-----BEGIN PRIVACY-ENHANCED MESSAGE-----
Proc-Type: 2001,MIC-CLEAR
Originator-Name: webmaster@www.sec.gov
Originator-Key-Asymmetric:
MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen
TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB
MIC-Info: RSA-MD5,RSA,
LBLxCLSGDraA67E+ObxjdQJNXbQ7dnB4ypKZp43yCHC5f//TY0ZABmgboO6IOs9u
sQ2f8ev0z3StGCnO2acosA==
<SEC-DOCUMENT>0000950129-00-000732.txt : 20000223
<SEC-HEADER>0000950129-00-000732.hdr.sgml : 20000223
ACCESSION NUMBER: 0000950129-00-000732
CONFORMED SUBMISSION TYPE: 10-K405
PUBLIC DOCUMENT COUNT: 14
CONFORMED PERIOD OF REPORT: 19991231
FILED AS OF DATE: 20000222
FILER:
COMPANY DATA:
COMPANY CONFORMED NAME: EL PASO ENERGY CORP/DE
CENTRAL INDEX KEY: 0001066107
STANDARD INDUSTRIAL CLASSIFICATION: NATURAL GAS TRANSMISSION [4922]
IRS NUMBER: 760568816
STATE OF INCORPORATION: DE
FISCAL YEAR END: 1231
FILING VALUES:
FORM TYPE: 10-K405
SEC ACT:
SEC FILE NUMBER: 001-14365
FILM NUMBER: 549948
BUSINESS ADDRESS:
STREET 1: 1001 LOUISIANA ST
STREET 2: EL PASCO ENERGY BLDG
CITY: HOUSTON
STATE: TX
ZIP: 77002
BUSINESS PHONE: 7134202131
MAIL ADDRESS:
STREET 1: 1001 LOUISIANA ST
CITY: HOUSTON
STATE: TX
ZIP: 77002
</SEC-HEADER>
<DOCUMENT>
<TYPE>10-K405
<SEQUENCE>1
<DESCRIPTION>EL PASO ENERGY CORPORATION - DATED 12/31/1999
<TEXT>
<PAGE> 1
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
---------------------
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, 1999
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 1-14365
EL PASO ENERGY CORPORATION
(Exact Name of Registrant as Specified in Its Charter)
<TABLE>
<S> <C>
DELAWARE 76-0568816
(State or Other Jurisdiction of (I.R.S. Employer
Incorporation or Organization) Identification No.)
EL PASO ENERGY BUILDING
1001 LOUISIANA STREET
HOUSTON, TEXAS 77002
(Address of Principal Executive Offices) (Zip Code)
</TABLE>
REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE: (713) 420-2131
SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:
<TABLE>
<CAPTION>
NAME OF EACH EXCHANGE
TITLE OF EACH CLASS ON WHICH REGISTERED
------------------- ---------------------
<S> <C>
Common Stock, par value $3 per New York Stock Exchange
share...............................
Preferred Stock Purchase Rights....... New York Stock Exchange
</TABLE>
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 of the voting stock (which consists solely of shares
of common stock) held by non-affiliates of the registrant as of February 16,
2000, computed by reference to the closing sale price of the registrant's common
stock on the New York Stock Exchange on such date: $8,554,320,151
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 $3 per share. Shares outstanding on February 16,
2000: 230,419,398
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: Portions of El Paso Energy Corporation's definitive Proxy
Statement for the 2000 Annual Meeting of Stockholders, to be filed not later
than 120 days after the end of the fiscal year covered by this report, are
incorporated by reference into Part III.
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
<PAGE> 2
EL PASO ENERGY CORPORATION
TABLE OF CONTENTS
<TABLE>
<CAPTION>
CAPTION PAGE
------- ----
<S> <C> <C>
Glossary.............................................................. ii
PART I
Item 1. Business.................................................... 1
Item 2. Properties.................................................. 20
Item 3. Legal Proceedings........................................... 20
Item 4. Submission of Matters to a Vote of Security Holders......... 20
PART II
Item 5. Market for Registrant's Common Equity and Related
Stockholder Matters....................................... 21
Item 6. Selected Financial Data..................................... 22
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations................................. 23
Risk Factors and Cautionary Statement for Purposes of the
"Safe Harbor" Provisions
of the Private Securities Litigation Reform Act of 1995... 35
Item 7A. Quantitative and Qualitative Disclosures About Market
Risk...................................................... 40
Item 8. Financial Statements and Supplementary Data................. 44
Item 9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure.................................. 89
PART III
Item 10. Directors and Executive Officers of the Registrant.......... 89
Item 11. Executive Compensation...................................... 89
Item 12. Security Ownership of Certain Beneficial Owners and
Management................................................ 89
Item 13. Certain Relationships and Related Transactions.............. 89
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form
8-K....................................................... 89
Signatures.................................................. 95
</TABLE>
i
<PAGE> 3
GLOSSARY
The following abbreviations, acronyms, or defined terms used in this Form
10-K are defined below:
<TABLE>
<S> <C>
BBbls............................. Billion barrels
BBtu(/d).......................... Billion British thermal units (per day)
Bcf(/d)........................... Billion cubic feet (per day)
Bcfe.............................. Billion cubic feet of gas equivalent
Board............................. Board of directors of El Paso Energy Corporation
CAPSA............................. Companias Asociadas Petroleras SA, a privately held integrated
energy company in Argentina
Company........................... El Paso Energy Corporation and its subsidiaries
DeepTech.......................... DeepTech International Inc., a wholly owned subsidiary of El Paso
Energy Corporation
Dth(/d)........................... Decatherms (per day)
Dynegy............................ Dynegy Inc.
EBIT.............................. Earnings before interest expense and income taxes
East Tennessee.................... East Tennessee Natural Gas Company, a wholly owned subsidiary of El
Paso Tennessee Pipeline Co.
Edison............................ Southern California Edison Company
EnCap............................. EnCap Investments L.L.C., a wholly owned subsidiary of El Paso
Field Services Company
EPA............................... United States Environmental Protection Agency
El Paso........................... El Paso Energy Corporation, unless the context otherwise requires
El Paso Energy Partners........... El Paso Energy Partners, L.P., a publicly held Delaware limited
partnership (formerly Leviathan Gas Pipeline Partners, L.P.)
EPNG.............................. El Paso Natural Gas Company, a wholly owned subsidiary of El Paso
Energy Corporation
EPTPC............................. El Paso Tennessee Pipeline Co., a direct subsidiary of El Paso
Energy Corporation
FERC.............................. Federal Energy Regulatory Commission
Field Services.................... El Paso Field Services Company, a wholly owned subsidiary of El
Paso Tennessee Pipeline Co.
International..................... El Paso Energy International Company (and its subsidiaries and
investments), a wholly owned subsidiary of El Paso Tennessee
Pipeline Co.
IRS............................... Internal Revenue Service
MBbls............................. Thousand barrels
Mcf............................... Thousand cubic feet
Mcfe.............................. Thousand cubic feet of gas equivalent
Merchant Energy................... El Paso Merchant Energy Group, LLC, a wholly owned subsidiary of El
Paso Tennessee Pipeline Co.
Mgal(/d).......................... Thousand gallons (per day)
Midwestern........................ Midwestern Gas Transmission Company, a wholly owned subsidiary of
El Paso Tennessee Pipeline Co.
MMBbls............................ Million barrels
MMcf(/d).......................... Million cubic feet (per day)
MMcfe............................. Million cubic feet of gas equivalent
Mdth(/d).......................... Thousand decatherms (per day)
</TABLE>
ii
<PAGE> 4
<TABLE>
<S> <C>
MPC............................... Mojave Pipeline Company, a wholly owned indirect partnership of El
Paso Natural Gas Company
PCB(s)............................ Polychlorinated biphenyl(s)
Production........................ El Paso Production Holding Company, a wholly owned subsidiary of El
Paso Energy Corporation
PRP(s)............................ Potentially responsible party(ies)
Sonat............................. Sonat Inc., a publicly traded company prior to its October 1999
merger with El Paso Energy Corporation
SNG............................... Southern Natural Gas Company, a wholly owned subsidiary of El Paso
Energy Corporation
TBtu/(d).......................... Trillion British thermal units (per day)
Tcfe.............................. Trillion cubic feet of gas equivalent
TGP............................... Tennessee Gas Pipeline Company, a wholly owned subsidiary of El
Paso Tennessee Pipeline Co.
</TABLE>
iii
<PAGE> 5
PART I
ITEM 1. BUSINESS
GENERAL
Over the past five years, El Paso Energy Corporation has transformed itself
from a regional natural gas transmission company into a global energy company
having a presence in all areas of the rapidly evolving wholesale global energy
industry. The Company has accomplished this transformation through a series of
acquisitions and transactions, each designed to enhance and improve the
Company's competitive abilities in both the regulated and non-regulated energy
markets. In 1995, the Company completed its acquisition of Eastex Energy Inc.,
signaling its entrance into the emerging energy marketing and trading business.
In early 1996, the Company engaged in an intensive organizational review and
work process rationalization program, resulting in the reduction of its total
workforce by over 30 percent, and positioning the Company for accelerated growth
in an increasingly competitive business environment. The Company completed its
$4 billion acquisition of EPTPC and its acquisition of Cornerstone Natural Gas,
Inc. in late 1996. These acquisitions expanded the Company's regulated pipeline
network from coast-to-coast, significantly enhanced its mid-stream asset base,
and provided the foundation for it to become an active participant in the
rapidly growing international energy business. In 1998, the Company acquired
DeepTech International Inc. and several other mid-stream assets, significantly
increasing its onshore and offshore gathering and processing capabilities. In
October 1999, the Company completed its $6 billion merger with Sonat. With this
transaction, which was accounted for as a pooling of interests, the combined
companies have emerged as one of the largest natural gas transmission companies
in America, expanding into the rapidly growing southeastern United States and
adding a new natural gas and oil production segment with reserves totaling
approximately 1.5 Tcfe. Throughout this period of growth and transition, the
Company has continued to evaluate its existing organizational processes and
workforce needs to maximize synergies resulting from its strategic acquisitions.
In both 1997 and 1999, the Company implemented further workforce reduction
programs of 19 percent and 15 percent, respectively.
Also during this five-year period, the Company has aggressively invested in
its higher growth non-regulated energy businesses. These investments have served
to transform the Company's merchant business from a regional trading concern to
a major intermediary in the wholesale natural gas and power industry. As a
result of its ongoing investment program, the Company is now one of the largest
non-utility owners and operators of power generation assets in the country.
These investments have also served to expand the Company's international
activities to over 35 projects in 18 countries with over $1 billion of capital
invested worldwide. The Company's business operations and activities are
discussed below in greater detail.
COMPANY OPERATIONS
The Company's principal operations include the interstate and intrastate
transportation, gathering, processing, and storage of natural gas; the marketing
of natural gas, power, and other energy-related commodities; power generation;
the development and operation of energy infrastructure facilities worldwide; and
the domestic exploration and production of natural gas and oil. The Company owns
or has interests in over 40,000 miles of interstate and intrastate pipeline
connecting the nation's principal natural gas supply regions to the five largest
consuming regions in the United States, namely the Gulf Coast, California, the
Northeast, the Midwest, and the Southeast. The Company's natural gas
transmission operations include the nation's only coast-to-coast mainline
natural gas transmission system and are comprised of eight wholly owned
interstate pipeline systems: the Tennessee Gas pipeline, the El Paso Natural Gas
pipeline, the Southern Natural Gas pipeline, the Sea Robin pipeline, the South
Georgia Natural Gas pipeline, the East Tennessee Natural Gas pipeline, the
Midwestern Gas Transmission pipeline, and the Mojave pipeline systems; as well
as interests in the Florida Gas Transmission pipeline, the Destin pipeline and
the Portland Natural Gas Transmission pipeline systems. During the first quarter
of 2000, the Company will complete its sales of the East Tennessee Natural Gas
pipeline and Sea Robin pipeline systems and the Company's one-third interest in
the Destin pipeline to comply with a Federal Trade Commission order related to
its merger with Sonat.
1
<PAGE> 6
Through Merchant Energy, the Company is a major intermediary in the
wholesale natural gas and electric power markets, and is engaged in buying and
selling natural gas, pipeline capacity, natural gas storage, power and other
energy commodities throughout North America. The Company has also become one of
the largest non-utility owners of electric generating capacity in the United
States. In its operations, the Company uses sophisticated systems and financial
modeling capabilities to evaluate and measure risks inherent in its markets,
then intermediates those risks using its presence in and knowledge of the
financial and physical commodity markets.
The Company's international activities focus on the development and
operation of international energy infrastructure projects. These activities
include ownership interests in three major operating natural gas transmission
systems in Australia and natural gas transmission systems and power generation
facilities currently in operation or under construction in Argentina,
Bangladesh, Bolivia, Brazil, Chile, China, the Czech Republic, Hungary, India,
Indonesia, Mexico, Pakistan, Peru, the Philippines and the United Kingdom.
The Company, through Field Services, provides natural gas gathering,
products extraction, dehydration, purification, compression and intrastate
transmission services. These services include gathering of natural gas from more
than 10,000 natural gas wells with approximately 11,000 miles of gathering
lines, and 11 natural gas processing and treating facilities located in some of
the most prolific and active production areas of the United States, including
the San Juan and Permian Basins, east and south Texas, Louisiana, and in the
Gulf of Mexico. The Company conducts its intrastate transmission operations
through its interests in five intrastate systems, including the Oasis pipeline
running from west Texas to Katy, Texas, the Channel pipeline extending from
south Texas to the Houston Ship Channel, the Shoreline and Tomcat gathering
systems, which gather gas from the Texas Gulf Coast, and the Gulf States
pipeline, which extends from the Texas border to Ruston, Louisiana. Through El
Paso Energy Partners, a publicly traded limited partnership in which the Company
is the general partner, the Company conducts natural gas and oil gathering,
transmission, midstream and other related services offshore in the Gulf of
Mexico.
The Company's natural gas and oil exploration and production activities
include properties with approximately 2.8 million net acres under lease in 11
states, including Louisiana, Texas, Oklahoma, Arkansas, and New Mexico, as well
as the Gulf of Mexico. At December 31, 1999, the Company's proved reserves
totaled approximately 1.5 Tcfe.
The Company is pursuing a telecommunications strategy that will leverage
its extensive North American natural gas pipeline system, its core competency in
right-of-way development and, to the extent that bandwidth associated with fiber
optic capacity becomes actively traded, its marketing and trading skills in
newly-developed commodity products. The Company, with partners or on its own, is
currently planning to install a fiber-optic network along certain key segments
of its pipeline system and may expand this network beyond its pipeline system
through fiber capacity swaps with or leases from other third party fiber optic
companies.
On August 1, 1998, El Paso succeeded EPNG as the publicly traded parent
corporation in a holding company reorganization. In the reorganization, EPNG, a
Delaware corporation formed in 1928, and its subsidiaries, became direct and
indirect subsidiaries of the Company.
MERGER WITH THE COASTAL CORPORATION
In January 2000, the Company announced it had entered into a definitive
agreement to merge with The Coastal Corporation ("Coastal"). In the merger, each
share of Coastal common stock and Class A common stock will be converted on a
tax-free basis into 1.23 shares of Company common stock. Coastal's outstanding
convertible preferred stock will be exchanged for Company common stock on the
same basis as if the preferred stock had been converted into Coastal common
stock immediately prior to the merger. The transaction will be accounted for as
a pooling of interests and is expected to close in the fourth quarter of 2000.
The merger is subject to customary conditions, including approval by the
stockholders of both companies, and receipt of certain required governmental
approvals.
2
<PAGE> 7
Coastal is a diversified energy holding company. It is engaged, through its
subsidiaries and joint ventures, in natural gas transmission, storage,
gathering, processing and marketing; natural gas and oil exploration and
production; petroleum refining, marketing and distribution; chemicals; power
production; and coal. Coastal owns interests in approximately 18,000 miles of
natural gas pipelines across the midwestern and the Rocky Mountain areas of the
United States and has proved reserves of 3.6 Tcfe. Coastal also has
international and domestic interests in natural gas and oil producing
properties, power production plants, and crude oil refining facilities.
PURCHASE OF TEXAS MIDSTREAM OPERATIONS
In January 2000, the Company entered into an agreement to purchase the
natural gas and natural gas liquids businesses of PG&E Gas Transmission, Texas
Corporation, and PG&E Gas Transmission Teco, Inc. The acquisition, which is
expected to close by mid-year 2000, is subject to the receipt of certain
required governmental approvals and third party consents. The transaction will
be accounted for as a purchase.
The assets being acquired consist of 8,500 miles of intrastate natural gas
transmission pipelines that transport approximately 2.8 Bcf/d in the south Texas
area, nine natural gas processing plants that currently process 1.5 Bcf/d, and a
7.2 Bcf natural gas storage field. The transaction also includes significant
natural gas liquids pipelines and fractionation facilities.
SEGMENTS
The Company segregates its business activities into five segments: Natural
Gas Transmission, Merchant Energy, International, Field Services, and
Production. These segments are strategic business units that provide a variety
of energy products and services. They are managed separately, as each business
unit requires different technology and marketing strategies. For information
relating to operating revenues, operating income, EBIT, and identifiable assets
attributable to each segment, see Item 8, Financial Statements and Supplementary
Data, Note 16, which is incorporated herein by reference.
NATURAL GAS TRANSMISSION
The Company's Natural Gas Transmission segment provides interstate natural
gas pipeline transportation to the northeast, southwest, southeast, mid-west and
mid-Atlantic sections of the United States, including the New York City,
Atlanta, Chicago, and Boston metropolitan areas, and various northern Mexico
markets. It conducts these activities through eight wholly owned and three
partially owned interstate systems along with a terminalling facility and three
storage facilities. Each of these is discussed below:
The TGP system. The TGP system consists of approximately 14,700 miles of
pipeline with a design capacity of 5,730 MMcf/d. During 1999, TGP transported
natural gas volumes averaging approximately 75 percent of its capacity. The TGP
system serves the northeast section of the United States, including the New York
City and Boston metropolitan areas. The multiple-line system begins in the
gas-producing regions of Louisiana, including the Gulf of Mexico, and south
Texas. TGP also recently completed an interconnect at the United States-Mexico
border.
The East Tennessee system. The East Tennessee system consists of
approximately 1,100 miles of pipeline with a design capacity of 680 MMcf/d.
During 1999, East Tennessee transported natural gas volumes averaging
approximately 45 percent of its capacity. The East Tennessee system serves the
states of Tennessee, Virginia and Georgia and connects with the TGP system in
Springfield and Lobelville, Tennessee.
The Midwestern system. The Midwestern system consists of approximately 400
miles of pipeline with a design capacity of 785 MMcf/d. During 1999, Midwestern
transported natural gas volumes averaging approximately 31 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.
The EPNG system. The EPNG system consists of approximately 9,800 miles of
pipeline with a design capacity of 4,744 MMcf/d. During 1999, EPNG transported
natural gas volumes averaging approximately 75 percent of its capacity. The EPNG
system serves California, which is its single largest market, and also
3
<PAGE> 8
serves markets in Nevada, Arizona, New Mexico, Texas, Oklahoma, and northern
Mexico. The EPNG system delivers natural gas from the San Juan Basin of northern
New Mexico and southern Colorado, and also accesses natural gas supplies in the
Permian and Anadarko Basins.
The MPC system. The MPC system consists of approximately 400 miles of
pipeline with a design capacity of approximately 400 MMcf/d. During 1999, MPC
transported natural gas volumes averaging approximately 98 percent of its
capacity. The MPC system is connected with the EPNG transmission system at
Topock, Arizona and Kern River Gas Transmission Company in California and
extends to customers in the vicinity of Bakersfield, California.
The SNG system. The SNG system consists of approximately 7,300 miles of
interstate natural gas pipelines with a design capacity of 2,632 MMcf/d. During
1999, SNG transported volumes averaging approximately 73 percent of its
capacity. SNG's interstate pipeline system extends from gas fields in Texas,
Louisiana, Mississippi, Alabama and the Gulf of Mexico to markets in Louisiana,
Mississippi, Alabama, Florida, Georgia, including the city of Atlanta, South
Carolina and Tennessee. SNG is the principal pipeline supplier to the growing
southeastern markets of Alabama and Georgia.
Florida Gas Transmission system. The Company owns a 50 percent interest in
Citrus Corp. ("Citrus"), a holding company that owns 100 percent of Florida Gas
Transmission Company ("Florida Gas"). Florida Gas is the primary pipeline
transporter of natural gas in the state of Florida and the sole pipeline
transporter to peninsular Florida. The system consists of approximately 4,900
miles of interstate natural gas pipelines with a design capacity of 1,462
MMcf/d. During 1999, Florida Gas transported volumes averaging approximately 92
percent of its capacity. The system extends from south Texas to a point near
Miami, Florida.
South Georgia Natural Gas system. The South Georgia Natural Gas system
("South Georgia"), consists of 910 miles of interstate natural gas pipelines
with a design capacity of 130 MMcf/d. During 1999, South Georgia transported
volumes averaging approximately 80 percent of its capacity. The South Georgia
system interconnects with the SNG system in eastern Alabama and extends from
eastern Alabama through southern Georgia to the Florida panhandle.
Sea Robin Pipeline Company. The Sea Robin Pipeline system consists of a 430
mile interstate natural gas pipeline system with a design capacity of 1,000
MMcf/d located off shore Louisiana in the Gulf of Mexico. During 1999, Sea Robin
Pipeline Company transported volumes averaging 57 percent of its capacity.
Southern LNG, Inc. Southern LNG is a liquified natural gas receiving
terminal, located on Elba Island, near Savannah, Georgia, capable of achieving a
peak sendout of 540 MMcf/d and a base load sendout of 333 MMcf/d. Inactive since
the early 1980s, Southern LNG filed an application with FERC in July 1999 to
reactivate the receiving terminal.
Destin Pipeline Company, L.L.C. Destin Pipeline Company ("Destin"), is
owned one-third by SNG. Destin owns a 254 mile interstate pipeline system with a
design capacity of 1,000 MMcf/d that transports natural gas from the growing
eastern Gulf of Mexico production area. Destin's pipeline system was partially
completed and in service in September 1998 and was fully in service in March
1999. During 1999, Destin transported volumes averaging 40 percent of its
capacity.
Portland Natural Gas Transmission. The Company has an approximate 19
percent ownership interest in the Portland Natural Gas Transmission system
("Portland"). Portland is a 292 mile 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 1999, Portland transported
volumes averaging approximately 34 percent of its capacity.
Bear Creek Storage. Bear Creek Storage Company ("Bear Creek") owns and
operates an underground natural gas storage facility located in Louisiana.
Services are provided pursuant to the authorization and subject to the
jurisdiction of FERC. Bear Creek has a capacity of 50 Bcf of base gas and 57 Bcf
of working storage capacity. Bear Creek's storage capacity is committed equally
to TGP and SNG under long-term contracts.
4
<PAGE> 9
Crystal Gas Storage, Inc. In January 2000, the Company completed its
acquisition of Crystal Gas Storage ("Crystal"). Crystal owns and operates two
natural gas storage facilities near Hattiesburg, Mississippi. The Hattiesburg
Gas Storage Facility has 3.5 Bcf of working storage capacity. The capacity is
fully subscribed on a firm basis under long term contracts that extend through
the year 2005. The Petal Gas Storage facility has 3.2 Bcf of natural gas storage
working capacity. A 7 Bcf expansion project, fully subscribed by The Southern
Company Services, Inc., is currently underway at the Petal facility. Combined,
the Hattiesburg and Petal storage systems can currently deliver in excess of 670
MMcf/d into four interstate pipelines, including TGP, SNG, Koch Gateway Pipeline
and Transcontinental Gas Pipeline.
From time to time, the Company holds open seasons in an effort to
capitalize on pipeline expansion opportunities. TGP has completed an open season
for the Eastern Express Project 2000 to provide gas transportation for the
growing markets in the northeast. As a result, TGP filed and received FERC
approval for the Eastern Express expansion, which will begin service in November
2000. In the fall of 1999, TGP completed and placed in service an international
border crossing at Reynosa, Tamaulipas, Mexico, and an interconnect with Pemex
Gas y Petroquimica Basica ("Pemex"), a Mexican state-owned company, to provide
the import and export of gas to and from Mexico.
During the first quarter of 2000, the Company will complete the sales of
its East Tennessee Natural Gas Company and Sea Robin Pipeline Company as well as
its one-third interest in Destin Pipeline Company to comply with a Federal Trade
Commission order related to its merger with Sonat.
Regulatory Environment
The Company's interstate systems are subject to the jurisdiction of FERC in
accordance with the Natural Gas Act of 1938 and the Natural Gas Policy Act of
1978. Each system operates under separate FERC approved tariffs which establish
rates, terms, and conditions under which each system provides services to its
customers.
In July 1998, FERC issued a Notice of Proposed Rulemaking ("NOPR") in which
it sought comments on a wide range of initiatives to change the manner in which
short-term (less than one year) transportation markets are regulated. On
February 9, 2000, the FERC issued a final ruling in response to the NOPR. Among
other things, the rule (i) allows pipelines to file to implement peak and
off-peak rates; (ii) removes the price cap for released capacity; (iii) requires
pipelines to make changes to their tariffs regarding customer imbalances,
penalties and pipeline operations; and (iv) increases the amount and type of
information that pipelines must make available to the FERC and its customers.
TGP. In December 1996, TGP filed for a general rate increase with FERC and
in October 1998, FERC approved a settlement resolving that proceeding. The
settlement included a structural rate design change that resulted in a larger
portion of TGP's transportation revenues being dependent upon throughput. One
party, a competitor of TGP, filed a Petition for Review of the FERC approved
settlement with the Court of Appeals, which remanded the case to FERC to respond
to the competitor's argument that TGP's cost allocation methodology deterred the
development of market centers (centralized locations where buyers and sellers
can physically exchange gas). Comments were filed with FERC in January 1999.
This matter is still pending before FERC.
EPNG. In June 1995, EPNG filed with FERC new system rates for mainline
transportation. In April 1997, FERC approved a comprehensive offer of settlement
to resolve that proceeding as well as issues surrounding certain contract
reductions and expirations that were to occur from January 1, 1996 through
December 31, 1997, and determined that only the contesting party, Edison, should
be severed for separate determination of the rates it directly pays EPNG. The
settlement was effective as of January 1, 1996. In August 1999, EPNG and Edison
filed a joint settlement with FERC resolving all issues related to EPNG's June
1995 rate filing. The joint settlement provides for Edison to pay EPNG the
maximum tariff rate provided for under the settlement for transportation service
to California from July 1, 1999, through the end of the term of the rate
settlement and for EPNG to pay Edison $32 million plus accrued interest to
resolve all claims raised by Edison. In November 1999, FERC approved the joint
settlement between EPNG and Edison and reapproved the rate settlement, subject
to implementation of a fuel adjustment to reflect certain facility
5
<PAGE> 10
functionalization changes ordered by FERC. In December 1999, FERC delayed the
implementation of the fuel adjustment pending its review of request for
rehearing.
SNG. In August 1999, SNG filed a $17 million rate increase with FERC based
on system costs and throughput during the base period ended April 30, 1999. The
matter is pending before FERC.
The Company's interstate systems are also subject to the Natural Gas
Pipeline Safety Act of 1968, as amended, which establishes pipeline and
liquified natural gas plant safety requirements, and the National Environmental
Policy Act and other environmental legislation. Each of the systems has a
continuing program of inspection designed to keep all of the facilities in
compliance with pollution control and pipeline safety requirements, and the
Company believes that its systems are in substantial compliance with applicable
requirements.
Markets and Competition
The Company's 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. Such
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. Customers of TGP, none of which individually represents more than 10
percent of the revenues on TGP's system, include natural gas producers,
marketers and end-users, as well as other gas transmission and distribution
companies. At the beginning of 1999, contracts representing 70 percent of TGP's
firm transportation capacity were due to expire by November 2000. However, as a
result of negotiations to extend or restructure these contracts, customers whose
contracts expire by November 2000 now represent only approximately 20 percent of
firm transportation capacity. The conditions of settlements and extensions are
similar to the original contracts and 80 percent of TGP's contracted firm
transportation capacity currently has an average term in excess of four years.
TGP continues to pursue future markets and customers for the capacity that is
not committed beyond November 2000 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 pressure from other major
pipeline systems, which enables 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 remaining expiring contracts may be adversely affected by
these competitive factors.
EPNG. EPNG faces significant competition from other pipeline companies that
transport natural gas to the California market. EPNG's current capacity to
deliver natural gas to California is approximately 3.3 Bcf/d, and the combined
capacity of all pipeline companies serving the California market is
approximately 6.9 Bcf/d. In 1999, the demand for interstate pipeline capacity to
California averaged 5.0 Bcf/d, equivalent to approximately 73 percent of the
total interstate pipeline capacity serving that state. Natural gas shipped to
California across the EPNG system represented approximately 33 percent of the
natural gas consumed in the state in 1999. The significant customers served by
EPNG in California during 1999 included Southern California Gas Company, with
capacity of 1,150 MMcf/d under contract until August 2006, and Dynegy, with
capacity of 1,311 MMcf/d under contract through December 1999.
Interstate pipeline capacity utilization to California is not expected to
reach 100 percent for three to five years, based on expected demand growth and
assuming no new interstate pipeline capacity is added. EPNG remarketed the
capacity relinquished by Pacific Gas and Electric Company at the end of 1997, by
entering into three contracts with Dynegy for the sale of all of its then
available firm capacity for a two-year period ending December 31, 1999, at rates
negotiated pursuant to EPNG's tariff provisions and FERC policies. In
6
<PAGE> 11
December 1999, EPNG remarketed this capacity to Enron North America Corp.
("Enron") for a one-year period ending December 31, 2000. Effective January 31,
2000, the Company and Enron mutually agreed to terminate the contracts due to a
FERC ruling modifying certain delivery rights. In February 2000, EPNG commenced
an open posting to sell this capacity and awarded it to Merchant Energy. The
contract is effective from March 2000 through May 2001.
SNG. SNG's customers include distribution and industrial customers,
electric generation companies, gas producers, other gas pipelines and gas
marketing and trading companies. SNG provides transportation services in both
its gas supply and market areas. SNG's contracts to provide firm transportation
service for its customers are for varying amounts and periods of time.
Substantially all of the firm transportation capacity currently available in
SNG's two largest market areas is fully subscribed. The significant customers
served by SNG during 1999 included (i) Atlanta Gas Light Company, with capacity
of 770 MMcf/d under contracts that expire beginning in 2001 through 2007, with
the majority expiring in 2002, (ii) Alabama Gas Corporation with capacity of 384
MMcf/d under contracts that expire beginning in 2002 through 2008, with the
majority expiring in 2008, and (iii) South Carolina Pipeline Corporation with
capacity of 188 MMcf/d under contract which expires primarily in 2003. Nearly
all of SNG's firm transportation contracts contain evergreen provisions that
automatically extend the term for additional months or years unless notice of
termination is given by one of the parties. Contracts representing approximately
43 percent of SNG's firm transportation capacity are due to expire during 2002
or 2003. This capacity is expected to be placed under a combination of long-term
and short-term contracts.
Competition among pipelines is strong in a number of SNG's key markets.
Customers purchase gas supply from producers and gas marketing companies in
unregulated transactions and contract with SNG for transportation services to
deliver this supply to their markets. SNG's three largest customers are able to
obtain a significant portion of their natural gas requirements through
transportation from other pipelines. In addition, SNG competes with several
pipelines for the transportation business of many of its other customers. The
competition with such pipelines is intense, and SNG must at times discount its
transportation rates in order to maintain market share.
MERCHANT ENERGY
The Company's Merchant Energy segment buys, sells, and trades natural gas,
power, natural gas transmission capacity, gas storage, and other energy and
natural gas related commodities and intermediates risk in its markets using
sophisticated integrated risk management techniques. Merchant Energy's merchant
activities provide customers with flexible solutions to meet their energy supply
and financial risk management requirements by utilizing its knowledge of the
marketplace, natural gas pipelines and power transmission infrastructure, supply
aggregation, transportation management and valuation, storage, and integrated
price risk management. It also acquires, develops, constructs, owns, operates
and manages domestic power generation facilities and other power related assets
and joint ventures. During 1999, Merchant Energy completed a fundamental
strategic shift to position itself as one of North America's largest
intermediaries in the wholesale energy marketplace.
The Merchant Energy segment is organized into four functional
units -- Origination, Trading and Risk Management, Finance and Administration,
and Operations. The Origination unit develops and acquires natural gas and power
assets, markets capacity from these assets, and creates innovative structured
transactions to enhance their value. The Trading and Risk Management unit
provides pricing and valuation information for the Origination unit, manages the
risk inherent in Merchant Energy's asset portfolio via the financial markets for
natural gas and power, and captures the option value inherent in the segment's
asset portfolio. The Company's portfolio is managed in accordance with strict
value-at-risk limits set by the Board. The Finance and Administration unit
implements financing strategies for Merchant Energy's assets, and provides
accounting and administration services for the segment's activities. The
Operations unit conducts the day to day operations of Merchant Energy's assets
in close coordination with the Origination and Trading and Risk Management
units. Merchant Energy controls a large portfolio of natural gas transmission
and storage capacity, and markets and trades over 6,713 Bcf/d of natural gas and
6,613 megawatts of power per month.
7
<PAGE> 12
During 1999, the Company was active in acquiring domestic non-utility
generation ("NUG") assets, especially those with above-market power purchase
agreements. As part of its efforts relating to NUG acquisitions, the Company
created a finance structure, known as Electron, to expand its growth in the
power generation business. The Company, together with a financial investor,
formed Electron, through the creation of a limited liability company, Chaparral
Investors, L.L.C. ("Chaparral"), and its wholly owned subsidiary, Mesquite
Investors, L.L.C. ("Mesquite"). Through Chaparral, the Company has currently
invested in 26 domestic power generation facilities with a total generating
capacity of approximately 3,200 megawatts. A subsidiary of the Company is the
manager of both Chaparral and Mesquite under a management agreement. In late
1999, the Company amended these arrangements to allow Electron to raise
additional capital and own additional assets. The Company intends to conduct its
NUG acquisition and restructuring activities through Electron. As compensation
for managing Electron, the Company will be paid an annual performance-based
management fee. Electron plans to raise approximately $1 billion of additional
financing in the first half of 2000 to expand its NUG activities.
Merchant Energy has ownership interests or management responsibilities in
40 power generation facilities with a total generating capacity of over 5,000
megawatts, including those power generation facilities invested in through
Electron. Approximately 79 percent of the output of the Company's operating
power plants is sold pursuant to long-term, fixed-price agreements. The Company
is actively seeking to restructure these agreements to enhance the value of
these facilities.
In March 1999, Merchant Energy acquired a 50 percent ownership interest in
CE Generation LLC. CE Generation LLC owns or has ownership interests in four
natural gas-fired cogeneration projects in New York, Pennsylvania, Texas and
Arizona and eight geothermal facilities near the Imperial Valley in southern
California. In addition, two additional geothermal facilities are currently
under construction in southern California. Collectively, these 14 power projects
will have a combined electric generating capacity of approximately 900
megawatts.
In connection with the Sonat merger, Merchant Energy has an interest in
Mid-Georgia Cogeneration, L.P., a 300 megawatt natural gas-fired combined cycle
power generation facility in Kathleen, Georgia, which sells power to a large
utility under a long-term power purchase agreement and provides steam to a local
customer.
In December 1999, the Company agreed to purchase two 67 megawatt natural
gas-fired electric generation plants located in Dartmouth, Massachusetts and
Pawtucket, Rhode Island. The acquisition of the Pawtucket plant closed in
February 2000 while the Dartmouth plant acquisition is expected to close in
March 2000. As part of the purchase agreement, the Company assumed
responsibility for all operations and maintenance activities of these plants.
In February 2000, Merchant Energy purchased partnership interests in a
portfolio of eleven gas-fired combined cycle power generation facilities in
California from Dynegy. The portfolio represents a net combined electric
generating capacity of approximately 370 megawatts. Also included in the
acquisition is an operating company and a turbine maintenance organization.
Eight of the eleven acquired facilities have entered into fuel management
agreements to purchase all natural gas and fuel oil used to operate the
facilities at market rates plus a management fee from Merchant Energy. Currently
ten of the eleven facilities sell power to three large public utilities pursuant
to long-term power contracts.
In January 2000, Merchant Energy acquired all the outstanding shares of
Bonneville Pacific Corporation ("Bonneville"). The principal business segments
acquired include a 50 percent interest in an 85 megawatt power plant that sells
power to a utility under a long-term contract, and an operating company which
provides operations and maintenance services under long-term contracts to two
cogeneration facilities in the Las Vegas area.
Merchant Energy is also constructing a 680 megawatt natural gas-fired
combined cycle power generation facility in Tominson, Georgia, which has
long-term power purchase agreements with three utilities to sell 70 percent of
its capacity. Commercial operations are expected to commence in June 2000.
8
<PAGE> 13
Merchant Energy purchases specific natural gas and power volumes from
suppliers at various times and points of receipt, arranges for the aggregation
and transportation of natural gas and transmission of power, and negotiates the
sale of these volumes to utilities (including local distribution companies and
power plants), municipalities, and a variety of industrial and commercial end
users. Merchant Energy seeks to maintain a diverse natural gas and power
supplier and customer base. During 1999, Merchant Energy's natural gas
activities served over 900 producers/suppliers and approximately 1,000 sales
customers in 41 states and shipped natural gas supplies on 61 pipelines. Its
power activities served over 125 sales customers in 48 states and traded
electricity in 11 North American Energy Reliability Council regions.
Merchant Energy utilizes a broad range of risk management instruments to
manage its fixed-price purchase and sales commitments and reduce its exposure to
market price volatility. It trades futures contracts and options on the New York
Mercantile Exchange and trades swaps and options in over-the-counter financial
markets with other major energy merchants. Market risks are managed on a
portfolio basis, subject to parameters established by a risk management
committee that operates independently from commercial operations. Market risk in
Merchant Energy's commodity derivative portfolio is measured on a daily basis
utilizing a Value-at-Risk (VAR) model to calculate the potential one-day
unfavorable impact on its earnings.
Detailed below are the marketed natural gas and power volumes for the years
ended December 31:
<TABLE>
<CAPTION>
1999 1998 1997
------ ------ ------
<S> <C> <C> <C>
Natural gas volumes marketed (BBtu/d)...................... 6,713 7,315 8,013
Power volumes marketed (Thousand megawatt hours)........... 79,361 55,210 21,735
</TABLE>
Regulatory Environment
Merchant Energy's power generation activities are subject to FERC's
regulatory jurisdiction under the Federal Power Act ("FPA") with respect to its
rates, terms and conditions of service and certain reporting requirements.
Exports of electricity are subject to approval by the Department of Energy. El
Paso's affiliates involved in cogeneration and independent power production are
subject to regulation by the FERC under the Public Utility Regulatory Policies
Act and the FPA with respect to rates, the procurement and provision of certain
services and operating standards.
Markets and Competition
Merchant Energy's merchant services business operates in a highly
competitive environment. Its primary competitors include: (i) marketing
affiliates of major oil and natural gas producers; (ii) marketing affiliates of
large local distribution companies; (iii) marketing affiliates of other
interstate and intrastate pipelines; and (iv) independent energy marketers with
varying scopes of operations and financial resources. 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 United States. 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. 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, the 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.
INTERNATIONAL
The Company's International segment was formed for the purpose of investing
in integrated energy projects with an emphasis on developing infrastructure to
gather, transport and use natural gas in northern Mexico and certain Latin
American countries. The focus of the international projects has expanded to
include power generation and pipeline investments located in Australia, Asia,
Europe and other Latin American
9
<PAGE> 14
countries. International enters into its projects through a combination of
acquisitions, international privatization efforts and greenfield development.
Acquisitions of existing energy projects and greenfield development
projects are subject to a higher level of commercial and financial risk in
foreign countries. Accordingly, International has adopted a risk mitigation
strategy to reduce risks to more acceptable and manageable levels.
International's practice is to select experienced partners with a history of
success in commercial operations. Individual partners are generally chosen based
on the complementary competencies which they offer to the various joint ventures
formed or to be formed. International designs and implements a formal due
diligence plan on every project it pursues, and contracts are negotiated to
secure fuel supply, manage operating and maintenance costs and, when possible,
index revenues to and denominate transactions in U.S. dollars. International
also obtains political risk insurance when deemed appropriate, through the
Overseas Private Investment Corporation, the Multilateral Investment Guarantee
Agency, or a private insurer.
Detailed below are brief descriptions, by region, of the projects that are
either operational or in various stages of development.
Latin America and Mexico
Agua del Cajon Processing Plant -- In November 1999, International acquired
a 50 percent ownership interest in a joint venture which owns a natural gas
processing plant located in Neuquen, Argentina. The joint venture leases the
plant under a ten-year term from Bank of Boston. Liquids from the plant are sold
under a ten year contract to CAPEX, a publicly traded company listed on the
Argentine and Luxembourg stock exchanges. The plant has a processing capacity of
77 MMcf/d.
Aguaytia Integrated Energy Project -- International owns a 24 percent
interest in an integrated natural gas and power generation project near
Pucallpa, located in central Peru. The project consists of a 302 Bcf natural gas
field, a natural gas processing facility, a 71 mile natural gas liquids pipeline
connected to a fractionation facility, a 126 mile natural gas pipeline connected
to a 155 megawatt simple cycle power plant, and a 250 mile power transmission
line connecting with the Peruvian grid at Paramonga.
Araucaria Power Project -- International has a 60 percent interest in a
consortium to build a 480 megawatt natural gas fired power plant located in
Araucaria, Brazil. The electricity will be purchased by Companhia Paranaense de
Energia, an integrated electric utility providing generation, transmission, and
distribution of electricity to all regions of the state of Parana in southern
Brazil. The plant will be fueled by natural gas provided from the Bolivia to
Brazil pipeline. The power purchase agreement was executed in August, 1999.
Financial close is expected in the fourth quarter of 2000. Commercial operations
are expected to commence in late 2002.
Bolivia to Brazil Pipeline Project -- International owns an 8 percent
interest in a 2,000 mile natural gas pipeline from Santa Cruz, Bolivia to Sao
Paulo, Brazil, with a southern lateral to Porto Alegre, Brazil. The pipeline,
which commenced operations in June 1999, transports natural gas to one of the
largest new markets in the western hemisphere which consists of approximately
100 million people.
