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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
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FORM 10-K
(MARK ONE)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2000
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
FOR THE TRANSITION PERIOD FROM TO .
COMMISSION FILE NUMBER 1-9864
EL PASO TENNESSEE PIPELINE CO.
(Exact name of registrant as specified in its charter)
DELAWARE 76-0233548
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
EL PASO BUILDING
1001 LOUISIANA STREET
HOUSTON, TEXAS 77002
(Address of principal executive offices) (Zip Code)
REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE: (713) 420-2131
SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:
NAME OF EACH EXCHANGE
TITLE OF EACH CLASS ON WHICH REGISTERED
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8 1/4% Cumulative Preferred Stock, Series A................. New York Stock Exchange
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: NONE
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days.
Yes [X] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [X]
STATE THE AGGREGATE MARKET VALUE OF THE VOTING STOCK HELD BY NON-AFFILIATES
OF THE REGISTRANT. Aggregate market value shall be computed by reference to the
price at which the stock was sold, or the average bid and asked prices of such
stock, as of the specified date within 60 days prior to the date of filing.
MARKET VALUE
CLASS OF VOTING STOCK AND NUMBER OF SHARES HELD
HELD BY NON-AFFILIATES AT MARCH 19, 2001 BY NON-AFFILIATES
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8 1/4% Cumulative Preferred Stock, Series A, 6,000,000
shares $306,000,000*
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* Based upon the closing price on the Composite Tape for the 8 1/4% Cumulative
Preferred Stock, Series A, on March 19, 2001.
INDICATE THE NUMBER OF SHARES OUTSTANDING OF EACH OF THE REGISTRANT'S
CLASSES OF COMMON STOCK, AS OF THE LATEST PRACTICABLE DATE.
Common Stock, par value $0.01 per share. Shares outstanding on March 19,
2001: 1,971
DOCUMENTS INCORPORATED BY REFERENCE
List hereunder the following documents if incorporated by reference and the
part of the Form 10-K (e.g., Part I, Part II, etc.) into which the document is
incorporated: our definitive Proxy Statement for the 2001 Annual Meeting of
Stockholders, to be filed not later than 120 days after the end of the fiscal
year covered by this report, is incorporated by reference into Part III.
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EL PASO TENNESSEE PIPELINE CO.
TABLE OF CONTENTS
CAPTION PAGE
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PART I
Item 1. Business.................................................... 1
Item 2. Properties.................................................. 9
Item 3. Legal Proceedings........................................... 10
Item 4. Submission of Matters to a Vote of Security Holders......... 10
PART II
Item 5. Market for Registrant's Common Equity and Related
Stockholder Matters....................................... 10
Item 6. Selected Financial Data..................................... 10
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations................................. 11
Cautionary Statement for Purposes of the "Safe Harbor"
Provisions of the Private Securities Litigation Reform Act
of 1995................................................... 20
Item 7A. Quantitative and Qualitative Disclosures About Market
Risk...................................................... 21
Item 8. Financial Statements and Supplementary Data................. 24
Item 9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure.................................. 55
PART III
Item 10. Directors and Executive Officers of the Registrant.......... 55
Item 11. Executive Compensation...................................... 55
Item 12. Security Ownership of Beneficial Owners and Management...... 55
Item 13. Certain Relationships and Related Transactions.............. 55
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form
8-K....................................................... 55
Signatures.................................................. 58
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Below is a list of terms that are common to our industry and used
throughout this document:
/d = per day
Bbl = barrels
BBtu = billion British thermal units
BBtue = billion British thermal unit equivalents
Bcf = billion cubic feet
MBbls = thousand barrels
MMBbls = million barrels
MMBtu = million British thermal units
Mcf = thousand cubic feet
Mcfe = thousand cubic feet of gas equivalents
MMcf = million cubic feet
MMcfe = million cubic feet of gas equivalents
Mgal = thousand gallons
MWh = megawatt hours
MMWh = thousand megawatt hours
Tcfe = trillion cubic feet of gas equivalents
When we refer to natural gas and oil in "equivalents," we are doing so to
compare quantities of oil with quantities of natural gas or to express these
different commodities in a common unit. In calculating equivalents, we use a
generally recognized standard in which one Bbl is equal to six Mcf of natural
gas. Also, when we refer to cubic feet measurements, all measurements are at
14.73 pounds per square inch.
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PART I
ITEM 1. BUSINESS
GENERAL
Prior to 1996, we operated as Tenneco Inc., an entity with operations in
the automotive, energy, packaging and shipbuilding businesses. During the latter
part of 1996, Tenneco distributed to its shareholders all of its businesses
except for its energy business and some of its corporate and discontinued
operations. In December 1996, El Paso Corporation acquired these remaining
business operations and renamed us El Paso Tennessee Pipeline Co. During 1998,
El Paso completed a tax-free internal reorganization of its businesses. In the
reorganization, we became a direct subsidiary of El Paso. In addition, through a
series of transfers, El Paso's merchant energy, international, and field
services businesses became our subsidiaries, and we transferred some of our
corporate assets and liabilities and discontinued operations to El Paso.
Following this reorganization, we continued to own the Tennessee Gas Pipeline
and Midwestern Gas Transmission interstate systems, as well as the discontinued
operations not included in the transfer to El Paso. On December 31, 1999, as
part of a similar internal reorganization, the power services businesses of El
Paso and the merchant operations of Sonat Inc., acquired by El Paso in its
October 1999 merger with Sonat, were transferred to us in the form of a tax-free
capital contribution. At December 31, 2000, El Paso owned 100 percent of our
common equity and greater than 80 percent of our equity value. The remaining
combined equity value consists of $300 million of outstanding preferred stock
that is traded on the New York Stock Exchange.
OPERATIONS
Our principal operations include:
- the transportation, gathering, processing, and storage of natural gas;
- the marketing of energy and energy-related commodities and products;
- the generation of power; and
- the development and operation of energy infrastructure facilities.
Our Pipelines segment owns or has interests in approximately 15,400 miles
of interstate natural gas pipelines in the U.S. Our systems connect the nation's
principal natural gas supply regions to three of the largest consuming regions
in the United States: the Gulf Coast, the Northeast, and the Midwest. Our
natural gas transmission operations are comprised of two wholly owned interstate
pipeline systems: the Tennessee Gas Pipeline system and the Midwestern Gas
Transmission system, as well as interests in the Portland Natural Gas
Transmission system and the Bear Creek Storage facility.
Our Merchant Energy segment is involved in a broad range of activities in
the energy marketplace including asset ownership, trading and risk management
and financial services. We are one of North America's largest wholesale energy
commodity marketers and traders, and buy, sell, and trade natural gas, power,
and other energy commodities in the U.S. and internationally. We are also a
significant non-utility owner of electric generating capacity with 64 facilities
in 16 countries. Most recently, we have announced our expansion into the
liquefied natural gas business, capitalizing upon the increasing U.S. and
worldwide demand for natural gas. The financial services businesses of Merchant
Energy invest in emerging businesses to facilitate growth in the U.S. and
Canadian energy markets. As a global energy merchant, we evaluate and measure
risks inherent in the markets we serve, and use sophisticated systems and
integrated risk management techniques to manage those risks.
Our Field Services segment provides natural gas gathering, products
extraction, fractionation, dehydration, purification, compression and intrastate
transmission services. These services include gathering of natural gas from more
than 11,000 natural gas wells with over 19,000 miles of natural gas gathering
and natural gas liquids pipelines, and 20 natural gas processing, treating, and
fractionation facilities located in some of the most prolific and active
production areas in the U.S., including the San Juan Basin, east and south
Texas, Louisiana, and the Gulf of Mexico. We conduct our intrastate transmission
operations through interests in five intrastate systems, which serve a majority
of the metropolitan areas and industrial load centers in Texas.
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Our primary vehicle for growth and development of midstream energy assets is El
Paso Energy Partners, L.P., a publicly traded master limited partnership.
Through Energy Partners, we provide natural gas and oil gathering and
transportation, storage, and other related services, principally in the Gulf of
Mexico.
SEGMENTS
Our business unit activities are segregated into three primary business
segments: Pipelines, Merchant Energy, and Field Services. These segments are
strategic business units that provide a variety of energy products and services.
During 2000, we combined our International and Merchant Energy segments to
reflect the ongoing globalization of our Merchant Energy strategy and its
operating activities. We manage each segment separately and each requires
different technology and marketing strategies. For information relating to
operating revenues, operating income, earnings before interest expense and
income taxes (EBIT), and identifiable assets by segment, you should see Item 8,
Financial Statements and Supplementary Data, Note 11, which is incorporated by
reference herein.
PIPELINES
Our Pipelines segment provides natural gas transmission services in the
U.S. We conduct our activities through two wholly owned and one partially owned
interstate systems along with a natural gas storage facility. Each of these
systems is discussed below:
The TGP system. The Tennessee Gas Pipeline system consists of
approximately 14,700 miles of pipeline with a design capacity of 5,970 MMcf/d.
During 2000, TGP transported natural gas volumes averaging approximately 73
percent of its capacity. This multiple-line system begins in the natural
gas-producing regions of Louisiana, including the Gulf of Mexico, and south
Texas and extends to the northeast section of the U.S., including the New York
City and Boston metropolitan areas. TGP also has an interconnect at the
U.S.-Mexico border. Along its system, TGP has approximately 89 Bcf of
underground working gas storage capacity.
The Midwestern system. The Midwestern Gas Transmission system consists of
approximately 400 miles of pipeline with a design capacity of 785 MMcf/d. During
2000, Midwestern transported natural gas volumes averaging approximately 33
percent of its capacity. The Midwestern system connects with the TGP system at
Portland, Tennessee, and extends to Chicago to serve the Chicago metropolitan
area. As a result of El Paso's merger with The Coastal Corporation in January
2001, we will be required to sell the Midwestern system. We expect to complete
the sale in the second quarter of 2001.
The Portland system. We own an approximate 19 percent interest in the
Portland Natural Gas Transmission system. Portland consists of approximately 300
miles of interstate natural gas pipeline with a design capacity of 215 MMcf/d
extending from the Canadian border near Pittsburg, New Hampshire to Dracut,
Massachusetts. During 2000, Portland transported volumes averaging approximately
51 percent of its capacity.
The Bear Creek storage facility. We own a 50 percent interest in Bear
Creek Storage Company, which owns and operates an underground natural gas
storage facility located in Louisiana. The facility has a capacity of 50 Bcf of
base gas and 58 Bcf of working storage. Bear Creek's working storage capacity is
committed equally to our TGP system and El Paso's Southern Natural Gas system
under long-term contracts.
Regulatory Environment
Our interstate natural gas systems and storage operations are regulated by
the Federal Energy Regulatory Commission (FERC) under the Natural Gas Act of
1938 and the Natural Gas Policy Act of 1978. Each
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system operates under separate FERC approved tariffs that establish rates,
terms, and conditions under which each system provides services to its
customers. Generally, FERC's authority extends to:
- transportation of natural gas, rates, and charges;
- certification and construction of new facilities;
- extension or abandonment of services and facilities;
- maintenance of accounts and records;
- depreciation and amortization policies;
- acquisition and disposition of facilities;
- initiation and discontinuation of services; and
- various other matters.
Our wholly owned and investee pipelines have tariffs established through
filings with FERC that have a variety of terms and conditions, each of which
affects its operations and its ability to recover fees for the services it
provides. By and large, changes to these fees or terms can only be implemented
upon approval by FERC.
Our interstate pipelines systems are also subject to the Natural Gas
Pipeline Safety Act of 1968 that establishes pipeline and liquefied natural gas
plant safety requirements, the National Environmental Policy Act, and other
environmental legislation. Each of our systems has a continuing program of
inspection designed to keep all of our facilities in compliance with pollution
control and pipeline safety requirements. We believe that our systems are in
substantial compliance with the applicable requirements.
Markets and Competition
Our interstate systems face varying degrees of competition from alternative
energy sources, such as electricity, hydroelectric power, coal, and fuel oil.
Also, the potential consequences of proposed and ongoing restructuring and
deregulation of the electric power industry are currently unclear. Restructuring
and deregulation may benefit the natural gas industry by creating more demand
for natural gas turbine generated electric power, or it may hamper demand by
allowing a more effective use of surplus electric capacity through increased
wheeling as a result of open access.
TGP's customers include natural gas producers, marketers and end-users, as
well as other gas transmission and distribution companies, none of which
individually represents more than 10 percent of the revenues on TGP's system.
Currently, over 70 percent of TGP's capacity is subject to firm contracts
expiring after 2001. These contracts have an average term in excess of five
years. TGP continues to pursue future markets and customers for the capacity
that is not committed beyond 2001 and expects this capacity will be placed under
a combination of long-term and short-term contracts. However, there can be no
assurance that TGP will be able to replace these contracts or that the terms of
new contracts will be as favorable to TGP as the existing ones.
In a number of key markets, TGP faces competitive pressures from other
major pipeline systems, which enable local distribution companies and end-users
to choose a supplier or switch suppliers based on the short-term price of
natural gas and the cost of transportation. Competition among pipelines is
particularly intense in TGP's supply areas, Louisiana and Texas. In some
instances, TGP has had to discount its transportation rates in order to maintain
market share. The renegotiation of TGP's expiring contracts may be adversely
affected by these competitive factors.
MERCHANT ENERGY
Our Merchant Energy segment is a market maker involved in a broad range of
activities in the wholesale energy marketplace, including asset ownership,
trading and risk management, and financial services. Merchant
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Energy is organized into six functional units, each with complementary
activities that support our overall global merchant energy model. These units
are:
- Marketing and Origination;
- Trading and Risk Management;
- Power Generation;
- LNG;
- Financial Services; and
- Operations.
Marketing and Origination. The Marketing and Origination unit provides
energy solutions in natural gas, power, and other energy commodity markets. This
unit also markets capacity from power and natural gas assets, and creates
innovative structured transactions to enhance the value of Merchant Energy's
assets. This unit is able to provide its customers with flexible solutions to
meet their energy supply and financial risk management requirements by utilizing
its knowledge of the marketplace, natural gas pipelines, storage, and power
transmission infrastructures, supply aggregation, transportation management and
valuation, and integrated price risk management. They also enter into short and
long term energy supply and purchase contracts and perform total energy
infrastructure outsourcing for customers.
Trading and Risk Management. The Trading and Risk Management unit trades
natural gas, power, other energy commodities, and related financial instruments
in North America and Europe and provides pricing and valuation analysis for the
Marketing and Origination unit. Using the financial markets, this unit manages
the inherent risk of Merchant Energy's asset and trading portfolios using
value-at-risk limits set by El Paso's Board of Directors and optimizes the value
inherent in the segment's asset portfolio.
During 2000, the Marketing and Origination and Trading and Risk Management
units grew their combined physical and financially settled volumes by
approximately 40% to 106,656 BBtue/d. Power marketed during 2000 increased by
over 43 percent. We expect our marketed volumes to significantly increase in
2001.
Marketing and trading energy commodity volumes for the years ended December
31 were:
2000 1999 1998
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Physical natural gas marketed (BBtu/d).................... 6,899 6,713 7,089
Power marketed (MMWh)..................................... 113,652 79,361 55,210
Financial settled volumes (BBtue/d)....................... 98,574 68,678 31,793
Power Generation. Our Power Generation unit is one of the largest
non-utility generators in the U.S., and currently owns or has interests in 64
power plants in 16 countries. These plants represent 17,153 gross megawatts of
generating capacity. Of these facilities, 75 percent are natural gas fired, 15
percent are geothermal, with the remaining 10 percent utilizing natural gas
liquids, coal, and other fuels. During 2000, Merchant Energy continued acquiring
domestic non-utility generation assets, especially those with above-market power
purchase agreements. As part of these efforts, we used Chaparral Investors,
L.L.C. (also
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referred to as Electron) to expand Merchant Energy's growth in the power
generation business. Through Chaparral, Merchant Energy has invested in 27 U.S.
power generation facilities with a total generating capacity of approximately
5,600 gross megawatts. A subsidiary of Merchant Energy serves as the manager of
Chaparral and its wholly-owned subsidiary, Mesquite Investors, L.L.C., under a
management agreement which expires in 2006. As compensation for managing
Chaparral, Merchant Energy is paid an annual performance-based management fee.
Detailed below are brief descriptions, by region, of Merchant Energy's
power generation projects that are either operational or in various stages of
construction or development.
NUMBER OF GROSS
REGION PROJECT STATUS FACILITIES MEGAWATTS
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North America
East Coast Operational............................... 13 3,263
Under Construction........................ 1 716
Under Development......................... 3 1,664
Central Operational............................... 7 1,253
West Coast Operational............................... 21 1,036
South America Operational............................... 7 4,114
Under Construction........................ 1 470
Asia Operational............................... 5 2,589
Under Construction........................ 2 1,108
Europe Operational............................... 3 544
Under Construction........................ 1 396
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Total..................................................... 64 17,153
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LNG. The LNG unit contracts for liquefied natural gas terminalling and
regasification capacity, coordinates short and long term LNG supply deliveries,
and is developing an international LNG supply and marketing business. As of
December 31, 2000, our LNG unit has contracted for over 280 Bcf per year of LNG
regasification capacity at three locations along the Eastern Coast of the U.S.
and one location in Louisiana. In the Caribbean, we have contracted for 105 Bcf
per year of long term supplies of LNG with deliveries scheduled to begin in
2002.
Financial Services. The Financial Services unit provides financing to the
energy and power industries and provides institutional funds management.
Merchant Energy owns EnCap Investments, an institutional funds management firm
specializing in financing independent oil and natural gas producers. EnCap
manages three separate institutional oil and natural gas investment funds in the
U.S., and serves as investment advisor to Energy Capital Investment Company PLC,
a publicly traded investment company in the United Kingdom. During 2000, we
acquired Enerplus Global Energy Management, Inc., an institutional and retail
funds management firm in Canada. Combined, EnCap and Enerplus manage funds with
a market value of approximately $2 billion. In addition to EnCap and Enerplus,
Merchant Energy's Financial Services unit holds investments of approximately $62
million. Also in 2000, it began originating financing for North American power
development projects. As of December 31, 2000, it had funded $5 million of loans
with additional commitments for $68 million.
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Operations. The Operations unit conducts the day-to-day operations of
Merchant Energy's assets in close coordination with the Marketing and
Origination, and Trading and Risk Management units. Our Operations unit operates
13 generating facilities in the U.S. and three facilities in two foreign
countries.
Finance and Administration. In addition to its functional units, Merchant
Energy has a Finance and Administration unit that implements financing
strategies for its assets, and provides accounting and administrative services
for the segment's activities.
Regulatory Environment
Merchant Energy's domestic power generation activities are regulated by
FERC under the Federal Power Act with respect to its rates, terms, and
conditions of service and other reporting requirements. In addition, exports of
electricity outside of the U.S. must be approved by the Department of Energy.
