ITEM 1. BUSINESS
GENERAL
In December 1996, EPNG acquired EPTPC. In March 1998, the energy marketing operations of El Paso Marketing Services Company were transferred to EPTPC. On December 31, 1998, EPTPC became a direct subsidiary of EPEC after a tax-free internal reorganization. As a result of the March 1998 transfer and the December 1998 reorganization, the merchant services operations of EPEM, the international operations of EPEI, and the field services operations of EPFS became subsidiaries of EPTPC. Also, as part of the reorganization, EPTPC transferred certain assets and liabilities of corporate and discontinued operations to EPEC. EPTPC continues to own the interstate systems known as the TGP system, the East Tennessee system, and the Midwestern system, as well as certain discontinued operations not included in the transfer to EPEC. At December 31, 1998, EPEC owns 100 percent of the common equity and greater than 80 percent of the combined equity value of EPTPC. The remaining combined equity value of EPTPC consists of $300 million of outstanding preferred stock that is traded on the New York Stock Exchange.
The Company's principal operations include the interstate and intrastate transportation, gathering and processing of natural gas; the marketing of natural gas, power, and other commodities; and the development and operation of energy infrastructure facilities worldwide. The Company owns or has interests in over 17,800 miles of interstate and intrastate pipeline connecting the nation's principal natural gas supply regions to three of the largest consuming regions in the United States, namely the Gulf Coast, the Northeast and the Midwest. The Company's natural gas transmission operations are comprised of three interstate pipeline systems: the Tennessee Gas pipeline, the Midwestern Gas Transmission pipeline, and the East Tennessee Natural Gas pipeline.
In addition to its interstate transmission services, the Company provides related services, including natural gas gathering, products extraction, dehydration, purification, compression, and intrastate transmission. These services include gathering of natural gas from more than 10,000 natural gas wells with approximately 11,000 miles of gathering lines, and 23 natural gas processing and treating facilities located in some of the most prolific and active production areas of the United States, including the San Juan and Permian Basins and in east Texas, south Texas, Louisiana, and the Gulf of Mexico. The Company conducts intrastate transmission operations through its interests in four Texas intrastate systems, which include the Oasis Pipeline running from west Texas to Katy, Texas, the Channel Pipeline extending from south Texas to the Houston Ship Channel, and the Shoreline and Tomcat gathering systems which gather gas from offshore Texas. The Company also provides intrastate transportation in north Louisiana through its Gulf States Pipeline that runs from the Texas border to Ruston, Louisiana. The Company's marketing activities include the marketing and trading of natural gas, power, and petroleum products, as well as providing integrated price risk management services associated with these commodities. The Company also participates in the development and ownership of domestic power generation facilities, and other power-related assets and joint ventures.
The Company's international activities focus on the development and operation of international energy infrastructure projects and include ownership interests in three major operating natural gas transmission systems in Australia, and natural gas transmission systems and power generation facilities currently in operation or under construction in Argentina, Bolivia, Brazil, Chile, the Czech Republic, Hungary, Indonesia, Mexico, Pakistan, Peru, the United Kingdom, Bangladesh, the Philippines and China. The Company also has an interest in three operating domestic power generation plants.
SEGMENTS
Beginning in 1998, the Company segregated its business activities into four segments: Tennessee Gas Pipeline segment, El Paso Field Services segment, El Paso Energy Marketing segment, and El Paso Energy International segment. These segments are strategic business units that offer a variety of different energy products and services. They are managed separately, as each business unit requires different technology and
marketing strategies. For information relating to operating revenues, operating income, EBIT, and identifiable assets attributable to each segment, see Item 8, Financial Statements and Supplementary Data, Note 9.
Set forth below is a description of the principal business activities conducted by each of the Company's segments:
In addition, the Company participates in the development and ownership of domestic power generation projects.
TENNESSEE GAS PIPELINE
The TGP system. The TGP system consists of approximately 14,700 miles of pipeline with a design capacity of 5,512 MMcf/d. During 1998, TGP transported natural gas volumes averaging approximately 80 percent of its capacity. The TGP system serves the northeast section of the U.S., including the New York City and Boston metropolitan areas. The multiple-line system begins in the gas-producing regions of south Texas and Louisiana, including the Gulf of Mexico.
The Midwestern system. The Midwestern system consists of approximately 400 miles of pipeline with a design capacity of 785 MMcf/d. During 1998, Midwestern transported natural gas volumes averaging approximately 35 percent of its capacity. The Midwestern system extends from a connection with the TGP system at Portland, Tennessee, to Chicago and principally serves the Chicago metropolitan area.
The East Tennessee system. The East Tennessee system consists of approximately 1,100 miles of pipeline with a design capacity of 675 MMcf/d. During 1998, East Tennessee transported natural gas volumes averaging approximately 45 percent of its capacity. The East Tennessee system serves the states of Tennessee, Virginia and Georgia and connects with the TGP system in Springfield and Lobelville, Tennessee.
Other. The Company increased its ownership interest in the Portland Natural Gas Transmission ("Portland") system from 17.8 percent to approximately 19 percent in April 1998. Portland is a 292-mile interstate natural gas pipeline with initial capacity of 178 MMcf/d extending from the Canadian border near Pittsburg, New Hampshire to Dracut, Massachusetts. In April 1998, Portland secured $256 million in non-recourse project financing. Construction started in June 1998, with an estimated total cost of $423 million. Portland commenced commercial operations in March of 1999.
From time to time, the Company holds open seasons in an effort to capitalize on pipeline expansion opportunities. Currently, TGP has completed an open season for the Eastern Express Project 2000 to provide gas transportation for the growing markets in the Northeast. As a result, TGP filed an application before FERC for the expansion in the first quarter of 1999 to begin service in 2000. TGP has received approval from FERC to construct an international border crossing at Reynosa, Tamaulipas, Mexico, and interconnect with Pemex Gas y Petroquimica Basica, a Mexican state-owned company ("Pemex") to provide the import of gas from Mexico. The border crossing service is expected to begin in 1999.
REGULATORY ENVIRONMENT
The interstate 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.
In the mid-1980s, FERC initiated a series of actions which ultimately had the effect of substantially removing interstate pipelines from the gas purchase and resale business and confining their role to transportation of gas owned by others. In Order No. 436, issued in 1985, FERC began this transition by requiring interstate pipelines to provide non-discriminatory access to their facilities for all transporters of natural gas. This requirement enabled consumers to purchase their own gas and have it transported on the interstate pipeline system, rather than purchase gas from the pipelines. The transition was completed with Order No. 636, issued in 1992, in which FERC required all interstate pipelines to "unbundle" their sales and transportation services so that the transportation services they provided to third parties would be "comparable" to the transportation services provided to gas owned by the pipeline. FERC's stated purpose was to ensure that the pipelines' monopoly over the transportation of natural gas did not distort the competition in the gas producer sales market, which had, by then, been essentially deregulated.
One of the obstacles to this transition was the existence of long-term gas purchase contracts between pipelines and producers which required the pipelines to take or pay for a significant percentage of the gas the producer was capable of delivering. While FERC did not deal with this issue initially, it eventually adopted rate recovery procedures which facilitated negotiations between pipelines and producers to address take-or-pay issues. Such procedures were established in Order Nos. 500, 528 and 636, in the last of which FERC provided that pipelines could recover 100 percent of the costs prudently incurred to terminate their gas purchase obligations. In July 1996, the Court of Appeals issued its decision upholding, in large part, Order No. 636.
In December 1994, TGP filed for a general rate increase with FERC and in October 1996, FERC approved the settlement resolving that proceeding. The settlement included a structural rate design change that resulted in a larger portion of TGP's transportation revenues being dependent upon throughput. One party, a competitor of TGP, filed a petition for review of the FERC orders with the Court of Appeals. The Court of Appeals remanded the case to FERC to respond to the competitor's argument that TGP's cost allocation methodology deterred the development of market centers (centralized locations where buyers and sellers can physically exchange gas) and, at FERC's request, comments were filed in January 1999.
For a further discussion of regulatory matters, see Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations.
MARKETS AND COMPETITION
The interstate systems face varying degrees of competition from alternative energy sources, such as electricity, hydroelectric power, coal, and fuel oil. The potential consequences of proposed and ongoing restructuring and deregulation of the electric power industry are currently unclear. It may benefit the natural gas industry by creating more demand for natural gas turbine generated electric power, or it may hamper demand by allowing more effective use of surplus electric capacity through increased wheeling as a result of open access. At this time, the Company is not projecting a significant change in natural gas demand as a result of such restructuring.
Customers of TGP 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. Substantially all of the revenues of TGP are generated under long-term natural gas transmission contracts. Contracts representing approximately 70 percent of TGP's firm transportation capacity will be expiring over the next two years, principally in November 2000. Although TGP cannot predict how much capacity will be resubscribed, a majority of the expiring contracts cover service to northeastern markets, where there is currently little excess capacity. Several projects, however, have been proposed to deliver incremental volumes to these markets. Although TGP is actively pursuing the renegotiation, extension and/or replacement of these contracts, TGP cannot give any assurance that it will be able to extend or replace these
contracts (or a substantial portion thereof) or that the terms of any renegotiated contracts will be as favorable to TGP as the existing contracts.
In a number of key markets, TGP faces competitive pressure from other major pipeline systems, enabling 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 the foregoing competitive factors.
EL PASO FIELD SERVICES
EPFS was formed for the purpose of owning, operating, acquiring and constructing natural gas gathering, processing and other related facilities. Effective January 1, 1996, EPNG transferred its non-regulated assets to EPFS. These assets included major natural gas gathering systems in the San Juan and Permian Basins. From this initial asset base, EPFS began to implement plans to increase natural gas gathering and processing volumes through a strategy of project development, acquisitions, and joint ventures.
EPFS provides its customers with wellhead-to-mainline field services, including natural gas gathering and transportation, products extraction, dehydration, purification and compression. EPFS also provides intrastate natural gas transmission services. EPFS, together with EPEM, provides fully bundled natural gas services with a broad range of pricing options as well as financial risk management products. EPFS also provides well-ties and offers real-time information services, including electronic wellhead gas flow measurement. EPFS services are provided under a variety of fee structures including fixed fee per decatherm, floating fee per decatherm indexed to the applicable local area price of gas, or percentage of products sold.
In August 1998, the Company completed the expansion of the Coyote Gulch Treating Plant which increased capacity from 120 MMcf/d to 240 MMcf/d, providing an additional outlet for coal seam gas production in southwestern Colorado.
In September 1998, the Company completed the Global Compression project, a $45 million capital investment that consists of 40,000 horsepower of compression, gas dehydration facilities, and 54 miles of pipeline looping. The project lowered wellhead pressures and increased production rates for 70 percent of the wells from which EPFS gathers in the San Juan Basin.
In September 1998, EPFS sold its natural gas gathering, treating, and processing assets in the Anadarko Basin to Midcoast Energy Resources, Inc. for $35 million.
The following table provides information as of December 31, 1998, concerning the natural gas gathering and transportation facilities, as well as natural gas gathered/transported for the three years ended December 31:
The following table provides information concerning the processing facilities for the three years ended December 31:
The following table provides information concerning natural gas gathering and transportation facilities in which EPFS owns a minority interest and accounts for under the equity method:
- ------------
(1) Mileage amounts are approximate for the total systems and have not been reduced to reflect EPFS's net ownership.
(2) All capacity information reflects EPFS's net interest and is subject to increases or decreases depending on operating pressures and point of delivery into or out of the system.
(3) Throughput for Oasis Pipeline was in El Paso Energy Marketing segment in 1997.
In January 1999, the Company and Leviathan Gas Pipeline Partners, L.P. ("Leviathan") entered into an agreement where the Company will sell, for approximately $85 million, all of its interest in Viosca Knoll Gathering Company to Leviathan except for a 1 percent interest in profits and capital. The transaction was approved by Leviathan's board of directors in January 1999, and at a special meeting held March 5, 1999, the Leviathan unitholders approved an increase in the authorized number of common units required to complete the acquisition. The transaction is expected to close in the second quarter of 1999.
Competition
EPFS operates in a highly competitive environment that includes independent natural gas gathering and processing companies, intrastate pipeline companies, natural gas marketers, and oil and gas producers. EPFS competes for throughput primarily based on price, efficiency of facilities, gathering system line pressures, availability of facilities near drilling activity, service, and access to favorable downstream markets.
EL PASO ENERGY MARKETING
EPEM, the Company's merchant services and trading business, utilizes its extensive knowledge of the marketplace, natural gas pipeline and power transmission infrastructure, supply aggregation, transportation management and valuation, storage and integrated price risk management to provide customers with flexible solutions to meet their energy supply and financial risk management requirements. EPEM markets and trades natural gas, power, and petroleum products in the United States, Canada and Mexico. EPEM has emerged as one of North America's largest energy marketing and trading companies.
EPEM contracts to purchase specific natural gas volumes from suppliers at various times and points of receipt, arranges for the aggregation and transportation of such natural gas, and negotiates the sale of these volumes to utilities (including local distribution companies and power plants), municipalities, and a variety of industrial and commercial end users. EPEM seeks to maintain a balanced portfolio of supply and demand
contracts and a diverse natural gas supplier and customer base. During 1998, it served over 400 producers/suppliers and approximately 2,000 sales customers in 26 states and shipped natural gas supplies on 65 pipelines.
EPEM utilizes a broad range of risk management instruments to manage its fixed-price purchase and sales commitments and reduce its exposure to market price volatility. EPEM trades futures contracts and options on the New York Mercantile Exchange and trades swaps and options in over-the-counter financial markets with other major energy merchants. Market risks are managed on a portfolio basis, subject to parameters established by a risk control committee that operates independently from commercial operations. Market risk in EPEM's commodity derivative portfolio is measured on a daily basis utilizing a Value-at-Risk (VAR) model to determine the maximum potential one-day unfavorable impact on its earnings. For additional information regarding the use of financial instruments, see Item 7A, Quantitative and Qualitative Disclosures About Market Risk and Item 8, Financial Statements and Supplementary Data, Note 4.
Set forth below are the marketed gas, power and petroleum volumes for the years ended December 31:
- ---------------
(1) Includes financial trades.
Competition
EPEM operates in a highly competitive environment. Its primary competitors include: (i) marketing affiliates of major oil and gas producers; (ii) marketing affiliates of large local distribution companies; (iii) marketing affiliates of other interstate and intrastate pipelines; and (iv) independent energy marketers with varying scopes of operations and financial resources. EPEM competes on the basis of price, access to production, understanding of pipeline and transmission networks, imbalance management, and experience in the marketplace.
EL PASO ENERGY INTERNATIONAL
EPEI was formed for the purpose of investing in integrated energy projects with an emphasis on developing infrastructure to gather, transport and use natural gas in northern Mexico and certain Latin American countries. The focus of international project pursuit has expanded to include power generation and to include investments located in Australia, Asia, Europe and other Latin American countries. Set forth below are brief descriptions, by region, of the projects that are either operational or in various stages of development.
Acquisitions and greenfield development projects are subject to a higher level of commercial and financial risk in foreign countries. Accordingly, EPEI has adopted a risk mitigation strategy to reduce risks to more acceptable and manageable levels. EPEI's practice is to select experienced partners with a history of success in commercial operations. Individual partners are generally chosen based on the complementary competencies which they offer to the various joint ventures formed or to be formed. EPEI designs and implements a formal due diligence plan on every project it pursues, and contracts are negotiated to secure fuel supply, manage operating and maintenance costs and, when possible, index revenues and denominate transactions in U.S. dollars. EPEI also obtains political risk insurance when deemed appropriate, through the Overseas Private Investment Corporation, the Multilateral Investment Guarantee Agency, or a private insurer.