CAPSA Power Project -- International has an effective 45 percent interest
in CAPSA, a privately held integrated energy company in Argentina. CAPSA was
incorporated in 1977 for the purpose of producing, selling and exploring for
liquid hydrocarbons. CAPSA's assets include ownership of the Diadema Oil Field
and a 55 percent ownership interest in CAPEX.
Costanera Power Project -- International owns a 12 percent interest in
Central Costanera, the largest thermal-power plant in Argentina consisting of
2,167 megawatts of power generation and an 8 percent interest in Central
Termoelectrica Buenos Aires, S.A., a 328 megawatt combined cycle power plant in
Buenos Aires.
Manaus Power Project -- International owns 100 percent of a 244 megawatt
power plant in Manaus, the capital city of the state of Amazonas in northern
Brazil. Power from the plant is currently sold under a seven-year contract to
Eletronorte, the local electric company.
10
<PAGE> 15
Rio Negro Power Project -- International owns 100 percent of a 158 megawatt
Rio Negro power plant located in Manaus, Brazil. Electricity from the Rio Negro
facility is currently being sold under a seven-year contract to Eletronorte.
Samalayuca Pipeline Project -- The project is a 45 mile, 212 MMcf/d
pipeline system which delivers natural gas to the Samalayuca Power Project from
EPNG's existing pipeline system in west Texas and Pemex's pipeline system in
northern Mexico. The system consists of 22 miles of pipeline in the United
States and 23 miles of pipeline in Mexico. International owns 50 percent of the
Mexican portion.
Samalayuca Power Project -- International owns a 40 percent interest in a
700 megawatt combined cycle gas fired power plant in Samalayuca, Mexico.
Comision Federal de Electricidad ("CFE"), the Mexican government-owned electric
utility, operates the plant under a 20 year lease. Upon expiration of the lease
term, ownership of the plant will be transferred to CFE.
Triunion Energy Company -- Triunion Energy Company ("Triunion") was a
development company formed by International, CAPEX and Interenergy to identify
and develop new energy related projects in Latin America. In November 1999,
International increased its interest in Triunion to 71 percent by purchasing the
remaining interest in Interenergy from Clan Energy International. Triunion
currently owns a 20 percent interest in an exploration and production project in
Charagua, Bolivia, as well as a 22 percent interest in an approved project to
build a 325 mile, natural gas pipeline that will cross the Andes Mountains
connecting natural gas production in Argentina's Neuquen Basin to customers in
Concepcion, Chile. Construction of the pipeline commenced in early 1998 and was
completed in December 1999.
Europe
EMA Power Project -- International owns a 50 percent controlling interest
in a 70 megawatt power plant located in Dunaujvaros, Hungary. The electricity
generated at the plant is committed, under a 20 year service agreement to
Dunaferr Kft., the largest steel mill in Hungary.
Enfield Power Project -- International owns a 25 percent interest in
Enfield Energy Center Limited. The 396 megawatt combined cycle natural gas-fired
merchant power plant is undergoing commissioning near London, England and is
expected to be operational in June 2000.
Fife Power Project -- International owns a 50 percent interest in the first
Scottish independent power project located in Fife. The existing plant consists
of a simple cycle natural gas fired turbine generating 75 megawatts, which
commenced operations in the fourth quarter of 1998. Under Phase II, a steam
turbine will be added to produce a total combined-cycle generating capacity of
115 megawatts. Financial close for Phase II occurred in July 1999, and
commercial operation is expected to commence in early 2001.
Kladno Power Project -- International owns an 18 percent interest in a 28
megawatt natural gas and coal fired cogeneration facility located approximately
19 miles northwest of Prague, in the Czech Republic. The facility is undergoing
expansion to increase its capacity to approximately 350 megawatts. Commercial
operations of the expanded facility are expected to commence in the third
quarter of 2000.
Asia Pacific
Australian Pipelines -- International owns a 33 percent interest in (i) the
Moomba to Adelaide pipeline system, a 488 mile natural gas pipeline in southern
Australia, (ii) the Ballera to Wallumbilla pipeline system, a 470 mile natural
gas pipeline in southwestern Queensland, and (iii) a 925 mile Dampier-to-Bunbury
natural gas pipeline in western Australia. The Dampier to Bunbury pipeline
system has a capacity of 550 MMcf/d and serves a number of western Australian
markets, including industrial end-users. An expansion of the Dampier-to-Bunbury
pipeline is currently underway to supply additional natural gas to Alcoa,
Worsley and Wesfarmers. The expansion, scheduled for completion in third quarter
of 2000, expands the pipeline's capacity to 585 MMcf/d.
East Asia Power -- In February 1999, International acquired a 46 percent
ownership interest in East Asia Power Resources Corporation ("EAPRC") along with
an interest in a convertible loan. Following its
11
<PAGE> 16
acquisition, International converted the loan to equity, increasing its
ownership interest to 65 percent, and in September 1999, International acquired
an additional 17 percent from another shareholder, increasing its ownership
interest to 82 percent. In December 1999, International participated in an EAPRC
rights offering, increasing its overall ownership to 92 percent. In February
2000, the Company entered into an agreement with a party to jointly own equal
interests in EAPRC and expects to complete the transaction prior to the end of
the first quarter of 2000 which would reduce the Company's interest in EAPRC to
less than 50 percent. EAPRC owns and operates seven power generation facilities
in the Philippines and one plant in China, with a total generating capacity of
412 megawatts. Electric power generated by the facilities is supplied to a
diversified base of customers including National Power Corporation, the
Philippine state-owned utility, private distribution companies and industrial
users.
Haripur Power Project -- International owns a 50 percent interest in a
consortium formed to construct a 115 megawatt oil and natural gas-fired power
generation facility in Haripur, Bangladesh. The plant sells power to the
Bangladesh Power Development Board under a 15 year power purchase agreement. The
plant commenced commercial operations in June 1999.
Kabirwala Power Project -- International owns a 42 percent interest in a
151 megawatt natural gas fired power plant in Kabirwala, Pakistan. Commercial
operation is expected to commence in the first quarter of 2000. The project has
a thirty year power purchase agreement with the State Water and Power
Development Authority of Pakistan ("WAPDA") to sell power from the plant.
Meizhou Wan Power Project -- In October 1999, International acquired a 25
percent interest in a 762 megawatt coal-fired power plant in the People's
Republic of China. The Meizhou Wan power plant, located in the Fujian Province,
is expected to be operational in the first quarter of 2001.
Sengkang Integrated Energy Project -- International has a 50 percent
interest in a producing natural gas field with proven reserves of 533 Bcf and a
47.5 percent interest in a 135 megawatt power plant in Sengkang, South Sulawesi,
Indonesia. The electricity produced by the power plant is sold to PLN, the
national electric utility, under a long-term power purchase agreement. The
combined cycle power plant was one of the first independent power plants to
operate in Indonesia.
PPN Power Project -- In June 1999, International acquired a 26 percent
interest in a power plant in Tamil Nadu, India. The project consists of a 346
megawatt combined cycle power plant which will serve as a base load facility and
sell power to the state-owned Tamil Nadu Electricity Board under a thirty year
power purchase agreement. Construction began in January 1999, and operations are
expected to commence in early 2001.
Other Projects
International owns interests in three operating domestic power generation
plants consisting of a 17.5 percent interest in a 240 megawatt power plant in
Springfield, Massachusetts and a 50 percent interest in two additional
cogeneration projects in Florida with a combined generating capacity of 220
megawatts.
Regulatory Environment
The foreign operations of International's subsidiaries and joint ventures
are subject to the jurisdiction of numerous governmental agencies in the
countries in which its projects are located. Generally, many of the countries in
which International presently 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 the Company expects that the interpretation of existing rules in
these jurisdictions will evolve over time. The Company believes that its
operations are in compliance in all material respects with all applicable
environmental laws and regulations in the applicable foreign jurisdictions. The
Company also believes that the operations of its projects in many of these
countries eventually may be required to meet standards that are
12
<PAGE> 17
comparable in many respects to those in effect in the United States and in
countries within the European Community.
Markets and Competition
International operates in a highly competitive environment. The number of
competitors varies from country to country, as does their respective scope of
operations. However, the type of competitors International competes against in
most of its markets typically include other large multi-national energy
infrastructure companies; large, in-country utilities and energy infrastructure
companies; affiliates of major natural gas and oil producers as well as
independent power producers and independent energy companies. The successful
acquisition of new business opportunities is dependent upon International's
ability to (i) respond to requests to provide new services; (ii) mitigate
potential risks; and (iii) maintain a strong business development, legal,
financial and operational support team with experience in the respective
marketplace.
Many of International's energy generation and natural gas transmission
pipelines sell their services under long-term agreements. In some instances,
these facilities sell their energy generation and transmission services on a
market-based system. Globally, many of the legal and regulatory regimes under
which International competes are migrating toward a market-driven framework
increasing the level of competition. As these trends toward increasing
competition continue, local-market knowledge, operating efficiency, access to
fuel supplies and other factors will affect International's success.
FIELD SERVICES
The Field Services segment provides its customers with wellhead-to-mainline
services, including natural gas gathering and transportation, products
extraction, dehydration, purification, compression and intrastate natural gas
transmission services. It also provides well-ties and offers real-time
information services, including electronic wellhead gas flow measurement and
often 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 major natural gas gathering systems in the
San Juan and Permian Basins as well as systems in the Louisiana, east and south
Texas producing regions and an interest in a natural gas pipeline system located
in the Gulf of Mexico.
In 1999, Field Services acquired EnCap, an institutional funds management
firm specializing in financing independent oil and natural gas producers. EnCap
manages three separate institutional oil and natural gas investment funds in the
United States, and serves as investment advisor to Energy Capital Investment
Company PLC, a publicly traded investment company in the United Kingdom.
The Company also owns a combined 35 percent ownership interest in El Paso
Energy Partners, a publicly traded master limited partnership. In June 1999, the
Company increased its effective ownership interest in El Paso Energy Partners
from 27 percent in a transaction that transferred a 49 percent interest in
Viosca Knoll Gathering Company ("Viosca Knoll") to El Paso Energy Partners. El
Paso Energy Partners provides integrated energy services, including natural gas
and oil gathering, transportation, midstream and other related services in the
Gulf of Mexico. Through its subsidiaries and joint ventures, El Paso Energy
Partners owns interests in (i) nine natural gas pipeline systems, (ii) two oil
pipeline systems, (iii) six multi-purpose platforms, (iv) production handling
and dehydration facilities, (v) four producing oil and natural gas properties
and (vi) an overriding royalty interest in the Ewing Bank 958 Unit.
13
<PAGE> 18
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, 1999, and
for the three years ended December 31:
<TABLE>
<CAPTION>
AVERAGE THROUGHPUT
MILES THROUGHPUT (BBTU/D)
OF CAPACITY ---------------------
GATHERING & TREATING PIPELINE(1) (MMCF/D)(2) 1999 1998 1997
-------------------- ----------- ----------- ----- ----- -----
<S> <C> <C> <C> <C> <C>
Western Division...................... 5,555 1,200 1,262 1,191 1,167
Eastern Division...................... 1,251 909 386 424 372
Central Division...................... 1,230 820 315 427 408
Offshore Division..................... 410 2,040 656 780 314
Jointly Owned Division................ 750 900 557 564 6
</TABLE>
<TABLE>
<CAPTION>
AVERAGE NATURAL GAS
AVG. INLET VOLUME LIQUIDS SALES
INLET (BBTU/D) (MGAL/D)
CAPACITY(2) ------------------ ---------------------
PROCESSING PLANTS (MMCF/D) 1999 1998 1997 1999 1998 1997
----------------- ----------- ---- ---- ---- ----- ----- -----
<S> <C> <C> <C> <C> <C> <C> <C>
Western Division...................... 600 650 586 551 432 370 505
Eastern Division...................... 175 83 109 126 204 275 229
Central Division...................... 258 242 269 58 202 208 94
Jointly Owned Division................ 194 57 51 102 60 74 167
</TABLE>
<TABLE>
<CAPTION>
AVERAGE
AVERAGE THROUGHPUT THROUGHPUT THROUGHPUT
PERCENT OF MILES THROUGHPUT (BBTU/D) CAPACITY MBBLS
OWNERSHIP OF CAPACITY --------------------------- MBBLS OIL/D
EQUITY INVESTMENTS INTEREST PIPELINE(1) (MMCF/D)(2) 1999 1998(3) 1997(4) OIL/D(2) 1999(3)
- ------------------ ---------- ----------- ----------- ------- ------- ------- ---------- ----------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
El Paso Energy
Partners........... 35 1,382 1,808 596 593 -- 103 17
Oasis................ 35 608 350 263 289 338 -- --
Coyote Gulch......... 50 -- 120 97 69 42 -- --
Viosca Knoll(5)...... 1 125 10 142 287 205 -- --
</TABLE>
- ------------
(1) Mileage amounts are approximate for the total systems and have not been
reduced to reflect Field Services' net ownership.
(2) All capacity 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) Throughput for El Paso Energy Partners is averaged since its acquisition on
August 14, 1998.
(4) Throughput for Oasis Pipeline was reported in the Merchant Energy segment in
1997.
(5) Field Services sold its 49 percent interest in Viosca Knoll to El Paso
Energy Partners in June of 1999.
Regulatory Environment
Certain of El Paso Energy Partners' operations are subject to regulation by
FERC in accordance with the Natural Gas Act of 1938 and the Natural Gas Policy
Act of 1978. Each pipeline subject to regulation operates under separate FERC
approved tariffs with established rates, terms and conditions under which the
pipeline provides services.
In addition, certain of El Paso Energy Partners' operations, directly owned
or owned through equity investments, are subject to the Natural Gas Pipeline
Safety Act of 1968, as amended, 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 El Paso Energy Partners
believes that these systems are in substantial compliance with applicable
requirements.
Markets and Competition
Field Services operates in a highly competitive environment that includes
independent natural gas gathering and processing companies, intrastate pipeline
companies, natural gas marketers, and oil and natural
14
<PAGE> 19
gas producers. Field Services competes for throughput primarily based on price,
efficiency of facilities, gathering system line pressures, availability of
facilities near drilling activity, service, and access to favorable downstream
markets.
PRODUCTION
Production is engaged in the exploration for and the acquisition,
development, and production of natural gas, oil, and liquids in the major
producing basins of the United States. Production has onshore and coal seam
operations and properties in 11 states and offshore operations and properties in
federal and state waters in the Gulf of Mexico.
Production sells its natural gas primarily to Merchant Energy at
spot-market prices. Sales of natural gas to Merchant Energy accounted for
approximately 78 percent of Production's revenues in 1999, 68 percent in 1998,
and 54 percent in 1997. Production sells natural gas liquids at market prices
under monthly or long-term contracts and its oil production at posted prices,
subject to adjustments for gravity and transportation. A significant portion of
Production's 1999 production was hedged by entering into third-party contracts
and forward sales managed by Merchant Energy to reduce the risks associated with
spot-market price volatility.
Strategically, Production emphasizes disciplined investment criteria and
manages its existing production portfolio to maximize volumes and minimize
costs. In 2000, Production expects to continue an active onshore and offshore
drilling program to capitalize on its land and seismic holdings. Production is
also pursuing strategic acquisitions of producing properties and the development
of coal seam methane projects. In 1999, Production replaced 99 percent of the
reserves it produced.
Natural Gas and Oil Reserves
The following table details Production's proved reserves at December 31,
1999. Information in the table is based upon the reserve report prepared by
Production dated January 1, 2000. For further discussion concerning reserves,
see Item 8, Financial Statements and Supplementary Data, Note 20.
<TABLE>
<CAPTION>
NET PROVED RESERVES(1)
--------------------------------------
NATURAL GAS LIQUIDS(2) TOTAL
----------- ---------- ---------
(MMCF) (MBBLS) (MMCFE)
<S> <C> <C> <C>
Producing................................................. 803,607 15,315 895,497
Non-Producing............................................. 163,519 4,398 189,907
Undeveloped............................................... 303,505 10,725 367,855
--------- ------ ---------
Total proved reserves........................... 1,270,631 30,438 1,453,259
========= ====== =========
</TABLE>
- ---------------
(1) Net proved reserves excludes royalties and interests owned by others and
reflects contractual arrangements and royalty obligations in effect at the
time of the estimate.
(2) Includes oil, condensate, and liquids
There are numerous uncertainties inherent in estimating quantities of
proved reserves and in projecting future rates of production and timing of
development expenditures, including many factors beyond the control of
Production. The reserve data represents only estimates. Reservoir engineering is
a subjective process of estimating underground accumulations of natural gas and
oil that cannot be measured in an exact manner. The accuracy of any reserve
estimate is a function of the quality of available data and of engineering and
geological interpretations and judgment. As a result, estimates of different
engineers often vary. In addition, results of drilling, testing, and production
subsequent to the date of an estimate may justify revision of such estimate.
Accordingly, reserve estimates are often different from the quantities of
natural gas and oil that are ultimately recovered. The meaningfulness of reserve
estimates is highly dependent upon the accuracy of the assumptions upon which
they were based. In general, the volume of production from natural gas and oil
properties owned by Production declines as reserves are depleted. Except to the
extent Production conducts successful exploration and development activities or
acquires additional properties containing proved reserves, or both, the proved
reserves of Production will decline as reserves are produced.
15
<PAGE> 20
Production's estimate of reserves filed with other federal agencies agrees
with the information detailed in Item 8, Financial Statements and Supplementary
Data, Note 20, except for differences resulting from actual production,
acquisitions, property sales, and necessary reserve revisions and additions to
reflect actual experience.
Wells and Acreage
The following table details Production's gross and net interest in
developed and undeveloped onshore, offshore, and coal seam acreage at December
31, 1999. Any acreage in which Production's interest is limited to owned
royalty, overriding royalty, and other similar interests is excluded.
<TABLE>
<CAPTION>
DEVELOPED UNDEVELOPED TOTAL
------------------ ---------------------- ----------------------
GROSS NET GROSS NET GROSS NET
------- ------- --------- --------- --------- ---------
<S> <C> <C> <C> <C> <C> <C>
Onshore.................. 459,130 240,024 1,019,998 691,266 1,479,128 931,290
Offshore................. 270,959 182,141 1,323,532 1,250,033 1,594,491 1,432,174
Coal seam................ 18,919 17,446 612,048 392,191 630,967 409,637
------- ------- --------- --------- --------- ---------
Total.......... 749,008 439,611 2,955,578 2,333,490 3,704,586 2,773,101
======= ======= ========= ========= ========= =========
</TABLE>
The following table details Production's working interests in onshore,
offshore, and coal seam natural gas and oil wells at December 31, 1999. Gross
wells include 35 multiple completions.
<TABLE>
<CAPTION>
NUMBER OF
PRODUCTIVE PRODUCTIVE TOTAL WELLS BEING
NATURAL GAS WELLS OIL WELLS PRODUCTIVE WELLS DRILLED
------------------ ------------ ---------------- -------------
GROSS NET GROSS NET GROSS NET GROSS NET
------- ------- ----- --- ------ ------ ----- ----
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Onshore....................... 1,468 993 38 34 1,506 1,027 17 5
Offshore...................... 187 126 60 17 247 143 5 5
Coal seam..................... 818 552 -- -- 818 552 33 26
----- ----- -- -- ----- ----- -- ----
Total............... 2,473 1,671 98 51 2,571 1,722 55 36
===== ===== == == ===== ===== == ====
</TABLE>
The following table details Production's exploratory and development wells
drilled during the years 1997 through 1999.
<TABLE>
<CAPTION>
NET EXPLORATORY NET DEVELOPMENT
WELLS DRILLED WELLS DRILLED
------------------ ------------------
1999 1998 1997 1999 1998 1997
---- ---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C> <C>
Productive............................................. 12 15 19 116 204 296
Dry.................................................... 14 19 15 2 18 19
-- -- -- --- --- ---
Total........................................ 26 34 34 118 222 315
== == == === === ===
</TABLE>
The information above should not be considered indicative of future
drilling performance, nor should it be assumed that there is any correlation
between the number of productive wells drilled and the amount of natural gas and
oil that may ultimately be recovered.
16
<PAGE> 21
Net Production, Unit Prices, and Production Costs
The following table details Production's net production volumes, average
sales prices received, and average production costs associated with the sale of
natural gas and oil for the years ended December 31:
<TABLE>
<CAPTION>
1999 1998 1997
------ ------ ------
<S> <C> <C> <C>
Net Production:
Natural Gas (Bcf)......................................... 186 226 266
Oil, Condensate, and Liquids (MMBbls)..................... 6 8 9
Total (Bcfe)...................................... 221 276 318
Average Realized Sales Price:
Natural Gas ($/Mcf)....................................... $ 2.05 $ 1.95 $ 2.26
Oil, Condensate, and Liquids ($/Bbl)...................... $15.46 $12.22 $17.95
Average Production Cost ($/Mcfe)(1)......................... $ 0.38 $ 0.33 $ 0.37
</TABLE>
- ---------------
(1) Includes direct lifting costs (labor, repairs and maintenance, materials,
and supplies) and the administrative costs of production offices, insurance,
and property and severance taxes.
Development, Exploration, and Acquisition Expenditures
The following table details certain information regarding Production's
costs incurred in its development, exploration, and acquisition activities
during the years ended December 31:
<TABLE>
<CAPTION>
1999 1998 1997
---- ---- ----
(IN MILLIONS)
<S> <C> <C> <C>
Development Costs........................................... $178 $375 $491
Exploration Costs:
Proved Acquisitions....................................... 3 2 6
Lease Acquisitions and Delay Rentals...................... 52 59 87
Seismic Acquisition and Reprocessing...................... 58 53 102
Drilling.................................................. 74 92 177
---- ---- ----
Total Capital Expenditures........................ $365 $581 $863
==== ==== ====
</TABLE>
Regulatory and Operating Environment
The federal government and the states in which Production operates or owns
interests in producing properties regulate various matters affecting natural gas
and oil production, including the drilling and spacing of wells, conservation,
forced pooling, and protection of correlative rights among interest owners.
Production is also subject to governmental safety regulations in the
jurisdictions in which it operates.
Production's operations under federal natural gas and oil leases are
subject to certain statutes and regulations of the United States Department of
the Interior that currently impose liability upon lessees for the cost of
pollution resulting from their operations. Royalty obligations on all federal
leases are regulated by the Minerals Management Service, which has promulgated
valuation guidelines for the payment of royalties by producers. Other federal,
state, and local laws and regulations relating to the protection of the
environment affect Production's natural gas and oil operations through their
effect on the construction and operation of facilities, drilling operations,
production, or the delay or prevention of future offshore lease sales. The
Company maintains substantial insurance on behalf of Production for sudden and
accidental spills and oil pollution liability.
Production's business is subject to all of the operating risks normally
associated with the exploration for and production of natural gas and oil,
including blowouts, cratering, pollution, and fires, each of which could result
in damage to life or property. Offshore operations are subject to usual marine
perils, including hurricanes and other adverse weather conditions, and
governmental regulations as well as interruption or termination by governmental
authorities based on environmental and other considerations. In accordance with
17
<PAGE> 22
customary industry practices, the Company maintains broad insurance coverage on
behalf of Production with respect to potential losses resulting from these
operating hazards.
Markets and Competition
The natural gas and oil business is highly competitive in the search for
and acquisition of additional reserves and in the sale of natural gas, oil, and
liquids. Production's competitors include the major and intermediate sized oil
and natural gas companies, independent oil and natural gas operations, and
individual producers or operators with varying scopes of operations and
financial resources. Competitive factors include price, contract terms, and
quality of service. These factors are, to some degree, mitigated by the large
percentage of natural gas sales made to Merchant Energy.
CORPORATE AND OTHER OPERATIONS
The Company, through its corporate and other segment, performs management,
legal, financial, tax, consultative, administrative and other services for the
operating business segments of the Company. The costs of providing such services
are allocated to the Company's business segments.
ENVIRONMENTAL
A description of the Company's environmental activities is included in Item
8, Financial Statements and Supplementary Data, Note 10, and is incorporated by
reference herein.
EMPLOYEES
The Company had approximately 4,700 full-time employees as of December 31,
1999. The Company has no collective bargaining arrangements. During 1999, the
Company reduced its combined workforce by approximately 850 employees as a
result of a program to streamline operations and reduce operating costs
following its merger with Sonat.
EXECUTIVE OFFICERS OF THE REGISTRANT
The executive officers of El Paso as of February 16, 2000, are set forth
below. For dates prior to
August 1, 1998 (the date of the holding company reorganization), references to
positions held with El Paso refer instead to positions held with EPNG.
<TABLE>
<CAPTION>
OFFICER
NAME OFFICE SINCE AGE
---- ------ ------- ---
<S> <C> <C> <C>
William A. Wise.............. President and Chief Executive Officer of El 1983 54
Paso
H. Brent Austin.............. Executive Vice President and Chief Financial 1992 45
Officer of El Paso
Ralph Eads................... Executive Vice President of El Paso 1999 40
Joel Richards III............ Executive Vice President of El Paso 1990 53
William A. Smith............. Executive Vice President of El Paso 1999 55
Britton White Jr............. Executive Vice President and General Counsel 1991 56
of El Paso
John B. Holmes, Jr........... President of Production 1999 52
John D. Hushon............... President of International 1996 54
Greg G. Jenkins.............. President of Merchant Energy 1996 42
Robert G. Phillips........... President of Field Services 1995 45
John W. Somerhalder II....... Chairman of the Board of TGP, EPNG, and SNG 1990 44
</TABLE>
18
<PAGE> 23
Mr. Wise has been Chief Executive Officer since January 1990 and was
Chairman of the Board from January 1994 until October 1999. Mr. Wise was
President of El Paso from January 1990 to April 1996 and from July 1998 to
present. He served as President and Chief Operating Officer of El Paso from
April 1989 to December 1989. From March 1987 until April 1989, Mr. Wise was an
Executive Vice President of El Paso. From January 1984 to February 1987, he was
a Senior Vice President of El Paso. Mr. Wise is a member of the Board of
Directors of Battle Mountain Gold Company and is the Chairman of the Board of
EPTPC and El Paso Energy Partners Company, the general partner of El Paso Energy
Partners.
Mr. Austin has been Executive Vice President and Chief Financial Officer of
El Paso since May 1995. He has been Chief Financial Officer of El Paso since
April 1992. He was Senior Vice President of El Paso from April 1992 to April
1995. He was Vice President, Planning and Treasurer of Burlington Resources Inc.
("BR") from November 1990 to March 1992 and Assistant Vice President, Planning
of BR from January 1989 to October 1990.
Mr. Eads has been Executive Vice President of El Paso since July 1999. Mr.
Eads was a Managing Director and Co-Head of the Energy Group at Donaldson,
Lufkin & Jenrette from January 1996 through June 1999. He was Managing Director,
Head of Energy at S.G. Warburg Company from October 1993 to December 1995.
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. He was Vice President from June 1990 to December 1990. He was Senior Vice
President, Finance and Human Resources of Meridian Minerals Company, a wholly
owned subsidiary of BR, from October 1988 to June 1990.
Mr. Smith has been Executive Vice President of El Paso since October 1999.
He was Executive Vice President and General Counsel of Sonat Inc. from 1995 to
September 1999. He was Vice Chairman of Sonat Exploration from 1994 to 1995 and
Chairman and President of SNG from 1989 to 1994.
Mr. White has been Executive Vice President of El Paso since December 1996
and General Counsel of El Paso since March 1991. He was Senior Vice President
and General Counsel of El Paso from March 1991 until December 1996. From March
1991 to April 1992, he was also Corporate Secretary of El Paso. For more than
five years prior to that time, Mr. White was a partner in the law firm of
Holland & Hart.
Mr. Holmes has been President of Production since October 1999. He was
Senior Vice President of Sonat Inc. and President of Sonat Exploration from May
1998 to October 1999. For more than five years prior to that time, Mr. Holmes
was President of Zilkha Energy Company.
Mr. Hushon has been President of International since April 1996. He was
Senior Vice President of International from September 1995 to April 1996. For
more than five years prior to that time, Mr. Hushon was a senior partner in the
law firm of Arent Fox Kintner Plotkin & Kahn.
Mr. Jenkins has been President of Merchant Energy since December 1996. He
was Senior Vice President and General Manager of Entergy Corp. from May 1996 to
December 1996 and President and Chief Executive Officer of Hadson Gas Services
Company from December 1993 to January 1996. For more than five years prior to
that time, Mr. Jenkins was in various managerial positions with Santa Fe Energy
Resources, Inc.
Mr. Phillips has been President of Field Services since June 1997. He was
President of El Paso Energy Resources Company from December 1996 to June 1997,
President of Field Services from April 1996 to December 1996 and was a Senior
Vice President of El Paso from September 1995 to April 1996. For more than five
years prior to that time, Mr. Phillips was Chief Executive Officer of Eastex
Energy, Inc.
Mr. Somerhalder has been Chairman of the Board of TGP, EPNG, and SNG since
January 2000. He was President of TGP from December 1996 to January 2000,
President of El Paso Energy Resources Company from April 1996 to December 1996
and Senior Vice President of El Paso from August 1992 to April 1996. From
January 1990 to July 1992, he was Vice President of El Paso.
Executive officers hold offices until their successors are elected and
qualified, subject to their earlier removal.
19
<PAGE> 24
ITEM 2. PROPERTIES
A description of the Company's properties is included in Item 1, Business
and is incorporated by reference herein.
The Company is of the opinion that it has generally satisfactory title to
the properties owned and used in its businesses, subject to liens for current
taxes, liens incident to minor encumbrances, and easements and restrictions that
do not materially detract from the value of such property or the interests
therein or the use of such properties in its businesses. The Company believes
that its physical properties are adequate and suitable for the conduct of its
business in the future.
ITEM 3. LEGAL PROCEEDINGS
See Item 8, Financial Statements and Supplementary Data, Note 10, which is
incorporated herein by reference.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
20
<PAGE> 25
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
El Paso's common stock is traded on the New York Stock Exchange under the
symbol "EPG." As of February 16, 2000, the number of holders of record of common
stock was approximately 75,700. This does not include individual participants on
whose behalf a clearing agency, or its nominee, holds El Paso's common stock.
The following table reflects the high and low sales prices for El Paso
common stock for the periods indicated based on the daily composite listing of
stock transactions for the New York Stock Exchange and cash dividends declared
during those periods.
<TABLE>
<CAPTION>
HIGH LOW DIVIDENDS(1)
-------- -------- ------------
(PER SHARE)
<S> <C> <C> <C>
1999
First Quarter.................................... $39.3750 $30.6875 $ 0.20000
Second Quarter................................... 38.3750 31.9375 0.20000
Third Quarter.................................... 40.5000 34.4375 0.20000
Fourth Quarter................................... 43.4375 33.3750 0.20000
1998
First Quarter.................................... $35.6250 $31.1250 $ 0.19125
Second Quarter................................... 38.9375 35.4375 0.19125
Third Quarter.................................... 38.6250 24.6875 0.19125
Fourth Quarter................................... 36.8125 30.1250 0.19125
</TABLE>
- ---------------
(1) During the first three quarters of 1999 and for the year 1998, Sonat
declared and paid quarterly dividends of $0.27 per share.
In January 2000, the Board declared a quarterly dividend of $0.206 per
share of common stock, payable on April 3, 2000, to stockholders of record on
March 3, 2000. The declaration of future dividends will be dependent upon
business conditions, earnings, the cash requirements of El Paso, and other
relevant factors.
In June 1999, in conjunction with the Sonat merger, the stockholders
approved an increase in the Company's authorized common stock to 750 million
shares. In July 1999, the Company rescinded its common stock repurchase program
in order to comply with the requirements to treat its merger with Sonat as a
pooling of interests under generally accepted accounting principles. The program
originally authorized El Paso to repurchase up to 10 million shares.
El Paso has made available a continuous odd-lot stock sales program (the
"Program"), in which stockholders owning beneficially fewer than 100 shares of
common stock ("Odd-Lot-Holders") are offered a convenient method of selling all
their odd-lot shares without incurring any brokerage costs. Only Odd-Lot Holders
are eligible to participate in the Program. The Program is strictly voluntary,
and no Odd-Lot Holder is obligated to sell pursuant to the Program. The Program
currently does not have a termination date but may be suspended at any time.
Inquiries regarding the Program should be directed to EquiServe.
El Paso has made available a dividend reinvestment and common stock
purchase plan (the "Plan"), which provides all stockholders of record a
convenient and economical means of increasing their holdings in the Company's
common stock. The Plan is strictly voluntary, and no stockholder of record is
obligated to participate in the Plan. The Plan currently does not have a
termination date but may be suspended at any time. Inquiries regarding the Plan
and participation therein should be directed to EquiServe.
21
<PAGE> 26
ITEM 6. SELECTED FINANCIAL DATA
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
----------------------------------------------
1999 1998 1997 1996 1995
------- ------- ------- ------ -------
(IN MILLIONS, EXCEPT PER COMMON SHARE AMOUNTS)
<S> <C> <C> <C> <C> <C>
Operating Results Data:(a)(b)
Operating revenues................................ $10,581 $9,500 $10,015 $6,217 $2,941
Merger-related and asset impairment
charges(c)(d)(e)(f)............................ 557 15 50 99 --
Ceiling test charges(c)(d)........................ 352 1,035 -- -- --
Income (loss) before cumulative effect of
accounting change.............................. (242) (306) 405 294 354
Basic earnings (loss) per common share before
cumulative effect of accounting change......... (1.06) (1.35) 1.81 1.61 1.98
Diluted earnings (loss) per common share before
cumulative effect of accounting change......... (1.06) (1.35) 1.77 1.59 1.97
Cash dividends declared per common share(g)....... .80 .76 .73 .70 .66
Basic average common shares outstanding........... 228 226 224 183 179
Diluted average common shares outstanding(h)...... 228 226 229 185 180
</TABLE>
<TABLE>
<CAPTION>
DECEMBER 31,
----------------------------------------------
1999 1998 1997 1996 1995
------- ------- ------- ------- ------
(IN MILLIONS)
<S> <C> <C> <C> <C> <C>
Financial Position Data:(a)(b)
Total assets..................................... $16,657 $14,443 $14,784 $13,206 $6,548
Long-term debt, less current maturities.......... 5,223 3,692 3,404 3,251 1,640
Company-obligated mandatorily redeemable
convertible preferred securities of El Paso
Energy Capital Trust I........................ 325 325 -- -- --
Other minority interest.......................... 1,368 374 380 347 9
Stockholders' equity............................. 2,947 3,437 3,921 3,514 2,428
</TABLE>
- ---------------
(a)Reflects the acquisition in January 1998 of Zilkha Energy Company and in
October 1999 of Sonat Inc. These acquisitions were accounted for as a pooling
of interests, and accordingly, the operating results and financial position
data have been restated to include the accounts and operations of Zilkha and
Sonat for all periods presented.
(b)Reflects the acquisition in September 1995 of Eastex Energy, Inc., in
December 1995 of Premier Gas Company, in June 1996 of Cornerstone Natural
Gas, Inc., in December 1996 of EPTPC, and in August 1998 of DeepTech. These
acquisitions were accounted for as purchases and therefore operating results
are included prospectively from the date of acquisition.
(c)Reflects charges in 1999 of $909 million pretax ($664 million after tax)
associated with the Company's merger with Sonat, certain asset impairment
charges, and a first quarter ceiling test charge. Basic earnings per common
share before cumulative effect of accounting change for the year ended
December 31, 1999, before giving effect to these charges would have been
$1.85. Diluted average common shares outstanding and diluted earnings per
common share before cumulative effect of accounting change for the year ended
December 31, 1999, before giving effect to these charges would have been 239
million shares and $1.81, respectively.
(d)Reflects charges in 1998 of $1,050 million pretax ($651 million after tax)
associated with the Company's acquisition of Zilkha and ceiling test charges.
Before giving effect to these charges, basic and diluted earnings per common
share before cumulative effect of accounting change for the year ended
December 31, 1998 would have been $1.53 and $1.49, respectively.
(e)Reflects charges in 1997 of $50 million pretax ($33 million after tax)
associated with the Company's acquisition of Zilkha. Before giving effect to
these charges, basic and diluted earnings per common share before cumulative
effect of accounting change for the year ended December 31, 1997 would have
been $1.95 and $1.91, respectively.
(f)Reflects a charge in 1996 of $99 million pre-tax ($60 million after tax) to
reflect costs associated with the implementation of a workforce reduction
plan and the impairment of certain long-lived assets. Before giving effect to
this charge and an $8 million pre-tax ($5 million after tax) charge taken in
the fourth quarter for relocating the corporate headquarters from El Paso,
Texas to Houston, Texas in connection with the acquisition of EPTPC, basic
and diluted earnings per common share before cumulative effect of accounting
change for the year ended December 31, 1996, would have been $1.96 and $1.94,
respectively.
(g)Dividends for all periods reflect historical El Paso dividends.
(h)The addition of potential dilutive common shares to basic average common
shares outstanding for the 1999 and 1998 periods would have been antidilutive
in the computation of diluted earnings per share.
22
<PAGE> 27
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
GENERAL
Over the past five years, the Company's business activities and operations
have changed dramatically as a result of significant acquisitions and
transactions designed to enhance the Company's ability to compete effectively in
the global energy industry. These changes have significantly expanded the
Company's operating scope, its ability to generate operating cash flows and its
needs for cash for investment opportunities. Consequently, the Company has
substantially expanded its credit facilities and created other financing
structures and facilities to meet its needs during this period.
The Company's business activities are segregated into five segments:
Natural Gas Transmission, Merchant Energy, International, Field Services and
Production. This structure reflects the Company's operating segments following
its merger with Sonat, and all historical periods have been presented on the
basis of the current segment presentation. Each of the Company's segments are
strategic business units that offer a variety of different energy products and
services. The Company manages each of these segments separately as each requires
different technology and marketing strategies. Certain business segments'
earnings are largely derived from the earnings of equity investments.
Accordingly, the Company evaluates segment performance based on EBIT.
Merger with The Coastal Corporation
In January 2000, the Company announced it had entered into a definitive
agreement to merge with Coastal. In the merger, each share of Coastal common
stock and Class A common stock will be converted on a tax-free basis into 1.23
shares of Company common stock. Coastal's outstanding convertible preferred
stock will be exchanged for Company common stock on the same basis as if the
preferred stock had been converted into Coastal common stock immediately prior
to the merger. The total value of the transaction is approximately $16 billion,
including $6 billion of assumed debt and preferred equity, will be accounted for
as a pooling of interests, and is expected to close in the fourth quarter of
2000. The Company and Coastal will complete the merger only if a number of
conditions are satisfied or waived, including:
- Coastal stockholders approve and adopt the merger agreement;
- Company stockholders approve the issuance of shares of El Paso common
stock in connection with the merger;
- no law or court order prohibits the transaction;
- all relevant waiting periods under federal antitrust laws applicable to
the merger expire or terminate;
- all other regulatory approvals, including the approval of FERC, are
received without conditions that would have a material adverse effect on
the financial condition, results of operations, or cash flow of the
Company's and Coastal's combined businesses;
- the Company's and Coastal's independent public accountants concur that
the merger will qualify for pooling of interest accounting treatment; and
- attorneys for the Company and Coastal issue opinions that the merger is
expected to be tax-free.
However, there cannot be any assurance that the Company and Coastal will
complete the merger even if all those conditions are satisfied.
Coastal is a diversified energy holding company. It is engaged, through its
subsidiaries and joint ventures, in natural gas transmission, storage,
gathering, processing and marketing; natural gas and oil exploration and
production; petroleum refining, marketing and distribution; chemicals; power
production; and coal. Coastal owns interests in approximately 18,000 miles of
natural gas pipelines extending across the midwestern and the Rocky Mountain
areas of the United States and has proved reserves of 3.6 Tcfe. Coastal also has
international
23
<PAGE> 28
and domestic interests in natural gas and oil producing properties, power
production plants, and crude oil refining facilities.
Purchase of Texas Midstream Operations
In January 2000, the Company entered into an agreement to purchase the
natural gas and natural gas liquids businesses of PG&E Gas Transmission, Texas
Corporation and PG&E Gas Transmission Teco, Inc. The total value of the
transaction is $840 million, including the face amount of assumed debt of
approximately $561 million. The acquisition, which is expected to close by
mid-year 2000, is subject to the receipt of certain required governmental
approvals and third party consents. The transaction will be accounted for as a
purchase and will be included in Field Services.
The assets being acquired consist of 8,500 miles of intrastate natural gas
transmission pipelines that transport approximately 2.8 Bcf/d in the South Texas
area, nine natural gas processing plants that currently process 1.5 Bcf/d, and a
7.2 Bcf natural gas storage field. The transaction also includes significant
natural gas liquids pipelines and fractionation facilities.
Merger with Sonat Inc.
On October 25, 1999, the Company completed its merger with Sonat. In the
merger, the Company issued one share of El Paso common stock for each share of
Sonat common stock. Total shares issued were approximately 110 million shares.
The Company also assumed approximately $2.3 billion of Sonat debt. As a result
of the merger, the Company incurred a total of approximately $515 million in
merger related costs and merger related asset impairment charges.
During the first quarter of 2000, the Company will complete the sales of
its East Tennessee Natural Gas Company and Sea Robin Pipeline Company as well as
its one-third interest in Destin Pipeline Company to comply with a Federal Trade
Commission order related to its merger with Sonat. Proceeds from the sales are
expected to be approximately $618 million. The Company will treat the expected
gain arising from these sales as an extraordinary item. After reflecting the
expected gain, the Company believes that the future impact of these dispositions
will not, individually or in the aggregate, have a material effect on the
Company's overall financial position, results of operations, or cash flows.
The Company accounted for the merger as a pooling of interests.
Accordingly, all information herein has been restated as though the transaction
occurred at the beginning of the earliest period presented.
Holding Company Reorganization and Tax-free Internal Reorganization
Effective August 1, 1998, the Company reorganized into a holding company
organizational structure, whereby El Paso became the parent holding company. See
Item 8, Financial Statements and Supplementary Data, Note 1, for a further
discussion of the holding company reorganization. On December 31, 1998, and
again in 1999, following its merger with Sonat, the Company completed a tax-free
internal reorganization of its assets and operations and those of certain of its
subsidiaries. In the reorganizations, a number of subsidiaries were transferred
to or from El Paso and/or other entities owned by El Paso. Neither the creation
of the holding company structure nor the tax-free internal reorganizations had
any impact on the overall, or segment, presentations herein.
RESULTS OF OPERATIONS
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 sales and
expenses which are eliminated in consolidation. The Company believes that gross
margin (revenue less cost of sales), rather than operating revenue, provides a
more accurate indicator 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 16.
