation. Because changes in energy commodity prices have a similar impact on both our operating revenues and cost of products sold from period to period, we believe that gross margin (revenue less cost of sales) provides a more accurate and meaningful basis for analyzing operating results for the Merchant Energy and the Field Services segments. For a further discussion of our individual segments, see the discussion of our businesses beginning on page 1, as well as the Supplemental Combined Financial Statements, Note 15. The following table presents EBIT by segment and in total including the merger-related costs and asset impairment charges discussed above for each of the three years ended December 31:
2000 1999 1998 ------ ------ ------ (IN MILLIONS) EARNINGS BEFORE INTEREST EXPENSE AND INCOME TAXES Pipelines................................................... $1,325 $1,293 $1,386 Merchant Energy............................................. 939 262 293 Field Services.............................................. 213 130 169 Production.................................................. 609 (85) (834) ------ ------ ------ Segment EBIT.............................................. 3,086 1,600 1,014 ------ ------ ------ Corporate and other expenses, net........................... (158) (381) (99) ------ ------ ------ Consolidated EBIT......................................... $2,928 $1,219 $ 915 ====== ====== ======
22 24 PIPELINES Our Pipelines segment operates our interstate pipeline businesses. Each of this segment's pipeline systems operates under a separate tariff that governs its operations and rates. Operating results for our pipeline systems have generally been stable because the majority of the revenues are based on fixed demand charges. As a result, we expect changes in this aspect of our business to be primarily driven by regulatory actions and contractual events. Commodity or throughput-based revenues account for a smaller portion of our operating results. These revenues vary from period to period, and system to system, and are impacted by factors such as weather, operating efficiencies, and to a lesser degree, fluctuations in natural gas prices. Results of operations of the Pipelines segment were as follows for each of the three years ending December 31:
2000 1999 1998 ------ ------- ------ (IN MILLIONS) Operating revenues.......................................... $2,712 $ 2,730 $2,762 Operating expenses.......................................... (1,599) (1,705) (1,637) Other income................................................ 212 268 261 ------ ------- ------ EBIT...................................................... $1,325 $ 1,293 $1,386 ====== ======= ======
YEAR ENDED DECEMBER 31, 2000 COMPARED TO YEAR ENDED DECEMBER 31, 1999 Operating revenues for the year ended December 31, 2000, were $18 million lower than the same period in 1999. This decrease was due to the impact of our sales of the East Tennessee Pipeline and Sea Robin systems in the first quarter of 2000, which we were required to sell under an FTC order as a condition to completing our Sonat merger, the favorable resolution of regulatory issues in the first quarter of 1999 on TGP, and lower rates following SNG's May 2000 rate case settlement. Additionally, the impact of customer settlements and contract terminations in 2000 and resolutions of customer imbalance issues in 1999 on TGP contributed to the decrease. Partially offsetting these decreases were higher revenues from transportation and other services provided on each of our transmission systems due to improved average throughput in 2000, higher realized prices on pipeline gas sales, the favorable resolution of litigation in 2000 on CIG, and revenues from the January 2000 acquisition of Crystal Gas Storage, Inc., prior to its sale to Energy Partners in September 2000. Operating expenses for the year ended December 31, 2000, were $106 million lower than the same period in 1999. The decrease was due to cost efficiencies following our merger with Sonat, lower operating costs on our East Tennessee Pipeline and Sea Robin systems, and the favorable impact of FERC's authorization to reactivate SNG's Elba Island facility in the first quarter of 2000. Also contributing to the decrease was the expense associated with a resolution of a contested rate matter with a customer of EPNG, severance and termination charges incurred as a result of our Sonat merger, and the impairment of several SNG expansion projects, all occurring in 1999. Additionally, estimated future environmental costs and write-offs of duplicate information technology assets in 1999 on SNG following our merger with Sonat contributed to the decrease. The decrease was partially offset by higher gas costs related to the Dakota gasification facility, higher system balancing requirements, and the impact of unfavorable producer and shipper settlements on EPNG. Other income for the year ended December 31, 2000 was $56 million lower than the same period in 1999. The decrease was due to the favorable settlement of a regulatory issue in 1999, the elimination of an asset for the future recovery of costs of the Elba Island facility, and a lower allowance for funds used during construction as a result of less expansion and construction activity in 2000. The decrease was partially offset by higher earnings on Citrus Corp. as a result of a one-time benefit recorded in 2000, higher earnings from our investments in 2000, as well as gains on the sale of non-pipeline assets in the third quarter of 2000. YEAR ENDED DECEMBER 31, 1999 COMPARED TO YEAR ENDED DECEMBER 31, 1998 Operating revenues for the year ended December 31, 1999, were $32 million lower than 1998. This decrease was largely due to revenues in 1998 resulting from the termination of ANR transportation contracts, revenues in 1998 resulting from the ANR rate case settlement and lower throughput and gas sales volumes in 23 25 1999 compared to 1998. The decrease was partially offset by a favorable resolution in 1999 of TGP's customer imbalance issues. Operating expenses for the year ended December 31, 1999 were $68 million higher than 1998. The increase was due to severance and termination charges incurred as a result of our merger with Sonat, the impairment of several SNG expansion projects, an increase in estimated environmental costs, and write-offs of duplicate information technology assets, all occurring in 1999. Also contributing to the increase were higher general and administrative costs on all systems, higher depreciation from expansion projects on SNG, and the unfavorable 1999 resolution of a contested rate matter with a customer of EPNG. Partially offsetting these increases were revised estimates of regulatory recoveries on EPNG and environmental liabilities on ANR. Other income for the year ended December 31, 1999, was $7 million higher than 1998. The increase was primarily an increase in 1999 interest income on a Destin Pipeline Company-related debt issuance during the latter part of 1998 and rental income on subleases of ANR's Detroit corporate offices. We were required to sell Destin as a result of our merger with Sonat. The increase was partially offset by lower equity earnings on Destin in 1999. MERCHANT ENERGY Merchant Energy is a market maker involved in a wide range of activities in the wholesale energy market place, including trading and risk management, asset ownership and financial services. Each of the markets served by Merchant Energy is highly competitive, and is influenced directly or indirectly by energy market economics. Prior to October 2000, Coastal conducted its marketing and trading activities through Engage Energy US, L.P. and Engage Canada, L.P., a joint venture between Coastal and Westcoast Energy Inc., a major Canadian natural gas company. During the fourth quarter 2000, Coastal terminated the Engage joint venture and commenced marketing and trading activities. Merchant Energy's trading and risk management activities provide sophisticated energy trading and energy management solutions for its customers and affiliates involving such energy commodities as natural gas, power, crude oil, refined products, chemicals and coal. Within its trading and risk management operations, Merchant Energy originates transactions with its customers to assist them with energy supply aggregation, storage and transportation management, as well as valuation and risk management. Merchant Energy maintains a substantial trading portfolio that balances its position risk across multiple commodities and over seasonally fluctuating energy demands. During 2000, U.S. energy supply and demand resulted in substantial volatility in the energy markets that significantly impacted Merchant Energy's earnings opportunities. This volatility is expected to continue for 2001, although not necessarily at the same levels we experienced in 2000. Merchant Energy is a provider of power and natural gas to the state of California. During the latter half of 2000, and continuing into 2001, California has experienced sharp increases in natural gas prices and wholesale power prices due to energy shortages resulting from the concurrence of a variety of circumstances, including unusually warm summer weather followed by high winter demand, low gas storage levels, poor hydroelectric power conditions, maintenance downtime of significant generation facilities, and price caps that discouraged power movement from other nearby states into California. The increase in power prices caused by the imbalance of natural gas and power supply and demand coupled with electricity price caps imposed on rates allowed to be charged to California electricity customers has resulted in large cash deficits to the two major California utilities, Southern California Edison and Pacific Gas and Electric. As a result, both utilities have defaulted on payments to creditors and have accumulated substantial under collections from customers, which has resulted in their credit ratings being downgraded in 2001 from above investment grade to below investment grade. The utilities filed for emergency rate increases with the California Public Utilities Commission and are working with the state authorities to restore the companies' financial viability. We have historically been one of the largest suppliers of energy to California and we are actively participating with all parties in California to be a part of the long-term, stabile solution to California's energy needs. As of March 2001, Merchant Energy believes its exposure for sales of power and gas 24 26 to the state of California, including receivables related to its interest in California power plant investments, is approximately $50 million, net of credit reserves to reflect market uncertainties. Merchant Energy's asset ownership activities include global power plants and refining operations, as well as power facilities owned and managed on behalf of Chaparral. Its asset-based businesses include 84 power plants in 20 countries. Merchant Energy is also actively involved in developing a global LNG operation. During 2000, Merchant Energy earned $80 million in fee based revenue from Chaparral and was reimbursed $20 million for operating expenses. We expect the 2001 fee based revenue to increase to approximately $147 million based on the growth in the Chaparral asset portfolio. In the financial services area, Merchant Energy owns EnCap and Enerplus, and conducts other energy financing activities. EnCap manages three separate oil and natural gas investment funds in the U.S., and serves as an investment advisor to one fund in Europe. EnCap also facilitates investment in emerging energy companies and earns a return from these investments. In 2000, Merchant Energy acquired Enerplus, a Canadian investment management company through which it conducts fund management activities similar to EnCap, but in Canada. Below are Merchant Energy's operating results and an analysis of those results for each of the three years ended December 31:
2000 1999 1998 ------- ------- ----- (IN MILLIONS) Trading, refining, and coal gross margin.................... $ 1,294 $ 950 $ 932 Operating and other revenues................................ 387 197 124 Operating expenses.......................................... (1,098) (1,112) (950) Other income................................................ 356 227 187 ------- ------- ----- EBIT...................................................... $ 939 $ 262 $ 293 ======= ======= =====
VOLUMES
2000 1999 1998 ------- ------- ------- (EXCLUDES INTRASEGMENT TRANSACTIONS) Physical Natural Gas (BBtue/d)................................... 10,357 6,713 7,089 ------- ------- ------- Power (MMWh)............................................ 115,836 79,858 55,575 ------- ------- ------- Crude oil and refined products (MBbls).................. 667,270 664,944 682,033 ------- ------- ------- Financial settlements (Bbtue/d)........................... 103,098 68,678 31,793 ------- ------- -------
YEAR ENDED DECEMBER 31, 2000 COMPARED TO YEAR ENDED DECEMBER 31, 1999 Trading, refining, and coal gross margin represents revenue from physical energy commodity sales less costs of these sales as well as results from financial trading activities. For the year ended December 31, 2000, trading, refining, and coal gross margin was $344 million higher than the same period in 1999. Commodity marketing and trading margins increased due to significant price volatility in natural gas and power markets which increased the value of our trading portfolio during 2000 versus 1999. Refining & chemical margins increased resulting from a 10 percent increase in sales volumes and increased prices on refined products in 2000. Also contributing to the increase was higher income from power transactions originated in 2000 versus 1999. These increases were partially offset by natural gas transactions originated in 1999. Operating and other revenues for the year end December 31, 2000, were $190 million higher than the same period in 1999. The increase was due to asset management fees earned from Chaparral, which began operations during the fourth quarter of 1999, revenues on the West Georgia power project, a seasonal peaking facility which began operating in June 2000, and the consolidation of a Brazilian power project in the latter part of 1999. Higher revenues due to higher electricity prices at our power generating facility in El Salvador, revenues on our Manchief power project, which began operating in July 2000, and Encap's financial services activities in 2000 also contributed to the increase. 25 27 Operating expenses for the year ended December 31, 2000, were $14 million lower than the same period in 1999. The decrease was due to reimbursements in 2000 of general and administrative costs relating to Chaparral, a 1999 charge to eliminate a minority investor in Sonat's marketing joint venture following the Sonat merger, and 1999 asset writedowns and charges to conform and consolidate accounting practices and policies with those of Sonat following the merger. These decreases were partially offset by higher general and administrative expenses and project development cost relating to international projects in 2000, by higher repairs and maintenance expense and fuel costs relating to increased volumes in our refining operations, higher rent and fuel costs relating to our power generating facility in El Salvador, higher depreciation expense relating to our Rensselaer generating facility, which was acquired in 1999, and operating costs on the Manchief generation facility. Other income for the year ended December 31, 2000, was $129 million higher than the same period in 1999. The increase was due to higher earnings from CE Generation, a power project acquired in March 1999, the benefit realized from the formation of our East Asia Power joint venture in March 2000, and a gain from the sale of our interest in a Guatemala power generation facility. Also contributing to the increase was increased earnings from Engage prior to the termination of the joint venture, and a gain recorded in 2000 from the sale of 49 percent of our Montreal petrochemical facility. These increases were partially offset by lower equity earnings from investments in various international projects, primarily our investment in East Asia Power in the Philippines. YEAR ENDED DECEMBER 31, 1999 COMPARED TO YEAR ENDED DECEMBER 31, 1998 Trading, refining, and coal gross margin for the year ended December 31, 1999, was $18 million higher than the same period in 1998. Commodity marketing and trading margins increased due to transactions originated in 1999 and revenues from consolidated power generation facilities acquired in December 1998. Refining and chemical margins decreased due to higher prices for raw materials and lower sales volumes in 1999. Operating and other revenues for the year ended December 31, 1999 were $73 million higher than the same period in 1998. The increase was primarily due to management fees earned from Chaparral, an increase in revenues from our Brazilian power projects consolidated during the latter part of 1999, and revenues from the Rensselaer power project, which was purchased in 1999. Operating expenses for the year ended December 31, 1999, were $162 million higher than the same period in 1998. The increase was due to higher operating costs associated with an increase in power activities, higher throughput at our refineries, increased coal volumes, operating expenses on consolidated power generation facilities acquired in December 1998, a charge to eliminate a minority investor in Sonat's marketing joint venture following the Sonat merger, and asset writedowns and charges to conform and consolidate accounting practices and policies with those of Sonat following the merger. Also contributing to the increase were higher general and administrative costs and higher operating costs from our Brazilian power projects consolidated during the latter part of 1999. The increases were partially offset by lower project development costs on international projects and revised estimates on environmental liabilities, both occurring in 1999. Other income for the year ended December 31, 1999, was $40 million higher than the same period in 1998. The increase was due to higher earnings from CE Generation and Engage, gains on the sale of non-jurisdictional assets in 1998, higher interest income, and 1999 equity swap gains recognized on our CAPSA project. These increases were partially offset by 1998 gains on the sale of project-related activities and surplus power equipment. FIELD SERVICES Field Services provides a variety of services for the midstream component of our operations, including gathering and treating of natural gas, processing and fractionation of natural gas, natural gas liquids and natural gas derivative products, such as butane, ethane, and propane. A subsidiary of Field Services also serves as the general partner of Energy Partners, a publicly traded master limited partnership. As the general partner, 26 28 Field Services earns a combination of management fees and partner distributions for services rendered to Energy Partners. Field Services attempts to balance its earnings from these activities through a combination of contractually based and market based services. The gathering and treating operations earn margins substantially from fee-based services. This means revenues are the product of a market price, usually related to the monthly natural gas price index and the volume gathered. During most of 2000, Field Services hedged a substantial amount of the risk associated with the changes in natural gas prices by entering into forward natural gas derivatives. Processing and fractionation operations earn a margin based on both fee-based contracts and make-whole contracts. Make-whole contracts allow us to retain the extracted liquid products and to return to the producer a Btu equivalent amount of natural gas. During periods when natural gas and liquid prices are volatile, Field Services may be at greater price risk under its make-whole contracts. Make-whole contracts constitute a greater portion of the operating contracts acquired in connection with our acquisition of PG&E's Texas Midstream operations in late December. Field Services' operating results and an analysis of those results is as follows for each of the three years ended December 31:
2000 1999 1998 ------- ------- ------- (IN MILLIONS) Gathering, treating and processing margin................. $ 440 $ 325 $ 290 Operating expenses........................................ (278) (254) (215) Other income.............................................. 51 59 94 ------- ------- ------- EBIT.................................................... $ 213 $ 130 $ 169 ======= ======= =======
YEAR ENDED DECEMBER 31, 2000 COMPARED TO YEAR ENDED DECEMBER 31, 1999 Gathering, treating and processing margin for the year ended December 31, 2000, was $115 million higher than the same period in 1999. Gathering and treating margins increased due to higher average gathering rates, predominantly in the San Juan Basin, which are substantially indexed to natural gas prices, and higher average condensate prices. Our higher 2000 margin was partially offset by the sale of El Paso Intrastate Alabama, a gathering system in the coal-bed methane producing regions of Alabama, to Energy Partners. Processing margins increased due to higher natural gas and natural gas liquids prices in 2000, the April 2000 acquisition of an interest in the Indian Basin processing assets, and higher processing volumes due to the acquisition of gas processing and fractionation facilities located in Louisiana at the end of 1999. Operating expenses for the year ended December 31, 2000, were $24 million higher than the same period in 1999 due to higher depreciation and amortization from assets transferred from EPNG to Field Services following a FERC order, the impairment of the Needle Mountain LNG processing facility in 2000, and higher expenses on Coastal's gas processing plants as a result of the acquisition of processing and fractionation assets located in Louisiana in 1999. The increase was partially offset by the impairment of gathering assets in 1999, lower costs for labor and benefits, and cost recoveries from managed facilities. Other income for the year ended December 31, 2000, was $8 million lower than the same period in 1999. The decrease was primarily due to net gains in 1999 from the sale of our interest in the Viosca Knoll gathering system to Energy Partners in June 1999, as well as lower equity earnings following the sale of our interest in Viosca Knoll. YEAR ENDED DECEMBER 31, 1999 COMPARED TO YEAR ENDED DECEMBER 31, 1998 Gathering, treating and processing margin for the year ended December 31, 1999, was $35 million higher than the same period in 1998. Gathering and treating margins increased due to higher volumes and average gathering rates, which are substantially indexed to natural gas prices, partially offset by the elimination of margins on assets in the Anadarko Basin that were sold in September 1998. Processing margins decreased due to lower liquids prices and the sale of two processing facilities in 1999. 27 29 Operating expenses for the year ended December 31, 1999, were $39 million higher than the same period in 1998. The increase was due to the impairment of gathering assets in the fourth quarter of 1999, and an increase in depreciation and amortization resulting from acquisitions. Other income for the year ended December 31, 1999, was $35 million lower than the same period in 1998. The decrease is primarily due to gains recorded on the sale of gathering and processing facilities in 1998. The decrease was partially offset by higher earnings from investments, primarily Energy Partners, as well as a gain recorded in 1999 from the sale of our interest in Viosca Knoll. PRODUCTION Production's operating results are driven by a variety of factors including its ability to locate and develop economic reserves, extract those reserves with minimal production costs, sell the products at attractive commodity prices, and operate at the lowest cost level possible. Over the past few years, Production has been successful in replacing its production with new, relatively low cost reserves. In addition, Production has also been successful in efficiently extracting its reserves and maintaining a low overall cost structure. In 1998, Production restructured its business in response to depressed market conditions and did so again in 1999 following the Sonat merger. Both of these efforts were successful in reducing overhead and administrative costs. Production engages in hedging activities on its natural gas and oil production in order to stabilize cash flows and reduce the risk of downward commodity price movements on sales of its production. This is achieved through natural gas and oil swaps. Typically, a higher percentage of production is hedged in the current year and then decreases each year thereafter. Production's hedged position is closely monitored and evaluated in an effort to achieve its earnings objective and reduce the risks associated with spot-market price volatility. In 2000, realized prices for natural gas and oil sales were lower than those that could have been realized had the production been sold at spot-market prices. However, this hedging strategy produced a relatively stable revenue stream that resulted in expected rates of return. For 2001, we anticipate hedging approximately 75 percent of our combined production. Below are the operating results and analysis of these results for December 31:
2000 1999 1998 ------ ------- ------- (IN MILLIONS) Natural gas................................................. $1,357 $ 889 $ 812 Oil, condensate and liquids................................. 253 164 167 Other....................................................... 19 11 5 ------ ------- ------- Total operating revenues.......................... 1,629 1,064 984 Operating expenses.......................................... (995) (1,148) (1,843) Other income (loss)......................................... (25) (1) 25 ------ ------- ------- EBIT...................................................... $ 609 $ (85) $ (834) ====== ======= ======= Volumes and prices Natural gas Volumes (Bcf).......................................... 517 416 411 ====== ======= ======= Average realized prices ($/Mcf)........................ $ 2.61 $ 2.11 $ 1.98 ====== ======= ======= Oil, condensate, and liquids Volumes (MMBbls)....................................... 12 10 14 ====== ======= ======= Average realized prices ($/Bbl)........................ $21.82 $ 15.03 $ 12.29 ====== ======= =======
28 30 YEAR ENDED DECEMBER 31, 2000 COMPARED TO YEAR ENDED DECEMBER 31, 1999 Operating revenues for the year ended December 31, 2000, were $565 million higher than in 1999. The increase was due to increased volumes and higher realized prices for natural gas and oil, condensate and liquids. Operating expenses for the year ended December 31, 2000, were $153 million lower than in 1999. The decrease was due to full cost ceiling test charges incurred in the first quarter of 1999, decreased 2000 labor costs as a result of an organizational restructuring following our Sonat merger, and 1999 charges to retain Sonat's seismic data in our production operations as a result of the merger. These decreases were partially offset by higher depletion rates in 2000, higher production taxes, and higher production costs. Other income for the year ended December 31, 2000 was $24 million lower than the same period in 1999. The decrease was primarily due to costs incurred to meet minimum production quantities under pipeline agreements. YEAR ENDED DECEMBER 31, 1999 COMPARED TO YEAR ENDED DECEMBER 31, 1998 Total operating revenues for the year ended December 31, 1999, were $80 million higher than 1998. The increase was primarily due to higher realized prices for natural gas, increased prices for crude oil, and a favorable contractual settlement in 1999, partially offset by the sales of properties during 1998. Operating expenses for the year ended December 31, 1999, were $695 million lower than 1998 primarily due to lower full cost ceiling test charges in 1999 versus the charges incurred in 1998, and lower operating and maintenance expenses due to property dispositions in 1998. Also contributing to the decrease were efficiencies created from Production's 1998 reorganization of its operations. These decreases were partially offset by charges to retain Sonat's seismic data in our production operations as a result of the Sonat merger, and higher depletion from increased production volumes. Other income for the year ended December 31, 1999, was $26 million lower than 1998 due primarily to a net gain on the sale of non-operating assets during the third quarter of 1998. CORPORATE AND OTHER EXPENSES, NET YEAR ENDED DECEMBER 31, 2000 COMPARED TO YEAR ENDED DECEMBER 31, 1999 Corporate and other expenses for the year ended December 31, 2000, were $223 million lower than in 1999. The decrease was primarily due to costs related to our merger with Sonat incurred in 1999, partially offset by costs incurred in 2000 related to our merger with Coastal. Also offsetting the decrease were increased funding commitments to the El Paso Energy Foundation in 2000. We will incur additional merger-related costs in 2001 as a result of our merger with Coastal. YEAR ENDED DECEMBER 31, 1999 COMPARED TO YEAR ENDED DECEMBER 31, 1998 Corporate and other expenses for the year ended December 31, 1999, were $282 million higher than 1998 primarily due to charges in 1999 related to our merger with Sonat including the accelerated amortization of employee benefits; legal, accounting, and financial advisory costs; employee severance and retention costs; and incremental costs incurred in combining office facilities following the merger. This increase was partially offset by costs assumed in 1998 from the introduction of our power services activities and higher recurring equity compensation charges in 1998. INTEREST AND DEBT EXPENSE YEAR ENDED DECEMBER 31, 2000 COMPARED TO YEAR ENDED DECEMBER 31, 1999 Interest and debt expense for the year ended December 31, 2000, was $174 million higher than 1999 primarily due to increased borrowings under a combination of short-term and long-term programs to fund capital expenditures, acquisitions, and other investing activities, higher average interest rates in 2000, and 29 31 $46 million of increased interest expense on borrowings from Chaparral in 2000. This increase was partially offset by an increase in interest capitalized. YEAR ENDED DECEMBER 31, 1999 COMPARED TO YEAR ENDED DECEMBER 31, 1998 Interest and debt expense for the year ended December 31, 1999, was $94 million higher than 1998 primarily due to increased borrowings to fund capital expenditures, acquisitions, and other investing activities offset by higher interest capitalized in 1999 from higher project investment and development primarily in Production and Merchant Energy. MINORITY INTEREST YEAR ENDED DECEMBER 31, 2000 COMPARED TO YEAR ENDED DECEMBER 31, 1999 Minority interest for the year ended December 31, 2000, was $111 million higher than in 1999 primarily due to a full year of costs associated with the preferred interest in Trinity River Associates, L.L.C., formed in June 1999 and the return to limited partners related to a partnership created in December 1999. Also contributing to the increase were costs associated with a preferred interest in Clydesdale Associates, L.P. and distributions associated with preferred securities of El Paso Energy Capital Trust IV, both of which were formed in May 2000. YEAR ENDED DECEMBER 31, 1999 COMPARED TO YEAR ENDED DECEMBER 31, 1998 Minority interest for the year ended December 31, 1999, was $33 million higher than in 1998 as a result of costs associated with a preferred interest in Trinity River Associates, L.L.C. in 1999, coupled with a full year of dividends on preferred securities of El Paso Energy Capital Trust I issued in March 1998. INCOME TAX EXPENSE (BENEFIT) Income tax expense (benefit) for the years ended December 