Latin America and Mexico
Samalayuca Power Project -- The Company owns a 30 percent interest in a 700 MW combined cycle gas fired power plant in Samalayuca, Mexico. The first, second, and third units commenced commercial operations in May, September, and December 1998, respectively. Comision Federal de Electricidad, the
Mexican government-owned electric utility ("CFE") operates the plant under a 20-year lease. Upon expiration of the lease term, ownership of the plant will be transferred to CFE.
Samalayuca Pipeline -- This 45-mile 212 MMcf/d pipeline system commenced gas deliveries in December 1997. The pipeline delivers natural gas to the Samalayuca Power Project from EPNG's existing pipeline system in west Texas and Pemex's pipeline system in northern Mexico. This system consists of 22 miles of pipeline in the U.S. (currently owned by EPNG) and 23 miles of pipeline in Mexico (currently 40 percent owned by the Company and 10 percent owned by EPNG).
Aguaytia Project -- The Company owns a 24 percent interest in an integrated natural gas and power generation project near Pucallpa, located in central Peru. The project consists of a 302 Bcf natural gas field, a natural gas processing facility, a 71-mile natural gas liquids pipeline to a fractionation facility, a 126-mile natural gas pipeline to a 155 MW simple cycle power plant, and a 250-mile 220 KV power transmission line interconnecting with the Peruvian grid at Paramonga. The project began operations in July 1998.
CAPSA -- The Company has an effective 45 percent interest in CAPSA, a privately held integrated energy company in Argentina. CAPSA was incorporated in 1977 for the purpose of producing, selling and exploring for liquid hydrocarbons. CAPSA's assets include a 100 percent ownership interest in the Diadema Oil Field and a 55 percent ownership interest in CAPEX, a publicly traded company on the Argentine and Luxembourg stock exchanges that owns the 382 MW (currently being expanded to 650 MW) Agua del Cajon gas fired power plant in western Argentina. This plant has been fully operational since 1995 and buys natural gas from CAPEX's Agua del Cajon gas field. CAPEX also owns a 24 percent interest in the 76 MW Energia del Sur gas fired power plant in southern Argentina.
Triunion Energy Company -- In January 1998, the Company, CAPEX and InterEnergy formed a new development company named Triunion Energy Company ("Triunion Energy") to identify and develop new energy related projects in Latin America. Triunion Energy currently owns a 20 percent interest in an exploration and production project in Charagua, Bolivia, as well as a 22 percent interest in an approved project to build a $380 million, 325 mile, natural gas pipeline that will cross the Andes Mountains connecting natural gas production in Argentina's Neuquen Basin to customers in Concepcion, Chile. Construction of the pipeline commenced in early 1998 and is expected to be completed in late 1999.
Manaus Power Project -- The Company owns 100 percent of a 250 MW power plant in Manaus, the capital city of the state of Amazonas in northern Brazil. Power from the plant is currently sold under a four-year contract to Electronorte, the local electric company. The first phase of the project commenced operations in February 1998. The second phase commenced operations in March 1998 and the third phase commenced operations in June 1998. See Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations for additional discussion of the Manaus power project.
Bolivia to Brazil Pipeline -- The Company is part of a consortium that is constructing a 2,000 mile pipeline from Santa Cruz, Bolivia to Sao Paulo, Brazil, with a southern lateral to Porto Alegre, Brazil. The pipeline will transport natural gas to the largest unserved market in the western hemisphere (approximately 100 million people). The pipeline is expected to be in service in early 1999. The Company's interest in the project is approximately 8 percent.
Parana Power Project -- The Company has an approximate 30 percent interest in a consortium to build a 480 MW natural gas fired power plant in the state of Parana, in southern Brazil. The power plant will be located in Araucaria, Brazil. The electricity will be purchased by Companhia Paranaense de Energia, an integrated electric utility providing generation, transmission, and distribution of electricity to all regions of the state of Parana. The plant will be fueled by natural gas provided from the Bolivia to Brazil pipeline. Final negotiation and signing of a power purchase agreement will take place in early 1999 with financial close expected in the fourth quarter of 1999. Commercial operations are expected to commence in late 2000.
Costanera -- In July 1998, the Company acquired 100 percent of KLT Power, Inc. ("KLT Power"), the international business unit of Kansas City Power and Light Company. KLT Power, was established in 1993, to develop, finance, own, and operate independent power projects in selected markets worldwide. KLT Power owns a 12 percent interest in Central Costanera, the largest thermal-power plant in Argentina consisting of
2,167 MW of power generation and a 7.8 percent interest in Central Termoelectrica Buenos Aires, S.A., a 328 MW combined cycle power plant in Buenos Aires.
Europe
EMA Power -- The Company owns a 50 percent controlling interest in a 70 MW power plant located in Dunaujvaros, Hungary. The electricity generated at the plant is consumed by Dunaferr Kft., the largest steel mill in Hungary. Approval has been given to expand the capacity of the electric generating plant to 140 MW and construction is scheduled to commence in late 1999.
Kladno Power -- In May 1997, the Company acquired a 31 percent interest in a 338 MW natural gas and coal fired expansion and upgrade of an existing 25 MW cogeneration facility located approximately 19 miles northwest of Prague, in the Czech Republic. The Company sold a 13 percent interest in the project to one of the original partners under a buy back option granted by the Company in June 1997. The Company expects to purchase a similar amount in 1999 from another partner under a similar option agreement. Non-recourse project financing was finalized in June 1997, and commercial operations are expected to commence in the fourth quarter of 1999.
Fife Power -- In September 1998, the Company acquired a 50 percent interest in the first Scottish independent power project located in Fife. The existing plant consists of a simple cycle natural gas fired turbine generating 75 MW, which commenced operations in the fourth quarter of 1998. Under Phase II, a steam turbine will be added to produce a total combined-cycle generating capacity of 115 MW. Financial close for Phase II is expected to occur in early 1999, and commercial operation is expected to commence in early 2001.
Enfield -- In December 1998, the Company acquired a 25 percent interest in Enfield Energy Center Limited. The 396 MW combined cycle natural gas turbine power plant is under construction near London, England and is expected to be operational by October 1999.
Asia Pacific
Australian Pipelines -- The Company owns a 30 percent interest in the Moomba to Adelaide pipeline system, a 488-mile natural gas pipeline in southern Australia and the Ballera to Wallumbilla pipeline system, a 470-mile natural gas pipeline in southwestern Queensland.
In March 1998, the Company, through its 33.3 percent interest in Epic Energy (WA) Pipeline Trust venture, purchased the 925-mile Dampier-to-Bunbury natural gas pipeline in western Australia. This 550 MMcf/d pipeline system serves a number of western Australian markets, including industrial end-users. An expansion of the Dampier-to-Bunbury pipeline is currently underway to supply additional natural gas to Alcoa, Worsley and Wesfarmers. The expansion, scheduled for completion in fourth quarter of 1999, will expand the pipeline capacity to 635 MMcf/d.
Sengkang Project -- The Company has a 50 percent interest in a producing natural gas field with proven reserves of 533 Bcf and a 47.5 percent interest in a 135 MW power plant in Sengkang, South Sulawesi, Indonesia. The electricity produced by the power plant is sold to PLN, the national electric utility, under a long-term power purchase agreement. The power plant began simple cycle commercial operation in September 1997, making it one of the first independent power plants to operate in Indonesia. Combined cycle completion was in September 1998. For a discussion related to the effects on the project of the devaluation of the Indonesian rupiah, see Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations.
Kabirwala Power -- The Company owns a 42 percent interest in a 151 MW natural gas fired power plant currently under construction in Kabirwala, Pakistan. Commercial operation is expected to commence in the second quarter of 1999. The power plant will sell electricity to the State Water and Power Development Authority.
Haripur -- The Company owns a 50 percent interest in a consortium formed to construct a 115 MW oil and gas-fired power generation facility in Haripur, Bangladesh. The plant will sell power to the Bangladesh Power Development Board under a 15-year power purchase agreement. The plant is expected to be in service by the end of May 1999.
East Asia Power -- In 1998, the Company executed agreements to acquire a 46 percent interest in East Asia Power Resources Corporation ("EAPRC"), a publicly traded company in the Philippines. EAPRC owns and operates three power generation facilities in the Philippines and owns an interest in one power generation facility in China, with a total generating capacity of 289 MW. EAPRC also has options to acquire two additional power generation facilities in the Philippines with an aggregate generating capacity of 123 MW. Electric power generated by the facilities is supplied to a diversified base of customers including National Power Corporation, the state-owned utility, private distribution companies and industrial users. This acquisition was completed in February 1999.
Other Projects
The Company owns interests in three operating domestic power generation plants consisting of a 17.5 percent interest in a 240 MW power plant in Springfield, Massachusetts and a 50 percent interest in two additional cogeneration projects in Florida with a combined generating capacity of 220 MW.
CORPORATE AND OTHER OPERATIONS
Corporate and other operations include certain liabilities of EPTPC's discontinued operations and businesses.
ENVIRONMENTAL
A description of the Company's environmental activities is included in Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations, and is incorporated by reference herein.
EMPLOYEES
The Company had approximately 2,100 full-time employees on December 31, 1998. The Company has no collective bargaining arrangements, and no significant changes in the workforce have occurred since December 31, 1998.
EXECUTIVE OFFICERS OF THE REGISTRANT
The executive officers of EPTPC as of March 16, 1999, are set forth below. For dates prior to August 1, 1998 (the effective date of the holding company reorganization), references to positions held with EPEC refer instead to positions held with EPNG.
Mr. Wise became the Chairman of the Board, President and Chief Executive Officer of EPTPC in December 1996. Mr. Wise has been Chairman of the Board of EPEC since January 1994 and Chief Executive Officer since January 1990. In July 1998, Mr. Wise also became the President of EPEC. He was President of EPEC from April 1989 to April 1996. From March 1987 until April 1989, Mr. Wise was an Executive Vice President of EPEC. From January 1984 to February 1987, he was a Senior Vice President of EPEC. Mr. Wise is a member of the Board of Directors of Battle Mountain Gold Company and is the chairman of the Board of EPNG and Leviathan Gas Pipeline Company, the general partner of Leviathan Gas Pipeline Partners, L.P.
Mr. Austin has been Executive Vice President and Chief Financial Officer of EPTPC since June 1997. From December 1996 until June 1997, he was Senior Vice President and Chief Financial Officer. Mr. Austin has been Executive Vice President of EPEC since May 1995. He has been Chief Financial Officer of EPEC since April 1992. He was Senior Vice President of EPEC from April 1992 to April 1995. He was Vice President, Planning and Treasurer of Burlington Resources Inc. ("BR") from November 1990 to March 1992 and Assistant Vice President, Planning of BR from January 1989 to October 1990.
Mr. Richards has been Executive Vice President of EPTPC since June 1997. From December 1996 until June 1997, he was Senior Vice President. Mr. Richards has been Executive Vice President of EPEC since December 1996. From January 1991 until December 1996, he was Senior Vice President of EPEC. He was Vice President from June 1990 to December 1990. He was Senior Vice President, Finance and Human Resources of Meridian Minerals Company, a wholly owned subsidiary of BR, from October 1988 to June 1990.
Mr. White has been Executive Vice President and General Counsel of EPTPC since June 1997. From December 1996 until June 1997, he was Senior Vice President and General Counsel. Mr. White has been Executive Vice President of EPEC since December 1996 and General Counsel of EPEC from March 1991. He was Senior Vice President and General Counsel of EPEC from March 1991 until December 1996. From March 1991 to April 1992, he was also Corporate Secretary of EPEC. For more than five years prior to that time, Mr. White was a partner in the law firm of Holland & Hart.
Executive officers hold offices until their successors are elected and qualified, subject to their earlier removal.
ITEM 2.
ITEM 2. PROPERTIES
A description of the Company's properties is included in Item 1, Business, and is incorporated by reference herein.
The Company is of the opinion that it has generally satisfactory title to the properties owned and used in its businesses, subject to the liens for current taxes, liens incident to minor encumbrances, and easements and restrictions that do not materially detract from the value of such property or the interests therein or the use of such properties in its businesses. The Company believes that its physical properties are adequate and suitable for the conduct of its business in the future.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
See Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations, Commitments and Contingencies, Legal Proceedings, which is incorporated herein by reference.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None
PART II
ITEM 5.
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
Following the acquisition by EPEC, a subsidiary of EPEC became the sole holder of EPTPC's common stock, par value $.01 per share (the "Common Stock"). The Common Stock was delisted from the New York Stock Exchange, and there is no longer a trading market for such securities. The Series A Preferred Stock is listed for trading on the New York Stock Exchange under the trading symbol "EPG_p".
As part of the tax-free internal reorganization, EPEC became the sole holder of EPTPC's 1,971 shares of common stock.
The declaration of dividends on EPTPC capital stock is at the discretion of its Board of Directors. The Board of Directors has not adopted a dividend policy as such; subject to legal and contractual restrictions, its decisions regarding dividends are based on all considerations that in its business judgment are relevant at the time, including past and projected earnings, cash flows, economic, business and securities market conditions and anticipated developments concerning EPTPC's business and operations.
Dividends on the Series A Preferred Stock are payable when, as, and if declared by EPTPC's Board of Directors. Dividends on such Series A Preferred Stock accrue, whether or not declared, on a daily basis. The dividend rate on the Series A Preferred Stock is 8 1/4% of $50 per share per annum (2.0625% per quarter). The dividend payment dates on such shares are March 31, June 30, September 30, and December 31, in each year. All dividends payable on outstanding shares of the Series A Preferred Stock of quarterly periods ending on or prior to December 31, 1998, have been paid in full.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
In March 1998, the energy marketing operations of El Paso Marketing Services Company were transferred to EPTPC. On December 31, 1998, EPEC, the Company's ultimate parent, completed a tax-free internal reorganization of its assets and operations and those of its subsidiaries in accordance with a private letter ruling from the IRS. As a result of the March 1998 transfer and the December 1998 reorganization, the merchant services operations of EPEM, the international operations of EPEI, and the field services operations of EPFS became subsidiaries of EPTPC. Also, as part of the reorganization, EPTPC transferred certain assets and liabilities of corporate and discontinued operations to EPEC. These transactions were treated as a transfer of ownership between entities under common control and accounted for in a manner similar to a pooling of interests. Accordingly, the Company's financial statements have been restated to reflect these transactions for all periods presented. The consolidated selected financial data as of December 31, 1998, and 1997 and for the years ended December 31, 1998, 1997, and 1996 were derived from the audited consolidated financial statements of the Company. The consolidated selected financial data as of December 31, 1996, 1995, and 1994 and for the years ending 1995 and 1994 is unaudited and was derived from the accounting records of the Company. The consolidated selected financial data as of December 31, 1998, 1997, and 1996, reflect the acquisition of EPTPC by EPEC. In the opinion of EPTPC's management, the combined selected financial data of the Company as of December 31, 1996, 1995, and 1994 and for the years ending 1995 and 1994 includes all adjusting entries (consisting only of normal recurring adjustments) necessary to present fairly the information set forth therein.
- ---------------
(a) Increases in operating revenues, total assets and combined equity between 1995 and 1996 are primarily due to (i) the growth of the energy marketing businesses through the acquisitions of Eastex Energy, Inc. and Premier Gas Company in late 1995, (ii) the transfer on January 1, 1996, of EPNG's non-regulated gathering and processing operations and (iii) the acquisition of EPTPC by EPEC.
(b) Reflects extraordinary losses as a result of the retirement of long-term debt in the debt realignment immediately prior to the acquisition by EPEC.