24
<PAGE> 29
During the three year period ended December 31, 1999, the Company has
incurred significant charges related to the Company's 1999 merger with Sonat
along with certain other asset impairment charges, costs associated with its
1998 acquisition with Zilkha Energy, and write-downs of capitalized costs of
natural gas and oil properties under the full cost method of accounting. These
charges have impacted each of the Company's operating units during this period
and similar costs are anticipated in the future as the Company makes and
integrates future acquisitions and/or enters into significant transactions that
shape and impact its business strategy and operations. The table below provides
a summary of these charges for each of the three years ended December 31, 1999
by business segment and in total:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
--------------------------
1999 1998 1997
---- ------ ----
(IN MILLIONS)
<S> <C> <C> <C>
Merger-related and asset impairment charges
Natural Gas Transmission.................................. $ 90 $ -- $ --
Merchant Energy........................................... 67 -- --
Field Services............................................ 8 -- --
Production................................................ 31 15 50
---- ------ ----
Segment total.......................................... 196 15 50
Corporate................................................. 361 -- --
---- ------ ----
Consolidated total..................................... $557 $ 15 $ 50
==== ====== ====
Ceiling test charges--Production............................ $352 $1,035 $ --
==== ====== ====
</TABLE>
The following table presents EBIT by segment and in total for each of the
three years ended December 31, 1999, including the charges discussed above:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
----------------------------
1999 1998 1997
----- ----- ------
(IN MILLIONS)
<S> <C> <C> <C>
EARNINGS BEFORE INTEREST EXPENSE AND INCOME TAXES
Natural Gas Transmission.................................... $ 719 $ 811 $ 808
Merchant Energy............................................. (50) 3 (21)
International............................................... 45 25 2
Field Services.............................................. 92 76 75
Production.................................................. (257) (936) 182
----- ----- ------
Segment EBIT.............................................. 549 (21) 1,046
----- ----- ------
Corporate expenses, net..................................... (358) (31) (38)
----- ----- ------
Consolidated EBIT......................................... $ 191 $ (52) $1,008
===== ===== ======
</TABLE>
EBIT year to year variances are discussed in the segment results below.
NATURAL GAS TRANSMISSION
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
------------------------------
1999 1998 1997
------ ------ ------
(IN MILLIONS)
<S> <C> <C> <C>
Operating revenues.......................................... $1,637 $1,630 $1,707
Operating expenses.......................................... (973) (881) (949)
Other income................................................ 55 62 50
------ ------ ------
EBIT...................................................... $ 719 $ 811 $ 808
====== ====== ======
</TABLE>
25
<PAGE> 30
YEAR ENDED DECEMBER 31, 1999 COMPARED TO YEAR ENDED DECEMBER 31, 1998
Operating revenues for the year ended December 31, 1999, were $7 million
higher than 1998. This increase was due to the favorable resolution of certain
regulatory issues during 1999 on the TGP system related to its New England rates
coupled with a downward revision in 1998 of the amount of recoverable interest
on TGP's GSR costs. Also contributing to the increase were higher revenues on
the EPNG system from increased long-term transportation and the sale of capacity
to Dynegy, and an increase in firm transportation revenues on the SNG system
associated with expansion projects. These increases were partially offset by
lower system throughput on the TGP system in 1999, the favorable resolution in
1998 of a contested rate matter on the MPC system related to its rate
methodology, higher non-transportation revenues in 1998 on the SNG system, and a
decrease in transportation revenues due to lower throughput on the Sea Robin
system in 1999.
Operating expenses for the year ended December 31, 1999, were $92 million
higher than 1998. The increase was primarily due to merger-related charges
resulting from the El Paso/Sonat merger including severance and termination
charges, the impact of conforming accounting policies and practices within the
transmission segment and impairment charges for redundant assets and inventory.
Also contributing to the increase were reserves established in 1999 for lower
anticipated recoveries of SNG's North Alabama and Palmetto pipeline projects,
higher general and administrative costs on each of the Company's systems, higher
depreciation from expansion projects completed on SNG, and the effect of EPNG's
regulatory settlement with Edison. Partially offsetting these increases were the
favorable resolution of TGP's customer imbalance mechanism, revised estimates of
rate recoveries on items included in EPNG's cost of service, and lower fuel
costs associated with lower throughput in 1999 on both the TGP and EPNG systems.
Other income for the year ended December 31, 1999, was $7 million lower
than 1998. The decrease in other was primarily due to lower equity earnings in
Destin in 1999, partially offset by an increase in 1999 interest income on a
Destin-related debt issuance during the latter part of 1998.
YEAR ENDED DECEMBER 31, 1998 COMPARED TO YEAR ENDED DECEMBER 31, 1997
Operating revenues for the year ended December 31, 1998, were $77 million
lower than 1997 primarily due to lower revenues on the EPNG system from the
expiration of the Pacific Gas & Electric Company contract effective December 31,
1997. Also contributing to the decrease was lower throughput on the TGP system
from warmer average temperatures in the northeastern and midwestern markets and
a downward revision in 1998 of TGP's recoverable interest on GSR costs. These
decreases were significantly offset by EPNG's risk sharing revenue and revenues
from the sale of capacity to Dynegy, and the favorable resolution of a contested
rate matter on the MPC system.
Operating expenses for the year ended December 31, 1998, were $68 million
lower than 1997 primarily due to lower system fuel usage on TGP associated with
operating efficiencies attained as a result of lower throughput, reduced general
and administrative expenses on TGP largely due to lower payroll costs, as well
as lower compensation and employee benefits costs at SNG. These decreases were
partially offset by the recovery of a receivable previously deemed uncollectible
in 1997.
Other income for the year ended December 31, 1998, was $12 million higher
than 1997 primarily due to the interest component of a favorable sales and use
tax settlement, gains on the sale of assets, and the inclusion of SNG's share of
earnings in Destin. Destin's earnings increase was the result of higher
allowance for funds used during construction capitalized in 1998 as compared
with 1997 levels.
26
<PAGE> 31
MERCHANT ENERGY
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-----------------------
1999 1998 1997
----- ----- -----
(IN MILLIONS)
<S> <C> <C> <C>
Natural gas margin.......................................... $ 80 $ 42 $ 67
Power margin................................................ 48 28 2
Other energy commodities margin............................. -- 1 (3)
---- ---- ----
Total gross margin................................ 128 71 66
Operating expenses.......................................... (193) (81) (88)
Other income................................................ 15 13 1
---- ---- ----
EBIT...................................................... $(50) $ 3 $(21)
==== ==== ====
</TABLE>
YEAR ENDED DECEMBER 31, 1999 COMPARED TO YEAR ENDED DECEMBER 31, 1998
Total gross margin for the year ended December 31, 1999, was $57 million
higher than 1998. The increase in the natural gas margin was primarily due to
higher income recognition from long-term natural gas transactions and contracts
completed during 1999, partially offset by a decline in the value of
mark-to-market positions resulting from the termination of certain contracts in
1999. The increase in the power margin was due to management fee income earned
in 1999 on Merchant Energy's Electron project and revenues on consolidated power
generation facilities acquired in December 1998. The increases were partially
offset by a decrease in power trading margins in 1999.
Operating expenses for the year ended December 31, 1999, were $112 million
higher than 1998 due to higher operating costs associated with an increase in
power activities, operating expenses on consolidated power facilities acquired
in December 1998, and increases in merger-related charges, including integrating
accounting policies and practices, a decline in the value of certain
mark-to-market positions, and the write off of certain capitalized project costs
on abandoned projects. Also contributing to the increase was higher amortization
of goodwill resulting from a change in the estimated useful life of goodwill
related to the Company's 1995 acquisitions of Premier Gas Company and Eastex
Energy, Inc.
Other income for the year ended December 31, 1999, was $2 million higher
than 1998 primarily due to the March 1999 acquisition of a 50 percent interest
in CE Generation LLC, partially offset by lower earnings on other equity
investments and gains in 1998 from the sales of several assets. Also offsetting
these increases were lower losses assumed in 1999 by AGL Resources, Inc.
("AGL"), through its ownership interest in Sonat's merchant energy operations.
YEAR ENDED DECEMBER 31, 1998 COMPARED TO YEAR ENDED DECEMBER 31, 1997
Total gross margin for the year ended December 31, 1998, was $5 million
higher than 1997. Higher power margins as a result of increased trading activity
and power price volatility, coupled with reduced losses from trading activity on
other energy commodities, were offset by lower natural gas margins from a
revised estimate of natural gas imbalances and reduced revenues from Channel
Pipeline Company which was transferred to Field Services in 1998.
Operating expenses for the year end December 31, 1998, were $7 million
lower than 1997 due to the 1997 restructuring of the merchant energy
organization following the EPTPC acquisition and the transfer of Channel
Pipeline Company operations to Field Services. The decrease was partially offset
by an increase in Sonat Energy Services operating costs due to the expansion of
the scope of its business.
Other income for the year ended December 31, 1998, was $12 million higher
than 1997 primarily due to higher losses assumed by AGL, through its ownership
interest in Sonat's merchant energy operations along with the sale of Creole
Pipeline and a portion of Merchant Energy's equity interest in Berkshire in
1998.
27
<PAGE> 32
INTERNATIONAL
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
------------------------
1999 1998 1997
------ ----- -----
(IN MILLIONS)
<S> <C> <C> <C>
Operating revenues.......................................... $ 73 $ 58 $ 13
Operating expenses.......................................... (105) (85) (37)
Other income................................................ 77 52 26
----- ---- ----
EBIT...................................................... $ 45 $ 25 $ 2
===== ==== ====
</TABLE>
YEAR ENDED DECEMBER 31, 1999 COMPARED TO YEAR ENDED DECEMBER 31, 1998
Operating revenues for the year ended December 31, 1999, were $15 million
higher than 1998 primarily due to an increase in revenues from the Rio Negro
project which was consolidated in the third quarter of 1999 coupled with higher
revenues on the Manaus power project, partially offset by a decrease in EMA
Power revenues.
Operating expenses for the year ended December 31, 1999, were $20 million
higher than 1998 primarily due to higher operating expenses on consolidated
projects including increased payroll, outside services, insurance, supplies and
depreciation and amortization. These increases were partially offset by lower
project development costs in 1999.
Other income for the year ended December 31, 1999, was $25 million higher
than 1998 due to interest income earned on notes receivable, higher earnings on
equity investments and equity swap gains recognized in 1999 on International's
CAPSA project. These increases were partially offset by certain 1998 gains on
project-related activities and a gain on the sale of surplus power equipment.
YEAR ENDED DECEMBER 31, 1998 COMPARED TO YEAR ENDED DECEMBER 31, 1997
Operating revenues for the year ended December 31, 1998, were $45 million
higher than 1997 due to the consolidation for financial reporting purposes of
the Manaus Power project in May 1998 after acquiring an additional ownership
interest and an increase in revenue attributable to the EMA Power project which
the Company began reporting on a consolidated basis in July 1997.
Operating expenses for the year ended December 31, 1998, were $48 million
higher than 1997 primarily due to costs related to the consolidation of the EMA
Power and Manaus Power projects and increased general and administrative
expenses largely due to higher project development costs reflecting an increase
in project-related activities in 1998.
Other income for the year ended December 31, 1998, was $26 million higher
than 1997 primarily due to increased equity earnings, a gain on the sale of
surplus power equipment, and the recognition of certain gains from
project-related activities.
As International's projects move from the development stage to the
operational stage, it is common to recognize one-time gains and fees, which may
include management fees, development fees, financing fees, and gains on the
sell-down of ownership interests. The Company anticipates additional one-time
events may result in the recognition of income or expense in the future.
28
<PAGE> 33
FIELD SERVICES
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
---------------------------
1999 1998 1997
----- ----- -----
(IN MILLIONS)
<S> <C> <C> <C>
Gathering and treating margin............................... $ 162 $ 157 $ 125
Processing margin........................................... 44 48 55
Other margin................................................ 13 3 5
----- ----- -----
Total gross margin................................ 219 208 185
Operating expenses.......................................... (176) (146) (118)
Other income................................................ 49 14 8
----- ----- -----
EBIT...................................................... $ 92 $ 76 $ 75
===== ===== =====
</TABLE>
YEAR ENDED DECEMBER 31, 1999 COMPARED TO YEAR ENDED DECEMBER 31, 1998
Total gross margin for the year ended December 31, 1999, was $11 million
higher than 1998. The increase in the gathering and treating margin is primarily
due to higher volumes and average gathering rates in the San Juan basin,
partially offset by the elimination of margins on assets in the Anadarko Basin
that were sold in September 1998. The decrease in the processing margin resulted
from lower volumes and realized liquids prices during 1999 compared to 1998 and
the sale of several processing plants in the second quarter of 1999. The
increase in other margin resulted from the acquisition of EnCap in March of
1999.
Operating expenses for the year ended December 31, 1999, were $30 million
higher than 1998 primarily due to higher operating expenses related to the
acquisition of EnCap, higher shared services allocations, the write down of
certain gathering assets held for sale following the Company's merger with
Sonat, and an increase in amortization and depreciation expense attributable to
acquisitions.
Other income for the year ended December 31, 1999, was $35 million higher
than 1998 due to an increase in earnings on equity investments, primarily an
increase in earnings from El Paso Energy Partners, partially offset by a
decrease in equity earnings from Viosca Knoll which was sold in the second
quarter of 1999. The increase was also attributable to the net gain on the sale
of several assets, primarily Viosca Knoll during the second quarter of 1999.
YEAR ENDED DECEMBER 31, 1998 COMPARED TO YEAR ENDED DECEMBER 31, 1997
Total gross margin for the year ended December 31, 1998, was $23 million
higher than 1997. The increase in the gathering and treating margin primarily
resulted from higher gathering rates compared to 1997, an increase in gathering
and treating volumes largely attributable to the acquisition of the Texas Gulf
Coast subsidiaries of PacifiCorp ("TPC") in December 1997, and the inclusion of
the results of operations of Channel Pipeline Company in Field Services
beginning in January 1998 versus Merchant Energy in 1997. The decrease in the
processing margin was largely attributable to lower liquids prices during 1998
compared to the same period of 1997.
Operating expenses for the year ended December 31, 1998, were $28 million
higher than 1997 primarily as a result of additional expenses associated with
the addition of Channel Pipeline Company and TPC as well as higher general and
administrative expenses.
Other income for the year ended December 31, 1998, was $6 million higher
than 1997 primarily due to higher earnings from equity investments.
29
<PAGE> 34
PRODUCTION
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-----------------------------
1999 1998 1997
----- ------- -----
(IN MILLIONS)
<S> <C> <C> <C>
Natural gas................................................. $ 380 $ 440 $ 601
Oil, condensate and liquids................................. 90 101 154
Other....................................................... 3 (6) 1
----- ------- -----
Total operating revenues.......................... 473 535 756
Operating expenses.......................................... (731) (1,474) (578)
Other income................................................ 1 3 4
----- ------- -----
EBIT...................................................... $(257) $ (936) $ 182
===== ======= =====
</TABLE>
YEAR ENDED DECEMBER 31, 1999 COMPARED TO YEAR ENDED DECEMBER 31, 1998
Total operating revenues for the year ended December 31, 1999, were $62
million lower than 1998. The decrease in natural gas and oil, condensates and
liquids revenues was primarily due to property dispositions during 1998,
partially offset by an increase in realized prices in 1999. The increase in
other revenues resulted from a favorable contractual settlement in 1999.
Operating expenses for the year ended December 31, 1999, were $743 million
lower than 1998 primarily due to lower full cost ceiling test charges in 1999
versus the charges incurred in 1998, along with lower production levels in 1999.
Also contributing to the decrease were lower operating and maintenance expenses
due to property dispositions in 1998 and efficiencies created from the 1998
reorganization of Production. These decreases were partially offset by El
Paso/Sonat merger-related costs including costs to retain seismic data licenses,
consolidate offices, and write-down inventory.
Other income for the year ended December 31, 1999, was $2 million lower
than 1998 due primarily to a net gain on the sale of non-operating assets during
the third quarter of 1998.
YEAR ENDED DECEMBER 31, 1998 COMPARED TO YEAR ENDED DECEMBER 31, 1997
Total operating revenues for the year ended December 31, 1998, were $221
million lower than 1997. The decrease in natural gas revenues primarily resulted
from an overall decline in production volumes and realized prices during 1998
compared to the same period of 1997. The decrease in oil, condensate and liquids
revenues was largely attributable to lower realized oil and condensate prices.
Operating expenses for the year ended December 31, 1998, were $896 million
higher than 1997 as a result of ceiling test charges incurred during 1998, along
with restructuring charges in connection with Production's 1998 reorganization
of its operations. Partially offsetting these increases were 1997 charges
related to the acquisition of Zilkha Energy Company, lower 1998 depletion
resulting from decreased natural gas production, and reduced operating and
administrative costs following Production's 1998 restructuring.
Future quarterly full cost ceiling tests will be based on the then-current
prices for both natural gas and oil. The net carrying value of the Company's
natural gas and oil properties has been reduced due to the full cost ceiling
limitation such that the present value of the Company's proved natural gas and
oil reserves (discounted at 10 percent) does not exceed the Company's net
natural gas and oil properties recorded on its balance sheet. There is a risk of
future property write-downs due to factors that negatively affect the estimated
present value of proved natural gas and oil reserves, including volatile natural
gas and oil prices, downward revisions in estimated proved natural gas and oil
quantities, and unsuccessful exploratory operations, see Item 8. Financial
Statements and Supplementary Data, Note 4.
30
<PAGE> 35
CORPORATE EXPENSES, NET
YEAR ENDED DECEMBER 31, 1999 COMPARED TO YEAR ENDED DECEMBER 31, 1998
Net corporate expenses for the year ended December 31, 1999, were $327
million higher than 1998 primarily due to charges in 1999 related to the merger
with Sonat including the accelerated amortization of certain employee benefits;
legal, accounting, and financial advisory costs; termination, retention, and
severance costs; and incremental costs incurred in combining office facilities
following the merger. This increase was partially offset by start up costs
assumed in 1998 from the Company's power services activities and higher
recurring equity compensation charges in 1998.
YEAR ENDED DECEMBER 31, 1998 COMPARED TO YEAR ENDED DECEMBER 31, 1997
Net corporate expenses for the year ended December 31, 1998, were $7
million lower than 1997. The decrease resulted from lower benefits costs and
non-recurring gains, partially offset by administrative costs associated with
the formation and startup of the Company's power services activities established
in the first quarter of 1998, and increased costs associated with the Company's
Year 2000 project.
INTEREST AND DEBT EXPENSE
YEAR ENDED DECEMBER 31, 1999 COMPARED TO YEAR ENDED DECEMBER 31, 1998
Interest and debt expense for the year ended December 31, 1999, was $66
million higher than 1998 primarily due to increased borrowings by El Paso of
$1.8 billion to fund capital expenditures, acquisitions, and other investing
activities offset by higher capitalized interest in 1999 from higher project
investments and development primarily in Production and Merchant Energy.
YEAR ENDED DECEMBER 31, 1998 COMPARED TO YEAR ENDED DECEMBER 31, 1997
Interest and debt expense for the year ended December 31, 1998, was $43
million higher than 1997 primarily due to increased borrowings to fund capital
expenditures, acquisitions, and other investing activities and a higher average
effective interest rate during 1998 generally resulting from the higher rates
associated with the March 1997 issuance of TGP long-term debt of approximately
$883 million. These increases were partially offset by higher interest expense
in 1997 on rate refunds due to EPNG's customers.
INCOME TAX EXPENSE
YEAR ENDED DECEMBER 31, 1999 COMPARED TO YEAR ENDED DECEMBER 31, 1998
Income tax benefits of $81 million in 1999 and $170 million in 1998
resulted in effective tax rates of 27 percent and 38 percent, respectively. The
lower rate in 1999 is primarily due to merger-related costs incurred in 1999,
offset by exclusions of a portion of the earnings from certain unconsolidated
equity investees for which a dividend received deduction is anticipated when the
earnings are distributed.
YEAR ENDED DECEMBER 31, 1998 COMPARED TO YEAR ENDED DECEMBER 31, 1997
An income tax benefit of $170 million in 1998 and an income tax expense of
$234 million in 1997 resulted in effective tax rates of 38 percent and 35
percent, respectively. The higher rate in 1998 is primarily due to a reduction
in pretax income in 1998 as compared with 1997. The higher rate is partially
offset by lower state income taxes which reduced the 1998 benefit.
MINORITY INTEREST
YEAR ENDED DECEMBER 31, 1999 COMPARED TO YEAR ENDED DECEMBER 31, 1998
Minority interest for the year ended December 31, 1999, was $24 million
higher than in 1998 as a result of costs associated with a preferred interest in
Trinity River Associates, L.L.C. in 1999, coupled with a full year of dividends
on preferred securities of El Paso Energy Capital Trust issued in March 1998.
31
<PAGE> 36
YEAR ENDED DECEMBER 31, 1998 COMPARED TO YEAR ENDED DECEMBER 31, 1997
Minority interest for the year ended December 31, 1998, was $12 million
higher than in 1997 as a result of dividends paid on preferred securities of El
Paso Energy Capital Trust, a wholly owned subsidiary of El Paso, issued in March
1998.
LIQUIDITY AND CAPITAL RESOURCES
CASH FROM OPERATING ACTIVITIES
Net cash provided by operating activities was $501 million for the year
ended December 31, 1999, compared to $1,033 million for the same period of 1998.
The decrease was primarily attributable to cash payments for charges related to
the Sonat merger, net income tax refunds received in 1998, a reduction in GSR
collections in 1999, and the early payout of certain employee benefits as a
result of an EPEC change of control (as defined in certain benefit plans) in
1999. The decrease was partially offset by a take-or-pay refund paid to EPNG
customers in 1998 and other working capital changes.
CASH FROM INVESTING ACTIVITIES
Net cash used in investing activities was $2.3 billion for the year ended
December 31, 1999. Amounts paid for joint ventures and equity investment
activities were primarily for the acquisition of an interest in Chaparral, a 50
percent ownership interest in CE Generation LLC, and an ownership interest in
EAPRC. In the third quarter of 1999, the Company repurchased a 35 percent
interest in each of Sonat Marketing Company L.P. and Sonat Power Marketing L.P.
from AGL. Other investment activities included expenditures for the acquisitions
of the Rio Negro power plant and EnCap, as well as expenditures for expansion
and construction projects. Internally generated funds, supplemented by other
financing activities, were used to fund the Company's investing activities.
The Company's planned capital and investment expenditures for 2000 of
approximately $2 billion are primarily intended for expansion of international
operations and domestic unregulated operations, pipeline systems and production
activities and other facilities, and computer and communication system
enhancements.
Funding for capital expenditures, acquisitions, and other investing
expenditures is expected to be provided by internally generated funds,
commercial paper issuances, available capacity under existing credit facilities,
and/or the issuance of other long-term debt, trust securities, or equity.
CASH FROM FINANCING ACTIVITIES
Net cash provided by financing activities was $2.2 billion for the year
ended December 31, 1999. Long-term debt borrowings, proceeds from the issuance
of a preferred interest in Trinity River Associates L.L.C., and proceeds from
the issuance of long-term notes payable, supplemented by internally generated
funds, were used to fund capital and equity investments, reduce short-term and
long-term borrowings, pay dividends, and for other corporate purposes.
Future funding for long-term debt retirements, dividends, and other
financing expenditures is expected to be provided by internally generated funds,
commercial paper issuances, available capacity under existing credit facilities,
and/or the issuance of other long-term debt, trust securities, or equity. In
addition through Electron, the Company plans to raise up to approximately $1
billion of off balance sheet debt in the first half of 2000 to finance its NUG
activities.
LIQUIDITY
The Company relies on cash generated from internal operations as its
primary source of liquidity, supplemented by its available credit facilities and
commercial paper programs. The availability of borrowings under the Company's
credit agreements is subject to specified conditions, which management believes
the
32
<PAGE> 37
Company currently meets. These conditions include compliance with the financial
covenants and ratios required by such agreements, absence of default under such
agreements, and continued accuracy of the representations and warranties
contained in such agreements (including the absence of any material adverse
changes since the specified dates). For a discussion of the Company's financing
arrangements, see Item 8, Financial Statements and Supplementary Data, Note 9.
COMMITMENTS AND CONTINGENCIES
See Item 8, Financial Statements and Supplementary Data, Note 10, for a
discussion of the Company's Commitments and Contingencies.
At December 31, 1999, the Company had capital and investment commitments of
$497 million which are expected to be funded through internally generated funds
and/or incremental borrowings. The Company's other planned capital and
investment projects are discretionary in nature, with no substantial capital
commitments made in advance of the actual expenditures.
OTHER
In February 2000, EPNG entered into an agreement to purchase a portion of
the All American Pipeline, a crude oil transportation system, for $129 million.
EPNG will purchase a 1,088 mile portion of the pipeline that runs from McCamey,
Texas to Emidio Station near Bakersfield, California. The acquisition is subject
to Federal Trade Commission approval. EPNG plans to convert the oil pipeline to
a natural gas pipeline at an estimated cost of $75 million pending FERC
approval.
In February 2000, the Company agreed to purchase two 67 megawatt natural
gas-fired electric generation plants located in Dartmouth, Massachusetts and
Pawtucket, Rhode Island. The acquisition of the Pawtucket plant closed in
February 2000 while the Dartmouth plant acquisition is expected to close in
March 2000. As part of the purchase agreement, the Company assumed
responsibility for all operations and maintenance activities of these plants.
In February 2000, Merchant Energy purchased partnership interests in a
portfolio of eleven gas-fired combined cycle power generation facilities in
California from Dynegy. The portfolio represents a net combined electric
generating capacity of approximately 370 megawatts. Also included in the
acquisition is an operating company and a turbine maintenance organization.
Eight of the eleven acquired facilities have entered into fuel management
agreements to purchase all natural gas and fuel oil used to operate the
facilities at market rates plus a management fee from Merchant Energy. Currently
ten of the eleven facilities sell power to three large public utilities pursuant
to long-term power contracts.
In January 2000, the Company acquired Bonneville for approximately $63
million, net of cash acquired. Bonneville owns a 50 percent interest in an 85
megawatt natural gas-fired cogeneration facility located in the Las Vegas area
which sells power to a large utility under a long-term contract. Bonneville also
provides operations and maintenance services under long-term contracts to two
cogeneration facilities in the Las Vegas area.
In January 2000, the Company completed its acquisition of Crystal Gas
Storage, Inc. for approximately $220 million. The transaction will be accounted
for as a purchase. Crystal Gas Storage owns and operates two natural gas storage
facilities near Hattiesburg, Mississippi, and holds interests in natural gas
producing properties in northern Louisiana and southern Arkansas.
In January 2000, the Company signed a power purchase agreement and
engineering procurement contract for a 40 percent interest in a $60 million
power plant located in the city of Porto Velho in Western Brazil. The 64
megawatt diesel-engine power plant will be fully commercial by July 2000. The
plant will sell all of its power under a ten year power purchase agreement to
Eletronorte, the local electric company.
In December 1999, the Company filed an application with FERC for the
Stagecoach Expansion Project. The project will connect the Stagecoach Storage
Field in Tioga County, New York to TGP's mainline. The new lateral will consist
of 24 miles of pipe and will have a capacity of 500,000 Dth/d. In addition, the
project
33
<PAGE> 38
will expand TGP's 300 line to provide 90,000 Dth/d of firm transportation
service from Bradford County, Pennsylvania to its interconnect with New Jersey
Natural Gas. The total cost for the project is estimated at $87 million with
service on the lateral scheduled to begin in August, 2001 and service on TGP's
300 line in November, 2001.
The Company is pursuing a telecommunications strategy that will leverage
its extensive North American natural gas pipeline system, its core competency in
right-of-way development and, to the extent that bandwidth associated with fiber
optic capacity becomes actively traded, its marketing and trading skills in
newly developed commodity products. The Company, with partners or by itself, is
currently planning to install a fiber optic network and along certain key
segments of its pipeline system and may expand this network beyond its pipeline
system through fiber capacity swaps with or leases from other third party fiber
optic companies.
Year 2000
To coordinate the phases of the Company's Year 2000 project, the Company
established an executive steering committee and a project team. The phases of
the project were: (i) awareness; (ii) assessment; (iii) remediation; (iv)
testing; (v) implementation of the necessary modifications, and (vi) contingency
planning. The goal of the Year 2000 project was to ensure that all of the
critical systems and processes under the Company's direct control remained
functional. As of December 31, 1999, the Company had substantially completed the
above phases for all critical domestic and international systems. While the Year
2000 rollover date has passed with no apparent disruptions experienced by the
Company's systems and processes, it remains possible that third parties may have
experienced disruptions which have not yet manifested any impact on the Company,
but could in the future. Accordingly, the Company is prepared to implement any
contingency plans should a disruption occur.
While the total cost of the Company's Year 2000 project continues to be
accumulated, the Company does not expect to incur any remaining material costs
in 2000. As of December 31, 1999, the Company has incurred expenses of
approximately $21 million and has capitalized costs of approximately $11
million, including costs accumulated by Sonat prior to its merger with the
Company. Sonat's Year 2000 costs include direct cost of its salaried employees,
including costs of benefits. The Company has only traced incremental expenses
related to its Year 2000 project. This means that the costs of the Year 2000
project related to salaried employees of the Company, including their direct
salaries and benefits, have not been included in the estimated costs of the
project.
The above disclosure is a "YEAR 2000 READINESS DISCLOSURE." To the extent
that any reader of the above Year 2000 Readiness Disclosure is other than an
investor or potential investor in the Company's -- or an affiliate's -- equity
or debt securities, this disclosure is made for the SOLE PURPOSE of
communicating or disclosing information aimed at correcting, helping to correct
and/or avoiding Year 2000 failures.
Other than the items discussed above, management is not aware of other
commitments or contingent liabilities which would have a materially adverse
effect on the Company's financial condition, results of operations, or cash
flows.
NEW ACCOUNTING PRONOUNCEMENTS NOT YET ADOPTED
See Item 8, Financial Statements and Supplementary Data, Note 1, for a
discussion relating to new accounting pronouncements not yet adopted.
34
<PAGE> 39
RISK FACTORS AND CAUTIONARY STATEMENT FOR PURPOSES OF THE "SAFE HARBOR"
PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995
This report contains or incorporates by reference forward-looking
statements within the meaning of the Private Securities Litigation Reform Act of
1995. Where any forward-looking statement includes a statement of the
assumptions or bases underlying the forward-looking statement, we caution that,
while we believe these assumptions or bases to be reasonable and to be made in
good faith, assumed facts or bases almost always vary from the actual results,
and differences between assumed facts or bases and actual results can be
material, depending upon the circumstances. Where, in any forward-looking
statement, we or our management express an expectation or belief as to future
results, that expectation or belief is expressed in good faith and is believed
to have a reasonable basis. We cannot assure you, however, that the statement of
expectation or belief will result or be achieved or accomplished. The words
"believe," "expect," "estimate," "anticipate" and similar expressions will
generally identify forward-looking statements.
With this in mind, you should consider the following important factors that
could cause actual results to differ materially from those expressed in any
forward-looking statement made by us or on our behalf:
OUR INDUSTRY IS HIGHLY COMPETITIVE
The hydrocarbons that we transport, gather, process and store are, in many
cases, owned by third parties. As a result, the volume of hydrocarbons involved
in these activities depends on the actions of those third parties, and are
beyond our control. Further, the following factors, most of which are beyond our
control, impact our ability to maintain or increase current transmission,
storage, gathering, processing, and sales volumes and rates, renegotiate
existing contracts as they expire or to remarket unsubscribed capacity at levels
and rates currently in place:
- future weather conditions, including those that favor hydroelectric
generation or other alternative energy sources;
- price competition;
- drilling activity and supply availability;
- expiration of significant contracts; and
- service area competition, especially due to current excess pipeline
capacity into California.
Our future profitability may be affected by our ability to compete with
services offered by other energy enterprises which may be larger, offer more
services, and possess greater resources.
The ongoing profitability of our interstate pipeline systems depends upon
having in place long-term firm transportation contracts for a major portion of
their capacity. Contracts representing 20 percent of TGP's firm transportation
will expire by November 2000, contracts representing 43 percent of SNG's firm
transportation will expire primarily in 2003, and EPNG continues to remarket a
portion of its capacity on a shorter-term contractual basis. Our ability to
negotiate new contracts and to renegotiate existing contracts could be harmed by
factors we cannot control, including:
- the proposed construction by other companies of additional pipeline
capacity in markets served by the Company's interstate pipelines;
- reduced demand due to higher gas prices;
- actions by regulators that may impact the competitiveness of short-term
and long-term capacity markets;
- the availability of alternative energy sources; and
- the viability of our expansion projects.
35
<PAGE> 40
For a further discussion see Item 1, Business, Natural Gas Transmission,
Markets and Competition.
FLUCTUATIONS IN ENERGY COMMODITY PRICES COULD ADVERSELY AFFECT OUR BUSINESS
Natural gas prices in the supply basins connected to our pipeline systems
as compared to prices in other gas producing regions, especially Canada, impact
our ability to compete with other transporters. Revenues generated by our
gathering and processing contracts depend on volumes and rates, both of which
can be affected by the prices of natural gas and natural gas liquids. The
success of our expanding gathering and processing operations in the offshore
Gulf of Mexico is subject to continued development of additional oil and gas
reserves in the vicinity of our facilities and our ability to access such
additional reserves to offset the natural decline from existing wells connected
to our systems. A decline in energy prices could precipitate a decrease in these
development activities and could cause a decrease in the volume of reserves
available for gathering and processing through our offshore facilities.
Fluctuations in energy prices, which may impact gathering rates and investments
by third parties in the development of new oil and gas reserves connected to our
gathering and processing facilities, are caused by a number of factors,
including:
- regional, domestic and international supply and demand;
- availability and adequacy of transportation facilities;
- energy legislation;
- federal or state taxes, if any, on the sale or transportation of natural
gas and natural gas liquids; and
- abundance of supplies of alternative energy sources.
If there are reductions in the average volume of the natural gas we
transport, gather and process for a prolonged period, our results of operations
and financial position could be significantly, negatively affected.
FLUCTUATIONS IN EXPLORATION AND PRODUCTION ACTIVITIES COULD HARM OUR BUSINESS
Our success in the exploration and production activities could be adversely
affected by factors we can not control, including:
- fluctuations in price of crude oil and natural gas;
- the timing and success of our exploration and development drilling
programs, which would affect production levels and reserves;
- risks incident to the drilling and operation of oil and gas wells; and
- future drilling, production and development costs, including drilling rig
rates.
THE SUCCESS OF OUR POWER GENERATION AND MARKETING ACTIVITIES DEPENDS ON MANY
FACTORS, SOME OF WHICH MAY BE BEYOND OUR CONTROL
The success of our international and domestic power projects and power
marketing activities could be adversely affected by factors beyond our control,
including:
- alternative sources and supplies of energy becoming available due to new
technologies and interest in self generation and cogeneration;
- uncertain regulatory conditions resulting from the ongoing deregulation
of the electric industry in the United States and in foreign
jurisdictions;
- our ability to negotiate successfully and enter into, restructure or
recontract advantageous long-term power purchase agreements; and
- the possibility of a reduction in the projected rate of growth in
electricity usage as a result of factors such as regional economic
conditions and the implementation of conservation programs.
36
<PAGE> 41
OUR TELECOMMUNICATIONS BUSINESS STRATEGY MAY NOT BE SUCCESSFUL
Our experience in the telecommunications industry is limited, and we cannot
assure you that our strategic communications objectives, such as marketing
telecommunications capacity on our proposed fiber-optic network, will be
successful. Our success depends in part on our ability to integrate and adapt
our facilities and services to keep pace with advances in communications
technologies and the new and improved devices and services that result from
these changes. In addition, the market for fiber-optic capacity and
telecommunications services is rapidly evolving, and although we expect demand
for these services to grow, we cannot assure you that this growth will occur.
Additionally, the price of fiber optic capacity is expected to continue to
decline sharply because of the increase in newly-installed fiber optic capacity
coming on the market and rapid fiber optic equipment technology improvements.
Further, certain critical issues, including security, reliability, ease and cost
of access, uncertain governmental regulation, and quality of service remain
unresolved and may adversely affect our business. We cannot assure you,
therefore, that our telecommunications strategy will be successful.
WE MAY HAVE DIFFICULTY INTEGRATING OPERATIONS AFTER THE SONAT MERGER
There are risks inherent in the integration process relating to our merger
with Sonat, including:
- the risk that Sonat's business may not be successfully integrated with El
Paso Energy's businesses;
- the risk that we may not fully realize the benefits we expected to result
from the merger with Sonat; and
- the impact of the loss of key employees.
If we are unsuccessful at integrating our operations, our business and
financial position could be adversely affected.
THE USE OF DERIVATIVE FINANCIAL INSTRUMENTS COULD RESULT IN FINANCIAL LOSSES
Some of our non-regulated subsidiaries use futures and option contracts
traded on the New York Mercantile Exchange, over-the-counter options and price
and basis swaps with other gas merchants and financial institutions. These
instruments are intended to reduce our exposure to short-term volatility in
changes in energy commodity prices. We could, however, incur financial losses in
the future as a result of volatility in the market values of the underlying
commodities or if one of our counterparties fails to perform under a contract.
Furthermore, because the valuation of these financial instruments can involve
estimates, changes in the assumptions underlying these estimates can occur,
changing our valuation and potentially resulting in financial losses. For
additional information concerning our derivative financial instruments, see item
7A, Quantitative and Qualitative Disclosures About Market Risks and Item 8,
Financial Statements and Supplementary Data, Note 7.
ATTRACTIVE ACQUISITION AND INVESTMENT OPPORTUNITIES MAY NOT BE AVAILABLE
Our ability to grow will depend, in part, upon our ability to identify and
complete attractive acquisition and investment opportunities. Opportunities for
growth through acquisitions and investments in joint ventures, and the future
operating results and success of these acquisitions and joint ventures within
and outside the United States may be subject to the effects of, and changes in
the following:
- United States and foreign trade and monetary policies;
- laws and regulations;
- political and economic developments;
- inflation rates;
- taxes; and
- operating conditions.
37
<PAGE> 42
OUR FOREIGN INVESTMENTS INVOLVE SPECIAL RISKS
Our activities in areas outside the U.S. are subject to the risks inherent
in foreign operations, including:
- loss of revenue, property and equipment as a result of hazards (such as
expropriation, nationalization, wars, insurrection and other political
risk), and
- the effects of currency fluctuations and exchange controls (such as
devaluations of the Indonesian and Brazilian currencies and other
economic problems).
These legal and regulatory events and other unforeseeable obstacles may be
beyond our control or ability to manage.
WE COULD INCUR SUBSTANTIAL ENVIRONMENTAL LIABILITIES
We may incur significant costs and liabilities in order to comply with
existing and future environmental laws and regulations. It is also possible that
other developments, such as increasingly strict environmental laws, regulations
and enforcement policies thereunder, and claims for damages to property,
employees, other persons and the environment resulting from current or
discontinued operations, could result in substantial costs and liabilities in
the future. For additional information concerning our environmental matters, see
Item 8, Financial Statements and Supplementary Data, Note 10.
OUR ACTIVITIES INVOLVE OPERATING HAZARDS AND UNINSURED RISKS
While we maintain insurance against certain of the risks normally
associated with the transportation, exploration and production, storage, and
gathering and processing of natural gas, including, but not limited to
explosions, pollution and fires, the occurrence of a significant event against
which we are not fully insured could have a significant negative effect on our
business.
THERE REMAIN POTENTIAL LIABILITIES RELATED TO THE ACQUISITION OF EPTPC
The amount of the actual and contingent liabilities assumed by the Company
in its merger with EPTPC could vary substantially from the amount we estimated,
which was based upon assumptions which could prove to be inaccurate. If new
Tenneco Inc. or Newport News Shipbuilding Inc. (organizations created and
distributed to Tenneco Inc. shareholders prior to the acquisition of Tenneco
Inc. by the Company in December 1996) were unable or unwilling to pay their
respective liabilities, a court could require us, under certain legal theories
which may or may not be applicable to the situation, to assume responsibility
for those obligations. If we were required to assume these obligations, it could
have a material adverse effect on our financial condition, results of operations
or cash flows.
THERE REMAIN POTENTIAL FEDERAL INCOME TAX LIABILITIES RELATED TO THE ACQUISITION
OF EPTPC
In connection with the acquisition of EPTPC and the distributions made by
EPTPC prior to its acquisition, the IRS issued a private letter ruling to old
Tenneco Inc. (Tenneco Inc., prior to its acquisition by the Company), in which
it ruled that for United States federal income tax purposes the distributions
would be tax-free to old Tenneco Inc. and, except to the extent cash was
received in lieu of fractional shares, to its then existing stockholders; the
merger would constitute a tax-free reorganization; and that certain other
transactions effected in connection with the merger and distribution would be
tax-free. If the distributions were not to qualify as tax-free, then a corporate
level federal income tax would be assessed to the consolidated group of which
old Tenneco Inc. was the common parent. This corporate level federal income tax
would be payable by EPTPC. Under certain limited circumstances, however, new
Tenneco Inc. and Newport News Shipbuilding Inc. have agreed to indemnify EPTPC
for a defined portion of such tax liabilities.
38
<PAGE> 43
WE ARE SUBJECT TO FINANCING AND INTEREST RATE EXPOSURE RISKS
Our business and operating results can be harmed by factors such as the
availability or cost of capital, changes in interest rates, changes in the tax
rates due to new tax laws, changes in the structured finance market, market
perceptions of the natural gas and energy industry or El Paso, or credit
ratings.
39
<PAGE> 44
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The Company utilizes derivative financial instruments to manage market
risks associated with certain energy commodities and interest and foreign
currency exchange rates. The Company's primary market risk exposure is to
changing energy commodity prices. Market risks are monitored by a corporate risk
management committee that operates independently from the business segments that
create or actively manage these risk exposures to ensure compliance with the
Company's stated risk management policies as approved by the Board.
TRADING COMMODITY PRICE RISK
Merchant Energy is exposed to certain market risks inherent in the
financial instruments used for trading energy and energy related commodities.
Merchant Energy marks to market its energy trading activities, including
transportation capacity and storage. 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 differential between fixed and variable prices for the commodity,
exchange-traded options, over-the-counter options and other contractual
arrangements. Merchant Energy manages its market risk on a portfolio basis,
subject to parameters established by the risk management committee.
Comprehensive risk management processes, policies, and procedures have been
established to monitor and control its market risk. The Company's risk
management committee also continually reviews these policies to ensure they are
responsive to changing business conditions.