Its cogeneration power production activities are regulated by FERC under the
Public Utility Regulatory Policies Act with respect to rates, procurement and
provision of services, and operating standards. All of its power generation
activities are also subject to U.S. Environmental Protection Agency (EPA)
regulations.
Merchant Energy's foreign operations are regulated by numerous governmental
agencies in the countries in which these projects are located. Generally, many
of the countries in which Merchant Energy conducts and will conduct business
have recently developed or are developing new regulatory and legal structures to
accommodate private and foreign-owned businesses. These regulatory and legal
structures and their interpretation and application by administrative agencies
are relatively new and sometimes limited. Many detailed rules and procedures are
yet to be issued and we expect that the interpretation of existing rules in
these jurisdictions will evolve over time. We believe that our operations are in
compliance in all material respects with all applicable environmental laws and
regulations in the applicable foreign jurisdictions. We also believe that the
operations of our projects in many of these countries eventually may be required
to meet standards that are comparable in many respects to those in effect in the
U.S. and in countries within the European Community.
Markets and Competition
Merchant Energy maintains a diverse supplier and customer base. During
2000, Merchant Energy's activities served over 900 suppliers and over 1,300
sales customers around the world.
Merchant Energy's trading, marketing, and power development businesses
operate in a highly
competitive environment. Its primary competitors include:
- affiliates of major oil and natural gas producers;
- multi-national energy infrastructure companies;
- large domestic and foreign utility companies;
- affiliates of large local distribution companies;
- affiliates of other interstate and intrastate pipelines; and
- independent energy marketers and power producers with varying scopes of
operations and financial resources.
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Merchant Energy competes on the basis of price, access to production,
understanding of pipeline and transmission networks, imbalance management,
experience in the marketplace, and counterparty credit.
Many of Merchant Energy's generation facilities sell power pursuant to
long-term agreements with investor-owned utilities in the U.S. Because of the
terms of its power purchase agreements for its facilities, Merchant Energy's
revenues are not significantly impacted by competition from other sources of
generation for these facilities. The power generation industry is rapidly
evolving, and regulatory initiatives have been adopted at the federal and state
level aimed at increasing competition in the power generation business. As a
result, it is likely that when the power purchase agreements expire, these
facilities will be required to compete in a significantly different market in
which operating efficiency and other economic factors will determine success.
Merchant Energy is likely to face intense competition from generation companies
as well as from the wholesale power markets. The successful acquisition of new
business opportunities is dependent upon Merchant Energy's ability to respond to
requests to provide new services, mitigate potential risks, and maintain strong
business development, legal, financial, and operational support teams with
experience in the respective marketplace.
FIELD SERVICES
Our Field Services segment provides customers with wellhead-to-mainline
services, including natural gas gathering, storage, products extraction,
fractionation, dehydration, purification, compression, transportation of natural
gas and natural gas liquids, and intrastate natural gas transmission services.
It also provides well-ties and offers real-time information services, including
electronic wellhead gas flow measurement, and works with Merchant Energy to
provide fully bundled natural gas services with a broad range of pricing options
as well as financial risk management products.
Field Services' assets include natural gas gathering and natural gas
liquids pipelines, treating, processing, and fractionation facilities in the San
Juan Basin, the producing regions of east and south Texas, and Louisiana.
Through our subsidiaries, we own approximately 8 percent of Energy
Partner's common units. Energy Partners is El Paso's primary vehicle for the
acquisition and development of midstream energy infrastructure assets. Energy
Partners' assets provide gathering, transportation, storage, and other related
activities for producers of natural gas and oil. Energy Partners owns or has
interests in twelve natural gas and oil pipeline systems, seven offshore
platforms, two natural gas storage facilities, five producing oil and natural
gas properties, and an overriding royalty interest in a non-producing oil and
natural gas property. As a result of El Paso's merger with Coastal in January
2001, Energy Partners sold its interests in several assets in the Gulf of
Mexico. These sales consisted of interests in seven natural gas pipeline
systems, a dehydration facility and two offshore platforms. Energy Partners
completed these sales in March of 2001.
In December 2000, Field Services purchased PG&E's Texas Midstream
operations for $887 million, including the assumption of $527 million of debt.
We accounted for the acquisition as a purchase. The acquired assets consisted of
7,500 miles of natural gas transmission and natural gas liquids pipelines that
transport approximately 2.8 Bcf/d, nine natural gas processing and fractionation
plants that process 1.5 Bcf/d, and rights to 7.2 Bcf of natural gas storage
capacity. These assets serve a majority of the metropolitan areas and the
largest industrial load centers in Texas, as well as numerous natural gas
trading hubs. These assets also create a physical link between our TGP system
and the El Paso Natural Gas system. In the first quarter of 2001, Field Services
sold some of these acquired natural gas liquids transportation and fractionation
assets to Energy Partners. The assets sold included more than 600 miles of
natural gas liquids gathering and transportation pipelines and three
fractionation plants located in south Texas.
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The following tables provide information concerning Field Services' natural
gas gathering and transportation facilities, its processing facilities, and its
facilities accounted for under the equity method as of December 31, 2000, and
for the three years ended December 31:
THROUGHPUT AVERAGE THROUGHPUT (BBTUE/D)(2) PERCENT OF
MILES OF CAPACITY -------------------------------- OWNERSHIP
GATHERING & TREATING PIPELINE(1) (MMCFE/D)(2) 2000 1999 1998 INTEREST
- -------------------- ----------- ------------ -------- -------- -------- ----------
Western Division................... 5,555 1,200 1,237 1,262 1,191 100
Eastern Division................... 1,251 909 271 386 424 100
Central Division(3)................ 9,890 6,760 1,425 1,528 1,771 100
Energy Partners(4)(5).............. 2,076 412 206 186 -- 8
Oasis(6)........................... 608 350 268 263 289 --
Viosca Knoll(5).................... 125 10 6 142 287 --
AVG. INLET VOLUME AVERAGE NATURAL GAS LIQUIDS
INLET (BBTU/D)(2) SALES (MGAL/D)(2) PERCENT OF
CAPACITY(2) ------------------ ----------------------------- OWNERSHIP
PROCESSING PLANTS (MMCF/D) 2000 1999 1998 2000 1999 1998 INTEREST
- ----------------- ----------- ---- ---- ---- ------- ------- ------- ----------
Western Division............ 600 635 650 586 384 432 370 100
Eastern Division............ 369 121 140 160 222 264 349 100
Central Division(3)......... 1,883 309 242 269 307 202 208 100
Coyote Gulch................ 120 87 97 69 -- -- -- 50
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(1) Mileage amounts are approximate for the total systems and have not been
reduced to reflect Field Services' net ownership.
(2) All volumetric information reflects Field Services' net interest and is
subject to increases or decreases depending on operating pressures and point
of delivery into or out of the system.
(3) Reflects the acquisition of PG&E's Texas Midstream operations in December
2000.
(4) In the first quarter of 2001, Energy Partners sold their interests in
several of its gathering, transmission, and treating systems in the Gulf of
Mexico. Total miles of the pipelines sold were 881. Our net interest in
these systems included combined throughput capacity of 144 MMcfe/d and
average throughput for the years ended December 31, 2000, and 1999 of 64
BBtue/d and 74 BBtue/d.
(5) Field Services sold its 49 percent interest in Viosca Knoll to Energy
Partners in June 1999 and its remaining one percent interest in September
2000.
(6) Field Services sold its 35 percent interest in Oasis in December 2000.
Regulatory Environment
Some of Field Services' operations are subject to regulation by FERC in
accordance with the Natural Gas Act of 1938 and the Natural Gas Policy Act of
1978. Each pipeline subject to regulation operates under separate FERC approved
tariffs with established rates, terms and conditions under which the pipeline
provides services.
In addition, some of Field Services' operations, directly owned or owned
through equity investments, are subject to the Natural Gas Pipeline Safety Act
of 1968, the Hazardous Liquid Pipeline Safety Act, and the National
Environmental Policy Act. Each of the pipelines has a continuing program of
inspection designed to keep all of the facilities in compliance with pollution
control and pipeline safety requirements and Field Services believes that these
systems are in substantial compliance with applicable requirements.
Markets and Competition
Field Services competes with, among others, major interstate and intrastate
pipeline companies in the transportation of natural gas and natural gas liquids.
Field Services also competes with major integrated energy companies, independent
natural gas gathering and processing companies, natural gas marketers, and oil
and natural gas producers in gathering and processing natural gas and natural
gas liquids. Competition for throughput and natural gas supplies is based on a
number of factors, including price, efficiency of facilities, gathering system
line pressures, availability of facilities near drilling activity, service, and
access to favorable downstream markets.
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CORPORATE AND OTHER OPERATIONS
Corporate and other operations include liabilities of our discontinued
operations and businesses.
ENVIRONMENTAL
A description of our environmental activities is included in Item 8,
Financial Statements and Supplementary Data, Note 8, and is incorporated by
reference herein.
EMPLOYEES
As of March 19, 2001, we had approximately 2,300 full-time employees, none
of which are subject to collective bargaining arrangements.
EXECUTIVE OFFICERS OF THE REGISTRANT
Our executive officers as of March 19, 2001, are listed below.
NAME OFFICE AGE
---- ------ ---
William A. Wise........................ Chairman of the Board, President and Chief Executive 55
Officer
H. Brent Austin........................ Executive Vice President and Chief Financial Officer 46
Joel Richards III...................... Executive Vice President 54
Britton White Jr....................... Executive Vice President and General Counsel 57
Mr. Wise became our Chairman of the Board, President and Chief Executive
Officer in December 1996. Mr. Wise has been Chief Executive Officer of El Paso
since January 1990 and Chairman of El Paso's Board of Directors since January
2001. He was also Chairman of El Paso's Board of Directors from January 1994
until October 1999. Mr. Wise became the President of El Paso in July 1998 and
also served in that capacity from January 1990 to April 1996. Mr. Wise is a
member of the Board of Directors of Battle Mountain Gold Company and is the
Chairman of the Board of El Paso Energy Partners Company, the general partner of
Energy Partners.
Mr. Austin has been our Executive Vice President and Chief Financial
Officer 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 El Paso since May 1995. He has been El Paso's Chief Financial
Officer since April 1992. Prior to that period, he served in various positions
with Burlington Resources Inc.
Mr. Richards has been our Executive Vice President since June 1997. From
December 1996 until June 1997, he was Senior Vice President. Mr. Richards has
been Executive Vice President of El Paso since December 1996. From January 1991
until December 1996, he was Senior Vice President of El Paso.
Mr. White has been our Executive Vice President and General Counsel 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 El Paso and
General Counsel of El Paso since December 1996. Prior to that period, he was a
Senior Vice President and General Counsel of El Paso.
Executive officers hold offices until their successors are elected and
qualified, subject to their earlier removal.
ITEM 2. PROPERTIES
A description of our properties is included in Item 1, Business, and is
incorporated by reference herein.
We are of the opinion that we have satisfactory title to the properties
owned and used in our 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
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properties in our businesses. We believe that our physical properties are
adequate and suitable for the conduct of our business in the future.
ITEM 3. LEGAL PROCEEDINGS
See Item 8, Financial Statements and Supplementary Data, Note 8, which is
incorporated by reference herein.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED
STOCKHOLDER MATTERS
All of our common stock, par value $0.01 per share, is owned by El Paso and
is not publicly traded. Our Series A preferred stock is traded on the New York
Stock Exchange under the symbol EPG_p.
We pay dividends on our capital stock from time to time from legally
available funds that have been approved for payment by our Board of Directors.
We pay dividends on our Series A preferred stock on a quarterly basis. The
dividend rate on our preferred stock is 8 1/4% per annum (2.0625% per quarter).
We pay dividends on March 31, June 30, September 30, and December 31 of each
year. All dividends payable on outstanding shares of our preferred stock for the
quarterly periods ending on or prior to December 31, 2000, have been paid in
full.
ITEM 6. SELECTED FINANCIAL DATA
YEAR ENDED DECEMBER 31,
-------------------------------------------
2000 1999 1998 1997 1996
------- ------ ------ ------ ------
(IN MILLIONS)
Operating Results Data:(1)
Operating revenues(2)(3)....................... $20,788 $9,670 $8,540 $8,842 $7,554
Merger-related costs and asset impairment
charges..................................... 11 75 -- -- --
Income before extraordinary items and
cumulative effect of accounting change...... 482 186 221 135 170
AS OF DECEMBER 31,
-------------------------------------------
2000 1999 1998 1997 1996
------- ------ ------ ------ ------
(IN MILLIONS)
Financial Position Data:(1)
Total assets(3)................................ $19,465 $9,764 $8,393 $9,200 $8,457
Long-term debt, less current maturities........ 1,845 1,459 1,467 1,083 1,152
Stockholders' equity........................... 3,154 2,430 2,172 1,935 1,797
- ---------------
(1) Our operating results and financial position reflect the acquisition in
December 2000 of PG&E's Texas Midstream operations. This acquisition was
accounted for as a purchase and therefore operating results are included in
our results prospectively from the purchase date.
(2) We restated historical operating revenues due to the implementation in 2000
of Emerging Issues Task Force Issue No. 99-19, Reporting Revenue Gross as a
Principal versus Net as an Agent, which provides guidance on the gross
versus net presentation of revenues and expenses. These reclassifications
impacted operating revenues and expenses, but had no impact on net income.
(3) The increase to our 2000 operating revenues and total assets reflects the
significant growth in our Merchant Energy operations.
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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
GENERAL
During 1998 and again in 1999, El Paso completed tax-free internal
reorganizations of its businesses and those of its subsidiaries. As a result of
its 1998 reorganization, Merchant Energy and Field Services became our
subsidiaries, and we transferred some of our corporate assets and liabilities
and discontinued operations to El Paso. Following this reorganization, we
continued to own the Tennessee Gas Pipeline and Midwestern interstate systems,
as well as the discontinued operations not included in the transfer to El Paso.
In its 1999 reorganization, El Paso contributed its power service business and
the merchant operations of Sonat to us. These internal reorganizations 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 included herein was restated as though the transactions occurred
at the beginning of the earliest period presented.
Purchase of Texas Midstream Operations
In late December 2000, we completed our purchase of PG&E's Texas Midstream
operations for $887 million, including the assumption of $527 million of debt.
We accounted for this acquisition as a purchase. The assets acquired consist of
7,500 miles of natural gas transmission and natural gas liquids pipelines that
transport approximately 2.8 Bcf/d, nine natural gas processing plants that
process 1.5 Bcf/d, and rights to 7.2 Bcf of natural gas storage capacity. These
assets serve a majority of the metropolitan areas and the largest industrial
load centers in Texas, as well as numerous natural gas trading hubs. These
assets also create a physical link between our TGP system and the EPNG system.
In March 2001, Field Services sold some of these acquired natural gas liquids
transportation and fractionation assets to Energy Partners. The assets sold
include more than 600 miles of natural gas liquids gathering and transportation
pipelines and three fractionation plants located in south Texas.
In December 2000, to comply with a Federal Trade Commission (FTC) order, we
sold our interest in Oasis Pipeline Company. Proceeds from the sale were $22
million and we recognized an extraordinary loss of $19 million, net of income
taxes of $9 million.
Merger-Related Costs and Asset Impairment Charges
In October 1999, El Paso merged with Sonat Inc., and in January 2001, El
Paso merged with The Coastal Corporation. The Sonat merger impacted our 1999
operating results, and we expect that additional charges related to the Coastal
merger will be incurred in 2001, as the operations of Coastal are integrated
with El Paso's and our operations. These costs may include employee severance,
retention, and transition charges; write-offs or write-downs of duplicate
assets; charges to relocate assets and employees; contract termination charges;
and charges to align accounting policies and practices.
As a result of El Paso's merger with Coastal, we will also be required to
sell our Midwestern system. Proceeds from the sale are expected to be
approximately $90 million, and will result in a before tax gain of approximately
$50 million. We expect to complete this sale in the second quarter of 2001. We
will treat this gain as an extraordinary item in our income statement.
Additionally, in the first quarter of 2001 Energy Partners sold its
interest in several offshore assets. These sales consisted of interests in seven
natural gas pipeline systems, a dehydration facility and two offshore platforms.
Proceeds from these sales were approximately $135 million and resulted in a loss
to the partnership of approximately $23 million. As additional consideration for
these sales, Field Services committed to pay Energy Partners a series of
payments totaling $29 million. This amount, as well as our proportional share of
the losses on the sale of the partnership's assets, will be recorded as a charge
in our income statement in the first quarter of 2001.
We do not anticipate the impact of the sale of our Midwestern system or the
transactions by or with Energy Partners to have a material effect on our ongoing
financial position, operating results, or cash flows.
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Also during the two year period ended December 31, 2000, we incurred a
variety of asset impairment charges related to write-downs of operating plants
and contracts that were determined to be impaired.
Our merger-related costs and asset impairment charges are reflected in the
results of operations discussed below for each of our segments. The table below
provides a summary of our merger-related costs and asset impairment charges by
each of our business segments, and in total, for each of the two years ended
December 31:
2000 1999
---- ----
(IN MILLIONS)
Merger-related costs and asset impairment charges
Merchant Energy........................................... $ -- $67
Field Services............................................ 11 8
---- ---
Total.................................................. $ 11 $75
==== ===
SEGMENT RESULTS OF OPERATIONS
Our business activities are segregated into three segments: Pipelines,
Merchant Energy, and Field Services. These segments are strategic business units
that offer a variety of different energy products and services. During the
fourth quarter of 2000, we combined our International segment with our Merchant
Energy segment to reflect the ongoing globalization of the Merchant Energy
strategy and its operating activities. In addition, our operating results
reflect the acquisition of PG&E's Texas Midstream operations as of the purchase
date. We manage each of our segments separately as each requires different
technology and marketing strategies. Since earnings from unconsolidated
affiliates can be a significant component of earnings in several of our
segments, we evaluate segment performance based on earnings before interest
expense and taxes, or EBIT, instead of operating income.
To the extent possible, results of operations 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 those periods.
Operating revenues and expenses by segment include intersegment revenues and
expenses which are eliminated in consolidation. Because changes in energy
commodity prices have a similar impact on both our operating revenues and cost
of products sold from period to period, we believe that gross margin (revenue
less cost of sales) provides a more accurate and meaningful basis for analyzing
operating results for the Merchant Energy and the Field Services segments. For a
further discussion of the individual segments, see Item 8, Financial Statements
and Supplementary Data, Note 11.