ITEM 7.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
GENERAL
In December 1996, EPNG acquired EPTPC. In March 1998, the energy marketing operations of El Paso Marketing Services Company were transferred to EPTPC. On December 31, 1998, EPTPC became a direct subsidiary of EPEC after a tax-free internal reorganization. As a result of the March 1998 transfer and the December 1998 reorganization, the merchant services operations of EPEM, the international operations of EPEI, and the field services operations of EPFS became subsidiaries of EPTPC. The value of the transfers associated with the tax-free reorganization was $667 million, which represented the book value of those items exchanged at the date of transfer. Also, as part of the reorganization, EPTPC transferred certain assets and liabilities of corporate and discontinued operations to EPEC. EPTPC continues to own the interstate systems known as the TGP system, the East Tennessee system, and the Midwestern system, as well as certain discontinued operations not included in the transfer to EPEC. At December 31, 1998, EPEC owns 100 percent of the common equity and greater than 80 percent of the combined equity value of EPTPC. The remaining combined equity value of EPTPC consists of $300 million of outstanding preferred stock that is traded on the New York Stock Exchange. The tax-free reorganization has been treated as a transfer of ownership between entities under common control and accounted for in a manner similar to a pooling of interests. Accordingly, all information included herein has been restated as though the transactions occurred at the beginning of the earliest period presented.
RESULTS OF OPERATIONS
The Company adopted the provisions of SFAS No. 131, Disclosures about Segments of an Enterprise and Related Information, effective December 31, 1998. Accordingly, the Company has segregated its business activities into four segments: Tennessee Gas Pipeline segment, El Paso Field Services segment, El Paso Energy Marketing segment, and El Paso Energy International segment. These segments are strategic business units that offer a variety of different energy products and services. They are managed separately as each business segment requires different technology and marketing strategies. Certain business segments' earnings are largely derived from the earnings of equity investments. Accordingly, the Company evaluates segment performance based on EBIT. The results of operations have been restated to reflect for all periods presented the tax-free internal reorganization discussed above.
Consolidated EBIT for the year ended December 31, 1998, increased 37 percent to $471 million compared to $344 million in the year ago period. Consolidated EBIT for the year ended December 31, 1997, was $13 million lower than for the same period of 1996. Variances are discussed in the segment results below.
SEGMENT RESULTS
To the extent practicable, results of operations for 1997 and 1996 have been reclassified to conform to the current business segment presentation and the effect of the tax-free internal reorganization, although such results are not necessarily indicative of the results which would have been achieved had the revised business segment structure or the tax-free internal reorganization been in effect during those periods. Operating revenues and expenses by segment include intersegment sales and expenses which are eliminated in consolidation. Because of energy commodity price volatility, the Company believes that gross margin (revenue less cost of sales), rather than operating revenue, provides a more accurate indicator for the El Paso Field
Services and the El Paso Energy Marketing segments. For a further discussion of the individual segments, see Item 8, Financial Statements and Supplementary Data, Note 9.
TENNESSEE GAS PIPELINE
YEAR ENDED DECEMBER 31, 1998 COMPARED TO YEAR ENDED DECEMBER 31, 1997
Operating revenues for the year ended December 31, 1998, were $32 million lower than for the same period of 1997 primarily because of lower throughput resulting from warmer average temperatures in the northeastern and midwestern markets and a downward revision in the amount of recoverable interest on GSR costs.
Operating expenses for the year ended December 31, 1998, were $60 million lower than for the same period of 1997 primarily due to lower system fuel usage associated with operating efficiencies attained during the period of lower throughput, reduced operation and maintenance expenses largely due to lower payroll costs, and lower franchise taxes.
Other -- net for the year ended December 31, 1998, was $12 million higher than for the same period of 1997 due to interest income on a favorable sales and use tax settlement and gains on the sale of assets.
YEAR ENDED DECEMBER 31, 1997 COMPARED TO YEAR ENDED DECEMBER 31, 1996
Operating revenues for the year ended December 31, 1997, were $1 million higher than for the same period of 1996 primarily due to new system rates on TGP which went into effect November 1, 1996. The increase was offset by reduced revenues attributable to the sale of the Bastian Bay assets whose revenues are included in the 1996 total.
Operating expenses for the year ended December 31, 1997, were $50 million lower than for the same period of 1996, primarily due to lower labor and benefit costs attributable to a reduction in staffing levels which occurred throughout the latter half of 1996 and the first quarter of 1997, as well as lower legal costs and operating and maintenance costs. The decrease in operating expenses was partially offset by an increase in depreciation expense as a result of the amortization of additional acquisition cost assigned to utility plant, as well as new lower fuel retention rates starting in the second quarter of 1997.
Other -- net for the year ended December 31, 1997, was $44 million lower than for the same period of 1996 due to the recognition in February 1996 of a gain on the sale of the Company's 50 percent general partnership interest in Tenneco Mobile Bay Gathering Co., a favorable legal settlement in the second quarter of 1996, and lower equity income from unconsolidated subsidiaries in 1997.
EL PASO FIELD SERVICES
YEAR ENDED DECEMBER 31, 1998 COMPARED TO YEAR ENDED DECEMBER 31, 1997
Total gross margin for the year ended December 31, 1998, was $21 million higher than for the same period of 1997. The increase in the gathering and treating margin primarily resulted from higher gathering rates compared to 1997, an increase in gathering and treating volumes largely attributable to the acquisition of PacifiCorp's Texas Gulf Coast ("TPC") gathering and processing subsidiaries in December 1997, and the inclusion of the results of operations of Channel Pipeline ("Channel"), in El Paso Field Services segment beginning January 1998 versus the El Paso Energy Marketing segment. The decrease in the processing margin was largely attributable to lower liquids prices during 1998 compared to the same period of 1997. Liquids prices directly impact EPFS's processing revenues. During 1998, liquids prices were at their lowest level since 1990, and the Company expects this trend to continue through 1999. The Company attempts to mitigate the impact of lower liquids prices by utilizing hedging strategies where possible.
Operating expenses for the year ended December 31, 1998, were $24 million higher than for the same period of 1997 primarily as a result of additional expenses associated with the addition of TPC and Channel as well as higher general and administrative expenses.
Other -- net for the year ended December 31, 1998, was $7 million higher than for the same period of 1997 reflecting higher earnings from equity investments and higher capitalized interest.
YEAR ENDED DECEMBER 31, 1997 COMPARED TO YEAR ENDED DECEMBER 31, 1996
Total gross margin for the year ended December 31, 1997, was $32 million higher than for the same period of 1996. The increase in the gathering and treating margin and the processing margin was primarily the result of higher natural gas prices in the San Juan Basin and an increase in gathering and treating volumes due to the acquisition of Cornerstone Natural Gas, Inc. in June 1996.
Operating expenses for the year ended December 31, 1997, were $8 million higher than for the same period of 1996 primarily due to the acquisition of Cornerstone Natural Gas, Inc. partially offset by lower benefit expenses.
EL PASO ENERGY MARKETING
YEAR ENDED DECEMBER 31, 1998 COMPARED TO YEAR ENDED DECEMBER 31, 1997
Total gross margin for the year ended December 31, 1998, was $21 million higher than for the same period of 1997. Increases in total gross margin in 1998 reflect a fundamental shift in focus initiated by the energy marketing business segment from a short-term positional trading operation to a long-term, asset-based origination, trading, and risk management operation. In 1998, such energy activities emphasized long-term power and gas contract management and related energy services for power and natural gas customers, including independent power producers, utilities and end users. Trading activities, while substantially increasing in volume in 1998, are primarily used to manage risk in long-term contract positions. Partially offsetting the increase in gross margin was the impact of reporting the operations of Channel in El Paso Field Services segment versus El Paso Energy Marketing segment beginning in January 1998. Effective December 31, 1998, the operations related to power trading were transferred to El Paso Power Services, a subsidiary of EPEC.
Operating expenses for the year ended December 31, 1998, were $15 million lower than for the same period of 1997. The decrease was attributable to the 1997 restructuring of the marketing organization and the transfer of Channel operations as mentioned above.
YEAR ENDED DECEMBER 31, 1997 COMPARED TO YEAR ENDED DECEMBER 31, 1996
Total gross margin for the year ended December 31, 1997, was $41 million lower than for the same period of 1996. The decrease resulted from generally lower industry-wide gas marketing margins in the second quarter of 1997, as well as extreme market volatility which negatively impacted the Company's natural gas marketing activities and trading positions during the first quarter of 1997. Partially offsetting this decrease was generally higher volumes from the assignment of contracts in the third quarter of 1997 and higher industry-wide gas marketing margins in the third and fourth quarters of 1997.
Operating expenses for the year ended December 31, 1997, were $15 million lower than for the same period of 1996 primarily due to lower general and administrative expenses and a decrease in depreciation expense.
EL PASO ENERGY INTERNATIONAL
YEAR ENDED DECEMBER 31, 1998 COMPARED TO YEAR ENDED DECEMBER 31, 1997
Operating revenues for the year ended December 31, 1998, were $45 million higher than for the same period of 1997 due to the consolidation for financial reporting purposes of the Manaus Power project in May 1998 after acquiring an additional ownership interest and an increase in revenue attributable to the EMA Power project which the Company began reporting on a consolidated basis in July 1997.
Operating expenses for the year ended December 31, 1998, were $49 million higher than for the same period of 1997 primarily due to costs related to the consolidation of the EMA Power and Manaus Power projects and increased general and administrative expenses largely due to higher project development costs reflecting an increase in project-related activities in 1998.
Other -- net for the year ended December 31, 1998, was $27 million higher than for the same period of 1997 primarily due to increased equity earnings, a gain on the sale of surplus power equipment, and the recognition of certain net gains from project-related activities.
As EPEI's projects move from the development stage to the operational stage, it is common to recognize one-time gains and fees, which may include management fees, development fees, financing fees, and gains on the sell-down of ownership interests. The Company anticipates additional one-time events may result in the recognition of income or expense in the future.
YEAR ENDED DECEMBER 31, 1997 COMPARED TO YEAR ENDED DECEMBER 31, 1996
Operating revenues and operating expenses for the year ended December 31, 1997, were $24 million lower and $6 million lower, respectively, than for the same period of 1996. The decreases were due to the sale of 70 percent of the Company's interests in two natural gas pipeline systems in Australia in 1996. Following the sale, the Company's retained interests in the Australian natural gas pipelines operations were accounted for by the equity method. In addition, partially offsetting the net decrease was the EMA Power project which the Company began reporting on a consolidated basis in July 1997.
Other -- net for the year ended December 31, 1997, was $14 million higher than for the same period of 1996 primarily due to the recognition of project-related activity income, higher interest income, and increased equity earnings.
CORPORATE EXPENSES, NET
YEAR ENDED DECEMBER 31, 1998 COMPARED TO YEAR ENDED DECEMBER 31, 1997
Net corporate expenses for the year ended December 31, 1998, were $23 million lower than for the same period of 1997. The decrease results from lower benefit costs, an increase in investment income, and nonrecurring gains.
YEAR ENDED DECEMBER 31, 1997 COMPARED TO YEAR ENDED DECEMBER 31, 1996
Net corporate expenses for the year ended December 31, 1997, were $11 million higher than for the same period of 1996 due primarily to the discontinuance of El Paso Energy Credit Corporation's commercial activities, the sale of Tenneco Ventures, and the recognition of a deferred gain on the sale of certain investments which occurred in 1996. In addition, benefit costs were higher in 1997.
INTEREST AND DEBT EXPENSE
YEAR ENDED DECEMBER 31, 1998 COMPARED TO YEAR ENDED DECEMBER 31, 1997
Interest and debt expense for the year ended December 31, 1998 was $11 million higher than for the same period in 1997 primarily due to an increase in long-term borrowings. The increase was partially offset by a decrease in short-term borrowings, and the 1997 interest on the rate refund to TGP's customers.
YEAR ENDED DECEMBER 31, 1997 COMPARED TO YEAR ENDED DECEMBER 31, 1996
Interest and debt expense for the year ended December 31, 1997 was $10 million lower than for the same period in 1996 primarily due to the reduction of EPTPC's revolving credit facility in 1997.
INCOME TAX EXPENSE
YEAR ENDED DECEMBER 31, 1998 COMPARED TO YEAR ENDED DECEMBER 31, 1997
Income tax expense for 1998 was $94 million compared to $73 million for 1997. The effective tax rate was 29 percent and 36 percent for 1998 and 1997, respectively. The effective tax rate for 1998 was lower than 1997 primarily as a result of increased consolidated foreign income subject to foreign tax rates different than U.S. tax rates, increased equity income from unconsolidated foreign affiliates recorded net of foreign income taxes for which no provision for U.S. income tax is required, and lower state income taxes.
YEAR ENDED DECEMBER 31, 1997 COMPARED TO YEAR ENDED DECEMBER 31, 1996
Income tax expense for 1997 was $73 million compared to $43 million for 1996. The effective tax rate was 36 percent and 21 percent for 1997 and 1996, respectively. The effective tax rate for 1997 was higher than 1996 primarily as a result of the 1996 reversal of a $38 million valuation allowance for deferred tax assets.
1996 EXTRAORDINARY LOSS
In 1996, in preparation for the acquisition by EPEC, Old Tenneco initiated a realignment of its indebtedness. Upon completion of the debt realignment transactions, the Company is only responsible for its remaining debt which was not tendered, exchanged, defeased or otherwise retired (approximately $265 million of such debt remained outstanding immediately after the acquisition by EPEC). The Company recognized an after-tax extraordinary charge of $234 million related to the debt realignment immediately prior to the acquisition by EPEC.
LIQUIDITY AND CAPITAL RESOURCES
CASH FROM OPERATING ACTIVITIES
Net cash provided by operating activities was $804 million for the year ended December 31, 1998, compared to $507 million for 1997. The increase was primarily due to a rate refund made to TGP's customers in the first quarter of 1997, higher net tax refunds in 1998, and changes in working capital. The increase was partially offset by lower GSR collections in 1998.
CASH FROM INVESTING ACTIVITIES
Net cash used in investing activities was $814 million for the year ended December 31, 1998. Investment activities included expenditures for joint ventures, equity investments, and capital expenditures. Expenditures related to joint ventures and equity investments were primarily attributable to the El Paso Energy International segment. Internally generated funds, supplemented by other financing activities, were used to fund these expenditures.
The Company's planned capital and investment expenditures for 1999 of approximately $850 million are primarily for expansion of international operations and domestic unregulated operations, pipeline systems activities and other facilities, and computer and communication system enhancements.
Funding for capital expenditures, acquisitions, and other investing expenditures is expected to be provided by internally generated funds, commercial paper issuance, available capacity under existing credit facilities, the issuance of other long-term debt or equity, and/or contributions from EPEC.
CASH FROM FINANCING ACTIVITIES
Net cash provided by financing activities was $3 million for the year ended December 31, 1998. In October 1998, TGP issued debentures due 2028 for net proceeds of $391 million. These proceeds, supplemented by internally generated funds, were used to retire long-term debt, pay dividends, fund capital and equity investments, and for other corporate purposes.
Future funding for long-term debt retirements, dividends, and other financing expenditures is expected to be provided by internally generated funds, available capacity under existing credit facilities, the issuance of long-term debt or equity, and/or contributions from EPEC.
LIQUIDITY
The Company relies on cash generated from internal operations as its primary source of liquidity, supplemented by its available credit facilities and commercial paper program. In October 1997, EPNG established a new $750 million five-year revolving credit and competitive advance facility and a new $750 million 364-day renewable revolving credit and competitive advance facility (collectively, the "Revolving Credit Facility"). EPTPC and TGP are also parties to the Revolving Credit Facility. In connection with the establishment of the Revolving Credit Facility, EPTPC's revolving credit facility was terminated, and the outstanding balance of $417 million was financed under the five-year portion of the new Revolving Credit Facility with TGP designated as the borrower. The availability under the Revolving Credit Facility is expected to be used for general corporate purposes including, but not limited to, backstopping EPNG's and TGP's $1 billion commercial paper programs.
In August 1998, EPEC became a guarantor of EPNG's Revolving Credit Facility. In October 1998, the $750 million 364-day portion of the Revolving Credit Facility was amended to extend the termination date to October 27, 1999. In addition, in October 1998, the Revolving Credit Facility was amended to permit TGP to issue commercial paper, provided that the total amount of commercial paper outstanding at EPNG and TGP is equal to or less than the unused capacity under the Revolving Credit Facility. The interest rate on the Revolving Credit Facility is 40 basis points above LIBOR, with the spread varying based on EPEC's long-term debt credit rating.