Merchant Energy measures the risk in its commodity and energy related
contract portfolio on a daily basis utilizing a Value-at-Risk ("VAR") model to
determine the maximum potential one-day unfavorable impact on its earnings from
its existing portfolio, due to normal market movements, and monitors its risk in
comparison to established thresholds. The VAR computations are based on
historical simulation of delta/gamma positions, which capture a significant
portion of the exposure related to option positions, and utilize price movements
over a specified period to simulate forward price curves in the energy markets
using several key assumptions, including the selection of a confidence level for
expected losses and the holding period for liquidation. Merchant Energy also
utilizes other measures outside the VAR methodology to monitor the risk in its
portfolio on a monthly basis, including stress testing, position limit control
and credit, liquidity and event risk management.
Assuming 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 VAR, related to
contracts held for trading purposes was approximately $3 million, $3 million and
$1 million at December 31, 1999, 1998, and 1997 respectively. In 1999, Merchant
Energy's highest, lowest and average estimated potential one day unfavorable
impact on income before taxes and minority interest, as measured by VAR were $3
million, $1 million and $2 million, respectively. The average value represents a
twelve month average of the 1999 month end values. The high and low valuations
represent the highest and lowest month end values during 1999. VAR was
implemented on April 1, 1998. Therefore, volatilities and correlations
applicable on April 1, 1998, were used to provide comparative data for December
31, 1997. Actual losses could exceed those measured by VAR.
NON-TRADING COMMODITY PRICE RISK
The Company mitigates market risk associated with significant physical
transactions, including crude oil and natural gas liquids production and
delivery through the use of non-trading financial instruments, including forward
contracts and swaps. In addition, Merchant Energy functions as an agent for
Production and Field Services hedging a portion of their commodity risk by
entering into derivative financial instruments with third parties.
40
<PAGE> 45
The estimated potential one-day unfavorable impact on income before income
taxes and minority interest, as measured by VAR, related to Merchant Energy's
non-trading commodity activities was insignificant at December 31, 1999, 1998,
and 1997.
INTEREST RATE RISK
The Company's debt financial instruments and certain project arrangements
are sensitive to market fluctuations in interest rates. The Company attempts to
mitigate exposure to these risks through the use of non-trading derivative
financial instruments, including interest rate and equity swaps. In August 1999,
El Paso entered an interest rate swap agreement with a notional amount of $600
million and a termination date of July 2001. El Paso swapped the fixed interest
rate on its July 1999, $600 million aggregate principal Senior Notes due 2001
for a floating 3 month LIBOR plus a rate margin of 14.75 basis points. This
transaction has been recorded using accrual accounting. At December 31, 1998,
the Company maintained an interest rate swap on debt held by MPC. In October
1999, that swap was terminated at a cost of approximately $5 million. In March
1997, the Company purchased a 10.5 percent interest in CAPSA for approximately
$57 million. In connection with its acquisition, the Company entered into an
equity swap associated with an additional 18.5 percent of CAPSA's then
outstanding stock. Under the equity swap, the Company pays interest to a
counterparty, on a quarterly basis, on a notional amount of $100 million at a
rate of LIBOR plus 0.85 basis points. In exchange, the Company receives
dividends, if any, on the CAPSA stock to the extent of the counterparty's equity
interest of 18.5 percent. The Company also fully participates in the market
appreciation or depreciation of the underlying investment whereby the Company
will realize appreciation or fund any depreciation attributable to the actual
sale of the stock upon termination or expiration of the swap transaction. In
February 1999, the Company extended the term of the swap for two and a half
years with a notional amount of $103 million and an interest rate of LIBOR plus
1.75 basis points.
The table below presents principal cash flows and related weighted average
interest rates by expected maturity dates. As of December 31, 1999, 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.
41
<PAGE> 46
For the interest rate and equity swaps, notional amounts and weighted
average interest rates are presented by expected or contractual maturity dates.
Notional amounts are used to calculate the contractual payments to be exchanged
under the contact. The fair value of the derivative financial instruments is the
estimated amount at which management believes they could be liquidated over a
reasonable period of time, based on quoted market prices, current market
conditions, or other estimates obtained from third-party dealers.
<TABLE>
<CAPTION>
DECEMBER 31, 1999 DECEMBER 31, 1998
-------------------------------------------------------------------------- ---------------------
EXPECTED FISCAL YEAR OF MATURITY
-------------------------------------------------------------------------- CARRYING
2000 2001 2002 2003 2004 THEREAFTER TOTAL FAIR VALUE AMOUNTS FAIR VALUE
------ ----- ----- ---- ---- ---------- ------ ------------- -------- ----------
(DOLLARS IN MILLIONS)
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
LIABILITIES:
Short-term debt -- variable
rate....................... $1,252 $1,252 $1,252 $1,471 $1,471
Average interest
rate................. 6.3%
Long-term debt, including
current portion -- fixed
rate................... $ 92 $ 938 $ 427 $200 $ -- $3,696 $5,353 $5,204 $3,871 $4,103
Average interest
rate................. 7.6% 7.3% 7.9% 8.0% -- 7.5%
Company-obligated
mandatorily redeemable
convertible preferred
securities of El Paso
Energy Capital Trust I... $ 325 $ 325 $ 327 $ 325 $ 311
Average interest
rate................. 4.8%
INTEREST RATE DERIVATIVES:
Interest rate swap
-----------------
Fixed to variable
rate -- notional
amounts................ $ 600 $ 600 $ 4 $ -- $ (9)
Average interest
rate(a)(c)........... 6.5% 7.0%
Average received
rate................. 6.6% 6.6%
Net cash flow
effect(c)............ $ (2.8) $ 7.8
Equity swap
------------
Interest to
dividend -- notional
amount................. $ 103 $ 103 $ 10 $ 3 $ 3
Average interest
rate(a).............. 8.2% 8.6%
Received dollars(b).... -- --
Net cash flow
effect(d)............ $ (8) (9)
</TABLE>
- ---------------
(a)The variable rates presented are the average forward rates for the remaining
term of each contract.
(b)The Company receives dividends, to the extent paid, on the CAPSA stock to the
extent of the counterparty's equity interest of 18.5 percent. No dividends
were received in 1998 or 1999 and no dividends are expected for 2000 or 2001.
(c)The difference between cash flow based on average interest rates and the
annual cash flow shown above is the result of timing differences between the
receipt and payment of interest.
(d)The Company will realize appreciation or fund any depreciation attributable
to the actual sale of the CAPSA stock upon termination of the swap
transaction in August 2001.
42
<PAGE> 47
FOREIGN CURRENCY EXCHANGE RATE RISK
The Company uses derivative financial instruments, principally foreign
currency forward purchase and sale contracts having various terms, to manage its
exposures to changes in foreign currency exchange rates. The Company's primary
exposure relates to changes in foreign currency rates on certain of its merchant
activities outside the United States. The following table summarizes, by major
currency, the notional amounts, average settlement rates, and fair value for
foreign currency forward purchase and sale contracts as of December 31, 1999:
<TABLE>
<CAPTION>
NOTIONAL AMOUNT FAIR VALUE
IN FOREIGN AVERAGE IN
CURRENCY SETTLEMENT U.S. DOLLARS
(IN MILLIONS) RATES (IN MILLIONS)
--------------- ---------- -------------
<S> <C> <C> <C> <C>
Canadian Dollars Purchase................................ 296 .668 $ 5
Sell.................................... 194 .684 (1)
British Pounds Purchase................................ -- -- --
Sell.................................... 28 1.666 --
---
$ 4
===
</TABLE>
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, 1999:
<TABLE>
<CAPTION>
EXPECTED MATURITY DATES
----------------------------------------------
2000 2001 2002 2003 2004 THEREAFTER TOTAL
----- ---- ---- ---- ---- ---------- -----
(IN MILLIONS)
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Canadian Dollars Purchase.................... $ 132 $ 13 $ 12 $ 12 $ 6 $ 23 $198
Sell........................ 29 28 27 27 22 -- 133
----- ---- ---- ---- ---- ---- ----
Net cash flow effect........ $(103) $ 15 $ 15 $ 15 $ 16 $(23) $(65)
===== ==== ==== ==== ==== ==== ====
British Pounds Purchase.................... $ -- $ -- $ -- $ -- $ -- $ -- $ --
Sell........................ -- 2 4 4 5 32 47
----- ---- ---- ---- ---- ---- ----
Net cash flow effect........ $ -- $ 2 $ 4 $ 4 $ 5 $ 32 $ 47
===== ==== ==== ==== ==== ==== ====
</TABLE>
43
<PAGE> 48
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
EL PASO ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF INCOME
(IN MILLIONS, EXCEPT PER COMMON SHARE AMOUNTS)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
----------------------------
1999 1998 1997
------- ------ -------
<S> <C> <C> <C>
Operating revenues
Transportation............................................ $ 1,536 $1,502 $ 1,567
Energy commodities........................................ 8,551 7,740 8,138
Gathering and processing.................................. 324 141 204
Other..................................................... 170 117 106
------- ------ -------
10,581 9,500 10,015
------- ------ -------
Operating expenses
Cost of gas and other products............................ 7,974 6,970 7,308
Operation and maintenance................................. 979 956 966
Merger-related and asset impairment charges............... 557 15 50
Ceiling test charges...................................... 352 1,035 --
Depreciation, depletion, and amortization................. 609 624 639
Taxes, other than income taxes............................ 146 138 138
------- ------ -------
10,617 9,738 9,101
------- ------ -------
Operating income(loss)...................................... (36) (238) 914
------- ------ -------
Other income
Equity investment earnings................................ 95 84 53
Interest income........................................... 48 22 18
Net gain on sale of assets................................ 27 36 5
Other, net................................................ 57 44 18
------- ------ -------
227 186 94
------- ------ -------
Income (loss) before interest, income taxes, and other
charges................................................... 191 (52) 1,008
------- ------ -------
Interest and debt expense................................... 453 387 344
Minority interest........................................... 36 12 --
Income tax expense (benefit)................................ (81) (170) 234
------- ------ -------
408 229 578
------- ------ -------
Income (loss) before preferred dividends of subsidiary and
cumulative effect of accounting change.................... (217) (281) 430
Preferred stock dividends of subsidiary..................... 25 25 25
------- ------ -------
Income (loss) before cumulative effect of accounting
change.................................................... (242) (306) 405
Cumulative effect of accounting change, net of income
taxes..................................................... (13) -- --
------- ------ -------
Net income (loss)........................................... $ (255) $ (306) $ 405
======= ====== =======
Basic earnings (loss) per common share
Income (loss) before cumulative effect of accounting
change................................................. $ (1.06) $(1.35) $ 1.81
Cumulative effect of accounting change, net of income
taxes.................................................. (0.06) -- --
------- ------ -------
Net income (loss)......................................... $ (1.12) $(1.35) $ 1.81
======= ====== =======
Diluted earnings (loss) per common share
Income (loss) before cumulative effect of accounting
change................................................. $ (1.06) $(1.35) $ 1.77
Cumulative effect of accounting change, net of income
taxes.................................................. (0.06) -- --
------- ------ -------
Net income (loss)......................................... $ (1.12) $(1.35) $ 1.77
======= ====== =======
Basic average common shares outstanding..................... 228 226 224
======= ====== =======
Diluted average common shares outstanding................... 228 226 229
======= ====== =======
</TABLE>
The accompanying Notes are an integral part of these Consolidated Financial
Statements.
44
<PAGE> 49
EL PASO ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS
(IN MILLIONS, EXCEPT COMMON SHARE AMOUNTS)
<TABLE>
<CAPTION>
DECEMBER 31,
-----------------
1999 1998
------- -------
<S> <C> <C>
ASSETS
Current assets
Cash and cash equivalents................................. $ 545 $ 104
Accounts and notes receivable, net
Customer............................................... 1,006 872
Receivables from affiliates............................ 367 134
Other.................................................. 289 183
Materials and supplies.................................... 74 84
Deferred income taxes..................................... 126 81
Assets from price risk management activities.............. 233 444
Other..................................................... 271 146
------- -------
Total current assets.............................. 2,911 2,048
Property, plant, and equipment, net......................... 10,261 10,086
Investments in unconsolidated affiliates.................... 2,029 1,104
Intangibles, net............................................ 543 538
Other....................................................... 913 667
------- -------
Total assets...................................... $16,657 $14,443
======= =======
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities
Accounts and notes payable
Trade.................................................. $ 961 $ 800
Notes payable to affiliates............................ 121 --
Other.................................................. 576 358
Short-term borrowings (including current maturities of
long-term debt)........................................ 1,344 1,650
Liabilities from price risk management activities......... 197 355
Other..................................................... 503 550
------- -------
Total current liabilities......................... 3,702 3,713
------- -------
Long-term debt, less current maturities..................... 5,223 3,692
------- -------
Deferred income taxes....................................... 1,738 1,728
------- -------
Other....................................................... 1,354 1,174
------- -------
Commitments and contingencies (See Note 10)
Company-obligated mandatorily redeemable convertible
preferred securities of El Paso Energy Capital Trust I.... 325 325
------- -------
Minority interest........................................... 1,368 374
------- -------
Stockholders' equity
Common stock, par value $3 per share; authorized
750,000,000 shares; issued 238,544,250 and 235,821,630
shares, respectively................................... 716 707
Additional paid-in capital................................ 1,367 1,288
Retained earnings......................................... 1,207 1,669
Accumulated other comprehensive income.................... (29) (12)
Treasury stock (at cost) 8,947,565 and 5,494,772 shares,
respectively........................................... (273) (150)
Deferred compensation..................................... (41) (65)
------- -------
Total stockholders' equity........................ 2,947 3,437
------- -------
Total liabilities and stockholders' equity........ $16,657 $14,443
======= =======
</TABLE>
The accompanying Notes are an integral part of these Consolidated Financial
Statements.
45
<PAGE> 50
EL PASO ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN MILLIONS)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-----------------------------
1999 1998 1997
------- ------- -------
<S> <C> <C> <C>
Cash flows from operating activities
Net income (loss)......................................... $ (255) $ (306) $ 405
Adjustments to reconcile net income (loss) to net cash
from operating activities
Depreciation, depletion, and amortization.............. 609 624 639
Deferred income taxes (benefit)........................ (44) (194) 280
Gain on sale of assets................................. (27) (36) (5)
Undistributed earnings in equity investees............. (52) (60) (34)
Amortization of deferred compensation.................. 9 27 19
Risk-sharing revenue................................... (31) (31) --
Non-cash portion of merger-related and asset impairment
charges.............................................. 380 -- --
Cumulative effect of accounting changes, net of income
tax.................................................. 13 -- --
Ceiling test charges................................... 352 1,035 --
Working capital changes, net of non-cash transactions
Accounts and notes receivable........................ (271) 481 334
Materials and supplies............................... 4 15 (18)
Net price risk management activities................. (204) (40) 5
Regulatory assets.................................... -- 124 19
Other current assets................................. (34) 15 43
Accrual for regulatory issues........................ (27) 16 (266)
Accounts and notes payable........................... 132 (391) (169)
Other current liabilities............................ (40) (158) 14
Other................................................ -- 42 (59)
Other.................................................. (13) (130) 4
------- ------- -------
Net cash provided by operating activities......... 501 1,033 1,211
------- ------- -------
Cash flows from investing activities
Capital expenditures...................................... (1,086) (1,137) (1,294)
Investment in joint ventures and equity investees......... (1,081) (689) (307)
Cash paid for acquisitions, net of cash received.......... (165) (373) (213)
Proceeds from sales of assets............................. 57 399 63
Return of investment in joint ventures and equity
investees.............................................. 88 153 53
Cash deposited in escrow related to equity investee....... (101) -- --
Other..................................................... (13) -- (28)
------- ------- -------
Net cash used in investing activities............. (2,301) (1,647) (1,726)
------- ------- -------
Cash flows from financing activities
Net commercial paper borrowings........................... 180 264 636
Revolving credit borrowings............................... 878 810 1,800
Revolving credit repayments............................... (1,253) (1,017) (2,955)
Long-term debt retirements................................ (343) (289) (188)
Net proceeds from issuance of long-term debt.............. 1,781 691 1,178
Net proceeds from issuance of preferred securities of El
Paso Energy Capital Trust I............................ -- 317 --
Acquisition of treasury stock............................. -- (37) (53)
Dividends paid on common stock............................ (184) (209) (170)
Net proceeds from issuance of common stock................ 5 -- 152
Net proceeds from issuance of notes payable............... 222 -- --
Net proceeds from issuance of interest in Trinity River
Associates, L.L.C...................................... 960 -- --
Other..................................................... (5) 43 9
------- ------- -------
Net cash provided by financing activities......... 2,241 573 409
------- ------- -------
Increase (decrease) in cash and cash equivalents............ 441 (41) (106)
Cash and cash equivalents
Beginning of period....................................... 104 145 251
------- ------- -------
End of period............................................. $ 545 $ 104 $ 145
======= ======= =======
</TABLE>
The accompanying Notes are an integral part of these Consolidated Financial
Statements.
46
<PAGE> 51
EL PASO ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
(IN MILLIONS, EXCEPT PER COMMON SHARE AMOUNTS)
<TABLE>
<CAPTION>
FOR THE YEARS ENDED DECEMBER 31,
---------------------------------------------------
1999 1998 1997
--------------- --------------- ---------------
SHARES AMOUNT SHARES AMOUNT SHARES AMOUNT
------ ------ ------ ------ ------ ------
<S> <C> <C> <C> <C> <C> <C>
COMMON STOCK, $3.00 PAR:
Balance at beginning of year............... 236 $ 707 234 $ 702 225 $ 675
Issuance of common stock, net of related
costs................................... 1 3 -- 1 7 20
Restricted stock activity, net............. 1 3 1 1 -- 2
Options exercised.......................... 2 6 1 3 2 5
Retirement of Sonat treasury shares........ (1) (3)
--- ------ --- ------ --- ------
Balance at end of year.................. 239 716 236 707 234 702
--- ------ --- ------ --- ------
ADDITIONAL PAID-IN CAPITAL:
Balance at beginning of year............... 1,288 1,229 1,021
Issuance of common stock, net of related
costs................................... 30 8 155
Restricted stock activity, net............. 45 16 22
Options exercised.......................... 45 14 16
Tax benefit of equity plans................ 13 10 15
Tax benefit of NOL carryforward............ 11
Early vesting of equity plans.............. 7
Retirement of Sonat treasury shares........ (61)
--- ------ --- ------ --- ------
Balance at end of year.................. 1,367 1,288 1,229
--- ------ --- ------ --- ------
RETAINED EARNINGS:
Balance at beginning of year............... 1,669 2,186 1,961
Net income (loss).......................... (255) (306) 405
Dividends ($0.800, $0.765, and $0.730 per
share).................................. (207) (211) (180)
--- ------ --- ------ --- ------
Balance at end of year.................. 1,207 1,669 2,186
--- ------ --- ------ --- ------
ACCUMULATED OTHER COMPREHENSIVE INCOME:
Balance at beginning of year............... (12) (4) 10
Cumulative translation adjustment.......... (12) (7) (7)
Realized gain on securities (net of tax
benefit of $--, $0.7, and $1.2)......... -- (1) (2)
Net change in unrealized (loss) on
securities (net of tax benefit of $2.5,
$0.2, and $2.5)......................... (5) -- (5)
--- ------ --- ------ --- ------
Balance at end of year.................. (29) (12) (4)
--- ------ --- ------ --- ------
TREASURY STOCK, AT COST:
Balance at beginning of year............... (5) (150) (4) (112) (4) (74)
Options exercised.......................... -- 6 -- 4 1 15
Restricted stock activity, net............. -- (22) -- (5) -- --
Stock repurchases.......................... (1) (37) (1) (53)
Early vesting of equity plans.............. (5) (166)
Retirement of Sonat treasury shares........ 1 59
--- ------ --- ------ --- ------
Balance at end of year.................. (9) (273) (5) (150) (4) (112)
--- ------ --- ------ --- ------
DEFERRED COMPENSATION:
Balance at beginning of year............... (65) (81) (79)
Restricted stock activity, net............. (43) 16 (2)
Early vesting of equity plans.............. 67
--- ------ --- ------ --- ------
Balance at end of year.................. (41) (65) (81)
--- ------ --- ------ --- ------
Total stockholders' equity................... 230 $2,947 231 $3,437 230 $3,920
=== ====== === ====== === ======
Comprehensive income (loss).................. $ (272) $ (314) $ 391
====== ====== ======
</TABLE>
The accompanying Notes are an integral part of these Consolidated Financial
Statements.
47
<PAGE> 52
EL PASO ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Basis of Presentation and Principles of Consolidation
The consolidated financial statements of the Company include the accounts
of all majority-owned, controlled subsidiaries after the elimination of all
significant intercompany accounts and transactions. Investments in companies
where the Company has the ability to exert significant influence over, but not
control operating and financial policies are accounted for using the equity
method. The consolidated financial statements for previous periods include
certain reclassifications that were made to conform to the current year
presentation. Such reclassifications have no impact on reported net income or
stockholders' equity.
Holding Company Reorganization
Effective August 1, 1998, the Company reorganized into a holding company
organizational structure, whereby El Paso became the holding company. In the
transaction, El Paso Energy Merger Company, a wholly owned subsidiary of El
Paso, merged with and into EPNG, with EPNG as the surviving corporation. By
virtue of the reorganization, EPNG became a direct, wholly owned subsidiary of
El Paso, and all of EPNG's outstanding capital stock was converted, on a share
for share basis, into capital stock of El Paso. EPNG's outstanding preferred
stock purchase rights were also exchanged with each one-half outstanding
preferred stock purchase right of EPNG being converted into one preferred stock
purchase right of El Paso common stock, with such right representing the right
to purchase one two-hundredth (subject to adjustment) of a share of Series A
Junior Participating Preferred Stock of El Paso. Because the reorganization was
with companies under common control, the stockholders' equity and components
thereof of EPNG became the basis for El Paso stockholders' equity. El Paso also
assumed ownership of the Trust (as defined in Note 12) and EPNG's obligations
related to the Trust. See Note 12, Trust Preferred Securities for a further
discussion. Finally, El Paso became the successor to EPNG's previous shelf
registration in the amount of $565 million. The New York Stock Exchange ticker
symbol used by El Paso following the reorganization remains unchanged as "EPG."
Tax-free Internal Reorganization
On December 31, 1998 and again following the Company's merger with Sonat,
the Company effected an internal reorganization of its assets and operations and
those of certain of its subsidiaries. In the reorganizations, certain
subsidiaries were transferred to or from El Paso and/or other entities owned by
El Paso. The internal reorganization had no impact on the presentation herein.
Stock Split
On January 21, 1998, the Board approved a two-for-one stock split of EPNG's
common stock (the "Stock Split"). The Stock Split was effected in the form of a
stock dividend of an aggregate of 60,944,417 shares of EPNG's common stock,
which was paid in April 1998. All common shares and per common share amounts
presented herein reflect the Stock Split.
Use of Estimates
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets, liabilities, revenues
and expenses and disclosure of contingent assets and liabilities that exist at
the date of the financial statements. Actual results are likely to differ from
those estimates.
48
<PAGE> 53
Accounting for Regulated Operations
The Company's 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. The Company's businesses that are
subject to the regulations and accounting requirements of FERC have followed the
accounting requirements of SFAS No. 71, Accounting for the Effects of Certain
Types of Regulation, which may differ from the accounting requirements of the
Company's non-regulated entities. Transactions that have been recorded
differently as a result of regulatory accounting requirements include: GSR costs
to be recovered under a demand and interruptible surcharge, environmental costs
to be recovered under a demand surcharge, the capitalization of an equity return
component on regulated capital projects, and certain benefits and other costs
and taxes included in or expected to be included in future rates, including
costs to refinance debt. When the accounting method followed is prescribed by or
allowed by the regulatory authority for rate-making purposes, such method
conforms to the generally accepted accounting principle of matching costs with
the revenues to which they apply.
Changes in the regulatory and economic environment may create, at some
point in the future, circumstances in which the application of regulatory
accounting principles will no longer be appropriate. Factors which could impact
this assessment include an inability to recover cost increases under rate caps
and rate case moratoriums, an inability to recover capitalized costs, including
an adequate return on those costs through the ratemaking process, excess
capacity or significant discounting of rates in the markets served by the
Company, and the impacts of ongoing initiatives in and deregulation of the
natural gas industry. Should these factors cause regulatory accounting
principles to no longer be applied, an amount would be charged to earnings as an
extraordinary item. At December 31, 1999, this amount was estimated to be
approximately $100 million, net of income taxes. Any potential charge would be
non-cash and would have no direct effect on the regulated companies' ability to
seek recovery of the underlying deferred costs in their future rate proceedings
or on their ability to collect the rates set thereby.
Cash and Cash Equivalents
Short-term investments purchased with an original maturity of three months
or less are considered cash equivalents.
Allowance for Doubtful Accounts and Notes Receivable
The Company has established a provision for losses on accounts and notes
which may become uncollectible. Collectibility is reviewed regularly, and the
allowance is adjusted as necessary, primarily under the specific identification
method. At December 31, 1999 and 1998, the allowance was $29 million and $23
million, respectively.
Gas Imbalances
The Company values gas imbalances due to or due from shippers and operators
at the appropriate index price. Gas imbalances represent the difference between
gas receipts from and gas deliveries to the Company's transportation and storage
customers. Gas imbalances arise when these customers deliver more or less gas
into the pipeline than they take out. Natural gas imbalances are settled in cash
or made up in-kind subject to the pipelines' various terms.
Materials and Supplies
Materials and supplies are valued at the lower of cost or market with cost
determined using the average cost method.
Property, Plant, and Equipment
The Company's regulated property, plant, and equipment is subject to
oversight by the FERC. The objectives of this regulation are to ensure the
proper recovery of capital investments in rates. Such recovery is
49
<PAGE> 54
generally accomplished by allowing a return of that investment through inclusion
of depreciation expense in the cost of service. Rates also allow for a return on
the net unrecovered rate base. Specific procedures are prescribed by FERC to
control capitalized costs, depreciation, and the disposal of assets. SFAS No. 71
specifically acknowledges the obligation of regulated companies to comply with
regulated accounting procedures, even when they conflict with other generally
accepted accounting principle pronouncements.
Regulated property, plant, and equipment is recorded at original cost of
construction or, on acquisition, the cost to the first party committing the
asset to utility service. Construction cost includes direct labor and materials,
as well as indirect charges, such as overhead and an allowance for both debt and
equity funds used during construction. Replacements or betterments of major
units of property are capitalized, while replacements or additions of minor
units of property are expensed.
Depreciation for regulated property, plant, and equipment is calculated
using the composite method. Assets with similar economic characteristics are
grouped. The depreciation rate prescribed in the rate settlement is applied to
the gross investment for the group until net book value of the group is equal to
the salvage value. Currently, depreciation rates vary from 1 percent to 33
percent. This results in remaining economic lives of groups ranging from 2 to 36
years. Depreciation rates are re-evaluated in conjunction with the rate making
process.
When regulated property, plant, and equipment is retired, due to
abandonment or replacement, the original cost, plus the cost of retirement, less
salvage, is charged to accumulated depreciation and amortization. No gain or
loss is recognized unless an entire operating unit, as defined by FERC, has been
retired. Gains or losses on dispositions of operating units are included in
income.
Additional acquisition cost assigned to utility plant primarily represents
the excess of allocated purchase costs over historical costs of these
facilities. These costs are amortized on a straight-line basis using FERC
approved rates.
The cost of the Company's non-regulated property, plant and equipment is
based on the original cost of construction or, on acquisition, the fair value of
the assets acquired. Construction costs include all direct costs of the project,
as well as indirect charges including capitalized interest costs on debt.
Depreciation on these properties is provided using the straight line or
composite method which, in the opinion of management, is adequate to allocate
the cost of properties over their estimated useful lives. Non-regulated
properties have expected lives of 5 to 40 years. When these properties are
retired due to abandonment or replacement, the original cost, plus retirement
cost, less salvage is charged as a gain or loss in income.
Included in the Company's property, plant, and equipment is construction
work in progress of approximately $597 million and $353 million at December 31,
1999, and 1998, respectively.
The Company evaluates impairment of its regulated and non-regulated
property, plant, and equipment in accordance with SFAS No. 121, Accounting for
the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of.
Natural Gas and Oil Properties
The Company uses the full cost method of accounting for its natural gas and
oil properties. Under the full cost method, all productive and nonproductive
costs incurred in connection with the acquisition, exploration and development
of natural gas and oil reserves are capitalized and amortized on the
unit-of-production method using proved reserves. Such costs include the costs of
all unproved properties and internal costs directly related to acquisition and
exploration activities, including capitalized interest. All other general and
administrative costs, as well as production costs, are expensed as incurred.
Certain unevaluated properties are excluded from the amortization base until a
determination has been made as to the existence of proved reserves. Capitalized
costs are subject to a quarterly ceiling test which limits such costs to the
aggregate of the present value of future net revenues, discounted at 10 percent,
plus the lower of cost or fair market value of unproved properties. Any
conveyance of properties is treated as an adjustment to the cost of natural gas
and oil properties with no gain or loss recognized, unless properties sold are
significant.
50
<PAGE> 55
Revenue Recognition
The Company's regulated businesses recognize revenues from natural gas
transportation in the period the service is provided. Reserves are provided on
revenues collected subject to refund, when appropriate. Revenues on services
other than transportation are recorded when earned.
Revenues for the Company's non-regulated businesses are recorded at various
points when earned including when deliveries of the physical commodities are
made or in the period services are provided. For the Company's revenue
recognition policy on its trading portfolio, see discussion of price risk
management activities below.
Intangible Assets
Intangible assets are amortized using the straight-line method over periods
ranging from 5 to 40 years. Accumulated amortization of intangible assets was
$39 million and $24 million as of December 31, 1999 and 1998, respectively. In
response to a fundamental shift in the strategy and direction of the Company's
merchant energy activities, the Company changed its estimated useful life of
goodwill related to its 1995 acquisitions of Eastex Energy Inc. and Premier Gas
Company. Had this change not been made, the reported net loss and diluted loss
per share of the Company for the year ended December 31, 1999 would have been
$236 million and $1.04, respectively.
The Company evaluates impairment of goodwill in accordance with SFAS No.
121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to be Disposed Of. Under this methodology, when an event occurs to
suggest that impairment may have occurred, the Company evaluates 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 an impairment in the Consolidated
Statements of Income.
Environmental Costs
Expenditures for ongoing compliance with environmental regulations that
relate to current operations are expensed or capitalized as appropriate.
Expenditures that relate to an existing condition caused by past operations, and
which do not contribute to current or future revenue generation, are expensed.
Liabilities are recorded when environmental assessments indicate that
remediation efforts are probable and the costs can be reasonably estimated.
Estimates of the liability are based upon currently available facts, existing
technology and presently enacted laws and regulations taking into consideration
the likely effects of inflation and other societal and economic factors, and
include estimates of associated legal costs. These amounts also consider prior
experience in remediating contaminated sites, other companies' clean-up
experience and data released by the EPA or other organizations. These estimated
liabilities are subject to revision in future periods based on actual costs or
new circumstances, and are included in the balance sheets at their undiscounted
amounts. Recoveries are evaluated separately from the liability and, when
recovery is assured, are recorded and reported separately from the associated
liability in the consolidated financial statements as an asset.
Price Risk Management Activities
The Company utilizes derivative financial instruments to manage market
risks associated with certain energy commodities, interest rates, and foreign
currency exchange rates. In its commodity price risk management activities, the
Company engages in both trading and non-trading activities.
Activities for trading purposes consist of services provided to the energy
sector, and all energy trading activities, including transportation capacity and
storage, are accounted for using the mark-to-market method. Trading activities
are conducted 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 payments to (or receipts from) counterparties based on the
differential between a fixed and variable prices for the commodity,
exchange-traded and over-the-counter options, and other contractual
arrangements.
51
<PAGE> 56
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 operating income in the Consolidated Statements of
Income. Net gains or losses recognized in a period result primarily from
transactions originating within that period and 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 the Consolidated
Balance Sheets, according to their term to maturity. Terms regarding cash
settlement of the contracts vary with respect to the actual timing of cash
receipts and payments. Receivables and payables resulting from these timing
differences are presented in accounts receivable and accounts payable in the
Consolidated Balance Sheets. Cash inflows and outflows associated with these
price risk management activities are recognized in operating cash flow as the
settlement of transactions occurs.
The market value of commodity and energy related contracts reflect
management's best estimate considering various factors including closing
exchange and over-the-counter quotations, time value and volatility factors
underlying the commitments. The values are adjusted to reflect the potential
impact of liquidating the Company's 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, the Company utilizes other valuation techniques
to estimate fair value. The use of these techniques requires the Company 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 the underlying market valuation and could materially
impact these estimates.
Derivative and other financial instruments are also utilized in connection
with non-trading activities. The Company enters into forwards, swaps, and other
contracts to hedge the impact of market fluctuations on assets, liabilities, or
other contractual commitments. Hedge accounting is applied only if the
derivative reduces the risk of the underlying hedge 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(s) being hedged. If correlation ceases
to exist, hedge accounting is terminated and mark-to-market accounting is
applied. Changes in market value of hedged transactions are deferred until the
gain or loss on the hedged item is recognized. Derivatives held for non-trading
price risk management activities are recorded as a gain or loss in operating
income and cash inflows and outflows are recognized in operating cash flow as
the settlement of these transactions occurs. See Note 7 for a further discussion
of the Company's price risk management activities.
Income Taxes
Income taxes are based on income reported for tax return purposes along
with a provision for deferred income taxes. Deferred income taxes are provided
to reflect the tax consequences in future years of differences between the
financial statement and tax bases of assets and liabilities at each year end.
Tax credits are accounted for under the flow-through method, which reduces the
provision for income taxes in the year the tax credits first become available.
Deferred tax assets are reduced by a valuation allowance when, based upon
management's estimates, it is more likely than not that a portion of 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.
Treasury Stock
Treasury stock is accounted for using the cost method and is shown as a
reduction to stockholders' equity in the Consolidated Balance Sheets. Treasury
stock sold or issued is valued on a first-in, first-out basis. Included in
treasury stock at December 31, 1999, and 1998, were 1,360,000 shares of common
stock that were reserved for use under certain of the Company's benefit plans,
as well as 5,845,269 shares of common stock which were placed in a trust under
the Company's deferred compensation programs.
52
<PAGE> 57
Stock-Based Compensation
The Company applies the provisions of Accounting Principles Board Opinion
No. 25 and related interpretations in accounting for its stock compensation
plans. Accordingly, compensation expense is not recognized for stock options
unless the options were granted at an exercise price lower than market on the
grant date. The Company uses fixed and variable plan accounting for its fixed
and variable
compensation plans, respectively.
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 defines start-up activities and requires start-up and
organization costs be expensed as incurred. In addition, it requires that any
such cost that exists on the balance sheet be expensed upon adoption of the
pronouncement. The Company adopted the pronouncement effective January 1, 1999,
and reported a charge of $13 million, net of income taxes, in the first quarter
of 1999 as a cumulative effect of an accounting change.
Accounting for Derivative Instruments and Hedging Activities
In June 1998, Statement of Financial Accounting Standards ("SFAS") No. 133,
Accounting for Derivative Instruments and Hedging Activities, was issued by the
Financial Accounting Standards Board to establish accounting and reporting
standards for derivative instruments, including certain derivative instruments
embedded in other contracts, and for hedging activities. This pronouncement
requires that an entity classify all derivatives as either assets or liabilities
in the statement of financial position and measure those instruments at fair
value. If certain conditions are met, a derivative may be specifically
designated as (i) a hedge of the exposure to changes in the fair value of a
recognized asset, liability or an unrecognized firm commitment, (ii) a hedge of
the exposure to variable cash flows of a forecasted transaction or (iii) a hedge
of the foreign currency exposure of a net investment in a foreign operation, an
unrecognized firm commitment, an available-for-sale security or a
foreign-currency-denominated forecasted transaction. Under SFAS No. 133,
accounting for the changes in the fair value of a derivative depends on its
intended use and its resulting designation. The standard was amended by SFAS No.
137 in June 1999. The amendment defers the effective date of SFAS No. 133 to
fiscal years beginning after June 15, 2000. The Company is currently evaluating
the effects of this pronouncement.
2. ACQUISITIONS
Sonat
On October 25, 1999, the Company completed its merger with Sonat, a
diversified energy holding company engaged in domestic oil and natural gas
exploration and production, the transmission and storage of natural gas, and
natural gas and power marketing. In the merger, one share of the Company's
common stock was issued in exchange for each share of Sonat common stock. Total
common shares issued in the merger were approximately 110 million. In addition,
the Company retained approximately $2.3 billion of Sonat debt. The transaction
was valued at approximately $6.8 billion based on the Company's closing stock
price on October 25, 1999. The merger was accounted for as a pooling of
interests. Therefore, the Consolidated Financial Statements and other financial
information included in this Annual Report for periods prior to the merger
include the combined historical financial results of El Paso and Sonat.
53
<PAGE> 58
The following table presents the revenues and net income (loss) for the
previously separate companies and the combined amounts presented in these
consolidated financial statements. Certain adjustments were made to conform the
accounting presentation of this financial information.
<TABLE>
<CAPTION>
(UNAUDITED)
TEN MONTHS YEAR ENDED
ENDED DECEMBER 31,
OCTOBER 31, ----------------
1999 1998 1997
----------- ------ -------
(IN MILLIONS)
<S> <C> <C> <C>
Revenues
El Paso................................................... $ 6,049 $5,782 $ 5,638
Sonat..................................................... 2,883 3,710 4,372
Conforming reclassifications.............................. (15) 8 5
------- ------ -------
Combined.................................................. $ 8,917 $9,500 $10,015
======= ====== =======
Net Income (Loss)
El Paso................................................... $ 107 $ 225 $ 186
Sonat..................................................... (181) (531) 219
------- ------ -------
Combined.................................................. $ (74) $ (306) $ 405
======= ====== =======
</TABLE>
In connection with the merger, the Company was ordered by the Federal Trade
Commission to sell East Tennessee Natural Gas Company, Sea Robin Pipeline
Company and its one-third interest in Destin Pipeline Company. Proceeds from the
sales are expected to be approximately $618 million, and the sales are
anticipated to close in the first quarter of 2000 pending Federal Trade
Commission approval. The Company will treat gains that arise from these sales as
extraordinary items, net of taxes in the Consolidated Statements of Income.
East Asia Power
In February 1999, the Company acquired a 46 percent ownership interest in
EAPRC along with an interest in a convertible loan. Following its acquisition,
the Company converted the loan to equity, increasing its ownership interest to
65 percent, and in September 1999, the Company acquired an additional 17 percent
from another shareholder, increasing its ownership interest to 82 percent. In
December 1999, International participated in an EAPRC rights offering,
increasing its overall ownership to 92 percent representing a total investment
of approximately $144 million. In February 2000, the Company entered into an
agreement with a party to jointly own equal interests in EAPRC. The Company
expects to complete the transaction prior to the end of the first quarter of
2000 which would reduce the Company's interest in EAPRC to less than 50 percent.
Since the Company's control of EAPRC is temporary, the investment has been
accounted for using the equity method of accounting. EAPRC owns and operates
seven power generation facilities in the Philippines and one plant in China with
a total generating capacity of 412 megawatts. Electric power generated by the
facilities is supplied to a diversified base of customers including National
Power Corporation, the Philippine state-owned utility, private distribution
companies and industrial users.
In connection with the acquisition of EAPRC, the Company entered into a
short-term, fully collateralized loan agreement with a third party. Under the
agreement, the Company placed $101 million in an interest bearing account with a
financial institution and was loaned an equal amount. The amount on deposit can
be withdrawn upon repayment of the loan. The loan's interest rate is LIBOR plus
400 basis points, which was 10.2 percent at December 31, 1999. The deposit is
reflected as other current assets and the loan is reflected in accounts and
notes payable in the Consolidated Balance Sheets.
CE Generation
In March 1999, the Company purchased a 50 percent ownership interest in CE
Generation LLC. The investment of approximately $254 million is accounted for
using the equity method of accounting. CE Generation LLC owns, or has ownership
interests in, four natural gas-fired cogeneration projects in New
54
<PAGE> 59
York, Pennsylvania, Texas and Arizona and eight geothermal facilities near the
Imperial Valley in southern California. In addition, two additional geothermal
facilities are currently under construction in southern California.
Collectively, the 14 power projects will have a combined electric generating
capacity of approximately 900 megawatts.
EnCap
In March 1999, the Company acquired EnCap for $52 million, net of cash
acquired. The purchase price included $17 million in Company common stock, of
which $7 million is issuable upon the occurrence of certain events. The
acquisition was accounted for as a purchase, and the Company recorded $45
million in goodwill, which is being amortized over 25 years. EnCap is 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.
Chaparral Investors
During 1999, the Company 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. A subsidiary of the Company manages
both Chaparral and Mesquite. During 1999, the Company issued a note payable of
approximately $121 million to Chaparral. The note is payable on demand and
carries a variable interest rate, which was 6.4 percent per annum for the fourth
quarter of 1999. The Company also has a note receivable from Mesquite with a
balance of approximately $262 million at December 31, 1999, which is
collateralized by Chaparral's membership interest in Mesquite. This note has a
variable interest rate, which was 8.3 percent for the fourth quarter of 1999,
and is payable upon demand. The Company's investment in Chaparral is being
accounted for using the equity method of accounting.
In January 2000, the Company acquired an additional interest in Chaparral
in exchange for a $160 million contingent interest promissory note. The maturity
date of the note is the earlier of December 2019, or upon the occurrence of
certain events specified in the note. The note carries a variable interest rate
not to exceed 12.75 percent.
DeepTech
In August 1998, the Company completed its acquisition of DeepTech. The
acquisition was accounted for as a purchase with a total purchase price of
approximately $415 million, net of cash acquired. The Company recorded $207
million of goodwill in connection with the acquisition which is being amortized
using the straight-line method over a period of 40 years. Operating results of
DeepTech were included in the Company's Consolidated Statements of Income
beginning on August 15, 1998. The components of the purchase price are as
follows:
<TABLE>
<CAPTION>
(IN MILLIONS)
<S> <C>
Fair value of assets acquired............................... $ 338
Goodwill.................................................... 207
Fair value of liabilities assumed........................... (101)
Cash acquired............................................... (29)
-----
Purchase price, net of cash acquired.............. 415
Affiliated receivable extinguished.......................... (77)
Issuance of common stock.................................... (2)
-----
Net cash consideration paid....................... $ 336
=====
</TABLE>
55
<PAGE> 60
In accordance with the DeepTech merger agreement, the Company has
guaranteed DeepTech's 12% senior notes due 2000. The following table contains
summarized financial information of DeepTech. Information for the twelve months
ended June 30, 1998 and 1997 is for pre-merger periods. The information as of
December 31, 1999 and 1998, and for the year ended December 31, 1999, is for the
post-merger period and the information for the six months ended December 31,
1998, is part post-merger and part pre-merger.