31, 2000, 1999, and 1998, was $538 million, $93 million, and $(3) million. These amounts resulted in effective tax rates of 30 percent, 27 percent, and (2) percent. Differences in our effective tax rates from the statutory tax rate of 35 percent were primarily a result of the following factors: - state income taxes; - earnings from unconsolidated equity investees where we anticipate receiving dividends; - foreign income, not taxed in the U.S., but taxed at foreign tax rates; - the utilization of deferred credits on loss carryovers; - the non-deductible portion of merger-related costs; - non-deductible dividends on preferred stock of subsidiaries; - non-conventional fuel tax credits; and - depreciation, depletion, and amortization. For a reconciliation of the statutory rate of 35 percent to the effective rates in each of the three years ended December 31, 2000, see the Supplemental Combined Financial Statements, Note 4. LIQUIDITY AND CAPITAL RESOURCES CASH FROM OPERATING ACTIVITIES Net cash provided by our operating activities was $99 million for the year ended December 31, 2000, compared to of $1,521 million for 1999. The decrease in cash provided by operations was primarily a result of cash used to expand our price risk management activities as well as higher trading receivables related to the substantial growth in our trading portfolio and higher prices in the energy commodity markets. We also had 30 32 higher interest payments in 2000 primarily related to higher long-term and short-term debt balances, and higher 2000 income tax payments. Partially offsetting these increases were higher payments in 1999 for merger-related costs and activities versus merger-related payments made in 2000 and higher cash generated in 2000 from our pipeline and production operations. In 2001, we expect to pay significant amounts related to our Coastal merger and expect cash demands from our expanded Merchant Energy activities to continue. Offsetting this should be higher cash generated from our expanded operations following our merger with Coastal. CASH FROM INVESTING ACTIVITIES Net cash used in our investing activities was $3.8 billion for the year ended December 31, 2000. Our investing activities principally consisted of additions to joint ventures and equity investments, including an increase in our Chaparral equity investment, the purchase of an additional 18.5% interest in an Argentine company, CAPSA, the purchase of an investment in a Korean power company, Korea Independent Energy Corporation (formerly Hanwha Energy Co., Ltd), and a note receivable from Quanta Investors, L.L.C., a company formed to hold telecommunications assets. Other investing activities in 2000 included the acquisitions of PG&E's Texas Midstream operations, Crystal Gas Storage, Inc., and Enerplus Global Management. We also purchased the All-American pipeline assets, an interest in the Indian Basin gas processing plant assets, and had expenditures for expansion and construction projects. Cash inflows from investment related activities included proceeds from the sales of our East Tennessee pipeline system, Sea Robin pipeline system, El Paso Intrastate-Alabama pipeline system, our one-third interest in the Destin pipeline system, and the West Georgia Generating Company. We also received the proceeds from the formation of our East Asia Power joint venture and the repayment of a note receivable by Chaparral. CASH FROM FINANCING ACTIVITIES Net cash provided by our financing activities was $3.9 billion for the year ended December 31, 2000. Cash provided from our financing activities included revolving credit borrowings, the issuance of long-term debt, the sale of an interest in Clydesdale Associates, L.P., the issuance of preferred securities of El Paso Energy Capital Trust IV, and notes payable to Chaparral. During 2000, we repaid short-term borrowings, paid dividends, and retired long-term debt. See the Supplemental Combined Financial Statements, Note 9. LIQUIDITY We rely on cash generated from internal operations as our primary source of liquidity, supplemented by our available credit facilities and commercial paper programs. The availability of borrowings under our credit agreements is subject to specified conditions, which we believe we currently meet. These conditions include compliance with the financial covenants and ratios required by our agreements, absence of default under these agreements, and continued accuracy of our representations and warranties (including the absence of any material adverse changes since the specified dates). We expect that future funding for working capital needs, capital expenditures, acquisitions, other investing activities, long-term debt retirements, payments of dividends and other financing expenditures will be provided by internally generated funds, commercial paper issuances, available capacity under existing credit facilities, and the issuance of new long-term debt, trust securities, or equity. For a discussion of our financing arrangements and activities, see the Supplemental Combined Financial Statements, Note 8. COMMITMENTS AND CONTINGENCIES See the Supplemental Combined Financial Statements, Note 10, for a discussion of our commitments and contingencies. At December 31, 2000, we had capital and investment commitments of $1.6 billion primarily relating to our production, pipeline, and international power activities. Our other planned capital and investment projects 31 33 are discretionary in nature, with no substantial capital commitments made in advance of the actual expenditures. NEW ACCOUNTING PRONOUNCEMENTS NOT YET ADOPTED See the Supplemental Combined Financial Statements, Note 1, for a discussion of new accounting pronouncements we have not yet adopted. 32 34 RISK FACTORS AND CAUTIONARY STATEMENT FOR PURPOSES OF THE "SAFE HARBOR" PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995 This report contains or incorporates by reference forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. Where any forward-looking statement includes a statement of the assumptions or bases underlying the forward-looking statement, we caution that, while we believe these assumptions or bases to be reasonable and to be made in good faith, assumed facts or bases almost always vary from the actual results, and differences between assumed facts or bases and actual results can be material, depending upon the circumstances. Where, in any forward-looking statement, we or our management express an expectation or belief as to future results, that expectation or belief is expressed in good faith and is believed to have a reasonable basis. We cannot assure you, however, that the statement of expectation or belief will result or be achieved or accomplished. The words "believe," "expect," "estimate," "anticipate" and similar expressions will generally identify forward-looking statements. With this in mind, you should consider the following important factors that could cause actual results to differ materially from those expressed in any forward-looking statement made by us or on our behalf: WE OPERATE IN HIGHLY COMPETITIVE INDUSTRIES. Most of the natural gas and natural gas liquids we transport, gather, process, and store are owned by third parties. As a result, the volume of natural gas and natural gas liquids involved in these activities depends on the actions of those third parties, and is beyond our control. Further, the following factors, most of which are beyond our control, may unfavorably impact our ability to maintain or increase current transmission, storage, gathering, processing, and sales volumes and rates, to renegotiate existing contracts as they expire or to remarket unsubscribed capacity: - future weather conditions, including those that favor hydroelectric generation or other alternative energy sources; - price competition; - drilling activity and supply availability; - expiration of significant contracts; and - service area competition, especially due to current excess pipeline capacity into California and the Midwest. If we are unable to compete with services offered by other energy enterprises which may be larger, offer more services, and possess greater resources, our future profitability may be negatively impacted. THE REVENUES OF OUR PIPELINE BUSINESSES ARE GENERATED UNDER CONTRACTS THAT MUST BE RENEGOTIATED PERIODICALLY. Substantially all of our pipeline subsidiaries' revenues are generated under natural gas transportation contracts which expire periodically and must be renegotiated and extended or replaced. Although we actively pursue the renegotiation, extension and/or replacement of these contracts, we cannot assure you that we will be able to extend or replace these contracts when they expire or that the terms of any renegotiated contracts will be as favorable as the existing contracts. In particular, our ability to extend and/or replace transportation contracts could be harmed by factors we cannot control, including: - the proposed construction by other companies of additional pipeline capacity in markets served by our interstate pipelines; - changes in state regulation of local distribution companies, which may cause them to negotiate short-term contracts; - reduced demand due to higher natural gas prices; 33 35 - the availability of alternative energy sources or supply points; and - the viability of our expansion projects. If we are unable to renew, extend or replace these contracts or if we renew them on less favorable terms, we may suffer a material reduction in our revenues and earnings. FLUCTUATIONS IN ENERGY COMMODITY PRICES COULD ADVERSELY AFFECT OUR BUSINESS. If natural gas prices in the supply basins connected to our pipeline systems are higher than prices in other natural gas producing regions, especially Canada, our ability to compete with other transporters may be negatively impacted. Revenues generated by our gathering and processing contracts depend on volumes and rates, both of which can be affected by the prices of natural gas and natural gas liquids. The success of our gathering and processing operations in the offshore Gulf of Mexico is subject to continued development of additional oil and natural gas reserves in the vicinity of our facilities and our ability to access additional reserves to offset the natural decline from existing wells connected to our systems. A decline in energy prices could precipitate a decrease in these development activities and could cause a decrease in the volume of reserves available for gathering and processing through our offshore facilities. Fluctuations in energy prices, which may impact gathering rates and investments by third parties in the development of new oil and natural gas reserves connected to our gathering and processing facilities, are caused by a number of factors, including: - regional, domestic, and international supply and demand; - availability and adequacy of transportation facilities; - energy legislation; - federal and state taxes, if any, on the sale or transportation of natural gas and natural gas liquids; and - abundance of supplies of alternative energy sources. If there are reductions in the average volume of the natural gas and natural gas liquids we transport, gather and process for a prolonged period, our results of operations and financial position could be significantly, negatively affected. THE RATES WE ARE ABLE TO CHARGE OUR CUSTOMERS MAY BE REDUCED BY GOVERNMENTAL AUTHORITIES. Our pipeline businesses are regulated by the FERC and various state and local regulatory agencies. In particular, the FERC generally limits the rates we are permitted to charge our customers for interstate natural gas transportation and, in some cases, sales of natural gas. If the rates we are permitted to charge our customers for use of our regulated pipelines are lowered, the profitability of our pipeline businesses may be reduced. THE SUCCESS OF OUR OIL AND NATURAL GAS EXPLORATION AND PRODUCTION BUSINESSES IS DEPENDENT ON FACTORS WHICH CANNOT BE PREDICTED WITH CERTAINTY. The performance of our exploration and production businesses is dependent upon a number of factors that we cannot control. These factors include: - fluctuations in crude oil and natural gas prices; - the results of future drilling activity; - our ability to identify and precisely locate prospective geologic structures and to drill and successfully complete wells in those structures in a timely manner; - our ability to expand our leased land positions in desirable areas, which often are subject to intensely competitive leasing conditions; 34 36 - risks incident to operations of natural gas and oil wells; and - future drilling, production and development costs, including drilling rig rates. ESTIMATES OF OIL AND NATURAL GAS RESERVES MAY CHANGE. Actual production, revenues, taxes, development expenditures and operating expenses with respect to our reserves will likely vary from our estimates of proved reserves of oil and natural gas, and those variances may be material. The process of estimating oil and natural gas reserves is complex, requiring significant decisions and assumptions in the evaluation of available geological, geophysical, engineering, and economic data for each reservoir or deposit. As a result, these estimates are inherently imprecise. Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves may vary substantially from our estimates. In addition, we may be required to revise the reserve information, downward or upward, based upon production history, results of future exploration and development, prevailing oil and natural gas prices and other factors, many of which will be beyond our control. THE SUCCESS OF OUR POWER GENERATION AND MARKETING ACTIVITIES DEPENDS ON MANY FACTORS, SOME OF WHICH MAY BE BEYOND OUR CONTROL. The success of our international and domestic power projects and power marketing activities, and the amount of the related performance-based management fee paid to us in connection with the Electron financing structure, could be adversely affected by factors beyond our control, including: - alternative sources and supplies of energy becoming available due to new technologies and interest in self generation and cogeneration; - uncertain regulatory conditions resulting from the ongoing deregulation of the electric industry in the United States and in foreign jurisdictions; - our ability to negotiate successfully and enter into, restructure or recontract advantageous long-term power purchase agreements; - the possibility of a reduction in the projected rate of growth in electricity usage as a result of factors such as regional economic conditions and the implementation of conservation programs; - the inability of customers to pay amounts owed under power purchase agreements; and - the increasing price volatility due to deregulation and changes in commodity trading practices. OUR TELECOMMUNICATIONS BUSINESS STRATEGY MAY NOT BE SUCCESSFUL. Our experience in the telecommunications industry is limited, and we cannot assure you that our telecommunications strategy will be successful. Our success depends in part on the evolution of telecommunications as a commodity and our ability to integrate and adapt our facilities and services to keep pace with advances in communications technologies and the new and improved devices and services that result from these changes. In addition, the market for fiber optic capacity and telecommunications services is rapidly evolving, and although we expect demand for these services to grow, we cannot assure you that this growth will occur. Additionally, the price of fiber optic capacity is expected to continue to decline sharply because of the increase in newly installed fiber optic capacity coming on the market and rapid fiber optic equipment technology improvements. Further, a variety of critical issues, including security, reliability, ease and cost of access, creation of a liquid trading market, uncertain governmental regulation, and quality of service remain unresolved and may adversely affect our business. We cannot assure you, therefore, that our telecommunications strategy will be successful. 35 37 WE CANNOT ASSURE YOU THAT WE AND COASTAL WILL BE SUCCESSFULLY COMBINED INTO A SINGLE ENTITY. If we cannot successfully combine our operations with Coastal, we may experience a material adverse effect on our business, financial condition, or results of operations. Our merger with Coastal involves combining two companies that have previously operated separately. The combining of our companies involves a number of risks, including: - the diversion of management's attention to the combining of operations; - difficulties in combining operations and systems; - difficulties in assimilating and retaining employees; - challenges in keeping customers; and - potential adverse short-term effects on operating results and financial position. Among the factors considered by the board of directors of each company in approving the merger agreement were the opportunities for economies of scale and scope, opportunities for growth and operating efficiencies that could result from the merger. Although we expect our combined company to achieve significant annual savings in operating costs as a result of the merger, we may not be able to maintain the levels of operating efficiency that we each previously achieved or might achieve if we remain separate. Because of difficulties in combining operations, we may not be able to achieve the cost savings and other size-related benefits that we hope to achieve after the merger. OUR USE OF DERIVATIVE FINANCIAL INSTRUMENTS COULD RESULT IN FINANCIAL LOSSES. Some of our non-regulated subsidiaries use futures and option contracts traded on the New York Mercantile Exchange, over-the-counter options and price and basis swaps with other natural gas merchants and financial institutions. These instruments are intended to reduce our exposure to short-term volatility in changes in energy commodity prices. We could, however, incur financial losses in the future as a result of volatility in the market values of the underlying commodities, or if one of our counterparties fails to perform under a contract. Furthermore, because the valuation of these financial instruments can involve estimates, changes in the assumptions underlying these estimates can occur, changing our valuation of these instruments and potentially resulting in financial losses. For additional information concerning our derivative financial instruments, see Quantitative and Qualitative Disclosures About Market Risks beginning on page 39, and Supplemental Combined Financial Statements, Note 6. ATTRACTIVE ACQUISITION AND INVESTMENT OPPORTUNITIES MAY NOT BE AVAILABLE. Our ability to grow will depend, in part, upon our ability to identify and complete attractive acquisition and investment opportunities. Opportunities for growth through acquisitions and investments in joint ventures, and the future operating results and success of these acquisitions and joint ventures within and outside the United States may be subject to the effects of, and changes in, United States and foreign: - trade and monetary policies; - laws and regulations; - political and economic developments; - inflation rates; - taxes; and - operating conditions. 36 38 OUR FOREIGN INVESTMENTS INVOLVE SPECIAL RISKS. Our activities in areas outside the U.S. are subject to the risks inherent in foreign operations, including: - loss of revenue, property and equipment as a result of hazards such as expropriation, nationalization, wars, insurrection and other political risk; - the effects of currency fluctuations and exchange controls, such as devaluations of foreign currencies and other economic problems; and - changes in laws, regulations, and policies of foreign governments, including those associated with changes in the governing parties. COSTS OF ENVIRONMENTAL LIABILITIES, REGULATIONS AND LITIGATION COULD EXCEED OUR ESTIMATES. Our current and former operations involve management of regulated materials and are subject to various environmental laws and regulations. These laws and regulations obligate us to clean up various sites at which petroleum, chemicals, low-level radioactive substances or other regulated materials may have been disposed of or released. Some of these sites have been designated Superfund sites by the EPA under the Comprehensive Environmental Response, Compensation and Liability Act. We are also party to legal proceedings involving environmental matters pending in various courts and agencies. It is not possible for us to estimate reliably the amount and timing of all future expenditures related to environmental matters because of: - the difficulty of estimating clean up costs; - the uncertainty in quantifying liability under environmental laws that impose joint and several liability on all potentially responsible parties; - the nature of environmental laws and regulations; and - the possible introduction of future environmental laws and regulations. Although we believe we have established appropriate reserves for liabilities, including clean up costs, we could be required to set aside additional reserves in the future due to these uncertainties. For additional information concerning our environmental matters, see Supplemental Combined Financial Statements, Note 10. OUR OPERATIONS ARE SUBJECT TO OPERATIONAL HAZARDS AND UNINSURED RISKS. Our exploration, production, transportation, gathering, refining and processing operations are subject to the inherent risks normally associated with those operations, including explosions, pollution, release of toxic substances, fires and other hazards, each of which could result in damage to or destruction of our facilities or damage to persons and property. If any of these events were to occur, we could suffer substantial losses. While we maintain insurance against these types of risks to the extent and in amounts that we believe are reasonable, our financial condition and operations could be adversely affected if a significant event occurs that is not fully covered by insurance. THERE REMAIN POTENTIAL LIABILITIES RELATED TO THE ACQUISITION OF EL PASO TENNESSEE PIPELINE CO. The amount of the actual and contingent liabilities we assumed in our merger with El Paso Tennessee in 1996 could vary substantially from the amounts we estimated, which were based upon assumptions which could prove to be inaccurate. If new Tenneco Inc. or Newport News Shipbuilding Inc. (organizations created and distributed to Tenneco Inc. shareholders prior to our acquisition of Tenneco Inc.'s energy businesses in December 1996) were unable or unwilling to pay their respective liabilities, a court could require us, under legal theories which may or may not be applicable to the situation, to assume responsibility for those 37 39 obligations. If we were required to assume these obligations, it could have a material adverse effect on our financial condition, results of operations, or cash flows. THERE REMAIN POTENTIAL FEDERAL INCOME TAX LIABILITIES RELATED TO THE ACQUISITION OF EL PASO TENNESSEE PIPELINE CO. In connection with our acquisition of El Paso Tennessee and the distributions made by El Paso Tennessee prior to its acquisition, the IRS issued a private letter ruling to old Tenneco Inc. (now known as El Paso Tennessee), in which it ruled that for United States federal income tax purposes the distributions would be tax-free to old Tenneco Inc. and, except to the extent cash was received in lieu of fractional shares, to its then existing stockholders; the merger would constitute a tax-free reorganization; and that other transactions effected in connection with the merger and distribution would be tax-free. If the distributions were not to qualify as tax-free, then a corporate level federal income tax would be assessed to the consolidated group of which old Tenneco Inc. was the common parent. This corporate level federal income tax would be payable by El Paso Tennessee. Under limited circumstances, however, new Tenneco Inc. and Newport News Shipbuilding Inc. have agreed to indemnify El Paso Tennessee for a defined portion of such tax liabilities. WE ARE SUBJECT TO FINANCING AND INTEREST RATE EXPOSURE RISKS. Our business and operating results can be harmed by factors such as the availability or cost of capital, changes in interest rates, changes in the tax rates due to new tax laws, changes in the structured finance market, market perceptions of us or the natural gas and energy industry, or our credit ratings. WE ARE SUBJECT TO FOREIGN CURRENCY EXCHANGE RISK. Fluctuations in the value of the dollar as it rises and falls daily on foreign currency exchanges can have a negative effect on our businesses and operating results. 38 40 QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK We utilize derivative financial instruments to manage market risks associated with energy commodities and interest and foreign currency exchange rates. Our market risks will continue to be monitored by our corporate risk management committee that operates independently from our business segments that create or actively manage these risk exposures to ensure compliance with our overall stated risk management policies as approved by our Board of Directors. Prior to the merger, Coastal managed their market risk exposures, operating under resolutions adopted by their Board of Directors. TRADING COMMODITY PRICE RISK We are exposed to market risks inherent in the financial instruments we use for trading energy and energy related commodities. We record our energy trading activities, including transportation capacity and storage at fair value. Changes in fair value are reflected in our income statement. Our policy is to manage commodity price risks through a variety of financial instruments, including: - exchange-traded futures contracts involving cash settlements; - forward contracts involving cash settlements or physical delivery of an energy commodity; - swap contracts which require payment to (or receipts from) counterparties based on the difference between fixed and variable prices for the commodity; - exchange-traded and over-the-counter options; and - other contractual arrangements. We will continue to manage its market risk, subject to parameters established by our corporate risk management committee. Comprehensive risk management processes, policies, and procedures have been established to monitor and control its market risk. Our risk management committee also continually reviews these policies to ensure they are responsive to changing business conditions. Prior to the merger, Coastal managed its trading commodity risk exposures based on directives from their Board of Directors. We measure the risk in our commodity and energy related contracts on a daily basis utilizing a Value-at-Risk model to determine the maximum potential one-day unfavorable impact on its earnings, due to normal market movements, and monitors its risk in comparison to established thresholds. The Value-at-Risk computations capture a significant portion of the exposure related to option positions, and utilize historical price movements over a specified period to project future price movements in the energy markets. We also utilize other measures to provide additional assurance that the risks in our commodity and energy related contracts are being properly monitored on a daily basis, including sensitivity analysis, position limit control and credit risk management. Based on a confidence level of 95 percent and a one-day holding period, our combined estimated potential one-day unfavorable impact on income before income taxes and minority interest, as measured by Value-at-Risk, related to contracts held for trading purposes was approximately $20 million, $3 million and $3 million at December 31, 2000, 1999, and 1998. The increase in Value-at-Risk during 2000 reflects the significant increase in our commodity trading activities during the period. In 2000, our combined highest, lowest, and average estimated potential one day unfavorable impact on income before taxes and minority interest, as measured by Value-at-Risk were $20 million, $2 million and $9 million. In the fourth quarter of 2000, Merchant Energy also began managing asset based commodity transactions under the same Value-at-Risk methodology utilized for trading purposes. The potential one-day unfavorable impact on income before income taxes and minority interest related to these asset based commodity transactions as measured by Value-at-Risk was $10 million at December 31, 2000. In 2000, the highest, lowest and average estimated one-day unfavorable impact on income before income taxes and minority interest for the asset based commodity transactions, as measured by Value-at-Risk, were $10 million, $5 million, and $8 million. The average values represent our average of the 2000 month end values including month end values for the periods where Coastal Merchant Energy was consolidated in Coastal's operations. The high and low valuations 39 41 represent the highest and lowest month end values during 2000. Actual losses could exceed those measured by Value-at-Risk. NON-TRADING COMMODITY PRICE RISK We mitigate market risk associated with significant physical transactions, including natural gas, crude oil, refined products, and natural gas liquids production, through the use of non-trading financial instruments, including forward contracts and swaps. We will continue to hedge a portion of the commodity risk in our Production and Field Services segments by entering into derivative financial instruments. We believe that our combined estimated potential one-day unfavorable impact on income before income taxes and minority interest, as measured by Value-at-Risk, related to our non-trading commodity instruments was insignificant at December 31, 2000, 1999, and 1998. INTEREST RATE RISK Many of our debt related financial instruments and project financing arrangements are sensitive to market fluctuations in interest rates. We mitigate exposure to interest rate risk through the use of non-trading derivative financial instruments, including interest rate and equity swaps. At December 31, 2000, we maintained an interest rate swap with a notional amount of $12 million. Under this swap, we will pay a counterparty interest at a fixed rate of 6.83 percent and will receive LIBOR or other market rates. At December 31, 2000, the rate at which we will receive interest was 6.485 percent. In August 1999, we entered an interest rate swap agreement on a notional amount of $600 million with a termination date of July 2001. We swapped the fixed interest rate on our $600 million aggregate principal Senior Notes due 2001 for a floating 3 month LIBOR plus 0.1475 percent. We accounted for this transaction using accrual accounting. In November 2000, we terminated the swap. The termination of this swap did not materially impact our financial statements. In March 1997, we purchased a 10.5 percent interest in CAPSA for approximately $57 million and entered into an equity swap for an additional 18.5 percent ownership interest. Under the equity swap, we paid interest to a counterparty, on a quarterly basis, on a notional amount of $100 million at a rate of LIBOR plus 0.85 percent. In exchange, we received 18.5 percent of CAPSA's dividends. In February 1999, we extended the term of the swap and modified the notional amount to $103 million at a rate of LIBOR plus 1.75 percent. In May 2000, we exercised our right to terminate the swap and purchased the counterparty's 18.5 percent ownership interest in CAPSA for approximately $127 million. During the term of this swap, we reflected changes in market value of the equity swap in our income statement. The termination of the swap did not materially impact our financial statements. 40 42 The table below shows cash flows and related weighted average interest rates of our interest bearing securities, by expected maturity dates. As of December 31, 2000, the carrying amounts of short-term borrowings are representative of fair values because of the short-term maturity of these instruments. The fair value of the long-term debt has been estimated based on quoted market prices for the same or similar issues.