The availability of borrowings under the Company's credit agreements is subject to certain specified conditions, which management believes the Company currently meets. 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 since the specified dates).
In March 1997, TGP issued $300 million aggregate principal amount of 7 1/2% debentures due 2017, $300 million aggregate principal amount of 7% debentures due 2027, and $300 million aggregate principal amount of 7 5/8% debentures due 2037. Proceeds of approximately $883 million, net of issuance costs, were used to repay a portion of EPTPC's credit facility and for general corporate purposes.
In September 1998, TGP filed a shelf registration permitting TGP to offer up to $600 million (including $100 million carried forward from a prior shelf registration) of debt securities. In October 1998, TGP issued $400 million aggregate principal amount of 7% debentures due 2028. Proceeds to TGP were approximately $391 million, net of issuance costs. Approximately $300 million of the proceeds were used to repay TGP's short-term indebtedness under the Revolving Credit Facility and the remainder were used by TGP for general corporate purposes. After this issuance, TGP has $200 million of capacity remaining under its existing shelf registration.
In August 1998, EPTPC retired its outstanding 10% debentures in the amount of $38 million.
COMMITMENTS AND CONTINGENCIES
Indonesia
The Company owns a 47.5 percent interest in a power generating plant in Sengkang, South Sulawesi, Indonesia. Under the terms of the project's power purchase agreement, PLN purchases power from the Company in Indonesian rupiah indexed to the U.S. dollar at the date of payment. Due to the devaluation of the rupiah, the cost of power to PLN has significantly increased. PLN is currently unable to pass this increase in cost on to its customers without creating further political instability. PLN has requested financial aid from the Minister of Finance to help ease the effects of the devaluation. PLN has been paying the Company in rupiah indexed to the U.S. dollar at the rate in effect prior to the rupiah devaluation, with a commitment to pay the balance when financial aid is received. The difference between the current and prior exchange rate has resulted in an outstanding balance due from PLN of $9.4 million at December 31, 1998. The Company continues to meet with PLN on a regular basis to resolve the payment in arrears issue but has been unsuccessful to date. Recently, the Company has met and discussed its situation and concerns with the World Bank, the International Monetary Fund, the Overseas Private Investment Corporation, and the U.S. Treasury Department in an attempt to achieve a resolution through the Indonesian Minister of Finance. The Company will meet with PLN in April 1999 to discuss payments in arrear and the terms of a contract rationalization process proposed by PLN. The Company has informed PLN that all payments in arrear must first be received as a prerequisite to any further discussions on contract rationalization. The Company cannot predict with certainty the outcome of such discussions. The Company's total investment in the Sengkang project was approximately $25 million at December 31, 1998. Additionally, the Company has provided specific recourse guarantees of up to $6 million for loans from the project lenders. All other project debt is non-recourse. The Company has political risk insurance on the Sengkang project. The Company believes the current economic difficulties in Indonesia will not have a material adverse effect on the Company's financial position, results of operations, or cash flows.
Brazil
The Company owns 100 percent of a 250 MW power plant in Manaus, Brazil. Power from the plant is currently sold under a four-year contract to Electronorte, denominated in Brazilian real. Due to the devaluation of the real in January 1999, Manaus suffered an $831,000 exchange loss on the December invoice. There is no provision in the contract to recover the effects of the devaluation on this invoice. However, future invoices are covered under a provision in the contract entitling the Company to recover a substantial portion of any future devaluation. The Company believes the current economic difficulties in Brazil will not have a material adverse effect on the Company's financial position, results of operations, or cash flows.
The contract for the Manaus power project provides for delay damages to be paid to Electronorte if the specified construction schedule was not met. Completion of the project was delayed beyond the originally scheduled completion dates provided in the contract and such delays have resulted in a claim by Electronorte for delay damages. The Company is in discussions with Electronorte regarding such claim. In any event, the Company has the right under its construction contract to assert claims against the construction contractor for such delay damages and believes that any such damages will not have a material adverse effect on the Company's financial position, results of operations, or cash flows.
Capital Commitments
At December 31, 1998, the Company had capital and investment commitments of $245 million, which are expected to be funded through internally generated funds and/or incremental borrowings. The Company's other planned capital and investment projects are discretionary in nature, with no substantial capital commitments made in advance of the actual expenditures.
Purchase Obligations
In connection with the financing commitments of certain joint ventures, TGP has entered into unconditional purchase obligations for products and services totaling $77 million at December 31, 1998. TGP's annual obligations under these agreements are $21 million for the years 1999 and 2000, $11 million for the year 2001, $4 million for the years 2002 and 2003, and $16 million in total thereafter. Excluded from these amounts is TGP's obligation to purchase 30 percent of the output of the Great Plains coal gasification project's original design capacity through July 2009. In January 1997, TGP executed a settlement of this contract as part of its GSR negotiations, recorded the related liability, and, in the third quarter of 1997, purchased an annuity for $42 million to fund the expected remaining monthly demand requirements of the contract which, under the settlement, continue through January 2004.
Operating Leases
The Company leases certain property, facilities and equipment under various operating leases. In addition, 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 certain events, to purchase the plant for a price sufficient to pay the amount of the $77 million construction financing, plus interest and certain 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. EPEC and EPNG unconditionally guaranteed all obligations of EPNC under the lease.
Minimum annual rental commitments at December 31, 1998, were as follows:
Rental expense for operating leases for the years ended December 31, 1998, 1997, and 1996 was $14 million, $11 million, and $11 million, respectively.
Guarantees
At December 31, 1998, EPTPC had guarantees of up to $37 million in connection with various projects. EPEC has issued guarantees and letters of credit associated with a number of the Company's projects including certain international projects.
Rates and Regulatory Matters
In July 1998, FERC issued a Notice of Proposed Rulemaking ("NOPR") in which it seeks comments on a wide range of initiatives to change the manner in which short-term (less than one year) transportation markets are regulated. Among other things, the NOPR proposes the following: (i) removing the price cap for the short-term capacity market; (ii) establishing procedures to make pipeline and shipper-owned capacity comparable; (iii) auctioning all available short-term pipeline capacity on a daily basis with the pipeline unable to set a reserve price above variable costs; (iv) changing policies or pipeline penalties, nomination procedures and services; (v) increasing pipeline reporting requirements; (vi) permitting the negotiation of terms and conditions of service; and (vii) potentially modifying the procedures for certificating new pipeline
construction. Also in July 1998, FERC issued a Notice of Inquiry ("NOI") seeking comments on FERC's policy for pricing long-term capacity. Comments on the NOPR and NOI are due in April 1999, and it is unclear when and what action, if any, FERC will take in connection with the NOPR and NOI and the comments received in response to them.
In February 1997, TGP filed a settlement with FERC of all issues related to the recovery of its GSR and other transition costs and related proceedings (the "GSR Stipulation and Agreement"). In April 1997, FERC approved the settlement. Under the terms of the GSR Stipulation and Agreement, TGP is entitled to collect up to $770 million from its customers, $693 million through a demand surcharge and $77 million through an interruptible transportation surcharge. As of December 31, 1998, the demand portion had been fully collected and $41 million of the interruptible transportation portion had been collected. There is no time limit for collection of the interruptible transportation surcharge portion. The terms of the GSR Stipulation and Agreement also provide for a rate case moratorium through November 2000 (subject to certain limited exceptions) and an escalating rate cap, indexed to inflation, through October 2005, for certain of TGP's customers. Under the terms of the GSR Stipulation and Agreement, TGP is required to refund to customers amounts collected in excess of each customer's share of transition costs.
In December 1994, TGP filed for a general rate increase with FERC and in October 1996, FERC approved a settlement resolving that proceeding. The settlement included a structural rate design change that results in a larger portion of TGP's transportation revenues being dependent upon throughput. Under the stipulation, TGP's refund obligation was approximately $185 million, inclusive of interest, of which $161 million was refunded to customers in March 1997 and June 1997 with the remaining $24 million refund obligation offset against GSR recoveries in accordance with particular customer elections. TGP provided a reserve for these rate refunds as revenues were collected. One party, a competitor of TGP, filed a Petition for Review of the FERC orders with the Court of Appeals. The Court of Appeals remanded the case to FERC to respond to the competitor's argument that TGP's cost allocation methodology deterred the development of market centers (centralized locations where buyers and sellers can physically exchange gas). At FERC's request, comments were filed in January 1999.
All cost of service issues related to TGP's 1991 general rate proceeding were resolved pursuant to a settlement agreement approved by FERC in an order which now has become final. However, cost allocation and rate design issues remained unresolved. In July 1996, following an ALJ's decision on these cost and design issues, FERC ruled on certain issues but remanded to the ALJ the issue of the proper allocation of TGP's New England lateral costs. In July 1997, FERC issued an order denying rehearing of its July 1996 order but clarifying that, among other things, although the ultimate resolution as to the proper allocation of costs would be applied retroactively to July 1, 1995, the cost of service settlement does not allow TGP to recover from other customers any amounts that TGP may ultimately be required to refund. In February 1999, petitions for review of the July 1996 and July 1997 FERC orders were denied by the Court of Appeals. In the remand proceeding, the ALJ issued his decision on the proper allocation of the New England lateral costs in December 1997. That decision adopts a methodology that, economically, approximates the one currently used by TGP. In October 1998, FERC issued an order affirming the ALJ's decision. Certain parties have requested rehearing of that order, and the matter is currently pending before FERC.
TGP has filed cash out reports for the period September 1993 through August 1998. TGP's filings showed a cumulative loss through August of 1998 of $3 million. TGP has reached a settlement in principle with its customers to resolve outstanding FERC proceedings related to these filed cash out reports. The reports, as well as the accounting for customer imbalances, had been challenged by TGP's customers. Upon FERC's approval, the settlement will provide for a new mechanism for accounting for TGP's cash out program.
Substantially all of the revenues of TGP are generated under long-term gas transmission contracts. Contracts representing approximately 70 percent of TGP's firm transportation capacity will be expiring over the next two years, principally in November 2000. Although TGP cannot predict how much capacity will be resubscribed, a majority of the expiring contracts cover service to northeastern markets, where there is currently little excess capacity. Several projects, however, have been proposed to deliver incremental volumes to these markets. Although TGP is actively pursuing the renegotiation, extension and/or replacement of these
contracts, there can be no assurance as to whether TGP will be able to extend or replace these contracts (or a substantial portion thereof) or that the terms of any renegotiated contracts will be as favorable to TGP as the existing contracts.
FERC Compliance Audits
TGP, as an interstate pipeline, is subject to FERC audits of its books and records. TGP does not have any open audits; however, TGP's property retirements are currently under review by the FERC audit staff.
Management believes the ultimate resolution of the aforementioned rate and regulatory matters, which are in various stages of finalization, will not have a material adverse effect on the Company's financial position, results of operations, or cash flows.
Legal Proceedings
In February 1998, the United States and the State of Texas filed in a United States District Court a Comprehensive Environmental Response, Compensation and Liability Act cost recovery action, United States v. Atlantic Richfield Co., et al., against fourteen companies including the following affiliates of EPEC: TGP, EPTPC, EPEC Corporation, EPEC Polymers, Inc. and the dissolved Petro-Tex Chemical Corporation, relating to the Sikes Disposal Pits Superfund Site ("Sikes") located in Harris County, Texas. Sikes was an unpermitted waste disposal site during the 1960s that accepted waste hauled from numerous Houston Ship Channel industries. The suit alleges that the former Tenneco Chemicals, Inc. and Petro-Tex Chemical Corporation arranged for disposal of hazardous substances at Sikes. TGP, EPTPC, EPEC Corporation and EPEC Polymers, Inc. are alleged to be derivatively liable as successors or as parent corporations. The suit claims that the United States and the State of Texas have expended over $125 million in remediating the site, and seeks to recover that amount plus interest. Other companies named as defendants include Atlantic Richfield Company, Crown Central Petroleum Corporation, Occidental Chemical Corporation, Exxon Corporation, Goodyear Tire & Rubber Company, Rohm & Haas Company, Shell Oil Company and Vacuum Tanks, Inc. These defendants have filed their answers and third-party complaints seeking contribution from twelve other entities believed to be PRPs at Sikes. Although factual investigation relating to Sikes is in very preliminary stages, the Company believes that the amount of material, if any, disposed at Sikes from the Tenneco Chemicals, Inc. or Petro-Tex Chemical Corporation facilities was small, possibly de minimis. However, the government 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. While the outcome of this matter cannot be predicted with certainty, management does not expect this matter to have a material adverse effect on the Company's financial position, results of operations, or cash flows.
TGP is a party in proceedings involving federal and state authorities regarding the past use by TGP of a lubricant containing PCBs in its starting air systems. TGP has executed a consent order with the EPA governing the remediation of certain of its compressor stations and is working with the relevant states regarding those remediation activities. TGP is also working with the Pennsylvania and New York environmental agencies to specify the remediation requirements at the Pennsylvania and New York stations. Remediation activities in Pennsylvania are complete with the exception of some long-term groundwater monitoring requirements. Remediation and characterization work at the compressor stations under its consent order with the EPA and the jurisdiction of the New York Department of Environmental Conservation is ongoing. Management believes that the ultimate resolution of these matters will not have a material adverse effect on the Company's financial position, results of operations, or cash flows.
In November 1988, the Kentucky environmental agency filed a complaint in a Kentucky state court, Commonwealth of Kentucky, Natural Resources and Environmental Protection Cabinet v. Tennessee Gas Pipeline Company, alleging that TGP discharged pollutants into the waters of the state without a permit and disposed of PCBs without a permit. The agency sought an injunction against future discharges, sought an order to remediate or remove PCBs, and sought a civil penalty. TGP has entered into agreed orders with the agency to resolve many of the issues raised in the original allegations, has received water discharge permits for
its Kentucky compressor stations from the agency, and continues to work to resolve the remaining issues. The relevant Kentucky compressor stations are scheduled to be characterized and remediated under the consent order with the EPA. Management believes that the resolution of this issue will not have a material adverse effect on the Company's financial position, results of operations, or cash flows.
A number of subsidiaries of EPTPC, both wholly owned and partially owned, have been named defendants in United States ex rel Grynberg v. El Paso Natural Gas Company, et al. Generally, the complaint in this motion alleges an industry-wide conspiracy to underreport the heating value as well as the volumes of the natural gas produced from federal and Indian lands, thereby depriving the U.S. government of royalties. The complaint remains sealed. The Company believes the complaint to be without merit.
The Company is a named defendant in numerous lawsuits and a named party in numerous governmental proceedings arising in the ordinary course of business. While the outcome of such lawsuits or other proceedings against the Company cannot be predicted with certainty, management currently does not expect these matters to have a material adverse effect on the Company's financial position, results of operations, or cash flows.
ENVIRONMENTAL
The Company is subject to extensive federal, state, and local laws and regulations governing environmental quality and pollution control. These laws and regulations require the Company 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, 1998, the Company had reserves for expected remediation costs and associated onsite, offsite and groundwater technical studies of approximately $138 million; and other costs of approximately $8 million which the Company anticipates incurring through 2027.
In addition, the Company estimates that its subsidiaries will make capital expenditures for environmental matters of approximately $6 million in 1999. Capital expenditures will range from approximately $51 million to $76 million in the aggregate for the years 2000 through 2007. These expenditures primarily relate to compliance with air regulations and, to a lesser extent, control of water discharges.
Since 1988, TGP has been engaged in an internal project to identify and deal with the presence of PCBs and other substances of concern, including substances on the EPA List of Hazardous Substances, at compressor stations and other facilities operated by both its interstate and intrastate natural gas pipeline systems. 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 assure that its efforts meet regulatory requirements.