The following table presents EBIT by segment and in total, including the
merger-related costs and asset impairment charges discussed above, for each of
the three years ended December 31:
2000 1999 1998
------ ---- ----
(IN MILLIONS)
EARNINGS BEFORE INTEREST EXPENSE AND INCOME TAXES
Pipelines................................................... $ 354 $383 $356
Merchant Energy............................................. 563 3 28
Field Services.............................................. 88 78 78
------ ---- ----
Segment EBIT.............................................. 1,005 464 462
------ ---- ----
Corporate income (expenses), net............................ (17) (17) 2
------ ---- ----
Consolidated EBIT......................................... $ 988 $447 $464
====== ==== ====
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PIPELINES
Our Pipelines segment operates our interstate pipeline businesses. Each of
this segment's pipeline systems operates under a separate tariff that governs
its operations and rates. Operating results for our pipeline systems have
generally been stable because the majority of the revenues are based on fixed
demand charges. As a result, we expect changes in this aspect of our business to
be primarily driven by regulatory actions and contractual events. Commodity or
throughput-based revenues account for a smaller portion of our operating
results. These revenues vary from period to period, and system to system, and
are impacted by factors such as weather, operating efficiencies, competition
from other pipelines, and to a lesser degree, fluctuations in natural gas
prices. Results of operations of our Pipelines segment were as follows for each
of the three years ending December 31:
2000 1999 1998
------ ------ ------
(IN MILLIONS)
Operating revenues.......................................... $ 776 $ 852 $ 799
Operating expenses.......................................... (441) (492) (467)
Other income................................................ 19 23 24
------ ------ ------
EBIT...................................................... $ 354 $ 383 $ 356
====== ====== ======
Total throughput (BBtu/d)......................... 4,635 4,510 4,695
====== ====== ======
YEAR ENDED DECEMBER 31, 2000 COMPARED TO YEAR ENDED DECEMBER 31, 1999
Operating revenues for the year ended December 31, 2000, were $76 million
lower than the same period in 1999. The decrease was due to the impact of the
sale of our East Tennessee Pipeline system in the first quarter of 2000, which
El Paso was required to sell under an FTC order as a condition to completing the
Sonat merger. Also contributing to the decrease was the impact of customer
settlements and contract terminations in 2000, and the favorable resolution of
regulatory issues and sale of emission credits in 1999. The decreases were
partially offset by higher revenues from transportation and other services due
to improved average throughput in 2000.
Operating expenses for the year ended December 31, 2000, were $51 million
lower than the same period in 1999. The decrease was due to cost efficiencies
following El Paso's merger with Sonat and lower operating costs on our East
Tennessee Pipeline system, which was sold in the first quarter of 2000.
Other income for the year ended December 31, 2000, was $4 million lower
than the same period in 1999 primarily due to a gain on the sale of non-pipeline
assets recorded in 1999.
YEAR ENDED DECEMBER 31, 1999 COMPARED TO YEAR ENDED DECEMBER 31, 1998
Operating revenues for the year ended December 31, 1999, were $53 million
higher than the same period in 1998. This increase was primarily due to the
favorable resolution of regulatory issues in 1999, a downward revision in 1998
of the amount of recoverable interest on gas supply realignment costs, and the
resolution of customer imbalance issues in 1999. These increases were partially
offset by lower system throughput in 1999.
Operating expenses for the year ended December 31, 1999, were $25 million
higher than the same period in 1998. The increase was primarily due to an
increase in shared services allocations.
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MERCHANT ENERGY
Merchant Energy is a market maker involved in a wide range of activities in
the wholesale energy market place, including trading and risk management, asset
ownership and financial services. Each of the markets served by Merchant Energy
is highly competitive, and is influenced directly or indirectly by energy market
economics.
Merchant Energy's trading and risk management activities provide
sophisticated energy trading and energy management solutions for its customers
and affiliates involving primarily natural gas and power. Within its trading and
risk management operations, Merchant Energy originates transactions with its
customers to assist them with energy supply aggregation, storage and
transportation management, as well as valuation and risk management. Merchant
Energy maintains a substantial trading portfolio that balances its position risk
across multiple commodities and over seasonally fluctuating energy demands.
During 2000, U.S. energy supply and demand resulted in substantial volatility in
the energy markets that significantly impacted Merchant Energy's earnings
opportunities. This volatility is expected to continue for 2001, although not
necessarily at the same levels we experienced in 2000.
Merchant Energy is a provider of power and natural gas to the state of
California. During the latter half of 2000, and continuing into 2001, California
has experienced sharp increases in natural gas prices and wholesale power prices
due to energy shortages resulting from the concurrence of a variety of
circumstances, including unusually warm summer weather followed by high winter
demand, low gas storage levels, poor hydroelectric power conditions, maintenance
downtime of significant generation facilities, and price caps that discouraged
power movement from other nearby states into California.
The increase in power prices caused by the imbalance of natural gas and
power supply and demand coupled with electricity price caps imposed on rates
allowed to be charged to California electricity customers has resulted in large
cash deficits to the two major California utilities, Southern California Edison
and Pacific Gas and Electric. As a result, both utilities have defaulted on
payments to creditors and have accumulated substantial under collections from
customers, which has resulted in their credit ratings being downgraded in 2001
from above investment grade to below investment grade. The utilities filed for
emergency rate increases with the California Public Utilities Commission and are
working with the state authorities to restore the companies' financial
viability. We have historically been one of the largest suppliers of energy to
California, and we are actively participating with all parties in California to
be a part of a long-term, stable solution to California's energy needs. As of
March 2001, Merchant Energy believes its exposure for sales of power and gas to
the state of California, including receivables related to its interest in
California power plant investments, is approximately $50 million, net of credit
reserves to reflect market uncertainties.
Merchant Energy's asset ownership activities include global power plants
and the power facilities owned and managed on behalf of Chaparral. Its
asset-based businesses include power plants in 16 countries. Merchant Energy is
also actively involved in developing a global LNG operation. During 2000,
Merchant Energy earned $80 million in fee based revenue from Chaparral and was
reimbursed $20 million for operating expenses. We expect the 2001 fee based
revenue to increase to approximately $147 million based on the growth in the
Chaparral asset portfolio.
In the financial services area, Merchant Energy owns EnCap and Enerplus,
and conducts other energy financing activities. EnCap manages three separate oil
and natural gas investment funds in the U.S., and serves as an investment
advisor to one fund in Europe. EnCap also facilitates investment in emerging
energy companies and earns a return from these investments. In 2000, Merchant
Energy acquired Enerplus, a
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Canadian investment management company through which it conducts fund management
activities similar to EnCap, but in Canada. Below are Merchant Energy's
operating results and an analysis of those results for each of the three years
ended December 31:
2000 1999 1998
----- ----- -----
(IN MILLIONS)
Trading gross margin........................................ $ 406 $ 91 $ 71
Operating and other revenues................................ 291 119 58
Operating expenses.......................................... (264) (301) (166)
Other income................................................ 130 94 65
----- ----- -----
EBIT...................................................... $ 563 $ 3 $ 28
===== ===== =====
VOLUMES
2000 1999 1998
------- ------ ------
(EXCLUDES INTRASEGMENT
TRANSACTIONS)
Physical
Natural Gas (BBtue/d)..................................... 6,899 6,713 7,089
Power (MMWh).............................................. 113,652 79,361 55,210
Petroleum (MBbls)......................................... 7,772 4,990 21,716
Financial Settlements (Bbtue/d)............................. 98,574 68,678 31,793
YEAR ENDED DECEMBER 31, 2000 COMPARED TO YEAR ENDED DECEMBER 31, 1999
Trading gross margin represents revenue from physical energy commodity
sales less costs of these sales as well as results from financial trading
activities. For the year ended December 31, 2000, trading gross margin was $315
million higher than the same period in 1999. Commodity marketing and trading
margins increased due to significant price volatility in natural gas and power
markets which increased the value of our trading portfolio during 2000. Also
contributing to the increase was higher income from power transactions
originated in 2000 versus 1999. These increases were partially offset by natural
gas transactions originated in 1999.
Operating and other revenues represent all operating and other revenues,
excluding revenue from energy commodity sales. For the year ended December 31,
2000, these revenues were $172 million higher than the same period in 1999. The
increase was due to higher asset management fees earned from Chaparral, which
began operations during the fourth quarter of 1999, the consolidation of a
Brazilian power project in the latter part of 1999, and higher income on the
West Georgia power project, a seasonal peaking facility, which began operating
in June 2000. Encap's financial services activities in 2000, and the acquisition
of Enerplus in March 2000 also contributed to the increase.
Operating expenses for the year ended December 31, 2000, were $37 million
lower than the same period in 1999. The decrease was due to higher
reimbursements in 2000 of general and administrative costs relating to
Chaparral, a 1999 charge to eliminate a minority investor in Sonat's marketing
joint venture following the Sonat merger, and 1999 asset writedowns and charges
to conform and consolidate accounting practices and policies with those of Sonat
following the merger. The decrease was partially offset by higher general and
administrative expenses and project development costs relating to international
projects in 2000.
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Other income for the year ended December 31, 2000, was $36 million higher
than the same period in 1999. The increase was due to higher earnings from power
projects and investments, primarily CE Generation, which was acquired in March
1999, as well as the benefit realized from the formation of our East Asia Power
joint venture in March 2000. Also contributing to the increase was a settlement
received from our Indonesian project in May 2000, and higher interest income.
These increases were partially offset by lower equity earnings from investments
in various international projects, primarily our investment in East Asia Power
in the Philippines.
YEAR ENDED DECEMBER 31, 1999 COMPARED TO YEAR ENDED DECEMBER 31, 1998
Trading gross margin for the year ended December 31, 1999, was $20 million
higher than the same period in 1998. Commodity marketing and trading margins
increased due to transactions originated in 1999, partially offset by a decrease
in trading margins in 1999.
Operating and other revenues for the year ended December 31, 1999, were $61
million higher than the same period in 1998. The increase was primarily due to
management fees earned from Chaparral, revenues from a Brazilian power project
consolidated during the latter part of 1999, and revenues from consolidated
power generation facilities acquired in December 1998.
Operating expenses for the year ended December 31, 1999, were $135 million
higher than the same period in 1998. The increase was due to higher operating
costs associated with an increase in power activities, operating expenses on
consolidated power generation facilities acquired in December 1998, a 1999
charge to eliminate a majority interest in Sonat's marketing joint venture
following the Sonat merger, and 1999 asset writedowns and charges to conform and
consolidate accounting practices and policies with those of Sonat following the
merger. Also contributing to the increase were higher general and administrative
costs and higher operating costs from our Brazilian power project. The increases
were partially offset by lower project development costs on international
projects in 1999.
Other income for the year ended December 31, 1999, was $29 million higher
than the same period in 1998. The increase was due to higher earnings from power
projects and investments, primarily CE Generation, higher interest income, and
1999 equity swap gains recognized on our CAPSA project. These increases were
partially offset by 1998 gains on the sale of project-related activities and
surplus power equipment.
FIELD SERVICES
Field Services provides a variety of services for the midstream component
of our operations, including gathering and treating of natural gas, processing
and fractionation of natural gas, natural gas liquids and natural gas derivative
products, such as butane, ethane, and propane. A subsidiary of Field Services
also serves as the general partner of Energy Partners, a publicly traded, master
limited partnership. As the general partner, Field Services earns a combination
of management fees and partner distributions for services rendered to Energy
Partners. Field Services attempts to balance its earnings from these activities
through a combination of contractually based and market based services.
The gathering and treating operations earn margins substantially from
fee-based services. This means revenues are the product of a market price,
usually related to the monthly natural gas price index, and the volume gathered.
During most of 2000, Field Services hedged a substantial amount of the risk
associated with the changes in natural gas prices by entering into forward
natural gas derivatives.
Processing and fractionation operations earn a margin based on both
fee-based contracts and make-whole contracts. Make-whole contracts allow us to
retain the extracted liquid products and to return to the producer a Btu
equivalent amount of natural gas. During periods when natural gas and liquid
prices are volatile, Field Services may be at greater price risk under its
make-whole contracts. Make-whole contracts constitute a greater portion of the
operating contracts acquired in late December in connection with our acquisition
of PG&E's Texas Midstream operations.
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Field Services' operating results and an analysis of those results are as
follows for each of the three years ended December 31:
YEAR ENDED DECEMBER 31,
---------------------------
2000 1999 1998
----- ----- -----
(IN MILLIONS)
Gathering and treating margin............................... $ 178 $ 162 $ 157
Processing margin........................................... 69 44 48
Other margin................................................ 2 1 3
----- ----- -----
Total gross margin................................ 249 207 208
Operating expenses.......................................... (165) (161) (142)
Other income................................................ 4 32 12
----- ----- -----
EBIT...................................................... $ 88 $ 78 $ 78
===== ===== =====
Volume and prices
Gathering and treating
Volumes (BBtu/d)....................................... 3,468 3,821 4,067
===== ===== =====
Prices ($/MMBtu)....................................... $0.17 $0.14 $0.13
===== ===== =====
Processing
Volumes (inlet BBtu/d)................................. 1,065 1,032 1,014
===== ===== =====
Prices ($/MMBtu)....................................... $0.18 $0.12 $0.13
===== ===== =====
YEAR ENDED DECEMBER 31, 2000 COMPARED TO YEAR ENDED DECEMBER 31, 1999
Total gross margin for the year ended December 31, 2000, was $42 million
higher than the same period in 1999. Gathering and treating margins increased
due to higher average gathering rates, predominately in the San Juan Basin,
which are substantially indexed to natural gas prices, and higher average
condensate prices. The higher 2000 margin was partially offset by lower
gathering and treating volumes due to the sale of El Paso Intrastate-Alabama, a
gathering system in the coal-bed methane producing regions of Alabama, to El
Paso Energy Partners in March 2000. Processing margins increased due to higher
liquids prices in 2000 and the acquisition, in April 2000, of an interest in the
Indian Basin processing assets.
Operating expenses for the year ended December 31, 2000, were $4 million
higher than the same period in 1999 due to higher depreciation and amortization
from assets transferred from El Paso Natural Gas to Field Services following a
FERC order as well as the December 2000 impairment charge related to the Needle
Mountain processing facility due to unrecoverability of costs. The increase was
partially offset by the impairment of gathering assets in 1999, lower costs for
labor and benefits, and cost recoveries from managed facilities.
Other income for the year ended December 31, 2000, was $28 million lower
than the same period in 1999. The decrease was primarily due to net gains in
1999 from the sale of our interest in the Viosca Knoll Gathering System to
Energy Partners in June 1999, as well as lower equity earnings following the
sale of our interest in Viosca Knoll.
YEAR ENDED DECEMBER 31, 1999 COMPARED TO YEAR ENDED DECEMBER 31, 1998
Total gross margin for the year ended December 31, 1999 was $1 million
lower than the same period in 1998. Gathering and treating margins increased due
to higher volumes and average gathering rates, which are substantially indexed
to natural gas prices, partially offset by the elimination of margins on assets
in the Anadarko Basin that were sold in September 1998. Processing margins
decreased due to lower liquids prices and the sale of two processing facilities
in 1999.
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Operating expenses for the year ended December 31, 1999 were $19 million
higher than the same period in 1998. The increase was due to higher shared
services allocations in 1999, the impairment of gathering assets in the fourth
quarter of 1999, and an increase in depreciation and amortization resulting from
acquisitions.
Other income for the year ended December 31, 1999, was $20 million higher
than the same period in 1998. The increase was due to net gains in 1999 from the
sale of our interest in Viosca Knoll offset by lower equity earnings following
the sale of Viosca Knoll.
INTEREST AND DEBT EXPENSE
YEAR ENDED DECEMBER 31, 2000 COMPARED TO YEAR ENDED DECEMBER 31, 1999
Non-affiliated Interest and Debt Expense
Non-affiliated interest and debt expense for the year ended December 31,
2000, was $6 million higher than 1999 due to higher finance costs on
international projects, higher Merchant Energy over-the-counter margins, and
higher average commercial paper borrowings.
Affiliated Interest and Debt Expense
Affiliated interest expense for the year ended December 31, 2000, was $82
million higher than 1999 due to an increase in advances from El Paso for ongoing
capital projects, investment programs, and operating requirements. The increase
was also due to higher average interest rates with El Paso in 2000.
YEAR ENDED DECEMBER 31, 1999 COMPARED TO YEAR ENDED DECEMBER 31, 1998
Non-affiliated Interest and Debt Expense
Non-affiliated interest and debt expense for the year ended December 31,
1999, was $13 million higher than 1998 due to increased borrowings to fund
capital expenditures, acquisitions, and other investing expenditures offset by
higher interest capitalized in 1999 from project investment and development
activities primarily in the Merchant Energy segment.
Affiliated Interest and Debt Expense
Affiliated interest expense, net for the year ended December 31, 1999, was
$12 million higher than 1998, primarily due to an increase in affiliated average
debt balance borrowings by us.
INCOME TAX EXPENSE
Income tax expense for the years ended December 31, 2000, 1999, and 1998,
was $242 million, $85 million, and $92 million. These amounts resulted in
effective tax rates of 33 percent, 31 percent, and 29 percent. Differences in
our effective tax rates from the statutory tax rate of 35 percent were primarily
a result of the following factors:
- state income taxes;
- earnings from unconsolidated equity investees where we anticipate
receiving dividends;
- foreign income, not taxed in the U.S., but taxed at foreign tax rates;
and
- the non-deductible portion of merger-related costs.
For a reconciliation of the statutory rate of 35 percent to the effective
rates in each of the three years ended December 31, 2000, see Item 8, Financial
Statements and Supplementary Data, Note 4.
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LIQUIDITY AND CAPITAL RESOURCES
CASH FROM OPERATING ACTIVITIES
Net cash used in our operating activities was $1,025 million for the year
ended December 31, 2000, compared to net cash provided by operating activities
of $325 million for 1999. The increase in cash used in operations was primarily
a result of cash expended in our price risk management activities as well as
higher trading receivables and payables related to substantial growth in our
trading portfolio and higher prices in the energy commodity markets. We also had
higher interest and income tax payments in 2000. In 2001, we anticipate cash
demands from our expanded merchant activities to continue.
CASH FROM INVESTING ACTIVITIES
Net cash used in our investing activities was $852 million for the year
ended December 31, 2000. Our investing activities principally consisted of
additions to joint ventures and equity investments, including an increase in our
Chaparral equity investment, the purchase of an additional 18.5% interest in an
Argentine company, CAPSA, and the purchase of an investment in a Korean power
company, Korea Independent Energy Corporation (formerly Hanwha Energy Co.,
Ltd.). Other investing activities in 2000 included the acquisitions of PG&E's
Texas Midstream Operations, the acquisition of Enerplus Global Management, an
interest in the Indian Basin gas processing plant assets, and expenditures for
expansion and construction projects. Cash inflows from investment related
activities included proceeds from the sales of our East Tennessee Pipeline
system, West Georgia Generating Company, and El Paso Intrastate-Alabama pipeline
system. We also received proceeds from the formation of our East Asia Power
joint venture.
CASH FROM FINANCING ACTIVITIES
Net cash provided by our financing activities was $2,024 million for the
year ended December 31, 2000. Cash provided from our financing activities
included proceeds from capital contributions provided to us by El Paso related
to an increase in our Chaparral equity investment and the Enerplus Global
Management acquisition and advances from El Paso. Financing activities also
included the repayment of short-term borrowings, the issuance and repayment of
notes related to East Asia Power, and the payment of dividends.