DECEMBER 31, 2000 DECEMBER 31, 1999 ---------------------------------------------------------------------- --------------------- EXPECTED FISCAL YEAR OF MATURITY OF CARRYING AMOUNTS ---------------------------------------------------------------------- CARRYING 2001 2002 2003 2004 2005 THEREAFTER TOTAL FAIR VALUE AMOUNTS FAIR VALUE ------ ---- ---- ---- ---- ---------- ------- ---------- -------- ---------- (DOLLARS IN MILLIONS) LIABILITIES: Short-term debt -- variable rate........................... $2,224 $ -- $ -- $ -- $ -- $ -- $ 2,224 $ 2,224 $1,357 $ 1,357 Average interest rate...... 6.2% Long-term debt, including current portion -- variable rate....... $ 60 $568 $212 $ 12 $112 $ 79 $ 1,043 $ 1,062 $ 854 $ 848 Average interest rate...... 6.1% 7.2% 7.4% 7.9% 10.1% 7.0% Long-term debt, including current portion -- fixed rate.......... $1,119 $774 $343 $765 $547 $7,490 $11,038 $11,211 $9,421 $ 9,263 Average interest rate...... 7.9% 8.3% 8.1% 7.0% 8.3% 7.6% Notes payable to unconsolidated affiliates -- variable rate.... $ 325 $ -- $ -- $ -- $ -- $ 174 $ 499 $ 499 $ 122 $ 122 Average interest rate...... 7.3% 10.9% Notes payable to unconsolidated affiliates -- fixed rate....... $ 84 $ 90 $ 51 $ 10 $ 12 $ 6 $ 253 $ 276 $ -- $ -- Average interest rate...... 7.4% 7.4% 7.4% 7.4% 7.4% 7.4% COMPANY-OBLIGATED PREFERRED SECURITIES: El Paso Energy Capital Trust I... $ -- $ -- $ -- $ -- $ -- $ 325 $ 325 $ 579 $ 325 $ 327 Average fixed interest rate..................... 4.8% El Paso Energy Capital Trust IV............................. $ -- $ -- $300 $ -- $ -- $ -- $ 300 $ 300 $ -- $ -- Average variable interest rate..................... 6.2% Coastal Finance I................ $ -- $ -- $ -- $ -- $ -- $ 300 $ 300 $ 293 $ 300 $ 276 Average fixed interest rate..................... 8.4%
FOREIGN CURRENCY EXCHANGE RATE RISK We manage our exposure to changes in foreign currency exchange rates by entering into derivative financial instruments, principally foreign currency forward purchase and sale contracts. Our primary exposure relates to changes in foreign currency rates on of our Merchant Energy activities outside the U.S. not denominated or adjusted to U.S. dollars. The following table summarizes the notional amounts, average settlement rates, and fair value for foreign currency forward purchase and sale contracts as of December 31, 2000:
NOTIONAL AMOUNT FAIR VALUE IN FOREIGN AVERAGE IN CURRENCY SETTLEMENT U.S. DOLLARS (IN MILLIONS) RATES (IN MILLIONS) --------------- ---------- ------------- Canadian Dollars Purchase................................ 1,095 0.673 $(3) Sell.................................... 441 0.686 6 --- $ 3 ===
41 43 The following table summarizes foreign currency forward purchase and sale contracts by expected maturity dates along with annual anticipated cash flow impacts as of December 31, 2000:
EXPECTED MATURITY DATES ----------------------------------------------------- 2001 2002 2003 2004 2005 THEREAFTER TOTAL ---- ---- ---- ---- ---- ---------- ----- (IN MILLIONS) Canadian Dollars Purchase......................... $(1) $(2) $(1) $-- $-- $ 1 $(3) Sell............................. 3 2 1 -- -- -- 6 --- --- --- --- --- --- --- Net cash flow effect............. $ 2 $-- $-- $-- $-- $ 1 $ 3 === === === === === === ===
EQUITY PRICE RISK We hold various securities that expose us to price risk associated with equity securities markets. Through Merchant Energy's financial services unit, we manage and invest in private investment funds as well as privately placed securities of both privately and publicly held companies. We account for these investments using investment company accounting. As a result, these holdings are measured at their fair value with changes in fair value recorded in our income statement. The fair value of these investments are determined based on estimates of amounts that would be realized if these securities were sold. We also hold a variety of publicly traded marketable equity securities. Below are the fair values of these holdings at December 31, 2000 and 1999, as well as the impact of a ten percent increase or decrease in the underlying fair values of these securities for each period presented:
2000 1999 --------------------------------- --------------------------------- IMPACT OF IMPACT OF IMPACT OF IMPACT OF FAIR 10 PERCENT 10 PERCENT FAIR 10 PERCENT 10 PERCENT VALUE INCREASE DECREASE VALUE INCREASE DECREASE ----- ---------- ---------- ----- ---------- ---------- (IN MILLIONS) Investment funds................. $ 7 $1 $ (1) $ 4 $ -- $ -- Securities....................... 75 7 (7) 29 3 (3) --- -- ---- ---- ---- ---- Total............................ $82 $8 $ (8) $ 33 $ 3 $ (3) === == ==== ==== ==== ====
42 44 SUPPLEMENTAL COMBINED FINANCIAL STATEMENTS The supplemental financial statements that follow reflect the combined information of El Paso and Coastal. We merged with Coastal on January 29, 2001, and accounted for the merger as a pooling of interests. The following information is restated as though we had been combined for all periods presented. See a further discussion of this presentation in Note 1 to the Supplemental Combined Financial Statements. EL PASO CORPORATION SUPPLEMENTAL COMBINED STATEMENTS OF INCOME (IN MILLIONS, EXCEPT PER COMMON SHARE AMOUNTS)
YEAR ENDED DECEMBER 31, ----------------------------- 2000 1999 1998 ------- ------- ------- Operating revenues.......................................... $49,268 $27,332 $23,773 ------- ------- ------- Operating expenses Cost of natural gas and other products.................... 42,700 22,225 18,656 Operation and maintenance................................. 2,788 2,380 2,479 Merger-related costs and asset impairment charges......... 125 557 15 Ceiling test charges...................................... -- 352 1,035 Depreciation, depletion, and amortization................. 1,247 1,101 1,079 ------- ------- ------- 46,860 26,615 23,264 ------- ------- ------- Operating income............................................ 2,408 717 509 Other income................................................ 520 502 406 ------- ------- ------- Income before interest, income taxes, and other charges..... 2,928 1,219 915 ------- ------- ------- Interest and debt expense................................... 950 776 682 Minority interest........................................... 204 93 60 Income tax expense (benefit)................................ 538 93 (3) ------- ------- ------- 1,692 962 739 ------- ------- ------- Income from continuing operations........................... 1,236 257 176 ------- ------- ------- Discontinued operations, net of income taxes................ -- -- (38) ------- ------- ------- Income before extraordinary items and cumulative effect of accounting change......................................... 1,236 257 138 Extraordinary items, net of income taxes.................... 70 -- -- Cumulative effect of accounting change, net of income taxes..................................................... -- (13) -- ------- ------- ------- Net income before preferred stock dividends................. 1,306 244 138 Preferred stock dividends................................... -- -- 6 ------- ------- ------- Net income available to common stockholders................. $ 1,306 $ 244 $ 132 ======= ======= ======= Basic earnings per common share Income from continuing operations available to common stockholders............................................ $ 2.50 $ 0.52 $ 0.35 Discontinued operations, net of income taxes.............. -- -- (0.08) Extraordinary items, net of income taxes.................. 0.14 -- -- Cumulative effect of accounting change, net of income taxes................................................... -- (0.03) -- ------- ------- ------- Net income available to common stockholders............... $ 2.64 $ 0.49 $ 0.27 ======= ======= ======= Diluted earnings per common share Income from continuing operations available to common stockholders............................................ $ 2.43 $ 0.52 $ 0.34 Discontinued operations, net of income taxes.............. -- -- (0.08) Extraordinary items, net of income taxes.................. 0.14 -- -- Cumulative effect of accounting change, net of income taxes................................................... -- (0.03) -- ------- ------- ------- Net income available to common stockholders............... $ 2.57 $ 0.49 $ 0.26 ======= ======= ======= Basic average common shares outstanding..................... 494 490 487 ======= ======= ======= Diluted average common shares outstanding................... 513 497 495 ======= ======= =======
See accompanying notes. 43 45 EL PASO CORPORATION SUPPLEMENTAL COMBINED BALANCE SHEETS (IN MILLIONS, EXCEPT COMMON SHARE AMOUNTS)
DECEMBER 31, ------------------- 2000 1999 -------- -------- ASSETS Current assets Cash and cash equivalents................................. $ 741 $ 562 Accounts and notes receivable, net of allowance of $122 in 2000 and $50 in 1999................................... Customer............................................... 6,188 2,379 Unconsolidated affiliates.............................. 304 366 Other.................................................. 895 850 Inventory................................................. 1,034 807 Assets from price risk management activities.............. 4,825 233 Other..................................................... 832 641 -------- -------- Total current assets.............................. 14,819 5,838 -------- -------- Property, plant, and equipment, at cost Pipelines................................................. 14,090 14,094 Refining, crude oil and chemical facilities............... 2,606 2,555 Power facilities.......................................... 418 571 Gathering and processing systems.......................... 2,884 1,516 Natural gas and oil properties -- at full cost............ 11,032 9,247 Other..................................................... 929 787 Additional acquisition cost assigned to utility plant..... 5,262 5,511 -------- -------- 37,221 34,281 Less accumulated depreciation, depletion, and amortization.............................................. 14,924 14,679 -------- -------- Total property, plant, and equipment, net......... 22,297 19,602 -------- -------- Other assets Investments in unconsolidated affiliates.................. 4,454 3,612 Assets from price risk management activities.............. 1,776 413 Other..................................................... 2,668 2,325 -------- -------- 8,898 6,350 -------- -------- Total assets...................................... $ 46,014 $ 31,790 ======== ========
See accompanying notes. 44 46 EL PASO CORPORATION SUPPLEMENTAL COMBINED BALANCE SHEETS (IN MILLIONS, EXCEPT COMMON SHARE AMOUNTS)
DECEMBER 31, ----------------- 2000 1999 ------- ------- LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities Accounts and notes payable Trade.................................................. $ 5,114 $ 2,799 Unconsolidated affiliates.............................. 409 122 Other.................................................. 1,998 1,059 Short-term borrowings (including current maturities of long-term debt)........................................ 3,403 1,611 Liabilities from price risk management activities......... 3,427 197 Other..................................................... 1,324 953 ------- ------- Total current liabilities......................... 15,675 6,741 ------- ------- Debt Long-term debt, less current maturities................... 10,902 10,021 Noncurrent notes payable to unconsolidated affiliates..... 343 -- ------- ------- 11,245 10,021 ------- ------- Deferred credits and other Liabilities from price risk management activities......... 1,011 95 Deferred income taxes..................................... 4,106 3,551 Noncurrent deferred credits............................... 1,451 1,470 Other..................................................... 700 584 ------- ------- 7,268 5,700 ------- ------- Commitments and contingencies Securities of subsidiaries Company-obligated preferred securities of consolidated trusts................................................. 925 625 Minority interests........................................ 2,782 1,819 ------- ------- 3,707 2,444 ------- ------- Stockholders' equity Common stock, par value $3 per share; authorized 750,000,000 shares; issued 513,815,775 shares in 2000 and 506,744,165 shares in 1999......................... 1,541 1,520 Additional paid-in capital................................ 1,925 1,667 Retained earnings......................................... 5,235 4,172 Accumulated other comprehensive income.................... (57) (29) Treasury stock (at cost) 13,943,779 shares in 2000 and 14,354,584 shares in 1999.............................. (400) (405) Unamortized compensation.................................. (125) (41) ------- ------- Total stockholders' equity........................ 8,119 6,884 ------- ------- Total liabilities and stockholders' equity........ $46,014 $31,790 ======= =======
See accompanying notes. 45 47 EL PASO CORPORATION SUPPLEMENTAL COMBINED STATEMENTS OF CASH FLOWS (IN MILLIONS)
YEAR ENDED DECEMBER 31, ----------------------------- 2000 1999 1998 ------- ------- ------- Cash flows from operating activities Net income................................................ $ 1,306 $ 244 $ 138 Less loss from discontinued operations, net of income taxes................................................... -- -- (38) ------- ------- ------- Income from continuing operations......................... 1,306 244 176 Adjustments to reconcile net income to net cash from operating activities Depreciation, depletion, and amortization............... 1,247 1,101 1,079 Deferred income tax expense (benefit)................... 531 68 (42) Extraordinary items..................................... (120) -- -- Undistributed earnings in equity investees.............. (71) (91) (101) Ceiling test charges.................................... -- 352 1,035 Non-cash portion of merger-related costs and asset impairment charges................................... 11 380 -- Other................................................... (51) (35) (40) Working capital changes, net of non-cash transactions Accounts and notes receivable........................ (3,040) (1,080) 876 Inventories.......................................... (147) (115) 200 Change in price risk management activities, net...... (1,816) (204) (40) Accounts payable..................................... 2,148 710 (964) Other working capital changes........................ 101 87 98 Other................................................... -- 104 (101) ------- ------- ------- Net cash provided by operating activities.......... 99 1,521 2,176 ------- ------- ------- Cash flows from investing activities Purchases of property, plant, and equipment............... (3,448) (2,867) (2,541) Additions to investments.................................. (1,673) (1,211) (944) Cash paid for acquisitions, net of cash received.......... (524) (165) (373) Net proceeds from the sale of assets...................... 787 70 487 Proceeds from the sale of investments..................... 354 122 223 Change in cash deposited in escrow related to an equity investee................................................ 24 (101) -- Repayment (advances) of notes receivable from unconsolidated affiliates............................... 647 (262) -- Net proceeds from discontinued operations................. (1) (3) 9 ------- ------- ------- Net cash used in investing activities.............. (3,834) (4,417) (3,139) ------- ------- ------- Cash flows from financing activities Net borrowings (repayments) of commercial paper and short-term notes........................................ (39) 250 411 Revolving credit borrowings............................... 1,145 878 810 Revolving credit repayments............................... (715) (1,253) (1,017) Payments to retire long-term debt......................... (865) (830) (462) Net proceeds from the issuance of long-term debt.......... 2,619 2,872 1,123 Net proceeds from issuance of preferred securities of a consolidated trust...................................... 293 -- 617 Issuances (repurchases) of common stock................... 141 39 (14) Dividends paid............................................ (243) (238) (265) Increase in notes payable to unconsolidated affiliates.... 583 222 -- Redemption of preferred stock............................. -- -- (200) Net proceeds from issuance of minority interests in subsidiaries............................................ 995 1,310 -- Other..................................................... -- -- 2 ------- ------- ------- Net cash provided by financing activities.......... 3,914 3,250 1,005 ------- ------- ------- Increase in cash and cash equivalents....................... 179 354 42 Cash and cash equivalents Beginning of period....................................... 562 208 166 ------- ------- ------- End of period............................................. $ 741 $ 562 $ 208 ======= ======= =======
See accompanying notes. 46 48 EL PASO CORPORATION SUPPLEMENTAL COMBINED STATEMENTS OF STOCKHOLDERS' EQUITY (IN MILLIONS, EXCEPT PER COMMON SHARE AMOUNTS)
FOR THE YEARS ENDED DECEMBER 31, --------------------------------------------------- 2000 1999 1998 --------------- --------------- --------------- SHARES AMOUNT SHARES AMOUNT SHARES AMOUNT ------ ------ ------ ------ ------ ------ Preferred stock: Balance at beginning of year.............................. -- -- -- -- 8 3 Redeemed.................................................. -- -- -- -- (8) (3) --- ------ --- ------ --- ------ Balance at end of year.................................. -- -- -- -- -- -- --- ------ --- ------ --- ------ Common stock, $3.00 par: Balance at beginning of year.............................. 507 1,520 503 1,508 501 1,500 Compensation related issuances............................ 6 18 4 13 2 5 Other..................................................... 1 3 -- (1) -- 3 --- ------ --- ------ --- ------ Balance at end of year.................................. 514 1,541 507 1,520 503 1,508 --- ------ --- ------ --- ------ Additional paid-in capital: Balance at beginning of year.............................. 1,667 1,575 2,438 Compensation related issuances............................ 171 96 41 Tax benefit of equity plans............................... 60 19 14 Retirement of Sonat treasury shares....................... -- (61) -- Redemption of Series H preferred stock.................... -- -- (197) Conversion of Coastal Class A common stock................ (6) (3) (729) Other..................................................... 33 41 8 ------ ------ ------ Balance at end of year.................................. 1,925 1,667 1,575 ------ ------ ------ Retained earnings: Balance at beginning of year.............................. 4,172 4,189 4,318 Net income................................................ 1,306 244 138 Dividends ($0.824, $0.800, and $0.765 per share).......... (243) (261) (267) ------ ------ ------ Balance at end of year.................................. 5,235 4,172 4,189 ------ ------ ------ Accumulated other comprehensive income: Balance at beginning of year.............................. (29) (12) (4) Cumulative translation adjustment......................... (30) (12) (7) Other..................................................... 2 (5) (1) ------ ------ ------ Balance at end of year.................................. (57) (29) (12) ------ ------ ------ Treasury stock, at cost: Balance at beginning of year.............................. (14) (405) (10) (282) (9) (244) Stock purchases........................................... -- -- -- -- (1) (37) Compensation related issuances............................ -- 3 (5) (182) -- (1) Retirement of Sonat treasury shares....................... -- 2 1 59 -- -- --- ------ --- ------ --- ------ Balance at end of year.................................. (14) (400) (14) (405) (10) (282) --- ------ --- ------ --- ------ Unamortized compensation: Balance at beginning of year.............................. (41) (65) (81) Restricted stock activity, net............................ (84) (43) 16 Early vesting of equity plans............................. -- 67 -- ------ ------ ------ Balance at end of year.................................. (125) (41) (65) --- ------ --- ------ --- ------ Total stockholders' equity.................................. 500 $8,119 493 $6,884 493 $6,913 === ====== === ====== === ====== Comprehensive income........................................ $1,278 $ 227 $ 130 ====== ====== ======
See accompanying notes. 47 49 EL PASO CORPORATION NOTES TO SUPPLEMENTAL COMBINED FINANCIAL STATEMENTS 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Basis of Presentation On January 29, 2001, we completed our merger with Coastal, see Note 2. We accounted for our merger as a pooling of interests. These financial statements include our combined results of operations, financial position, and cash flows. These financial statements do not extend through the date of consummation; however, they will become our historical consolidated financial statements after financial statements covering the date of consummation of the business combination are issued. Our financial statements for previous periods include reclassifications that were made to conform to the current year presentation. Those reclassifications have no impact on reported net income or stockholders' equity. Principles of Combination Our combined financial statements include the accounts of all majority-owned, controlled subsidiaries after the elimination of all significant intercompany accounts and transactions. We account for investments in companies where we have the ability to exert significant influence, but not control, over operating and financial policies using the equity method. Use of Estimates The preparation of financial statements in conformity with generally accepted accounting principles requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, and expenses and disclosure of contingent assets and liabilities that exist at the date of the financial statements. Our actual results may differ from those estimates. Accounting for Regulated Operations Our interstate natural gas systems are subject to the jurisdiction of FERC in accordance with the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. Each system operates under separate FERC approved tariffs which establish rates, terms and conditions under which each system provides services to its customers. All of our regulated interstate systems, except ANR, CIG, and WIC follow the accounting requirements of Statement of Financial Accounting Standards (SFAS) No. 71, Accounting for the Effects of Certain Types of Regulation. This accounting differs from the accounting requirements of our non-regulated entities, as well as ANR, CIG, and WIC, who discontinued the application of SFAS No. 71 in 1996. Transactions that have been recorded differently as a result of the application of SFAS No. 71 include the capitalization of an equity return component on regulated capital projects, employee related benefits, and other costs and taxes included in, or expected to be included in, future rates, including costs to refinance debt. Cash and Cash Equivalents We consider short-term investments purchased with an original maturity of less than three months to be cash equivalents. Inventory Our inventory consists of refined products, crude oil and chemicals, materials and supplies, natural gas in storage for non-trading purposes, coal, and optic fiber being constructed for sale to, or exchange with, third parties. Inventories of refined products, crude oil, and chemicals are valued at the lower of cost or market with cost determined using the first-in, first-out cost method. We value coal, natural gas, materials and supplies, and optic fiber at the lower of cost or market with cost determined using the average cost method. 48 50 Property, Plant, and Equipment Our property, plant, and equipment is recorded at its original cost of construction or, upon acquisition, at either the fair value of the assets acquired or the cost to the entity that first placed the asset in service, whichever is applicable. We capitalize direct costs, like labor and materials, and indirect costs, like overhead, interest, and allowance for funds used during construction. We capitalize the major units of property replacements or improvements and expense the minor ones. Additional acquisition costs assigned to utility plant represents the excess of allocated purchase costs over historical costs of our regulated facilities. These costs are amortized on a straight-line basis using FERC approved rates and we do not recover these excess costs in our rates. For our regulated interstate systems, we use the composite (group) method to depreciate regulated property, plant, and equipment. Under this method, assets with similar lives and other characteristics are grouped and depreciated as one asset. We apply the depreciation rate, approved in our rates, to the total cost of the group, until its net book value equals its salvage value. Currently, our depreciation rates vary from 1 to 33 percent. These rates depreciate the related assets over 2 to 50 years. We re-evaluate depreciation rates each time we redevelop our transportation rates. For all other properties, we depreciate or deplete them over their estimated useful lives using a straight-line, unit of production, or composite method, whichever is applicable. The annual depreciation and depletion rates for these operations are as follows: Refining, crude oil and chemical facilities................. 3.0% to 20.0% Gathering and processing systems............................ 1.2% to 20.0% Coal facilities............................................. 5.0% to 33.3% Power facilities............................................ 2.0% to 33.3% Transportation equipment.................................... 2.5% to 33.3% Buildings and improvements.................................. 1.3% to 20.0% Office and miscellaneous equipment.......................... 3.0% to 33.3%