In May 1995, following negotiations with its customers, TGP filed with FERC a separate Stipulation and Agreement (the "Environmental Stipulation") that establishes a mechanism for recovering a substantial portion of the environmental costs identified in the internal project. In November 1995, FERC issued an order approving the Environmental Stipulation. Although one shipper filed for rehearing, FERC denied rehearing of its order in February 1996. The Environmental Stipulation was effective July 1, 1995. As of December 31, 1998, a balance of $2 million remains to be collected under the stipulation.
The Company and certain of its subsidiaries have been designated, have received notice that they could be designated, or have been asked for information to determine whether they could be designated as a PRP with respect to 11 sites under the Comprehensive Environmental Response, Compensation and Liability Act (CERCLA or Superfund) or state equivalents. The Company has sought to resolve its liability as a PRP with respect to these Superfund sites through indemnification by third parties and/or settlements which provide for payment of the Company's allocable share of remediation costs. As of December 31, 1998, the Company has estimated its share of the remediation costs at these sites to be between $3 million and $6 million and has provided reserves that it believes 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 the Company has asserted a defense to any liability, the Company's estimate of its
share of remediation costs could change. Moreover, liability under the federal Superfund statute is joint and several, meaning that the Company could be required to pay in excess of its pro rata share of remediation costs. The Company's understanding of the financial strength of other PRPs has been considered, where appropriate, in its determination of its estimated liability as described herein. The Company presently believes that the costs associated with the current status of such entities as PRPs at the Superfund sites referenced above will not have a material adverse effect on the Company's financial position, results of operations, or cash flows.
The Company has initiated proceedings against its historic liability insurers seeking payment or reimbursement of costs and liabilities associated with environmental matters. In these proceedings, the Company contends that certain environmental costs and liabilities associated with various entities or sites, including costs associated with former operating sites, must be paid or reimbursed by certain of its historic insurers. The proceedings are in the discovery stage, and it is not yet possible to predict the outcome.
It is possible that new information or future developments could require the Company to reassess its potential exposure related to environmental matters. The Company 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, regulations and enforcement policies thereunder, and claims for damages to property, employees, other persons and the environment resulting from current or discontinued operations, could result in substantial costs and liabilities in the future. As such information becomes available, or developments occur, related accrual amounts will be adjusted accordingly. While there are still uncertainties relating to the ultimate costs which may be incurred, based upon the Company's evaluation and experience to date, the Company believes the recorded reserve is adequate.
For a further discussion of specific environmental matters, see Legal Proceedings above.
OTHER
PPN Power Project
In March 1999, the Company signed a sale and purchase agreement to acquire a 26 percent interest in a $295 million power plant in Tamil Nadu, India. The project consists of a 346 MW combined cycle power plant which will serve as a base load facility and sell power to the state-owned Tamil Nadu Electricity Board under a thirty-year power purchase agreement. Construction began in January 1999, and operations are expected to commence in early 2001. Transfer of the funds to complete the acquisition is expected to be finalized by the end of March 1999.
Year 2000
EPEC has established an executive steering committee and a project team to coordinate the phases of its Year 2000 project to assure that the Company's key automated systems and related processes will remain functional through the year 2000. Those phases are: (i) awareness; (ii) assessment; (iii) remediation; (iv) testing; (v) implementation of the necessary modifications and (vi) contingency planning (which was previously included as a component of EPEC's implementation phase). The Company has participated in EPEC's Year 2000 project as described below.
In recognition of the importance of Year 2000 issues and their potential impact to EPEC, the initial phase of the Year 2000 project involved the establishment of a company-wide awareness program. The awareness program is directed by the executive steering committee and project team and includes participation of senior management in each core business area. The awareness phase is substantially completed, although EPEC will continually update awareness efforts for the duration of the Year 2000 project.
The Company's assessment phase consists of conducting a company-wide inventory of its key automated systems and related processes, analyzing and assigning levels of criticality to those systems and processes, identifying and prioritizing resource requirements, developing validation strategies and testing plans, and evaluating business partner relationships. The portion of the assessment phase related to internally developed computer applications, hardware and equipment, and embedded chips is substantially complete. The
Company estimates that it has finished more than three-fourths of the portion of the assessment to determine the nature and impact of the Year 2000 date change for third-party-developed software. The assessment phase of the project, among other things, involves efforts to obtain representations and assurances from third parties, including third party vendors, that their hardware and equipment products, embedded chip systems, and software products being used by or impacting the Company are or will be modified to be Year 2000 compliant. To date, the responses from such third parties, although generally encouraging, are inconclusive. As a result, the Company cannot predict the potential consequences if these or other third parties or their products are not Year 2000 compliant. The Company is currently evaluating the exposure associated with such business partner relationships.
The remediation phase involves converting, modifying, replacing or eliminating key automated systems identified in the assessment phase. The testing phase involves the validation of the identified key automated systems. The Company is utilizing test tools and written test procedures to document and validate, as necessary, its unit, system, integration, and acceptance testing. The Company estimates that approximately one-half of the work of these phases remains, and expects each to be substantially completed by mid-1999.
The implementation phase involves placing the converted or replaced key automated systems into operation. In some cases, this phase will also involve the implementation of contingency plans needed to support business functions and processes that may be interrupted by Year 2000 failures that are outside of the Company's control. The Company has completed more than one-fourth of the implementation phase, which is expected to be substantially completed by mid-1999.
The contingency planning phase consists of developing a risk profile of the Company's critical business processes and then providing for actions the Company will pursue to keep such processes operational in the event of Year 2000 disruptions. The focus of such contingency planning is on prompt response to any Year 2000 events, and a plan for subsequent resumption of normal operations. The plan is expected to assess the risk of a significant failure to critical processes performed by the Company, and to address the mitigation of those risks. The plan will also consider any significant failures related to the most reasonably likely worst case scenario, discussed below, as they may occur. In addition, the plan is expected to factor in the severity and duration of the impact of a significant failure. The Company plans to have its contingency plan completed by mid-1999. The Year 2000 contingency plan will continue to be modified and adjusted throughout the year as additional information becomes available.
The goal of the Year 2000 project is to ensure that all of the critical systems and processes which are under the Company's direct control remain functional. Certain systems and processes may be interrelated with or dependent upon systems outside the Company's control, however, and systems within the Company's control may have unpredicted problems. Accordingly, there can be no assurance that significant disruptions will be avoided. The Company's present analysis of its most reasonably likely worst case scenario for Year 2000 disruptions includes Year 2000 failures in the telecommunications and electricity industries, as well as interruptions from suppliers that might cause disruptions in the Company's operations, thus causing temporary financial losses and an inability to deliver products and services to customers. Virtually all of the natural gas transported through the Company's interstate pipelines is owned by third parties. Accordingly, failures of natural gas producers to be ready for the Year 2000 could significantly disrupt the flow of product to the Company's customers. In many cases, the producers have no direct contractual relationship with the Company, and the Company relies on its customers to verify the Year 2000 readiness of the producers from whom they purchase natural gas. Since most of the Company's revenues from the delivery of natural gas are based upon fees paid by its customers for the reservation of capacity, and not based upon the volume of actual deliveries, short term disruptions in deliveries caused by factors beyond the Company's control should not have a significant financial impact on the Company, although it could cause operational problems for the Company's customers. Longer-term disruptions, however, could materially impact the Company's results of operations, financial condition, and cash flows.
While the Company owns or controls most of its domestic facilities and projects, nearly all of the Company's international investments have been made in conjunction with unrelated third parties. In many cases, the operators of such international facilities are not under the sole or direct control of the Company. As
a consequence, the Year 2000 programs instituted at some of the international facilities may be different from the Year 2000 program implemented by the Company domestically, and the party responsible for the results of such program may not be under the direct or indirect control of the Company. In addition, the "non-controlled" programs may not provide the same degree of communication, documentation and coordination as the Company achieves in its domestic Year 2000 program. Moreover, the regulatory and legal environment in which such international facilities operate makes analysis of possible disruption and associated financial impact difficult. Many foreign countries appear to be substantially behind the United States in addressing potential Year 2000 disruption of critical infrastructure and in developing a framework governing the reporting requirements and relative liabilities of business entities. Accordingly, the Year 2000 risks posed by international operations as a whole are different than those presented domestically. As part of its Year 2000 effort, the Company is assessing the differences between the non-controlled programs and its domestic Year 2000 project, and has formulated and instituted a program for identifying such risks and preparing a response to such risks. While the Company believes that most of the international facilities in which it has significant investments are addressing Year 2000 issues in an adequate manner, it is possible that some of them may experience significant Year 2000 disruption, and that the aggregate effect of problems experienced at multiple international locations may be material and adverse. The Company intends to incorporate this possibility into the relevant contingency plans.
While the total cost of the Company's Year 2000 project is still being evaluated, the Company estimates that the costs to be incurred in 1999 and 2000 associated with assessing, remediating and testing internally developed computer applications, hardware and equipment, embedded chip systems, and third-party-developed software will be between $10 million and $19 million. Of these estimated costs, the Company expects between $5 million and $11 million to be capitalized and the remainder to be expensed. As of December 31, 1998, the Company has incurred expenses of approximately $6 million. The Company has previously only traced incremental expenses related to its Year 2000 project. This means that the costs of the Year 2000 project related to salaried employees of the Company, including their direct salaries and benefits, are not available, and have not been included in the estimated costs of the project. Since the earlier phases of the project mostly involved work performed by such salaried employees, the costs expended to date do not reflect the percentage completion of the project. The Company anticipates that it will expend most of the costs reported above in the remediation, implementation and contingency planning phases of the project. It is possible the Company may need to reassess its estimate of Year 2000 costs in the event the Company completes an acquisition of, or makes a material investment in, substantial facilities or another business entity.
Although the Company does not expect the costs of its Year 2000 project to have a material adverse effect on its financial position, results of operations, or cash flows, based on information available at this time the Company cannot conclude that disruption caused by internal or external Year 2000 related failures will not have such an effect. Specific factors which might affect the success of the Company's Year 2000 efforts and the occurrence of Year 2000 disruption or expense include the failure of the Company of its outside consultants to properly identify deficient systems, the failure of the selected remedial action to adequately address the deficiencies, the failure of the Company's outside consultants to complete the remediation in a timely manner (due to shortages of qualified labor or other factors), unforeseen expenses related to the remediation of existing systems or the transition to replacement systems, the failure of third parties to become Year 2000 compliant or to adequately notify the Company of potential noncompliance and the effects of any significant disruption at international facilities in which the Company has significant investments.
The above disclosure is a "YEAR 2000 READINESS DISCLOSURE" made with the intention to comply fully with the Year 2000 Information and Readiness Disclosure Act of 1998, Pub. L. No. 105-271, 112 Stat, 2386, signed into law October 19, 1998. All statements made herein shall be construed within the confines of that Act. To the extent that any reader of the above Year 2000 Readiness Disclosure is other than an investor or potential investor in the Company's -- or an affiliate's -- equity or debt securities, this disclosure is made for the SOLE PURPOSE of communicating or disclosing information aimed at correcting, helping to correct and/or avoid Year 2000 failures.
Management is not aware of other commitments or contingent liabilities which would have a materially adverse effect on the Company's financial condition, results of operations, or cash flows.
NEW ACCOUNTING PRONOUNCEMENTS NOT YET ADOPTED
Accounting for the Costs of Computer Software Developed or Obtained for Internal Use
In March 1998, the American Institute of Certified Public Accountants issued Statement of Position 98-1, Accounting for the Costs of Computer Software Developed or Obtained for Internal Use. This statement provides guidance on accounting for such costs, and also defines internal-use computer software. The statement is effective for fiscal years beginning after December 15, 1998. The application of this pronouncement will not have a material impact on the Company's financial position, results of operations, or cash flows.
Reporting on the Costs of Start-Up Activities
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 defines start-up activities and requires start-up and organization costs to be expensed as incurred. In addition, it requires that any such cost that exists on the balance sheet be expensed upon adoption of this pronouncement. The statement is effective for fiscal years beginning after December 15, 1998. The Company will adopt this pronouncement effective January 1, 1999, and expects to report a charge in the range of $7 million to $12 million, net of income taxes, in the first quarter of 1999 as a cumulative effect of a change in accounting principle.
Accounting for Derivative Instruments and Hedging Activities
In June 1998, SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, was issued by the Financial Accounting Standards Board to establish accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities. SFAS No. 133 requires that an entity classify all derivatives as either assets or liabilities in the statement of financial position and measure those instruments at fair value. If certain conditions are met, a derivative may be specifically designated as (i) a hedge of the exposure to changes in the fair value of a recognized asset or liability or an unrecognized firm commitment, (ii) a hedge of the exposure to variable cash flows of a forecasted transaction, or (iii) a hedge of the foreign currency exposure of a net investment in a foreign operation, an unrecognized firm commitment, an available-for-sale security, or a foreign-currency-denominated forecasted transaction. The accounting for the changes in the fair value of a derivative depends on the intended use of the derivative and the resulting designation. The standard is effective for all quarters in fiscal years beginning after June 15, 1999. The Company is currently evaluating the effects of this pronouncement.
Disclosure relating to Euro Conversion
In July 1998, the Securities and Exchange Commission issued Staff Legal Bulletin No. 6 to provide guidance for disclosure related to the Euro Conversion. The guidance primarily focuses on disclosure in the Management's Discussion and Analysis of Financial Condition and Results of Operations, as well as Description of Business. The Company currently has no investments in the countries affected by the Euro Conversion.
Accounting for Contracts Involved in Energy Trading and Risk Management Activities
In November 1998, the Emerging Issues Task Force reached a consensus on EITF 98-10, Accounting for Contracts Involved in Energy Trading and Risk Management Activities. EITF 98-10 requires energy trading contracts to be recorded at fair value on the balance sheet, with the changes in fair value included in earnings. EITF 98-10 is effective for fiscal years beginning after December 15, 1998. The Company adopted the provisions of EITF 98-10 in January 1999. The application of this pronouncement did not have a material impact on the Company's financial position, results of operations, or cash flows.
RISK FACTORS -- 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 such forward-looking statement includes a statement of the assumptions or bases underlying such forward-looking statement, we caution that, while such assumptions or bases are believed to be reasonable and are made in good faith, assumed facts or bases almost always vary from the actual results, and the 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, such expectation or belief is expressed in good faith and is believed to have a reasonable basis, but there can be no assurance that the statement of expectation or belief will result or be achieved or accomplished. The words "believe," "expect," "estimate," "anticipate" and similar expressions may 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:
OUR INDUSTRY IS HIGHLY COMPETITIVE
The hydrocarbons that we transport, gather, process and store are owned by third parties. As a result, the volume of hydrocarbons involved in such activities is dependent upon the actions of those third parties, and are beyond our control. Further, our ability to maintain or increase current transmission, gathering, processing, and sales volumes or to remarket unsubscribed capacity, is subject to the impact of the following:
- future weather conditions or other alternative energy sources;
- price competition;
- drilling activity and supply availability; and
- service competition.
Our future profitability may be affected by our ability to compete with the services offered by other energy enterprises which may be larger, offer more services, and possess greater resources.
Seventy percent of TGP's contracts are expiring over the next two years, principally in November 2000. Our ability to negotiate new contracts and to renegotiate existing contracts could be adversely affected by factors we cannot control, including:
- the proposed construction by other companies of additional pipeline capacity in the markets served by TGP;
- reduced demand due to higher gas prices;
- the availability of alternative energy sources; and
- the viability of our expansion projects.
For a further discussion see Item 1, Business, Markets and Competition.