<TABLE>
<CAPTION>
FOR THE TWELVE
FOR THE FOR THE SIX MONTHS ENDED
YEAR ENDED MONTHS ENDED JUNE 30,
DECEMBER 31, DECEMBER 31, ---------------
1999 1998(a) 1998 1997
------------ ------------ ------ ------
(IN MILLIONS)
<S> <C> <C> <C> <C>
Operating results data:
Operating revenue................................. $44 $15 $69 $120
Operating expenses................................ $54 $25 $74 $132
Net income (loss)................................. $(2) $11 $(2) $(20)
</TABLE>
<TABLE>
<CAPTION>
DECEMBER 31,
--------------
1999 1998(b)
---- -------
(IN MILLIONS)
<S> <C> <C>
Financial position data:
Total assets.............................................. $522 $551
Short term debt (including current maturities of long-term
debt).................................................. $ 85 $ 17
Long term debt............................................ $ -- $ 90
Stockholder's equity...................................... $436 $444
</TABLE>
- ---------------
(a) Unaudited
(b) Reflects the allocation of the purchase price to the assets acquired and
liabilities assumed in connection with the Company's acquisition of DeepTech
in August 1998.
Other
In March 1999, the Company acquired an additional 10 percent interest in
the Samalayuca Power project for approximately $22 million, bringing its overall
ownership to 40 percent. The Company also made a $48 million equity contribution
to the project to replace equity financing established in the second quarter of
1996.
In June 1999, the Company acquired a 26 percent interest in the PPN Power
Plant in Tamil Nadu, India for $37 million. Approximately $11 million was paid
in June 1999, and the remaining amount will be paid in the first quarter of
2001. The project consists of a 346 megawatt combined cycle power plant which
will serve as a base load facility and sell power to the state-owned Tamil Nadu
Electricity Board under a thirty-year power purchase agreement. Construction
began in January 1999, and operations are expected to commence in early 2001.
In June 1999, the Company increased its effective ownership interest in El
Paso Energy Partners from approximately 27 percent to approximately 35 percent
by transferring a 49 percent interest in Viosca Knoll Gathering Company to El
Paso Energy Partners for total consideration of approximately $80 million.
Proceeds included cash of approximately $20 million with the balance in El Paso
Energy Partners common units. The gain from the transaction, limited to the
extent of third-party ownership in El Paso Energy Partners, is included in
Other, net in the Consolidated Statements of Income.
In 1999, Sonat Energy Services, a wholly owned subsidiary of the Company,
purchased AGL's 35 percent interests in Sonat Marketing Company LP and Sonat
Power Marketing LP for approximately $65 million. At December 31, 1999, the
Company owned 100 percent of the two partnerships.
In August 1999, the Company acquired a 100 percent interest in the 158
megawatt Rio Negro power plant located in Manaus, Brazil for $110 million.
Electricity from the Rio Negro facility will be sold under a long-term contract
to a subsidiary of the Brazilian federal electric utility, Eletronorte.
56
<PAGE> 61
In October 1999, the Company acquired a 25 percent interest in a 762
megawatt coal-fired power plant in the People's Republic of China. Approximately
$5 million was paid in October and the remaining $63 million will be paid in the
first quarter of 2001. The Meizhou Wan power plant, located in the Fujian
Province, is expected to be operational in the first quarter of 2001.
In January 1998, Sonat completed its merger with Zilkha Energy Company
("Zilkha") by exchanging approximately 24 million common shares for all of the
outstanding shares of Zilkha. Zilkha was a privately owned exploration and
production company. The transaction was valued at $1.3 billion. The merger was
accounted for as a pooling of interests, therefore, the Consolidated Financial
Statements and other financial information included in this Annual Report for
periods prior to the merger include the historical financial results of Zilkha.
Pending Mergers and Acquisitions
In January 2000, the Company announced it had entered into a definitive
agreement to merge with Coastal. In the merger, each share of Coastal common
stock and Class A common stock will be converted on a tax-free basis into 1.23
shares of Company common stock. Coastal's outstanding convertible preferred
stock will be exchanged for Company common stock on the same basis as if the
preferred stock had been converted into Coastal common stock immediately prior
to the merger. The total value of the transaction is approximately $16 billion,
including $6 billion of assumed debt and preferred equity, and will be accounted
for as a pooling of interests. The merger is expected to close in the fourth
quarter of 2000 and is subject to the approval of the stockholders of both
companies and normal regulatory approvals.
Coastal is a diversified energy holding company. It is engaged, through its
subsidiaries and joint ventures, in natural gas transmission, storage,
gathering, processing and marketing; natural gas and oil exploration and
production; petroleum refining, marketing and distribution; chemicals; power
production; and coal. Coastal owns interests in approximately 18,000 miles of
natural gas pipelines extending across the midwestern and the Rocky Mountain
areas of the United States and has proved reserves of 3.6 Tcfe. Coastal also has
international and domestic interests in natural gas and oil producing
properties, power production plants, and crude oil refining facilities.
In January 2000, the Company entered into an agreement to purchase the
natural gas and natural gas liquids businesses of PG&E Gas Transmission, Texas
Corporation and PG&E Gas Transmission Teco, Inc. The total value of the
transaction is $840 million, including the face amount of assumed debt of
approximately $561 million. The acquisition, which is expected to close by
mid-year 2000, is subject to the receipt of certain required governmental
approvals and third party consents. The transaction will be accounted for as a
purchase and will be included in Field Services.
The assets being acquired consist of 8,500 miles of intrastate natural gas
transmission pipelines that transport approximately 2.8 Bcf/d in the South Texas
area, nine natural gas processing plants that currently process 1.5 Bcf/d, and a
7.2 Bcf natural gas storage field. The transaction also includes significant
natural gas liquids pipelines and fractionation facilities.
3. MERGER-RELATED AND ASSET IMPAIRMENT CHARGES
In 1999, the Company incurred $557 million in charges related to its merger
with Sonat, as well as certain asset impairment charges. Merger-related costs
include $294 million related to benefit costs associated with a change in
control (as defined in certain benefit plans), retention and termination
charges; $71 million for transaction costs; $28 million in costs related to
conforming accounting practices and policies of El Paso and Sonat; $46 million
of other merger-related charges, primarily consisting of facilities integration
costs and incremental fees to retain seismic data; and merger-related asset
impairment charges of $76 million related to duplicate systems and facilities
identified as impaired following the merger. The Company also recorded other
asset impairment charges of $42 million for lower estimated recoveries on
certain regulatory assets related to SNG's pending rate case.
57
<PAGE> 62
For the year ended December 31, 1997, the Company incurred approximately
$50 million in other merger-related charges in connection with the merger with
Zilkha Energy.
4. CEILING TEST CHARGES
Under the full cost method of accounting for natural gas and oil
properties, quarterly ceiling tests are required to ensure that the carrying
value of oil and gas properties is not overstated. At March 31, 1999, and at
March 31, June 30, and September 30, 1998, it was determined that capitalized
costs exceeded the ceiling test limits by $352 million, $40 million, $540
million and $455 million, respectively. These write-downs are included as
ceiling test charges in the Consolidated Statements of Income.
5. INCOME TAXES
The following table reflects the components of income tax expense (benefit)
for the years ended December 31:
<TABLE>
<CAPTION>
1999 1998 1997
---- ----- ----
(IN MILLIONS)
<S> <C> <C> <C>
Current
Federal.................................................. $(44) $ 25 $(32)
State.................................................... (4) (6) (14)
Foreign.................................................. 11 5 --
---- ----- ----
(37) 24 (46)
---- ----- ----
Deferred
Federal.................................................. (51) (210) 246
State.................................................... 8 17 34
Foreign.................................................. (1) (1) --
---- ----- ----
(44) (194) 280
---- ----- ----
Total tax expense (benefit)...................... $(81) $(170) $234
==== ===== ====
</TABLE>
Tax expense (benefit) of the Company differs from the amount computed by
applying the statutory federal income tax rate (35 percent) to income before
taxes. The following table outlines the reasons for the differences for the
periods ended December 31:
<TABLE>
<CAPTION>
1999 1998 1997
----- ----- ----
(IN MILLIONS)
<S> <C> <C> <C>
Tax expense (benefit) at the statutory federal rate of
35%....................................................... $(104) $(158) $232
Increase (decrease)
State income tax, net of federal income tax benefit....... 3 7 13
Dividend exclusion........................................ (14) (7) (8)
Merger-related costs...................................... 29 -- --
Non-conventional fuel tax credits......................... -- (7) (7)
Other..................................................... 5 (5) 4
----- ----- ----
Income tax expense (benefit)................................ $ (81) $(170) $234
===== ===== ====
Effective tax rate.......................................... 27% 38% 35%
===== ===== ====
</TABLE>
58
<PAGE> 63
The following table reflects the components of the net deferred tax
liability at December 31:
<TABLE>
<CAPTION>
1999 1998
------ ------
(IN MILLIONS)
<S> <C> <C>
Deferred tax liabilities
Property, plant, and equipment............................ $2,377 $2,252
Regulatory and other assets............................... 491 514
------ ------
Total deferred tax liability...................... 2,868 2,766
------ ------
Deferred tax assets
U.S. net operating loss and tax credit carryovers......... 364 141
Accrual for regulatory issues............................. 272 286
Postretirement benefits................................... 137 132
Other liabilities......................................... 493 567
Valuation allowance....................................... (6) (5)
------ ------
Total deferred tax asset.......................... 1,260 1,121
------ ------
Net deferred tax liability(a)............................... $1,608 $1,645
====== ======
</TABLE>
- ---------------
(a) As of December 31, 1999, and December 31, 1998, $4 million and $2 million,
respectively, of non-current foreign deferred income taxes are included in
other assets in the Consolidated Balance Sheets.
The cumulative undistributed earnings of certain foreign subsidiaries and
foreign corporate joint ventures were approximately $86 million as of December
31, 1999. 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, the Company
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 such
taxes is not practicable. For the same reasons, the Company has not provided for
any U.S. taxes on the foreign currency translation adjustments recognized in
comprehensive income.
The tax benefit associated with the exercise of non-qualified stock options
and the vesting of restricted stock as well as restricted stock dividends,
reduced taxes payable by $13 million in 1999, $10 million in 1998 and $15
million in 1997. Such benefits are included in additional paid-in capital in the
Consolidated Balance Sheets.
As of December 31, 1999, the Company has $69 million of alternative minimum
tax credit carryovers, $1 million of general business credit carryovers, $759
million of net operating loss carryovers and $81 million of capital loss
carryovers. The alternative minimum tax credits carry forward indefinitely. The
net operating loss carry forward periods end as follows -- approximately $9
million in the years 2000 through 2005, $16 million in 2006, $26 million in
2007, $24 million in the years 2008 through 2011, $181 million in 2012, $72
million in 2016, $22 million in 2017, $239 million in 2018 and $170 million in
2019. The carry forward period for $74 million of the capital loss ends in 2002
and the carry forward period for the remainder ends in 2003. The general
business credit carry forward periods end at various times in the years 2000
through 2017. Usage of these carryovers is subject to the limitations provided
under Sections 382 and 383 of the Internal Revenue Code as well as the separate
return limitation year rules of IRS regulations.
The Company has recorded a valuation allowance to reflect the estimated
amount of deferred tax assets which may not be realized due to the expiration of
net operating loss and tax credit carryovers. As of December 31, 1999 and 1998,
approximately $4 million of the valuation allowance relates to the net operating
loss carryovers of an acquired company. The remainder of the allowance relates
to general business credit carryovers. With the exception of $1 million, any tax
benefits subsequently recognized from the reversal of the allowance will be
allocated to additional purchase cost assigned to utility plant.
Prior to 1999, EPTPC and its subsidiaries filed a consolidated federal
income tax return and El Paso and its other subsidiaries filed a separate
consolidated federal income tax return. As a result of the tax-free
59
<PAGE> 64
reorganization described in Note 1, El Paso and its subsidiaries, including
EPTPC and its subsidiaries, will file one consolidated federal income tax
return. The subsidiaries of Sonat will be included in El Paso's consolidated
return after the merger date.
In connection with the acquisition of EPTPC by the Company, EPTPC entered
into a tax sharing agreement with Newport News Shipbuilding Inc., new Tenneco
Inc. and El Paso, as successor to EPNG. This tax sharing agreement provides,
among other things, for the allocation among the parties of tax assets and
liabilities arising prior to, as a result of, and subsequent to the
distributions of new Tenneco Inc. and Newport News Shipbuilding Inc. to the
shareholders of old Tenneco Inc. (now known as EPTPC). Generally, EPTPC will be
liable for taxes imposed on itself. With respect to periods prior to the
consummation of the distributions, in the case of federal income taxes imposed
on the combined activities of old Tenneco Inc. and other members of its
consolidated group prior to giving effect to the distributions, new Tenneco Inc.
and Newport News Shipbuilding Inc. will be liable to EPTPC for federal income
taxes attributable to their activities, and each will be allocated an
agreed-upon share of estimated tax payments made by EPTPC for old Tenneco Inc.
Pursuant to the tax sharing agreement, EPTPC paid new Tenneco Inc. in 1997 for
the tax benefits realized from the deduction of 1996 taxable losses generated by
a debt realignment in accordance with the merger.
6. EARNINGS PER SHARE
Basic and diluted earnings per share amounts calculated in accordance with
SFAS No. 128 Earnings Per Share, are presented below for the years ended
December 31.
<TABLE>
<CAPTION>
1999 1998 1997
-------- -------- ---------------
BASIC(1) BASIC(1) BASIC DILUTED
-------- -------- ----- -------
(IN MILLIONS, EXCEPT PER
COMMON SHARE AMOUNTS)
<S> <C> <C> <C> <C>
Income (loss) before cumulative effect of accounting
change.................................................... $ (242) $ (306) $ 405 $ 405
Interest on trust preferred securities.................... -- -- -- --
------ ------ ----- -----
Adjusted income (loss) before cumulative effect of
accounting change...................................... (242) (306) 405 405
Cumulative effect of accounting change, net of income
taxes.................................................. (13) -- -- --
------ ------ ----- -----
Adjusted net income (loss).................................. $ (255) $ (306) $ 405 $ 405
====== ====== ===== =====
Average common shares outstanding........................... 228 226 224 224
Effect of diluted securities
Restricted stock.......................................... -- -- -- 1
Stock options............................................. -- -- -- 4
Trust preferred securities................................ -- -- -- --
------ ------ ----- -----
Average common shares outstanding........................... 228 226 224 229
====== ====== ===== =====
Earnings (loss) per common share
Adjusted income (loss) before cumulative effect of
accounting change...................................... $(1.06) $(1.35) $1.81 $1.77
Cumulative effect of accounting change, net of income
taxes.................................................. (0.06) -- -- --
------ ------ ----- -----
Net income (loss)......................................... $(1.12) $(1.35) $1.81 $1.77
====== ====== ===== =====
</TABLE>
- ---------------
(1) The addition of potential average common shares outstanding for 1999 and
1998 would have reduced the loss per share. Therefore, the diluted loss per
share has not been presented for these years.
60
<PAGE> 65
7. FINANCIAL INSTRUMENTS AND PRICE RISK MANAGEMENT ACTIVITIES
Fair Value of Financial Instruments
The following disclosure of the estimated fair value of financial
instruments is presented in accordance with the requirements of SFAS No. 107 and
SFAS No. 119. The estimated fair value amounts have been determined by the
Company using available market information and valuation methodologies.
As of December 31, 1999, and 1998, the carrying amounts of certain
financial instruments held by the Company, including cash, cash equivalents,
short-term borrowings, and trade receivables and payables are representative of
fair value because of the short-term maturity of these instruments. The fair
value of long-term debt with variable interest rates is the carrying value
because of the variable nature of the respective debt's interest rates. The fair
value of debt with fixed interest rates has been estimated based on quoted
market prices for the same or similar issues. The fair value of all derivative
financial instruments is the estimated amount at which management believes the
instruments could be liquidated over a reasonable period of time, based on
quoted market prices, current market conditions, or other estimates obtained
from third-party brokers or dealers.
The following table reflects the carrying amount and estimated fair value
of the Company's financial instruments at December 31:
<TABLE>
<CAPTION>
1999 1998
--------------------- ---------------------
CARRYING CARRYING
AMOUNT FAIR VALUE AMOUNT FAIR VALUE
-------- ---------- -------- ----------
(IN MILLIONS)
<S> <C> <C> <C> <C>
Balance sheet financial instruments:
Long-term debt, excluding project financing....... $5,315 $5,204 $3,705 $3,936
Project financing debt............................ -- -- 166 167
Company obligated preferred securities of
subsidiary...................................... 325 327 325 311
Other financial instruments:
Trading
Futures contracts................................. $ (24) $ (24) $ (10) $ (10)
Option contracts(1)............................... 264 264 80 80
Swap and forward contracts........................ (65) (65) (6) (6)
Non-Trading
Interest rate swap agreements..................... $ -- $ 4 $ -- $ (9)
Equity swap....................................... 10 10 3 3
Commodity option contracts........................ -- -- -- 1
Commodity swap and forward contracts.............. -- (17) -- (21)
Commodity futures contracts....................... -- 2 -- --
</TABLE>
- ---------------
(1) Excludes transportation capacity and natural gas in storage held for trading
purposes.
Trading Commodity Activities
The Company's merchant energy business offers integrated price risk
management services to the energy sector. These services primarily relate to
energy related commodities including natural gas and power products. The Company
provides these services through a variety of contracts entered into for trading
purposes including exchange traded futures contracts involving cash settlement,
forward contracts involving cash settlements or physical delivery of an energy
commodity, swap contracts, which require payments to (or receipt of payments
from) counterparties based on the differential between a fixed and variable
price for the commodity, options and other contractual arrangements. The Company
recognized gross margin of $97 million and $53 million during 1999 and 1998,
respectively, from its trading activities.
61
<PAGE> 66
The fair value of commodity and energy related contracts entered into for
trading purposes as of December 31, 1999 and 1998, and the average fair value of
those instruments held during the years then ended are set forth below. At
December 31, 1999 and 1998, $413 million and $118 million, respectively, of
assets from price risk management activities are included in other non-current
assets and $95 million and $57 million, respectively, of liabilities from price
risk management activities are included in other non-current liabilities in the
Consolidated Balance Sheets.
<TABLE>
<CAPTION>
AVERAGE FAIR
VALUE FOR THE
YEAR ENDED
ASSETS LIABILITIES DECEMBER 31,(1)
------ ----------- ---------------
(IN MILLIONS)
<S> <C> <C> <C>
1999
Futures contracts.................................. $ 2 $ (26) $(12)
Option contracts................................... 455 (35) 184
Swap and forward contracts......................... 205 (247) 93
1998
Futures contracts.................................. $(72) $ 62 $ (9)
Option contracts................................... 224 (60) 55
Swap and forward contracts......................... 409 (415) (14)
</TABLE>
- ---------------
(1) Computed using the net asset (liability) balance at each month end.
Notional Amounts and Terms
The notional amounts and terms of the Company's energy commodity financial
instruments at December 31, 1999, and 1998 are set forth below (natural gas
volumes are in trillions of British thermal units, power volumes are in millions
of megawatt hours, and liquids volumes are in millions of British thermal
units):
<TABLE>
<CAPTION>
FIXED PRICE FIXED PRICE MAXIMUM
PAYOR RECEIVER TERMS IN YEARS
----------- ----------- --------------
<S> <C> <C> <C>
1999
Energy Commodities:
Natural gas...................................... 13,613 13,045 26
Power............................................ 30 41 20
Liquids(1)....................................... 185 185 7
1998
Energy Commodities:
Natural gas...................................... 11,111 10,320 20
Power............................................ 22 28 20
Liquids(1)....................................... 201 127 5
</TABLE>
- ---------------
(1) Liquids include crude oil, condensate and other petroleum based products.
The notional amount and terms of foreign currency forward purchases and
sales at December 31, 1999, were as follows:
<TABLE>
<CAPTION>
NOTIONAL VOLUME
------------------------- MAXIMUM
BUY SELL TERM IN YEARS
----------- ----------- --------------
<S> <C> <C> <C>
Foreign Currency (in millions)
Canadian Dollars................................. 296 194 9
British Pounds................................... -- 28 9
</TABLE>
Notional amounts reflect the volume of transactions but do not represent
the amounts exchanged by the parties. Accordingly, notional amounts are an
incomplete measure of the Company's exposure to market or credit risks. The
maximum terms in years detailed above are not indicative of likely future cash
flows as these positions may be offset or cashed-out in the commodity and
currency markets based on the Company's risk management needs and liquidity in
those markets.
62
<PAGE> 67
The weighted average maturity of the Company's entire portfolio of price
risk management activities was approximately six years as of December 31, 1999,
and two years as of December 31, 1998.
Market and Credit Risks
The Company serves a diverse customer group that includes independent power
producers, industrial companies, gas and electric utilities, natural gas and oil
producers, financial institutions and other energy marketers. This broad
customer mix generates a need for a variety of financial structures, products
and terms. This diversity requires the Company to manage, on a portfolio basis,
the resulting market risks inherent in these transactions subject to parameters
established by the Company's risk management committee. Market risks are
monitored by a risk control committee operating independently from the units
that create or actively manage these risk exposures to ensure compliance with
the Company's stated risk management policies.
The Company measures and adjusts the risk in its portfolio in accordance
with mark-to-market and other risk management methodologies which utilize
forward price curves in the energy markets to estimate the size and probability
of future potential exposure.
Credit risk relates to the risk of loss that the Company would incur as a
result of non-performance by counterparties pursuant to the terms of their
contractual obligations. The Company maintains credit policies with regard to
its counterparties to minimize overall credit risk. These policies require an
evaluation of potential counterparties' financial condition (including credit
rating), collateral requirements under certain circumstances (including cash in
advance, letters of credit, and guarantees), and the use of standardized
agreements which allow for the netting of positive and negative exposures
associated with a single counterparty. The counterparties associated with the
Company's assets from price risk management activities are summarized as
follows:
<TABLE>
<CAPTION>
ASSETS FROM PRICE RISK MANAGEMENT ACTIVITIES AS OF
DECEMBER 31, 1999
---------------------------------------------------
BELOW
INVESTMENT GRADE(A) INVESTMENT GRADE TOTAL(B)
------------------- ---------------- --------
(IN MILLIONS)
<S> <C> <C> <C>
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............................................ 76 -- 76
---- --- ----
Total assets from price risk management
activities............................ $679 $ 3 $682
==== === ====
</TABLE>
<TABLE>
<CAPTION>
ASSETS FROM PRICE RISK MANAGEMENT ACTIVITIES AS OF
DECEMBER 31, 1998
---------------------------------------------------
BELOW
INVESTMENT GRADE(A) INVESTMENT GRADE TOTAL(B)
------------------- ---------------- --------
(IN MILLIONS)
<S> <C> <C> <C>
Energy marketers................................. $192 $ 8 $200
Financial institutions........................... 33 -- 33
Oil and natural gas producers.................... 77 5 82
Natural gas and electric utilities............... 153 7 160
Industrials...................................... 35 -- 35
Other............................................ 49 2 51
---- --- ----
Total assets from price risk management
activities............................ $539 $22 $561
==== === ====
</TABLE>
- ---------------
(a)"Investment Grade" is primarily determined using publicly available credit
ratings along with consideration of collateral, which encompass standby
letters of credit, parent company guarantees and property interest, including
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-.
(b)Four and two customers' exposure at December 31, 1999, and 1998, respectively
comprise greater than 5 percent of assets from price risk management
activities. These customers have investment grade ratings.
63
<PAGE> 68
This concentration of counterparties may impact the Company's overall
exposure to credit risk, either positively or negatively, in that the
counterparties may be similarly affected by changes in economic, regulatory or
other conditions. Based on the Company's policies, risk exposure, and reserves,
the Company does not anticipate a material adverse effect on its financial
position, results of operations, or cash flows as a result of counterparty
nonperformance.
Non-Trading Price Risk Management Activities
The Company also utilizes 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.
At December 31, 1999 and 1998, the Company had outstanding energy commodity
futures, forwards, swaps and options for purposes other than trading. The table
below represents the notional amounts and terms of these contracts at December
31, 1999 and 1998.
<TABLE>
<CAPTION>
1999 1998
--------------------- ---------------------
NOTIONAL NOTIONAL
VOLUME VOLUME
---------- MAXIMUM ---------- MAXIMUM
BUY SELL TERM BUY SELL TERM
--- ---- -------- --- ---- --------
<S> <C> <C> <C> <C> <C> <C>
Commodity
Natural Gas (TBtu)............................ 22 548 13 years 17 103 2 years
Power (Thousands of MWh)...................... -- -- -- 39 45 4 months
Liquids (TBtu)................................ -- 1 2 years
</TABLE>
On January 1, 1999, Sonat Power Marketing began accounting for its power
portfolio using mark to market accounting to apply the provisions of EITF 98-10,
Accounting for Contracts Involved in Energy Trading and Risk Management
Activities. The impact of adopting mark to market accounting was not material to
the financial position, results of operations or cash flows of the Company.
At December 31, 1998, MPC was a party to two interest rate swap agreements
which effectively converted $114 million of floating-rate debt to fixed-rate
debt (see Note 9). MPC made payments to counterparties at fixed rates and in
return received payments at floating rates. In October 1999, MPC terminated its
interest rate swaps at a cost of approximately $5 million. Interest expense and
cash requirements were $3 million higher in 1999, 1998, and 1997, respectively,
as a result of these swaps.
In August 1999, El Paso entered an interest rate swap agreement with a
notional amount of $600 million and a termination date of July 2001. In the
agreement, El Paso swapped the fixed interest rate on its July 1999 $600 million
aggregate principal Senior Notes due 2001, for a floating three month LIBOR plus
a rate margin of 14.75 basis points. The rate under the swap at December 31,
1999, was 6.19 percent. Total interest expense was approximately $1 million in
1999, as a result of this swap agreements.
In March 1997, the Company purchased a 10.5 percent interest in CAPSA, a
privately held Argentine company engaged in power generation and natural gas and
oil production for approximately $57 million. In connection with this
acquisition, the Company entered into an equity swap transaction associated with
an additional 18.5 percent of CAPSA's then outstanding stock. Under the swap,
the Company paid interest to the counterparty, on a quarterly basis, on a
notional amount of $100 million at a rate of LIBOR plus 0.85 percent. In
exchange, the Company receives dividends, if any, on the CAPSA stock to the
extent of the counterparty's equity interest of 18.5 percent. The Company also
fully participates in the market appreciation or depreciation of the underlying
investment whereby the Company will realize appreciation or fund any
depreciation attributable to the actual sale of the stock upon termination or
expiration of the swap transaction. The initial term of the swap was two years,
and in February 1999, the contract was extended for an additional two and
one-half years on a notional amount of $103 million and interest rate of LIBOR
plus 1.75 percent. Upon maturity or termination of the swap, the Company has a
right of first refusal to purchase the counterparty's
64
<PAGE> 69
18.5 percent investment in CAPSA common stock at the fair value of the stock at
that date or at a later date at a price offered by a good faith buyer. This
transaction is recorded using mark-to-market accounting.
The Company also faces credit risk with respect to its non-trading
activities, and takes similar measures as in its trading activities to mitigate
this risk. Based upon the Company's policies and risk exposure, the Company does
not anticipate a material effect on its financial position, results of
operations or cash flows resulting from counterparty non-performance.
8. PROPERTY, PLANT, AND EQUIPMENT
Property, plant, and equipment consisted of the following at December 31:
<TABLE>
<CAPTION>
1999 1998
------- -------
(IN MILLIONS)
<S> <C> <C>
Property, plant, and equipment, at cost
Natural Gas Transmission.................................. $ 8,121 $ 7,776
Merchant Energy........................................... 199 98
International............................................. 316 162
Field Services............................................ 1,221 1,180
Production................................................ 5,415 5,569
Corporate and Other....................................... 196 173
------- -------
15,468 14,958
Less accumulated depreciation and depletion................. 7,656 7,353
------- -------
7,812 7,605
Additional acquisition cost assigned to utility plant, net
of accumulated amortization............................... 2,449 2,481
------- -------
Total property, plant, and equipment, net................... $10,261 $10,086
======= =======
</TABLE>
9. DEBT AND OTHER CREDIT FACILITIES
The average interest rate of short-term borrowings was 6.6% and 5.9% at
December 31, 1999 and 1998, respectively. The Company had the following
short-term borrowings, including current maturities of long-term debt, at
December 31:
<TABLE>
<CAPTION>
1999 1998
------ ------
(IN MILLIONS)
<S> <C> <C>
Revolving credit facility................................... $ -- $ 350
Commercial paper............................................ 1,217 1,037
Other credit facilities..................................... 35 84
Current maturities of long-term debt........................ 92 179
------ ------
$1,344 $1,650
====== ======
</TABLE>
65
<PAGE> 70
Long-term debt outstanding consisted of the following at December 31:
<TABLE>
<CAPTION>
1999 1998
------ ------
(IN)MILLIONS
<S> <C> <C>
Long-term debt
El Paso Energy Corporation
Senior notes, 6.625% through 6.75%, due 2000 through
2009.................................................. $1,100 $ 4
Notes, 6.625% through 9.5%, due 1999 through 2018...... 1,200 700
Variable rate senior note due 2001, average interest
for 1999 of 6.35%..................................... 100 --
EPTPC
Notes, 7.25% through 10%, due 2008 through 2025........ 51 51
Debentures, 6.5% through 10.375%, due 1999 through
2005.................................................. 42 45
TGP
Debentures, 6% through 7.75%, due 2011 through 2037.... 1,386 1,386
EPNG
Notes, 6.75% through 9.45%, due 1999 through 2003...... 415 463
Debentures, 7.5% and 8.625%, due 2022 and 2026......... 460 460
SNG
Notes, 6.125% through 8.875%, due 2001 through 2008.... 500 500
EPEC Corporation
Note, 9.625%, due 2001................................. 13 13
DeepTech
Senior note, 12%, due 2000............................. 82 82
Subordinate note, 11%, due 2000........................ -- 15
Bear Creek
Senior secured notes 8.16% and 11.39%, due 1999........ -- 49
MPC
Variable rate project financing loan, due 1999 through
2007, average interest rate 7.8% for 1999 and 9.7% for
1998.................................................. -- 117
Other..................................................... 4 11
------ ------
5,353 3,896
Less: Unamortized discount................................ 38 25
Current maturities.................................. 92 179
------ ------
Long-term debt, less current maturities................... $5,223 $3,692
====== ======
</TABLE>
The following are aggregate maturities of the principal amounts of
long-term debt for the next 5 years and in total thereafter:
<TABLE>
<CAPTION>
(IN MILLIONS)
-------------
<S> <C>
2000........................................................ $ 92
2001........................................................ 938
2002........................................................ 427
2003........................................................ 200
2004........................................................ --
Thereafter.................................................. 3,696
------
Total long-term debt, including current
maturities....................................... $5,353
======
</TABLE>
Other Financing Arrangements
El Paso has both a $1,250 million 364-day and a $750 million five-year
revolving credit facility (collectively the "Revolving Credit Facility"). The
$1,250 million 364-day renewable revolving credit and competitive advance
facility was established in August 1999 and replaced El Paso's 1998, $750
million 364-day renewable revolving credit and competitive advance facility. The
$750 million five-year revolving credit and competitive advance facility was
established in October 1997. EPNG and TGP are designated borrowers under the
Revolving Credit Facility. The rate for the Revolving Credit Facility varies
based on El Paso's unsecured debt rating. As of December 31, 1999, the interest
rate for borrowing under the Revolving
66
<PAGE> 71
Credit Facility was equal to LIBOR plus 50 basis points, and no amounts were
outstanding. The available credit under the Revolving Credit Facility is
expected to be used for general corporate purposes including, but not limited
to, backstopping TGP's and EPNG's combined $2 billion commercial paper program.
The availability of borrowings under the Company's credit agreements is
subject to specified conditions, which management believes the Company currently
meets. These conditions include compliance with the financial covenants and
ratios required by such agreements, absence of default under such agreements,
and continued accuracy of the representations and warranties contained in such
agreements (including the absence of any material adverse changes in the
Company). All of the Company's senior debt issues have been given investment
grade ratings by Standard & Poor's and Moody's.
In September 1998, TGP filed a shelf registration permitting it to offer up
to $600 million of debt securities. In October 1998, TGP issued $400 million
aggregate principal amount of 7% debentures due 2028. After this issuance, TGP
has $200 million of capacity remaining under its shelf registration.
SNG has a shelf registration which provides for the issuance of up to $500
million in debt securities. In 1998, SNG issued $100 million aggregate principal
amount of 6.625% notes due 2008. As a result, SNG has $400 million of capacity
remaining under its shelf registration.
In May 1999, El Paso issued $500 million aggregate principal amount of
6.75% Senior Notes due 2009. Proceeds of approximately $496 million, net of
issuance costs, were used to repay short-term debt and for other corporate
purposes.
In 1999, the Company received net proceeds of $960 million from a
third-party investor as a result of the sale of a preferred interest in Trinity
River Associates, L.L.C., a consolidated joint venture in which the Company has
a 20 percent interest. The proceeds were used to repay short-term debt and for
other corporate purposes.
In July 1999, El Paso issued $600 million aggregate principal amount of
6.625% Senior Notes due 2001 and $100 million aggregate principal amount of
floating rate Senior Notes due 2001. Proceeds of approximately $697 million, net
of issuance costs, were used to repay short-term borrowings and for other
corporate purposes. Also in July, Sonat issued $600 million aggregate principal
amount of 7.625% Notes due 2011. Proceeds of approximately $590 million, net of
issuance cost, were used to repay short-term borrowings.
In August 1999, El Paso filed a shelf registration statement pursuant to
which it may offer up to $900 million (including $65 million transferred from
prior shelf registrations) of common or preferred equity, various forms of debt
securities (including convertible debt securities), and trust preferred
securities. These securities may be issued from time to time as determined by
market conditions. In December 1999, El Paso modified this registration to allow
up to $600 million of the $900 million to be used for the issuance of
medium-term notes. At December 31, 1999, no securities have been issued under
this shelf registration.
In 1999, El Paso received proceeds of approximately $121 million from the
issuance of demand notes payable to Chaparral Investors, L.L.C. The notes are
due on demand and have a variable rate of LIBOR plus 75 basis points.
In January 2000, El Paso established and borrowed under a $250 million
non-committed line of credit with a financial institution.
In November 1999, Bear Creek Capital Corporation retired its 8.16% Series A
Note and its 11.39% Series B Note with an aggregate principal amount of $42
million, and EPTPC retired its 8% notes with an aggregate principal of $3
million. In February 1999, DeepTech retired its 11% senior promissory note due
2000 in the amount of $16 million and in September 1999, EPNG retired its
outstanding 9.45% note with a principal amount of $47 million. In August 1999,
Sonat retired its outstanding 9.5% note with a principal amount of $100 million.
In October 1999, MPC retired its variable rate non-recourse project financing
with a principal amount of $107 million. Concurrently, MPC also terminated its
associated interest rate swap at a cost of approximately $5 million.
67
<PAGE> 72
10. COMMITMENTS AND CONTINGENCIES
International Project Contingencies
International is subject to various claims that arise in the ordinary
course of its project activities. These claims include, among other things,
those relating to project delays, contractual disputes and/or the adverse impact
of uncertainties and risks related to unstable currencies or governments that
arise in the countries where International conducts business. International
attempts to mitigate its risks through the use of indemnification clauses,
private and public insurance, denominating transactions in United States
dollars, where possible, and other activities it deems necessary. Where losses
are both probable and estimable, International establishes reserves. However,
despite International's efforts to mitigate its risks and establish appropriate
reserves, unreserved losses can occur. While management cannot predict with
certainty the final outcome of its currently pending issues and matters, it
believes, based on experience to date and after considering reserves that have
been established, that the resolution of currently pending issues and matters
will not have a material adverse effect on the Company's financial position,
results of operations, or cash flows.
The Company has a non-controlling interest in a project in Senkang, South
Sulawesi, Indonesia with a total investment of approximately $28 million.
Throughout 1999, the project faced difficulties stemming from Indonesia's weak
economy and the devaluation of its currency. Currently, the project is operating
under an interim agreement while the Company negotiates long-term resolutions to
existing and past contract terms. The Company carries political risk insurance
coverage for the Indonesian project. Furthermore, all project debt is
non-recourse to the Company. The Company believes that the current economic
difficulties in Indonesia will not have a material adverse effect on the
Company's financial position, results of operations or cash flows.
Capital Commitments
At December 31, 1999, the Company had capital and investment commitments of
$497 million. The Company's other planned capital and investment projects are
discretionary in nature, with no substantial capital commitments made in advance
of the actual expenditures.
Purchase Obligations
In connection with the financing commitments of certain joint ventures, TGP
has entered into unconditional purchase obligations for products and services
totaling $56 million at December 31, 1999. TGP's annual obligations under these
agreements are $21 million for 2000, $11 million for the year 2001, $4 million
for the years 2002, 2003 and 2004, and $12 million in total thereafter. Excluded
from these amounts is TGP's obligation to purchase 30 percent of the output of
the Great Plains coal gasification project's original design capacity through
July 2009. In January 1997, TGP settled this contract as part of its GSR
negotiations, recorded the related liability, and purchased an annuity for $42
million to fund the expected remaining monthly demand requirements of the
contract which continue through January 2004.
Operating Leases
The Company leases certain 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
which time EPNC has an option, and an obligation upon the occurrence of certain
events, to purchase the plant for a price sufficient to pay the amount of the
$77 million construction financing, plus interest and certain expenses. If EPNC
does not purchase the plant at the end of the lease term, it has an obligation
to pay a residual guaranty amount equal to approximately 87 percent of the
amount financed, plus interest. The Company unconditionally guaranteed all
obligations of EPNC under this lease.
68
<PAGE> 73
Minimum annual rental commitments at December 31, 1999, were as follows:
<TABLE>
<CAPTION>
YEAR ENDING
DECEMBER 31, OPERATING LEASES
- ------------------------------------------------------------ ----------------
(IN MILLIONS)
<S> <C>
2000..................................................... $ 27
2001..................................................... 27
2002..................................................... 21
2003..................................................... 20
2004..................................................... 20
Thereafter............................................... 88
----
Total............................................. $203
====
</TABLE>
Aggregate minimum commitments have not been reduced by minimum sublease
rentals of approximately $15 million due in the future under noncancelable
subleases.
Rental expense for operating leases for the years ended December 31, 1999,
1998, and 1997 was $37 million, $39 million, and $33 million, respectively.
Guarantees
At December 31, 1999, the Company had parental guarantees of approximately
$995 million in connection with its international development activities and
various other projects. The Company also had outstanding letters of credit of
approximately $170 million at December 31, 1999.
Rates and Regulatory Matters
The Company's interstate natural gas pipeline companies are subject to the
regulatory jurisdiction of the FERC with respect to rates, terms and conditions
of service, accounts and records, the addition of facilities, the abandonment of
services and facilities, the curtailment of gas deliveries and other matters.
The interstate natural gas pipelines have various pending regulatory proceedings
including, but not limited to, issues relating to SNG's August 1999 rate case
filing, EPNG's June 1995 rate case filing and TGP's December 1996 rate case
filing. As rate and regulatory matters are fully and unconditionally resolved,
the Company may either recognize an additional refund obligation or a non-cash
benefit to finalize previously estimated liabilities.
Each of the Company's pipeline systems has contracts covering a portion of
their firm transportation capacity which have various terms of maturity.
Additionally, each of these systems operate in different markets and regions
with different competitive and regulatory pressures which can impact the ability
of these systems to renegotiate and renew existing contracts, or enter into new
long-term firm transportation commitments. At December 31, 1999, TGP has
contracts representing 20 percent of its firm transportation capacity expiring
by November 2000. SNG has 43 percent of its firm transportation capacity due to
expire primarily in 2003. EPNG has a portion of its capacity subscribed under
shorter-term contracts primarily through 2001. Each of the Company's systems has
aggressively pursued the renegotiation and renewal of its expiring contracts,
and the sale of excess capacity under firm transportation arrangements, and has
made progress in its efforts. However, it is uncertain if future contracts will
be on terms as favorable to the Company as those that exist currently.
Furthermore, new and renewed contracts can be disputed by customers and other
groups, and there is no certainty that regulators or other jurisdictional bodies
will not intercede in the re-contracting process and alter the ultimate outcome
of these efforts.
All of EPNG's customers, except Edison participate in risk sharing
provisions under EPNG's rate case settlement. Under these provisions, EPNG
received and continues to receive cash payments for the risk it assumed from
certain capacity relinquishments by its customers at the end of 1997. The cash
received is deferred, and EPNG recognizes this deferral in revenues ratably over
the risk sharing period. As of December 31, 1999, the Company had unearned risk
sharing revenues of approximately $127 million and had $54 million remaining to
be collected from customers under this provision. If EPNG remarkets its
69
<PAGE> 74
relinquished capacity to customers above certain dollar levels specified in the
risk sharing agreement, it may be obligated to refund the excess to customers.
For the year ended December 31, 1999, EPNG refunded approximately $8 million to
customers under this provision, and has accrued approximately $7 million for
refunds to be made in 2000. The risk sharing provisions of the rate settlement
extend through 2003, at which time EPNG will be at risk for all unsubscribed,
excess capacity on its system.
In July 1998, FERC issued a Notice of Proposed Rulemaking ("NOPR") in which
it sought comments on a wide range of initiatives to change the manner in which
short-term (less than one year) transportation markets are regulated. On
February 9, 2000, the FERC issued a final ruling in response to the NOPR. Among
other things, the rule (i) allows pipelines to file to implement peak and
off-peak rates; (ii) removes the price cap for released capacity; (iii) requires
pipelines to make changes to its tariffs regarding customer imbalances,
penalties and pipeline operations; and (iv) increases the amount and type of
information that pipelines must make available to the FERC and its customers.
While management cannot predict with certainty the final outcome, or
timing, of the final resolution of rates and regulatory matters, the outcome of
its current re-contracting and capacity subscription efforts, or the outcome of
industry trends and initiatives, management believes, based upon its experience
to date and after considering appropriate reserves that have been established,
that the ultimate resolution of these pending rate and regulatory matters will
not have a material adverse effect on the Company's financial position, results
of operations, or cash flows.