When we retire regulated property, plant, and equipment, we charge accumulated depreciation and amortization for the original cost, plus the cost of retirement (the cost to remove, sell, or dispose), less its salvage value. We do not recognize a gain or loss unless we sell an entire operating unit. We include gains or losses on dispositions of operating units in income. When we retire non-regulated properties, we reduce property, plant, and equipment for its original cost, less accumulated depreciation, and salvage. Any remaining amount is charged to income. At December 31, 2000 and 1999, we had approximately $1,224 million and $995 million construction work in progress included in our property, plant, and equipment. We evaluate impairment of our regulated and non-regulated property, plant, and equipment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable, in accordance with SFAS No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of. Natural Gas and Oil Properties We use the full cost method to account for our natural gas and oil properties. Under the full cost method, all productive and nonproductive costs incurred in connection with the acquisition, exploration, and development of natural gas and oil reserves are capitalized. These capitalized costs include the costs of all unproved properties, internal costs directly related to acquisition and exploration activities, and capitalized interest. We amortize these costs using a unit of production method over the life of our proved reserves. We exclude unevaluated properties from our amortization base, until we make a determination as to the existence of proved reserves. Our total capitalized costs are limited to a ceiling of the present value of future net revenues, discounted at 10 percent, plus the lower of cost or fair market value of unproved properties. If these 49 51 discounted revenues are not equal to or greater than total capitalized costs, we are required to write-down our capitalized costs to this level. In 1999 and 1998, we determined that capitalized costs exceeded the ceiling test limits by a total of $352 million and $1,035 million. These write-downs are included in our income statement as ceiling test charges. We treat the sale of natural gas and oil properties as an adjustment to cost of those properties. We do not recognize a gain or loss on these sales, unless the properties sold are significant. Planned Major Maintenance Repair and maintenance costs incurred in connection with planned major maintenance activities at various refineries or plants are accrued as a liability in a systematic and rational manner over the period of time until the planned major maintenance activities occur. Any difference between the accrued liability and the actual costs incurred in performing the maintenance activities are charged or credited to expense at the time the maintenance occurs. At various other refineries or plants, the cost of each major maintenance activity is capitalized and amortized to expense in a systematic and rational manner over the estimated period extending to the next planned major maintenance activity. Our accrual was $50 million and $33 million at December 31, 2000 and 1999. Intangible Assets Our intangible assets consist primarily of goodwill arising from purchase business combinations. We amortize our intangible assets using the straight-line method over periods ranging from five to 40 years. We evaluate impairment of goodwill and other intangible assets in accordance with SFAS No. 121. Under this methodology, when an event occurs to suggest that impairment may have occurred, we evaluate the undiscounted net cash flows of the underlying asset or entity. If these cash flows are not sufficient to recover the value of the underlying asset or entity plus the goodwill amount, these cash flows are discounted at a risk-adjusted rate with any difference recorded as a charge to our income statement. Revenue Recognition Our regulated businesses recognize revenues from natural gas transportation in the period the service is provided. Reserves are provided on revenues collected that may be subject to refund. Revenues on services other than transportation are recorded when they are earned. Our non-regulated businesses record revenues at various points when they are earned, including when deliveries of the physical commodities are made, or in the period services are provided. See the discussion of price risk management activities below for our revenue recognition policies on our trading activities. In the fourth quarter of 2000, we implemented Emerging Issues Task Force Issue No. 99-19, Reporting Revenue Gross as a Principal versus Net as an Agent, which provides guidance on the gross versus net presentation of revenues and expenses. As a result of adoption, revenues and related costs increased by $4 billion, $2 billion, and $2 billion for 2000, 1999, and 1998. These reclassifications primarily related to the manner in which Coastal historically accounted for its crude oil supply and refined products marketing activities and had no impact on net income or earnings per share. Environmental Costs Expenditures for ongoing compliance with environmental regulations that relate to current operations are expensed or capitalized as appropriate. We expense amounts that relate to existing conditions caused by past operations, and which do not contribute to current or future revenue generation. We record liabilities when environmental assessments indicate that remediation efforts are probable and the costs can be reasonably estimated. Estimates of our liabilities are based upon currently available facts, existing technology and presently enacted laws and regulations taking into consideration the likely effects of inflation and other societal and economic factors, and include estimates of associated legal costs. These amounts also consider prior experience in remediating contaminated sites, other companies' clean-up experience and data released by the 50 52 EPA or other organizations. They are subject to revision in future periods based on actual costs or new circumstances, and are included in our balance sheet at their undiscounted amounts. We evaluate recoveries separately from the liability and, when recovery is assured, we record and report an asset separately from the associated liability in our financial statements. Price Risk Management Activities We utilize derivative financial instruments to manage market risks associated with commodities we sell, interest rates, and foreign currency exchange rates. We engage in both trading and non-trading commodity price risk management activities. Our trading activities consist of services provided to the energy sector, primarily related to natural gas and power. Our energy trading activities, including transportation capacity and storage, are accounted for using the mark-to-market method of accounting. We conduct our trading activities through a variety of financial instruments, including: - exchange traded futures contracts involving cash settlement; - forward contracts involving cash settlement or physical delivery of a commodity; - swap contracts, which require us to make payments to (or receive payments from) counterparties based on the difference between fixed and variable prices for the commodity; - exchange-traded and over-the-counter options; and - other contractual arrangements. Under the mark-to-market method of accounting, commodity and energy related contracts are reflected at quoted or estimated market value with resulting gains and losses included in our income statement. Net gains or losses recognized in a period result primarily from the impact of price movements on transactions originating in that or previous periods. Assets and liabilities resulting from mark-to-market accounting are included in our balance sheets and are classified according to their term to maturity. We reflect receivables and payables that arise upon the actual settlement of these contracts separately from price risk management activities in our balance sheet as trade receivables or payables. Cash inflows and outflows associated with these price risk management activities are recognized in operating cash flows as transactions are settled. During the years ended December 31, 2000 and 1999, we recognized gross margins from our trading activities of $418 million and $91 million. The market value of commodity and energy related contracts reflects our best estimate, and considers factors including closing exchange and over-the-counter quotations, time value, and volatility factors underlying these contracts. The values are adjusted to reflect the potential impact of liquidating our position in an orderly manner over a reasonable period of time under present market conditions and to reflect other types of risks, including model risk, credit risk and operational risks. In the absence of quoted market prices, we utilize other valuation techniques to estimate fair value. The use of these techniques requires us to make estimations of future prices and other variables, including market volatility, price correlation, and market liquidity. Derivative and other financial instruments are also utilized in connection with non-trading activities. We enter into forwards, swaps, and other contracts to hedge the impact of market fluctuations on assets, liabilities, or other contractual commitments. Hedge accounting is applied only if the derivative reduces the risk of the underlying hedged item, is designated as a hedge at its inception, and is expected to result in financial impacts which are inversely correlated to those of the item being hedged. If correlation ceases to exist, hedge accounting is terminated and mark-to-market accounting is applied. Changes in the market value of hedged transactions are deferred until the gain or loss on the hedged item is recognized. Derivatives held for non-trading purposes are recorded as gains or losses in operating income and cash inflows and outflows are recognized in operating cash flow as the settlement of these transactions occurs. See Note 6 for a further discussion of our price risk management activities. 51 53 Income Taxes We report income taxes based on income reported on our tax returns along with a provision for deferred income taxes. Deferred income taxes reflect the estimated future tax consequences of differences between the financial statement and tax bases of assets and liabilities and carryovers at each year end. We account for tax credits under the flow-through method, which reduces the provision for income taxes in the year the tax credits first become available. We reduce deferred tax assets by a valuation allowance when, based upon our estimates, it is more likely than not that a portion of those assets will not be realized in a future period. The estimates utilized in the recognition of deferred tax assets are subject to revision in future periods based on new facts or circumstances. Currency Translation The U.S. dollar is the functional currency for substantially all of our foreign operations. For those operations, all gains and losses from currency translations are included in income currently. For foreign operations whose functional currency is deemed to be other than the U.S. dollar, translation adjustments are included as a separate component of comprehensive income and stockholders' equity. Currency transaction gains and losses are recorded in income. Comprehensive Income (Loss) Comprehensive income (loss) is determined based on net income (loss), adjusted for changes in accumulated other comprehensive income. Treasury Stock We account for treasury stock using the cost method and report it in our balance sheet as a reduction to stockholders' equity. Treasury stock sold or issued is valued on a first-in, first-out basis. Included in treasury stock at December 31, 2000, and 1999, were 1.36 million shares of common stock that were reserved for use under several of our benefit plans, as well as approximately 5.8 million shares of common stock which were placed in a trust under our deferred compensation programs. Stock-Based Compensation We apply the provisions of Accounting Principles Board Opinion No. 25 and its related interpretations in accounting for our stock compensation plans. Accordingly, compensation expense is not recognized for stock options unless the options were granted at an exercise price that is lower than the market price on the grant date. We use fixed and variable plan accounting for our fixed and variable compensation plans. Cumulative Effect of Accounting Change In April 1998, the American Institute of Certified Public Accountants issued Statement of Position 98-5, Reporting on the Costs of Start-Up Activities. The statement defined start-up activities and required start-up and organization costs be expensed as incurred. In addition, it required that any such cost that existed on the balance sheet be expensed upon adoption of the pronouncement. We adopted the pronouncement effective January 1, 1999, and reported a charge of $13 million, net of income taxes, as a cumulative effect of an accounting change. Accounting for Derivative Instruments and Hedging Activities In June of 1998, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) No. 133, Accounting for Derivative Instruments and Hedging Activities. In June of 1999, the FASB extended the adoption date of SFAS No. 133 through the issuance of SFAS No. 137, Deferral of the Effective Date of SFAS 133. In June 2000, the FASB issued SFAS No. 138, Accounting for Certain Derivative Instruments and Certain Hedging Activities, which also amended SFAS No. 133. SFAS No. 133, and its amendments and interpretations, establishes accounting and reporting standards for derivative 52 54 instruments, including derivative instruments embedded in other contracts, and derivative instruments used for hedging activities. It requires that we measure all derivative instruments at their fair value, and classify them as either assets or liabilities on our balance sheet, with a corresponding offset to income or other comprehensive income depending on their designation, their intended use, or their ability to qualify as hedges under the standard. We adopted SFAS No. 133 on January 1, 2001, and applied the standard to all derivative instruments that existed on that date, except for derivative instruments embedded in other contracts. As provided for in SFAS No. 133, we applied the provisions of the standard to derivative instruments embedded in other contracts issued, acquired, or substantially modified after December 31, 1998. We use a variety of derivative instruments to conduct both energy trading activities and to hedge risks associated with commodity prices, foreign currencies and interest rates. The derivative instruments we use in commodity trading activities are recorded at their fair value in our financial statements under the provisions of Emerging Issues Task Force Issue No. 98-10, Accounting for Contracts Involved in Energy Trading and Risk Management Activities. As a result, SFAS No. 133 did not impact our accounting for these instruments. Based on commodity prices, interest rates, and foreign currency exchange rates existing at December 31, 2000, we will reflect the impact of our adoption of SFAS No. 133 as of January 1, 2001, by recording a cumulative effect transition adjustment as a charge to other comprehensive income of $1,280 million, net of income taxes, an increase in net income of $3 million, an increase of assets of $301 million, and an increase in liabilities of $1,578 million. This charge to other comprehensive income represents the fair value of our derivative instruments designated as cash flow hedges. The majority of the initial charge relates to the hedging of the forecasted sales of natural gas we expect to produce through the end of 2001. Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities In September 2000, the FASB issued SFAS No. 140, Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities, which replaces SFAS No. 125. This statement revises the standards for accounting for securitizations and other transfers of financial assets and collateral and requires certain disclosures, but carries over most of SFAS No. 125's provisions without reconsideration. This standard has various effective dates, the earliest of which is for fiscal years ending after December 15, 2000. This pronouncement will not have a material effect on our financial statements. 2. MERGERS AND ACQUISITIONS Coastal In January 2001, we merged with Coastal. We accounted for the transaction as a pooling of interests and converted each share of Coastal common stock and Class A common stock on a tax-free basis into 1.23 shares of our common stock. We exchanged Coastal's outstanding convertible preferred stock for our common stock on the same basis as if the preferred stock had been converted into Coastal common stock immediately prior to the merger. The total value of the transaction was approximately $24 billion, including $7 billion of assumed debt and preferred equity. In the merger, we issued approximately 271 million shares of our common stock, including 4 million shares in exchange for Coastal stock options. All financial information for all periods presented have been restated to reflect the pooling of interests. 53 55 The following table presents the revenues and net income for the previously separate companies and the combined amounts presented in these audited combined financial statements. Several adjustments were made to conform the accounting presentation of this financial information.
YEAR ENDED DECEMBER 31, ----------------------------- 2000 1999 1998 ------- ------- ------- (IN MILLIONS) Revenues El Paso................................................... $21,950 $10,709 $ 9,560 Coastal................................................... 18,014 10,331 9,404 Conforming reclassifications(1)........................... 9,304 6,292 4,809 ------- ------- ------- Combined.................................................. $49,268 $27,332 $23,773 ======= ======= ======= Extraordinary items, net of income taxes El Paso................................................... $ 70 $ -- $ -- Coastal................................................... -- -- -- ------- ------- ------- Combined.................................................. $ 70 $ -- $ -- ======= ======= ======= Net income (loss) El Paso................................................... $ 652 $ (255) $ (306) Coastal................................................... 654 499 444 ------- ------- ------- Combined.................................................. $ 1,306 $ 244 $ 138 ======= ======= =======
--------------- (1) Conforming reclassifications include a gross-up of revenues associated with Coastal's physical petroleum marketing and trading activities. Texas Midstream Operations In December 2000, we completed our purchase of PG&E's Texas Midstream operations. The total value of the transaction was $887 million, including assumed debt of approximately $527 million. The transaction was accounted for as a purchase and is included in our Field Services segment. The operations acquired consisted of 7,500 miles of intrastate natural gas transmission and natural gas liquids pipelines that transport approximately 2.8 Bcf/d in nine natural gas processing and fractionation plants that currently process 1.5 Bcf/d, and rights to 7.2 Bcf of natural gas storage capacity. In March 2001, we sold some of these acquired natural gas liquids transportation and fractionation assets to Energy Partners for approximately $133 million. Sonat In October 1999, we completed our merger with Sonat, a diversified energy holding company engaged in domestic oil and natural gas exploration and production, the transmission and storage of natural gas, and natural gas and power marketing. In the merger, one share of our common stock was issued in exchange for each share of Sonat common stock. Total common shares issued in the merger were approximately 110 million. The transaction was valued at approximately $7 billion based on our closing stock price on October 25, 1999. The merger was accounted for as a pooling of interests. Divestitures During 2000, we completed the sales of East Tennessee Natural Gas Company, Sea Robin Pipeline Company and our one-third interest in Destin Pipeline Company to comply with a Federal Trade Commission order related to our merger with Sonat. Proceeds from the sales were approximately $616 million and we recognized an extraordinary gain of $89 million, net of income taxes of $60 million. In December 2000, we sold our interest in Oasis Pipeline Company to comply with a Federal Trade Commission order. We incurred a 54 56 loss on this transaction of approximately $19 million, net of income taxes. We recorded the gains and losses on these sales as extraordinary items in our income statement. Under a Federal Trade Commission order as a result of our merger with Coastal, we sold our Gulfstream Pipeline project, as well as our 50 percent interest in the Stingray pipeline and U-T Offshore pipeline systems. Proceeds from these sales were approximately $70 million and resulted in a loss of approximately $29 million, before income taxes. We will also be required to sell our Midwestern system and our interest in the Iroquois pipeline and Empire pipeline systems. The income impact of our completed and anticipated sale transactions will be reflected as extraordinary items in our 2001 income statement. Additionally, in the first quarter of 2001, Energy Partners sold its interests in several offshore assets. These sales consisted of interests in seven natural gas pipeline systems, a dehydration facility, and two offshore platforms. Proceeds from the sales of these assets were approximately $135 million and resulted in a loss to the partnership of approximately $23 million. As consideration for these sales, we committed to pay Energy Partners a series of payments totaling $29 million. This amount, as well as our proportional share of the losses on the sale of the partnership's assets, will be recorded as a charge in our income statement in the first quarter of 2001. We do not anticipate the impact from these sales to be material to our ongoing financial position, operating results, or cash flows. 3. MERGER-RELATED COSTS AND ASSET IMPAIRMENT CHARGES Merger-Related Costs During 2000, 1999, and 1998, we incurred merger-related costs related to our mergers with Coastal, Sonat, and our merger in 1998 with Zilkha Energy Company. These costs included the following for the years ended December 31:
2000 1999 1998 ---- ---- ---- (IN MILLIONS) Employee severance, retention and transition costs.......... $31 $303 $-- Transaction costs........................................... 57 62 -- Merger-related asset impairments............................ -- 78 -- Other....................................................... 5 72 15 --- ---- --- $93 $515 $15 === ==== ===
Employee severance, retention, and transition costs include direct payments to, and benefit costs for, severed employees and early retirees that occurred as a result of merger-related workforce consolidations within our operating segments and the elimination of redundant positions within our merged operations. These costs included actual severance payments and costs for pension and post-retirement benefits settled and curtailed under existing benefit plans. Retention charges include payments to employees who were retained following the merger and payments to employees to satisfy contractual obligations. Transition costs relate to costs to relocate employees and costs for severed and retired employees arising after their severance date to transition their jobs into the ongoing workforce. The unpaid portion of these charges was $7 million at December 31, 2000, and $76 million at December 31, 1999. Transaction costs include investment banking, legal, accounting, consulting, and other advisory fees incurred to obtain federal and state regulatory approvals and take other actions necessary to complete our mergers. Merger-related asset impairments relate to write-offs or write-downs of capitalized costs for duplicate systems, redundant facilities and assets whose value was impaired as a result of decisions on the strategic direction of our combined operations following each of our mergers. Other costs primarily consist of charges to conform accounting policies and practices, integrate facilities, and retain seismic data in our production operations. 55 57 In conjunction with the Coastal merger, we issued approximately 4.4 million shares of common stock in exchange for Coastal options. This resulted in a charge of approximately $278 million that will be recorded in the first quarter of 2001. On January 30, 2001, we announced a workforce reduction and consolidation. The restructuring resulted in the reduction of 3,285 full-time positions through terminations and early retirement. A majority of the total charges connected with the restructuring will be recorded in the first quarter of 2001 and are estimated to be approximately $890 million. Asset Impairment Charges During 2000 and 1999, we incurred asset impairment charges of $32 million and $42 million. The 2000 charge resulted from the impairment of Field Services' Needle Mountain processing facility in Arizona as well as several Merchant Energy coal and refining assets and facilities, all impaired due to the unrecoverability of costs. The 1999 charges consisted of impairments of regulatory assets that were not recoverable based on the settlement of SNG's rate case. 4. INCOME TAXES Pretax income from continuing operations are composed of the following:
YEAR ENDED DECEMBER 31, ----------------------- 2000 1999 1998 ------- ----- ----- (IN MILLIONS) United States............................................... $1,610 $240 $ 29 Foreign..................................................... 164 110 144 ------ ---- ---- $1,774 $350 $173 ====== ==== ====
The following table reflects the components of income tax expense (benefit) included in income from continuing operations for the three years ended December 31:
2000 1999 1998 ---- ---- ---- (IN MILLIONS) Current Federal................................................... $(78) $ 1 $ 30 State..................................................... (20) 5 (2) Foreign................................................... 16 19 11 ---- ---- ---- (82) 25 39 ---- ---- ---- Deferred Federal................................................... 566 61 (69) State..................................................... 54 5 25 Foreign................................................... -- 2 2 ---- ---- ---- 620 68 (42) ---- ---- ---- Total income tax expense (benefit)................ $538 $ 93 $ (3) ==== ==== ====
56 58 Our tax expense (benefit), included in income from continuing operations differs from the amount computed by applying the statutory federal income tax rate of 35 percent for the following reasons at December 31:
2000 1999 1998 ---- ---- ----- (IN MILLIONS) Tax expense at the statutory federal rate of 35%............ $621 $123 $ 61 Increase (decrease) State income tax, net of federal income tax benefit....... 22 7 17 Dividend exclusion........................................ (28) (17) (11) Non-deductible portion of merger-related costs............ 12 29 -- Foreign income taxed at different rates, not subject to U.S. tax............................................... (66) (25) (35) Deferred credit on loss carryovers........................ (18) -- -- Preferred stock dividends of a subsidiary................. 13 9 9 Non-conventional fuel tax credit.......................... (9) (6) (15) Depreciation, depletion, and amortization................. (14) (7) 7 Other..................................................... 5 (20) (36) ---- ---- ----- Income tax expense (benefit)................................ $538 $ 93 $ (3) ==== ==== ===== Effective tax rate.......................................... 30% 27% (2)% ==== ==== =====
The following are the components of our net deferred tax liability at December 31:
2000 1999 ------ ------ (IN MILLIONS) Deferred tax liabilities Property, plant, and equipment............................ $4,074 $3,693 Investments in unconsolidated affiliates.................. 827 548 Price risk management activities.......................... 244 17 Regulatory and other assets............................... 751 610 ------ ------ Total deferred tax liability...................... 5,896 4,868 ------ ------ Deferred tax assets U.S. net operating loss and tax credit carryovers......... 699 554 Accrual for regulatory issues............................. 266 299 Employee benefit and deferred compensation obligations.... 37 81 Other liabilities......................................... 874 621 Valuation allowance....................................... (3) (6) ------ ------ Total deferred tax asset.......................... 1,873 1,549 ------ ------ Net deferred tax liability.................................. $4,023 $3,319 ====== ======
At December 31, 2000, the portion of the cumulative undistributed earnings of our foreign subsidiaries and foreign corporate joint ventures on which we have not recorded U.S. income taxes was approximately $994 million. Since these earnings have been or are intended to be indefinitely reinvested in foreign operations, no provision has been made for any U.S. taxes or foreign withholding taxes that may be applicable upon actual or deemed repatriation. If a distribution of such earnings were to be made, we might be subject to both foreign withholding taxes and U.S. income taxes, net of any allowable foreign tax credits or deductions. However, an estimate of these taxes is not practicable. For the same reasons, we have not recorded a provision for U.S. income taxes on the foreign currency translation adjustment recorded in other comprehensive income. The tax benefit associated with the exercise of non-qualified stock options and the vesting of restricted stock, as well as restricted stock dividends, reduced taxes payable by $60 million in 2000, $19 million in 1999, and $14 million in 1998. These benefits are included in additional paid-in capital in our balance sheets. 57 59 As of December 31, 2000, we had capital loss carryovers of $21 million for which the carryover period ends in 2001, alternative minimum tax credits of $283 million that carryover indefinitely, and $2 million of general business credit carryovers for which the carryover periods end at various times in the years 2006 through 2017. Usage of these carryovers is subject to the limitations provided under Sections 382 and 383 of the Internal Revenue Code as well as the separate return limitation year rules of IRS regulations. The table below presents the details of our net operating loss carryover periods.