LIQUIDITY
We rely on cash generated from internal operations as our primary source of
liquidity, supplemented by our available credit facilities and commercial paper
programs. The availability of borrowings under our credit agreements is subject
to specified conditions, which we believe we currently meet. These conditions
include compliance with the financial covenants and ratios required by our
agreements, absence of default under these agreements, and continued accuracy of
our representations and warranties (including the absence of any material
adverse changes since the specified dates).
We expect that future funding for our working capital needs, capital
expenditures, acquisitions, other investing activities, long-term debt
retirements, payments of dividends and other financing expenditures will be
provided by internally generated funds, commercial paper issuances, available
capacity under existing credit facilities, the issuance of new long-term debt or
equity, and/or contributions from El Paso. For a discussion of our financing
arrangements, see Item 8, Financial Statements and Supplementary Data, Note 7.
COMMITMENTS AND CONTINGENCIES
See Item 8, Financial Statements and Supplementary Data, Note 8, for a
discussion of our Commitments and Contingencies which is incorporated by
reference herein.
NEW ACCOUNTING PRONOUNCEMENTS NOT YET ADOPTED
See Item 8, Financial Statements and Supplementary Data, Note 1, for a
discussion relating to new accounting pronouncements not yet adopted.
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CAUTIONARY STATEMENT FOR PURPOSES OF THE "SAFE HARBOR" PROVISIONS OF THE PRIVATE
SECURITIES LITIGATION REFORM ACT OF 1995
This report contains or incorporates by reference forward-looking
statements within the meaning of the Private Securities Litigation Reform Act of
1995. Where any forward-looking statement includes a statement of the
assumptions or bases underlying the forward-looking statement, we caution that,
while we believe these assumptions or bases to be reasonable and to be made in
good faith, assumed facts or bases almost always vary from the actual results,
and 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, that expectation or belief is expressed in good faith and is believed
to have a reasonable basis. We cannot assure you, however, that the statement of
expectation or belief will result or be achieved or accomplished. The words
"believe," "expect," "estimate," "anticipate" and similar expressions will
generally identify forward-looking statements.
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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
We utilize derivative financial instruments to manage market risks
associated with energy commodities and interest and foreign currency exchange
rates. Our market risks are monitored by El Paso's corporate risk management
committee that operates independently from our business segments that create or
actively manage these risk exposures to ensure compliance with our overall
stated risk management policies as approved by El Paso's Board of Directors.
TRADING COMMODITY PRICE RISK
Our Merchant Energy segment is exposed to market risks inherent in the
financial instruments it uses for trading energy and energy related commodities.
Merchant Energy records its energy trading activities, including transportation
capacity and storage at fair value. Changes in fair value are reflected in our
income statement. Merchant Energy's policy is to manage commodity price risks
through a variety of financial instruments, including:
- exchange-traded futures contracts involving cash settlements;
- forward contracts involving cash settlements or physical delivery of an
energy commodity;
- swap contracts which require payment to (or receipts from) counterparties
based on the difference between fixed and variable prices for the
commodity;
- exchange-traded and over-the-counter options; and
- other contractual arrangements.
Merchant Energy manages its market risk, subject to parameters established
by El Paso's corporate risk management committee. Comprehensive risk management
processes, policies, and procedures have been established to monitor and control
its market risk. El Paso's risk management committee also continually reviews
these policies to ensure they are responsive to changing business conditions.
Merchant Energy measures the risk in its commodity and energy related
contracts on a daily basis utilizing a Value-at-Risk model to determine the
maximum potential one-day unfavorable impact on its earnings, due to normal
market movements, and monitors its risk in comparison to established thresholds.
The Value-at-Risk computations capture a significant portion of the exposure
related to option positions, and utilize historical price movements over a
specified period to project future price movements in the energy markets.
Merchant Energy also utilizes other measures to provide additional assurance
that the risks in its commodity and energy related contracts are being properly
monitored on a daily basis, including sensitivity analysis, position limit
control and credit risk management.
Based on a confidence level of 95 percent and a one-day holding period,
Merchant Energy's estimated potential one-day unfavorable impact on income
before income taxes and minority interest, as measured by Value-at-Risk, related
to contracts held for trading purposes was approximately $19 million, $3 million
and $3 million at December 31, 2000, 1999, and 1998. The increase in
Value-at-Risk during 2000 reflects the significant increase in our commodity
trading activities during the period. In 2000, Merchant Energy's highest,
lowest, and average estimated potential one day unfavorable impact on income
before taxes and minority interest, as measured by Value-at-Risk were $19
million, $2 million and $9 million. In the fourth quarter of 2000, Merchant
Energy also began managing asset based commodity transactions under the same
Value-at-Risk methodology utilized for trading purposes. The potential one-day
unfavorable impact on income before income taxes and minority interest related
to these asset based commodity transactions as measured by Value-at-Risk was $10
million at December 31, 2000. In 2000, the highest, lowest and average estimated
one-day unfavorable impact on income before income taxes and minority interest
for the asset based commodity transactions, as measured by Value-at-Risk, were
$10 million, $5 million, and $8 million. The average value represents the
average of the 2000 month end values. The high and low valuations represent the
highest and lowest month end values during 2000. Actual losses could exceed
those measured by Value-at-Risk.
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NON-TRADING COMMODITY PRICE RISK
We mitigate market risk associated with significant physical transactions
through the use of non-trading financial instruments, including forward
contracts and swaps. Merchant Energy hedges a portion of its anticipated
purchases and sales of natural gas.
The estimated potential one-day unfavorable impact on income before income
taxes and minority interest, as measured by Value-at-Risk, related to our
non-trading commodity activities was insignificant at December 31, 2000, 1999,
and 1998.
INTEREST RATE RISK
Many of our debt related financial instruments and project financing
arrangements are sensitive to market fluctuations in interest rates. In March
1997, we purchased a 10.5 percent interest in CAPSA for approximately $57
million and entered into an equity swap for an additional 18.5 percent
ownership. Under the equity swap, we paid interest to a counterparty, on a
quarterly basis, on a notional amount of $100 million at a rate of LIBOR plus
0.85 percent. In exchange, we received 18.5 percent of CAPSA's dividends. In
February 1999, we extended the term of the swap and modified the notional amount
to $103 million at a rate of LIBOR plus 1.75 percent. In May 2000, we exercised
our right to terminate the swap and purchased the counterparty's 18.5 percent
ownership interest in CAPSA for approximately $127 million. During the term of
this swap, we reflected changes in the market value of the equity swap in our
income statement. The termination of the swap did not materially impact our
financial statements.
We also have notes payable to unconsolidated affiliates which reflects our
cash management program with El Paso whereby we are advanced cash to fund our
operations.
The table below shows cash flows and related weighted average interest
rates of our interest bearing securities, by expected maturity dates. As of
December 31, 2000, the carrying amounts of short-term borrowings are
representative of fair values because of the short-term maturity of these
instruments. The fair value of the long-term debt has been estimated based on
quoted market prices for the same or similar issues.
DECEMBER 31, 2000 DECEMBER 31, 1999
------------------------------------------------------------------------ ---------------------
EXPECTED FISCAL YEAR OF MATURITY OF CARRYING AMOUNTS
------------------------------------------------------------------------ CARRYING
2001 2002 2003 2004 2005 THEREAFTER TOTAL FAIR VALUE AMOUNTS FAIR VALUE
------ ---- ---- ---- ---- ---------- ------ ------------- -------- ----------
(DOLLARS IN MILLIONS)
LIABILITIES:
Short-term debt -- variable
rate......................... $ 215 $ 215 $ 215 $ 649 $ 649
Average interest rate.... 5.6%
Notes payable to unconsolidated
affiliates -- variable
interest rate................ $3,769 $3,769 $3,769 $1,400 $1,400
6.7%
Long-term debt, including
current portion -- fixed
rate......................... $ 132 $107 $ 41 $ 71 $ 91 $1,535 $1,977 $2,004 $1,467 $1,405
Average interest rate.... 9.3% 9.1% 10.2% 9.8% 8.9% 7.7%
FOREIGN CURRENCY EXCHANGE RATE RISK
We manage our exposure to changes in foreign currency exchange rates by
entering into derivative financial instruments, principally foreign currency
forward purchase and sale contracts. Our primary exposure
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relates to changes in foreign currency rates on certain of our merchant
activities outside the U.S. not denominated or adjusted to U.S. dollars. The
following table summarizes the notional amounts, average settlement rates, and
fair value for foreign currency forward purchase and sale contracts as of
December 31, 2000:
NOTIONAL AMOUNT FAIR VALUE
IN FOREIGN AVERAGE IN
CURRENCY SETTLEMENT U.S. DOLLARS
(IN MILLIONS) RATES (IN MILLIONS)
--------------- ---------- -------------
Canadian Dollars Purchase................................ 1,095 0.673 $(3)
Sell.................................... 441 0.686 6
---
$ 3
===
Korean Won Sell.................................... 132,500 0.0008 $ 1
Philippine Peso Sell.................................... 4,392 0.0203 $ 1
The following table summarizes foreign currency forward purchase and sale
contracts by expected maturity dates along with annual anticipated cash flow
impacts as of December 31, 2000:
EXPECTED MATURITY DATES
-----------------------------------------------------
2001 2002 2003 2004 2005 THEREAFTER TOTAL
---- ---- ---- ---- ---- ---------- -----
(IN MILLIONS)
Canadian Dollars Purchase......................... $(1) $(2) $(1) $-- $-- $ 1 $(3)
Sell............................. 3 2 1 -- -- -- 6
--- --- --- --- --- --- ---
Net cash flow effect............. $ 2 $-- $-- $-- $-- $ 1 $ 3
=== === === === === === ===
Korean Won Sell............................. $ 1 $-- $-- $-- $-- $-- $ 1
Philippine Peso Sell............................. $ 1 $-- $-- $-- $-- $-- $ 1
EQUITY RISK
Through Merchant Energy's financial services unit, we manage and invest in
private investment funds as well as privately placed securities of both
privately and publicly held companies. We account for these investments using
investment company accounting. As a result, these holdings are measured at their
fair value with changes in fair value recorded in our income statement. The fair
value of these investments are determined based on estimates of amounts that
would be realized if these securities were sold. Below are the fair values of
our investments subject to equity risks at December 31, 2000 and 1999, as well
as the impact of a ten percent increase or decrease in the fair values of those
investments for each period presented:
2000 1999
------------------------------------ ------------------------------------
IMPACT OF IMPACT OF IMPACT OF IMPACT OF
10 PERCENT 10 PERCENT 10 PERCENT 10 PERCENT
FAIR VALUE INCREASE DECREASE FAIR VALUE INCREASE DECREASE
---------- ---------- ---------- ---------- ---------- ----------
(IN MILLIONS)
Investment funds............... $ 7 $ 1 $(1) $ 4 $-- $--
Securities..................... 54 5 (5) 7 1 (1)
Other.......................... 1 -- -- 1 -- --
--- --- --- --- --- ---
Total................ $62 $ 6 $(6) $12 $ 1 $(1)
=== === === === === ===
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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
EL PASO TENNESSEE PIPELINE CO.
CONSOLIDATED STATEMENTS OF INCOME
(IN MILLIONS)
YEAR ENDED DECEMBER 31,
---------------------------
2000 1999 1998
------- ------ ------
Operating revenues
Transportation............................................ $ 625 $ 727 $ 729
Energy commodities........................................ 19,401 8,458 7,560
Gathering and processing.................................. 452 285 141
Other..................................................... 310 200 110
------- ------ ------
20,788 9,670 8,540
------- ------ ------
Operating expenses
Cost of natural gas and other products.................... 19,109 8,411 7,411
Operation and maintenance................................. 543 577 519
Merger-related costs and asset impairment charges......... 11 75 --
Depreciation, depletion, and amortization................. 223 247 208
Taxes, other than income taxes............................ 62 62 56
------- ------ ------
19,948 9,372 8,194
------- ------ ------
Operating income............................................ 840 298 346
------- ------ ------
Other income
Earnings from unconsolidated affiliates................... 61 61 45
Interest income........................................... 35 30 15
Net gain on sale of assets................................ 24 24 34
Other, net................................................ 28 34 24
------- ------ ------
148 149 118
------- ------ ------
Income before interest, income taxes, and other charges..... 988 447 464
------- ------ ------
Non-affiliated interest and debt expense.................... 142 136 123
Affiliated interest and debt expense, net................... 122 40 28
Income tax expense.......................................... 242 85 92
------- ------ ------
506 261 243
------- ------ ------
Income before extraordinary items and cumulative effect of
accounting change......................................... 482 186 221
Extraordinary items, net of income taxes.................... 58 -- --
Cumulative effect of accounting change, net of income
taxes..................................................... -- (13) --
------- ------ ------
Net income.................................................. $ 540 $ 173 $ 221
======= ====== ======
See accompanying notes.
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EL PASO TENNESSEE PIPELINE CO.
CONSOLIDATED BALANCE SHEETS
(IN MILLIONS, EXCEPT SHARE AMOUNTS)
DECEMBER 31,
----------------
2000 1999
------- ------
ASSETS
Current assets
Cash and cash equivalents................................. $ 179 $ 32
Accounts and notes receivable, net of allowance of $100 in
2000 and $23 in 1999
Customer............................................... 2,828 582
Unconsolidated affiliates.............................. 194 91
Other.................................................. 262 223
Inventory................................................. 84 23
Deferred income taxes..................................... 41 107
Assets from price risk management activities.............. 4,281 231
Other..................................................... 544 215
------- ------
Total current assets.............................. 8,413 1,504
Property, plant, and equipment, net......................... 6,988 6,004
Investments in unconsolidated affiliates.................... 2,070 1,509
Assets from price risk management activities................ 1,638 425
Other....................................................... 356 322
------- ------
Total assets...................................... $19,465 $9,764
======= ======
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities
Accounts and notes payable
Trade.................................................. $ 3,156 $ 881
Unconsolidated affiliates.............................. 3,769 1,400
Other.................................................. 179 220
Short-term borrowings (including current maturities of
long-term debt)........................................ 347 657
Liabilities from price risk management activities......... 2,880 234
Other..................................................... 701 299
------- ------
Total current liabilities......................... 11,032 3,691
------- ------
Long-term debt, less current maturities..................... 1,845 1,459
------- ------
Deferred credits and other..................................
Deferred income taxes..................................... 1,647 1,409
Liabilities from price risk management activities......... 898 95
Other..................................................... 838 592
------- ------
3,383 2,096
------- ------
Commitments and contingencies
Minority interest........................................... 51 88
------- ------
Stockholders' equity
Preferred stock, 20,000,000 shares authorized; Series A,
no par; 6,000,000 shares issued; stated at liquidation
value.................................................. 300 300
Common stock, par value $0.01 per share; authorized
100,000 shares; issued 1,971 shares.................... -- --
Additional paid-in capital................................ 1,962 1,707
Retained earnings......................................... 949 451
Accumulated other comprehensive income.................... (57) (28)
------- ------
Total stockholders' equity........................ 3,154 2,430
------- ------
Total liabilities and stockholders' equity........ $19,465 $9,764
======= ======
See accompanying notes.
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EL PASO TENNESSEE PIPELINE CO.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN MILLIONS)
YEAR ENDED DECEMBER 31,
---------------------------
2000 1999 1998
------- ------- -----
Cash flows from operating activities
Net income................................................ $ 540 $ 173 $ 221
Adjustments to reconcile net income to net cash from
operating activities
Depreciation, depletion, and amortization.............. 223 247 208
Deferred income tax expense............................ 207 69 93
Extraordinary items.................................... (99) -- --
Net gain on sale of assets............................. (24) (24) (34)
Undistributed earnings from unconsolidated
affiliates........................................... (21) (30) (29)
Non-cash portion of merger-related and asset impairment
charges.............................................. 11 75 --
Cumulative effect of accounting changes, net of income
taxes................................................ -- 13 --
Working capital changes, net of non-cash transactions
Accounts and notes receivable........................ (2,072) (76) 402
Change in price risk management activities, net...... (1,816) (178) (45)
Accounts payable..................................... 1,939 92 (440)
Other working capital changes........................ 94 (67) 168
Other.................................................. (7) 31 (269)
------- ------- -----
Net cash provided by (used in) operating
activities...................................... (1,025) 325 275
------- ------- -----
Cash flows from investing activities
Capital expenditures...................................... (471) (458) (309)
Additions to investments.................................. (794) (796) (547)
Cash paid for acquisitions, net of cash received.......... (368) (165) (30)
Net proceeds from the sale of assets...................... 650 31 60
Proceeds from sale of investments......................... 122 33 153
Change in cash deposited in escrow related to an equity
investee............................................... 24 (101) --
Net change in other affiliated advances receivable........ (15) -- (4)
------- ------- -----
Net cash used in investing activities............. (852) (1,456) (677)
------- ------- -----
Cash flows from financing activities
Net borrowings (repayments) of commercial paper........... (434) 459 190
Revolving credit repayments............................... -- -- (417)
Payments to retire long-term debt......................... (8) (4) (46)
Net proceeds from the issuance of long-term debt.......... -- -- 391
Dividends paid............................................ (25) (25) (25)
Increase (decrease) in notes to unconsolidated
affiliates............................................. (14) 101 --
Net change in affiliated advances payable................. 2,305 496 275
Capital contributions..................................... 200 108 20
Other..................................................... -- -- (2)
------- ------- -----
Net cash provided by financing activities......... 2,024 1,135 386
------- ------- -----
Increase (decrease) in cash and cash equivalents............ 147 4 (16)
Cash and cash equivalents
Beginning of period....................................... 32 28 44
------- ------- -----
End of period............................................. $ 179 $ 32 $ 28
======= ======= =====
See accompanying notes.
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EL PASO TENNESSEE PIPELINE CO.
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
(IN MILLIONS)
FOR THE YEARS ENDED DECEMBER 31,
---------------------------------------------------
2000 1999 1998
--------------- --------------- ---------------
SHARES AMOUNT SHARES AMOUNT SHARES AMOUNT
------ ------ ------ ------ ------ ------
Series A Preferred Stock..................... 6 $ 300 6 $ 300 6 $ 300
--- ------ -- ------ -- ------
Common stock................................. -- -- -- -- -- --
--- ------ -- ------ -- ------
Additional paid-in capital:
Balance at beginning of year............... 1,707 1,580 1,529
Capital contributions...................... 233 120 47
Allocated tax benefit of El Paso's equity
plans................................... 22 7 4
------ ------ ------
Balance at end of year.................. 1,962 1,707 1,580
------ ------ ------
Retained earnings:
Balance at beginning of year............... 451 306 114
Net income................................. 540 173 221
Dividends to parent........................ (18) (1) (3)
Preferred dividends........................ (25) (25) (25)
Other...................................... 1 (2) (1)
------ ------ ------
Balance at end of year.................. 949 451 306
------ ------ ------
Accumulated other comprehensive income:
Balance at beginning of year............... (28) (14) (7)
Cumulative translation adjustment.......... (31) (12) (7)
Realized loss on available-for-sale
securities, net of tax.................. 2 -- --
Net change in unrealized loss on
securities, net of tax.................. -- (2) --
------ ------ ------
Balance at end of year.................. (57) (28) (14)
------ ------ ------
Total stockholders' equity................... $3,154 $2,430 $2,172
====== ====== ======
Comprehensive income......................... $ 511 $ 159 $ 214
====== ====== ======
See accompanying notes.