FLUCTUATIONS IN NATURAL GAS AND NATURAL GAS LIQUIDS PRICES COULD ADVERSELY AFFECT OUR BUSINESS
Our ability to compete with other transporters is impacted by natural gas prices in the supply basins connected to our pipeline systems as compared to prices in other gas producing regions, especially Canada. Revenues generated by our gathering and processing contracts are dependent upon volumes and rates, both of which can be affected by the prices of natural gas and natural gas liquids. The success of our expanding gathering and processing operations in the offshore Gulf of Mexico is subject to continued development of additional oil and gas reserves in the vicinity of our facilities and our ability to access such additional reserves to offset the natural decline from existing wells connected to our systems. A decline in energy prices could
precipitate a decrease in such 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 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 or state taxes, if any, on the sale or transportation of natural gas and natural gas liquids and the price; and
- abundance of supplies of alternative energy sources.
If there are reductions in the average volume of the natural gas we transport, gather and process for a prolonged period, our results of operations and financial position could be materially adversely affected.
THE USE OF DERIVATIVE FINANCIAL INSTRUMENTS COULD RESULT IN FINANCIAL LOSSES
Some of our non-regulated subsidiaries are engaged in the gathering, processing and marketing of natural gas and other energy commodities and utilize futures and option contracts traded on the New York Mercantile Exchange and over-the-counter options and price and basis swaps with other gas merchants and financial institutions. These instruments are intended to reduce our exposure to short-term volatility in changes in commodities 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. For additional information concerning our derivative financial instruments, see item 7A, Quantitative and Qualitative Disclosures About Market Risks and Item 8, Financial Statements and Supplementary Data, Note 4.
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 such acquisitions and joint ventures within and outside the U.S. may be subject to the effects of, and changes in the following:
- U.S. and foreign trade and monetary policies;
- laws and regulations;
- political and economic developments;
- inflation rates;
- taxes; and
- operating conditions.
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 risks, and
- the effects of currency fluctuations and exchange controls (such as the recent devaluation of the Indonesian and Brazilian currencies and other economic problems).
Such legal and regulatory events and other unforeseeable obstacles may be beyond our control or ability to manage.
WE COULD INCUR SUBSTANTIAL ENVIRONMENTAL LIABILITIES
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, regulations and enforcement policies thereunder, and claims for damages to property, employees, other persons and the environment resulting from current or discontinued operations, could result in substantial costs and liabilities in the future. For additional information concerning the Company's environmental matters, see the section of this item entitled "Environmental."
OUR ACTIVITIES INVOLVE OPERATING HAZARDS AND UNINSURED RISKS
While we maintain insurance against certain of the risks normally associated with the transportation, gathering and processing of natural gas, including explosions, pollution and fires, the occurrence of a significant event that is not fully insured against could have a material adverse effect on our business.
THERE REMAIN POTENTIAL LIABILITIES RELATED TO THE ACQUISITION OF EPTPC
The amount of the actual and contingent liabilities of EPTPC, which remained the liabilities of EPEC after the acquisition by EPEC of EPTPC, could vary materially from the amount we estimated, which was based upon assumptions which could prove to be inaccurate. If New Tenneco or Newport News Shipbuilding Inc. were unable or unwilling to pay their respective liabilities, a court could require us, under certain legal theories which may or may not be applicable to the situation, to assume responsibility for such 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 EPTPC
In connection with the acquisition by EPEC of EPTPC and distributions made by EPTPC prior to that acquisition, the IRS issued a private letter ruling to Old Tenneco, in which it ruled that for U.S. federal income tax purposes the Distributions would be tax-free to Old Tenneco and, except to the extent cash was received in lieu of fractional shares, to its then existing stockholders; the acquisition by EPEC would constitute a tax-free reorganization; and that certain other transactions effected in connection with the acquisition by EPEC would be tax-free. If the distributions were not to qualify as tax-free distributions, then a corporate level federal income tax would be assessed to the consolidated group of which Old Tenneco was the common parent. This corporate level federal income tax would be payable by EPTPC. Under certain limited circumstances, however, New Tenneco and Newport News Shipbuilding Inc. have agreed to indemnify EPTPC 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 adversely affected by factors such as the availability or cost of capital, changes in interest rates, changes in the tax rates due to new tax laws, market perceptions of the natural gas industry or EPEC, or credit ratings.
WE ARE SUBJECT TO RISKS ASSOCIATED WITH YEAR 2000 ISSUES
We are taking steps to mitigate any adverse effects of the Year 2000 date change on our customers and business operations including the assessment, remediation, testing of our applications, hardware and software, and the implementation of necessary change. Nevertheless, our failure, or the failure of third-parties with whom we deal, to achieve Year 2000 compliance may adversely affect our business. For additional information on our Year 2000 strategy and specific factors that may affect our ability to achieve Year 2000 compliance, see the section of this item entitled "Other -- Year 2000."
ITEM 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The Company utilizes derivative financial instruments to manage market risks associated with certain energy commodities and interest and foreign currency exchange rates. The Company's primary market risk exposure is to changing commodity prices. Market risks are monitored by a corporate risk management committee that operates independently from the business segments that create or actively manage these risk exposures to ensure compliance with the Company's stated risk management policies as approved by EPEC's Board of Directors. These policies are set forth in Item 8, Financial Statements and Supplementary Data, Note 1.
TRADING COMMODITY PRICE RISK
EPEM is exposed to certain market risks inherent in its financial instruments entered into for trading purposes associated with natural gas, power and petroleum products. EPEM marks to market all energy trading activities, including transportation capacity and storage. EPEM's policy is to manage commodity price risk through a variety of financial instruments, including 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 differential between a fixed and variable price for the commodity, exchange-traded options, over-the-counter options and other contractual arrangements. EPEM manages market risk on a portfolio basis, subject to parameters established by the risk management committee. Comprehensive risk management processes, policies, and procedures have been established to monitor and control its market risk. The Company's risk management committee also continually reviews these policies to ensure they are responsive to changing business conditions.
EPEM measures the risk in its commodity and energy related contract portfolio on a daily basis utilizing a Value-at-Risk ("VAR") model to determine the maximum potential one-day unfavorable impact on its earnings from its existing portfolio due to normal market movements and monitors its risk in comparison to established thresholds. The VAR computations are based on historical simulation, which utilizes price movements over a specified period to simulate forward price curves in the energy markets, and several key assumptions, including the selection of a confidence level for expected losses and the holding period for liquidation. EPEM also utilizes other measures outside the VAR methodology to monitor the risk in its commodity and energy related contract portfolio on a monthly basis, including stress testing, position limit control and credit, liquidity and event risk management. EPEM previously utilized sensitivity analysis to report market risk based on a ten percent change in commodity prices. The uncertainty of the market place, increased trading of derivative instruments, and the complexity of these instruments created the demand for a more comprehensive portfolio level quantitative measure of market risk. Accordingly, EPEM converted from utilizing sensitivity analysis to the VAR model during 1998.
Assuming a confidence level of 95 percent and a one-day holding period, EPEM's estimated potential one-day unfavorable impact on income before income taxes, as measured by VAR, related to its commodity and energy related contracts held for trading purposes was approximately $2 million as of December 31, 1998, and 1997. VAR was implemented on April 1, 1998, therefore volatilities and correlations applicable on April 1, 1998, were used to provide comparative data for December 31, 1997. Actual losses could exceed those measured by VAR.
NON-TRADING COMMODITY PRICE RISK
The estimated potential one-day unfavorable impact on income before income taxes and minority interest, as measured by VAR, related to EPEM's non-trading commodity activities was immaterial at December 31, 1998, and 1997.
NON-TRADING INTEREST RATE RISK
The Company's debt financial instruments are sensitive to market fluctuations in interest rates. The table below presents principal cash flows and related weighted average interest rates by expected maturity dates. As of December 31, 1998, and 1997, 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.
The Company's equity swap is also sensitive to market fluctuations in interest rates. In March 1997, the Company purchased a 10.5 percent interest in CAPSA for approximately $57 million. In connection with this acquisition, the Company entered into an equity swap transaction associated with an additional 18.5 percent of CAPSA's then outstanding stock. Under the equity swap, the Company pays interest to the counterparty, on a quarterly basis, on a notional amount of $100 million at a rate of LIBOR plus 0.85 percent. In exchange, the Company receives dividends on the CAPSA stock to the extent of the counterparty's equity interest of 18.5 percent. In February 1999, the Company extended the term of the swap for two and a half years. For the equity swap, the table below presents the notional amount and weighted average interest rate by expected or contractual maturity dates. The notional amount is used to calculate the contractual payments to be exchanged under the contract. The fair value of the derivative financial instrument is the estimated amount at which management believes it could be liquidated over a reasonable period of time, based on quoted market prices, current market conditions, or other estimates obtained from third-party dealers.
The tabular presentation related to activities other than commodity trading, as of December 31, 1998, and 1997, is illustrated below:
- ---------------
(a) The variable rates presented are the average forward rates for the remaining term of each contract.
(b) The Company receives dividends, to the extent paid, on the CAPSA stock to the extent of the counterparty's equity interest of 18.5 percent. No dividends were received in 1998 and no dividends are expected for 1999.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
EL PASO TENNESSEE PIPELINE CO.
CONSOLIDATED STATEMENTS OF INCOME (IN MILLIONS)
The accompanying Notes are an integral part of these Consolidated Financial Statements.
EL PASO TENNESSEE PIPELINE CO.
CONSOLIDATED BALANCE SHEETS (IN MILLIONS, EXCEPT SHARE AMOUNTS)
The accompanying Notes are an integral part of these Consolidated Financial Statements.
EL PASO TENNESSEE PIPELINE CO.
CONSOLIDATED STATEMENTS OF CASH FLOWS (IN MILLIONS)
The accompanying Notes are an integral part of these Consolidated Financial Statements.
EL PASO TENNESSEE PIPELINE CO.
STATEMENTS OF CHANGES IN CONSOLIDATED STOCKHOLDERS' EQUITY (IN MILLIONS, EXCEPT SHARE AMOUNTS)
The accompanying Notes are an integral part of these Consolidated Financial Statements.
EL PASO TENNESSEE PIPELINE CO.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (IN MILLIONS)
The accompanying Notes are an integral part of these Consolidated Financial Statements.
EL PASO TENNESSEE PIPELINE CO.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICY
Change in Company Structure
On December 31, 1998, EPEC completed a series of steps to effect a tax-free internal restructuring. In an initial step, certain energy marketing operations were transferred to EPTPC from its former parent, EPNG, in exchange for 934,000 shares of Series C Preferred Stock, in a transaction valued at $47 million. On December 31, 1998, the field services operations of EPFS and the international operations of EPEI were transferred to EPTPC by its former parent and became subsidiaries of EPTPC. EPTPC issued 971 shares of its common stock to EPNG as consideration for (i) the assets and operations transferred to EPTPC, (ii) the redemption of Series C Preferred Stock, and (iii) the redemption of Series B Preferred Stock that had been issued in March 1997 for the forgiveness of intercompany debt. This transaction had a total value of $667 million at December 31, 1998. EPNG then distributed the common stock received in the exchange to EPEC who, as a result, became the parent of the Company. The restructuring transactions were treated as a transfer of ownership between entities under common control and were accounted for in a manner similar to a pooling of interests. Accordingly, all information in these financial statements has been restated as though the transactions occurred in the earliest period presented. As of January 1, 1996, the value assigned to EPTPC's common stock issued in the reorganization was $508 million which represented the value of the items exchanged as of that date.
As part of the reorganization, EPTPC also transferred certain assets and liabilities of corporate and discontinued operations to EPEC. EPTPC continues to own the interstate systems known as the TGP system, the East Tennessee system, and the Midwestern system, as well as certain discontinued operations not included in the transfer to EPEC.
The following table reflects the operating revenues and net income, excluding the effects of the tax-free internal restructuring, for the periods ended December 31:
Basis of Presentation and Principles of Consolidation
The consolidated financial statements include the accounts of all majority-owned, controlled subsidiaries of the Company after the elimination of all significant intercompany accounts and transactions. Investments in companies where the Company has the ability to exert significant influence over, but not control operating and financial policies are accounted for using the equity method. The financial statements for previous periods include certain reclassifications that were made to conform to the current year presentation. Such reclassifications have no impact on reported net income or stockholders' equity. In 1996, Old Tenneco reorganized its businesses along an operational basis. As a result, Old Tenneco's operations consisted solely of its energy related businesses and certain discontinued operations. Financial information for periods prior to the acquisition of Old Tenneco in December 1996 by EPEC, has been prepared on a combined basis.
Use of Estimates
The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and disclosure of contingent assets and liabilities that exist at the date of the financial statements. Actual results are likely to differ from those estimates.
Accounting for Regulated Operations
The Company's businesses that are subject to the regulations and accounting requirements of FERC have followed the accounting requirements of SFAS No. 71, Accounting for the Effects of Certain Types of Regulation, which may differ from the accounting requirements of the Company's non-regulated entities. Transactions that have been recorded differently as a result of regulatory accounting requirements include: GSR costs to be recovered under a demand and interruptible surcharge, environmental costs to be recovered under a demand surcharge, and certain benefits and other costs and taxes included in or expected to be included in future rates, including costs to refinance debt. When the accounting method followed is prescribed by or allowed by the regulatory authority for rate-making purposes, such method conforms to the generally accepted accounting principle of matching costs with the revenues to which they apply.
Cash and Temporary Investments
Short-term investments purchased with an original maturity of three months or less are considered cash equivalents.
Allowance for Doubtful Accounts and Notes Receivable
The Company has established a provision for losses on accounts and notes receivable, as well as for gas imbalances due from shippers and operators, which may become uncollectible. Collectibility is reviewed regularly, and the allowance is adjusted as necessary primarily under the specific identification method. The balances of this provision at December 31, 1998 and 1997, were $26 million and $39 million, respectively.
Gas Imbalances
The Company values gas imbalances due to or due from shippers and operators at the appropriate index price. Natural gas imbalances are settled in cash or made up in-kind.
Inventories
Inventories, consisting of materials and supplies and natural gas in storage, are valued at the lower of cost or market with cost determined using the average cost method.
Property, Plant, and Equipment
Included in the Company's property, plant, and equipment is construction work in progress of approximately $363 million and $210 million at December 31, 1998, and 1997, respectively. An allowance for both debt and equity funds used during construction of regulated projects is included in the cost of the Company's property, plant, and equipment.
Accounting for a substantial portion of property, plant, and equipment is subject to regulation by the FERC. The objectives of this regulation are to ensure the proper recovery of capital investments in rates. Such recovery is generally accomplished by allowing a return of the investment through inclusion of depreciation expense in the cost of service. Rates also allow for a return on the net unrecovered rate base. Specific procedures are prescribed by FERC to control capitalized costs, depreciation, and the disposal of assets. SFAS No. 71 specifically acknowledges the obligation of regulated companies to comply with regulated accounting procedures, even when they conflict with other generally accepted accounting principle pronouncements.
Regulated property, plant, and equipment is recorded at original cost of construction or, on acquisition, the cost of first party committing the asset to utility services. Construction cost includes direct labor and materials, as well as indirect charges such as overheads and allowance for funds used during construction. Replacements or betterments of major units of property are capitalized. Replacements or additions of minor units of property are expensed.
Depreciation for regulated property, plant, and equipment is calculated using the composite method. Assets with similar economic characteristics are grouped. The depreciation rate prescribed in the rate
settlement is applied to the gross investment for the group until net book value of the group is equal to the salvage value. Currently, depreciation rates vary from 1 percent to 24 percent. This results in remaining economic lives of groups ranging from 2 to 30 years. Depreciation rates are reevaluated in conjunction with the rate making process.
When regulated property, plant, and equipment is retired, due to abandonment or replacement, the original cost, plus the cost of retirement, less salvage, is charged to accumulated depreciation and amortization. No gain or loss is recognized unless an entire operating unit, as defined by FERC, has been retired. Gains or losses on dispositions of operating units are included in income.
Additional acquisition cost assigned to utility plant primarily represents the excess of allocated purchase costs over historical costs that resulted from the December 1996 acquisition of EPTPC. These costs are being amortized on a straight-line basis using FERC approved rates.