CARRYOVER PERIOD ----------------------------------------------------- 2001 2002-2010 20011-2015 2016-2020 TOTAL ---- ---------- ----------- ---------- ------ (IN MILLIONS) Net operating loss........................ -- $74 $253 $835 $1,162 ==== === ==== ==== ======
We recorded a valuation allowance to reflect the estimated amount of deferred tax assets which we may not realize due to the expiration of net operating loss and tax credit carryovers. As of December 31, 2000 and 1999, approximately $1 million and $4 million, of the valuation allowance relates to net operating loss carryovers of an acquired company. The remainder of the allowance relates to general business credit carryovers. With the exception of $2 million, any tax benefits subsequently recognized from the reversal of the allowance will be allocated to additional acquisition costs assigned to utility plant. Prior to 1999, our subsidiary, El Paso Tennessee Pipeline Co., and its subsidiaries filed a separate consolidated federal income tax return from our consolidated return. On January 1, 1999, as a result of a 1998 tax-free internal reorganization, El Paso Tennessee and its subsidiaries joined our consolidated federal income tax group. The subsidiaries of Sonat Inc. joined our consolidated federal income tax group on October 26, 1999, after our merger. After the Coastal merger, we will file a consolidated federal income tax return with Coastal. In connection with our acquisition of El Paso Tennessee, we entered into a tax sharing agreement with Newport News Shipbuilding Inc., new Tenneco Inc. and El Paso Tennessee. This tax sharing agreement provides, among other things, for the allocation among the parties of tax assets and liabilities arising prior to, as a result of, and subsequent to the distributions of new Tenneco Inc. and Newport News Shipbuilding Inc. to the shareholders of old Tenneco Inc. (now known as El Paso Tennessee). 58 60 5. EARNINGS PER SHARE We calculated basic and diluted earnings per share amounts as follows as of December 31:
2000 1999 1998 ---------------- ---------------- --------------- BASIC DILUTED BASIC DILUTED BASIC DILUTED ------ ------- ------ ------- ----- ------- (IN MILLIONS, EXCEPT PER COMMON SHARE AMOUNTS) Income from continuing operations.................. $1,236 $1,236 $ 257 $ 257 $ 176 $ 176 Preferred stock dividend......................... -- -- -- -- 6 6 ------ ------ ------ ------ ----- ------ Income from continuing operations available to common stockholders............................ 1,236 1,236 257 257 170 170 Trust preferred securities....................... -- 10 -- -- -- -- ------ ------ ------ ------ ----- ------ Adjusted income from continuing operations....... 1,236 1,246 257 257 170 170 Discontinued operations, net of income taxes..... -- -- -- -- (38) (38) Extraordinary items, net of income taxes......... 70 70 -- -- -- -- Cumulative effect of accounting change, net of income taxes................................... -- -- (13) (13) -- -- ------ ------ ------ ------ ----- ------ Adjusted net income.............................. $1,306 $1,316 $ 244 $ 244 $ 132 $ 132 ====== ====== ====== ====== ===== ====== Average common shares outstanding.................. 494 494 490 490 487 487 Effect of diluted securities Restricted stock................................. -- -- -- -- -- 1 Stock options.................................... -- 7 -- 5 -- 5 FELINE PRIDES(sm)................................ -- 3 -- -- -- -- Preferred stock.................................. -- 1 -- 2 -- 2 Trust preferred securities....................... -- 8 -- -- -- -- ------ ------ ------ ------ ----- ------ Average common shares outstanding.................. 494 513 490 497 487 495 ====== ====== ====== ====== ===== ====== Earnings per common share Adjusted income from continuing operations....... $ 2.50 $ 2.43 $ 0.52 $ 0.52 $0.35 $ 0.34 Discontinued operations, net of income taxes..... -- -- -- -- (0.08) (0.08) Extraordinary items, net of income taxes......... 0.14 0.14 -- -- -- -- Cumulative effect of accounting change, net of income taxes................................... -- -- (0.03) (0.03) -- -- ------ ------ ------ ------ ----- ------ Adjusted net income.............................. $ 2.64 $ 2.57 $ 0.49 $ 0.49 $0.27 $ 0.26 ====== ====== ====== ====== ===== ======
59 61 6. FINANCIAL INSTRUMENTS AND PRICE RISK MANAGEMENT ACTIVITIES Fair Value of Financial Instruments Following are the carrying amounts and estimated fair values of our financial instruments at December 31:
2000 1999 --------------------- --------------------- CARRYING CARRYING AMOUNT FAIR VALUE AMOUNT FAIR VALUE -------- ---------- -------- ---------- (IN MILLIONS) Balance sheet financial instruments: Notes receivable.................................. $ 245 $ 272 $ 259 $ 271 Investments....................................... 132 132 80 80 Long-term debt, including current maturities...... 12,081 12,273 10,275 10,111 Notes payable to unconsolidated affiliates........ 752 775 122 122 Company obligated preferred securities of subsidiaries.................................... 925 1,172 625 603 Trading instruments Futures contracts............................... 152 152 (24) (24) Option contracts(1)............................. (106) (106) 264 264 Swap and forward contracts...................... 1,379 1,379 (65) (65) Equity swap....................................... -- -- -- 10 Other financial instruments: Non-Trading instruments Commodity swap and forward contracts............ $ -- $(1,906) $ -- $ (22) Commodity futures contracts..................... -- -- -- 2 Foreign currency forward purchases.............. -- 3 -- 4 Interest rate swap agreements................... -- -- -- 4
--------------- (1) Excludes transportation capacity, tolling agreements, and natural gas in storage held for trading purposes since these do not constitute financial instruments. As of December 31, 2000, and 1999, our carrying amounts of cash and cash equivalents, short-term borrowings, and trade receivables and payables are representative of fair value because of the short-term nature of these instruments. The fair value of long-term debt with variable interest rates approximates its carrying value because of the market based nature of the debt's interest rates. We estimated the fair value of debt with fixed interest rates based on quoted market prices for the same or similar issues. We estimated the fair value of all derivative financial instruments, based on quoted market prices, current market conditions, estimates we obtained from third-party brokers or dealers, or amounts derived using valuation models. 60 62 Trading Commodity Activities The fair value of commodity and energy related contracts entered into for trading purposes as of December 31, 2000 and 1999, and the average fair value of those instruments are set forth below. In September 2000, we terminated our Engage Energy joint venture with Westcoast Energy, Inc. and have consolidated their U.S. activities subsequent to the termination. The 2000 information below includes information for Coastal Merchant Energy for the periods it was consolidated in Coastal's operations.
AVERAGE FAIR VALUE FOR THE YEAR ENDED ASSETS LIABILITIES DECEMBER 31,(1) ------ ----------- --------------- (IN MILLIONS) 2000 Futures contracts................................. $ 152 $ -- $263 Option contracts.................................. 2,194 (1,641) 598 Swap and forward contracts........................ 4,354 (2,896) 688 1999 Futures contracts................................. $ 2 $ (26) $(12) Option contracts.................................. 455 (35) 184 Swap and forward contracts........................ 205 (247) 93
--------------- (1) Computed using the net asset (liability) balance at each month end. Notional Amounts and Terms The notional amounts and terms of our energy commodity financial instruments at December 31, 2000, and 1999 are set forth below (natural gas volumes are in trillions of British thermal units, power volumes are in millions of megawatt hours, crude oil and refined products volumes are in millions of barrels, weather volumes are in thousands of degree days, and energy capacity volumes are in millions of kilowatt hours):
FIXED PRICE FIXED PRICE MAXIMUM PAYOR RECEIVER TERMS IN YEARS ----------- ----------- -------------- 2000 Energy Commodities: Natural gas...................................... 34,306 29,896 27 Power............................................ 133 143 20 Crude oil and refined products................... 8 8 6 Weather.......................................... 133 135 -- Energy Capacity.................................. 22 29 3 1999 Energy Commodities: Natural gas...................................... 26,457 24,565 26 Power............................................ 30 41 20 Crude oil and refined products................... 8 8 7
61 63 The notional amount and terms of foreign currency forward purchases and sales at December 31, 2000 and 1999, were as follows:
NOTIONAL VOLUME ------------------------- MAXIMUM BUY SELL TERM IN YEARS ----------- ----------- -------------- 2000 Foreign Currency (in millions) Canadian Dollars.............................. 1,095 441 8 1999 Foreign Currency (in millions) Canadian Dollars.............................. 296 194 9 British Pounds................................ -- 28 9
Notional amounts reflect the volume of transactions but do not represent the actual amounts exchanged by the parties. As a result, notional amounts are an incomplete measure of our exposure to market or credit risks. The maximum terms in years detailed above are not indicative of likely future cash flows as these positions may be offset or cashed-out in the commodity and currency markets based on our risk management needs and liquidity in those markets. The weighted average maturity of our entire portfolio of price risk management activities was approximately two years as of December 31, 2000, and six years as of December 31, 1999. Market and Credit Risks We serve a diverse customer group that generates a need for a variety of financial structures, products, and terms. This diversity requires us to manage, on a portfolio basis, the resulting market risks inherent in these transactions subject to parameters established by our risk management committee. We monitor market risks through a risk control committee operating independently from the units that create or actively manage these risk exposures to ensure compliance with our stated risk management policies. We measure and adjust the risk in our portfolio in accordance with mark-to-market and other risk management methodologies which utilize forward price curves in the energy markets to estimate the size and probability of future potential exposure. Credit risk relates to the risk of loss that we would incur as a result of non-performance by counterparties pursuant to the terms of their contractual obligations. We maintain credit policies with regard to our counterparties to minimize overall credit risk. These policies require an evaluation of potential counterparties' financial condition (including credit rating), collateral requirements under certain circumstances (including cash in advance, letters of credit, and guarantees), and the use of standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty. The counterparties associated with our assets from price risk management activities are summarized as follows:
ASSETS FROM PRICE RISK MANAGEMENT ACTIVITIES AS OF DECEMBER 31, 2000 --------------------------------------------------- BELOW INVESTMENT GRADE(1) INVESTMENT GRADE TOTAL(2) ------------------- ---------------- -------- (IN MILLIONS) Energy marketers................................. $2,673 $ 34 $2,707 Financial institutions........................... 1,533 -- 1,533 Oil and natural gas producers.................... 642 1 643 Natural gas and electric utilities............... 1,558 68 1,626 Industrials...................................... 103 2 105 Municipalities................................... 17 -- 17 Other............................................ 68 1 69 ------ ---- ------ Total assets from price risk management activities............................ $6,594 $106 $6,700 ====== ==== ======
62 64
ASSETS FROM PRICE RISK MANAGEMENT ACTIVITIES AS OF DECEMBER 31, 1999 --------------------------------------------------- BELOW INVESTMENT GRADE(1) INVESTMENT GRADE TOTAL(2) ------------------- ---------------- -------- (IN MILLIONS) Energy marketers................................. $226 $ 1 $227 Financial institutions........................... 21 -- 21 Oil and natural gas producers.................... 26 -- 26 Natural gas and electric utilities............... 251 2 253 Industrials...................................... 15 -- 15 Municipalities................................... 64 -- 64 Other............................................ 56 -- 56 ---- --- ---- Total assets from price risk management activities............................ $659 $ 3 $662 ==== === ====
--------------- (1)"Investment Grade" is primarily determined using publicly available credit ratings along with consideration of collateral, which encompasses standby letters of credit, parent company guarantees and property interest, including natural gas and oil reserves. Included in Investment Grade are counterparties with a minimum Standard & Poor's or Moody's rating of BBB- or Baa3, respectively, or minimum implied (through internal credit analysis) Standard & Poor's equivalent rating of BBB-. (2)We had one customer in 2000 and four customers in 1999 that comprised greater than 5 percent of assets from price risk management activities. These customers have investment grade ratings. This concentration of counterparties may impact our overall exposure to credit risk, either positively or negatively, in that the counterparties may be similarly affected by changes in economic, regulatory or other conditions. Based on our policies, risk exposure, and reserves, we do not anticipate a material adverse effect on our financial position, operating results, or cash flows as a result of counterparty nonperformance. Non-Trading Price Risk Management Activities We also utilize derivative financial instruments for non-trading activities to mitigate market price risk associated with significant physical transactions. Non-trading commodity activities are accounted for using hedge accounting provided they meet hedge accounting criteria. Non-trading activities are conducted through exchange traded futures contracts, swaps, and forward agreements with third parties. The notional amounts and terms of contracts held for purposes other than trading were as follows at December 31:
1999 2000 --------------------- ------------------------- NOTIONAL NOTIONAL VOLUME VOLUME --------------- MAXIMUM ---------- MAXIMUM BUY SELL TERM BUY SELL TERM ------ ------ ------- --- ---- -------- Commodity Natural Gas (TBtu)........................ 116 676 12 22 548 13 Power (MMWh).............................. 134 35 2 -- -- -- Liquids (MMbls)........................... 11,270 13,052 1 -- 1 2
In August 1999, we entered an interest rate swap agreement with a notional amount of $600 million and a termination date of July 2001. In the agreement, we swapped the fixed interest rate on our July 1999 $600 million aggregate principal Senior Notes due 2001, for a floating three month LIBOR plus a margin of 14.75 basis points. Total interest expense was less than $1 million in 2000 and 1999, as a result of this swap agreement. In November 2000, we terminated this swap. The termination of this swap did not have a material impact on our financial results. In May 2000, we terminated our equity swap transaction associated with an additional 18.5 percent of CAPSA's outstanding stock and purchased the counterparty's 18.5 percent interest in CAPSA for approximately $127 million. CAPSA is a privately held Argentine company engaged in power generation and natural gas and oil production. Under the swap, we paid interest to the counterparty, on a quarterly basis, on a notional amount of $103 million at a rate of LIBOR plus 1.75 percent. In exchange, we received dividends, if 63 65 any, on the CAPSA stock to the extent of the counterparty's equity interest of 18.5 percent. We also fully participated in the market appreciation or depreciation of the underlying investment whereby we realized appreciation or funded any depreciation attributable to the actual sale of the stock upon termination or expiration of the swap transaction. The termination of this swap did not have a material impact on our financial results. At December 31, 2000, we had interest rate swaps with a notional amount of $12 million. Under these agreements, we will pay the counterparties interest at a weighted average fixed rate of 6.83%, and the counterparties will pay us interest at a variable rate equal to LIBOR or other market rates. The weighted average rate applicable to these agreements was 6.485% at December 31, 2000. The notional amounts do not represent amounts exchanged by the parties and thus are not a measure of our exposure. The amounts exchanged are normally based on the notional amounts and other terms of the swaps. The weighted average variable rates are subject to change over time as market rates fluctuate. Terms expire at various dates through the year 2011. We also face credit risk with respect to our non-trading activities and take similar measures, as in our trading activities, to mitigate this risk. Based upon our policies and risk exposure, we do not anticipate a material effect on our financial position, operating results, or cash flows resulting from counterparty non-performance. 7. INVENTORY Our inventory consisted of the following at December 31:
2000 1999 ------ ---- (IN MILLIONS) Refined products, crude oil and chemicals................... $ 690 $576 Coal, materials and supplies, and other..................... 272 229 Natural gas in storage...................................... 72 2 ------ ---- Total............................................. $1,034 $807 ====== ====
8. DEBT AND OTHER CREDIT FACILITIES The average interest rate on our short-term borrowings was 7.4% and 6.6% at December 31, 2000 and 1999. We had the following short-term borrowings, including current maturities of long-term debt, at December 31:
2000 1999 ------ ------ (IN MILLIONS) Short-term credit facility.................................. $ 455 $ -- Notes payable............................................... 798 106 Commercial paper............................................ 961 1,216 Other credit facilities..................................... 10 35 Current maturities of long-term debt........................ 1,179 254 ------ ------ $3,403 $1,611 ====== ======
64 66 Our long-term debt outstanding consisted of the following at December 31:
2000 1999 ------- ------- (IN MILLIONS) Long-term debt El Paso Corporation Senior notes, 6.625% through 7.375%, due 2001 through 2012................................................. $ 1,700 $ 1,100 Notes, 6.625% through 9%, due 2001 through 2030........ 1,500 1,200 Variable rate senior note due 2001, average interest for 2000 of 7.11% and 6.35% for 1999................. 100 100 El Paso Tennessee Notes, 7.25% through 10%, due 2008 through 2025........ 51 51 Debentures, 6.5% through 10.375%, due 2000 through 2005................................................. 36 42 Tennessee Gas Pipeline Debentures, 6% through 7.625%, due 2011 through 2037... 1,386 1,386 El Paso Natural Gas Notes, 6.75% through 7.75%, due 2002 through 2003...... 415 415 Debentures, 7.5% and 8.625%, due 2022 and 2026......... 460 460 Southern Natural Gas Notes, 6.125% through 8.875%, due 2001 through 2008.... 500 500 EPEC Corporation Senior note, 9.625%, due 2001.......................... 13 13 DeepTech International Senior note, 12%, due 2000............................. -- 82 Field Services Notes, 7.41% through 11.5% due, 2001 through 2012...... 511 -- El Paso CGP Notes payable (revolving credit agreement)............. 135 50 Senior notes, 6.2% through 10.375%, due 2000 through 2010................................................. 1,650 855 Floating rate senior notes, due 2002 through 2003...... 600 -- Senior debentures, 6.375% through 10.75%, due 2003 through 2037......................................... 1,497 1,497 FELINE PRIDES, 6.625%, due 2004........................ 460 460 ANR Debentures, 7.0% through 9.625%, due 2021 through 2025................................................. 500 500 CIG Debentures, 6.85% through 10.0%, due 2005 through 2037................................................. 280 280 Other..................................................... 334 859 Amount reclassified from short-term debt(1)............... -- 475 ------- ------- 12,128 10,325 Less: Unamortized discount................................ 47 50 Current maturities.................................. 1,179 254 ------- ------- Long-term debt, less current maturities................... $10,902 $10,021 ======= =======
--------------- (1) As of December 31, 1999, our financial statements reflected $475 million of short-term borrowings that had been reclassified as long-term, based on the availability of committed credit lines with maturities in excess of one year and our intent to maintain such amounts as long-term borrowings. Aggregate maturities of the principal amounts of long-term debt for the next 5 years and in total thereafter are as follows:
(IN MILLIONS) ------------- 2001........................................................ $ 1,179 2002........................................................ 1,339 2003........................................................ 557 2004........................................................ 775 2005........................................................ 657 Thereafter.................................................. 7,621 ------- Total long-term debt, including current maturities....................................... $12,128 =======
65 67 Other Financing Arrangements As of December 31, 2000, we have a $2 billion, 364-day renewable credit and competitive advance facility and a $1 billion, 3-year revolving credit and competitive advance facility. These facilities replaced our $1,250 million and our $750 million revolving credit facilities in August 2000. EPNG and TGP are also designated borrowers under these facilities. The interest rate for these facilities varies and was LIBOR plus 50 basis points on December 31, 2000. No amounts were outstanding under these facilities as of December 31, 2000. In October 2000, we established a $30 million multi-currency revolving credit facility. The 364-day facility allows us access to U.S. Dollars, English Pounds, German Marks, Norwegian Kroner, and Euros. The interest rate for this facility varies and was LIBOR plus 50 basis points on December 31, 2000. No amounts were outstanding at December 31, 2000. In December 2000, we established a $700 million floating rate bridge facility for use in connection with the acquisition of PG&E's Texas Midstream operations. As of December 31, 2000, $455 million was outstanding under this facility. As part of our acquisition, we assumed approximately $527 million in debt, and in February 2001, we borrowed the balance of this facility and redeemed $340 million of the debt assumed. As of December 31, 2000, Coastal had $798 million of outstanding indebtedness to banks under its short-term lines of credit, compared to $581 million at December 31, 1999. The weighted average interest rates were 7.15% and 6.63% at December 31, 2000 and 1999. As of December 31, 2000, $622 million was available to be drawn under these short-term credit lines. This program was cancelled as a result of our merger and Coastal became a named borrower under our credit facilities. The availability of borrowings under our credit agreements is subject to specified conditions, which we believe we currently meet. These conditions include compliance with the financial covenants and ratios required by such agreements, absence of default under such agreements, and continued accuracy of the representations and warranties contained in such agreements (including the absence of any material adverse changes). All of our senior debt issues have been given investment grade ratings by Standard & Poor's and Moody's. We use a commercial paper program to manage our short-term cash requirements. Under this program we can borrow up to $1 billion. In addition, TGP and EPNG have the ability to individually borrow up to $1 billion each. As of March 2001, TGP has $200 million and SNG has $100 million in capacity remaining under shelf registration statements on file with the Securities and Exchange Commission. 66 68 Other Financing Activities Our significant long-term debt issuances and retirements during 2000 and 1999 were as follows: ISSUANCES
NET DATE COMPANY TYPE OF ISSUE INTEREST RATE PRINCIPAL PROCEEDS(1) DUE DATE ---- ------- ------------- ------------- --------- ------------ -------- (IN MILLIONS) 2000 March Coastal Floating Rate Notes Variable $400 $399 2002 June Coastal Notes 7.75% 400 399 2010 July Coastal Floating Rate Notes Variable 200 200 2003 August Coastal Notes 7.5% 300 299 2006 September Coastal Notes 7.625% 215 214 2008 El October Paso Medium-term notes 8.05% 300 296 2030 El December Paso Medium-term notes 7.38% 300 298 2012 El December Paso Medium-term notes 6.95% 300 297 2007 1999 February Coastal Senior Debentures 6.375% $199 $199 2009 El May Paso Senior notes 6.75% 500 495 2009 May Coastal Senior notes 6.2% 200 200 2004 May Coastal Senior notes 6.5% 200 200 2006 El July Paso Senior notes 6.625% 600 596 2001 El July Paso Senior notes Variable 100 100 2001 July Sonat Notes 7.625% 600 590 2011
--------------- (1) Net proceeds were primarily used to repay short-term borrowings and for general corporate purposes. RETIREMENTS
DATE COMPANY INTEREST RATE DUE DATE AMOUNT ---- ------- ------------- -------- ------------- (IN MILLIONS) 2000 July DeepTech International 12.00% 2000 $ 82 October Coastal 10.375% 2000 121 1999 May Coastal 8.75% 1999 $150 August Sonat 9.50% 1999 100 September El Paso Natural Gas 9.45% 1999 47 October Mojave Pipeline Company Variable 1999 107