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EL PASO TENNESSEE PIPELINE CO.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Change in Company Structure
In 1998 and again in 1999, El Paso completed tax-free internal
reorganizations of its businesses and those of its subsidiaries. Through a
series of transfers, El Paso's merchant energy, international, and field
services businesses became our subsidiaries, and we transferred some of our
corporate assets and liabilities and discontinued operations to El Paso. In
1998, the merchant energy operations were transferred to us in exchange for
934,000 shares of Series C preferred stock, valued at $47 million. We issued 971
shares of our common stock as consideration for the field services and
international businesses and for the redemption of our outstanding Series B and
Series C preferred stock. This transaction had a total book value of $667
million. In 1999, the power services business of El Paso and the merchant
operations of Sonat were transferred to us in the form of a capital
contribution. This transaction had a total book value of $98 million. These
internal reorganizations were treated as transfers of ownership between entities
under common control and were accounted for in a manner similar to a pooling of
interests. Accordingly, all information in our financial statements have been
restated as though the transactions occurred in the earliest period presented.
Basis of Presentation and Principles of Consolidation
Our consolidated financial statements include the accounts of all
majority-owned, controlled subsidiaries after the elimination of all significant
intercompany accounts and transactions. We account for investments in companies
where we have the ability to exert significant influence, but not control, over
operating and financial policies using the equity method. Our consolidated
financial statements for previous periods include reclassifications that were
made to conform to the current year presentation. Those reclassifications have
no impact on reported net income or stockholders' equity.
Use of Estimates
The preparation of financial statements in conformity with generally
accepted accounting principles requires us to make estimates and assumptions
that affect the reported amounts of assets, liabilities, revenues, and expenses
and disclosure of contingent assets and liabilities that exist at the date of
the financial statements. Our actual results are likely to differ from those
estimates.
Accounting for Regulated Operations
Our interstate natural gas systems are subject to the jurisdiction of FERC
in accordance with the Natural Gas Act of 1938 and the Natural Gas Policy Act of
1978. Each system operates under separate FERC approved tariffs which establish
rates, terms and conditions under which each system provides services to its
customers. Our businesses that are subject to the regulations and accounting
requirements of FERC have followed the accounting requirements of Statement of
Financial Accounting Standards (SFAS) No. 71, Accounting for the Effects of
Certain Types of Regulation, which may differ from the accounting requirements
of our non-regulated entities. Transactions that have been recorded differently
as a result of regulatory accounting requirements include the capitalization of
an equity return component on regulated capital projects, employee related
benefits, and other costs and taxes included in, or expected to be included in,
future rates, including costs to refinance debt.
When the accounting method followed is required by or allowed by the
regulatory authority for rate-making purposes, the method conforms to the
generally accepted accounting principle of matching costs with the revenues to
which they apply.
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Cash and Cash Equivalents
We consider short-term investments purchased with an original maturity of
less than three months to be cash equivalents.
Inventory
Our inventory consists of $26 million and $23 million in materials and
supplies as of December 31, 2000 and 1999, and $58 million in natural gas in
storage for non-trading purposes as of December 31, 2000. We value these
inventories at the lower of cost or market with cost determined using the
average cost method.
Property, Plant, and Equipment
Regulated. Our regulated property, plant, and equipment is recorded at its
original cost of construction or, upon acquisition, the cost to the entity that
first placed the asset in service. We capitalize direct costs, like labor and
materials, and indirect costs, like overhead and allowance for funds used during
construction. We capitalize the major units of property replacements or
improvements and expense the minor ones.
When applicable, we use the composite (group) method to depreciate
regulated property, plant, and equipment. Assets with similar lives and other
characteristics are grouped and depreciated as one asset. We apply the
depreciation rate, approved in our rates, to the total cost of the group, until
its net book value equals its salvage value. Currently, our depreciation rates
vary from 1 to 24 percent. Using these rates, the remaining economic lives of
these assets range from 2 to 33 years. We re-evaluate depreciation rates each
time we redevelop our transportation rates.
When we retire regulated property, plant, and equipment, we charge
accumulated depreciation and amortization for the original cost, plus the cost
of retirement (the cost to remove, sell, or dispose), less its salvage value. We
do not recognize a gain or loss unless we sell an entire operating unit. We
include gains or losses on dispositions of operating units in income.
Non-Regulated. We record our non-regulated property, plant, and equipment
at its original cost of construction or, upon acquisition, at the fair value of
the assets acquired. We capitalize all direct and indirect costs of the project,
including interest costs on related debt.
We depreciate these properties over their estimated useful lives using a
straight line or composite method. The annual depreciation rates are as follows:
Gathering and processing systems......................... 2.5% to 20.0%
Power facilities......................................... 2.0% to 33.0%
Transportation equipment................................. 2.5% to 10.0%
Buildings and improvements............................... 2.5% to 20.0%
Office and miscellaneous equipment....................... 10.0% to 33.0%
When we retire non-regulated properties, we reduce property, plant, and
equipment for its original cost, less accumulated depreciation, and salvage. Any
remaining amount is charged to income.
General. At December 31, 2000 and 1999, we had approximately $343 million
and $462 million of construction work in progress included in our property,
plant, and equipment.
We evaluate impairment of our regulated and non-regulated property, plant,
and equipment whenever events or changes in circumstances indicate that the
carrying amount of an asset may not be recoverable in accordance with SFAS No.
121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to be Disposed Of.
Intangible Assets
Intangible assets consist primarily of goodwill arising as a result of
mergers and acquisitions. We amortize these intangible assets using the
straight-line method over periods ranging from 5 to 40 years. Our
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accumulated amortization of intangible assets was $17 million and $40 million as
of December 31, 2000 and 1999. We evaluate impairment of goodwill in accordance
with SFAS No. 121. Under this methodology, when an event occurs to suggest that
impairment may have occurred, we evaluate the undiscounted net cash flows of the
underlying asset or entity. If these cash flows are not sufficient to recover
the value of the underlying asset or entity plus the goodwill amount, these cash
flows are discounted at a risk-adjusted rate with any difference recorded as a
charge to our income statement.
Revenue Recognition
Our regulated businesses recognize revenues from natural gas transportation
in the period the service is provided. Reserves are provided on revenues
collected that may be subject to refund. Revenues on services other than
transportation are recorded when they are earned.
Our non-regulated businesses record revenues at various points when they
are earned, including when deliveries of the physical commodities are made, or
in the period services are provided. See the discussion of price risk management
activities below for our revenue recognition policies on our trading activities.
In the fourth quarter of 2000, we implemented Emerging Issues Task Force
Issue No. 99-19, Reporting Revenue Gross as a Principal versus Net as an Agent,
which provides guidance on the gross versus net presentation of revenues and
expenses. As a result of adoption, revenues and related costs increased by $42
million, $80 million, and $33 million for 2000, 1999, and 1998. These
reclassifications had no impact on net income.
Environmental Costs
Expenditures for ongoing compliance with environmental regulations that
relate to current operations are expensed or capitalized as appropriate. We
expense amounts that relate to existing conditions caused by past operations,
and which do not contribute to current or future revenue generation. We record
liabilities when environmental assessments indicate that remediation efforts are
probable and the costs can be reasonably estimated. Estimates of our liabilities
are based upon currently available facts, existing technology and presently
enacted laws and regulations taking into consideration the likely effects of
inflation and other societal and economic factors, and include estimates of
associated legal costs. These amounts also consider prior experience in
remediating contaminated sites, other companies' clean-up experience and data
released by the Environmental Protection Agency (EPA) or other organizations.
They are subject to revision in future periods based on actual costs or new
circumstances, and are included in our balance sheet at their undiscounted
amounts. We evaluate recoveries separately from the liability and, when recovery
is assured, we record and report an asset separately from the associated
liability in our financial statements.
Price Risk Management Activities
We utilize derivative financial instruments to manage market risks
associated with commodities we sell, interest rates, and foreign currency
exchange rates. We engage in both trading and non-trading commodity price risk
management activities.
Our trading activities consist of services provided to the energy sector,
primarily related to natural gas and power. Our energy trading activities,
including transportation capacity and storage, are accounted for using the
mark-to-market method of accounting. We conduct our trading activities through a
variety of financial instruments, including:
- exchange traded futures contracts involving cash settlement;
- forward contracts involving cash settlement or physical delivery of an
energy commodity;
- swap contracts, which require us to make payments to (or receive payments
from) counterparties based on the difference between fixed and variable
prices for the commodity;
- exchange-traded and over-the-counter options; and
- other contractual arrangements.
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Under the mark-to-market method of accounting, commodity and energy related
contracts are reflected at quoted or estimated market value with resulting gains
and losses included in our income statement. Net gains or losses recognized in a
period result primarily from the impact of price movements on transactions
originating in that or previous periods. Assets and liabilities resulting from
mark-to-market accounting are included in our balance sheets and are classified
according to their term to maturity. We reflect receivables and payables that
arise upon the actual settlement of these contracts separately from price risk
management activities in our balance sheet as trade receivables or payables.
Cash inflows and outflows associated with these price risk management activities
are recognized in operating cash flows as transactions are settled. During the
years ended December 31, 2000 and 1999, we recognized gross margins from our
trading activities of $406 million and $91 million.
The market value of commodity and energy related contracts reflects our
best estimate, and considers factors including closing exchange and
over-the-counter quotations, time value, and volatility factors underlying these
contracts. The values are adjusted to reflect the potential impact of
liquidating our position in an orderly manner over a reasonable period of time
under present market conditions and to reflect other types of risks, including
model risk, credit risk and operational risks. In the absence of quoted market
prices, we utilize other valuation techniques to estimate fair value. The use of
these techniques requires us to make estimations of future prices and other
variables, including market volatility, price correlation, and market liquidity.
Changes in these estimates could have a significant impact on our market
valuations and could materially impact our estimates.
Derivative and other financial instruments are also utilized in connection
with non-trading activities. We enter into forwards, swaps, and other contracts
to hedge the impact of market fluctuations on assets, liabilities, or other
contractual commitments. Hedge accounting is applied only if the derivative
reduces the risk of the underlying hedged item, is designated as a hedge at its
inception, and is expected to result in financial impacts which are inversely
correlated to those of the item being hedged. If correlation ceases to exist,
hedge accounting is terminated and mark-to-market accounting is applied. Changes
in the market value of hedged transactions are deferred until the gain or loss
on the hedged item is recognized. Derivatives held for non-trading purposes are
recorded as gains or losses in operating income and cash inflows and outflows
are recognized in operating cash flows as transactions are settled. See Note 5
for a further discussion of our price risk management activities.
Income Taxes
We report income taxes based on income reported on our tax returns along
with a provision for deferred income taxes. Deferred income taxes reflect the
estimated future tax consequences of differences between the financial statement
and tax bases of assets and liabilities and carryovers at each year end. We
account for tax credits under the flow-through method, which reduces the
provision for income taxes in the year the tax credits first become available.
We reduce deferred tax assets by a valuation allowance when, based upon our
estimates, it is more likely than not that a portion of those assets will not be
realized in a future period. The estimates utilized in the recognition of
deferred tax assets are subject to revision in future periods based on new facts
or circumstances.
El Paso maintains a tax sharing policy for companies included in its
consolidated federal income tax return 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, El Paso pays all federal income tax
directly to the IRS and bills or refunds its subsidiaries, including us, for
their portion of these income tax payments. Prior to 1999, we filed a separate
tax return and were not subject to El Paso's tax sharing policy.
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Cumulative Effect of Accounting Change
In April 1998, the American Institute of Certified Public Accountants
issued Statement of Position 98-5, Reporting on the Costs of Start-Up
Activities. The statement defined start-up activities and required start-up and
organization costs be expensed as incurred. In addition, it required that any
such cost that existed on the balance sheet be expensed upon adoption of the
pronouncement. We adopted the pronouncement effective January 1, 1999, and
reported a charge of $13 million, net of income taxes, as a cumulative effect of
an accounting change.
Comprehensive Income
Comprehensive income is determined based on net income, adjusted for
changes in accumulated other comprehensive income.
Accounting for Derivative Instruments and Hedging Activities
In June of 1998, the Financial Accounting Standards Board (FASB) issued
Statement of Financial Accounting Standards (SFAS) No. 133, Accounting for
Derivative Instruments and Hedging Activities. In June of 1999, the FASB
extended the adoption date of SFAS No. 133 through the issuance of SFAS No. 137,
Deferral of the Effective Date of SFAS 133. In June 2000, the FASB issued SFAS
No. 138, Accounting for Certain Derivative Instruments and Certain Hedging
Activities, which also amended SFAS No. 133. SFAS No. 133, and its amendments
and interpretations, establishes accounting and reporting standards for
derivative instruments, including derivative instruments embedded in other
contracts, and derivative instruments used for hedging activities. It requires
that we measure all derivative instruments at their fair value, and classify
them as either assets or liabilities on our balance sheet, with a corresponding
offset to income or other comprehensive income depending on their designation,
their intended use, or their ability to qualify as hedges under the standard.
We adopted SFAS No. 133 on January 1, 2001, and applied the standard to all
derivative instruments that existed on that date, except for derivative
instruments embedded in other contracts. As provided for in SFAS No. 133, we
applied the provisions of the standard to derivative instruments embedded in
other contracts issued, acquired, or substantially modified after December 31,
1998.
We use a variety of derivative instruments to conduct both energy trading
activities and to hedge risks associated with commodity prices, foreign
currencies and interest rates. The derivative instruments we use in commodity
trading activities are recorded at their fair value in our financial statements
under the provisions of Emerging Issues Task Force Issue No. 98-10, Accounting
for Contracts Involved in Energy Trading and Risk Management Activities. As a
result, SFAS No. 133 did not impact our accounting for these instruments.
Based on commodity prices, interest rates, and foreign currency exchange
rates existing at December 31, 2000, we will reflect the impact of our adoption
of SFAS No. 133 as of January 1, 2001, by recording a cumulative effect
transition adjustment as a charge to other comprehensive income of $154 million,
net of income taxes, a reduction of assets of $37 million, and an increase in
liabilities of $117 million. This represents the fair value of our derivative
instruments designated as cash flow hedges. The majority of the initial charge
relates to anticipated purchases and sales of natural gas in 2001.
Accounting for Transfers and Servicing of Financial Assets and Extinguishment
of Liabilities
In September 2000, the FASB issued SFAS No. 140, Accounting for Transfers
and Servicing of Financial Assets and Extinguishments of Liabilities, which
replaces SFAS No. 125. This statement revises the standards for accounting for
securitizations and other transfers of financial assets and collateral and
requires certain disclosures, but carries over most of SFAS No. 125's provisions
without reconsideration. This standard has various effective dates, the earliest
of which is for fiscal years ending after December 15, 2000. This pronouncement
will not have a material effect on our financial statements.
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2. ACQUISITIONS
Texas Midstream Operations
In December 2000, we completed our purchase of PG&E's Texas Midstream
operations. The total value of the transaction was $887 million, including
assumed debt of approximately $527 million. The transaction was accounted for as
a purchase and is included in our Field Services segment.
The operations acquired consisted of 7,500 miles of intrastate natural gas
transmission and natural gas liquids pipelines that transport approximately 2.8
Bcf/d, nine natural gas processing and fractionation plants that currently
process 1.5 Bcf/d, and rights to 7.2 Bcf of natural gas storage capacity. In
March 2001, we sold some of these acquired natural gas liquids transportation
and several fractionation assets to Energy Partners for approximately $133
million.
Divestitures
During 2000, we sold East Tennessee Natural Gas Company to comply with a
Federal Trade Commission order related to El Paso's merger with Sonat. Net
proceeds from the sale were approximately $386 million and we recognized an
extraordinary gain of $77 million, net of income taxes of $51 million. In
December 2000, we sold our interest in Oasis Pipeline Company to comply with a
Federal Trade Commission order. We incurred a loss on this transaction of
approximately $19 million, net of income taxes. We recorded the gains and losses
on these sales as extraordinary items in our income statement.
As a result of El Paso's merger with The Coastal Corporation, we will be
required by the Federal Trade Commission to sell our Midwestern system, a
pipeline system in the midwest. Total estimated proceeds from the sale are $90
million, resulting in an estimated gain of $50 million, before income taxes. We
expect to complete this sale in the second quarter of 2001.
Additionally, in the first quarter of 2001, Energy Partners sold its
interests in several offshore assets. These sales consisted of interests in
seven natural gas pipeline systems, a dehydration facility, and two offshore
platforms. Proceeds from the sales of these assets were approximately $135
million and resulted in a loss to the partnership of approximately $23 million.
As consideration for these sales, Field Services committed to pay Energy
Partners a series of payments totaling $29 million. This amount, as well as our
proportional share of the losses on the sale of the partnership's assets, will
be recorded as a charge in our income statement in the first quarter of 2001.
We do not anticipate the impact from these sales to be material to our
ongoing financial position, operating results, or cash flows.
3. MERGER-RELATED COSTS AND ASSET IMPAIRMENT CHARGES
Merger-Related Costs
In October 1999, El Paso completed its $6 billion merger with Sonat Inc. in
a transaction accounted for as a pooling of interests. As a result of this
transaction, El Paso's and Sonat Inc.'s subsidiaries incurred merger-related
costs as well as asset impairment charges. Charges included in our statements of
income reflect the effect of this merger on us and our subsidiaries. Total
merger charges were $72 million, and included $63 million of merger-related
asset impairment charges for duplicate systems and facilities identified as
impaired following the merger and $9 million related to conforming accounting
practices and policies of Sonat Inc.'s merchant operations to ours.
We recorded merger-related asset impairments related to write-offs or
write-downs of capitalized costs for duplicate systems, redundant facilities and
assets whose value was impaired as a result of decisions on the strategic
direction of our combined operations following each of our mergers.
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Asset Impairment Charges
During 2000 and 1999, we incurred asset impairment charges of $11 million
and $3 million. The 2000 charge resulted from Field Services' impairment of its
Needle Mountain processing facility in Arizona due to unrecoverability of costs.
The 1999 charges consisted of discontinued capital projects.