Depreciation of the Company's non-regulated properties is provided using the straight line or composite method which, in the opinion of management, is adequate to allocate the cost of properties over their estimated useful lives. Non-regulated properties have expected lives of 5 to 40 years.
The Company evaluates impairment of its property, plant, and equipment in accordance with SFAS No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of.
Intangible Assets
Intangible assets are amortized using the straight-line method over periods ranging from 5 years to 40 years. Accumulated amortization of intangible assets was $13 million and $9 million for 1998 and 1997, respectively.
The Company evaluates impairment of goodwill in accordance with SFAS No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of.
Environmental Costs
Expenditures for ongoing compliance with environmental regulations that relate to current operations are expensed or capitalized as appropriate. Expenditures that relate to an existing condition caused by past operations, and which do not contribute to current or future revenue generation, are expensed. Liabilities are recorded when environmental assessments indicate that remediation efforts are probable and the costs can be reasonably estimated. Estimates of the liability 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. All available evidence is considered including prior experience in remediation of contaminated sites, other companies' clean-up experience and data released by the EPA or other organizations. These estimated liabilities are subject to revision in future periods based on actual costs or new circumstances. These liabilities are included in the balance sheets at their undiscounted amounts. Recoveries are evaluated separately from the liability and, when recovery is assured, are recorded and reported separately from the associated liability in the consolidated financial statements as an asset.
Price Risk Management Activities
The Company utilizes derivative financial instruments to manage market risks associated with certain energy commodities, and interest rates. In its commodity price risk management activities, the Company engages in both trading and non-trading activities.
Activities for trading purposes consist of services provided to the energy sector, and all energy trading activities, including transportation capacity and storage, are accounted for using the mark-to-market method of accounting. Such trading activities are conducted through a variety of financial instruments, including forward contracts involving cash settlement or physical delivery of an energy commodity, swap contracts which require payments to (or receipts from) counterparties based on the differential between a fixed and
variable price for the commodity, exchange-trade options, over-the-counter options, and other contractual arrangements.
Under mark-to-market accounting, commodity and energy related contracts are reflected at estimated market value with resulting gains and losses recorded in operating income in the Consolidated Statements of Income. The net gains or losses recognized in the current period result primarily from transactions originating within the period and the impact of price movements on transactions originating in previous periods. The assets and liabilities resulting from mark-to-market accounting are presented as assets and liabilities from price risk management activities in the Consolidated Balance Sheets. Terms regarding cash settlement of the contracts vary with respect to the actual timing of cash receipts and payments. Receivables and payables resulting from these timing differences are presented in accounts receivable and accounts payable in the Consolidated Balance Sheets. Cash inflows and outflows associated with these price risk management activities are recognized in operating cash flow as the settlements of transactions occur.
The market value of these commodity and energy related contracts reflects management's best estimate considering various factors including closing exchange and over-the-counter quotations, time value and volatility factors underlying the commitments. The values are adjusted to reflect the potential impact of liquidating the Company's position in an orderly manner over a reasonable period of time under present market conditions.
Derivative and other financial instruments are also utilized in connection with non-trading activities. The Company enters into forwards, swaps, and other contracts to hedge the impact of market fluctuations on assets, liabilities, or other contractual commitments. Derivatives held for non-trading price risk management activities are not recorded on the balance sheet. Net periodic settlements are recorded as a gain or loss in operating income in the consolidated statements of income, and cash inflows and outflows are recognized in operating cash flow as the settlements of the transactions occur. See Note 4 for a further discussion of the Company's price risk management activities.
In late 1998, the Emerging Issues Task Force reached a consensus which supported the Company's accounting policy as described above.
Income Taxes
Income taxes are based on income reported for tax return purposes along with a provision for deferred income taxes. Deferred income taxes are provided to reflect the tax consequences in future years of differences between the financial statement and tax bases of assets and liabilities at each year end. Tax credits are accounted for under the flow-through method, which reduces the provision for income taxes in the year the tax credits first become available. Deferred tax assets are reduced by a valuation allowance when, based upon management's estimates, it is more likely than not that a portion of the deferred tax 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.
Old Tenneco, together with certain of its subsidiaries which were owned 80 percent or more, including subsidiaries in its industrial business and the shipbuilding business, had an agreement to file a consolidated U.S. federal income tax return. Such agreement provided, among other things, that (i) each company in a taxable income position would be charged with an amount equivalent to its federal income tax computed on a separate return basis, and (ii) each company in a tax loss position would be reimbursed to the extent that its deductions, including general business credits, were utilized in the consolidated return. Management believes that income tax amounts reflected in the financial statements of the Company prior to the acquisition by EPEC under the provisions of the tax sharing arrangement would not be materially different from the income taxes which would have been provided had the Company filed a separate consolidated tax return. Under the tax sharing agreement, Old Tenneco paid all federal taxes directly and billed or refunded, as applicable, its subsidiaries for the applicable portion of the total tax payments. This tax sharing agreement remains in effect for 1998 among EPTPC and certain of its subsidiaries which are owned 80 percent or more. Starting in 1999, EPEC and its 80 percent or more owned subsidiaries, including EPTPC, will file a consolidated U.S. federal income tax return.
On behalf of itself and all members filing in its consolidated federal income tax return, EPNG adopted a tax sharing policy (the "Policy") which provides, among other things, that (i) each company in a taxable income position will be currently charged with an amount equivalent to its federal income tax computed on a separate return basis, and (ii) each company in a tax loss position will be reimbursed currently to the extent its deductions, including general business credits, were utilized in the consolidated return. Under the Policy, EPNG paid all federal income taxes through 1998 directly to the IRS and will bill or refund, as applicable, its subsidiaries for their applicable portion of such income tax payments. The subsidiaries that were transferred to EPTPC as part of the tax-free internal reorganization will be included in the 1998 EPEC consolidated federal income tax return. These subsidiaries will continue to be included in the EPNG tax sharing policy through 1998.
As a result of the acquisition by EPEC, the Company entered into a new tax sharing agreement with Newport News Shipbuilding, Inc., New Tenneco and EPNG. This new 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. Generally, EPTPC will be liable for taxes imposed on itself. With respect to periods prior to the consummation of the distributions, in the case of federal income taxes imposed on the combined activities of Old Tenneco and other members of its consolidated group prior to the distributions, New Tenneco and Newport News Shipbuilding, Inc. are liable to the Company for federal income taxes attributable to their activities, and each will be allocated an agreed-upon share of estimated tax payments made by EPTPC for Old Tenneco. Pursuant to the new tax sharing agreement, the Company paid New Tenneco in 1997 for the tax benefits realized from the deduction of 1996 taxable losses generated by a debt realignment effected in accordance with the merger agreement.
New Accounting Pronouncements Not Yet Adopted
See Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations, New Accounting Pronouncements Not Yet Adopted, which is incorporated herein by reference.
2. ACQUISITION BY EPEC
In December 1996, EPEC acquired all of the common stock of EPTPC. As of December 31, 1998, EPEC owns 100 percent of the common stock of EPTPC, representing over 80 percent of the equity value of EPTPC; and the balance of the equity value of EPTPC is held by the holders of its Series A Preferred Stock.
In preparation for the acquisition by EPEC, Old Tenneco initiated tender offers for certain issues of the Company's debt and certain other debt issues were exchanged into New Tenneco debt, defeased or otherwise retired. Upon completion of the debt realignment transactions, the Company was only responsible for the remaining debt which was not tendered, exchanged, defeased or otherwise retired. The Company recognized an after-tax extraordinary charge of $234 million in 1996 (net of $126 million income tax benefit) related to the debt realignment immediately prior to the acquisition by EPEC.
The consideration provided in the acquisition by EPEC was approximately $4 billion, including retained debt and EPEC equity consideration valued at $913 million.
Accounting for Acquisition by EPEC
The acquisition of the Company by EPEC was accounted for using the purchase method of accounting. Accordingly, an allocation of the purchase price was assigned to the assets and liabilities acquired based upon the estimated fair value of those assets and liabilities as of the acquisition date. Substantially all of the excess of the purchase price over historical carrying amounts of net assets acquired was allocated to the property, plant and equipment of the Company's interstate pipeline systems. Such allocation was confirmed by an independent appraisal of the property acquired. Current FERC policy does not permit the Company to recover through its rates amounts allocated in purchase accounting to its regulated operations in excess of original cost.
The Consolidated Balance Sheets of EPTPC and subsidiaries as of December 31, 1998 and 1997, contained herein reflect the purchase price recorded by EPEC.
3. FINANCING TRANSACTIONS
The average interest rate of short-term borrowings was 6.0% and 5.8% at December 31, 1998, and 1997, respectively. The Company had short-term borrowings, including current maturities of long-term debt, at December 31, 1998 and December 31, 1997, as follows:
Long-term debt outstanding at December 31, 1998 and 1997, consisted of the following:
The following are aggregate maturities of long-term debt for the next 5 years and in total thereafter:
Other Financing Arrangements
In March 1997, TGP issued $300 million aggregate principal amount of 7 1/2% debentures due 2017, $300 million aggregate principal amount of 7% debentures due 2027, and $300 million aggregate principal amount of 7 5/8% debentures due 2037. Proceeds of approximately $883 million, net of issuance costs, were used to repay a portion of EPTPC's credit facility and for general corporate purposes.
In October 1997, EPNG established a new $750 million five-year revolving credit and competitive advance facility and a new $750 million 364-day renewable revolving credit and competitive advance facility (collectively, the "Revolving Credit Facility"). In connection with the establishment of the Revolving Credit Facility, EPTPC's revolving credit facility was also terminated, and the outstanding balance of $417 million was financed under the five-year portion of the new Revolving Credit Facility with TGP designated as the borrower. The availability under the Revolving Credit Facility is expected to be used for general corporate purposes including, but not limited to, backstopping EPNG's and TGP's $1 billion commercial paper programs.
In August 1998, EPEC became a guarantor of the Revolving Credit Facility. In October 1998, the $750 million 364-day portion of the Revolving Credit Facility was amended to extend the termination date to October 27, 1999. In addition, in October 1998, the Revolving Credit Facility was amended to permit TGP to issue commercial paper, provided that the total amount of commercial paper outstanding at EPNG and TGP is equal to or less than the unused capacity under the Revolving Credit Facility. In December 1998, EPEC became a borrower under the Revolving Credit Facility. The interest rate is 40 basis points above LIBOR, with the spread varying based on EPEC's long-term debt credit rating.
The availability of borrowings under the Revolving Credit Facility is subject to specified conditions, which management believes the Company currently meets. 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 since the specified dates).
In September 1998, TGP filed a shelf registration permitting TGP to offer up to $600 million (including $100 million carried forward from a prior shelf registration) of debt securities. In October 1998, TGP issued $400 million aggregate principal amount of 7% debentures due 2028. Proceeds to TGP were approximately $391 million, net of issuance cost. Approximately $300 million of the proceeds were used to repay TGP's short-term indebtedness under the Revolving Credit Facility and the remainder were used by TGP for general corporate purposes. After this issuance, TGP has $200 million of capacity remaining under its existing shelf registration.
In August 1998, EPTPC retired its outstanding 10% debentures due August 1, 1998, in the amount of $38 million.
4. FINANCIAL INSTRUMENTS AND PRICE RISK MANAGEMENT ACTIVITIES
Fair Value of Financial Instruments
The following disclosure of the estimated fair value of financial instruments is presented in accordance with the requirements of SFAS No. 107. The estimated fair value amounts have been determined by the Company using available market information and valuation methodologies.
As of December 31, 1998, and 1997, the carrying amounts of certain financial instruments held by the Company, including cash, cash equivalents, short-term borrowings and investments, and trade receivables and payables are representative of fair value because of the short-term maturity of these instruments. The fair value of long-term debt with variable interest rates is the carrying value because of the variable nature of the respective debt's interest rate, and the fair value of debt with fixed interest rates has been estimated based on quoted market prices for the same or similar issues. The fair value of all derivative financial instruments is the estimated amount at which management believes the instruments could be liquidated over a reasonable period of time, based on quoted market prices, current market conditions, or other estimates obtained from third-party brokers or dealers.
The following table reflects the carrying amount and estimated fair value of the Company's financial instruments at December 31:
Trading Commodity Activities
The Company, through its merchant services business, offers integrated price risk management services to the energy sector. These services primarily relate to energy related commodities including natural gas, power and petroleum products. The Company provides these services through a variety of contracts entered into for trading purposes including forward contracts involving cash settlements or physical delivery of an energy commodity, swap contracts, which require payments to (or receipt of payments from) counterparties based on the differential between a fixed and variable price for the commodity, options and other contractual arrangements. Effective December 31, 1998, the operations related to power trading were transferred to El Paso Power Services, a subsidiary of EPEC.
The fair value of commodity and energy related contracts entered into for trading purposes as of December 31, 1998, and 1997, and the average fair value of those instruments held during the years ended December 31, 1998, and 1997 are set forth below. At December 31, 1998, $76 million of assets from price risk management activities are included in other assets and $33 million of liabilities from price risk management activities are included in other liabilities in the Consolidated Balance Sheets.
- ---------------
(a) Computed using the net asset balance at each month end.
Notional Amounts and Terms
The notional amounts and terms of these financial instruments at December 31, 1998, and 1997 are set forth below (natural gas volumes in trillions of British thermal units, power volumes in millions of megawatt hours, petroleum products volumes in millions of British thermal units equivalent):
Notional amounts reflect the volume of transactions but do not represent the amounts exchanged by the parties. Accordingly, notional amounts are an incomplete measure of the Company's exposure to market or credit risks. The maximum terms in years detailed above are not indicative of likely future cash flows as these positions may be offset or cashed-out in the markets at any time based on the Company's risk management needs and liquidity in the commodity markets.
The weighted average maturity of the Company's entire portfolio of price risk management activities was approximately two years as of December 31, 1998 and 1997, respectively.
Market and Credit Risks
The Company serves a diverse customer group that includes independent power producers, industrial companies, gas and electric utilities, oil and gas producers, financial institutions and other energy marketers. This broad customer mix generates a need for a variety of financial structures, products and terms. This diversity requires the Company to manage, on a portfolio basis, the resulting market risks inherent in these transactions subject to parameters established by the Company's risk management committee. Market risks are monitored by a risk control committee operating independently from the units that create or actively manage these risk exposures to ensure compliance with the Company's stated risk management policies.
The Company measures and adjusts the risk in its 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 the Company would incur as a result of non-performance by counterparties pursuant to the terms of their contractual obligations. The Company maintains credit policies with regard to its 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 parental guarantees), and the use of standardized agreements which allow for the netting of positive and negative exposures associated with a single counterparty. The counterparties associated with the Company's assets from price risk management activities as of December 31, 1998, and 1997 are summarized as follows:
- ---------------
(a) "Investment Grade" is primarily determined using publicly available credit ratings along with consideration of collateral, which encompass standby letters of credit, parent company guarantees and property interest, including oil and gas 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-.
(b) Two customers' exposure at December 31, 1998, and 1997 comprise greater than 5 percent of assets from price risk management activities. These customers have Investment Grade ratings.
This concentration of counterparties may impact the Company's overall exposure to credit risk, either positively or negatively, in that the counterparties may be similarly affected by changes in economic, regulatory or other conditions. Based on the Company's policies, risk exposure, and reserves, the Company does not anticipate a material adverse effect on its financial position, or results of operations, or cash flows as a result of counterparty nonperformance.