In addition, we established and drew upon a $250 million non-committed line of credit in January 2000. In March 2000, we repaid this facility. In May 2000, we issued preferred securities of a consolidated trust, El Paso Energy Capital Trust IV. Proceeds of approximately $293 million, net of issuance costs, were used for general corporate purposes. We also received approximately $984 million from a third-party investor in 2000 as a result of the sale of a preferred interest in Clydesdale Associates, L.P., a consolidated joint venture. In 1999, we received net proceeds of $960 million from a third-party investor as a result of the sale of a preferred interest in Trinity River Associates, L.L.C., a consolidated joint venture. The proceeds from these issuances were used to repay short-term debt and for other corporate purposes. For a further discussion of these transactions, see Note 9. In November 2000, we terminated an interest rate swap with a notional amount of $600 million and a termination date of July 2001. The swap was originally put into place to swap the 6.625% fixed interest rate on our July 1999, $600 million aggregate principal Senior Notes due 2001 with a variable interest rate. The termination of the swap did not have a material impact on our financial results. In August 1999, we issued a total of 18,400,000 FELINE PRIDES(SM) consisting of 17,000,000 Income PRIDES with a stated value of $25 and 1,400,000 Growth PRIDES with a stated value of $25. The Income PRIDES consist of a unit comprised of a Senior Debenture and a purchase contract under which the holder is 67 69 obligated to purchase from us by no later than August 16, 2002 for $25 (the stated price) a number of shares of our common stock. The Growth PRIDES consist of a unit comprised of a purchase contract under which the holder is obligated to purchase from us by no later than August 16, 2002 for $25 (the stated price) a number of shares of our common stock and a 2.5% undivided beneficial interest in a three-year Treasury security having a principal amount at maturity equal to $1,000. Under the terms of the purchase contract in effect prior to the merger with El Paso, the number of shares of common stock the holder of a PRIDE received varied between 0.5384 and 0.6568 shares, depending on the price of our common stock. Under the terms of the purchase contract, as a result of the merger with El Paso, the holder of a PRIDE is entitled and required to receive upon settlement 0.6622 shares of El Paso common stock. This will result in the issuance of approximately 12.2 million shares of El Paso common stock. The obligation of a holder of PRIDES to purchase common stock is secured by a pledge of the Senior Debenture of Treasury Security. In October 1999, Mojave Pipeline Company terminated its associated interest rate swap at a cost of approximately $5 million. We also entered into various financing transactions with unconsolidated affiliates. See Note 17, Investments in Unconsolidated Affiliates, for a further discussion of these transactions. Financing Activities in 2001 In February 2001, SNG issued $300 million aggregate principal amount 7.35% Notes due 2031. Proceeds of approximately $297 million, net of issuance costs, were used to pay off $100 million of SNG's 8.875% Notes due 2001, and for general corporate purposes. Also in February 2001, we issued approximately $1.8 billion zero coupon convertible debentures due 2021, with a yield to maturity of 4%. Proceeds of approximately $784 million, net of issuance costs, were used to repay short-term borrowings and for general corporate purposes. These debentures are convertible into 8,456,589 shares of our common stock which is based on a conversion rate of 4.7872 shares per $1,000 principal amount at maturity. This rate was equivalent to an initial conversion price of $94.604 per share of our common stock. In March 2001, we issued E550 million (approximately $510 million) of euro notes at 5.75% due 2006. Proceeds of approximately $505 million, net of issuance costs, were used to repay short-term debt and for general corporate purposes. To reduce our exposure to foreign currency risk, we entered into a swap transaction exchanging the euro note for a $510 million U.S. dollar denominated obligation with a fixed interest rate of 6.61% for the five year term of the note. 9. SECURITIES OF SUBSIDIARIES Company-obligated Preferred Securities In March 1998, we formed El Paso Energy Capital Trust I which issued 6.5 million of 4 3/4% trust convertible preferred securities for $325 million ($317 million, net of issuance costs). We own all of the Common Securities of Trust I. We used the net proceeds from the preferred securities to pay down our commercial paper. Trust I exists for the sole purpose of issuing preferred securities and investing the proceeds in 4 3/4% convertible subordinated debentures due 2028, their sole asset. We guarantee Trust I's preferred securities. Trust I's preferred securities are reflected as company-obligated preferred securities of consolidated trusts in our balance sheet. Distributions paid on the preferred securities are included as minority interest in our income statement. Trust I's preferred securities are non-voting (except in limited circumstances), pay quarterly distributions at an annual rate of 4 3/4%, carry a liquidation value of $50 per security plus accrued and unpaid distributions and are convertible into our common shares at any time prior to the close of business on March 31, 2028, at the option of the holder at a rate of 1.2022 common shares for each Trust I Preferred Security (equivalent to a conversion price of $41.59 per common share), subject to adjustment in certain circumstances. In May 1998, Coastal completed a public offering of 12 million mandatory redemption preferred securities through an affiliate, Coastal Finance I, a business trust, for $300 million. Coastal Finance I holds 68 70 debt securities of ours purchased with the proceeds of the preferred securities offering. Cumulative quarterly distributions are being paid on the preferred securities at an annual rate of 8.375% of the liquidation amount of $25 per preferred security. The preferred securities are mandatorily redeemable on the maturity date, May 13, 2038, and may be redeemed at our option on or after May 13, 2003, or earlier if various events occur. The redemption price to be paid is $25 per preferred security, plus accrued and unpaid distributions to the date of redemption. In May 2000, we formed El Paso Energy Capital Trust IV which issued $300 million ($293 million, net of issuance costs) of preferred securities to a third party investor. These preferred securities pay cash distributions at a floating rate equal to the three-month LIBOR plus 0.75 percent. As of December 31, 2000, the floating rate was 7.49%. These preferred securities must be redeemed by Trust IV no later than November 30, 2003. Proceeds from the sale of the securities were used by Trust IV to purchase a series of our floating rate senior debentures whose yield and maturity terms mirror those of Trust IV's preferred securities. The sole assets of Trust IV are these floating rate senior debentures. We guarantee all obligations of Trust IV related to its preferred securities. At the time Trust IV issued the preferred securities, we also agreed to issue $300 million of equity securities, including, but not limited to, our common stock in one or more public offerings prior to May 31, 2003. Minority Interests Trinity River. During 1999, we formed Sabine River Investors, L.L.C., a wholly owned limited liability company, and other separate legal entities, to generate funds to invest in capital projects and other assets. Through Sabine, we contributed $250 million of equity capital to Trinity River Associates, L.L.C., and a third-party investor contributed $980 million. The third-party investor is entitled to an adjustable preferred return derived from Trinity's net income. Trinity used the proceeds to invest in a note receivable from Sabine collateralized by selected assets. We have the option to acquire the third-party's interest in Trinity at any time prior to June 2004. If we do not exercise this option or if the agreement is not extended, Trinity's note receivable from Sabine will mature and a portion of the proceeds will be used by Trinity to redeem the third-party interest in Trinity. The assets, liabilities, and operations of Sabine, Trinity, and other entities involved in the transaction are included in our financial statements. Clydesdale. In May 2000, we formed Clydesdale Associates, L.P., a limited partnership, and several other separate legal entities to generate funds to invest in capital projects and other assets. Initially, we contributed $55 million of equity capital into Clydesdale and a third-party investor contributed $250 million. In December 2000, we contributed an additional $200 million into Clydesdale and a third-party investor contributed an additional $750 million. The third-party investor is entitled to an adjustable preferred return derived from Clydesdale's net income. Clydesdale used the proceeds to invest in a note receivable with us. The third-party's contributions are collateralized by production properties, rental income from real estate assets, and notes receivable from us. We have the option to acquire the third-party's interest in Clydesdale at any time prior to May 2005. If we do not exercise this option, or if the agreement is not extended, the note receivable will mature and a portion of the proceeds will be used to redeem the third-party interest in Clydesdale. The assets, liabilities, and operations of the entities involved in this transaction are included in our financial statements. Preferred Stock of Subsidiaries. In November 1996, El Paso Tennessee Pipeline Co. issued 6 million shares of 8.25% cumulative preferred stock with a par value of $50 per share for $296 million (net of issuance costs). The preferred stock is redeemable, at the option of El Paso Tennessee, after December 31, 2001, at a redemption price equal to $50 per share, plus dividends accrued and unpaid up to the date of redemption. During 2000, 1999, and 1998, dividends of approximately $25 million were paid each year on the preferred stock. Coastal Securities Company Limited, our wholly owned subsidiary, issued 4 million shares of preferred stock in 1996 for $100 million. Quarterly cash dividends are being paid on the preferred stock at a rate based on LIBOR. The preferred shareholders are also entitled to participating dividends based on certain refining margins. Coastal Securities may redeem the preferred stock on or after December 31, 1999 for cash. 69 71 In 1999, Coastal Oil & Gas Resources, Inc., our wholly owned subsidiary, issued 50,000 shares of preferred stock for $50 million. The preferred shareholders are entitled to quarterly cash dividends at a rate based on LIBOR. The dividend rate is subject to renegotiation in 2004 and on each fifth anniversary thereafter. In the event Coastal Oil & Gas and the preferred shareholders are unable to agree to a new rate, Coastal Oil & Gas must redeem the shares at $1,000 per share plus any accrued and unpaid dividends, or cause the preferred stock to be registered with the Securities and Exchange Commission and remarketed. Coastal Oil & Gas also has the option to redeem all shares on any dividend rate reset date for $1,000 per share plus any accrued and unpaid preferred dividends. In 1999, Coastal Limited Ventures, Inc., our wholly owned subsidiary, issued 150,000 shares of preferred stock for $15 million. The preferred shareholders are entitled to quarterly cash dividends at an annual rate of 6%. The dividend rate is subject to renegotiation in 2004 and on each fifth anniversary thereafter. In the event Coastal Limited and the preferred shareholders are unable to agree to a new rate, the preferred shareholders may call for redemption of all of the preferred shares. The redemption price is $100 per share plus any accrued and unpaid preferred dividends thereon. Coastal Limited also has the option to redeem all shares on any rate reset date for $100 per share plus any accrued and unpaid preferred dividends. Consolidated Joint Venture. In December 1999, Coastal Limited contributed assets to a limited partnership in exchange for a controlling general partnership interest. Limited interests in the partnership were issued to unaffiliated investors for $285 million. The limited partners are entitled to a cumulative priority return based on LIBOR. The return is subject to renegotiation in 2004 and on each fifth anniversary thereafter. The partnership has a maximum life of 20 years, but may be terminated sooner subject to certain conditions, including failure to agree to a new rate. Coastal Limited may terminate the partnership at any time by repayment of the limited partners' outstanding capital plus any unpaid priority returns. 10. COMMITMENTS AND CONTINGENCIES Legal Proceedings On August 19, 2000, a main transmission line owned and operated by EPNG ruptured at the crossing of the Pecos River near Carlsbad, New Mexico. Twelve individuals at the site were fatally injured. Eleven lawsuits brought on behalf of the twelve deceased persons have been filed against EPNG and EPEC for damages for personal injuries and wrongful death -- three in state district court in Harris County, Texas (Diane Heady, et. al v. EPEC and EPNG, filed September 7, 2000; Richard Heady v. EPEC and EPNG, filed February 15, 2001; Geneva Smith v. EPEC and EPNG, filed October 23, 2000), two in federal district court in Albuquerque, New Mexico (Dawson v. EPEC and EPNG, filed November 8, 2000; Jennifer Smith v. EPEC and EPNG, filed August 29, 2000), and six in state district court in Carlsbad, New Mexico (Chapman, as Personal Representative of the Estate of Amy Smith Heady, v. EPEC, EPNG, and John Cole, filed February 9, 2001; and Chapman, as Personal Representative of the Estate of Dustin Wayne Smith, v. EPEC, EPNG, and John Cole; Green v. EPEC, EPNG, and John Cole; Rackley, as Personal Representative of the Estate of Glenda Gail Sumler, v. EPEC, EPNG, and John Cole; and Rackley, as Personal Representative of the Estate of Amanda Sumler Smith, v. EPEC, EPNG, and John Cole, all filed March 16, 2001). In March 2001, we settled all claims in the Heady cases. Payments for these four claimants will be fully covered by insurance. The National Transportation Safety Board is conducting an investigation into the facts and circumstances concerning the possible causes of the rupture. In August 2000, the Liquidating Trustee in the bankruptcy of Power Corporation of America (PCA) sued El Paso Merchant Energy, and several other power traders, in the U.S. Bankruptcy Court in Connecticut claiming El Paso Merchant Energy improperly cancelled its contracts with PCA during the summer of 1998. The trustee alleges we breached contracts damaging PCA in the amount of $120 million. We have entered into a joint defense agreement with the other defendants. This matter will be mediated in the second quarter of 2001. In a related matter, PCA appealed the FERC's ruling that power marketers such as EPME did not have to give 60 days notice to cancel its power contracts under the Federal Power Act. PCA has appealed this decision to the United States Court of Appeals. Oral arguments were heard in January 2001 and we are awaiting the Court's decision. 70 72 In late 2000, we and several of our subsidiaries, including El Paso Natural Gas Company and El Paso Merchant Energy, were named as defendants in four purported class action lawsuits filed in state court in California. (Continental Forge Co. v. Southern California Gas Co., et al, Los Angeles; Berg v. Southern California Gas Co., et al, Los Angeles; John Phillip v. El Paso Merchant Energy, et al, San Diego; John WHK Phillip v. El Paso Merchant Energy, et al, San Diego.) Two of these cases, filed in Los Angeles, contend generally that our entities conspired with other unrelated companies to create artificially high prices for natural gas in California; the other two cases, filed in San Diego, assert that our companies used Merchant Energy's acquisition of capacity on the EPNG pipeline to manipulate the market for natural gas in California. We have remanded each of these cases to the federal courts in California and have filed motions to dismiss in the San Diego actions. On March 20, 2001, two additional lawsuits, The City of Los Angeles, et. al. v. Southern California Gas Company, et. al. and The City of Long Beach, et. al. v. Southern California Gas Company et. al. were filed in a Los Angeles County Superior Court. These cases seek monetary damages against us and several of our subsidiaries and make similar allegations to the Continental Forge and Berg cases discussed above. In 1999, a number of our subsidiaries were named defendants in actions brought by Jack Grynberg on behalf of the U.S. Government under the False Claims Act. Generally, these complaints allege an industry-wide conspiracy to under report the heating value as well as the volumes of the natural gas produced from federal and Native American lands, which deprived the U.S. Government of royalties. These matters have been consolidated for pretrial purposes. (In re: Natural Gas Royalties Oui Tam Litigation, U.S. District Court for the District of Wyoming.) A number of our subsidiaries are named defendants in an action styled Quinque Operating Company, et al v. Gas Pipelines and Their Predecessors, et al, filed in 1999, in the District Court of Stevens County, Kansas. This class action complaint alleges that the defendants mismeasured natural gas volumes and heating content of natural gas on non-federal and non-Native American lands. The Quinque complaint, once transferred to the same court handling the Grynberg complaint, has been sent back to Kansas State Court for further proceedings. In February 1998, the United States and the State of Texas filed in a U.S. District Court a Comprehensive Environmental Response, Compensation and Liability Act (CERCLA) cost recovery action against fourteen companies, including some of our current and former affiliates, related to the Sikes Disposal Pits Superfund Site located in Harris County, Texas. The suit claims that the United States and the State of Texas have spent over $125 million in remediating Sikes, and seeks to recover that amount plus interest from the defendants to the suit. The EPA has recently indicated that it may seek an additional amount up to $30 million plus interest in indirect costs from the defendants under a new cost allocation methodology. Defendants are challenging this allocation policy. Although an investigation relating to Sikes is ongoing, we believe that the amount of material, if any, disposed at Sikes by our former affiliates was small, possibly de minimis. However, the plaintiffs have alleged that the defendants are each jointly and severally liable for the entire remediation costs and have also sought a declaration of liability for future response costs such as groundwater monitoring. TGP is a party in proceedings involving federal and state authorities regarding the past use of a lubricant containing polychlorinated biphenyls (PCBs) in its starting air systems. TGP has executed a consent order with the EPA governing the remediation of some compressor stations and is working with the EPA and the relevant states regarding those remediation activities. TGP is also working with the Pennsylvania and New York environmental agencies regarding remediation and post-remediation activities at the Pennsylvania and New York stations. In October 1992, several property owners in McAllen, Texas filed suit in the 93rd Judicial District Court, Hidalgo County, Texas, against, among others, one of our subsidiaries. The suit sought damages for the alleged diminution of property value and damages related to the exposure to hazardous chemicals arising from the operation of service stations and storage facilities. In July 2000, the trial court entered a judgment for approximately $1.2 million in actual damages for property diminution and approximately $100 million in punitive damages. The judgment is being appealed. 71 73 In November 1988, the Kentucky environmental agency filed a complaint in a Kentucky state court alleging that TGP discharged pollutants into the waters of the state and disposed of PCBs without a permit. The agency sought an injunction against future discharges, an order to remediate or remove PCBs, and a civil penalty. TGP entered into agreed orders with the agency to resolve many of the issues raised in the original allegations, received water discharge permits from the agency for its Kentucky compressor stations, and continues to work to resolve the remaining issues. The relevant Kentucky compressor stations are being characterized and remediated under a consent order with the EPA. We are also a named defendant in numerous lawsuits and a named party in numerous governmental proceedings arising in the ordinary course of our business. While the outcome of the matters discussed above cannot be predicted with certainty, we do not expect the ultimate resolution of these matters will have a material adverse effect on our financial position, operating results, or cash flows. Environmental We are subject to extensive federal, state, and local laws and regulations governing environmental quality and pollution control. These laws and regulations require us to remove or remedy the effect on the environment of the disposal or release of specified substances at current and former operating sites. As of December 31, 2000, we had a reserve of approximately $309 million for expected remediation costs, including approximately $257 million for associated onsite, offsite and groundwater technical studies, and approximately $52 million for other costs which we anticipate incurring through 2027. In addition, we expect to make capital expenditures for environmental matters of approximately $469 million in the aggregate for the years 2001 through 2007. These expenditures primarily relate to compliance with air regulations. From March to October 2000, our Eagle Point Oil Company received several Administrative Order Notices of Civil Administrative Penalty Assessment from the New Jersey Department of Environmental Protection. All of the assessments are related to similar alleged noncompliances of the New Jersey Air Pollution Control Act pertaining to occurrences of air pollution from the second quarter 1998 through the third quarter 2000 by Eagle Point's refinery in Westville, New Jersey. The New Jersey Department of Environmental Protection has assessed penalties totaling approximately $1 million for these alleged noncompliances. Eagle Point has requested an administrative hearing on all issues raised by the assessments and concurrently, is in negotiations to settle these assessments. Since 1988, TGP has been engaged in an internal project to identify and deal with the presence of PCBs and other substances, including those on the EPA List of Hazardous Substances, at compressor stations and other facilities it operates. While conducting this project, TGP has been in frequent contact with federal and state regulatory agencies, both through informal negotiation and formal entry of consent orders, to ensure that its efforts meet regulatory requirements. In May 1995, following negotiations with its customers, TGP filed a Stipulation and Agreement (the "Environmental Stipulation") with FERC that established a mechanism for recovering a substantial portion of the environmental costs identified in its internal project. The Environmental Stipulation was effective July 1, 1995, and as of December 31, 1999, all amounts have been collected from customers. Refunds may be required to the extent actual eligible expenditures are less than amounts collected. We have been designated and have received notice that we could be designated, or have been asked for information to determine whether we could be designated as a Potentially Responsible Party (PRP) with respect to 50 sites under the Comprehensive Environmental Response, Compensation and Liability Act (CERCLA or Superfund) or state equivalents. We sought to resolve our liability as a PRP at these Superfund sites through indemnification by third parties and/or settlements which provide for payment of our allocable share of remediation costs. As of December 31, 2000, we have estimated our share of the remediation costs at these sites to be between $63 million and $198 million and have provided reserves that we believe are adequate for such costs. Since the clean-up costs are estimates and are subject to revision as more information becomes available about the extent of remediation required, and because in some cases we have asserted a defense to 72 74 any liability, our estimates could change. Moreover, liability under the federal Superfund statute is joint and several, meaning that we could be required to pay in excess of our pro rata share of remediation costs. Our understanding of the financial strength of other PRPs has been considered, where appropriate, in the determination of our estimated liabilities. We presently believe that the costs associated with these Superfund sites will not have a material adverse effect on our financial position, operating results, or cash flows. It is possible that new information or future developments could require us to reassess our potential exposure related to environmental matters. We may incur significant costs and liabilities in order to comply with existing environmental laws and regulations. It is also possible that other developments, such as increasingly strict environmental laws and regulations, and claims for damages to property, employees, other persons and the environment resulting from our current or past operations, could result in substantial costs and liabilities in the future. As this information becomes available, or other relevant developments occur, we will adjust our accrual amounts accordingly. While there are still uncertainties relating to the ultimate costs we may incur, based upon our evaluation and experience to date, we believe the recorded reserves are adequate. For a further discussion of specific environmental matters, see Legal Proceedings above. Rates and Regulatory Matters In April 2000, the California Public Utilities Commission (CPUC) filed a complaint alleging that El Paso Natural Gas' sale of capacity to Merchant Energy was anticompetitive and an abuse of the affiliate relationship under FERC's policies. The CPUC served data requests to us, which have been either substantially answered or contested. In August 2000, the CPUC filed a motion requesting that the contract between EPNG and Merchant Energy be terminated and other parties in the proceedings have requested that the original complaint be set for hearings and that Merchant Energy pay back any profits it has earned under the contract. The matter is pending at FERC. In February 2001, EPNG completed its open season on 1,221 MMcf/d of capacity held by Merchant Energy through May 2001 and all the capacity was re-subscribed. Contracts were awarded to 30 different entities, including 271 MMcf/d to Merchant Energy, all at published tariff rates under contracts with durations from 17 months to 15 years. While we cannot predict with certainty the final outcome or the timing of the resolution of all of our rates and regulatory matters, we believe the ultimate resolution of these issues will not have a material adverse effect on our financial position, results of operations, or cash flows. Capital Commitments and Purchase Obligations At December 31, 2000, we had capital and investment commitments of $1.6 billion primarily relating to our production, pipeline, and international power activities. Our other planned capital and investment projects are discretionary in nature, with no substantial capital commitments made in advance of the actual expenditures. In connection with the financing commitments on one of our joint ventures, TGP has entered into unconditional purchase obligations for products and services totaling $122 million at December 31, 2000. TGP's annual obligations under these agreements are $21 million for the years 2001, 2002, 2003, 2004 and 2005, and $17 million in total thereafter. Operating Leases We lease property, facilities and equipment under various operating leases, some of which contain residual value guarantees. Such residual value guarantees amount to approximately $533 million at December 31, 2000. Also in 1995, El Paso New Chaco Company (EPNC) entered into an unconditional lease for the Chaco Plant. The lease term expires in 2002, at which time EPNC has an option, and an obligation upon the occurrence of various events, to purchase the plant for a price sufficient to pay the amount of the $77 million construction financing, plus interest and other expenses. If EPNC does not purchase the plant at the end of the lease term, it has an obligation to pay a residual guaranty amount equal to approximately 87 percent of the amount financed, plus interest. We unconditionally guaranteed all obligations of EPNC under this lease. 73 75 Minimum annual rental commitments, were as follows at December 31:
OPERATING LEASES ---------------- (IN MILLIONS) 2001..................................................... $ 191 2002..................................................... 173 2003..................................................... 158 2004..................................................... 156 2005..................................................... 152 Thereafter............................................... 672 ------ Total............................................. $1,502 ======
Aggregate minimum commitments have not been reduced by minimum sublease rentals of approximately $14 million due in the future under noncancelable subleases. Rental expense on our operating leases for the years ended December 31, 2000, 1999, and 1998 was $198 million, $157 million, and $125 million. Guarantees At December 31, 2000, we had parental guarantees of approximately $2.2 billion in connection with our international development activities and various other projects, including approximately $1 billion associated with our investments in unconsolidated affiliates and minority interests as discussed in Note 17. Additionally, we and a former partner have issued a number of trade guarantees related to the operations of the Engage Energy US, L.P. and Engage Energy Canada, L.P. joint venture. The joint venture terminated in the fourth quarter of 2000, with each of the former partners retaining certain operations. As a condition to the termination, each of the former partners agreed to a continuation of the guarantees that were issued in connection with the operations retained by the other partner. Such guarantees are to be replaced as soon as practical, and in any event, by July 2001. Each party has agreed to reimburse the other for any payments that are made under such guarantees. As of December 31, 2000, we had outstanding guarantees in the principal amount of $61 in connection with the operations of the Engage joint venture that were transferred to the other party. We believe that the actual potential liability is significantly less than the principal amount of these guarantees. We believe that these parties will be able to perform under the guaranteed transactions and that no payments will be required or losses incurred by us under these guarantees. We also had outstanding letters of credit of approximately $233 million at December 31, 2000. At December 31, 1999, parental guarantees total approximately $1.9 billion and outstanding letters of credit were $170 million. 11. RETIREMENT BENEFITS Pension Benefits Prior to January 1, 1997, we maintained a defined benefit pension plan that covered substantially all of our employees. Pension benefits were based on years of credited service and final five year average compensation, subject to maximum limitations as defined in that plan. Effective January 1, 1997, the plan was amended to provide benefits determined by a cash balance formula and to include employees added as a result of our merger with El Paso Tennessee and other acquisitions prior to 1997. Employees who were pension plan participants on December 31, 1996, receive the greater of cash balance benefits or prior plan benefits accrued through December 31, 2001. Effective January 1, 2000, Sonat's pension plan was merged into our pension plan. Sonat employees who were participants in the Sonat pension plan on the Sonat merger effective date receive the greater of cash balance benefits or the Sonat plan benefits accrued through December 31, 2004. Coastal provides non-contributory pension plans covering substantially all of its U.S. employees. These plans provide benefits based on final average monthly compensation and years of service. Coastal's funding policy was to contribute amounts necessary to these plans to maintain their qualified status under the 74 76 Employee Retirement Income Security Act of 1974, as amended. As a result of our merger with Coastal, these plans will be merged into our existing plans, terminated, or a combination of both. Following our merger with Sonat, and again following our merger with Coastal, we offered an early retirement incentive program for eligible employees of these organizations. These programs offered enhanced pension benefits to individuals who elected early retirement. Charges incurred in connection with the Sonat program were $8 million and those in connection with the Coastal Program have yet to be determined. Other Postretirement Benefits We provide postretirement medical benefits for certain closed groups of retired employees of EPNG, El Paso Tennessee, and Sonat, and limited postretirement life insurance benefits for current and retired employees. Other postretirement employee benefits (OPEB) are prefunded to the extent such costs are recoverable through rates. Coastal also provides postretirement benefits to substantially all of its U.S. employees. Under our early retirement incentive program for Sonat employees, employees of PG&E's Texas Midstream operations, and Coastal employees, participating eligible employees were allowed to keep postretirement medical and life benefits commencing at the later of age 55 or retirement. Total charges associated with these programs and the elimination of retiree benefits for future retirees were $29 million for the Sonat program, $8 million for the PG&E Texas program, and are yet to be determined for the Coastal program. Medical benefits for these closed groups of retirees may be subject to deductibles, co-payment provisions, and other limitations and dollar caps on the amount of employer costs. We have reserved the right to change these benefits. The following table presents the combined pension and postretirement benefits for us and Coastal. Our benefits are presented and computed as of and for the twelve months ended September 30. Coastal's information was determined as of and for the twelve months ended December 31.