4. INCOME TAXES
The following table reflects the components of income tax expense for the
three years ended December 31:
2000 1999 1998
---- ---- ----
(IN MILLIONS)
Current
Federal................................................... $ (8) $ 21 $ 10
State..................................................... (27) (16) (15)
Foreign................................................... 7 11 4
---- ---- ----
(28) 16 (1)
---- ---- ----
Deferred
Federal................................................... 234 64 86
State..................................................... 39 6 9
Foreign................................................... (3) (1) (2)
---- ---- ----
270 69 93
---- ---- ----
Total income tax expense.......................... $242 $ 85 $ 92
==== ==== ====
Our income tax expense included in income before extraordinary items and
cumulative effect of accounting change differs from the amount computed by
applying the statutory federal income tax rate of 35 percent for the following
reasons at December 31:
2000 1999 1998
---- ---- ----
(IN MILLIONS)
Income tax expense at the statutory federal rate of 35%..... $253 $ 95 $110
Increase (decrease)
State income tax, net of federal income tax benefit....... 8 (7) (4)
Dividend exclusion........................................ (11) (6) (1)
Non-deductible portion of merger-related costs............ -- 5 --
Foreign income taxed at different rates, not subject to
U.S. tax............................................... (19) (4) (6)
Other..................................................... 11 2 (7)
---- ---- ----
Income tax expense.......................................... $242 $ 85 $ 92
==== ==== ====
Effective tax rate.......................................... 33% 31% 29%
==== ==== ====
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The following are the components of our net deferred tax liability at
December 31:
2000 1999
------ ------
(IN MILLIONS)
Deferred tax liabilities
Property, plant, and equipment............................ $1,884 $1,672
Investments in unconsolidated affiliates.................. 113 38
Price risk management activities.......................... 244 17
Regulatory assets......................................... 37 62
Other..................................................... 101 53
------ ------
Total deferred tax liability...................... 2,379 1,842
------ ------
Deferred tax assets
U.S. net operating loss and tax credit carryovers......... 235 135
Accrual for regulatory issues............................. 61 68
Employee benefit and deferred compensation obligations.... 78 107
Environmental reserves.................................... 71 71
Other..................................................... 336 166
Valuation allowance....................................... (2) (4)
------ ------
Total deferred tax asset.......................... 779 543
------ ------
Net deferred tax liability.................................. $1,600 $1,299
====== ======
At December 31, 2000, the portion of the cumulative undistributed earnings
of our foreign subsidiaries and foreign corporate joint ventures on which we
have not recorded U.S. income taxes was approximately $175 million. Since these
earnings have been or are intended to be indefinitely reinvested in foreign
operations, no provision has been made for any U.S. taxes or foreign withholding
taxes that may be applicable upon actual or deemed repatriation. If a
distribution of such earnings were to be made, we might be subject to both
foreign withholding taxes and U.S. income taxes, net of any allowable foreign
tax credits or deductions. However, an estimate of these taxes is not
practicable. For the same reasons, we have not recorded a provision for U.S.
income taxes on the foreign currency translation adjustments recorded in other
comprehensive income.
Under El Paso's tax sharing policy, we are allocated the tax benefit
associated with our employees' exercise of non-qualified stock options and the
vesting of restricted stock as well as restricted stock dividends. This
allocation reduced taxes payable by $22 million in 2000, $7 million in 1999 and
$4 million in 1998. These benefits are included in additional paid-in capital in
our balance sheets. See Note 1 for further discussion of the tax sharing policy.
As of December 31, 2000, we had alternative minimum tax credits of $23
million that carryover indefinitely. The table presented below details the tax
carryover periods for the net operating loss carryovers. Usage of these
carryovers is subject to the limitations provided under Sections 382 and 383 of
the Internal Revenue Code as well as the separate return limitation year rules
of the IRS regulations.
CARRYOVER PERIOD
----------------------------------------------------
2001 2002-2010 2011-2015 2016-2020 TOTAL
---- --------- --------- --------- -----
Net operating loss........................... $-- $45 $181 $379 $605
We 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 carryovers of an acquired company. Any tax benefits subsequently
recognized from the reversal of the allowance will be allocated to additional
acquisition cost assigned to utility plant.
Prior to 1999, we and our subsidiaries filed a consolidated federal income
tax return and El Paso and its other subsidiaries filed a separate consolidated
federal income tax return. On January 1, 1999, as a result of the 1998 tax-free
internal reorganization described in Note 1, we and our subsidiaries joined El
Paso's consolidated federal income tax group. Beginning January 30, 2001, as a
result of El Paso's merger with
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Coastal, El Paso and its subsidiaries, including us, will file a consolidated
federal income tax return with El Paso CGP Company, formerly The Coastal
Corporation, and its subsidiaries.
In connection with our acquisition by El Paso in 1996, we entered into a
tax sharing agreement with Newport News Shipbuilding Inc., new Tenneco Inc. and
El Paso. This tax sharing agreement provides, among other things, for the
allocation among the parties of tax assets and liabilities arising prior to, as
a result of, and subsequent to the distributions of new Tenneco Inc. and Newport
News Shipbuilding Inc. to the shareholders of old Tenneco Inc.
5. FINANCIAL INSTRUMENTS AND PRICE RISK MANAGEMENT ACTIVITIES
Fair Value of Financial Instruments
The carrying amounts and estimated fair values of our financial instruments
at December 31 are as follows:
2000 1999
--------------------- ---------------------
CARRYING CARRYING
AMOUNT FAIR VALUE AMOUNT FAIR VALUE
-------- ---------- -------- ----------
(IN MILLIONS)
Balance sheet financial instruments:
Investments....................................... $ 62 $ 62 $ 12 $ 12
Long-term debt, including current maturities...... 1,977 2,004 1,467 1,405
Preferred stock................................... 300 300 300 315
Trading instruments
Futures contracts............................... 137 137 (24) (24)
Option contracts(1)............................. (118) (118) 264 264
Swap and forward contracts...................... 1,150 1,150 (69) (69)
Foreign currency forward contracts................ -- 5 -- 4
Equity swap....................................... -- -- 10 10
Other financial instruments:
Non-trading instruments
Commodity swap and forward contracts............ $ -- $ -- $ -- $ 18
- ---------------
(1) Excludes transportation capacity, tolling agreements, and natural gas in
storage held for trading purposes since these do not constitute financial
instruments.
As of December 31, 2000, and 1999, our carrying amounts of cash and cash
equivalents, short-term borrowings, and trade receivables and payables are
representative of fair value because of the short-term nature of these
instruments. We estimated the fair value of debt with fixed interest rates based
on quoted market prices for the same or similar issues. We estimated the fair
value of all derivative financial instruments based on quoted market prices,
current market conditions, estimates we obtained from third-party brokers or
dealers, or amounts derived using valuation models.
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Trading Commodity Activities
The fair value of commodity and energy related contracts entered into for
trading purposes as of December 31, 2000 and 1999, and the average fair value of
those instruments are set forth below.
AVERAGE FAIR
VALUE FOR THE
YEAR ENDED
ASSETS LIABILITIES DECEMBER 31,(1)
------ ----------- ---------------
(IN MILLIONS)
2000
Futures contracts................................. $ 137 $ -- $266
Option contracts.................................. 2,135 (1,593) 589
Swap and forward contracts........................ 3,647 (2,185) 518
1999
Futures contracts................................. $ 2 $ (26) $(12)
Option contracts.................................. 455 (35) 184
Swap and forward contracts........................ 199 (268) 93
- ---------------
(1) Computed using the net asset (liability) balance at each month end.
Notional Amounts and Terms
The notional amounts and terms of our energy commodity financial
instruments at December 31, 2000, and 1999 are set forth below (natural gas
volumes are in trillions of British thermal units, power volumes are in millions
of megawatt hours, liquids volumes are in millions of barrels, weather volumes
are in thousands of degree days, and energy capacity volumes are in millions of
kilowatt hours):
FIXED PRICE FIXED PRICE MAXIMUM
PAYOR RECEIVER TERMS IN YEARS
----------- ----------- --------------
2000
Energy Commodities:
Natural gas...................................... 34,305 29,895 27
Power............................................ 133 143 20
Liquids(1)....................................... 8 8 6
Weather.......................................... 133 135 --
Energy capacity.................................. 22 29 13
1999
Energy Commodities:
Natural gas...................................... 26,457 24,565 26
Power............................................ 30 41 20
Liquids(1)....................................... 8 8 7
- ---------------
(1) Liquids include crude oil, condensate and natural gas liquids.
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The notional amount and terms of foreign currency forward purchases and
sales at December 31, 2000 and 1999, were as follows:
NOTIONAL VOLUME
------------------------- MAXIMUM
BUY SELL TERM
----------- ----------- -------
2000
Foreign Currency (in millions)
Canadian Dollars.................................. 1,095 441 8years
Korean Won........................................ -- 132,500 1month
Phillipine Peso................................... -- 4,392 1month
1999
Foreign Currency (in millions)
Canadian Dollars.................................. 296 194 9years
British Pounds.................................... -- 28 9years
Notional amounts reflect the volume of transactions but do not represent
the actual amounts exchanged by the parties. As a result, notional amounts are
an incomplete measure of our exposure to market or credit risks. The maximum
terms in years detailed above are not indicative of likely future cash flows as
these positions may be offset or cashed-out in the commodity and currency
markets based on our risk management needs and liquidity in those markets.
The weighted average maturity of our entire portfolio of price risk
management activities was approximately two years as of December 31, 2000, and
six years as of December 31, 1999.
Market and Credit Risks
We serve a diverse customer group that generates a need for a variety of
financial structures, products and terms. This diversity requires us to manage,
on a portfolio basis, the resulting market risks inherent in these transactions
subject to parameters established by our risk management committee. We monitor
market risks through El Paso's risk control committee which operates
independently from the units that create or actively manage these risk exposures
to ensure compliance with our stated risk management policies.
We measure and adjust the risk in our portfolio in accordance with
mark-to-market and other risk management methodologies which utilize forward
price curves in the energy markets to estimate the size and probability of
future potential exposure.
Credit risk relates to the risk of loss that we would incur as a result of
non-performance by counterparties pursuant to the terms of their contractual
obligations. We maintain credit policies with regard to our counterparties to
minimize overall credit risk. These policies require an evaluation of potential
counterparties' financial condition (including credit rating), collateral
requirements under certain circumstances (including
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cash in advance, letters of credit, and guarantees), and the use of standardized
agreements that allow for the netting of positive and negative exposures
associated with a single counterparty. The counterparties associated with our
assets from price risk management activities are summarized as follows:
ASSETS FROM PRICE RISK MANAGEMENT ACTIVITIES AS OF
DECEMBER 31, 2000
---------------------------------------------------
INVESTMENT BELOW
GRADE(1) INVESTMENT GRADE TOTAL(2)
------------------- ---------------- --------
(IN MILLIONS)
Energy marketers............................. $2,459 $ 8 $2,467
Financial institutions....................... 1,161 -- 1,161
Oil and natural gas producers................ 613 -- 613
Natural gas and electric utilities........... 1,496 54 1,550
Industrials.................................. 98 2 100
Municipalities............................... 17 -- 17
Other........................................ 10 1 11
------ --- ------
Total assets from price risk
management activities............. $5,854 $65 $5,919
====== === ======
ASSETS FROM PRICE RISK MANAGEMENT ACTIVITIES AS OF
DECEMBER 31, 1999
---------------------------------------------------
INVESTMENT BELOW
GRADE(1) INVESTMENT GRADE TOTAL(2)
------------------- ---------------- --------
(IN MILLIONS)
Energy marketers............................. $226 $ 1 $227
Financial institutions....................... 21 -- 21
Oil and natural gas producers................ 26 -- 26
Natural gas and electric utilities........... 251 2 253
Industrials.................................. 15 -- 15
Municipalities............................... 64 -- 64
Other........................................ 50 -- 50
---- --- ----
Total assets from price risk
management activities............. $653 $ 3 $656
==== === ====
- ---------------
(1)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
natural gas and oil reserves. Included in Investment Grade are counterparties
with a minimum Standard & Poor's or Moody's rating of BBB- or Baa3,
respectively, or minimum implied (through internal credit analysis) Standard
& Poor's equivalent rating of BBB-.
(2)We had one customer in 2000 and four customers in 1999 that comprised greater
than 5 percent of assets from price risk management activities. Each of these
customers have investment grade ratings.
This concentration of counterparties may impact our overall exposure to
credit risk, either positively or negatively, in that the counterparties may be
similarly affected by changes in economic, regulatory or other conditions. Based
on our policies, risk exposure, and reserves, we do not anticipate a material
adverse effect on our financial position, operating results, or cash flows as a
result of counterparty nonperformance.
Non-Trading Price Risk Management Activities
We also utilize derivative financial instruments for non-trading activities
to mitigate market price risk associated with significant physical transactions.
Non-trading commodity activities are accounted for using hedge accounting
provided they meet hedge accounting criteria. Non-trading activities are
conducted through exchange traded futures contracts, swaps, and forward
agreements with third parties.
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At December 31, 2000 and 1999, the notional amounts and terms of contracts
held for purposes other than trading were as follows:
2000 1999
----------------------------- -----------------------
NOTIONAL NOTIONAL
VOLUME VOLUME
------------- MAXIMUM ------------- MAXIMUM
BUY SELL TERM IN YEARS BUY SELL TERM
--- ---- ------------- --- ---- -------
Commodity
Natural Gas (TBtu)...................... 114 130 5 months -- 13 1 year
In May 2000, we terminated our equity swap transaction associated with an
additional 18.5 percent of CAPSA's outstanding stock and purchased the
counterparty's 18.5 percent interest in CAPSA for approximately $127 million.
CAPSA is a privately held Argentine company engaged in power generation and
natural gas and oil production. Under the swap, we paid interest to the
counterparty, on a quarterly basis, on a notional amount of $103 million at a
rate of LIBOR plus 1.75 percent. In exchange, we received dividends, if any, on
the CAPSA stock to the extent of the counterparty's equity interest of 18.5
percent. We also fully participated in the market appreciation or depreciation
of the underlying investment whereby we realized appreciation or funded any
depreciation attributable to the actual sale of the stock upon termination or
expiration of the swap transaction. The termination of this swap did not have a
material impact on our financial results.
We also face credit risk with respect to our non-trading activities, and
take similar measures as in our trading activities to mitigate this risk. Based
upon our policies and risk exposure and considering recorded reserves, we do not
anticipate a material effect on our financial position, operating results or
cash flows resulting from counterparty non-performance.
6. PROPERTY, PLANT, AND EQUIPMENT
Our property, plant, and equipment consisted of the following at December
31:
2000 1999
------ ------
(IN MILLIONS)
Property, plant, and equipment, at cost
Pipelines................................................. $2,554 $2,608
Power facilities.......................................... 351 516
Gathering and processing systems.......................... 2,543 1,219
Corporate and Other....................................... 96 79
------ ------
5,544 4,422
Less accumulated depreciation, depletion, and
amortization.............................................. 843 789
------ ------
4,701 3,633
Additional acquisition costs assigned to utility plant, net
of accumulated amortization............................... 2,287 2,371
------ ------
Total property, plant, and equipment, net................... $6,988 $6,004
====== ======
7. DEBT AND OTHER CREDIT FACILITIES
The average interest rate on our short-term borrowings was 7.6% and 6.6% at
December 31, 2000 and 1999. We had the following short-term borrowings,
including current maturities of long-term debt, at December 31:
2000 1999
----- -----
(IN MILLIONS)
Commercial paper............................................ $215 $649
Current maturities of long-term debt........................ 132 8
---- ----
$347 $657
==== ====
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Our long-term debt outstanding consisted of the following at December 31:
2000 1999
------ ------
(IN MILLIONS)
Long-term debt
El Paso Tennessee
Notes, 7.25% through 10.0%, due 2008 through 2025...... $ 51 $ 51
Debentures, 6.5% through 10.375%, due 2000 through
2005.................................................. 36 42
Tennessee Gas Pipeline
Debentures, 6.0% through 7.625% due 2011 through
2037.................................................. 1,386 1,386
EPEC Corporation
Senior note, 9.625% due 2001........................... 13 13
Field Services
Notes, 7.41% through 11.5% due 2001 through 2012....... 511 --
Other....................................................... 1 3
------ ------
1,998 1,495
Less: Unamortized discount, net........................... 21 28
Current maturities.................................. 132 8
------ ------
Long-term debt, less current maturities................... $1,845 $1,459
====== ======
Aggregate maturities of the principal amounts of long-term debt for the
next 5 years and in total thereafter are as follows:
(IN MILLIONS)
-------------
2001........................................................ $ 132
2002........................................................ 105
2003........................................................ 41
2004........................................................ 69
2005........................................................ 89
Thereafter.................................................. 1,562
------
Total long-term debt, including current
maturities....................................... $1,998
======
Other Financing Arrangements
TGP is eligible to borrow up to $1 billion under a commercial paper
program. The program is used to manage our short-term cash requirements.
As of December 31, 2000, El Paso has a $2 billion, 364-day renewable credit
and competitive advance facility and a $1 billion, 3-year revolving credit and
competitive advance facility. These facilities replaced El Paso's $1,250 million
and its $750 million revolving credit facilities in August 2000. TGP is a
designated borrower under these facilities and, as such, is liable for any
amounts outstanding under these facilities. The interest rate for these
facilities varies and was LIBOR plus 50 basis points on December 31, 2000. No
amounts were outstanding under these facilities as of December 31, 2000. The
available credit under these facilities is expected to be used for El Paso's
general corporate purposes including, but not limited to, supporting TGP's $1
billion commercial paper program.
In December 2000, El Paso established a $700 million floating rate bridge
facility for use in connection with our acquisition of PG&E's Texas Midstream
operations. As of December 31, 2000, $455 million was outstanding under this
facility. As part of our acquisition, we assumed approximately $527 million in
debt, and in February 2001, we borrowed the balance of this facility and
redeemed $340 million of the debt assumed.
As of March 2001, TGP has $200 million under a shelf registration statement
on file with the Securities and Exchange Commission.
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The availability of borrowings under our credit agreements is subject to
specified conditions, which we believe we currently meet. These conditions
include compliance with the financial covenants and ratios required by such
agreements, absence of default under such agreements, and continued accuracy of
the representations and warranties contained in such agreements (including the
absence of any material adverse changes). All of our senior debt issues have
been given investment grade ratings by Standard & Poor's and Moody's.
8. COMMITMENTS AND CONTINGENCIES
Legal Proceedings
In August 2000, the Liquidating Trustee in the bankruptcy of Power
Corporation of America (PCA) sued El Paso Merchant Energy, and several other
power traders, in the U.S. Bankruptcy Court in Connecticut, claiming El Paso
Merchant Energy improperly cancelled its contracts with PCA during the summer of
1998. The trustee alleges we breached contracts damaging PCA in the amount of
$120 million. We have entered into a joint defense agreement with the other
defendants. This matter will be mediated in the second quarter of 2001. In a
related matter, PCA appealed the FERC's ruling that power marketers such as EPME
did not have to give 60 days notice to cancel its power contracts under the
Federal Power Act. PCA has appealed this decision to the United States Court of
Appeals. Oral arguments were heard in January 2001 and we are awaiting the
Court's decision.