Legal Proceedings
In November 1993, TransAmerican Natural Gas Corporation ("TransAmerican")
filed a complaint in a Texas state court which, as amended, seeks approximately
$7.5 billion in actual and punitive damages related to a 1990 settlement
agreement between EPNG, TransAmerican, and others. TransAmerican's complaint, as
amended, advanced ten causes of action against defendants, which include EPNG,
Coastal, entities related to both of them, and certain of their present and
former officers and directors. As a result of orders by the court on various
motions for summary judgment made on behalf of EPNG, its affiliated entities and
its present and former officers and directors, six causes of action have been
dismissed in their entirety and one has been partially dismissed. The partially
dismissed claim alleges fraud, and the other claims that remain pending allege
breach of contract, bad faith and violation of the Texas Antitrust Act. With
respect to the fraud claim, the court dismissed TransAmerican's claim that it
was fraudulently induced to enter into the settlement transaction, but refused
to dismiss the remainder of the fraud claim, in which TransAmerican alleges
misrepresentations in the settlement documents. Motions for summary judgment on
TransAmerican's other remaining claims are expected to be heard and decided by
the court prior to the current trial setting of April 24, 2000. Additionally,
EPNG has filed a breach of contract counterclaim against TransAmerican seeking
to recover EPNG's expenses incurred in connection with the lawsuit.
TransAmerican's motion for summary judgment on this counterclaim was denied by
the court. In April 1996, a former employee of TransAmerican filed a related
case in Harris County, Texas, Vickroy E. Stone v. Godwin & Carlton, P.C., et al.
("Stone"), seeking other damages in unspecified amounts related to litigation
consulting work allegedly performed for various entities, including EPNG, in
cases involving TransAmerican. In June 1998, the court granted EPNG's motion for
summary judgment and dismissed all claims in the Stone litigation. Stone has
appealed the court's ruling to the Texas Court of Appeals in Houston, Texas.
Based on information available at this time, management believes that the claims
asserted against it in both cases have no factual or legal basis.
In February 1998, the United States and the State of Texas filed in a
United States District Court a Comprehensive Environmental Response,
Compensation and Liability Act ("CERCLA" or "Superfund") cost recovery action
against fourteen companies including the Company and certain of its affiliated
companies relating to the Sikes Disposal Pits Superfund Site ("Sikes") located
in Harris County, Texas. The suit claims that the United States and the State of
Texas have expended over $125 million in remediating Sikes, and seeks to recover
that amount plus interest from all defendants to the suit. Although factual
investigation relating to Sikes is in the preliminary stages, the Company
believes that the amount of material, if any, disposed at Sikes by the Company
was small, possibly de minimis. However, the plaintiffs have alleged that
70
<PAGE> 75
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 by TGP of a lubricant containing PCBs in its starting air
systems. TGP has executed a consent order with the EPA governing the remediation
of certain of its compressor stations and is working with the 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 without a permit and disposed of PCBs without a permit. The agency
sought an injunction against future discharges, sought an order to remediate or
remove PCBs, and sought a civil penalty. TGP has entered into agreed orders with
the agency to resolve many of the issues raised in the original allegations, has
received water discharge permits for its Kentucky compressor stations from the
agency, and continues to work to resolve the remaining issues. The relevant
Kentucky compressor stations are scheduled to be characterized and remediated
under the consent order with the EPA.
A number of subsidiaries of El Paso, both wholly and partially owned, have
been named defendants in actions brought by Jack Grynberg on behalf of the U.S.
Government under the False Claims Act. Generally, the complaints allege an
industry-wide conspiracy to underreport the heating value as well as the volumes
of the natural gas produced from federal and Indian lands, thereby depriving the
United States Government of royalties. The Company believes the complaint to be
without merit.
A number of subsidiaries of El Paso, both wholly and partially owned, have
been named defendants in a class action suit, Quinque Operating Company v. Gas
Pipelines. The Plaintiff alleges that the defendants have mismeasured natural
gas volumes and heating content of natural gas on non-federal and non-Native
American lands. This suit is similar to the action brought by Jack Grynberg on
behalf of the United States Government. The Company believes the complaint to be
without merit.
The Company is also a named defendant in numerous lawsuits and a named
party in numerous governmental proceedings arising in the ordinary course of its
business.
While the outcome of the matters discussed above cannot be predicted with
certainty, management currently does not expect the ultimate resolution of these
matters to have a material adverse effect on the Company's financial position,
its results of operations, or cash flows.
Environmental
The Company is subject to extensive federal, state, and local laws and
regulations governing environmental quality and pollution control. These laws
and regulations require the Company to remove or remedy the effect on the
environment of the disposal or release of specified substances at current and
former operating sites. As of December 31, 1999, the Company had a reserve of
approximately $245 million for expected remediation costs, including
approximately $233 million for associated onsite, offsite and groundwater
technical studies, and approximately $12 million for other costs which the
Company anticipates incurring through 2027.
In addition, the Company estimates that its subsidiaries will make capital
expenditures for environmental matters of approximately $3 million in 2000.
Capital expenditures are estimated to total approximately $103 million in the
aggregate for the years 2001 through 2007. These expenditures primarily relate
to compliance with air regulations and, to a lesser extent, control of water
discharges.
Since 1988, TGP has been engaged in an internal project to identify and
deal with the presence of PCBs and other substances of concern, including
substances on the EPA List of Hazardous Substances, at compressor stations and
other facilities operated by both its interstate and intrastate natural gas
pipeline systems. While conducting this project, TGP has been in frequent
contact with federal and state regulatory
71
<PAGE> 76
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 with FERC
a separate Stipulation and Agreement (the "Environmental Stipulation") that
established a mechanism for recovering a substantial portion of the
environmental costs identified in the internal project. The Environmental
Stipulation was effective July 1, 1995, and as of December 31, 1999, all amounts
have been collected thereunder. Refunds may be required to the extent actual
eligible expenditures are less than amounts collected.
The Company and certain of its subsidiaries have been designated, have
received notice that they could be designated, or have been asked for
information to determine whether they could be designated as a PRP with respect
to 33 sites under the Comprehensive Environmental Response, Compensation and
Liability Act (CERCLA or Superfund) or state equivalents. The Company has sought
to resolve its liability as a PRP with respect to these Superfund sites through
indemnification by third parties and/or settlements which provide for payment of
the Company's allocable share of remediation costs. As of December 31, 1999, the
Company has estimated its share of the remediation costs at these sites to be
between $76 million and $94 million and has provided reserves that it believes
are adequate for such costs. Since the clean-up costs are estimates and are
subject to revision as more information becomes available about the extent of
remediation required, and because in some cases the Company has asserted a
defense to any liability, the Company's estimate of its share of remediation
costs could change. Moreover, liability under the federal Superfund statute is
joint and several, meaning that the Company could be required to pay in excess
of its pro rata share of remediation costs. The Company's understanding of the
financial strength of other PRPs has been considered, where appropriate, in its
determination of its estimated liability as described herein. The Company
presently believes that the costs associated with the current status of such
entities as PRPs at the Superfund sites referenced above will not have a
material adverse effect on the Company's financial position, results of
operations, or cash flows.
The Company has initiated proceedings against its historic liability
insurers seeking payment or reimbursement of costs and liabilities associated
with environmental matters. In these proceedings, the Company contends that
certain environmental costs and liabilities associated with various entities or
sites, including costs associated with former operating sites, must be paid or
reimbursed by certain of its historic insurers. The proceedings are in the
discovery stage, and it is not yet possible to predict the outcome of this
matter.
It is possible that new information or future developments could require
the Company to reassess its potential exposure related to environmental matters.
The Company may incur significant costs and liabilities in order to comply with
existing environmental laws and regulations. It is also possible that other
developments, such as increasingly strict environmental laws, regulations and
enforcement policies thereunder, and claims for damages to property, employees,
other persons and the environment resulting from current or discontinued
operations, could result in substantial costs and liabilities in the future. As
such information becomes available, or other relevant developments occur,
related accrual amounts will be adjusted accordingly. While there are still
uncertainties relating to the ultimate costs which may be incurred, based upon
the Company's evaluation and experience to date, the Company believes the
recorded reserves are adequate.
For a further discussion of specific environmental matters, see Legal
Proceedings above.
11. RETIREMENT BENEFITS
Pension Benefits
Prior to January 1, 1997, the Company maintained a defined benefit pension
plan covering substantially all employees of EPNG and EPFS. Pension benefits
were based on years of credited service and final five year average
compensation, subject to maximum limitations as defined in the pension plan.
Effective January 1, 1997, the plan was amended to provide benefits
determined by a cash balance formula and to include employees added as a result
of the merger of El Paso with EPTPC and other
72
<PAGE> 77
acquisitions prior to 1997. Employees who were pension plan participants on
December 31, 1996, receive the greater of cash balance benefits or prior plan
benefits accrued through December 31, 2001.
Following the merger with Sonat, the Company offered an early retirement
incentive program to Sonat employees who were at least 50 years of age with 10
years of service as of December 31, 1999, and who terminate employment by June
30, 2000. Total charges as a result of the early retirement program were
approximately $8 million.
Effective January 1, 2000, the Sonat pension plans were merged into the
Company pension plans. Sonat employees who were participants in the Sonat
pension plan on the Sonat merger effective date receive the greater of cash
balance benefits or the Sonat plan benefits accrued through December 31, 2004.
Other Postretirement Benefits
The Company provides postretirement medical benefits for certain closed
groups of retired employees of EPNG, EPTPC and Sonat, and limited postretirement
life insurance benefits for current and retired employees. Other postretirement
employee benefits ("OPEB") are prefunded to the extent such costs are
recoverable through rates. To the extent actual OPEB costs for TGP, EPNG, or SNG
differ from the amounts recovered in rates, a regulatory asset or liability is
recorded.
Under the Company's early retirement incentive program for Sonat employees,
participating eligible employees were allowed to keep postretirement medical and
life benefits commencing at the later of age 55 or retirement. Total charges
associated with this incentive program and the elimination of retiree benefits
for future retirees were $29 million and were accrued as of December 31, 1999.
Medical benefits for this closed group of retirees may be subject to
deductibles, co-payment provisions, and other limitations and dollar caps on the
amount of employer costs. The Company has reserved the right to change these
benefits.
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 pension benefits and other postretirement benefits. In 1998,
the Company changed the measurement date for measuring its pension and OPEB
obligations from December 31 to September 30. This measurement date was also
assumed for Sonat Plan results included herein.
<TABLE>
<CAPTION>
POSTRETIREMENT
PENSION BENEFITS BENEFITS
----------------- ---------------
1999 1998 1999 1998
------- ------- ------ ------
(IN MILLIONS)
<S> <C> <C> <C> <C>
Change in benefit obligation
Benefit obligation at beginning of period................. $ 953 $ 907 $ 494 $ 500
Service cost.............................................. 21 22 2 2
Interest cost............................................. 57 64 33 33
Participant contributions................................. -- -- 8 5
Plan amendments........................................... (18) -- (13) (25)
Settlements, curtailments and special termination
benefits............................................... 3 (2) 6 --
Actuarial (gain) or loss.................................. (92) 24 24 31
Benefits paid............................................. (65) (62) (65) (52)
------ ------ ----- -----
Benefit obligation at end of period....................... $ 859 $ 953 $ 489 $ 494
====== ====== ===== =====
Change in plan assets
Fair value of plan assets at beginning of period.......... $1,126 $1,098 $ 112 $ 94
Actual return on plan assets.............................. 90 83 9 9
Employer contributions.................................... 7 7 62 56
Participant contributions................................. -- -- 8 5
Benefits paid............................................. (65) (62) (65) (52)
------ ------ ----- -----
Fair value of plan assets at end of period................ $1,158 $1,126 $ 126 $ 112
====== ====== ===== =====
</TABLE>
73
<PAGE> 78
<TABLE>
<CAPTION>
POSTRETIREMENT
PENSION BENEFITS BENEFITS
----------------- ---------------
1999 1998 1999 1998
------- ------- ------ ------
(IN MILLIONS)
<S> <C> <C> <C> <C>
Reconciliation of funded status
Funded status at end of period............................ $ 299 $ 174 $(363) $(382)
Fourth quarter contributions and income................... 31 5 15 15
Unrecognized net actuarial (gain) or loss................. (246) (137) (3) (33)
Unrecognized net transition obligation.................... -- (1) 46 97
Unrecognized prior service cost........................... (46) (30) (11) (10)
------ ------ ----- -----
Prepaid (accrued) benefit cost at December 31,............ $ 38 $ 11 $(316) $(313)
====== ====== ===== =====
</TABLE>
Included in the pension benefits information are certain plans in which the
projected benefit obligation and accumulated benefit obligation for pension
plans with accumulated benefit obligations in excess of plan assets were $57
million and $53 million as of December 31, 1999, and $51 million and $34 million
as of December 31, 1998, respectively.
The current liability portion of the postretirement benefits was $46
million as of December 31, 1999 and 1998. Benefit obligations are based upon
certain actuarial estimates as described below.
<TABLE>
<CAPTION>
POSTRETIREMENT
PENSION BENEFITS BENEFITS
------------------- ------------------
YEAR ENDED DECEMBER 31,
----------------------------------------
1999 1998 1997 1999 1998 1997
----- ---- ---- ---- ---- ----
(IN MILLIONS)
<S> <C> <C> <C> <C> <C> <C>
Benefit cost for the plans includes the following
components
Service cost...................................... $ 23 $ 22 $ 20 $ 2 $ 2 $ 2
Interest cost..................................... 65 64 64 33 33 37
Expected return on plan assets.................... (104) (96) (83) (8) (6) (5)
Amortization of net actuarial gain................ (2) (2) (2) (1) (2) (5)
Amortization of transition obligation............. 2 -- -- 10 11 12
Amortization of prior service cost................ (2) (2) (2) (1) (1) --
Settlements, curtailment, and special termination
benefits expense............................... 1 (1) -- 29 6 2
----- ---- ---- --- --- ---
Net benefit cost.................................. $ (17) $(15) $ (3) $64 $43 $43
===== ==== ==== === === ===
</TABLE>
<TABLE>
<CAPTION>
POSTRETIREMENT
PENSION BENEFITS BENEFITS
---------------- --------------
1999 1998(1) 1999 1998(1)
----- -------- ---- -------
<S> <C> <C> <C> <C>
Weighted average assumptions
Discount rate............................................. 7.50% 6.86% 7.50% 6.79%
Expected return on plan assets............................ 9.98% 9.94% 7.50% 8.81%
Rate of compensation increase............................. 4.64% 4.72% -- --
</TABLE>
- ---------------
(1) Reflects weighted average of El Paso and Sonat plan assumptions.
Actuarial estimates for the Company's postretirement benefits plans assumed
a weighted average annual rate of increase in the per capita costs of covered
health care benefits of 10 percent through 2000, gradually decreasing to 6
percent by the year 2008. In 1998, Sonat assumed a health cost trend rate of 4.5
percent for all years. Assumed health care cost trends have a significant effect
on the amounts reported for other
74
<PAGE> 79
postretirement benefit plans. A one-percentage point change from assumed health
care cost trend rates would have the following effects:
<TABLE>
<CAPTION>
1999 1998
----- -----
(IN MILLIONS)
<S> <C> <C>
One Percentage Point Increase
Aggregate of Service Cost and Interest Cost............... $ 2 $ 2
Accumulated Postretirement Benefit Obligation............. $ 23 $ 19
One Percentage Point Decrease
Aggregate of Service Cost and Interest Cost............... $ (2) $ (2)
Accumulated Postretirement Benefit Obligation............. $(21) $(17)
</TABLE>
Retirement Savings Plan
The Company maintains a defined contribution plan covering all employees of
the Company. The Company matches 75 percent of participant basic contributions
of up to 6 percent, with the matching contribution being made in Company stock.
Prior to the merger, Sonat matched 100 percent of participant basic
contributions of up to 6 percent. Amounts expensed under the plan were
approximately $16 million, $16 million and $11 million for the years ended
December 31, 1999, 1998, and 1997, respectively.
12. TRUST PREFERRED SECURITIES
In March 1998, El Paso Energy Capital Trust I (the "Trust") issued 6.5
million of 4 3/4% trust convertible preferred securities (the "Trust Preferred
Securities") for $325 million ($317 million, net of issuance costs). In
addition, the Trust issued approximately $10 million of trust convertible common
securities to EPNG. The net proceeds were used by EPNG to pay down commercial
paper. The Trust exists for the sole purpose of issuing Trust Preferred
Securities and investing the proceeds in 4 3/4% convertible subordinated
debentures due 2028 (the "Trust Debentures") of EPNG, the Trust's sole asset.
EPNG executed a full and unconditional subordinated guarantee of the Trust
Preferred Securities.
As a result of the holding company reorganization discussed in Note 1, El
Paso assumed ownership of the Trust, as well as the obligations of the Trust
Debentures, and the guarantee of the Trust's obligations under the Trust
Preferred Securities. The results of the Trust are consolidated with those of
the Company and, therefore, the Trust Debentures are eliminated and the Trust
Preferred Securities are reflected as company-obligated mandatorily redeemable
convertible preferred securities of El Paso Energy Capital Trust I in the
Consolidated Balance Sheets. Distributions paid on Trust Preferred Securities
are included as Minority interest in the Consolidated Statements of Income.
The Trust Preferred Securities are non-voting (except in limited
circumstances), pay quarterly distributions at an annual rate of 4 3/4%, carry a
liquidation value of $50 per security plus accrued and unpaid distributions and
are convertible into the Company's common shares at any time prior to the close
of business on March 31, 2028, at the option of the holder at a rate of 1.2022
common shares for each Trust Preferred Security (equivalent to a conversion
price of $41.59 per common share), subject to adjustment in certain
circumstances.
13. MINORITY INTEREST
Trinity River
During 1999, the Company formed Sabine River Investors, L.L.C. ("Sabine"),
a wholly owned limited liability company, and other separate legal entities, for
the purpose of generating funds to invest in capital projects and other assets.
Through its ownership in Sabine, the Company contributed $250 million of equity
capital to Trinity River Associates, L.L.C. ("Trinity"), in exchange for a
managing member interest in Trinity. A third-party investor contributed $980
million of equity capital to Trinity for a non-controlling, preferred interest.
The third-party investor is entitled to an adjustable preferred return derived
from Trinity's net income. As of December 31, 1999, the minority interest
expense recorded in the Consolidated Statements
75
<PAGE> 80
of Income is $21 million. Proceeds from the equity contributions were used by
Trinity to invest in a note receivable from Sabine collateralized by certain
assets of the Company. The Company has the option to acquire the third-party
investor's interest in Trinity at any time prior to June 2004. If the Company
does not exercise this option, and if the Company and the third-party investor
do not agree to extend the terms of their agreement, Trinity's note receivable
from Sabine will mature and a portion of the proceeds therefrom will be used by
Trinity to redeem the third-party investor's interest in Trinity. The assets,
liabilities and operations of Sabine, Trinity and other entities involved in
this transaction are included in the Company's consolidated financial
statements. The third-party investor's interest is included as Minority interest
in the Consolidated Balance Sheets.
Preferred Stock of Subsidiary
In November 1996, EPTPC issued 6 million shares of 8.25% cumulative
preferred stock with a par value of $50 per share for $296 million (net of
issuance costs). The preferred stock is redeemable, at the option of EPTPC,
after December 31, 2001, at a redemption price equal to $50 per share, plus
dividends accrued and unpaid up to the date of redemption. During 1999, 1998,
and 1997, dividends of approximately $25 million, were paid each year on the
preferred stock. This preferred stock is included as Minority interest to the
Consolidated Balance Sheets.
14. CAPITAL STOCK
In June 1999, the stockholders of El Paso approved an amendment to El
Paso's Restated Certificate of Incorporation to authorize the issuance of up to
750 million shares of common stock and 50 million shares of preferred stock.
Common Stock
In October 1999, approximately 110 million shares of Company common stock
were issued in connection with the acquisition of Sonat. Such shares were valued
at approximately $4.5 billion. In March 1999, approximately .3 million shares of
Company common stock valued at approximately $10 million were issued in
connection with the acquisition of EnCap.
In October 1997, approximately .8 million shares of Company common stock,
valued at approximately $21 million, were issued in connection with the
acquisition of Gulf States Gas Pipeline Company. In February 1997, approximately
6 million shares of Company common stock, valued at approximately $152 million,
were issued in a public offering registered under the Securities Act of 1933, as
amended.
Treasury Stock
From time to time, the Board has authorized the repurchase of El Paso's
outstanding shares of common stock to be used in connection with El Paso
employee stock-based compensation plans and for other corporate purposes. During
1998, the Company repurchased approximately 1,052,000 common shares at a
weighted average cost of approximately $36 per share. In July 1999, the Company
rescinded its common stock repurchase program in order to comply with the
requirements to treat its merger with Sonat as a pooling of interests under
generally accepted accounting principles. The program originally authorized El
Paso to repurchase up to 10 million shares. As of December 31, 1999, and 1998,
El Paso held 8,947,565 and 5,494,772 shares of treasury stock, respectively.
Included in the balance at December 31, 1999, were 5,845,269 shares of treasury
stock used to secure benefits under certain of the Company's benefit plans which
are subject to certain restrictions.
Stock Dividend
In January 1998, the Board declared a two-for-one stock split in the form
of a 100 percent stock dividend (on a per share basis). The stock dividend of an
aggregate of 60,944,417 shares of common stock was paid on April 1, 1998 to
stockholders of record on March 13, 1998. All presentations herein are made on a
post-split basis.
76
<PAGE> 81
Other
El Paso has 50,000,000 shares of authorized preferred stock, par value
$0.01 per share, none of which have been issued, but of which 7,500,000 shares
have been designated as Series A Junior Participating Preferred Stock and
reserved for issuance pursuant to the Company's preferred stock purchase rights
plan.
15. STOCK-BASED COMPENSATION
During 1999, 1998, and 1997 the Company granted stock options under various
stock option plans (the "Plans"). The Company applies Accounting Principles
Board Opinion No. 25 and its related Interpretations in accounting for these
Plans. In 1995, the Financial Accounting Standards Board issued SFAS No. 123,
Accounting for Stock-Based Compensation which, if fully adopted, changes the
methods companies use in determining expense related to their stock option
plans. Adoption of the expense recognition provisions of SFAS No. 123 was
optional and the Company elected not to apply its provisions. However, pro forma
disclosures as if the Company had adopted the expense recognition provisions of
SFAS No. 123 are presented below.
Under the Company's existing stock option plans, the Company is authorized
to issue shares of common stock to employees and non-employee directors pursuant
to awards granted as incentive stock options (intended to qualify under Section
422 of the Internal Revenue Code), non-qualified stock options, restricted
stock, stock appreciation rights ("SARs"), phantom stock options, and
performance units.
Non-qualified Stock Options
The Company granted non-qualified stock options in 1999, 1998, and 1997
under its stock option plans. The stock options granted during these periods
have contractual terms of 10 years and generally vest after completion of one to
five years of continuous employment from the grant date. Options are also
granted to non-employee members of the Board at fair market value on the date of
grant and are exercisable immediately. Under the terms of certain plans, El Paso
may grant SARs to certain holders of stock options. SARs are subject to the same
terms and conditions as the related stock options. As of December 31, 1999,
44,710 SARs were outstanding which have been included in stock options as part
of tandem awards. The stock option holder who has been granted tandem SARs can
elect to exercise either an option or a SAR. SARs entitle an option holder to
receive a payment equal to the difference between the option price and the fair
market value of the common stock of El Paso at the date of exercise of the SAR.
To the extent a SAR is exercised, the related option is canceled, and to the
extent an option is exercised, the related SAR is canceled. Currently, the SARs
are being accounted for as compensation expense under Accounting Principles
Board Opinion No. 25 and are not considered for purposes of computing fair value
of outstanding options using the Black-Scholes option pricing model as described
below.
A summary of the status of the Company's stock options as of December 31,
1999, 1998, and 1997 is presented below:
<TABLE>
<CAPTION>
STOCK OPTIONS
------------------------------------------------------------------------
1999 1998 1997
---------------------- ---------------------- ----------------------
WEIGHTED WEIGHTED WEIGHTED
# SHARES OF AVERAGE # SHARES OF AVERAGE # SHARES OF AVERAGE
UNDERLYING EXERCISE UNDERLYING EXERCISE UNDERLYING EXERCISE
OPTIONS PRICES OPTIONS PRICES OPTIONS PRICES
----------- -------- ----------- -------- ----------- --------
<S> <C> <C> <C> <C> <C> <C>
Outstanding at beginning of the
year............................ 15,331,658 $25.46 13,198,433 $22.86 13,025,416 $20.43
Granted......................... 9,639,750 $41.02 3,651,550 $32.34 2,487,600 $31.27
Exercised....................... 2,092,953 $18.26 1,262,775 $17.77 2,097,283 $17.53
Forfeited....................... 366,751 $31.15 255,550 $27.99 217,300 $24.14
---------- ---------- ----------
Outstanding at end of year........ 22,511,704 $32.80 15,331,658 $25.46 13,198,433 $22.86
========== ========== ==========
Exercisable at end of year........ 12,996,454 $26.71 8,486,647 $22.35 7,223,927 $20.76
========== ========== ==========
</TABLE>
77
<PAGE> 82
The fair value of each stock option granted is estimated on the date of
grant using the Black-Scholes option-pricing model with the following
weighted-average assumptions:
<TABLE>
<CAPTION>
ASSUMPTION: 1999 1998 1997
----------- ----- ----- -----
<S> <C> <C> <C>
Expected Term in Years...................................... 7 5 3
Expected Volatility......................................... 21.9% 20.3% 17.3%
Expected Dividends.......................................... 3.0% 3.0% 3.0%
Risk-Free Interest Rate..................................... 6.3% 4.6% 6.3%
</TABLE>
The Black-Scholes weighted average fair value of options granted during
1999, 1998 and 1997 was $11.42, $7.00, and $3.86, respectively.
Options outstanding as of December 31, 1999 are summarized below:
<TABLE>
<CAPTION>
OPTIONS OUTSTANDING OPTIONS EXERCISABLE
------------------------------------------------- -----------------------------
NUMBER WEIGHTED AVERAGE WEIGHTED NUMBER WEIGHTED
RANGE OF OUTSTANDING REMAINING AVERAGE EXERCISABLE AVERAGE
EXERCISE PRICES AT 12/31/99 CONTRACTUAL LIFE EXERCISE PRICE AT 12/31/99 EXERCISE PRICE
--------------- ----------- ---------------- -------------- ----------- --------------
<S> <C> <C> <C> <C> <C>
$ 7.75 to $20.80 4,480,729 4.6 $15.49 4,480,729 $15.49
$20.81 to $31.20 4,337,075 6.1 $26.81 4,337,075 $26.81
$31.21 to $41.60 5,049,680 8.5 $35.88 2,690,430 $33.98
$41.61 to $52.00 8,644,220 9.4 $42.98 1,488,220 $47.08
---------- ----------
$ 7.75 to $52.00 22,511,704 7.6 $32.80 12,996,454 $26.71
========== ==========
</TABLE>
Restricted Stock
Under the Company's various stock-based compensation plans, a limited
number of shares of restricted Company common stock may be granted at no cost to
certain key officers and employees. These shares carry voting and dividend
rights; however, sale or transfer of the shares is restricted in accordance with
the vesting procedures. These restricted stock awards vest over a specific
period of time and/or if the Company achieves certain performance targets.
Restricted stock awards representing 1.4 million, .6 million, and .8 million
shares were granted during 1999, 1998, and 1997, respectively, with a weighted
average grant date fair value of $35.10, $32.40, and $30.01 per share,
respectively. At December 31, 1999, 1.1 million shares of restricted stock were
outstanding. The value of these shares is determined based on the fair market
value on the measurement date and is charged to compensation expense ratably
over the restriction period based on the number of shares which have met
performance vesting target. For 1999, 1998, and 1997, these charges totaled $69
million, $29 million, and $19 million, respectively. Included in the 1999 amount
is $60 million related to the accelerated vesting of restricted stock due to the
change in control (as defined in certain benefit plans) resulting from the
merger with Sonat.
Performance Units
Certain employees and officers of the Company are awarded performance units
that are payable in cash or stock at the end of the vesting period. The final
value of the performance units may vary according to the plan under which they
are granted, but is usually based on the Company's common stock price at the end
of the vesting period. The value of the performance units is charged ratably to
compensation expense over the vesting period with periodic adjustments to
account for the fluctuation in the market price of the Company's stock. Amounts
charged to compensation expense in 1999, 1998, and 1997 were $30 million, $13
million, and $5 million, respectively. Included in the 1999 amount is $22
million related to the accelerated vesting of the performance units due to the
change in control resulting from the merger with Sonat.
78
<PAGE> 83
Pro Forma Net Income and Net Income Per Common Share
Had the compensation expense for the Company's stock-based compensation
plans been determined applying the provisions of SFAS No. 123, the Company's net
income and net income per common share for 1999, 1998, and 1997 would
approximate the pro forma amounts below:
<TABLE>
<CAPTION>
DECEMBER 31, 1999 DECEMBER 31, 1998 DECEMBER 31, 1997
----------------------- ----------------------- -----------------------
AS REPORTED PRO FORMA AS REPORTED PRO FORMA AS REPORTED PRO FORMA
----------- --------- ----------- --------- ----------- ---------
<S> <C> <C> <C> <C> <C> <C>
SFAS No. 123 charge, pretax..... $ -- $ 160 $ -- $ 63 $ -- $ 30
APB No. 25 charge, pretax....... $ 145 $ -- $ 51 $ -- $ 24 $ --
Net income (loss)............... $ (255) $ (267) $ (306) $ (313) $ 405 $ 401
Basic earnings per common
share......................... $(1.12) $(1.17) $(1.35) $(1.39) $1.81 $1.79
Diluted earnings per common
share......................... $(1.12) $(1.17) $(1.35) $(1.39) $1.77 $1.75
</TABLE>
The effects of applying SFAS No. 123 in this pro forma disclosure are not
indicative of future amounts. SFAS No. 123 does not apply to awards granted
prior to the 1995 fiscal year.
The Company has reserved approximately 38 million shares of common stock
for issuance pursuant to existing and future stock awards. As of December 31,
1999, approximately 14 million shares remained unissued. In January 2000, an
additional 4 million shares were issued under the Company's existing plans.
Employee Stock Purchase Program
Effective July 1999, the Company implemented an employee stock purchase
plan under Section 423 of the Internal Revenue Code ("ESPP"), with purchases of
common stock to commence at the end of the quarter in which the El Paso and
Sonat merger occurred. The ESPP affords participants the right to purchase
common stock on a quarterly basis at 85 percent of the lower of the market price
at the beginning of the offering period or at the end of each calendar quarter.
In April 1999, Company stockholders authorized the issuance of 2 million shares
of common stock under the plan. During 1999, there were approximately 1,500
participants with total contributions of approximately $5 million. On December
31, 1999, approximately 140,000 shares of common stock were issued under the
ESPP at $33.10 per share. Funds received or held by the Company with respect to
the ESPP may be used for general corporate purposes. However, the Company
records a liability for the ESPP withholdings not yet applied towards the
purchase of common stock. The Company bears all expenses associated with
administering the ESPP, except for costs, including any applicable taxes,
associated with the participants' sale of common stock.
16. SEGMENT INFORMATION
The Company has adopted the provisions of SFAS No. 131, Disclosures about
Segments of an Enterprise and Related Information. As a result of the merger
with Sonat, the Company has segregated its business activities into five
segments: Natural Gas Transmission, Merchant Energy, International, Field
Services, and Production. These segments are strategic business units that offer
a variety of different energy products and services. They are managed separately
as each business requires different technology and marketing strategies.
The accounting policies of the individual segments are the same as those of
the Company, as a whole, as described in Note 1. Certain business segments'
earnings are largely derived from the earnings on equity investments which are
reported in Other, net in the Consolidated Statements of Income. Accordingly,
the Company evaluates segment performance, based on EBIT. To the extent
practicable, results of operations for the years ended December 31, 1998 and
1997 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.
79
<PAGE> 84
<TABLE>
<CAPTION>
SEGMENTS
AS OF OR FOR THE YEAR ENDED DECEMBER 31, 1999
-------------------------------------------------------------------------
NATURAL
GAS MERCHANT FIELD
TRANSMISSION ENERGY INTERNATIONAL SERVICES PRODUCTION TOTAL
------------ -------- ------------- -------- ---------- -------
(IN MILLIONS)
<S> <C> <C> <C> <C> <C> <C>
Revenue from external customers
Domestic........................... $1,586 $7,886 $ -- $ 400 $ 108 $ 9,980
Foreign............................ -- 518 73 -- -- 591
Intersegment revenue................. 51 36 -- 78 365 530
Merger-related and asset impairment
charges............................ 90 67 -- 8 31 196
Ceiling test charges................. -- -- -- -- 352 352
Depreciation, depletion, and
amortization....................... 275 32 14 61 210 592
Operating income (loss).............. 664 (65) (32) 43 (258) 352
Other income......................... 55 15 77 49 1 197
Earnings before interest and taxes... 719 (50) 45 92 (257) 549
Assets
Domestic........................... 8,909 1,881 166 1,513 1,393 13,862
Foreign............................ -- 127 1,209 -- -- 1,336
Capital expenditures and investments
in joint ventures and equity
investees.......................... 455 806 433 121 365 2,180
Equity investments................... 618 479 791 122 6 2,016
</TABLE>
<TABLE>
<CAPTION>
SEGMENTS
AS OF OR FOR THE YEAR ENDED DECEMBER 31, 1998
-------------------------------------------------------------------------
NATURAL
GAS MERCHANT FIELD
TRANSMISSION ENERGY INTERNATIONAL SERVICES PRODUCTION TOTAL
------------ -------- ------------- -------- ---------- -------
(IN MILLIONS)
<S> <C> <C> <C> <C> <C> <C>
Revenue from external customers
Domestic........................... $1,542 $7,186 $ -- $ 212 $ 174 $ 9,114
Foreign............................ -- 323 58 -- -- 381
Intersegment revenue................. 88 23 -- 65 361 537
Merger-related and asset impairment
charges............................ -- -- -- -- 15 15
Ceiling test charges................. -- -- -- -- 1,035 1,035
Depreciation, depletion and
amortization....................... 254 8 9 49 292 612
Operating income (loss).............. 749 (10) (27) 62 (939) (165)
Other income......................... 62 13 52 14 3 144
Earnings before interest and taxes... 811 3 25 76 (936) (21)
Assets
Domestic........................... 8,649 1,313 249 1,461 1,544 13,216
Foreign............................ -- 73 581 -- -- 654
Capital expenditures and investments
in joint ventures and equity
investees.......................... 401 46 536 453 581 2,017
Equity investments................... 519 43 435 87 6 1,090
</TABLE>
80
<PAGE> 85
<TABLE>
<CAPTION>
SEGMENTS
FOR THE YEAR ENDED OF DECEMBER 31, 1997
------------------------------------------------------------------------
NATURAL
GAS MERCHANT FIELD
TRANSMISSION ENERGY INTERNATIONAL SERVICES PRODUCTION TOTAL
------------ -------- ------------- -------- ---------- ------
(IN MILLIONS)
<S> <C> <C> <C> <C> <C> <C>
Revenue from external customers
Domestic............................ $1,582 $7,469 $ -- $381 $346 $9,778
Foreign............................. -- 218 13 -- -- 231
Intersegment revenue.................. 125 26 -- 27 410 588
Merger-related and asset impairment
charges............................. -- -- -- -- 50 50
Depreciation, depletion and
amortization........................ 245 7 1 35 341 629
Operating income (loss)............... 758 (22) (24) 67 178 957
Other income.......................... 50 1 26 8 4 89
Earnings before interest and taxes.... 808 (21) 2 75 182 1,046
</TABLE>
The reconciliations of revenues for reportable segments to total
consolidated revenues are presented below.
<TABLE>
<CAPTION>
FOR THE YEAR ENDED DECEMBER 31,
---------------------------------
1999 1998 1997
--------- --------- ---------
(IN MILLIONS)
<S> <C> <C> <C>
Total revenues for segments................................. $11,101 $10,032 $10,597
Corporate revenues.......................................... 10 5 6
Elimination of intersegment revenue......................... (530) (537) (588)
------- ------- -------
Total consolidated revenues....................... $10,581 $ 9,500 $10,015
======= ======= =======
</TABLE>
The reconciliations of other income for reportable segments to total
consolidated other income are presented below.
<TABLE>
<CAPTION>
FOR THE YEAR ENDED
DECEMBER 31,
----------------------
1999 1998 1997
----- ----- ------
(IN MILLIONS)
<S> <C> <C> <C>
Total other income for segments............................. $ 197 $ 144 $ 89
Corporate other income...................................... 30 42 5
----- ----- ------
Total consolidated other income................... $ 227 $ 186 $ 94
===== ===== ======
</TABLE>
The reconciliations of EBIT to income (loss) before preferred dividends of
subsidiary and the cumulative effect of accounting change are presented below.
<TABLE>
<CAPTION>
FOR THE YEAR ENDED
DECEMBER 31,
----------------------
1999 1998 1997
----- ----- ------
(IN MILLIONS)
<S> <C> <C> <C>
Total EBIT for segments..................................... $ 549 $ (21) $1,046
Corporate expenses, net..................................... 358 31 38
Interest and debt expense................................... 453 387 344
Minority interest........................................... 36 12 --
Income tax expense (benefit)................................ (81) (170) 234
----- ----- ------
Income (loss) before preferred dividends of
subsidiary and cumulative effect of accounting
change.......................................... $(217) $(281) $ 430
===== ===== ======
</TABLE>
81
<PAGE> 86
The reconciliations of assets for reportable segments to total consolidated
assets are presented below.
<TABLE>
<CAPTION>
AS OF DECEMBER 31,
-------------------
1999 1998
-------- --------
(IN MILLIONS)
<S> <C> <C>
Total assets for segments................................... $15,198 $13,870
Corporate and other assets.................................. 1,459 573
------- -------
Total consolidated assets......................... $16,657 $14,443
======= =======
</TABLE>
The Company did not have gross revenue from any customer equal to, or in
excess of, ten percent of consolidated operating revenue for the years ended
December 31, 1999, 1998, and 1997.
17. SUPPLEMENTAL CASH FLOW INFORMATION
The following table contains supplemental cash flow information for the
years ended December 31:
<TABLE>
<CAPTION>
1999 1998 1997
---- ---- ----
(IN MILLIONS)
<S> <C> <C> <C>
Interest.................................................. $421 $386 $348
Income tax payments (refunds)............................. 9 (86) (14)
</TABLE>
See Note 2, for a discussion of the non-cash investing transactions related
to certain acquisitions.
18. INVESTMENT IN AFFILIATED COMPANIES (UNAUDITED)
The Company holds investments in various affiliates which are accounted for
on the equity method of accounting. The Company's principal equity method
investees are international pipelines, interstate pipelines, power generation
plants, and gathering systems.
Summarized financial information of the Company's proportionate share of 50
percent or less owned companies and majority owned unconsolidated subsidiaries
accounted for by the equity method of accounting is as follows:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-----------------------
1999 1998 1997
----- ----- -----
(IN MILLIONS)
<S> <C> <C> <C>
Operating results data:
Revenues and other income................................. $930 $579 $480
Costs and expenses........................................ 814 492 424
Income from continuing operations......................... 116 87 56
Net income................................................ 95 84 53
</TABLE>
<TABLE>
<CAPTION>
DECEMBER 31,
----------------
1999 1998
------ ------
<S> <C> <C>
Financial position data:
Current assets............................................ $ 589 $ 259
Non-current assets........................................ 5,197 3,467
Short-term debt........................................... 249 292
Other current liabilities................................. 321 143
Long-term debt............................................ 2,505 1,569
Other non-current liabilities............................. 608 481
Minority interest......................................... 9 --
Equity in net assets(1)................................... 2,094 1,241
</TABLE>
- ---------------
(1) Investments in unconsolidated affiliates on the Consolidated Balance Sheets
include amounts associated with unamortized purchase price differences
relating to certain unconsolidated investees.
82
<PAGE> 87
19. SUPPLEMENTAL SELECTED QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
Financial information by quarter is summarized below. In the opinion of
management, all adjustments necessary for a fair presentation have been made.
<TABLE>
<CAPTION>
QUARTERS ENDED
-----------------------------------------------
DECEMBER 31 SEPTEMBER 30 JUNE 30 MARCH 31
----------- ------------ ------- --------
(IN MILLIONS, EXCEPT PER COMMON SHARE AMOUNTS)
<S> <C> <C> <C> <C>
1999
Operating revenues...................................... $2,443 $3,263 $2,600 $2,275
Merger-related and asset impairment charges............. 364 58 131 4
Ceiling test charges.................................... -- -- -- 352
Operating income (loss)................................. (141) 143 116 (154)
Income (loss) before cumulative effect of accounting
change................................................ (178) 39 38 (141)
Cumulative effect of accounting change, net of income
taxes................................................. -- -- -- 13
Net income (loss)....................................... (178) 39 38 (154)
Basic earnings (loss) per common share
Income (loss) before cumulative effect of accounting
change.............................................. $(0.78) $ 0.17 $ 0.17 $(0.62)
Cumulative effect of accounting change, net of income
taxes............................................... -- -- -- (0.06)
------ ------ ------ ------
Net income (loss)..................................... $(0.78) $ 0.17 $ 0.17 $(0.68)
====== ====== ====== ======
Diluted earnings (loss) per common share
Income (loss) before cumulative effect of accounting
change.............................................. $(0.78) $ 0.17 $ 0.17 $(0.62)
Cumulative effect of accounting change, net of income
taxes............................................... -- -- -- (0.06)
------ ------ ------ ------
Net income (loss)..................................... $(0.78) $ 0.17 $ 0.17 $(0.68)
====== ====== ====== ======
1998
Operating revenues...................................... $2,059 $2,484 $2,222 $2,735
Merger-related and asset impairment charges............. -- -- -- 15
Ceiling test charges.................................... -- 455 540 40
Operating income (loss)................................. 188 (273) (358) 205
Net income (loss)....................................... 74 (206) (260) 86
Basic earnings (loss) per common share.................. 0.33 (0.91) (1.15) 0.38
Diluted earnings (loss) per share....................... 0.33 (0.91) (1.15) 0.38
</TABLE>
20. SUPPLEMENTAL NATURAL GAS AND OIL OPERATIONS (UNAUDITED)
At December 31, 1999, the Company had interests in natural gas and oil
properties that are located primarily in Texas, Louisiana, Oklahoma, Arkansas,
New Mexico, and offshore Louisiana and Texas in the Gulf of Mexico. Production
does not own or lease any natural gas and oil properties outside the United
States.