POSTRETIREMENT PENSION BENEFITS BENEFITS ----------------- --------------- 2000 1999 2000 1999 ------- ------- ------ ------ (IN MILLIONS) Change in benefit obligation Benefit obligation at beginning of period................. $1,636 $1,711 $ 597 $ 602 Service cost.............................................. 39 42 3 5 Interest cost............................................. 121 109 43 40 Participant contributions................................. -- -- 12 11 Plan amendments........................................... -- (18) -- (13) Settlements, curtailments and special termination benefits............................................... -- 3 -- 6 Acquisition of PG&E's Texas Midstream operations.......... -- -- 8 -- Actuarial (gain) or loss.................................. 16 (103) (19) 21 Benefits paid............................................. (139) (108) (74) (75) ------ ------ ----- ----- Benefit obligation at end of period....................... $1,673 $1,636 $ 570 $ 597 ====== ====== ===== ===== Change in plan assets Fair value of plan assets at beginning of period.......... $2,820 $2,608 $ 155 $ 136 Actual return on plan assets.............................. 482 312 12 10 Employer contributions.................................... 23 8 81 72 Participant contributions................................. -- -- 10 8 Administrative expense.................................... -- -- -- (2) Benefits paid............................................. (139) (108) (70) (69) ------ ------ ----- ----- Fair value of plan assets at end of period................ $3,186 $2,820 $ 188 $ 155 ====== ====== ===== =====
75 77
POSTRETIREMENT PENSION BENEFITS BENEFITS ----------------- --------------- 2000 1999 2000 1999 ------- ------- ------ ------ (IN MILLIONS) Reconciliation of funded status Funded status at end of period............................ $1,513 $1,184 $(382) $(442) Fourth quarter contributions and income................... 2 31 16 15 Unrecognized net actuarial gain........................... (760) (614) (55) (41) Unrecognized net transition obligation.................... (13) (20) 110 123 Unrecognized prior service cost........................... (38) (41) (7) (8) ------ ------ ----- ----- Prepaid (accrued) benefit cost at December 31,............ $ 704 $ 540 $(318) $(353) ====== ====== ===== =====
Included in the above information are plans in which the projected benefit obligation and accumulated benefit obligation for pension plans with accumulated benefit obligations in excess of plan assets were $43 million and $34 million as of December 31, 2000, and $66 million and $59 million as of December 31, 1999. The current liability portion of the postretirement benefits was $46 million as of both December 31, 2000 and 1999. Benefit obligations for us and Coastal are based upon actuarial estimates as described below. Where these assumptions differed, average rates have been presented.
PENSION BENEFITS POSTRETIREMENT BENEFITS -------------------- ------------------------ YEAR ENDED DECEMBER 31, ----------------------------------------------- 2000 1999 1998 2000 1999 1998 ----- ----- ---- ------ ------ ------ (IN MILLIONS) Benefit cost for the plans includes the following components Service cost.................................... $ 38 $ 42 $ 42 $ 3 $ 5 $ 4 Interest cost................................... 121 117 113 43 40 40 Expected return on plan assets.................. (277) (250) (222) (8) (9) (7) Amortization of net actuarial gain.............. (30) (15) (10) (2) (3) (5) Amortization of transition obligation........... (6) (6) (9) 13 16 17 Amortization of prior service cost.............. (3) (1) (1) -- (1) -- Settlements, curtailment, and special termination benefits expense................. -- 1 (1) -- 29 6 ----- ----- ---- ---- --- --- Net benefit cost................................ $(157) $(112) $(88) $ 49 $77 $55 ===== ===== ==== ==== === ===
POSTRETIREMENT PENSION BENEFITS BENEFITS ----------------- -------------- 2000 1999 2000 1999 ------- ------ ----- ----- Weighted average assumptions Discount rate............................................. 7.75% 7.66% 7.75% 7.79% Expected return on plan assets............................ 10.00% 9.98% 5.11% 4.39% Rate of compensation increase............................. 4.44% 4.58% N/A N/A
Actuarial estimates for our postretirement benefits plans assumed a weighted average annual rate of increase in the per capita costs of covered health care benefits of 10 percent in 2000, gradually decreasing to 6 percent by the year 2008. The Coastal estimates assumed rates of 7.8 percent through 2000, gradually decreasing to 6 percent by the year 2004. Assumed health care cost trends have a significant effect on the 76 78 amounts reported for other postretirement benefit plans. A one-percentage point change in assumed health care cost trends would have the following effects:
2000 1999 ----- ----- (IN MILLIONS) One Percentage Point Increase Aggregate of Service Cost and Interest Cost............... $ 1 $ 2 Accumulated Postretirement Benefit Obligation............. $ 25 $ 28 One Percentage Point Decrease Aggregate of Service Cost and Interest Cost............... $ (1) $ (2) Accumulated Postretirement Benefit Obligation............. $(24) $(26)
Plan assets of Coastal's pension plan included Coastal's common stock and Class A common stock, amounting to a total of 8.9 million of shares, after conversion, at December 31, 2000 and 1999. We also participate in several multi-employer pension plans for the benefit of our employees who are union members. Our contributions to these plans were not material for 2000, 1999, or 1998. Retirement Savings Plan We maintain a defined contribution plan covering all of our respective employees. We match 75 percent of participant basic contributions of up to 6 percent, with the matching contribution being made in our stock. Prior to our merger, Coastal matched 100 percent of basic contributions up to 8 percent with matching contributions made in Coastal stock. Amounts expensed under these combined plans were approximately $35 million, $36 million and $35 million for the years ended December 31, 2000, 1999, and 1998, respectively. 12. CAPITAL STOCK We have 50,000,000 shares of authorized preferred stock, par value $0.01 per share, none of which have been issued, but of which 7,500,000 shares have been designated as Series A Junior Participating Preferred Stock and reserved for issuance pursuant to our preferred stock purchase rights plan. On April 15, 1998, we redeemed all 8,000,000 outstanding shares of our $2.125 Cumulative Preferred Stock, Series H. Redemption price for the Series H stock was $25 per share plus accrued dividends of approximately $0.18 to April 15, 1998. Coastal had Preferred Stock, Series A, B and C, and Class A common stock which was exchanged for our common stock at the merger date. The prior year amounts for these preferred shares is not material. 13. STOCK-BASED COMPENSATION We grant stock awards under various stock option plans. We account for these plans using Accounting Principles Board Opinion No. 25 and its related interpretations. Under our stock option plans, we are authorized to issue shares of common stock to employees and non-employee directors pursuant to awards granted as incentive stock options (intended to qualify under Section 422 of the Internal Revenue Code), non-qualified stock options, restricted stock, stock appreciation rights (SARs), phantom stock options, and performance units. We have reserved approximately 53 million shares of common stock for issuance pursuant to existing and future stock awards. As of December 31, 2000, approximately 27 million shares remained unissued. Non-qualified Stock Options We granted non-qualified stock options to our employees in 2000, 1999, and 1998. Our stock options have contractual terms of 10 years and generally vest after completion of one to five years of continuous employment from the grant date. We also granted options to non-employee members of the Board of Directors at fair market value on the grant date that are exercisable immediately. Under the terms of certain plans, we may grant SARs to certain holders of stock options. SARs are subject to the same terms and conditions as the 77 79 related stock options. As of December 31, 2000, we have no SARs outstanding. Coastal granted options to executives, directors and other key employees. These options vest at rates ranging from 15 percent to 33 percent on each anniversary date from the date of grant and expire in five or ten year periods. A summary of our stock options and stock options outstanding as of December 31, 2000, 1999, and 1998 is presented below:
EL PASO STOCK OPTIONS ------------------------------------------------------------------------ 2000 1999 1998 ---------------------- ---------------------- ---------------------- WEIGHTED WEIGHTED WEIGHTED # SHARES OF AVERAGE # SHARES OF AVERAGE # SHARES OF AVERAGE UNDERLYING EXERCISE UNDERLYING EXERCISE UNDERLYING EXERCISE OPTIONS PRICES OPTIONS PRICES OPTIONS PRICES ----------- -------- ----------- -------- ----------- -------- Outstanding at beginning of the year................................ 22,511,704 $32.80 15,331,658 $25.46 13,198,433 $22.86 Granted............................. 1,065,110 $41.35 9,639,750 $41.02 3,651,550 $32.34 Exercised........................... (3,648,752) $25.99 (2,092,953) $18.26 (1,262,775) $17.77 Forfeited........................... (263,911) $38.44 (366,751) $31.15 (255,550) $27.99 ---------- ---------- ---------- Outstanding at end of year............ 19,664,151 $34.43 22,511,704 $32.80 15,331,658 $25.46 ========== ========== ========== Exercisable at end of year............ 12,431,102 $30.51 12,996,454 $26.71 8,486,647 $22.35 ========== ========== ==========
EL PASO OPTIONS OUTSTANDING OPTIONS EXERCISABLE ------------------------------------------------- ----------------------------- NUMBER WEIGHTED AVERAGE WEIGHTED NUMBER WEIGHTED RANGE OF OUTSTANDING REMAINING AVERAGE EXERCISABLE AVERAGE EXERCISE PRICES AT 12/31/00 CONTRACTUAL LIFE EXERCISE PRICE AT 12/31/00 EXERCISE PRICE --------------- ----------- ---------------- -------------- ----------- -------------- $ 7.15 to $21.40 3,468,451 3.6 $15.93 3,468,451 $15.93 $21.41 to $35.70 5,119,933 6.2 $30.32 4,644,633 $29.90 $35.71 to $42.90 9,531,247 8.7 $41.08 2,980,798 $41.01 $42.91 to $71.50 1,544,520 6.9 $48.61 1,337,220 $47.02 ---------- ---------- $ 7.15 to $71.50 19,664,151 7.0 $34.43 12,431,102 $30.51 ========== ==========
Upon the merger with Coastal, we issued approximately 4.4 million El Paso shares for Coastal's outstanding options. As a result, we have presented the information on Coastal's stock options below on an unconverted basis and have not presented information regarding Coastal's outstanding options at December 31, 2000.
COASTAL STOCK OPTIONS ------------------------------------------------------------------------ 2000 1999 1998 ---------------------- ---------------------- ---------------------- WEIGHTED WEIGHTED WEIGHTED # SHARES OF AVERAGE # SHARES OF AVERAGE # SHARES OF AVERAGE UNDERLYING EXERCISE UNDERLYING EXERCISE UNDERLYING EXERCISE OPTIONS PRICES OPTIONS(1) PRICES OPTIONS(1) PRICES ----------- -------- ----------- -------- ----------- -------- Outstanding at beginning of year....... 7,113,709 $25.68 6,604,617 $22.64 5,213,310 $18.12 Granted.............................. 21,268 $51.45 1,809,068 $32.93 2,080,349 $32.72 Exercised............................ (1,800,493) $17.99 (865,688) $17.23 (466,812) $16.15 Revoked or expired................... (57,800) $26.43 (434,288) $26.52 (222,230) $23.84 ---------- --------- --------- Outstanding at end of year............. 5,276,684 $28.40 7,113,709 $25.68 6,604,617 $22.64 ========== ========= ========= Exercisable at end of year............. 1,501,462 $26.46 1,983,595 $19.18 1,706,453 $16.01 ========== ========= =========
--------------- (1) Includes Class A common shares. 78 80 The fair value of each stock option granted is estimated on the date of grant using the Black-Scholes option-pricing model with the following weighted-average assumptions:
EL PASO ASSUMPTIONS: 2000 1999 1998 -------------------- ---- ---- ---- Expected Term in Years...................................... 7 7 5 Expected Volatility......................................... 23.9% 21.9% 20.3% Expected Dividends.......................................... 3.0% 3.0% 3.0% Risk-Free Interest Rate..................................... 5.0% 6.3% 4.6%
COASTAL ASSUMPTIONS: 2000 1999 1998 -------------------- ---- ---- ---- Expected Term in Years...................................... 5 8 8 Expected Volatility......................................... 36.7% 35.8% 22.4% Expected Dividends.......................................... 0.3% 0.8% 0.6% Risk-Free Interest Rate..................................... 5.1% 5.2% 5.6%
The Black-Scholes weighted average fair value of the El Paso options granted during 2000, 1999 and 1998 was $10.16, $11.42, and $7.00, and the weighted average fair value of the Coastal options granted during 2000, 1999 and 1998 was $17.79, $15.22, and $12.77. Pro Forma Net Income and Net Income Per Common Share Had the compensation expense for our combined stock-based compensation plans been determined applying the provisions of SFAS No. 123, Accounting for Stock-Based Compensation, our net income and net income per common share for 2000, 1999, and 1998 would approximate the pro forma amounts below (in millions, except per share data):
DECEMBER 31, 2000 DECEMBER 31, 1999 DECEMBER 31, 1998 ----------------------- ----------------------- ----------------------- AS REPORTED PRO FORMA AS REPORTED PRO FORMA AS REPORTED PRO FORMA ----------- --------- ----------- --------- ----------- --------- SFAS No. 123 charge, pretax...... $ -- $ 109 $ -- $ 179 $ -- $ 75 APB No. 25 charge, pretax........ $ 38 $ -- $ 145 $ -- $ 51 $ -- Net income....................... $ 1,306 $1,259 $ 244 $ 220 $ 132 $ 122 Basic earnings per common share.......................... $ 2.64 $ 2.55 $0.49 $0.45 $0.27 $0.25 Diluted earnings per common share.......................... $ 2.57 $ 2.45 $0.49 $0.44 $0.26 $0.25
The effects of applying SFAS No. 123 in this pro forma disclosure are not indicative of future amounts. SFAS No. 123 does not apply to awards granted prior to the 1995 fiscal year. Restricted Stock Under our various stock-based compensation plans, a limited number of shares of restricted common stock may be granted at no cost to certain key officers and employees. These shares carry voting and dividend rights; however, sale or transfer of the shares is restricted. These restricted stock awards vest over a specific period of time and generally include performance vesting targets. Restricted stock awards representing 0.4 million, 1.4 million, and 0.6 million shares were granted during 2000, 1999, and 1998, respectively, with a weighted average grant date fair value of $34.82, $35.10, and $32.40 per share. At December 31, 2000, 1.5 million shares of restricted stock were outstanding. The value of these shares is determined based on the fair market value on the date performance targets are achieved, and this value is charged to compensation expense ratably over the required service or restriction period. For 2000, 1999, and 1998, these charges totaled $13 million, $69 million, and $29 million. Included in deferred compensation at December 31, 2000, is $69 million related to options that will be converted at the holder's election into common stock at the end of their vesting period. These options met all performance targets in December 2000. 79 81 Performance Units and Phantom Stock Options We award eligible employees phantom stock options that are payable in cash. We also award eligible employees and officers performance units that are payable in cash or stock at the end of the vesting period. The final value of the performance units may vary according to the plan under which they are granted, but is usually based on our common stock price at the end of the vesting period. The value of the performance units is charged ratably to compensation expense over the vesting period with periodic adjustments to account for the fluctuation in the market price of our stock. Amounts charged to compensation expense in 2000, 1999, and 1998 were $25 million, $30 million, and $13 million. Included in the 1999 amount is $22 million related to the accelerated vesting of the performance units due to our merger with Sonat. In March 2001, we paid our phantom stock options, resulting in a charge of $51 million. Employee Stock Purchase Program In October 1999, we implemented an employee stock purchase plan under Section 423 of the Internal Revenue Code. The plan allows participating employees the right to purchase common stock on a quarterly basis at 85 percent of the lower of the market price at the beginning of the plan period or at the end of each calendar quarter. Two million shares of common stock are authorized for issuance under this plan. We issued 346,332 shares at $32.33 per share in 2000, and 139,842 shares at $33.10 per share in 1999. Funds we receive may be used for general corporate purposes. However, we record a liability for the withholdings not yet applied towards the purchase of common stock. We bear all expenses associated with administering the plan, except for costs, including any applicable taxes, associated with the participants' sale of common stock. 14. DISCONTINUED OPERATIONS We are pursuing the disposition of our 50% ownership of ANR Advance Transportation Company, Inc., a trucking operation. ANR Advance is being liquidated in cooperation with other owners. Accordingly, the trucking operations are being reported as a discontinued operation. The net assets being disposed of have been classified in the accompanying balance sheets in Other Assets at December 31, 2000 and 1999. The net assets of the discontinued operations amounted to $3 million at December 31, 2000 and 1999. Operating results of the discontinued operations are shown in the accompanying statements of income. The loss in 1998 of $38 million resulted from a $3 million loss from operations, net of income tax benefits of $2 million, and an estimated loss on disposal of the discontinued operations of $35 million, net of income tax benefits of $19 million. 15. SEGMENT INFORMATION Our business activities are segregated into four segments: Pipelines, Merchant Energy, Field Services, and Production. These segments are strategic business units that offer a variety of different energy products and services. We manage each segment separately as each business requires different technology and marketing strategies. Our Pipelines segment provides natural gas transmission services in the U.S. and internationally. We conduct our activities through seven wholly owned and four partially owned interstate systems along with a liquified natural gas terminalling facility and numerous natural gas storage facilities. Our Merchant Energy segment is involved in a broad range of activities in the energy marketplace, including asset ownership, trading and risk management and financial services. We buy, sell, and trade natural gas, power, crude oil, refined products, coal and other energy commodities throughout the world and own or have interests in 84 power generation plants in 20 countries, four refineries, seven chemical production facilities, and coal operations. Our Field Services segment provides natural gas gathering, storage, products extraction, fractionation, dehydration, purification, compression and intrastate transmission services. Field Services' assets are located 80 82 in some of the most prolific and active production areas in the U.S., including the San Juan Basin, east and south Texas, Louisiana, the Gulf of Mexico, and the Rocky Mountains. Our Production segment is engaged in the exploration for and the acquisition, development, and production of natural gas, oil and natural gas liquids in the major producing basins of the United States. Production has onshore and coal seam operations and properties in 16 states and offshore operations and properties in federal and state waters in the Gulf of Mexico. We also have exploration and production rights in Australia, Brazil, Canada, Hungary, Indonesia, and Turkey. The accounting policies of the individual segments are the same as those described in Note 1. Since earnings on equity investments can be a significant component of earnings in several of our segments, we evaluate segment performance based on EBIT instead of operating income. To the extent practicable, results of operations for the years presented have been reclassified to conform to the current business segment presentation, although such results are not necessarily indicative of the results which would have been achieved had the revised business segment structure been in effect during that period.
SEGMENTS AS OF OR FOR THE YEAR ENDED DECEMBER 31, 2000 ----------------------------------------------------------------- MERCHANT FIELD PIPELINES ENERGY SERVICES PRODUCTION OTHER(1) TOTAL --------- -------- -------- ---------- -------- ------- (IN MILLIONS) Revenue from external customers Domestic....................................... $ 2,492 $38,696 $1,373 $1,080 $ 1,194 $44,835 Foreign........................................ -- 4,426 2 5 -- 4,433 Intersegment revenue............................. 220 353 129 544 (1,246) -- Merger-related costs and asset impairment charges........................................ -- 21 11 93 125 Depreciation, depletion, and amortization........ 376 116 75 611 69 1,247 Operating income (loss).......................... 1,113 583 162 634 (84) 2,408 Other income (loss).............................. 212 356 51 (25) (74) 520 Earnings (loss) before interest and taxes........ 1,325 939 213 609 (158) 2,928 Extraordinary items, net of income taxes......... 89 -- (19) -- -- 70 Assets Domestic....................................... 14,015 14,736 3,753 5,851 3,286 41,641 Foreign........................................ 83 4,018 17 198 57 4,373 Capital expenditures and investments in unconsolidated affiliates...................... 725 1,170 484 2,067 1,082 5,528 Total investments in unconsolidated affiliates... 1,119 2,687 567 7 74 4,454
--------------- (1) Includes Corporate and eliminations as well as our telecommunication and retail operations which are not significant. 81 83
SEGMENTS AS OF OR FOR THE YEAR ENDED DECEMBER 31, 1999 ----------------------------------------------------------------- MERCHANT FIELD PIPELINES ENERGY SERVICES PRODUCTION OTHER(1) TOTAL --------- -------- -------- ---------- -------- ------- (IN MILLIONS) Revenue from external customers Domestic................................ $ 2,612 $19,783 $ 664 $ 663 $ 1,058 $24,780 Foreign................................. -- 2,544 -- 8 -- 2,552 Intersegment revenue...................... 118 395 103 393 (1,009) -- Merger-related costs and asset impairment charges................................. 90 67 8 31 361 557 Ceiling test charges...................... -- -- -- 352 -- 352 Depreciation, depletion, and amortization............................ 408 131 67 449 46 1,101 Operating income (loss)................... 1,025 35 71 (84) (330) 717 Other income (loss)....................... 268 227 59 (1) (51) 502 Earnings (loss) before interest and taxes................................... 1,293 262 130 (85) (381) 1,219 Assets Domestic................................ 14,035 5,259 1,842 4,352 2,712 28,200 Foreign................................. 53 3,391 -- 74 72 3,590 Capital expenditures and investments in unconsolidated affiliates............... 685 1,590 198 1,447 71 3,991 Total investments in unconsolidated affiliates.............................. 1,220 1,937 438 6 11 3,612
--------------- (1) Includes Corporate and eliminations as well as retail operations which are not significant.