In late 2000, El Paso Merchant Energy and several of our subsidiaries were
named as defendants in four purported class action lawsuits filed in state court
in California. (Continental Forge Co. v. Southern California Gas Co., et al, Los
Angeles; Berg v. Southern California Gas Co., et al, Los Angeles; John Phillip
v. El Paso Merchant Energy, et al, San Diego; John WHK Phillip v. El Paso
Merchant Energy, et al, San Diego.) Two of these cases, filed in Los Angeles,
contend generally that our entities conspired with other unrelated companies to
create artificially high prices for natural gas in California; the other two
cases, filed in San Diego, assert that our companies used Merchant Energy's
acquisition of capacity on the El Paso Natural Gas pipeline to manipulate the
market for natural gas in California. We have removed each of these cases to the
federal courts in California and have filed motions to dismiss in the San Diego
actions. On March 20, 2001, two additional lawsuits, The City of Los Angeles,
et. al. v. Southern California Gas Company, et. al. and The City of Long Beach,
et. al. v. Southern California Gas Company et. al. were filed in a Los Angeles
County Superior Court. In addition, on March 22, 2001, a lawsuit filed on behalf
of a purported class, Sweeties et. al. v. El Paso Corporation, et al., was filed
in Superior Court of San Francisco, State of California. These cases seek
monetary damages against us and several of our subsidiaries and make similar
allegations to the Continental Forge and Berg cases discussed above.
In 1999, a number of our subsidiaries were served as defendants in actions
brought by Jack Grynberg on behalf of the U.S. Government under the False Claims
Act. Generally, these complaints allege an industry-wide conspiracy to under
report the heating value as well as the volumes of the natural gas produced from
federal and Native American lands, which deprived the U.S. Government of
royalties. These matters have been consolidated for pretrial purposes. (In re:
Natural Gas Royalties Qui Tam Litigation, U.S. District Court for the District
of Wyoming.)
A number of our subsidiaries are named defendants in an action styled
Quinque Operating Company, et al v. Gas Pipelines and Their Predecessors, et al,
filed in 1999 in the District Court of Stevens County, Kansas. This class action
complaint alleges that the defendants mismeasured natural gas volumes and
heating content of natural gas on non-federal and non-Native American lands. The
Quinque complaint, once transferred to the same court handling the Grynberg
complaint, has been sent back to the Kansas State Court for further proceedings.
In February 1998, the United States and the State of Texas filed in a U.S.
District Court a Comprehensive Environmental Response, Compensation and
Liability Act (CERCLA) cost recovery action against fourteen companies,
including some of our current and former affiliates, related to the Sikes
Disposal Pits Superfund Site located in Harris County, Texas. The suit claims
that the United States and the State of Texas have spent over $125 million in
remediating Sikes, and seeks to recover that amount plus interest from
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the defendants to the suit. The EPA has recently indicated that it may seek an
additional amount up to $30 million plus interest in indirect costs from the
defendants under a new cost allocation methodology. Defendants are challenging
this allocation policy. Although an investigation relating to Sikes is ongoing,
we believe that the amount of material, if any, disposed at Sikes by our former
affiliates was small, possibly de minimis. However, the plaintiffs have alleged
that the defendants are each jointly and severally liable for the entire
remediation costs and have also sought a declaration of liability for future
response costs such as groundwater monitoring.
TGP is a party in proceedings involving federal and state authorities
regarding the past use of a lubricant containing polychlorinated biphenyls
(PCBs) in its starting air systems. TGP has executed a consent order with the
EPA governing the remediation of some compressor stations and is working with
the EPA and the relevant states regarding those remediation activities. TGP is
also working with the Pennsylvania and New York environmental agencies regarding
remediation and post-remediation activities at the Pennsylvania and New York
stations.
In November 1988, the Kentucky environmental agency filed a complaint in a
Kentucky state court alleging that TGP discharged pollutants into the waters of
the state and disposed of PCBs without a permit. The agency sought an injunction
against future discharges, an order to remediate or remove PCBs, and a civil
penalty. TGP entered into agreed orders with the agency to resolve many of the
issues raised in the original allegations, received water discharge permits from
the agency for its Kentucky compressor stations, and continues to work to
resolve the remaining issues. The relevant Kentucky compressor stations are
being characterized and remediated under a consent order with the EPA.
We are also a named defendant in numerous lawsuits and a named party in
numerous governmental proceedings arising in the ordinary course of our
business.
While the outcome of the matters discussed above cannot be predicted with
certainty, we do not expect the ultimate resolution of these matters will have a
material adverse effect on our financial position, operating results, or cash
flows.
Environmental
We are subject to extensive federal, state, and local laws and regulations
governing environmental quality and pollution control. These laws and
regulations require us to remove or remedy the effect on the environment of the
disposal or release of specified substances at current and former operating
sites. As of December 31, 2000, we had a reserve of approximately $121 million
for expected remediation costs, including approximately $257 million for
associated onsite, offsite and groundwater technical studies, and approximately
$17 million for other costs which we anticipate incurring through 2027. In
addition, we expect to make capital expenditures for environmental matters of
approximately $64 million in the aggregate for the years 2001 through 2007.
These expenditures primarily relate to compliance with air regulations.
Since 1988, TGP has been engaged in an internal project to identify and
deal with the presence of PCBs and other substances, including those on the EPA
List of Hazardous Substances, at compressor stations and other facilities it
operates. While conducting this project, TGP has been in frequent contact with
federal and state regulatory agencies, both through informal negotiation and
formal entry of consent orders, to ensure that its efforts meet regulatory
requirements.
In May 1995, following negotiations with its customers, TGP filed a
Stipulation and Agreement (the Environmental Stipulation) with FERC that
established a mechanism for recovering a substantial portion of the
environmental costs identified in its internal project. The Environmental
Stipulation was effective July 1, 1995, and as of December 31, 1999, all amounts
have been collected from customers. Refunds may be required to the extent actual
eligible expenditures are less than amounts collected.
We have been designated and have received notice that we could be
designated, or have been asked for information to determine whether we could be
designated as a Potentially Responsible Party (PRP) with respect to 8 sites
under the Comprehensive Environmental Response, Compensation and Liability Act
(CERCLA or Superfund) or state equivalents. We sought to resolve our liability
as a PRP at these Superfund
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sites through indemnification by third parties and/or settlements which provide
for payment of our allocable share of remediation costs. As of December 31,
2000, we have estimated our share of the remediation costs at these sites to be
between $1 million and $2 million and have provided reserves that we believe are
adequate for such costs. Since the clean-up costs are estimates and are subject
to revision as more information becomes available about the extent of
remediation required, and because in some cases we have asserted a defense to
any liability, our estimates could change. Moreover, liability under the federal
Superfund statute is joint and several, meaning that we could be required to pay
in excess of our pro rata share of remediation costs. Our understanding of the
financial strength of other PRPs has been considered, where appropriate, in the
determination of our estimated liabilities. We presently believe that the costs
associated with these Superfund sites will not have a material adverse effect on
our financial position, operating results, or cash flows.
It is possible that new information or future developments could require us
to reassess our potential exposure related to environmental matters. We may
incur significant costs and liabilities in order to comply with existing
environmental laws and regulations. It is also possible that other developments,
such as increasingly strict environmental laws and regulations, and claims for
damages to property, employees, other persons and the environment resulting from
our current or past operations, could result in substantial costs and
liabilities in the future. As this information becomes available, or other
relevant developments occur, we will adjust our accrual amounts accordingly.
While there are still uncertainties relating to the ultimate costs we may incur,
based upon our evaluation and experience to date, we believe the recorded
reserves are adequate. For a further discussion of specific environmental
matters, see Legal Proceedings above.
Rates and Regulatory Matters
In April 2000, the California Public Utilities Commission (CPUC) filed a
complaint alleging that El Paso Natural Gas' sale of capacity to Merchant Energy
was anti-competitive and an abuse of the affiliate relationship under FERC's
policies. The CPUC served data requests to us, which have been either
substantially answered or contested. In August 2000, the CPUC filed a motion
requesting that the contract between El Paso Natural Gas and Merchant Energy be
terminated. Other parties in the proceedings have requested that the original
complaint be set for hearings and that Merchant Energy pay back any profits it
has earned under the contract. On March 28, 2001, FERC issued an order
dismissing arguments that the sale of capacity to Merchant Energy violated the
marketing affiliate rule and concluded that allegations regarding the awarding
of capacity to Merchant Energy were unsupported. FERC further established a
hearing, before an administrative law judge to address the issue of whether El
Paso Natural Gas and/or Merchant Energy had market power and, if so, had
exercised it.
While we cannot predict with certainty the final outcome or the timing of
the resolution of our rates and regulatory matters, we believe the ultimate
resolution of these issues will not have a material adverse effect on our
financial position, results of operations, or cash flows.
Capital Commitments and Purchase Obligations
At December 31, 2000, we had capital and investment commitments of $488
million primarily relating to our pipeline and international power activities.
Our other planned capital and investment projects are discretionary in nature,
with no substantial capital commitments made in advance of the actual
expenditures. In connection with the financing commitments on one of our joint
ventures, TGP has entered into unconditional purchase obligations for products
and services totaling $122 million at December 31, 2000. TGP's annual
obligations under these agreements are $21 million for the years 2001, 2002,
2003, 2004 and 2005, and $17 million in total thereafter.
Operating Leases
We lease property, facilities and equipment under various operating leases.
In 1995, El Paso New Chaco Company (EPNC) entered into an unconditional lease
for the Chaco Plant. The lease term expires in 2002, at
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which time EPNC has an option, and an obligation upon the occurrence of various
events, to purchase the plant for a price sufficient to pay the amount of the
$77 million construction financing, plus interest and other expenses. If EPNC
does not purchase the plant at the end of the lease term, it has an obligation
to pay a residual guaranty amount equal to approximately 87 percent of the
amount financed, plus interest. We unconditionally guaranteed all obligations of
EPNC under this lease.
Minimum annual rental commitments at December 31, 2000, were as follows:
YEAR ENDING
DECEMBER 31, OPERATING LEASES
- ------------------------------------------------------------ ----------------
(IN MILLIONS)
2001..................................................... $20
2002..................................................... 18
2003..................................................... 12
2004..................................................... 11
2005..................................................... 11
Thereafter............................................... 27
---
Total............................................. $99
===
Aggregate minimum commitments have not been reduced by minimum sublease
rentals of approximately $14 million due in the future under noncancelable
subleases.
Rental expense on our operating leases for the years ended December 31,
2000, 1999, and 1998 was $15 million, $13 million, and $16 million.
Guarantees
At December 31, 2000, we had parental guarantees of approximately $9
million in connection with our international development activities and various
other projects.
9. RETIREMENT BENEFITS
Pension and Retirement Benefits
El Paso maintains a pension plan to provide benefits as determined by a
cash balance formula covering substantially all of its employees, including our
employees. Also, El Paso maintains a defined contribution plan covering its
employees, including our employees. El Paso matches 75 percent of participant
basic contributions of up to 6 percent, with matching contributions made in El
Paso common stock. El Paso is responsible for benefits accrued under its plan
and allocates the related costs to its affiliates. See Note 13 for a summary of
transactions with affiliates.
Other Postretirement Benefits
Following our acquisition by El Paso in 1996, we retained responsibility
for some of the postretirement medical and life insurance benefits for our
former employees of operations previously disposed of by Old Tenneco, and for
employees, including TGP employees, added as a result of the merger 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 are subject to deductibles,
co-payment provisions, and other limitations and dollar caps on the amount of
employer costs. We have reserved the right to change these benefits. Employees
who retired after July 1, 1997, will continue to receive limited postretirement
life insurance benefits. Effective February 1, 1992, TGP began recovering
through its rates the other postretirement benefits (OPEB) costs included in the
June 1993 rate case settlement agreement. To the extent actual OPEB costs differ
from the amounts funded, a regulatory asset or liability is recorded.
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The following table sets forth the change in benefit obligation, change in
plan assets, reconciliation of funded status, and components of net periodic
benefit cost for other postretirement benefits as of and for the twelve month
period ended September 30:
2000 1999
----- -----
(IN MILLIONS)
Change in benefit obligation
Benefit obligation at beginning of period................. $ 273 $ 318
Interest cost............................................. 19 20
Participant contributions................................. 9 7
Actuarial (gain) or loss.................................. 1 (18)
Benefits paid............................................. (53) (54)
----- -----
Benefit obligation at end of period....................... $ 249 $ 273
===== =====
Change in plan assets
Fair value of plan assets at beginning of period.......... $ 6 $ 8
Actual return on plan assets.............................. 1 --
Employer contributions.................................... 43 45
Participant contributions................................. 9 7
Benefits paid............................................. (53) (54)
----- -----
Fair value of plan assets at end of period................ $ 6 $ 6
===== =====
Reconciliation of funded status
Funded status at end of period............................ $(243) $(267)
Fourth quarter contributions and income................... 11 11
Unrecognized net actuarial gain........................... (3) (4)
Unrecognized prior service cost........................... (10) (11)
----- -----
Net accrued benefit cost at December 31,.................. $(245) $(271)
===== =====
The current liability portion of the postretirement benefits was $46
million as of December 31, 2000 and 1999. Benefit obligations are based upon
actuarial estimates as described below:
YEAR ENDED
DECEMBER 31,
--------------------
2000 1999 1998
---- ---- ----
(IN MILLIONS)
Benefit cost for the plans includes the following components
Interest cost............................................. $19 $20 $21
Amortization of prior service cost........................ (1) (1) (1)
--- --- ---
Net benefit cost.......................................... $18 $19 $20
=== === ===
2000 1999
---- ----
Weighted average assumptions
Discount rate............................................. 7.75% 7.50%
Expected return on plan assets............................ 7.50% 7.50%
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Actuarial estimates for our postretirement benefits plans assumed a
weighted average annual rate of increase in the per capita costs of covered
health care benefits of 10 percent in 2000, gradually decreasing to 6 percent by
the year 2008. Assumed health care cost trends have a significant effect on the
amounts reported for other postretirement benefit plans. A one-percentage point
change in our assumed health care cost trends would have less than a $1 million
increase or decrease in our obligation.
10. PREFERRED STOCK
At December 31, 2000, we had authorized 20 million shares of preferred
stock. In November 1996, we issued 6 million shares of Series A preferred stock.
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 our option 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 our option, in whole or in part, upon not less
than 30 days' notice at a redemption price of $50 per share, plus unpaid
dividends.
11. SEGMENT INFORMATION
Our business activities are segregated into three segments: Pipelines,
Merchant Energy, and Field Services. These segments are strategic business units
that offer a variety of different energy products and services. We manage each
segment separately as each business requires different technology and marketing
strategies. During 2000, we combined our International and Merchant Energy
segments reflecting the ongoing globalization of our Merchant Energy strategy
and its operating activities. All prior periods have been restated to reflect
the current year presentation.
Our Pipelines segment provides natural gas transmission services in the
U.S. We conduct our activities through two wholly owned and one partially owned
interstate systems along with a natural gas storage facility.
Our Merchant Energy segment is involved in a broad range of activities in
the wholesale energy marketplace, including asset ownership, trading and risk
management, and financial services. We buy, sell, and trade natural gas, power,
and other energy commodities throughout the world, and own or have interests in
64 power generation plants in 16 countries.
Our Field Services segment provides natural gas gathering, storage,
products extraction, fractionation, dehydration, purification, compression, and
intrastate transmission services. These services include gathering of natural
gas from some of the most prolific and active production areas in the United
States, including the San Juan Basin, east and south Texas, Louisiana and the
Gulf of Mexico.
The accounting policies of the individual segments are the same as those
described in Note 1. Since earnings on equity investments is a significant
source of earnings in several of our segments, we evaluate segment performance
based on EBIT. To the extent practicable, results of operations for the years
ended December 31, 1999 and 1998 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.
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SEGMENTS
AS OF OR FOR THE YEAR ENDED DECEMBER 31, 2000
----------------------------------------------------
MERCHANT FIELD
PIPELINES ENERGY SERVICES OTHER(1) TOTAL
--------- -------- -------- -------- -------
(IN MILLIONS)
Revenue from external customers
Domestic....................................... $ 707 $18,467 $ 574 $ 2 $19,750
Foreign........................................ -- 1,038 -- -- 1,038
Intersegment revenue............................. 69 16 84 (169) --
Merger-related costs and asset impairment
charges........................................ -- -- 11 -- 11
Depreciation, depletion, and amortization........ 135 27 58 3 223
Operating income (loss).......................... 335 433 84 (12) 840
Other income (loss).............................. 19 130 4 (5) 148
Earnings (loss) before interest and taxes........ 354 563 88 (17) 988
Assets
Domestic....................................... 4,991 9,760 2,543 239 17,533
Foreign........................................ -- 1,932 -- -- 1,932
Capital expenditures and investments in
unconsolidated affiliates...................... 186 923 451 18 1,578
Total investments in unconsolidated affiliates... 135 1,910 57 (32) 2,070
- ---------------
(1) Includes Corporate and eliminations.
SEGMENTS
AS OF OR FOR THE YEAR ENDED DECEMBER 31, 1999
---------------------------------------------------
MERCHANT FIELD
PIPELINES ENERGY SERVICES OTHER(1) TOTAL
--------- -------- -------- -------- ------
(IN MILLIONS)
Revenue from external customers
Domestic........................................ $ 819 $7,909 $ 348 $ 3 $9,079
Foreign......................................... -- 591 -- -- 591
Intersegment revenue.............................. 33 20 74 (127) --
Merger-related costs and asset impairment
charges......................................... -- 67 8 -- 75
Depreciation, depletion, and amortization......... 146 46 52 3 247
Operating income (loss)........................... 360 (91) 46 (17) 298
Other income...................................... 23 94 32 -- 149
Earnings (loss) before interest and taxes......... 383 3 78 (17) 447
Assets
Domestic........................................ 5,036 2,119 1,053 220 8,428
Foreign......................................... -- 1,336 -- -- 1,336
Capital expenditures and investments in
unconsolidated affiliates....................... 231 994 141 7 1,373
Total investments in unconsolidated affiliates.... 123 1,274 112 -- 1,509
- ---------------
(1) Includes Corporate and eliminations.
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SEGMENTS
AS OF OR FOR THE YEAR ENDED DECEMBER 31, 1998
---------------------------------------------------
MERCHANT FIELD
PIPELINES ENERGY SERVICES OTHER(1) TOTAL
--------- -------- -------- -------- ------
(IN MILLIONS)
Revenue from external customers
Domestic........................................ $ 761 $7,181 $ 212 $ 5 $8,159
Foreign......................................... -- 381 -- -- 381
Intersegment revenue.............................. 38 22 65 (125) --
Depreciation, depletion and amortization.......... 143 17 46 2 208
Operating income (loss)........................... 332 (37) 66 (15) 346
Other income...................................... 24 65 12 17 118
Earnings before interest and taxes................ 356 28 78 2 464
Assets
Domestic........................................ 4,940 1,564 1,029 206 7,739
Foreign......................................... -- 654 -- -- 654
Capital expenditures and investments in
unconsolidated affiliates....................... 144 582 104 4 834
Total investments in unconsolidated affiliates.... 74 480 69 -- 623
- ---------------
(1) Includes Corporate and eliminations.