Capitalized costs relating to natural gas and oil producing activities and
related accumulated depreciation, depletion and amortization were as follows:
<TABLE>
<CAPTION>
DECEMBER 31,
----------------
1999 1998
------ ------
(IN MILLIONS)
<S> <C> <C>
Natural gas and oil properties:
Costs subject to amortization............................. $5,285 $5,420
Costs not subject to amortization......................... 130 149
------ ------
5,415 5,569
Less accumulated depreciation, depletion and amortization... 4,154 4,094
------ ------
$1,261 $1,475
====== ======
</TABLE>
83
<PAGE> 88
Costs incurred in natural gas and oil producing activities, whether
capitalized or expensed, were as follows:
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
--------------------------
1999 1998 1997
------ ------ ------
(IN MILLIONS)
<S> <C> <C> <C>
Property acquisition costs:
Proved properties......................................... $ 3 $ 2 $ 6
Unproved properties....................................... 45 48 78
Exploration costs........................................... 139 156 288
Development costs........................................... 178 375 491
---- ---- ----
Total costs....................................... $365 $581 $863
==== ==== ====
</TABLE>
Presented below is an analysis of the capitalized costs of natural gas and
oil properties by year of expenditure that are not being amortized as of
December 31, 1999, pending determination of proved reserves. Capitalized
interest of $12 million, $2 million, and $6 million for the years ended December
31, 1999, 1998, and 1997, respectively, is included in the presentation below.
<TABLE>
<CAPTION>
CUMULATIVE COSTS EXCLUDED FOR CUMULATIVE
BALANCE YEARS ENDED DEC. 31 BALANCE
------------- --------------------- -------------
DEC. 31, 1999 1999 1998 1997 DEC. 31, 1996
------------- ----- ----- ----- -------------
(IN MILLIONS)
<S> <C> <C> <C> <C> <C>
Acquisition................................ $ 72 $(22) $40 $24 $30
Exploration................................ 58 3 42 13 --
---- ---- --- --- ---
$130 $(19) $82 $37 $30
==== ==== === === ===
</TABLE>
Projects presently excluded from amortization are in various stages of
evaluation. The majority of these costs are expected to be included in the
amortization calculation in the years 2000 through 2003. Total amortization
expense per Mcfe, including ceiling test charges was $2.54, $4.81, and $1.07 in
1999, 1998 and 1997, respectively. Excluding ceiling test charges, amortization
expense would have been $0.95 and $1.06 per Mcfe in 1999 and 1998, respectively.
Net quantities of proved developed and undeveloped reserves of natural gas
and liquids, including condensate and crude oil, and changes in such quantities,
were as follows:
<TABLE>
<CAPTION>
DECEMBER 31,
---------------------------------------------------------
1999 1998 1997
----------------- ----------------- -----------------
GAS LIQUIDS GAS LIQUIDS GAS LIQUIDS
(BCF) (MBBLS) (BCF) (MBBLS) (BCF) (MBBLS)
------- ------- ------- ------- ------- -------
<S> <C> <C> <C> <C> <C> <C>
Proved (developed and undeveloped)
reserves, net:
Beginning of year............... 1,423 29,717 2,161 72,882 2,006 65,984
Revisions of previous
estimates.................... (65) (336) (349) (12,816) 157 4,506
Extensions, discoveries and
other additions.............. 188 10,599 119 1,688 287 10,540
Purchases of reserves in
place........................ 34 117 6 -- 21 850
Sales of reserves in place...... (123) (3,834) (288) (23,710) (44) (433)
Production...................... (186) (5,825) (226) (8,327) (266) (8,565)
------- ------ ------- ------- ------- ------
End of year.................. 1,271 30,438 1,423 29,717 2,161 72,882
======= ====== ======= ======= ======= ======
Proved developed reserves:
Beginning of year............... 1,123 24,743 1,558 45,225 1,396 33,327
======= ====== ======= ======= ======= ======
End of year..................... 967 19,713 1,123 24,743 1,558 45,225
======= ====== ======= ======= ======= ======
</TABLE>
84
<PAGE> 89
There are numerous uncertainties inherent in estimating quantities of
proved reserves and in projecting future rates of production and timing of
development expenditures, including many factors beyond the control of
Production. The reserve data represents only estimates. Reservoir engineering is
a subjective process of estimating underground accumulations of natural gas and
oil that cannot be measured in an exact manner.
The significant changes to reserves, other than purchases, sales or
production, are due to reservoir performance in existing fields and drilling of
additional wells in existing fields. There have been no major discoveries or
other events, favorable or adverse, that may be considered to have caused a
significant change in the estimated proved reserves since December 31, 1999.
Results of operations from producing activities by fiscal year were as
follows:
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
-------------------------
1999 1998 1997
----- ------- -----
(IN MILLIONS)
<S> <C> <C> <C>
Net revenues:
Sales to external customers............................ $ 108 $ 174 $ 346
Affiliated sales....................................... 365 361 410
----- ------- -----
Total.......................................... 473 535 756
Production costs......................................... (98) (91) (116)
Depreciation, depletion and amortization................. (210) (292) (341)
Ceiling test charges..................................... (352) (1,035) --
----- ------- -----
Results of operations from producing activities before
tax.................................................... (187) (883) 299
Income tax (expense) benefit............................. 71 315 (98)
----- ------- -----
Results of operations from producing activities
(excluding corporate overhead and interest costs)...... $(116) $ (568) $ 201
===== ======= =====
</TABLE>
The standardized measure of discounted future net cash flows relating to
proved natural gas and oil reserves follows:
<TABLE>
<CAPTION>
DECEMBER 31,
-----------------------------
1999 1998 1997
------- ------- -------
(IN MILLIONS)
<S> <C> <C> <C>
Future cash inflows................................... $ 3,421 $ 3,124 $ 6,059
Future production and development costs............... (1,056) (1,028) (1,889)
Future income tax expenses............................ (458) (317) (912)
------- ------- -------
Future net cash flows................................. 1,907 1,779 3,258
10% annual discount for estimated timing of cash
flows............................................... (656) (617) (1,059)
------- ------- -------
Standardized measure of discounted future net cash
flows............................................... $ 1,251 $ 1,162 $ 2,199
======= ======= =======
</TABLE>
For the calculations in the preceding table, estimated future cash inflows
from estimated future production of proved reserves were computed using realized
natural gas and oil prices for December of each respective year.
85
<PAGE> 90
The following are the principal sources of change in the standardized
measure of discounted future net cash flows:
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
---------------------------
1999 1998 1997
----- ------- -------
(IN MILLIONS)
<S> <C> <C> <C>
Sales and transfers of natural gas and oil produced, net
of production costs................................... $(375) $ (444) $ (641)
Net changes in prices and production costs.............. 297 (394) (1,859)
Extensions, discoveries and improved recovery, less
related costs......................................... 262 72 329
Changes in estimated future development costs........... 9 36 (84)
Development costs incurred during the period............ 58 182 229
Revisions of previous quantity estimates................ (73) (413) 175
Accretion of discount................................... 127 269 449
Net change in income taxes.............................. (166) 379 611
Purchases of reserves in place.......................... 37 4 24
Sales of reserves in place.............................. (174) (469) (47)
Changes in production rates (timing) and other.......... 87 (259) (381)
----- ------- -------
$ 89 $(1,037) $(1,195)
===== ======= =======
</TABLE>
86
<PAGE> 91
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors and Stockholders of
El Paso Energy Corporation:
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 Energy Corporation as of December 31,
1999 and 1998, and the consolidated results of its operations and its cash flows
for each of the three years in the period ended December 31, 1999, in conformity
with accounting principles generally accepted in the United States. 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. The consolidated financial statements
give retroactive effect to the merger of Sonat Inc. on October 25, 1999, in a
transaction accounted for as a pooling of interests, as described in Note 2 to
the consolidated financial statements. We conducted our audits of these
statements in accordance with auditing standards generally accepted in the
United States, which require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements, assessing the
accounting principles used and significant estimates made by management, and
evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for the opinions expressed above.
PricewaterhouseCoopers LLP
Houston, Texas
February 16, 2000
87
<PAGE> 92
SCHEDULE II
EL PASO ENERGY CORPORATION
VALUATION AND QUALIFYING ACCOUNTS
YEARS ENDED DECEMBER 31, 1999, 1998, AND 1997
(IN MILLIONS)
<TABLE>
<CAPTION>
CHARGED
BALANCE AT TO COSTS CHARGED BALANCE
BEGINNING AND TO OTHER AT END
DESCRIPTION OF PERIOD EXPENSES ACCOUNTS DEDUCTIONS OF PERIOD
----------- ---------- -------- -------- ---------- ---------
<S> <C> <C> <C> <C> <C>
1999
Allowance for doubtful accounts............... $32 $10 $(2) $ (7)(a) $33
Allowance for price risk management
activities................................. 28 21 -- (10)(b) 39
Valuation allowance on deferred tax assets.... 5 -- 1 -- 6
1998
Allowance for doubtful accounts............... $52 $-- $ 6 $(26)(a) $32
Allowance for price risk management
activities................................. 25 23 -- (20)(b) 28
Valuation allowance on deferred tax assets.... 19 -- 4 (18)(c) 5
1997
Allowance for doubtful accounts............... $53 $11 $ 5 $(17)(a) $52
Allowance for price risk management
activities................................. 4 39 -- (18)(b) 25
Valuation allowance on deferred tax assets.... 11 -- 8(d) -- 19
</TABLE>
- ---------------
(a)Primarily accounts written off.
(b)Primarily liquidation of positions on which allowance was established.
(c)$11 million credited to additional paid-in capital for utilization of Zilkha
Energy Company net operating loss ("NOL") carryforward and $7 million
credited to deferred tax assets for waiver of Gulf States Gas Pipeline
Company NOL carryforward.
(d)Due to acquisition of Gulf States Gas Pipeline Company.
88
<PAGE> 93
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 captions "Proposal No. 1 -- Election of
Directors" and "Section 16(a) Beneficial Ownership Reporting Compliance" in El
Paso's proxy statement for the 2000 Annual Meeting of Stockholders is
incorporated herein by reference. Information regarding executive officers of El
Paso is presented in Item 1, Business, of this Form 10-K under the caption
"Executive Officers of the Registrant."
ITEM 11. EXECUTIVE COMPENSATION
Information appearing under the caption "Executive Compensation" in El
Paso's proxy statement for the 2000 Annual Meeting of Stockholders is
incorporated herein by reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
Information appearing under the caption "Security Ownership of Certain
Beneficial Owners and Management" in El Paso's proxy statement for the 2000
Annual Meeting of Stockholders is incorporated herein by reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
None.
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.
The following consolidated financial statements of the Company are included
in Part II, Item 8 of this report:
<TABLE>
<CAPTION>
PAGE
----
<S> <C>
Consolidated Statements of Income...................... 44
Consolidated Balance Sheets............................ 45
Consolidated Statements of Cash Flows.................. 46
Consolidated Statements of Stockholders' Equity........ 47
Notes to Consolidated Financial Statements............. 48
Report of Independent Accountants...................... 87
2. Financial statement schedules and supplementary information
required to be submitted.
Schedule II -- Valuation and qualifying accounts....... 88
Schedules other than that listed above are omitted
because they are not applicable
3. Exhibit list............................................. 91
</TABLE>
(b) REPORTS ON FORM 8-K:
- El Paso filed a Current Report on Form 8-K, dated October 26, 1999,
regarding the completion of the merger between El Paso and Sonat Inc.
89
<PAGE> 94
- El Paso filed a Current Report on Form 8-K, dated October 29, 1999,
providing the consolidated financials of Sonat Inc.
- El Paso filed a Current Report on Form 8-K, dated December 1, 1999,
announcing the results of operations for the first thirty days following
the merger between El Paso and Sonat Inc. which was accounted for as a
pooling of interests transaction.
- El Paso filed a Current Report on Form 8-K, dated January 18, 2000,
announcing that El Paso has entered into an Agreement and Plan of Merger
with The Coastal Corporation.
- El Paso filed a Current Report on Form 8-K/A, dated January 20, 2000,
providing additional disclosure exhibits regarding the Agreement and Plan
of Merger between El Paso and The Coastal Corporation.
- El Paso filed a Current Report on Form 8-K, dated February 3, 2000,
announcing that El Paso agreed to acquire certain assets of PG&E Gas
Transmission, Texas Corporation and PG&E Gas Transmission Teco, Inc.
90
<PAGE> 95
EL PASO ENERGY CORPORATION
EXHIBIT LIST
DECEMBER 31, 1999
Each exhibit identified below is filed as a part of this report. 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. Exhibits designated with a "+" constitute a management
contract or compensatory plan or arrangement required to be filed as an exhibit
to this report pursuant to Item 14(c) of Form 10-K.
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
------- -----------
<C> <S>
2.A -- Second Amended and Restated Agreement and Plan of Merger,
dated as of March 13, 1999, by and between Sonat Inc. and
El Paso Energy Corporation. (Exhibit 2.1 Registration
Statement to Form S-4 filed by El Paso on April 7, 1999,
File No. 333-75781)
2.B -- Agreement and Plan of Merger, dated January 17, 2000, by
and among El Paso, El Paso Merger Company and The Coastal
Corporation (Exhibit 1 to Schedule 13D filed by El Paso
on January 26, 2000, File No. 5-55241).
3.A -- Restated Certificate of Incorporation of El Paso as filed
with the Delaware Secretary of State on October 25, 1999.
(Exhibit 3.A to El Paso's Form 10-Q, filed November 12,
1999, File No. 1-14365 ("El Paso's 1999 Third Quarter
10-Q")).
3.B -- Restated By-Laws of El Paso (Exhibit 3.B to El Paso's
1999 Third Quarter 10-Q).
4.A -- Amended and Restated Shareholder Rights Agreement,
between El Paso and BankBoston, N.A., dated January 20,
1999 (Exhibit 1 to El Paso's Registration Statement on
Form 8-A/A Amendment No. 1, filed January 29, 1999, File
No. 1-14365).
4.B -- Amended and Restated Declaration of Trust of El Paso
Energy Capital Trust I dated March 16, 1998 and
Certificate of Trust Preferred Security (Exhibits 4.4 and
4.5 to EPNG's Form 8-K, filed March 17, 1998, File No.
1-2700); First Amendment to the Amended and Restated
Declaration of Trust of El Paso Energy Capital Trust I,
dated August 1, 1998 (Exhibit 4.3 of El Paso's Form 8-K,
filed August 3, 1998, File No. 1-14365).
4.C -- Subordinated Debt Securities Indenture dated March 1,
1998, between EPNG and The Chase Manhattan Bank as
Trustee; First Supplemental Indenture dated March 17,
1998, between EPNG and The Chase Manhattan Bank, as
Trustee; and 4 3/4% Convertible Subordinated Debenture
due 2028 (Exhibits 4.1, 4.2 and 4.6 respectively to
EPNG's Form 8-K, filed March 17, 1998, File No. 1-2700);
Second Supplemental Indenture, dated August 1, 1998
between El Paso and The Chase Manhattan Bank, as Trustee
(Exhibit 4.2 to El Paso's Form 8-K, filed August 3, 1998,
File No. 1-14365).
4.D -- Trust Preferred Securities Guarantee Agreement issued by
EPNG dated March 17, 1998 (Exhibit 4.7 to EPNG's Form
8-K, filed March 17, 1998, File No. 1-2700); First
Amendment to Trust Preferred Securities Guarantee
Agreement issued by El Paso dated August 1, 1998 (Exhibit
4.4 to El Paso's Form 8-K, filed August 3, 1998, File No.
1-14365).
4.E -- Indenture dated as of May 10, 1999, by and between El
Paso and The Chase Manhattan Bank, as Trustee (Exhibit
4.1 to El Paso's Form 8-K, dated May 10, 1999, File No.
1-14365).
4.F -- First Supplemental Indenture dated as of May 10, 1999, by
and between El Paso and The Chase Manhattan Bank, as
Trustee, including the form of 6 3/4% Senior Note Due
2009. (Exhibit 4.2 to El Paso's Form 8-K, filed May 10,
1999).
</TABLE>
91
<PAGE> 96
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
------- -----------
<C> <S>
4.G -- Second Supplemental Indenture dated as of July 12, 1999,
between El Paso and The Chase Manhattan Bank, as Trustee,
including the form of 6.625% Senior Note Due 2001
(Exhibit 4.I to El Paso's Form 10-Q, filed August 12,
1999, File No. 1-14365 ("El Paso's 1999 Second Quarter
10-Q")).
4.H -- Third Supplemental Indenture dated as of July 12, 1999,
by and between El Paso and The Chase Manhattan Bank, as
Trustee, including the form of Floating Rate Senior Note
Due 2001. (Exhibit 4.J to El Paso's 1999 Second Quarter
10-Q).
4.I -- Indenture dated as of June 1, 1986, by and between Sonat
Inc., and Manufacturers Hanover Trust Company, as
trustee; First Supplemental Indenture dated as of June 1,
1995, by and between Sonat and Chase Bank as trustee; and
Second Supplemental Indenture dated as of October 25,
1999, by and between El Paso and The Chase Manhattan
Bank, as trustee. (Exhibit 4.K to El Paso's 1999 Third
Quarter 10-Q).
10.A -- $1,250,000,000 364-Day Revolving Credit and Competitive
Advance Facility Agreement dated as of August 16, 1999,
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, as
administrative agent and as CAF Advance Agent for the
Lenders thereunder, 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 El Paso's 1999 Third Quarter 10-Q).
10.B -- $750 million 5-Year Revolving Credit and Competitive
Advance Facility Agreement dated as of October 29, 1997,
by and among EPNG, TGP, The Chase Manhattan Bank,
Citibank, N.A., Morgan Guaranty Trust Company of New
York, and certain other banks. (Exhibit 10.D to the El
Paso 1998's Form 10-Q, filed November 12, 1998, File No.
1-14365 ("El Paso's 1998 Third Quarter 10-Q")); First
Amendment to the $750 million 5-Year Revolving Credit and
Competitive Advance Facility dated as of October 9, 1998,
among EPNG, TGP, The Chase Manhattan Bank, Citibank,
N.A., Morgan Guaranty Trust Company of New York, and
certain other banks (Exhibit 10.E to El Paso's 1998 Third
Quarter 10-Q); Guarantee, dated as of August 28, 1998,
made by El Paso in favor of The Chase Manhattan Bank, as
Administrative Agent for several banks and other
financial institutions from time to time parties to the
$750 million 5-Year Revolving Credit and Competitive
Advance Facility dated as of October 29, 1997, by and
among EPNG, TGP, The Chase Manhattan Bank, Citibank,
N.A., Morgan Guaranty Trust Company of New York, and
certain other banks. (Exhibit 10.F to El Paso's 1998
Third Quarter 10-Q); Joinder Agreement dated December 7,
1998, made by El Paso to the $750 million 5-Year
Revolving Credit and CAF Advance Facility Agreement, by
and among EPNG, TGP, The Chase Manhattan Bank, Citibank,
N.A., Morgan Guaranty Trust Company of New York (Exhibit
10.B.1 to El Paso's Form 10-K, filed March 10, 1999, File
No. 1-14365 ("El Paso's 1998 10-K")).
+10.C -- Omnibus Compensation Plan dated January 1, 1992;
Amendment No. 1 effective as of April 1, 1998; Amendment
No. 2 effective as of August 1, 1998; Amendment No. 3
effective as of December 3, 1998; and Amendment No. 4
effective as of January 20, 1999 (Exhibit 10.C to El
Paso's 1998 10-K).
+10.D -- 1995 Incentive Compensation Plan, Amended and Restated
effective as of December 3, 1998 (Exhibit 10.D to El
Paso's 1998 10-K).
</TABLE>
92
<PAGE> 97
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
------- -----------
<C> <S>
+10.E -- 1995 Compensation Plan for Non-Employee Directors,
Amended and Restated effective as of August 1, 1998
(Exhibit 10.H to El Paso's 1998 Third Quarter 10-Q);
Amendment No. 1, effective March 9, 1999, to the 1995
Compensation Plan for Non-Employee Directors, Amended and
Restated as of August 1, 1998 (Exhibit 10.E.1 to El
Paso's 1999 Second Quarter 10-Q) and Amendment No. 2,
effective as of July 16, 1999, to the 1995 Compensation
Plan for Non-Employee Directors, Amended and Restated
effective as of August 1, 1998 (Exhibit 10.E.2 to El
Paso's 1999 Second Quarter 10-Q).
+10.F -- Stock Option Plan for Non-Employee Directors, Amended and
Restated effective as of January 20, 1999 (Exhibit 10.F
to El Paso's 1998 10-K) and Amendment No. 1, effective as
of July 16, 1999, to the Stock Option Plan for
Non-Employee Directors, Amended and Restated effective as
of January 20, 1999 (Exhibit 10.F.1 to El Paso's 1999
Second Quarter 10-Q).
+10.G -- 1995 Omnibus Compensation Plan, Amended and Restated
effective as of August 1, 1998 (Exhibit 10.J to El Paso's
1998 Third Quarter 10-Q); Amendment No. 1 to the 1995
Omnibus Compensation Plan effective as of December 3,
1998; Amendment No. 2 to the 1995 Omnibus Compensation
Plan effective as of January 20, 1999 (Exhibit 10.G.1 to
El Paso's 1998 10-K).
+10.H -- Supplemental Benefits Plan, Amended and Restated
effective as of December 3, 1998 (Exhibit 10.H to El
Paso's 1998 10-K).
+10.I -- Senior Executive Survivor Benefit Plan, Amended and
Restated effective as of August 1, 1998 (Exhibit 10.M to
El Paso's 1998 Third Quarter 10-Q).
+10.J -- Deferred Compensation Plan, Amended and Restated
effective as of December 3, 1998. (Exhibit 10.J to El
Paso's 1998 10-K).
+10.K -- Key Executive Severance Protection Plan, Amended and
Restated effective as of August 1, 1998 (Exhibit 10.O to
El Paso's 1998 Third Quarter 10-Q).
+10.L -- Director Charitable Award Plan, Amended and Restated
effective as of August 1, 1998 (Exhibit 10.P to the El
Paso's 1998 Third Quarter 10-Q).
+10.M -- Strategic Stock Plan, Amended and Restated effective as
of August 1, 1998 (Exhibit 10.1 to El Paso's Form S-8
filed January 14, 2000).
+10.N -- Domestic Relocation Policy, effective November 1, 1996
(Exhibit 10.Q to EPNG's Form 10-K, filed March 20, 1998,
File No. 1-2700).
+10.O -- Employment Agreement dated July 31, 1992 between EPNG and
William A. Wise (Exhibit 10.R to El Paso's 1998 Third
Quarter 10-Q); Amendment to Employment Agreement dated
January 29, 1996, between EPNG and William A. Wise
(Exhibit 10.U.1 to EPNG's Form 10-K for 1995, File No.
1-2700); Amendment to Employment Agreement dated August
25, 1999, by and between El Paso and William A. Wise
(Exhibit 10.O.1 to El Paso's 1999 Third Quarter 10-Q).
*+10.O.1 -- Letter of Waiver by William A. Wise dated March 18, 1999
relating to his Employment Agreement.
+10.P -- Letter Agreement dated January 13, 1995 between EPNG and
William A. Wise (Exhibit 10.P to El Paso's 1998 10-K).
+10.Q -- Promissory Note dated May 30, 1997, made by William A.
Wise to El Paso (Exhibit 10.R to EPNG's Form 10-Q, filed
May 15, 1998, File No. 1-2700 ("EPNG's 1998 First Quarter
10-Q"); Amendment to Promissory Note dated November 20,
1997 (Exhibit 10.R to EPNG's 1998 First Quarter 10-Q).
</TABLE>
93
<PAGE> 98
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
------- -----------
<C> <S>
+10.R -- Executive Award Plan of Sonat Inc., amended and restated
effective as of July 23, 1998, as amended May 27, 1999
(Exhibit 10.R to El Paso's 1999 Third Quarter 10-Q).
+10.S -- Letter Agreement dated February 22, 1991, between EPNG
and Britton White Jr. (Exhibit 10.V to the El Paso's 1998
Third Quarter 10-Q).
10.T -- El Paso Employee Stock Purchase Plan effective as of
January 20, 1999 (Exhibit 10.1 to El Paso's Form S-8,
filed May 20, 1999, File No. 333-78949); Amendment No. 1
to the Employee Stock Purchase Plan effective as of May
24, 1999 (Exhibit 10.T.1 to El Paso's 1999 Second Quarter
Form 10-Q).
+10.U -- Amended and Restated Omnibus Plan for Management
Employees effective as of December 3, 1999 (Exhibit 10.1
to El Paso's Form S-8 filed January 14, 2000, File No.
333-94719).
*21 -- Subsidiaries of El Paso.
*23 -- Consent of Independent Accountants.
</TABLE>
<TABLE>
<C> <S>
*27(1) --Financial Data Schedule for the Year ended December 31,
1999.
*27(2) --Financial Data Schedule for the Year ended December 31,
1998.
*27(3) --Financial Data Schedule for the Year ended December 31,
1997.
*27(4) --Financial Data Schedule for the Quarter ended March 31,
1999.
*27(5) --Financial Data Schedule for the Quarter ended June 30,
1999.
*27(6) --Financial Data Schedule for the Quarter ended September
30, 1999.
*27(7) --Financial Data Schedule for the Quarter ended March 31,
1998.
*27(8) --Financial Data Schedule for the Quarter ended June 30,
1998.
*27(9) --Financial Data Schedule for the Quarter ended September
30, 1998.
</TABLE>
94
<PAGE> 99
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, as amended, El Paso Energy Corporation has duly caused
this report to be signed on its behalf by the undersigned, thereunto duly
authorized on the 21st day of February 2000.
EL PASO ENERGY CORPORATION
Registrant
By /s/ WILLIAM A. WISE
-----------------------------------
William A. Wise
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 Energy Corporation and in the capacities and on the dates indicated:
<TABLE>
<CAPTION>
SIGNATURE TITLE DATE
--------- ----- ----
<C> <S> <C>
/s/ WILLIAM A. WISE President Chief Executive February 21, 2000
- ----------------------------------------------------- Officer and Director
(William A. Wise)
/s/ RONALD L. KUEHN, JR. Non-Executive Chairman of the February 21, 2000
- ----------------------------------------------------- Board
(Ronald L. Kuehn, Jr.)
/s/ H. BRENT AUSTIN Executive Vice President and February 21, 2000
- ----------------------------------------------------- Chief Financial Officer
(H. Brent Austin)
/s/ JEFFREY I. BEASON Senior Vice President and February 21, 2000
- ----------------------------------------------------- Controller (Chief
(Jeffrey I. Beason) Accounting Officer)
Director February 21, 2000
- -----------------------------------------------------
(Byron Allumbaugh)
/s/ JUAN CARLOS BRANIFF Director February 21, 2000
- -----------------------------------------------------
(Juan Carlos Braniff)
/s/ JAMES F. GIBBONS Director February 21, 2000
- -----------------------------------------------------
(James F. Gibbons)
Director February 21, 2000
- -----------------------------------------------------
(Ben F. Love)
/s/ MAX L. LUKENS Director February 21, 2000
- -----------------------------------------------------
(Max L. Lukens)
/s/ KENNETH L. SMALLEY Director February 21, 2000
- -----------------------------------------------------
(Kenneth L. Smalley)
/s/ ADRIAN M. TOCKLIN Director February 21, 2000
- -----------------------------------------------------
(Adrian M. Tocklin)
</TABLE>
95
<PAGE> 100
<TABLE>
<CAPTION>
SIGNATURE TITLE DATE
--------- ----- ----
<C> <S> <C>
/s/ MALCOLM WALLOP Director February 21, 2000
- -----------------------------------------------------
(Malcolm Wallop)
/s/ JOE B. WYATT Director February 21, 2000
- -----------------------------------------------------
(Joe B. Wyatt)
/s/ SELIM K. ZILKHA Director February 21, 2000
- -----------------------------------------------------
(Selim K. Zilkha)
</TABLE>
96
<PAGE> 101
EXHIBIT INDEX
Each exhibit identified below is filed as a part of this report. 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. Exhibits designated with a "+" constitute a management
contract or compensatory plan or arrangement required to be filed as an exhibit
to this report pursuant to Item 14(c) of Form 10-K.
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
------- -----------
<C> <S>
2.A -- Second Amended and Restated Agreement and Plan of Merger,
dated as of March 13, 1999, by and between Sonat Inc. and
El Paso Energy Corporation. (Exhibit 2.1 Registration
Statement to Form S-4 filed by El Paso on April 7, 1999,
File No. 333-75781)
2.B -- Agreement and Plan of Merger, dated January 17, 2000, by
and among El Paso, El Paso Merger Company and The Coastal
Corporation (Exhibit 1 to Schedule 13D filed by El Paso
on January 26, 2000, File No. 5-55241).
3.A -- Restated Certificate of Incorporation of El Paso as filed
with the Delaware Secretary of State on October 25, 1999.
(Exhibit 3.A to El Paso's Form 10-Q, filed November 12,
1999, File No. 1-14365 ("El Paso's 1999 Third Quarter
10-Q")).
3.B -- Restated By-Laws of El Paso (Exhibit 3.B to El Paso's
1999 Third Quarter 10-Q).
4.A -- Amended and Restated Shareholder Rights Agreement,
between El Paso and BankBoston, N.A., dated January 20,
1999 (Exhibit 1 to El Paso's Registration Statement on
Form 8-A/A Amendment No. 1, filed January 29, 1999, File
No. 1-14365).
4.B -- Amended and Restated Declaration of Trust of El Paso
Energy Capital Trust I dated March 16, 1998 and
Certificate of Trust Preferred Security (Exhibits 4.4 and
4.5 to EPNG's Form 8-K, filed March 17, 1998, File No.
1-2700); First Amendment to the Amended and Restated
Declaration of Trust of El Paso Energy Capital Trust I,
dated August 1, 1998 (Exhibit 4.3 of El Paso's Form 8-K,
filed August 3, 1998, File No. 1-14365).
4.C -- Subordinated Debt Securities Indenture dated March 1,
1998, between EPNG and The Chase Manhattan Bank as
Trustee; First Supplemental Indenture dated March 17,
1998, between EPNG and The Chase Manhattan Bank, as
Trustee; and 4 3/4% Convertible Subordinated Debenture
due 2028 (Exhibits 4.1, 4.2 and 4.6 respectively to
EPNG's Form 8-K, filed March 17, 1998, File No. 1-2700);
Second Supplemental Indenture, dated August 1, 1998
between El Paso and The Chase Manhattan Bank, as Trustee
(Exhibit 4.2 to El Paso's Form 8-K, filed August 3, 1998,
File No. 1-14365).
4.D -- Trust Preferred Securities Guarantee Agreement issued by
EPNG dated March 17, 1998 (Exhibit 4.7 to EPNG's Form
8-K, filed March 17, 1998, File No. 1-2700); First
Amendment to Trust Preferred Securities Guarantee
Agreement issued by El Paso dated August 1, 1998 (Exhibit
4.4 to El Paso's Form 8-K, filed August 3, 1998, File No.
1-14365).
4.E -- Indenture dated as of May 10, 1999, by and between El
Paso and The Chase Manhattan Bank, as Trustee (Exhibit
4.1 to El Paso's Form 8-K, dated May 10, 1999, File No.
1-14365).
4.F -- First Supplemental Indenture dated as of May 10, 1999, by
and between El Paso and The Chase Manhattan Bank, as
Trustee, including the form of 6 3/4% Senior Note Due
2009. (Exhibit 4.2 to El Paso's Form 8-K, filed May 10,
1999).
4.G -- Second Supplemental Indenture dated as of July 12, 1999,
between El Paso and The Chase Manhattan Bank, as Trustee,
including the form of 6.625% Senior Note Due 2001
(Exhibit 4.I to El Paso's Form 10-Q, filed August 12,
1999, File No. 1-14365 ("El Paso's 1999 Second Quarter
10-Q")).
</TABLE>
<PAGE> 102
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
------- -----------
<C> <S>
4.H -- Third Supplemental Indenture dated as of July 12, 1999,
by and between El Paso and The Chase Manhattan Bank, as
Trustee, including the form of Floating Rate Senior Note
Due 2001. (Exhibit 4.J to El Paso's 1999 Second Quarter
10-Q).
4.I -- Indenture dated as of June 1, 1986, by and between Sonat
Inc., and Manufacturers Hanover Trust Company, as
trustee; First Supplemental Indenture dated as of June 1,
1995, by and between Sonat and Chase Bank as trustee; and
Second Supplemental Indenture dated as of October 25,
1999, by and between El Paso and The Chase Manhattan
Bank, as trustee. (Exhibit 4.K to El Paso's 1999 Third
Quarter 10-Q).
10.A -- $1,250,000,000 364-Day Revolving Credit and Competitive
Advance Facility Agreement dated as of August 16, 1999,
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, as
administrative agent and as CAF Advance Agent for the
Lenders thereunder, 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 El Paso's 1999 Third Quarter 10-Q).
10.B -- $750 million 5-Year Revolving Credit and Competitive
Advance Facility Agreement dated as of October 29, 1997,
by and among EPNG, TGP, The Chase Manhattan Bank,
Citibank, N.A., Morgan Guaranty Trust Company of New
York, and certain other banks. (Exhibit 10.D to the El
Paso 1998's Form 10-Q, filed November 12, 1998, File No.
1-14365 ("El Paso's 1998 Third Quarter 10-Q")); First
Amendment to the $750 million 5-Year Revolving Credit and
Competitive Advance Facility dated as of October 9, 1998,
among EPNG, TGP, The Chase Manhattan Bank, Citibank,
N.A., Morgan Guaranty Trust Company of New York, and
certain other banks (Exhibit 10.E to El Paso's 1998 Third
Quarter 10-Q); Guarantee, dated as of August 28, 1998,
made by El Paso in favor of The Chase Manhattan Bank, as
Administrative Agent for several banks and other
financial institutions from time to time parties to the
$750 million 5-Year Revolving Credit and Competitive
Advance Facility dated as of October 29, 1997, by and
among EPNG, TGP, The Chase Manhattan Bank, Citibank,
N.A., Morgan Guaranty Trust Company of New York, and
certain other banks. (Exhibit 10.F to El Paso's 1998
Third Quarter 10-Q); Joinder Agreement dated December 7,
1998, made by El Paso to the $750 million 5-Year
Revolving Credit and CAF Advance Facility Agreement, by
and among EPNG, TGP, The Chase Manhattan Bank, Citibank,
N.A., Morgan Guaranty Trust Company of New York (Exhibit
10.B.1 to El Paso's Form 10-K, filed March 10, 1999, File
No. 1-14365 ("El Paso's 1998 10-K")).
+10.C -- Omnibus Compensation Plan dated January 1, 1992;
Amendment No. 1 effective as of April 1, 1998; Amendment
No. 2 effective as of August 1, 1998; Amendment No. 3
effective as of December 3, 1998; and Amendment No. 4
effective as of January 20, 1999 (Exhibit 10.C to El
Paso's 1998 10-K).
+10.D -- 1995 Incentive Compensation Plan, Amended and Restated
effective as of December 3, 1998 (Exhibit 10.D to El
Paso's 1998 10-K).
+10.E -- 1995 Compensation Plan for Non-Employee Directors,
Amended and Restated effective as of August 1, 1998
(Exhibit 10.H to El Paso's 1998 Third Quarter 10-Q);
Amendment No. 1, effective March 9, 1999, to the 1995
Compensation Plan for Non-Employee Directors, Amended and
Restated as of August 1, 1998 (Exhibit 10.E.1 to El
Paso's 1999 Second Quarter 10-Q) and Amendment No. 2,
effective as of July 16, 1999, to the 1995 Compensation
Plan for Non-Employee Directors, Amended and Restated
effective as of August 1, 1998 (Exhibit 10.E.2 to El
Paso's 1999 Second Quarter 10-Q).
</TABLE>
<PAGE> 103
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
------- -----------
<C> <S>
+10.F -- Stock Option Plan for Non-Employee Directors, Amended and
Restated effective as of January 20, 1999 (Exhibit 10.F
to El Paso's 1998 10-K) and Amendment No. 1, effective as
of July 16, 1999, to the Stock Option Plan for
Non-Employee Directors, Amended and Restated effective as
of January 20, 1999 (Exhibit 10.F.1 to El Paso's 1999
Second Quarter 10-Q).
+10.G -- 1995 Omnibus Compensation Plan, Amended and Restated
effective as of August 1, 1998 (Exhibit 10.J to El Paso's
1998 Third Quarter 10-Q); Amendment No. 1 to the 1995
Omnibus Compensation Plan effective as of December 3,
1998; Amendment No. 2 to the 1995 Omnibus Compensation
Plan effective as of January 20, 1999 (Exhibit 10.G.1 to
El Paso's 1998 10-K).
+10.H -- Supplemental Benefits Plan, Amended and Restated
effective as of December 3, 1998 (Exhibit 10.H to El
Paso's 1998 10-K).
+10.I -- Senior Executive Survivor Benefit Plan, Amended and
Restated effective as of August 1, 1998 (Exhibit 10.M to
El Paso's 1998 Third Quarter 10-Q).
+10.J -- Deferred Compensation Plan, Amended and Restated
effective as of December 3, 1998. (Exhibit 10.J to El
Paso's 1998 10-K).
+10.K -- Key Executive Severance Protection Plan, Amended and
Restated effective as of August 1, 1998 (Exhibit 10.O to
El Paso's 1998 Third Quarter 10-Q).
+10.L -- Director Charitable Award Plan, Amended and Restated
effective as of August 1, 1998 (Exhibit 10.P to the El
Paso's 1998 Third Quarter 10-Q).
+10.M -- Strategic Stock Plan, Amended and Restated effective as
of August 1, 1998 (Exhibit 10.1 to El Paso's Form S-8
filed January 14, 2000).
+10.N -- Domestic Relocation Policy, effective November 1, 1996
(Exhibit 10.Q to EPNG's Form 10-K, filed March 20, 1998,
File No. 1-2700).
+10.O -- Employment Agreement dated July 31, 1992 between EPNG and
William A. Wise (Exhibit 10.R to El Paso's 1998 Third
Quarter 10-Q); Amendment to Employment Agreement dated
January 29, 1996, between EPNG and William A. Wise
(Exhibit 10.U.1 to EPNG's Form 10-K for 1995, File No.
1-2700); Amendment to Employment Agreement dated August
25, 1999, by and between El Paso and William A. Wise
(Exhibit 10.O.1 to El Paso's 1999 Third Quarter 10-Q).
*+10.O.1 -- Letter of Waiver by William A. Wise dated March 18, 1999
relating to his Employment Agreement.
+10.P -- Letter Agreement dated January 13, 1995 between EPNG and
William A. Wise (Exhibit 10.P to El Paso's 1998 10-K).
+10.Q -- Promissory Note dated May 30, 1997, made by William A.
Wise to El Paso (Exhibit 10.R to EPNG's Form 10-Q, filed
May 15, 1998, File No. 1-2700 ("EPNG's 1998 First Quarter
10-Q"); Amendment to Promissory Note dated November 20,
1997 (Exhibit 10.R to EPNG's 1998 First Quarter 10-Q).
+10.R -- Executive Award Plan of Sonat Inc., amended and restated
effective as of July 23, 1998, as amended May 27, 1999
(Exhibit 10.R to El Paso's 1999 Third Quarter 10-Q).
+10.S -- Letter Agreement dated February 22, 1991, between EPNG
and Britton White Jr. (Exhibit 10.V to the El Paso's 1998
Third Quarter 10-Q).
10.T -- El Paso Employee Stock Purchase Plan effective as of
January 20, 1999 (Exhibit 10.1 to El Paso's Form S-8,
filed May 20, 1999, File No. 333-78949); Amendment No. 1
to the Employee Stock Purchase Plan effective as of May
24, 1999 (Exhibit 10.T.1 to El Paso's 1999 Second Quarter
Form 10-Q).
+10.U -- Amended and Restated Omnibus Plan for Management
Employees effective as of December 3, 1999 (Exhibit 10.1
to El Paso's Form S-8 filed January 14, 2000, File No.
333-94719).
*21 -- Subsidiaries of El Paso.
</TABLE>
<PAGE> 104
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
------- -----------
<C> <S>
*23 -- Consent of Independent Accountants.
</TABLE>
<TABLE>
<C> <S>
*27(1) --Financial Data Schedule for the Year ended December 31,
1999.
*27(2) --Financial Data Schedule for the Year ended December 31,
1998.
*27(3) --Financial Data Schedule for the Year ended December 31,
1997.
*27(4) --Financial Data Schedule for the Quarter ended March 31,
1999.
*27(5) --Financial Data Schedule for the Quarter ended June 30,
1999.
*27(6) --Financial Data Schedule for the Quarter ended September
30, 1999.
*27(7) --Financial Data Schedule for the Quarter ended March 31,
1998.
*27(8) --Financial Data Schedule for the Quarter ended June 30,
1998.
*27(9) --Financial Data Schedule for the Quarter ended September
30, 1998.
</TABLE>
</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-10.O.1
<SEQUENCE>2
<DESCRIPTION>LETTER OF WAIVER BY WILLIAM A. WISE - 03/18/1999
<TEXT>
<PAGE> 1
EXHIBIT 10.O.1
[EL PASO ENERGY LETTERHEAD]
March 18, 1999
El Paso Energy Corporation
1001 Louisiana Street
Houston, TX 77002
To Whom It May Concern:
This letter shall acknowledge that I hereby waive any right that I may
have to terminate my employment with El Paso Energy Corporation (the "Company")
for "Good Reason" under my Employment Agreement dated July 31, 1992, as
amended, and under Section 2.10(a) of the Company's Key Executive Severance
Protection Plan by reason of my no longer serving as Chairman of the Board of
the Company following the merger of the Company and Sonat Inc. until the
earlier of: (1) January 1, 2001 or (2) Ronald L. Kuehn, Jr. ceasing to serve as
Chairman of the Company. In addition, I hereby waive my right under my
Employment Agreement to have my base salary automatically reinstated as a
result of the transaction with Sonat Inc.