Non-Trading Price Risk Management Activities
In March 1997, the Company purchased a 10.5 percent interest in CAPSA, a privately held Argentine company engaged in power generation and oil and gas production for approximately $57 million. In connection with this acquisition, the Company entered into an equity swap transaction associated with an additional 18.5 percent of CAPSA's then outstanding stock. Under the swap, the Company pays interest to the counterparty, on a quarterly basis, on a notional amount of $100 million at a rate of LIBOR plus 0.85 percent. In exchange, the Company receives dividends on the CAPSA stock to the extent of the counterparty's equity interest of 18.5 percent. The Company also fully participates in the market appreciation or depreciation of the underlying investment whereby the Company will realize appreciation or fund any depreciation attributable to the actual sale of the stock upon termination or expiration of the swap transaction. The initial term of the swap was two years, and in February 1999, was extended for an additional two and one-half years. Upon maturity or termination of the swap, the Company has a right of first refusal to purchase the counterparty's 18.5 percent investment in CAPSA common stock at the fair value of the stock at that date or at a later date at a price offered by a good faith buyer. This transaction is recorded using mark-to-market accounting.
5. COMMITMENTS AND CONTINGENCIES
See Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations, Commitments and Contingencies and Environmental, which are incorporated herein by reference.
6. INCOME TAXES
The following table reflects the components of income tax expense for the years ended December 31:
Tax expense of the Company differs from the amount computed by applying the statutory federal income tax rate (35 percent) to income before taxes. The following table outlines the reasons for the differences for the periods ended December 31:
The following table reflects the components of the net deferred tax liability at December 31:
- ---------------
(a) As of December 31, 1998, $1 million of non-current foreign deferred income taxes are included in other assets and as of December 31, 1997, $4 million of current deferred state income taxes are included in other current liabilities in the Consolidated Balance Sheets.
The cumulative undistributed earnings of certain foreign subsidiaries and foreign corporate joint ventures were approximately $35 million as of December 31, 1998. Since the 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, the Company may 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 such taxes is not practicable. For the same reasons, the Company has not provided for any U.S. taxes on the foreign currency translation adjustments recognized in comprehensive income.
As of December 31, 1998, approximately $20 million of alternative minimum tax credits were available to offset future regular tax liabilities. These alternative minimum tax credit carryovers have no expiration date. Additionally, at December 31, 1998, approximately $1 million of general business credit, $102 million of net operating loss, and $9 million of capital loss carryovers were available to offset future tax liabilities. The general business credit carryovers expire in the years 1999 and 2000. Approximately $57 million of the net operating loss carryovers expire in 2012 and the remaining $45 million expire in the years 2004 through 2011. Usage of these carryovers is subject to the limitations provided for under Sections 382 and 383 of the Internal Revenue Code as well as the separate return limitation year rules of the Treasury Regulations.
The Company has recorded a valuation allowance to reflect the estimated amount of deferred tax assets which may not be realized due to the expiration of net operating loss and tax credit carryovers. As of December 31, 1998, and 1997, approximately $5 million and $8 million, respectively, of the valuation allowance relates to the net operating loss carryovers of an acquired company. The remainder of the valuation allowance relates to the general business credit carryovers of an acquired company. Any tax benefits subsequently recognized from reversal of this valuation allowance will be allocated to goodwill.
Prior to 1999, EPTPC and its subsidiaries filed a consolidated federal income tax return and EPEC and its other subsidiaries filed a separate consolidated federal income tax return. As a result of the tax-free reorganization described in Note 1, starting in 1999, EPEC and its subsidiaries, including EPTPC and its subsidiaries, will file one consolidated federal income tax return.
7. RETIREMENT BENEFITS
Pension Benefits
Prior to January 1, 1997 substantially all of the Company's employees were covered under one of two defined benefit pension plans. Certain employees were included in the Old Tenneco Retirement Plan ("TRP"). The related benefit obligation is the responsibility of New Tenneco and as such, is not included in the Consolidated Balance Sheets. The remaining employees were covered by the EPEC defined benefit plan.
Effective January 1, 1997, the EPEC plan was amended to provide benefits determined by a cash balance formula and to include employees added as a result of the acquisition of the Company by EPEC and other acquisitions prior to 1997. Employees who were participants on December 31, 1996, received the greater of cash balance benefits or prior plan benefits accrued through December 31, 2001.
EPEC is responsible for benefits accrued under its defined benefit plan and its cash balance plan and allocates the related costs to its affiliates.
During 1997, EPEC offered special termination benefits to Company employees, as a result of the acquisition of the Company by EPEC, who were at least 55 years old and who were eligible to retire under the TRP on December 31, 1996. Eligible employees accepting this offer and retiring by July 1, 1997, received a cash balance credit based on an enhanced formula not to exceed one year's base salary. The cost associated with the special termination benefits was accrued at December 31, 1996, as part of the liabilities assumed in the acquisition by EPEC. In 1997, the Company funded $11 million for these special termination benefits.
Other Postretirement Benefits
As a result of the acquisition by EPEC, EPTPC retained responsibility for certain postretirement medical and life insurance benefits for former employees of operations previously disposed of by Old Tenneco, and for employees, including TGP employees, added as a result of the acquisition by EPEC who were eligible to retire on December 31, 1996, and did so on or before July 1, 1997. Medical benefits for this closed group of retirees may be subject to deductibles, co-payment provisions, and other limitations and dollar caps on the amount of employer costs. EPTPC has reserved the right to change these benefits. Employees who retired on or after July 1, 1997 will continue to receive limited postretirement life insurance benefits. TGP's postretirement benefit plan costs are pre-funded to the extent such costs are recoverable through rates. Effective February 1, 1992, TGP began recovering through its rates the other post retirement employee benefits
("OPEB") costs included in the June 2, 1993 rate case settlement agreement. To the extent actual OPEB costs differ from the amounts funded, a regulatory asset or liability is recorded.
Several plan amendments were made effective January 1, 1998, including increases in deductibles, increases in out-of-pocket limits, and changes to the prescription drug provisions. These changes resulted in a $16 million decrease in the postretirement benefits obligation.
The following table sets forth the change in benefit obligation, change in plan assets, funded status, and components of net periodic benefit cost for other postretirement benefits. In 1998, the Company changed the measurement date for measuring its OPEB obligations from December 31 to September 30. Traditionally, timing of the receipt of this information has limited the Company's ability to maximize planning and budgeting opportunities with respect to projected costs of its various plans. The Company changed its benefit reporting date to facilitate the planning process and gather necessary financial reporting information in a more timely manner. Management believes the date change is preferable to the method previously employed. This change in measurement date has been accounted for as a change in accounting principle and had no material cumulative effect on retirement benefit expense for the current or prior periods.
As of December 31, 1998, and 1997, the current liability portion of the postretirement benefits was $50 million and $45 million, respectively. Benefit obligations are based upon certain actuarial estimates as described below.
Actuarial estimates for the Company's postretirement benefits plans assumed a weighted average annual rate of increase in the per capital costs of covered health care benefits of 10 percent through 2000, gradually decreasing to 6 percent by the year 2008. Assumed health care cost trends have a significant effect on the amounts reported for other postretirement benefit plans. A one-percentage point change in assumed health care cost trends would have the following effects:
Retirement Savings Plan
EPTPC employees participate in EPEC's defined contribution plan.
8. PREFERRED STOCK
At December 31, 1998, EPTPC had authorized 20 million shares of preferred stock. In November 1996, the Company issued 6 million shares of Series A Preferred Stock. The Series A Preferred Stock is not convertible into shares of any other class or series of stock of the Company and it has no maturity date. Holders of shares of Series A Preferred Stock are entitled to receive cash dividends payable quarterly at the rate of 8 1/4% of the stated value of $50 per share. It is not redeemable at the option of EPTPC prior to December 31, 2001, unless one or more amendments to the Internal Revenue Code are enacted that reduce the percentage of the dividends received deduction as specified in Section 243(a)(1) of the Internal Revenue Code. On or after December 31, 2001, the Series A Preferred Stock is redeemable at the option of the
Company, in whole or in part, upon not less than 30 days' notice at a redemption price of $50 per share, plus unpaid dividends.
9. SEGMENT INFORMATION
The Company adopted the standards outlined in SFAS No. 131, Disclosures about Segments of an Enterprise and Related Information, effective January 1, 1998. Accordingly, the Company has segregated its business activities into four segments: Tennessee Gas Pipeline segment, El Paso Field Services segment, El Paso Energy Marketing segment, and El Paso Energy International segment. These segments are strategic business units that offer a variety of different energy products and services. They are managed separately as each business requires different technology and marketing strategies.
The Tennessee Gas Pipeline segment, which includes the interstate pipeline systems of TGP, Midwestern, and East Tennessee, transports natural gas to the northeast, midwest, and mid-Atlantic sections of the U.S. including the states of Tennessee, Virginia and Georgia as well as the New York City, Chicago, and Boston metropolitan areas. The El Paso Field Services segment provides natural gas gathering, products extraction, dehydration, purification, compression and intrastate transmission services. The El Paso Energy Marketing segment markets and trades natural gas, power, and petroleum products and participates in the development and ownership of domestic power generation projects. The El Paso Energy International segment develops and operates energy infrastructure facilities worldwide.
The accounting policies of the individual segments are the same as those of the Company, as a whole, as summarized in Note 1, Basis of Presentation. Certain business segments' earnings are largely derived from the earnings on equity investments which are reported in Other, net in the Consolidated Statements of Income. Accordingly, the Company evaluates segment performance based on EBIT. To the extent practicable, results of operations for the years ended December 31, 1997 and 1996 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.
The reconciliations of revenues for reportable segments to total consolidated revenues are presented below.
The reconciliations of EBIT to income before income taxes are presented below.
The reconciliations of assets for reportable segments to total consolidated assets are presented below.
The reconciliations of other, net for reportable segments to total consolidated other, net are presented below.
The Company did not have gross revenue from any customer equal to, or in excess of, ten percent of consolidated operating revenue for the years ended December 31, 1998, 1997, and 1996.
10. INVENTORIES
Inventories consisted of the following at December 31:
11. PROPERTY, PLANT, AND EQUIPMENT
Property, plant and equipment consisted of the following at December 31:
Current FERC policy does not permit the Company to recover amounts in excess of original cost allocated in purchase accounting to its regulated operations through rates.
12. INVESTMENT IN AFFILIATED COMPANIES (UNAUDITED)
The Company holds investments in various affiliates which are accounted for on the equity method of accounting. The principal equity method investments are the Company's investments in international pipelines, interstate pipelines, power generation plants, gathering systems and natural gas storage facilities.
Summarized financial information of the Company's proportionate share of 50 percent or less owned companies accounted for by the equity method of accounting is as follows:
13. SUPPLEMENTAL CASH FLOW INFORMATION
The following table contains supplemental cash flow information for the years ended December 31:
14. TRANSACTIONS WITH AFFILIATES
General and Administrative
In 1998, EPEC allocated certain general and administrative expenses to the Company. The allocation is based on the estimated level of effort devoted to the Company's operations and relative size based on revenues, gross property and payroll. In 1996 and 1997, the Company performed most of its own administrative functions, and therefore, allocated general and administrative expenses were lower than for 1998. In 1996, the Company received an allocation of costs for these services from Old Tenneco. Costs allocated to the Company included in operation and maintenance expense in the Consolidated Income Statements were $176 million, $35 million, and $28 million for the years ended December 31, 1998, 1997, and 1996, respectively.
The Company's management believes the method for allocating corporate general and administrative expenses is reasonable and that total general and administrative expenses reflected in the accompanying pre-acquisition combined statements of income are reasonable when compared with the total general and administrative costs the Company would have incurred on a stand-alone basis.
Notes and Advances Receivable or Payable with Affiliates
For the years 1996 cash contributions from (distributions to) affiliates in the Statements of Changes in Consolidated Stockholders' Equity and Combined Equity consist of net cash changes in notes and advances receivable or payable between the Company and the industrial business and shipbuilding business which have been included in combined equity. Historically, Old Tenneco has utilized notes and advances to centrally manage cash funding requirements for its consolidated group.
The "Note payable to EPEC" balance at December 31, 1998 and 1997 relates to an interest-bearing demand loan first made to TGP from EPEC in December 1996 subsequent to the Merger.
15. QUARTERLY FINANCIAL DATA (UNAUDITED)
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors and Stockholders of El Paso Tennessee Pipeline Co.:
In our opinion, the consolidated financial statements listed in the index appearing under Item 14. (a) 1. present fairly, in all material respects, the consolidated financial position of El Paso Tennessee Pipeline Co. as of December 31, 1998 and 1997, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 1998, in conformity with generally accepted accounting principles. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 14. (a) 2. presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and the financial statement schedule are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements and the financial statement schedule based on our audits. We conducted our audits of these statements in accordance with generally accepted auditing standards which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for the opinions expressed above.
PricewaterhouseCoopers LLP
Houston, Texas March 9, 1999
SCHEDULE II
EL PASO TENNESSEE PIPELINE CO. VALUATION AND QUALIFYING ACCOUNTS
YEARS ENDED DECEMBER 31, 1998, 1997, AND 1996
(IN MILLIONS)
- ---------------
(a) Primarily accounts written off.
(b) Due to acquisition of Gulf States Gas Pipeline Company.
(c) The Company had potential tax benefits of $117 million at December 31, 1995, which were not recognized in the statement of income when generated. These benefits resulted primarily from U.S. capital loss carryforwards which were available to offset future capital gains. During 1996, these capital loss carryforwards were utilized to offset taxes on capital gain transactions of the Company and certain Old Tenneco affiliates.
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
PART III
ITEM 10.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The information appearing under the caption "Proposal No. 1 -- Nominee for Election of Director by Series A Preferred Stockholders" and "Section 16(a) Beneficial Ownership Reporting Compliance" in EPTPC's proxy statement for the 1999 Annual Meeting of Stockholders is incorporated herein by reference. Information regarding executive officers of EPTPC is presented in Item 1 of this Form 10-K under the caption "Executive Officers of the Registrant" and is incorporated herein by reference.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
Information appearing under the caption "Executive Compensation" in EPTPC's proxy statement for the 1999 Annual Meeting of Stockholders is incorporated herein by reference.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
Information appearing under the captions "Security Ownership of Beneficial Owners and Management of the Company" and "Security Ownership of a Beneficial Owner and Management of EPEC" in EPTPC's proxy statement for the 1999 Annual Meeting of Stockholders is incorporated herein by reference.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Information appearing under the caption "Relationship with El Paso Energy Corporation" in EPTPC's proxy statement for the 1999 Annual Meeting of Stockholders is incorporated herein by reference.
PART IV
ITEM 14.
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(a) The following documents are filed as a part of this report:
1. Financial statements.
The following consolidated and combined financial statements of the Company are included in Part II, Item 8 of this report:
(b) Reports on Form 8-K:
On October 16, 1998, EPTP filed a report under Item 5 on Form 8-K, dated October 16, 1998 with respect to the tax-free internal reorganization.
EL PASO TENNESSEE PIPELINE CO.
EXHIBIT LIST DECEMBER 31, 1998
Exhibits not incorporated by reference to a prior filing are designated by an asterisk; all exhibits not so designated are incorporated herein by reference to a prior filing as indicated.
UNDERTAKING
The undersigned Registrant hereby undertakes, pursuant to Regulation S-K, Item 601(b), paragraph (4)(iii), to furnish to the Securities and Exchange Commission upon request all constituent instruments defining the rights of holders of long-term debt of Registrant and its consolidated subsidiaries not filed herewith for the reason that the total amount of securities authorized under any of such instruments does not exceed 10 percent of the total consolidated assets of Registrant and its consolidated subsidiaries.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, as amended, El Paso Tennessee Pipeline Co. has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized on the 17th day of March 1999.
EL PASO TENNESSEE PIPELINE CO.
By: /s/ WILLIAM A. WISE ------------------------------------ William A. Wise Chairman of the Board, President and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1933, as amended, this report has been signed below by the following persons on behalf of El Paso Tennessee Pipeline Co. and in the capacities and on the dates as indicated.
INDEX TO EXHIBITS
Exhibits not incorporated by reference to a prior filing are designated by an asterisk, all exhibits not so designated are incorporated herein by reference to a prior filing as indicated.