The reconciliations of EBIT to income before extraordinary items and
cumulative effect of accounting change are presented below.
FOR THE YEAR ENDED
DECEMBER 31,
------------------
2000 1999 1998
---- ---- ----
(IN MILLIONS)
Total EBIT for segments..................................... $988 $447 $464
Interest and debt expense................................... 264 176 151
Income tax expense.......................................... 242 85 92
---- ---- ----
Income before extraordinary items and cumulative
effect of accounting change...................... $482 $186 $221
==== ==== ====
Prior to the current year, we had no customers whose revenues exceeded 10
percent of our total revenue. In 2000, Merchant Energy had revenues of $2.1
billion from subsidiaries of Enron Corp. We did not have revenues in excess of
10 percent with any other customer in 2000.
12. SUPPLEMENTAL CASH FLOW INFORMATION
The following table contains supplemental cash flow information for the
years ended December 31:
2000 1999 1998
---- ---- ----
(IN MILLIONS)
Interest paid............................................... $284 $208 $189
Income tax payments (refunds)............................... 54 (1) (86)
13. INVESTMENTS IN UNCONSOLIDATED AFFILIATES (UNAUDITED)
We hold investments in various unconsolidated affiliates which are
accounted for using the equity method of accounting. Our principal equity method
investees are international pipelines, interstate pipelines, power generation
plants, and gathering systems. Our investment balance includes unamortized
purchase price differences of $343 million and $15 million as of December 31,
2000 and 1999, that are being amortized over
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the remaining life of the unconsolidated affiliate's underlying assets. Our
investments in and advances to our unconsolidated affiliates are as follows:
NET DECEMBER 31,
OWNERSHIP ----------------
INTEREST 2000 1999
--------- ------ ------
(IN MILLIONS)
Bolivia to Brazil Pipeline............................... 8% $ 53 $ 45
CAPSA/CAPEX.............................................. 45% 282 145
CE Generation............................................ 50% 354 334
Chaparral................................................ 20% 268 373
East Asia Power.......................................... 46% 118 144
Korea Independent Energy Corporation..................... 50% 108 --
Porto Velho.............................................. 50% 99 --
Samalayuca Power......................................... 40% 93 130
Other.................................................... various 662 269
------ ------
$2,037 $1,440
====== ======
Our equity earnings (losses) from our unconsolidated affiliates are as
follows:
2000 1999 1998
---- ---- ----
(IN MILLIONS)
Bolivia to Brazil Pipeline................................. $ -- $ 4 $ --
CAPSA/CAPEX................................................ 4 3 --
CE Generation.............................................. 35 24 --
Chaparral.................................................. (5) (8) --
East Asia Power............................................ (32) -- --
Samalayuca Power........................................... 17 17 11
Other...................................................... 42 21 34
---- ---- ----
$ 61 $ 61 $ 45
==== ==== ====
Summarized financial information of our proportionate share of our
unconsolidated affiliates is as follows:
YEAR ENDED DECEMBER 31,
-----------------------
2000 1999 1998
----- ----- -----
(IN MILLIONS)
Operating results data:
Revenues and other income................................. $753 $510 $275
Costs and expenses........................................ 660 444 229
Income from continuing operations......................... 93 66 46
Net income................................................ 61 61 45
DECEMBER 31,
----------------
2000 1999
------ ------
(IN MILLIONS)
Financial position data:
Current assets............................................ $ 628 $ 455
Non-current assets........................................ 3,917 3,866
Short-term debt........................................... 239 143
Other current liabilities................................. 230 287
Long-term debt............................................ 1,981 2,139
Other non-current liabilities............................. 456 305
Minority interest......................................... 37 9
Equity in net assets...................................... 1,602 1,438
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The following table shows revenues and charges from our unconsolidated
affiliates:
YEAR ENDED DECEMBER 31,
------------------------
2000 1999 1998
------ ------ ------
(IN MILLIONS)
Revenues from affiliates.................................... $ 6 $ 24 $ 1
Management fee income....................................... 80 20 --
Reimbursement for costs..................................... 42 17 4
Charges from affiliates..................................... 172 209 180
Natural gas sales........................................... 104 -- --
Power purchases............................................. 43 -- --
Sabine River Investors
During 1999, El Paso formed Sabine River Investors, L.L.C., a wholly owned
limited liability company, and other separate legal entities, for the purpose of
generating funds for El Paso to invest in capital projects and other assets. The
proceeds are collateralized by specific assets of El Paso, including 100 percent
of our investments in Bear Creek and Energy Partners. At December 31, 2000, our
investment in Bear Creek was $101 million and our investment in Energy Partners
was $51 million.
Chaparral Investors
During 1999, we contributed approximately $120 million of equity capital
and assets to a newly formed limited liability company, Chaparral. A third-party
financial investor contributed approximately $123 million on which they earn a
preferred return. In connection with this transaction, Chaparral formed a wholly
owned subsidiary, Mesquite. Merchant Energy manages both Chaparral and Mesquite.
During 1999, El Paso issued a note payable of approximately $121 million to
Chaparral which was payable upon demand and carried a variable interest rate
which was 6.4%. This note was repaid in 2000. El Paso also had a note receivable
from Mesquite which had a balance of $262 million at December 31, 1999. This
note was payable on demand and had a variable rate which was 8.3%. The note was
repaid by Mesquite in 2000. During 2000, El Paso issued a note payable to
Mesquite. The note is payable on demand and had a balance of $241 million at a
rate of 7.3% as of December 31, 2000.
During the first quarter of 2000, El Paso provided $160 million to us to
increase our investment in Chaparral. We recorded the contribution from El Paso
as an increase in paid-in capital on our balance sheet. During the first quarter
of 2000, Chaparral completed its acquisitions of several domestic non-utility
generation assets including equity interests in eleven natural gas-fired
combined generation facilities in California, two natural gas-fired electric
generation plants located in Dartmouth, Massachusetts and Pawtucket, Rhode
Island, and all the outstanding shares of Bonneville Pacific Corporation, which
owns a 50 percent interest in a power generation facility. Chaparral also
acquired several operating companies which provide the services required to
operate and maintain these newly acquired facilities and a natural gas service
company which provides fuel procurement services to eight of Chaparral's natural
gas-fired combined generation facilities in California. Chaparral acquired these
assets from El Paso in exchange for notes payable to El Paso in the amount of
$385 million. In March 2000, Chaparral's third-party investor increased its
overall investment in Chaparral by $1,027 million. The proceeds were used by
Chaparral to repay El Paso $647 million of notes, to make a $278 million
contribution to a trust as provided in the Chaparral agreement, to invest in a
note with El Paso, and to fund transaction costs. Also, in March 2000, El Paso
issued mandatorily convertible preferred stock to a trust it controls. Upon the
occurrence of certain negative events, the trustee of the trust may be required
to remarket this preferred stock on terms that are designed to generate $1
billion to distribute to the third party investor.
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Under our management agreement with Chaparral, we earn a performance-based
management fee. We are also reimbursed for expenses we incur on behalf of
Chaparral. For 2000, our management fee related to Chaparral was $100 million
and this fee included an $80 million performance-based component and a $20
million reimbursement for costs we incurred on behalf of Chaparral. This fee was
collected and recognized ratably throughout the year as management services were
provided.
We also sell natural gas and buy power from qualifying power facilities
owned by Chaparral.
Energy Partners
In the first quarter of 2001, as a result of El Paso's merger with Coastal,
Energy Partners sold its interest in several offshore assets. These sales
consisted of interests in seven natural gas pipeline systems, a dehydration
facility and two offshore platforms. Proceeds from these sales were
approximately $135 million and resulted in a loss to the partnership of
approximately $23 million. As consideration for these sales, Field Services
committed to pay Energy Partners a series of payments totaling $29 million. This
amount, as well as our proportional share of the losses on the sale of the
partnership's assets, will be recorded as a charge in our income statement in
the first quarter of 2001.
El Paso
El Paso allocates general and administrative expenses to us. The allocation
is based on the estimated level of effort devoted to our operations and relative
size based on revenues, gross property and payroll. In addition, we enter into
transactions with other El Paso subsidiaries and unconsolidated affiliates in
the ordinary course of our business to transport, sell and purchase natural gas.
Services provided by these affiliates for our benefit are based on the same
terms as nonaffiliates.
14. SUPPLEMENTAL SELECTED QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
Financial information by quarter is summarized below.
QUARTERS ENDED
-----------------------------------------------
DECEMBER 31 SEPTEMBER 30 JUNE 30 MARCH 31
----------- ------------ ------- --------
(IN MILLIONS)
2000
Operating revenues(1)................................... $7,234 $6,707 $3,980 $2,867
Merger-related costs and asset impairment charges....... 11 -- -- --
Operating income........................................ 286 153 239 162
Income before extraordinary items....................... 144 90 140 108
Extraordinary items, net of income taxes................ (19) -- -- 77
Net income.............................................. 125 90 140 185
1999
Operating revenues(1)................................... $2,192 $3,038 $2,393 $2,047
Merger-related costs and asset impairment charges....... 39 36 -- --
Operating income........................................ 50 28 115 105
Income before cumulative effect of accounting change.... 16 17 89 64
Cumulative effect of accounting change, net of income
taxes................................................. -- -- -- (13)
Net income.............................................. 16 17 89 51
- ---------------
(1) In the fourth quarter of 2000, we restated operating revenues for 1999 and
2000 due to the implementation of Emerging Issues Task Force Issue No.
99-19, Reporting Revenue Gross as a Principal versus Net as an Agent. For
the first, second, and third quarters of 2000, operating revenues increased
by $10 million, $11 million, and $21 million. For the first, second, third,
and fourth quarters of 1999, operating revenues increased by $13 million,
$38 million, $20 million, and $9 million. These adjustments had no impact on
net income.
52
55
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, 2000 and 1999, and the consolidated results of its operations and its cash
flows for each of the three years in the period ended December 31, 2000, in
conformity with accounting principles generally accepted in the United States of
America. 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 auditing standards generally accepted in the
United States of America, 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 our opinion.
/s/ PricewaterhouseCoopers LLP
Houston, Texas
March 28, 2001
53
56
SCHEDULE II
EL PASO TENNESSEE PIPELINE CO.
VALUATION AND QUALIFYING ACCOUNTS
YEARS ENDED DECEMBER 31, 2000, 1999, AND 1998
(IN MILLIONS)
BALANCE AT CHARGED TO CHARGED TO BALANCE
BEGINNING COSTS AND OTHER AT END
DESCRIPTION OF PERIOD EXPENSES ACCOUNTS DEDUCTIONS OF PERIOD
----------- ---------- ---------- ---------- ---------- ---------
2000
Allowance for doubtful accounts....... $23 $ 85 $(4) $ (4)(a) $100
Allowance for price risk management
activities......................... 39 157 -- (3)(b) 193
Valuation allowance on deferred tax
assets............................. 4 -- -- (2) 2
1999
Allowance for doubtful accounts....... $23 $ 6 $(2) $ (4)(a) $ 23
Allowance for price risk management
activities......................... 28 21 -- (10)(b) 39
Valuation allowance on deferred tax
assets............................. 5 -- -- (1) 4
1998
Allowance for doubtful accounts....... $39 $ (1) $ 5 $(20)(a) $ 23
Allowance for price risk management
activities......................... 25 23 -- (20)(b) 28
Valuation allowance on deferred tax
assets............................. 8 -- 4 (7)(c) 5
- ---------------
(a) Primarily accounts written off.
(b) Primarily liquidation of positions on which allowance was established.
(c) Credited to deferred tax assets for a waiver of Gulf States Gas Pipeline
Company's NOL carryforward.
54
57
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
PART III
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 our proxy statement for the 2001
Annual Meeting of Stockholders is incorporated herein by reference. Information
regarding our executive officers 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. EXECUTIVE COMPENSATION
Information appearing under the caption "Executive Compensation" in our
proxy statement for the 2001 Annual Meeting of Stockholders is incorporated
herein by reference.
ITEM 12. SECURITY OWNERSHIP OF BENEFICIAL OWNERS AND MANAGEMENT
Information appearing under the captions "Security Ownership of Beneficial
Owners and Management of the Company" and "Security Ownership of Management of
El Paso Corporation" in our proxy statement for the 2001 Annual Meeting of
Stockholders is incorporated herein by reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Information appearing under the caption "Relationship with El Paso
Corporation" in our proxy statement for the 2001 Annual Meeting of Stockholders
is incorporated herein by reference.
55
58
PART IV
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.
Our consolidated financial statements included in Part II, Item 8 of this
report:
PAGE
----
Consolidated Statements of Income...................... 24
Consolidated Balance Sheets............................ 25
Consolidated Statements of Cash Flows.................. 26
Consolidated Statements of Stockholders' Equity........ 27
Notes to Consolidated Financial Statements............. 28
Report of Independent Accountants...................... 53
2. Financial statement schedules and supplementary information required to
be submitted.
Schedule II -- Valuation and qualifying accounts....... 54
Schedules other than that listed above are omitted
because they are not applicable
3. Exhibit list............................................ 57
(B) REPORTS ON FORM 8-K:
None.
56
59
EL PASO TENNESSEE PIPELINE CO.
EXHIBIT LIST
DECEMBER 31, 2000
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.
EXHIBIT
NUMBER DESCRIPTION
------- -----------
3.A -- Restated Certificate of Incorporation, dated May 11, 1999
(Exhibit 3.A to EPTP's 1999 First Quarter 10-Q).
3.B -- By-laws of EPTP as amended March 1, 1998 (Exhibit 3.B to
the EPTPC 1997 10-K).
4.A -- Indenture dated as of March 4, 1997, between TGP and The
Chase Manhattan Bank (Exhibit 4.1 to the EPTPC 1997
10-K); First Supplemental Indenture dated as of March 13,
1997, between TGP and The Chase Manhattan Bank (Exhibit
4.2 to the EPTPC 1997 10-K); Second Supplemental
Indenture dated as of March 13, 1997, between TGP and The
Chase Manhattan Bank (Exhibit 4.3 to the EPTPC 1997
10-K); Third Supplemental Indenture dated as of March 13,
1997, between TGP and The Chase Manhattan Bank (Exhibit
4.4 to the EPTPC 1997 10-K); Fourth Supplemental
Indenture dated as of October 9, 1998, between TGP and
The Chase Manhattan Bank (Exhibit 4.2 to TGP's Form 8-K
filed October 9, 1998, File No. 1-4101).
10.A -- $2,000,000 364-Day Revolving Credit and Competitive
Advance Facility Agreement dated as of August 2, 2000, by
and among El Paso, EPNG, TGP, the several banks and other
financial institutions from time to time parties to the
Agreement, The Chase Manhattan Bank, Citibank N.A. and
ABN Amro Bank, N.V. as co-documentation agents for the
Lenders and Bank of America, N.A. as syndication agent
for the Lenders (Exhibit 10.A to EPTP's 2000 Third
Quarter 10-Q).
10.B -- $1,000,000,000 3-Year Revolving Credit and Competitive
Advance Facility Agreement dated as of August 4, 2000, by
and among El Paso, EPNG, TGP, the several banks and other
financial institutions from time to time parties to the
Agreement, The Chase Manhattan Bank, Citibank N.A. and
ABN Amro Bank, N.V. as co-documentation agents for the
Lenders and Bank of America, N.A. as syndication agent
for the Lenders (Exhibit 10.B to EPTP's 2000 Third
Quarter 10-Q).
*21 -- List of Subsidiaries.
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.
57
60
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 29th day of March 2001.
EL PASO TENNESSEE PIPELINE CO.
Registrant
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 1934, 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 indicated.
SIGNATURE TITLE DATE
--------- ----- ----
/s/ WILLIAM A. WISE Chairman of the Board, President, March 29, 2001
- -------------------------------------------- Chief Executive Officer and
(William A. Wise) Director
/s/ H. BRENT AUSTIN Executive Vice President, Chief March 29, 2001
- -------------------------------------------- Financial Officer and Director
(H. Brent Austin)
/s/ JOEL RICHARDS III Executive Vice President and March 29, 2001
- -------------------------------------------- Director
(Joel Richards III)
/s/ BRITTON WHITE JR. Executive Vice President, General March 29, 2001
- -------------------------------------------- Counsel and Director
(Britton White Jr.)
/s/ JEFFREY I. BEASON Senior Vice President, Controller March 29, 2001
- -------------------------------------------- and Director
(Jeffrey I. Beason)
/s/ KENNETH L. SMALLEY Director March 29, 2001
- --------------------------------------------
(Kenneth L. Smalley)
58
61
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.
EXHIBIT
NUMBER DESCRIPTION
------- -----------
3.A -- Restated Certificate of Incorporation, dated May 11, 1999
(Exhibit 3.A to EPTP's 1999 First Quarter 10-Q).
3.B -- By-laws of EPTP as amended March 1, 1998 (Exhibit 3.B to
the EPTPC 1997 10-K).
4.A -- Indenture dated as of March 4, 1997, between TGP and The
Chase Manhattan Bank (Exhibit 4.1 to the EPTPC 1997
10-K); First Supplemental Indenture dated as of March 13,
1997, between TGP and The Chase Manhattan Bank (Exhibit
4.2 to the EPTPC 1997 10-K); Second Supplemental
Indenture dated as of March 13, 1997, between TGP and The
Chase Manhattan Bank (Exhibit 4.3 to the EPTPC 1997
10-K); Third Supplemental Indenture dated as of March 13,
1997, between TGP and The Chase Manhattan Bank (Exhibit
4.4 to the EPTPC 1997 10-K); Fourth Supplemental
Indenture dated as of October 9, 1998, between TGP and
The Chase Manhattan Bank (Exhibit 4.2 to TGP's Form 8-K
filed October 9, 1998, File No. 1-4101).
10.A -- $2,000,000 364-Day Revolving Credit and Competitive
Advance Facility Agreement dated as of August 2, 2000, by
and among El Paso, EPNG, TGP, the several banks and other
financial institutions from time to time parties to the
Agreement, The Chase Manhattan Bank, Citibank N.A. and
ABN Amro Bank, N.V. as co-documentation agents for the
Lenders and Bank of America, N.A. as syndication agent
for the Lenders (Exhibit 10.A to EPTP's 2000 Third
Quarter 10-Q).
10.B -- $1,000,000,000 3-Year Revolving Credit and Competitive
Advance Facility Agreement dated as of August 4, 2000, by
and among El Paso, EPNG, TGP, the several banks and other
financial institutions from time to time parties to the
Agreement, The Chase Manhattan Bank, Citibank N.A. and
ABN Amro Bank, N.V. as co-documentation agents for the
Lenders and Bank of America, N.A. as syndication agent
for the Lenders (Exhibit 10.B to EPTP's 2000 Third
Quarter 10-Q).
*21 -- List of Subsidiaries.