Very truly yours,
/s/ WILLIAM A. WISE
------------------------
William A. Wise
</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-21
<SEQUENCE>3
<DESCRIPTION>SUBSIDIARIES OF EL PASO
<TEXT>
<PAGE> 1
EL PASO ENERGY CORPORATION
SUBSIDIARIES AND AFFILIATES
AS OF DECEMBER 31, 1999
<TABLE>
<S> <C>
EL PASO ENERGY CORPORATION (Delaware)
Citrus Corp. (Delaware).................................................................................................... 50%
(El Paso Energy Corporation owns 50%; an unaffiliated party owns 50%)
Florida Gas Transmission Company (Delaware)........................................................................... 100
Border Gas Inc. (Delaware)........................................................................................ 3.33
(Southern Natural Gas Company owns 6.67%; Tennessee Gas Pipeline Company owns 37.5%; El
Paso Natural Gas Company owns 15%; Florida Gas Transmission Company owns 3.33%;
unaffiliated parties own 37.5%)
Citrus Trading Corp. (Delaware)....................................................................................... 100
Citrus Energy Services, Inc. (Delaware)............................................................................... 100
Citrus Marketing, Inc. (Delaware)..................................................................................... 100
Cross Country Development L.L.C. (Delaware LLC) ........................................................................... 50.33
(El Paso Energy Corporation owns 50.33%; unaffiliated parties own 49.67%.)
DEEPTECH INTERNATIONAL INC. (Delaware)..................................................................................... 100
DeepTech Offshore (Cayman) Ltd. (Cayman).............................................................................. 100
Deepwater Production Systems, Inc. (Texas)............................................................................ 100
FPSI, Inc. (Delaware)............................................................................................. 100
Dover Technology, Inc. (Texas)........................................................................................ 50
(DeepTech International Inc. owns 50%; unaffiliated parties own 50%.)
Key Ocean Services, Inc. (Texas)...................................................................................... 50
(DeepTech International Inc. owns 50%; unaffiliated parties own 50%.)
El Paso Energy Partners Holding Company (Delaware).................................................................... 100
El Paso Energy Partners Company (Delaware)........................................................................ 100
Delos Offshore Company, L.L.C. (Delaware LLC)................................................................ 1.0101
(EL Paso Energy Partners, L.P., owns 98.9899%; El Paso Energy Partners Company owns
1.0101%)
Ewing Bank Gathering Company, L.L.C. (Delaware LLC).......................................................... 1.0101
(El Paso Energy Partners, L.P., owns 98.9899%; El Paso Energy Partners Company owns
1.0101%)
Flextrend Development Company, L.L.C. (Delaware LLC)......................................................... 1.0101
(El Paso Energy Partners, L.P., owns 98.9899%; El Paso Energy Partners Company owns
1.0101%)
Green Canyon Pipe Line Company, L.L.C. (Delaware LLC)........................................................ 1.0101
(El Paso Energy Partners, L.P., owns 98.9899%; El Paso Energy Partners Company owns
1.0101%)
El Paso Energy Partners Deepwater, L.L.C. (Delaware LLC)..................................................... 1.0101
(El Paso Energy Partners, L.P., owns 98.9899%; El Paso Energy Partners Company owns
1.0101%)
Deepwater Holdings, L.L.C. (Delaware LLC)................................................................ 50
(El Paso Energy Partners Deepwater, L.L.C. owns 50%; unaffiliated parties own 50%.)
Stingray Pipeline Company, L.L.C. (Louisiana)........................................................ 100
U-T Offshore System (Delaware GP).................................................................... 100
West Cameron Dehydration Company, L.L.C. (Delaware LLC).............................................. 100
Western Gulf Holdings, L.L.C. (Delaware LLC)......................................................... 100
East Breaks Gathering Company, L.L.C. (Delaware LLC)............................................ 100
High Island Offshore System (Delaware GP)....................................................... 100
El Paso Energy Partners, L.P. ............................................................................... 11.98
(El Paso Energy Partners Company owns 11.98%; Sabine River Investors I, L.L.C. owns 11.549%;
Sabine River Investors II, L.L.C. owns 9.955%; the remaining 65.51% is publicly traded.)
Delos Offshore Company, L.L.C. (Delaware LLC)............................................................98.9899
(El Paso Energy Partners, L.P, owns 98.9899%; El Paso Energy Partners Company owns
1.0101%)
Ewing Bank Gathering Company, L.L.C. (Delaware LLC)......................................................98.9899
(El Paso Energy Partners, L.P. owns 98.9899%; El Paso Energy Partners Company owns
1.0101%)
Flextrend Development Company, L.L.C. (Delaware LLC).....................................................98.9899
(El Paso Energy Partners, L.P., owns 98.9899%; El Paso Energy Partners Company owns
1.0101%)
Green Canyon Pipe Line Company, L.L.C. (Delaware LLC)....................................................98.9899
(El Paso Energy Partners, L.P., owns 98.9899%; El Paso Energy Partners Company owns
1.0101%)
El Paso Energy Partners Deepwater, L.L.C. (Delaware LLC).................................................98.9899
(El Paso Energy Partners, L.P., owns 98.9899%; El Paso Energy Partners Company owns
1.0101%)
</TABLE>
1
<PAGE> 2
EL PASO ENERGY CORPORATION
SUBSIDIARIES AND AFFILIATES
AS OF DECEMBER 31, 1999
<TABLE>
<S> <C>
Deepwater Holdings, L.L.C. (Delaware LLC)............................................................ 50
(El Paso Energy Partners Deepwater, L.L.C. owns 50%; unaffiliated parties own 50%.)
Stingray Pipeline Company, L.L.C. (Louisiana)................................................... 100
U-T Offshore System (Delaware GP)............................................................... 100
West Cameron Dehydration Company, L.L.C. (Delaware LLC)......................................... 100
Western Gulf Holdings, L.L.C. (Delaware LLC).................................................... 100
East Breaks Gathering Company, L.L.C. (Delaware LLC)........................................ 100
High Island Offshore System (Delaware GP)................................................... 100
El Paso Energy Partners Finance Corporation (Delaware)................................................... 100
El Paso Energy Partners Oil Transport Systems, L.L.C. (Delaware LLC).....................................98.9899
(El Paso Energy Partners, L.P., owns 98.9899%; El Paso Energy Partners Company owns
1.0101%)
El Paso Partners Operating Company, L.L.C. (Delaware LLC)................................................98.9899
(El Paso Energy Partners, L.P., owns 98.9899%; El Paso Energy Partners Company owns
1.0101%)
Manta Ray Gathering Company, L.L.C. (Delaware LLC).......................................................98.9899
(El Paso Energy Partners, L.P., owns 98.9899%; El Paso Energy Partners Company owns
1.0101%)
Moray Pipeline Company, L.L.C. (Delaware LLC)............................................................98.9899
(El Paso Energy Partners, L.P., owns 98.9899%; El Paso Energy Partners Company owns
1.0101%)
Nemo Gathering Company, L.L.C. (Delaware LLC)........................................................ 33.9
(Moray Pipeline Company, L.L.C. owns 33.9%; unaffiliated parties own 76.1%)
Poseidon Pipeline Company, L.L.C. (Delaware LLC).........................................................98.9899
(El Paso Energy Partners, L.P., owns 98.9899%; El Paso Energy Partners Company owns
1.0101%)
Poseidon Oil Pipeline Company, L.L.C. (Delaware LLC)................................................. 36
(Poseidon Pipeline Company, L.L.C. owns 36%; Unaffiliated parties own 64%)
Sailfish Pipeline Company, L.L.C. (Delaware LLC).........................................................98.9899
(El Paso Energy Partners, L.P., owns 98.9899%; El Paso Energy Partners Company owns
1.0101%)
Neptune Pipeline Company, L.L.C. (Delaware LLC)...................................................... 25.67
(Sailfish Pipeline Company, L.L.C. owns 25.67%; unaffiliated parties own 74.33%)
Manta Ray Offshore Gathering Company, L.L.C. (Delaware LLC)..................................... 99
(Neptune Pipeline Company, L.L.C. owns 99%; Ocean Breeze Pipeline Company,
L.L.C. owns 1%)
Nautilus Pipeline Company, L.L.C. (Delaware LLC)................................................ 99
(Neptune Pipeline Company, L.L.C. owns 99%; Ocean Breeze Pipeline Company,
L.L.C. owns 1%)
Ocean Breeze Pipeline Company, L.L.C. (Delaware LLC)................................................. 25.67
(Sailfish Pipeline Company, L.L.C. owns 25.67%; unaffiliated parties own 74.33%)
Manta Ray Offshore Gathering Company, L.L.C. (Delaware LLC)..................................... 1
(Neptune Pipeline Company, L.L.C. owns 99%; Ocean Breeze Pipeline Company,
L.L.C. owns 1%)
Nautilus Pipeline Company, L.L.C. (Delaware LLC)................................................ 1
(Neptune Pipeline Company, L.L.C. owns 99%; Ocean Breeze Pipeline Company,
L.L.C. owns 1%)
Tarpon Transmission Company (Texas)...................................................................... 100
VK Deepwater Gathering Company, L.L.C. (Delaware LLC)....................................................98.9899
(El Paso Energy Partners, L.P., owns 98.9899%; El Paso Energy Partners Company owns
1.0101%)
Viosca Knoll Gathering Company (Delaware JV)......................................................... 99
(VK Deepwater Gathering Company, L.L.C. owns 99.0%; El Paso Energy Partners,
L.P. holds a 1% option)
VK-Main Pass Gathering Company, L.L.C. (Delaware LLC)....................................................98.9899
(El Paso Energy Partners, L.P., owns 98.9899%; El Paso Energy Partners Company owns
1.0101%)
El Paso Energy Partners Oil Transport Systems, L.L.C. (Delaware LLC)..................................... 1.0101
(El Paso Energy Partners, L.P., owns 98.9899%; El Paso Energy Partners Company owns
1.0101%)
</TABLE>
2
<PAGE> 3
EL PASO ENERGY CORPORATION
SUBSIDIARIES AND AFFILIATES
AS OF DECEMBER 31, 1999
<TABLE>
<S> <C>
El Paso Energy Partners Operating Company, L.L.C. (Delaware LLC)............................................. 1.0101
(El Paso Energy Partners, L.P., owns 98.9899%; El Paso Energy Partners Company owns
1.0101%)
Manta Ray Gathering Company, L.L.C. (Delaware LLC)........................................................... 1.0101
(El Paso Energy Partners, L.P., owns 98.9899%; El Paso Energy Partners Company owns
1.0101%)
Moray Pipeline Company, L.L.C. (Delaware LLC)................................................................ 1.0101
(El Paso Energy Partners, L.P., owns 98.9899%; El Paso Energy Partners Company owns
1.0101%)
Nemo Gathering Company, L.L.C. (Delaware LLC)............................................................ 33.9
(Moray Pipeline Company, L.L.C. owns 33.9%; unaffiliated parties own 76.1%)
Poseidon Pipeline Company, L.L.C. (Delaware LLC)............................................................. 1.0101
(El Paso Energy Partners, L.P., owns 98.9899%; El Paso Energy Partners Company owns
1.0101%)
Poseidon Oil Pipeline Company, L.L.C. (Delaware LLC)..................................................... 36
(Poseidon Pipeline Company, L.L.C. owns 36%; Unaffiliated parties own 64%)
Sailfish Pipeline Company, L.L.C. (Delaware LLC)............................................................. 1.0101
(El Paso Energy Partners, L.P., owns 98.9899%; El Paso Energy Partners Company owns
1.0101%)
Neptune Pipeline Company, L.L.C. (Delaware LLC).......................................................... 25.67
(Sailfish Pipeline Company, L.L.C. owns 25.67%; unaffiliated parties own 74.33%)
Manta Ray Offshore Gathering Company, L.L.C. (Delaware LLC).......................................... 99
(Neptune Pipeline Company, L.L.C. owns 99%; Ocean Breeze Pipeline Company, L.L.C.
owns 1%)
Nautilus Pipeline Company, L.L.C. (Delaware LLC)..................................................... 99
(Neptune Pipeline Company, L.L.C. owns 99%; Ocean Breeze Pipeline Company
owns 1%)
Ocean Breeze Pipeline Company, L.L.C. (Delaware LLC)..................................................... 25.67
(Sailfish Pipeline Company, L.L.C. owns 25.67%; unaffiliated parties own 74.33%)
Manta Ray Offshore Gathering Company, L.L.C. (Delaware LLC).......................................... 1
(Neptune Pipeline Company, L.L.C. owns 99%; Ocean Breeze Pipeline Company, L.L.C.
owns 1%)
Nautilus Pipeline Company, L.L.C. (Delaware LLC)..................................................... 1
(Neptune Pipeline Company, L.L.C. owns 99%; Ocean Breeze Pipeline Company
owns 1%)
Sabine River Investors I, L.L.C. (Delaware)....................................................................... 100
El Paso Energy Partners, L.P. ............................................................................... 11.549
(El Paso Energy Partners Company owns 11.98%; Sabine River Investors I, L.L.C. owns 11.549%;
Sabine River Investors II, L.L.C. owns 9.955%; the remaining 65.51% is publicly traded.)
Delos Offshore Company, L.L.C. (Delaware LLC)............................................................98.9899
(El Paso Energy Partners, L.P, owns 98.9899%; El Paso Energy Partners Company owns
1.0101%)
Ewing Bank Gathering Company, L.L.C. (Delaware LLC)......................................................98.9899
(El Paso Energy Partners, L.P. owns 98.9899%; El Paso Energy Partners Company owns
1.0101%)
Flextrend Development Company, L.L.C. (Delaware LLC).....................................................98.9899
(El Paso Energy Partners, L.P., owns 98.9899%; El Paso Energy Partners Company owns
1.0101%)
Green Canyon Pipe Line Company, L.L.C. (Delaware LLC)....................................................98.9899
(El Paso Energy Partners, L.P., owns 98.9899%; El Paso Energy Partners Company owns
1.0101%)
El Paso Energy Partners Deepwater, L.L.C. (Delaware LLC).................................................98.9899
(El Paso Energy Partners, L.P., owns 98.9899%; El Paso Energy Partners Company owns
1.0101%)
Deepwater Holdings, L.L.C. (Delaware LLC)............................................................ 50
(El Paso Energy Partners Deepwater, L.L.C. owns 50%; unaffiliated parties own 50%.)
Stingray Pipeline Company, L.L.C. (Louisiana)................................................... 100
U-T Offshore System (Delaware GP)............................................................... 100
West Cameron Dehydration Company, L.L.C. (Delaware LLC)......................................... 100
Western Gulf Holdings, L.L.C. (Delaware LLC).................................................... 100
East Breaks Gathering Company, L.L.C. (Delaware LLC)........................................ 100
High Island Offshore System (Delaware GP)................................................... 100
El Paso Energy Partners Finance Corporation (Delaware)................................................... 100
</TABLE>
3
<PAGE> 4
EL PASO ENERGY CORPORATION
SUBSIDIARIES AND AFFILIATES
AS OF DECEMBER 31, 1999
<TABLE>
<S> <C>
El Paso Energy Partners Oil Transport Systems, L.L.C. (Delaware LLC).....................................98.9899
(El Paso Energy Partners, L.P., owns 98.9899%; El Paso Energy Partners Company owns
1.0101%)
El Paso Partners Operating Company, L.L.C. (Delaware LLC)................................................98.9899
(El Paso Energy Partners, L.P., owns 98.9899%; El Paso Energy Partners Company owns
1.0101%)
Manta Ray Gathering Company, L.L.C. (Delaware LLC).......................................................98.9899
(El Paso Energy Partners, L.P., owns 98.9899%; El Paso Energy Partners Company owns
1.0101%)
Moray Pipeline Company, L.L.C. (Delaware LLC)............................................................98.9899
(El Paso Energy Partners, L.P., owns 98.9899%; El Paso Energy Partners Company owns
1.0101%)
Nemo Gathering Company, L.L.C. (Delaware LLC)........................................................ 33.9
(Moray Pipeline Company, L.L.C. owns 33.9%; unaffiliated parties own 76.1%)
Poseidon Pipeline Company, L.L.C. (Delaware LLC).........................................................98.9899
(El Paso Energy Partners, L.P., owns 98.9899%; El Paso Energy Partners Company owns
1.0101%)
Poseidon Oil Pipeline Company, L.L.C. (Delaware LLC)................................................. 36
(Poseidon Pipeline Company, L.L.C. owns 36%; Unaffiliated parties own 64%)
Sailfish Pipeline Company, L.L.C. (Delaware LLC).........................................................98.9899
(El Paso Energy Partners, L.P., owns 98.9899%; El Paso Energy Partners Company owns
1.0101%)
Neptune Pipeline Company, L.L.C. (Delaware LLC)...................................................... 25.67
(Sailfish Pipeline Company, L.L.C. owns 25.67%; unaffiliated parties own 74.33%)
Manta Ray Offshore Gathering Company, L.L.C. (Delaware LLC)..................................... 99
(Neptune Pipeline Company, L.L.C. owns 99%; Ocean Breeze Pipeline Company,
L.L.C. owns 1%)
Nautilus Pipeline Company, L.L.C. (Delaware LLC)................................................ 99
(Neptune Pipeline Company, L.L.C. owns 99%; Ocean Breeze Pipeline Company,
L.L.C. owns 1%)
Ocean Breeze Pipeline Company, L.L.C. (Delaware LLC)................................................. 25.67
(Sailfish Pipeline Company, L.L.C. owns 25.67%; unaffiliated parties own 74.33%)
Manta Ray Offshore Gathering Company, L.L.C. (Delaware LLC)..................................... 1
(Neptune Pipeline Company, L.L.C. owns 99%; Ocean Breeze Pipeline Company,
L.L.C. owns 1%)
Nautilus Pipeline Company, L.L.C. (Delaware LLC)................................................ 1
(Neptune Pipeline Company, L.L.C. owns 99%; Ocean Breeze Pipeline Company,
L.L.C. owns 1%)
Tarpon Transmission Company (Texas).................................................................. 100
VK Deepwater Gathering Company, L.L.C. (Delaware LLC)................................................98.9899
(El Paso Energy Partners, L.P., owns 98.9899%; El Paso Energy Partners Company owns
1.0101%)
Viosca Knoll Gathering Company (Delaware JV).................................................... 99
(VK Deepwater Gathering Company, L.L.C. owns 99.0%; El Paso Energy Partners, L.P. owns
a 1% option.)
VK-Main Pass Gathering Company, L.L.C. (Delaware LLC)................................................98.9899
(El Paso Energy Partners, L.P., owns 98.9899%; El Paso Energy Partners Company owns
1.0101%)
Offshore Gas Marketing, Inc. (Texas).................................................................................. 100
Offshore Gas Processors (Texas)....................................................................................... 100
Tatham Offshore Development, Inc. (Delaware).......................................................................... 100
El Paso CE Generation Holding Company (Delaware)........................................................................... 100
CE Generating, L.L.C. (Delaware)...................................................................................... 100
El Paso Energy Capital Trust I (Delaware).................................................................................. 100
El Paso Energy Capital Trust II (Delaware)................................................................................. 100
El Paso Energy Capital Trust III (Delaware)................................................................................ 100
El Paso Energy Communications Company (Delaware)........................................................................... 100
El Paso Energy E.S.T. Company (Delaware)................................................................................... 100
El Paso Energy Finance Company (Delaware).................................................................................. 100
</TABLE>
4
<PAGE> 5
EL PASO ENERGY CORPORATION
SUBSIDIARIES AND AFFILIATES
AS OF DECEMBER 31, 1999
<TABLE>
<S> <C>
El Paso Energy Foundation (Texas).......................................................................................... 100
El Paso Energy Holdings Inc. (Delaware) ................................................................................... 100
El Paso Energy Management Company (Delaware)............................................................................... 100
El Paso Energy Resources Company (Delaware) ............................................................................... 100
El Paso Energy Risk Management Company (Delaware).......................................................................... 100
El Paso Energy Service Company (Delaware) ................................................................................. 100
El Paso Energy Sports Corporation (Delaware)............................................................................... 100
El Paso Gas Services Company (Delaware) ................................................................................... 100
EL PASO NATURAL GAS COMPANY (Delaware) ................................................................................... 100
Border Gas Inc. (Delaware)............................................................................................ 15
(Southern Natural Gas Company owns 6.67%; Tennessee Gas Pipeline Company owns 37.5%; El
Paso Natural Gas Company owns 15%; Florida Gas Transmission Company owns 3.33%;
unaffiliated parties own 37.5%)
El Paso Development Company (Delaware) ............................................................................... 100
El Paso Gas Transportation Company (Delaware) ........................................................................ 100
El Paso Middle East B.V. (Netherlands) ............................................................................... 100
El Paso Pipeline Services Company (Delaware) ......................................................................... 100
El Paso TransColorado Company (Delaware) ............................................................................. 100
El Paso Mojave Pipeline Co. (Delaware) ............................................................................... 100
Mojave Pipeline Company (Texas GP)................................................................................ 50
(El Paso Mojave Pipeline Co. owns 50%; EPNG Mojave, Inc. owns 50%.)
Mojave Pipeline Operating Company (Texas).................................................................... 100
EPEC Energy Argentina S.A. (Argentina) ............................................................................... 7.7
(El Paso Energy International Company owns 92.3%; El Paso Natural Gas Company owns 7.7%)
Gasoductos de Chihuahua, S. de R.L. de C.V. (Mexico) ................................................................. 10
(El Paso Natural Gas Company owns 10%; El Paso Energy International
Company owns 40%; unaffiliated parties own 50%.)
Sabine River Investors V, L.L.C. (Delaware)........................................................................... 100
EPNG Mojave, Inc. (Delaware)...................................................................................... 100
Mojave Pipeline Company (Texas GP)........................................................................... 50
(EPNG Mojave, Inc. owns 50%; El Paso Mojave Pipeline Co. owns 50%.)
Mojave Pipeline Operating Company (Texas) ............................................................... 100
Samalayuca Pipeline Company, L.L.C. (Delaware LLC).................................................................... 100
El Paso PPN (Cayman) Company (Cayman Islands)......................................................................... 100
PPN Mauritius Company (Mauritius).......................................................................................... 100
PPN Power Generating Company Limited (India).......................................................................... 26
(PPN Mauritius Company owns 26%; unaffiliated parties own 74%.)
EL PASO PRODUCTION HOLDING COMPANY (Delaware).............................................................................. 100
Sabine River Investors VI, L.L.C. (Delaware).......................................................................... 100
El Paso Production GOM Inc. (Delaware)............................................................................ 100
Sabine River Investors VII, L.L.C. (Delaware)......................................................................... 100
Sabine River Investors VIII, L.L.C. (Delaware)........................................................................ 100
Sabine River Investors IX, L.L.C. (Delaware).......................................................................... 100
El Paso Production Company (Delaware)............................................................................. 100
El Paso Chaparral Holding Company (Delaware)............................................................................... 100
El Paso Chaparral Investor, L.L.C. (Delaware LLC)..................................................................... 100
Chaparral Investors, L.L.C. (Delaware LLC)........................................................................ 67
(El Paso Chaparral Investor, L.L.C. has a 50% vote; an unaffiliated party has a 50%
vote on certain matters.)
BIV Generation Company, L.L.C. (Delaware).................................................................... 100
Brush Generation Company, L.L.C. (Delaware).................................................................. 100
Colorado Power Partners (Colorado G.P.).................................................................. 1
(Brush Generation Company, L.L.C. owns a 1% partnership interest and Morgan Generation
Company, L.L.C. owns a 99% partnership interest.)
Morgan Generation Company, L.L.C. (Delaware)............................................................. 100
Colorado Power Partners (Colorado GP)................................................................ 99
(Brush Generation Company, L.L.C. owns a 1% partnership interest and Morgan
Generation Company, L.L.C. owns a 99% partnership interest.)
</TABLE>
5
<PAGE> 6
EL PASO ENERGY CORPORATION
SUBSIDIARIES AND AFFILIATES
AS OF DECEMBER 31, 1999
<TABLE>
<S> <C>
El Paso Berkshire Power I Company, L.L.C. (Delaware)......................................................... 100
Berkshire Power Company L.L.C. (Massachusetts)........................................................... 31.4
(El Paso Berkshire Power II Company owns 25%; El Paso Berkshire Power I Company,
L.L.C. owns 31.4%; an unaffiliated party owns 43.6%.)
El Paso Milford Power I Company, L.L.C. (Delaware)........................................................... 100
Milford Power Company L.L.C. (Delaware).................................................................. 70
(El Paso Milford Power I Company, L.L.C. owns 70%; El Paso Milford Power II Company
owns 25%; and an unaffiliated party owns 5%.)
Mesquite Investors, L.L.C. (Delaware LLC).................................................................... 100
East Coast Power, L.L.C. (Delaware LLC).................................................................. 49
Masspower L.L.C. (Delaware LLC).......................................................................... 51
MASSPOWER (Massachusetts G.P.) ..................................................................... 30
(EPEC Independent Power I Company owns 17.5% as general partner;
Masspower L.L.C. owns 30%; Springfield Generating Company, LLC. owns
17.5%; unaffiliated parties own 35%.)
Newark Bay Holding Company, L.L.C. (Delaware LLC)........................................................ 100
Liberty View Power L.L.C. (Delaware LLC)............................................................. 100
Newark Bay Cogeneration Partnership, L.P. (New Jersey LP)....................................... 2
(Newark Bay Holding Company, L.L.C. owns a 98% limited partnership
interest; Liberty View Power L.L.C. owns a 2% general partnership
interest)
NBCP Urban Renewal Corporation............................................................
NBCP Urban Renewal Partnership......................................................... 1
(Newark Bay Cogeneration Partnership, L.P. owns 99%; NBCP
Urban Renewal Corporation owns 1%)
Newark Bay Cogeneration Partnership, L.P. (New Jersey LP)............................................ 98
(Newark Bay Holding Company, L.L.C. owns a 98% limited partnership
interest; Liberty View Power L.L.C. owns a 2% general partnership
interest)
NBCP Urban Renewal Partnership................................................................ 99
(Newark Bay Cogeneration Partnership, L.P. owns 99%; NBCP Urban
Renewal Corporation owns 1%)
Springfield Generating Company LLC (Delaware LLC)........................................................ 100
MASSPOWER (Massachusetts G.P.) ......................................................................... 17.5
(EPEC Independent Power I Company owns 17.5% as general partner;
Masspower L.L.C. owns 30%; Springfield Generating Company, L.L.C. owns
17.5%; unaffiliated parties own 35%.)
Morgan Generation Company, L.L.C......................................................................... 100
Colorado Power Partners (Colorado G.P.).............................................................. 99
(Brush Generation Company, L.L.C. owns a 1% partnership interest and
Morgan Generation Company, L.L.C. owns a 99% partnership interest)
El Paso Chaparral Management, L.P. (Delaware)..................................................................... 1
(El Paso Chaparral Holding Company owns a 1% general partnership interest and
EPCHC Company owns a 99% limited partnership interest.)
EPCHC Company .................................................................................................... 100
El Paso Chaparral Management, L.P. (Delaware)................................................................ 99
(El Paso Chaparral Holding Company owns a 1% general partnership interest and
EPCHC Company owns a 99% limited partnership interest.)
El Paso Red River Holding Company (Delaware)............................................................................... 100
Sabine River Investors LLC (Delaware LLC)............................................................................. 100
Trinity River Associates LLC (Delaware LLC)....................................................................... 20
(Sabine River Investors LLC owns 20%; unaffiliated parties own 80%.)
EL PASO TENNESSEE PIPELINE CO. (Delaware) ................................................................................ 100
(El Paso Energy Corporation owns 100% of the issued and outstanding Company Common Stock.
Unaffiliated parties own 100% of the Series A Preferred Stock.)
East Tennessee Natural Gas Company (Tennessee) ....................................................................... 100
EL PASO ENERGY INTERNATIONAL COMPANY (Delaware)....................................................................... 100
El Paso Energia Mexico, S.A. de C.V. (Mexico) .................................................................... 0.1
(El Paso Energy International Company owns 0.1%; EPEC Gas Latin America Inc. owns
99.9%.)
El Paso Energy Asia Corporation (Delaware) ....................................................................... 100
El Paso Energy Europe Company (Delaware).......................................................................... 100
</TABLE>
6
<PAGE> 7
EL PASO ENERGY CORPORATION
SUBSIDIARIES AND AFFILIATES
AS OF DECEMBER 31, 1999
<TABLE>
<S> <C>
El Paso Energy Pittsfield Corporation (Delaware) ................................................................. 100
Berkshire Feedline Acquisition L.P. (Massachusetts L.P.)..................................................... 50
(El Paso Energy Pittsfield Corporation owns 50%; an unaffiliated party owns
50%.)
El Paso Energy Servicios S. de R.L. de C.V. (Mexico).............................................................. 1
(EPED Holding Company owns 99%; El Paso Energy International Company owns 1%.)
El Paso Mauritius Power Limited (Mauritius) ...................................................................... 100
El Paso Pakistan Power (Private) Limited (Pakistan) ......................................................... 99.9
(El Paso Mauritius Power Limited owns 99.9%; Individuals own 0.1%)
El Paso Cayman Power Company (Cayman Islands)............................................................ 100
El Paso Kabirwala Power Ltd. (Cayman Islands) ........................................................... 100
Fauji Kabirwala Power Company Limited (Pakistan) .................................................... 42.17
(El Paso Kabirwala Power Ltd. owns 42.17%; unaffiliated parties own
57.83%.)
EPEC Argentina Corporation (Delaware) ............................................................................ 100
EPEC Baja California Corporation (Delaware) ...................................................................... 100
EPEC Canada Ltd. (Canada)......................................................................................... 100
EPEC China Inc. (Delaware)........................................................................................ 100
EPEC Energy Argentina S.A. (Argentina) ........................................................................... 92.3
(El Paso Energy International Company owns 92.3%; El Paso Natural Gas Company owns
7.7%)
EPEC Cayman Islands Company (Cayman Islands) ................................................................ 100
Companias Asociadas Petroleraoes S.A. (Argentina) ....................................................... 45
(EPEC Cayman Islands Company owns 45%; unaffiliated parties own 55%.)
CAPEX S.A. (Argentina) .............................................................................. 55
(Companias Asociadas Petroleraoes S.A. owns 55%; remaining is publicly
traded.)
Triunion Energy Company (Cayman Islands)........................................................ 38.4
(EPED B Company owns 23.2%; an unaffiliated party owns 38.4% and
CAPEX S.A. owns 38.4%)
El Paso Energy Argentina Limitada S.A. (Argentina) ......................................... 99.99
(Triunion Energy Company owns 99.99%; unaffiliated parties own
.01%)
Gasoducto del Pacifico (Argentina) S.A. (Argentina).................................... 12.5
(Gasoducto del Pacifico (Cayman) Ltd. owns 87.5%; El Paso
Energy Argentina Limitada owns 12.5%.)
Triunion Energy Inversiones Company (Cayman Islands)........................................ 100
Triunion Energy Chile A Company (Cayman Islands) ...................................... 100
Triunion Energy Inversiones (Chile) Limitada (Chile) .............................. 0.1
(Triunion Energy Pacifico Company owns 99.9%;
Triunion Energy Chile A Company owns 0.1%.)
Triunion Energy Finance Pacifico Company (Cayman Islands) ............................. 100
Triunion Energy Pacifico Company (Cayman Islands) ..................................... 100
Gasoducto del Pacifico (Cayman) Ltd. (Cayman Islands).............................. 21.8
(Triunion Energy Pacifico Company owns 21.8%;
unaffiliated parties own 78.2%)
Gasoducto del Pacifico (Argentina) S.A. (Argentina)............................ 87.5
(Gasoducto del Pacifico (Cayman) Ltd. owns 87.5%;
El Paso Energy Argentina Limitada owns 12.5%.)
Gasoducto del Pacifico (Chile) S.A. (Chile).................................... 87.5
(Gasoducto del Pacifico (Cayman) Ltd. owns 87.5%;
Triunion Energy Inversiones Pacifico (Chile)
Limitada owns 12.5%.)
Triunion Energy Inversiones Pacifico (Chile) Limitada (Chile) ..................... 0.1
(Triunion Energy Pacifico Company owns 0.1%; Triunion
Energy Inversiones (Chile) Limitada owns 99.9%.)
Gasoducto del Pacifico (Chile) S.A. (Chile).................................... 12.5
(Gasoducto del Pacifico (Cayman) Ltd. owns 87.5%;
Triunion Energy Inversiones Pacifico (Chile)
Limitada owns 12.5%.)
Triunion Energy Inversiones (Chile) Limitada (Chile) .............................. 99.9
(Triunion Energy Pacifico Company owns 99.9%;
Triunion Energy Chile A Company owns 0.1%.)
Triunion Energy Inversiones Pacifico (Chile) Limitada (Chile) ................. 99.9
(Triunion Energy Pacifico Company owns 0.1%;
Triunion Energy Inversiones (Chile) Limitada owns
99.9%.)
EPEC Ethanol Company (Delaware) .................................................................................. 100
</TABLE>
7
<PAGE> 8
EL PASO ENERGY CORPORATION
SUBSIDIARIES AND AFFILIATES
AS OF DECEMBER 31, 1999
<TABLE>
<S> <C>
EPEC Ethanol Services Company (Delaware) ......................................................................... 100
EPEC Gas Brazil Corporation (Delaware) ........................................................................... 100
EPIC Gas International Servicos do Brasil Ltda. (Brazil) .................................................... 99.9
(EPEC Gas Brazil Corporation owns 99.9%; El Paso Energy International Company,
owns 0.1%.)
BBPP Holdings Ltda. (Brazil)............................................................................. 33
(EPIC Gas International Servicos do Brasil Ltda. owns 33%; unaffiliated
parties own 67%)
Transportadora Brasiliera Gasoducto Bolivia- Brazil S.A. (Brazil).................................... 29
(BBPP Holdings Ltda. owns 25%; unaffiliated parties own 75%)
EPEC Gas Canada Ltd. (Ontario) ................................................................................... 100
EPEC Gas Chile Corporation (Delaware) ............................................................................ 100
Gas de Chile S.A. (Chile) ................................................................................... 50
(EPEC Gas Chile Corporation owns 50%; unaffiliated parties own 50%.)
Inversiones EPEC Gas (Chile) Limitada (Chile)................................................................ 99.99
(EPEC Gas Chile Corporation owns 99.99%; EPEC Gas Latin America Inc. owns .01%.)
EPEC Gas Latin America Inc. (Delaware) ........................................................................... 100
El Paso Energia Mexico, S.A. de C.V. (Mexico) ............................................................... 99.9
(EPEC Gas Latin America Inc. owns 99.9%; El Paso Energy International Company
owns 0.1%.)
Pasotronica, S.A. de C.V. (Mexico)....................................................................... 50
(El Paso Energia Mexico, S.A. de C.V. owns 50%; an unaffiliated party owns
50%.)
Inversiones EPEC Gas (Chile) Limitada (Chile)................................................................ 0.01
(EPEC Gas Chile Corporation owns 99.99%; EPEC Gas Latin America Inc. owns .01%.)
Gasoducto Transandino S.A. de Argentina (Argentina) ......................................................... 0.01
(EPEC Gas Latin America Inc. owns.01%; Gasoducto Transandino S.A. owns 99.99%)
EPEC Gas Services (Chile) Corporation (Delaware) ................................................................. 100
EPIC Gas Transportes S.A. (Chile) ........................................................................... 99.9
(EPEC Gas Services (Chile) Corporation owns 99.9%; unaffiliated parties own 0.1%.)
EPEC Hungary Inc. (Delaware) ................................................................................... 100
EPEC Independent Power I Company (Delaware) ...................................................................... 100
MASSPOWER (Massachusetts G.P.) ............................................................................. 17.5
(EPEC Independent Power I Company owns 17.5% as general partner; Masspower
L.L.C. owns 30%; Springfield Generating Company, L.L.C. owns 17.5%; unaffiliated
parties own 35%.)
EPEC Independent Power II Company (Delaware) ..................................................................... 100
EPEC International (East Asia/Pacific) Inc. (Delaware) ........................................................... 100
EPEC MLP Inc. (Delaware) ................................................................................... 100
Polk Power Partners, L.P. (Delaware L.P.) .................................................................. 45.75
(EPEC MLP Inc., as a Limited Partner, owns 45.75%; Polk Power GP, Inc., as
General Partner, owns 1%; unaffiliated parties, as Limited Partners, own
53.25%.)
EP Power, L.L.C. (Delaware LLC).......................................................................... 100
EML Power, L.L.C. (Delaware LLC)..................................................................... 50
(EO Power, L.L.C. owns 50%; EP Power, L.L.C. owns 50%.)
EPEC Trinidad LNG, Inc. (Delaware) ............................................................................... 100
EPEC Ventures Bolivia Corporation (Delaware) ..................................................................... 100
EPEC Ventures Poland Corporation (Delaware) ...................................................................... 100
Wielkopolska Energia S.A. (Poland)........................................................................... 50
(EPEC Ventures Poland Corporation owns 50%; unaffiliated parties own 50%)
EPED Holding Company (Delaware) .................................................................................. 100
DBNGP Finance Company L.L.C. (Delaware LLC).................................................................. 50
(EPED Holding Company owns 50%; unaffiliated parties own 50%)
El Paso Cayman DBNGP, Ltd. (Cayman Islands).............................................................. 100
El Paso DBNGP Limited (Labuan)....................................................................... 100
Epic Energy Australia Trust (Australia)......................................................... 33.33
(El Paso DGNGP Limited owns 33.33%; unaffiliated parties own
66.67%)
Epic Energy (Australia) Nominees Pty. Ltd. (Australia).......................................... 33.33
(El Paso DBNGP Limited owns 33.33%; unaffiliated parties own
66.67%)
Epic Energy (Victoria) Nominees Pty. Ltd. (Australia)....................................... 100
Epic Energy (Victoria) Pipeline Trust (Australia)........................................... 100
Epic Energy (WA) Nominees Pty. Ltd. (Australia)............................................. 100
</TABLE>
8
<PAGE> 9
EL PASO ENERGY CORPORATION
SUBSIDIARIES AND AFFILIATES
AS OF DECEMBER 31, 1999
<TABLE>
<S> <C>
Epic Energy (DBNGP Finance) Pty. Ltd. (Australia)...................................... 100
Epic Energy Western Australia Pty. Limited (Australia) ................................ 100
Epic Energy (WA) Investments Pty. Ltd. (Australia).......................................... 100
Dampier to Bunbury Pipeline Employment Pty. Ltd. (Australia)........................... 100
Epic Energy (Pilbara Pipeline) Pty. Ltd. (Australia)................................... 100
Epic Energy (Victoria) Transmission Pty. Ltd. (Australia).............................. 100
Epic Energy (WA) Transmission Pty. Ltd. (Australia).................................... 100
Epic Energy WA Pipeline Trust (Australia)................................................... 100
El Paso ECK Holding Company (Delaware)....................................................................... 100
Energeticke Centrum Kladno s.r.o. (Czechoslovakia) ..................................................... 18.55
(El Paso ECK Holding Company owns 18.55%; unaffiliated parties own 81.45%.)
El Paso Energy Argentina Service Company (Delaware).......................................................... 100
El Paso Neuquen Holding Company (Cayman Islands)......................................................... 100
Agua del Cajon (Cayman) Company...................................................................... 50
(El Paso Neuquen Holding owns 50%; unaffiliated parties own 50%)
Servicios El Paso S.R.L. (Argentina)............................................................ 99.9
(Agua del Cajon (Cayman) Company owns 99.9%; unaffiliated parties
own 0.1%)
El Paso Energy Global Holdings Company....................................................................... 100
El Paso Energy Global Holdings Company (Cayman Islands).................................................. 100
El Paso Energy Portugal (Cayman) Company (Cayman Islands) ................................................... 100
El Paso Energy Portugal L.L.C. (Delaware LLC)............................................................ 100
El Paso Energy Servicios S.de R.L. de C.V. (Mexico).......................................................... 99
(EPED Holding Company owns 99%; El Paso Energy International Company owns 1%.)
El Paso Kladno B.V. (Netherlands) ........................................................................... 100
Matra Powerplant Holding B.V. (Netherlands) ............................................................. 20
(El Paso Kladno B.V. owns 20%; unaffiliated parties own 80%.)
ECK Generating s.r.o. (Czechoslovakia) ............................................................. 89
(Matra Powerplant Holding B.V. owns 89%; unaffiliated parties own 11%.)
El Paso Rosarito Company, L.L.C. (Delaware).................................................................. 100
El Paso Sierra Chaco Holding AB (Sweden)..................................................................... 100
Dynaf Bolivia S.A. (Bolivia)............................................................................. 98
(El Paso Sierra Chaco Holding AB owns 98%; El Paso Sierra Chaco Sweden AB
owns 1%; El Paso Sierra Chaco Bolivia AB owns 1%)
Empresa Energetica Sierra Chaco S.A. (Bolivia)........................................................... 98
(El Paso Sierra Chaco Holding AB owns 98%; El Paso Sierra Chaco Sweden AB
owns 1%; El Paso Sierra Chaco Bolivia AB owns 1%)
El Paso Sierra Chaco Sweden AB (Sweden).................................................................. 100
Dynaf Bolivia S.A. (Bolivia)......................................................................... 1
(El Paso Sierra Chaco Sweden AB owns 10%; El Paso Sierra Chaco Bolivia
AB owns 90%)
Empresa Energetica Sierra Chaco SA (Bolivia)......................................................... 1
(El Paso Sierra Chaco Holding AB owns 98%; El Paso Sierra Chaco Sweden
AB owns 1%; El Paso Sierra Chaco Bolivia AB owns 1%)
El Paso Sierra Chaco Bolivia AB (Sweden)................................................................. 100
Dynaf Bolivia S.A. (Bolivia)......................................................................... 1
(El Paso Sierra Chaco Holding AB owns 98%; El Paso Sierra Chaco Sweden
AB owns 1%; El Paso Sierra Chaco Bolivia AB owns 1%)
Empresa Energetica Sierra Chaco SA (Bolivia)......................................................... 1
(El Paso Sierra Chaco Holding AB owns 98%; El Paso Sierra Chaco Sweden
AB owns 1%; El Paso Sierra Chaco Bolivia AB owns 1%)
EPEC Nederland Holding B.V. (Netherlands).................................................................... 100
El Paso El Sauz B.V. (Netherlands)....................................................................... 100
El Paso Energy Hydro Holding B.V. (Netherlands).......................................................... 100
El Paso Energy Ujung Pangdang B.V. (Netherlands)......................................................... 100
El Paso Hermosillo B.V. (Netherlands).................................................................... 100
El Paso Mexico I B.V. (Netherlands)...................................................................... 100
El Paso Mexico II B.V. (Netherlands)..................................................................... 100
</TABLE>
9
<PAGE> 10
EL PASO ENERGY CORPORATION
SUBSIDIARIES AND AFFILIATES
AS OF DECEMBER 31, 199