SEGMENTS AS OF OR FOR THE YEAR ENDED DECEMBER 31, 1998 ----------------------------------------------------------------- MERCHANT FIELD PIPELINES ENERGY SERVICES PRODUCTION OTHER(1) TOTAL --------- -------- -------- ---------- -------- ------- (IN MILLIONS) Revenue from external customers Domestic............................... $ 2,661 $17,219 $ 372 $ 607 $1,100 $21,959 Foreign................................ -- 1,814 -- -- -- 1,814 Intersegment revenue..................... 101 325 97 377 (900) -- Merger-related costs and asset impairment charges................................ -- -- -- 15 -- 15 Ceiling test charges..................... -- -- -- 1,035 -- 1,035 Depreciation, depletion, and amortization........................... 379 97 55 508 40 1,079 Operating income (loss).................. 1,125 106 75 (859) 62 509 Other income (loss)...................... 261 187 94 25 (161) 406 Earnings (loss) before interest and taxes.................................. 1,386 293 169 (834) (99) 915 Assets Domestic............................... 13,543 3,853 1,669 3,670 1,766 24,501 Foreign................................ 33 2,105 33 87 2,258 Capital expenditures and investments in unconsolidated affiliates.............. 559 827 471 1,521 65 3,443 Total investments in unconsolidated affiliates............................. 972 914 170 6 13 2,075
--------------- (1) Includes Corporate and eliminations as well as retail operations which are not significant. 82 84 The reconciliations of EBIT to income from continuing operations are presented below for the years ended December 31:
2000 1999 1998 ------ ------ ---- (IN MILLIONS) Total EBIT for segments..................................... $2,928 $1,219 $915 Interest and debt expense................................... 950 776 682 Minority interest........................................... 204 93 60 Income tax expense (benefit)................................ 538 93 (3) ------ ------ ---- Income from continuing operations................. $1,236 $ 257 $176 ====== ====== ====
16. SUPPLEMENTAL CASH FLOW INFORMATION The following table contains supplemental cash flow information for the years ended December 31:
2000 1999 1998 ------ ---- ---- (IN MILLIONS) Interest paid........................................... $1,018 $728 $678 Income tax payments (refunds)........................... 61 19 (44)
See Note 2, for a discussion of the non-cash investing transactions related to our acquisitions. 83 85 17. INVESTMENTS IN AND ADVANCES TO UNCONSOLIDATED AFFILIATES (UNAUDITED) We hold investments in various unconsolidated affiliates which are accounted for using the equity method of accounting. Our principal equity method investees are international pipelines, interstate pipelines, power generation plants, and gathering systems. Our investment balance includes unamortized purchase price differences of $402 million and $379 million as of December 31, 2000 and 1999, that are being amortized over the remaining life of the unconsolidated affiliate's underlying assets. Our investments in and advances to our unconsolidated affiliates are as follows:
YEAR ENDED NET DECEMBER 31, OWNERSHIP ---------------- INTEREST 2000 1999 --------- ------ ------ (IN MILLIONS) Alliance Pipeline Limited Partnership.................. 14% $ 216 $ 141 Bolivia to Brazil Pipeline............................. 8% 53 45 CAPSA/CAPEX............................................ 45% 282 145 CE Generation.......................................... 50% 354 334 Chapparal.............................................. 20% 268 373 Citrus Corporation..................................... 50% 474 422 Eagle Point Cogeneration Partnership................... 50% 34 30 East Asia Power........................................ 46% 118 144 Empire State Pipeline.................................. 50% 49 47 Energy Partners........................................ 30% 368 280 Engage Energy US, LP and Engage Energy Canada, LP (through September 2000)............................. 40% -- 79 Great Lakes Gas Transmission, LP....................... 50% 291 320 Iroquois Gas Pipeline System, LP....................... 16% 29 38 Javalina Company....................................... 40% 55 57 Korea Independent Energy Corporation................... 50% 108 -- Midland Cogeneration Venture........................... 44% 198 67 Photon Investors....................................... 42% 136 -- Porto Velho............................................ 50% 99 -- Samalayuca Power....................................... 40% 93 130 Other.................................................. various 1,287 1,220 ------ ------ $4,512 $3,872 ====== ======
84 86 Earnings from our unconsolidated affiliates are as follows for the years ended December 31:
2000 1999 1998 ---- ---- ---- (IN MILLIONS) Alliance Pipeline Limited Partnership....................... $ 12 $ 10 $ 3 Bolivia to Brazil Pipeline.................................. -- 4 -- CAPSA/CAPEX................................................. 4 3 -- CE Generation............................................... 35 24 -- Chapparal Investors......................................... (5) (8) -- Citrus Corporation.......................................... 51 25 24 Eagle Point Cogeneration Partnership........................ 25 22 20 East Asia Power............................................. (32) -- -- Empire State Pipeline....................................... 8 9 11 Energy Partners............................................. 20 18 1 Engage Energy US, LP and Engage Energy Canada, LP (through September 2000)........................................... 11 5 (25) Great Lakes Gas Transmission, LP............................ 52 52 53 Iroquois Gas Pipeline System, LP............................ 7 6 9 Javalina Company............................................ 17 10 (4) Midland Cogeneration Venture................................ 37 16 14 Porto Velho................................................. 1 -- -- Samalayuca Power............................................ 17 17 11 Other....................................................... 132 72 80 ==== ==== ==== $392 $285 $197 ==== ==== ====
As discussed in Note 2, we have, or will, divest our ownership interest in the Empire State pipeline, the Iroquois pipeline, the Stingray pipeline, and the U-T offshore pipeline systems. In October 2000, we terminated the Engage joint venture that was formed in 1997. As a result, the operations were divided into separate entities that are owned and operated independently by each former joint venture partner. Summarized financial information of our proportionate share of unconsolidated affiliates is as follows:
YEAR ENDED DECEMBER 31, -------------------------- 2000 1999 1998 ------ ------ ------ (IN MILLIONS) Operating results data: Revenues and other income.............................. $4,947 $4,275 $4,097 Costs and expenses..................................... 4,411 3,921 3,843 Income from continuing operations...................... 536 354 254 Net income............................................. 368 291 180
DECEMBER 31, ----------------- 2000 1999 ------- ------ Financial position data: Current assets............................................ $ 1,781 $1,419 Non-current assets........................................ 11,100 7,627 Short-term debt........................................... 518 320 Other current liabilities................................. 1,047 964 Long-term debt............................................ 4,330 3,679 Other non-current liabilities............................. 3,045 819 Minority interest......................................... 36 9 Equity in net assets...................................... 3,905 3,255
85 87 The following table shows revenues and charges from our unconsolidated affiliates:
2000 1999 1998 ---- ---- ---- Natural gas sales........................................... $104 -- -- Power purchases............................................. 43 -- -- Management fee income....................................... 81 20 -- Reimbursement for costs..................................... 44 17 4 Interest income............................................. 10 5 -- Interest expense............................................ 49 15 --
Chaparral Investors During 1999, we contributed approximately $120 million of equity capital and assets to a newly formed limited liability company, Chaparral. A third-party financial investor contributed approximately $123 million on which they earn a preferred return. In connection with this transaction, Chaparral formed a wholly owned subsidiary, Mesquite. Merchant Energy manages both Chaparral and Mesquite. In January 2000, we acquired an additional interest in Chaparral in exchange for a $160 million contingent interest promissory note. The maturity date of the note is the earlier of December 2019, or upon the occurrence of events specified in the note. The note carries a variable interest rate not to exceed 12.75 percent. At December 31, 1999, we had a note payable of $121 million to Chaparral which was payable upon demand and carried a variable interest rate which was 6.4%. This note was repaid in 2000. We also had a note receivable from Mesquite which had a balance of $262 million at December 31, 1999. This note was payable on demand and had a variable rate which was 8.3%. This note was repaid by Mesquite in 2000. During 2000, we issued a note payable to Mesquite. The note is payable on demand and had a balance of $241 million at a rate of 7.3% as of December 31, 2000. During the first quarter of 2000, Chaparral completed its acquisitions of several domestic non-utility generation assets including equity interests in eleven natural gas-fired combined generation facilities in California, two natural gas-fired electric generation plants located in Dartmouth, Massachusetts and Pawtucket, Rhode Island, and all the outstanding shares of Bonneville Pacific Corporation, which owns a 50 percent interest in a power generation facility. Chaparral also acquired several operating companies which provide the services required to operate and maintain these newly acquired facilities and a natural gas service company which provides fuel procurement services to eight of Chaparral's natural gas-fired combined generation facilities in California. Chaparral acquired these assets from us in exchange for notes payable in the amount of $385 million. In March 2000, Chaparral's third-party investor increased its overall investment in Chaparral by $1,027 million. The proceeds were used by Chaparral to repay $647 million of notes from us, to make a $278 million contribution to a trust as provided in the Chaparral agreement, to invest in a note with us, and to fund transaction costs. Also, in March 2000, we issued mandatorily convertible preferred stock to a trust we control. Upon the occurrence of certain negative events, the trustee of the trust may be required to remarket this preferred stock on terms that are designed to generate $1 billion to distribute to the third party investor. Under our management agreement with Chaparral, we earn a performance-based management fee. We are also reimbursed for expenses we incur on behalf of Chaparral. For 2000, our management fee related to Chaparral was $100 million and this fee included an $80 million performance-based component and a $20 million reimbursement for costs we incurred on behalf of Chaparral. This fee was collected and recognized ratably throughout the year as management services were provided. We also sell natural gas and buy power from qualifying power facilities owned by Chaparral. Photon Investors During 2000, we contributed $44 million of equity capital and assets to a newly formed limited liability company, Photon Investors, L.L.C., which acquires and holds telecommunication assets. A third-party financial investor contributed $60 million on which they earn a preferred return. In connection with this 86 88 transaction, Photon formed a wholly owned subsidiary, Quanta Investors, L.L.C. A subsidiary of ours manages both Photon and Quanta. During 2000, we entered into a credit agreement with Quanta, with a commitment by us to lend up to $500 million, of which approximately $94 million was advanced and outstanding at December 31, 2000. These amounts are evidenced by a subordinated promissory note, payable the earlier of Quanta's liquidation date or any date agreed by the parties to the note. We also have a demand note payable to Quanta with a balance of approximately $61 million at December 31, 2000. Both the credit agreement and the demand note carry a variable interest rate, which was 9.57% per annum during 2000. Our investment in Photon is being accounted for using the equity method of accounting. El Paso Energy Partners During the third quarter of 2000, Energy Partners completed a public offering of 4.6 million common units. The offering reduced our common units ownership interest from 32.5 percent to 27.8 percent. This transaction had no effect on our general partner interest or our non-managing member interest. Also, in the third quarter, we received $170 million of Series B preference units in exchange for the transfer of the natural gas storage businesses of Crystal Gas Storage, Inc., our wholly owned subsidiary, to Energy Partners. These preference units accrue dividends at a rate of 10% on a cumulative basis and are redeemable at the option of Energy Partners. In the first quarter of 2001, as a result of our merger with Coastal, Energy Partners sold its interest in several offshore assets. These sales consisted of interests in seven natural gas pipeline systems, a dehydration facility and two offshore platforms. Proceeds from these sales were approximately $135 million and resulted in a loss to the partnership of approximately $23 million. As consideration for these sales, we committed to pay Energy Partners a series of payments totaling $29 million. This amount, as well as our proportional share of the losses on the sale of the partnership's assets, will be recorded as a charge in our income statement in the first quarter of 2001. 18. SUPPLEMENTAL SELECTED QUARTERLY FINANCIAL INFORMATION (UNAUDITED) Financial information by quarter is summarized below.
QUARTERS ENDED ----------------------------------------------- DECEMBER 31 SEPTEMBER 30 JUNE 30 MARCH 31 ----------- ------------ ------- -------- (IN MILLIONS, EXCEPT PER COMMON SHARE AMOUNTS) 2000 Operating revenues(1).................................. $16,659 $13,282 $10,242 $9,085 Merger-related costs and asset impairment charges...... 68 3 50 4 Operating income....................................... 690 561 545 612 Income before extraordinary items...................... 354 281 262 339 Extraordinary items, net of income taxes............... (19) -- -- 89 Net income............................................. 335 281 262 428 Basic earnings per common share Income before extraordinary items.................... 0.71 0.57 0.53 0.69 Extraordinary items, net of income taxes............. (0.04) -- -- 0.18 ------- ------- ------- ------ Net income........................................... $ 0.67 $ 0.57 $ 0.53 $ 0.87 ======= ======= ======= ====== Diluted earnings per common share Income before extraordinary items.................... $ 0.68 $ 0.54 $ 0.51 $ 0.67 Extraordinary items, net of income taxes............. (0.04) -- -- 0.18 ------- ------- ------- ------ Net income........................................... $ 0.64 $ 0.54 $ 0.51 $ 0.85 ======= ======= ======= ======
87 89
QUARTERS ENDED ----------------------------------------------- DECEMBER 31 SEPTEMBER 30 JUNE 30 MARCH 31 ----------- ------------ ------- -------- (IN MILLIONS, EXCEPT PER COMMON SHARE AMOUNTS) 1999 Operating revenues(1)................................... $8,011 $7,561 $6,360 $5,400 Merger-related costs and asset impairment charges....... 364 58 131 4 Ceiling test charges.................................... -- -- -- 352 Operating income........................................ 87 309 263 58 Income (loss) before cumulative effect of accounting change................................................ (9) 141 131 (6) Cumulative effect of accounting change, net of income taxes................................................. -- -- -- (13) Net income (loss)....................................... (9) 141 131 (19) Basic earnings (loss) per common share Income (loss) before cumulative effect of accounting change............................................. $(0.02) $ 0.29 $ 0.27 $(0.01) Cumulative effect of accounting change, net of income taxes.............................................. -- -- -- (0.03) ------ ------ ------ ------ Net income (loss)..................................... $(0.02) $ 0.29 $ 0.27 $(0.04) ====== ====== ====== ====== Diluted earnings (loss) per common share Income (loss) before cumulative effect of accounting change............................................. $(0.02) $ 0.28 $ 0.26 $(0.01) Cumulative effect of accounting change, net of income taxes.............................................. -- -- -- (0.03) ------ ------ ------ ------ Net income (loss)..................................... $(0.02) $ 0.28 $ 0.26 $(0.04) ====== ====== ====== ======
--------------- (1) In the fourth quarter of 2000, we restated operating revenues for 1999 and 2000 due to the implementation of Emerging Issues Task Force Issue No. 99-19, Reporting Revenue Gross as a Principal versus Net as an Agent. For the first, second, and third quarters of 2000, operating revenues increased by $695 million, $944 million, and $1,248 million. For the first, second, third and fourth quarters of 1999, operating revenues increased by $485 million, $519 million, $536 million and $727 million. These adjustments had no impact on net income (loss) or earnings per share. 19. SUPPLEMENTAL NATURAL GAS AND OIL OPERATIONS (UNAUDITED) At December 31, 2000, we had interests in natural gas and oil properties that are located primarily in Texas, Louisiana, Oklahoma, Arkansas, New Mexico, and offshore Louisiana and Texas in the Gulf of Mexico. We also have a limited number of natural gas and oil properties in Canada and Brazil as well as exploration and production rights in Australia, Brazil, Canada, Hungary, Indonesia, and Turkey. For purposes of the Supplemental Natural Gas and Oil Operations disclosure, we have presented our natural gas and oil properties on a worldwide basis. In addition, natural gas systems reserves, standardized measure of discounted future net cash flows and the related changes in standardized measure are separately presented for natural gas systems operations. Capitalized costs relating to natural gas and oil producing activities and related accumulated depreciation, depletion and amortization were as follows at December 31:
2000 1999 ------- ------ (IN MILLIONS) Natural gas and oil properties: Costs subject to amortization............................. $10,076 $8,519 Costs not subject to amortization......................... 882 666 ------- ------ 10,958 9,185 Less accumulated depreciation, depletion, and amortization.............................................. 5,399 5,058 ------- ------ $ 5,559 $4,127 ======= ======
88 90 Costs incurred in natural gas and oil producing activities, whether capitalized or expensed, were as follows for the years ended December 31:
2000 1999 1998 ------ ------ ------ (IN MILLIONS) Property acquisition costs: Proved properties...................................... $ 204 $ 157 $ 131 Unproved properties.................................... 177 197 181 Exploration costs........................................ 367 307 279 Development costs........................................ 1,298 771 915 ------ ------ ------ Total costs.................................... $2,046 $1,432 $1,506 ====== ====== ======
Presented below is an analysis of the capitalized costs of natural gas and oil properties by year of expenditure that are not being amortized as of December 31, 2000, pending determination of proved reserves. Capitalized interest of $47 million, $24 million, and $2 million for the years ended December 31, 2000, 1999, and 1998 is included in the presentation below.
CUMULATIVE COSTS EXCLUDED FOR CUMULATIVE BALANCE YEARS ENDED DEC. 31 BALANCE ------------- --------------------- ------------- DEC. 31, 2000 2000 1999 1998 DEC. 31, 1997 ------------- ----- ----- ----- ------------- (IN MILLIONS) Acquisition.............................. $477 $189 $129 $133 $22 Exploration.............................. 283 177 57 40 12 Development.............................. 122 62 35 19 7 ---- ---- ---- ---- --- $882 $428 $221 $192 $41 ==== ==== ==== ==== ===
Projects presently excluded from amortization are in various stages of evaluation. The majority of these costs are expected to be included in the amortization calculation in the years 2001 through 2003. Total amortization expense per Mcfe, including ceiling test charges, was $1.00, $1.64, and $3.08 in 2000, 1999 and 1998. Excluding ceiling test charges, amortization expense would have been $0.91 and $0.99 per Mcfe in 1999 and 1998. Depreciation, depletion, and amortization excludes provisions for the impairment of international projects of $15 million in 2000, $10 million in 1999, and $9 million in 1998. All of our proved properties, with the exception of the proved reserves in Brazil, are located in North America (United States and Canada). The following reserve table presents U.S. operations and excludes approximately 190,000 MMcf equivalents of Canadian proved reserves with 1,139 MMcf equivalents of Canadian production during 2000 and 120,000 MMcf equivalents of Brazilian proved reserves. 89 91 Net quantities of proved developed and undeveloped reserves of natural gas and liquids, including condensate and crude oil, and changes in these reserves, were as follows:
Natural Gas Liquids ------------------------ --------------------- Natural Exploration Natural Exploration Gas and Gas and Systems(1) Production Systems Production ---------- ----------- ------- ----------- (Bcf) (MBbls) Proved reserves, net: January 1, 1998................................... 248 3,665 349 112,676 Revisions of previous estimates................ 2 (421) (68) (15,013) Extensions, discoveries, and other............. 1 637 -- 10,873 Purchases of reserves in place................. -- 582 -- 11,915 Sales of reserves in place..................... -- (314) -- (24,782) Production..................................... (39) (411) (44) (13,905) --- ----- --- ------- December 31, 1998................................. 212 3,738 237 81,764 Revisions of previous estimates................ 22 (126) 36 (6,956) Extensions, discoveries and other.............. -- 934 -- 15,953 Purchases of reserves in place................. -- 573 -- 11,494 Sales of reserves in place..................... -- (163) -- (4,639) Production..................................... (36) (416) (24) (10,300) --- ----- --- ------- December 31, 1999................................. 198 4,540 249 87,316 Revisions of previous estimates................ 10 (249) 7 (576) Extensions, discoveries and other.............. -- 1,240 -- 13,196 Purchases of reserves in place................. -- 577 -- 7,589 Sales of reserves in place..................... -- (19) -- (609) Production..................................... (33) (517) (25) (11,614) --- ----- --- ------- December 31, 2000................................. 175 5,572 231 95,302 === ===== === ======= Proved developed reserves December 31, 1998.............................. 212 2,410 237 56,637 December 31, 1999.............................. 198 2,593 249 53,403 December 31, 2000.............................. 175 2,877 231 55,044
--------------- (1) Includes regulated natural gas and oil properties owned by Colorado Interstate Gas Company. Total proved reserves for natural gas systems exclude storage gas and liquids volumes. The natural gas systems storage gas volumes are 199,937, 221,509 and 225,853 MMcf and storage liquids volumes are approximately 237, 301 and 232 MBbls at December 31, 2000, 1999 and 1998. Total proved reserves for natural gas equivalents include approximately 130,000, 152,000 and 162,000 MMcf associated with volumetric production payments we sold to unaffiliated entities for the years 2000, 1999 and 1998. 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 our control. The reserve data represents only estimates. Reservoir engineering is a subjective process of estimating underground accumulations of natural gas and oil that cannot be measured in an exact manner. The significant changes to reserves, other than purchases, sales or production, are due to reservoir performance in existing fields and from drilling additional wells in existing fields. There have been no major discoveries or other events, favorable or adverse, that may be considered to have caused a significant change in the estimated proved reserves since December 31, 2000. 90 92 Results of operations from producing activities by fiscal year were as follows at December 31:
2000 1999 1998 ------ ----- ------- (IN MILLIONS) Net revenues: Sales to external customers............................ $1,088 $ 651 $ 587 Affiliated sales....................................... 544 393 377 ------ ----- ------- Total.......................................... 1,632 1,044 964 Production costs......................................... (240) (202) (180) Depreciation, depletion, and amortization................ (603) (440) (494) Ceiling test charges..................................... -- (352) (1,035) ------ ----- ------- Results of operations from producing activities before tax.................................................... 789 50 (745) Income tax (expense) benefit............................. (265) (6) 274 ------ ----- ------- Results of operations from producing activities (excluding corporate overhead and interest costs)...... $ 524 $ 44 $ (471) ====== ===== =======
The standardized measure of discounted future net cash flows relating to proved natural gas and oil reserves follows at December 31:
2000 1999 1998 ---------------------------- ---------------------------- ---------------------------- NATURAL GAS EXPLORATION NATURAL GAS EXPLORATION NATURAL GAS EXPLORATION SYSTEMS AND PRODUCTION SYSTEMS AND PRODUCTION SYSTEMS AND PRODUCTION ----------- -------------- ----------- -------------- ----------- -------------- (IN MILLIONS) Future cash inflows............. $ 474 $ 46,585 $229 $11,825 $256 $ 8,063 Future production and development costs............. (110) (7,895) (74) (3,824) (79) (2,937) Future income tax expenses...... (116) (12,487) (49) (1,757) (57) (901) ----- -------- ---- ------- ---- ------- Future net cash flows........... 248 26,203 106 6,244 120 4,225 10% annual discount for estimated timing of cash flows......................... (89) (10,807) (41) (2,212) (51) (1,482) ----- -------- ---- ------- ---- ------- Standardized measure of discounted future net cash flows......................... $ 159 $ 15,396 $ 65 $ 4,032 $ 69 $ 2,743 ===== ======== ==== ======= ==== =======
For the calculations in the preceding table, estimated future cash inflows from estimated future production of proved reserves were computed using year-end market natural gas and oil prices. We may receive amounts different than the standardized measure of discounted cash flow for a number of reasons, including changes in prices and the effects of our hedging activities. 91 93 The following are the principal sources of change in the standardized measure of discounted future net cash flows at December 31:
2000 1999 1998 ---------------------------- ---------------------------- ---------------------------- NATURAL GAS EXPLORATION NATURAL GAS EXPLORATION NATURAL GAS EXPLORATION SYSTEMS AND PRODUCTION SYSTEMS AND PRODUCTION SYSTEMS AND PRODUCTION ----------- -------------- ----------- -------------- ----------- -------------- (IN MILLIONS) Sales and transfers of oil and gas produced, net of production costs............................. $(52) $(1,747) $(36) $ (849) $(34) $(782) Net changes in prices and production costs............................. 150 12,333 (5) 1,031 3 (728) Extensions, discoveries and improved recovery, less related costs...... -- 5,938 -- 896 -- 502 Changes in estimated future development costs................. -- (422) -- 9 -- 36 Development costs incurred during the period........................ -- 269 -- 160 -- 297 Revisions of previous quantity estimates......................... 34 (1,207) 28 (308) 6 (735) Accretion of discount............... 4 349 6 263 8 410 Net change in income taxes.......... (42) (5,975) 3 (473) 6 547 Purchases of reserves in place...... -- 1,739 -- 680 -- 321 Sale of reserves in place........... -- (15) -- (207) -- (490) Change in production rates, timing and other......................... -- 102 -- 87 -- (259) ---- ------- ---- ------ ---- ----- Net change.......................... $ 94 $11,364 $ (4) $1,289 $(11) $(881) ==== ======= ==== ====== ==== =====
None of the amounts include any value for natural gas systems storage gas and liquids volumes, which was approximately 39 Bcf for CIG, 107 Bcf for ANR, 54 Bcf for Mid Michigan Gas Storage Company and 237 MBbls of liquids for CIG at the end of 2000. 92 94 SCHEDULE II EL PASO CORPORATION VALUATION AND QUALIFYING ACCOUNTS YEARS ENDED DECEMBER 31, 2000, 1999, AND 1998 (IN MILLIONS)
CHARGED BALANCE AT TO COSTS CHARGED BALANCE BEGINNING AND TO OTHER AT END DESCRIPTION OF PERIOD EXPENSES ACCOUNTS DEDUCTIONS OF PERIOD ----------- ---------- -------- -------- ---------- --------- 2000 Allowance for doubtful accounts............... $50 $95 $(1) $(22)(a) $122 Allowance for price risk management activities................................. 39 157 -- (3)(b) 193 Valuation allowance on deferred tax assets.... 6 -- -- (3) 3 1999 Allowance for doubtful accounts............... $48 $14 $(2) $(10)(a) $ 50 Allowance for price risk management activities................................. 28 21 -- (10)(b) 39 Valuation allowance on deferred tax assets.... 5 -- 1 -- 6 1998 Allowance for doubtful accounts............... $69 $ 4 $ 6 $(31)(a) $ 48 Allowance for price risk management activities................................. 25 23 -- (20)(b) 28 Valuation allowance on deferred tax assets.... 19 -- 4 (18)(c) 5
--------------- (a)Primarily accounts written off. (b)Primarily liquidation of positions on which allowance was established. (c)$11 million of this deduction was credited to additional paid-in capital for the utilization of Zilkha Energy Company's net operating loss (NOL) carryforward and $7 million was credited to deferred tax assets for a waiver of Gulf States Gas Pipeline Company's NOL carryforward. 93 95 ITEM 7. FINANCIAL STATEMENTS AND EXHIBITS We file the following exhibits as part of this Report:
EXHIBIT NO. DESCRIPTION ------- ----------- 23.1 -- Consent of Independent Accountants, PricewaterhouseCoopers LLP 23.2 -- Independent Auditors' Consent, Deloitte & Touche, LLP 23.3 -- Consent of Huddleston & Co., Inc. 99.1 -- Opinion of Independent Accountants, PricewaterhouseCoopers LLP 99.2 -- Opinion of Independent Accountants, Deloitte & Touche, LLP 99.3 -- Annual Report on Form 10-K for El Paso CGP Corporation for the year ended December 31, 2000 (incorporating by reference the filing by El Paso CGP Corporation of its Annual Report on Form 10-K for the fiscal year ended December 31, 2000, Commission File No. 1-7176).
94 96 SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, as amended, El Paso Corporation has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized on the 23rd day of March 2001. EL PASO CORPORATION Registrant By /s/ JEFFREY I. BEASON ----------------------------------- Jeffrey I. Beason Senior Vice President and Controller (Chief Accounting Officer) 97 EXHIBIT INDEX
EXHIBIT NO. DESCRIPTION ------- ----------- 23.1 -- Consent of Independent Accountants, PricewaterhouseCoopers LLP 23.2 -- Independent Auditors' Consent, Deloitte & Touche, LLP 23.3 -- Consent of Huddleston & Co., Inc. 99.1 -- Opinion of Independent Accountants, PricewaterhouseCoopers LLP 99.2 -- Opinion of Independent Accountants, Deloitte & Touche, LLP 99.3 -- Annual Report on Form 10-K for El Paso CGP Corporation for the year ended December 31, 2000 (incorporating by reference the filing by El Paso CGP Corporation of its Annual Report on Form 10-K for the fiscal year ended December 31, 2000, Commission File No. 1-7176).