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 1-9864
EL PASO TENNESSEE PIPELINE CO.
(Exact name of registrant as specified in its charter)
DELAWARE 76-0233548
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
EL PASO ENERGY BUILDING
1001 LOUISIANA STREET
HOUSTON, TEXAS 77002
(Address of principal executive offices) (Zip Code)
REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE: (713) 420-2131
SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:
NAME OF EACH EXCHANGE
TITLE OF EACH CLASS ON WHICH REGISTERED
------------------- ---------------------
8 1/4% Cumulative Preferred Stock, Series A................. New York Stock Exchange
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: NONE
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days.
Yes [X] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [X]
STATE THE AGGREGATE MARKET VALUE OF THE VOTING STOCK HELD BY NON-AFFILIATES
OF THE REGISTRANT. Aggregate market value shall be computed by reference to the
price at which the stock was sold, or the average bid and asked prices of such
stock, as of the specified date within 60 days prior to the date of filing.
MARKET VALUE
CLASS OF VOTING STOCK AND NUMBER OF SHARES HELD
HELD BY NON-AFFILIATES AT MARCH 8, 2000 BY NON-AFFILIATES
--------------------------------------- -----------------
8 1/4% Cumulative Preferred Stock, Series A, 6,000,000
shares $318,000,000*
- ---------------
* Based upon the closing price on the Composite Tape for the 8 1/4% Cumulative
Preferred Stock, Series A, on March 8, 2000.
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 $.01 per share. Shares outstanding on March 10,
2000: 1,971
DOCUMENTS INCORPORATED BY REFERENCE
List hereunder the following documents if incorporated by reference and the
part of the Form 10-K (e.g., Part I, Part II, etc.) into which the document is
incorporated: El Paso Tennessee Pipeline Co.'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, is incorporated by
reference into Part III.
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
2
EL PASO TENNESSEE PIPELINE CO.
TABLE OF CONTENTS
CAPTION PAGE
------- ----
Glossary............................................................... ii
PART I
Item 1. Business.................................................... 1
Item 2. Properties.................................................. 13
Item 3. Legal Proceedings........................................... 13
Item 4. Submission of Matters to a Vote of Security Holders......... 13
PART II
Item 5. Market for Registrant's Common Equity and Related
Stockholder Matters....................................... 14
Item 6. Selected Financial Data..................................... 15
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations................................. 16
Risk Factors and Cautionary Statement for Purposes of the
"Safe Harbor" Provisions of the Private Securities
Litigation Reform Act of 1995............................. 25
Item 7A. Quantitative and Qualitative Disclosures About Market
Risk...................................................... 29
Item 8. Financial Statements and Supplementary Data................. 32
Item 9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure.................................. 63
PART III
Item 10. Directors and Executive Officers of the Registrant.......... 63
Item 11. Executive Compensation...................................... 63
Item 12. Security Ownership of Certain Beneficial Owners and
Management................................................ 63
Item 13. Certain Relationships and Related Transactions.............. 63
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form
8-K....................................................... 64
Signatures.................................................. 67
i
3
GLOSSARY
The following abbreviations, acronyms, or defined terms used in this Form
10-K are defined below:
DEFINITION
----------
BBtu(/d).......................... Billion British thermal units (per day)
Bcf(/d)........................... Billion cubic feet (per day)
CAPSA............................. Companias Asociadas Petroleras SA, a privately held integrated
energy company in Argentina
Company........................... El Paso Tennessee Pipeline Co. and its subsidiaries
Dth(/d)........................... Decatherms (per day)
East Tennessee.................... East Tennessee Natural Gas Company, a wholly owned subsidiary of El
Paso Tennessee Pipeline Co.
EBIT.............................. Earnings before interest expense and income taxes, excluding
affiliated interest income
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, the parent of El Paso Tennessee
Pipeline Co.
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.
GSR............................... Gas supply realignment
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
Merchant Energy................... El Paso Merchant Energy Group, LLC, a wholly owned subsidiary of El
Paso Tennessee Pipeline Co.
Midwestern........................ Midwestern Gas Transmission Company, a wholly owned subsidiary of
El Paso Tennessee Pipeline Co.
Mgal(/d).......................... Thousand gallons per day
MMcf(/d).......................... Million cubic feet (per day)
PCB(s)............................ Polychlorinated biphenyl(s)
PRP(s)............................ Potentially responsible party(ies)
Series A Preferred Stock.......... 8 1/4% Cumulative Preferred Stock, Series A of El Paso Tennessee
Pipeline Co.
TBtu(/d).......................... Trillion British thermal units (per day)
TGP............................... Tennessee Gas Pipeline Company, a wholly owned subsidiary of El
Paso Tennessee Pipeline Co.
ii
4
PART I
ITEM 1. BUSINESS
GENERAL
Prior to 1996, the Company operated as Tenneco Inc., an entity with
operations in the automotive, energy, packaging and shipbuilding businesses.
During the latter part of 1996, Tenneco Inc. distributed to its shareholders all
of its businesses except for its energy business and certain corporate and
discontinued operations. In December 1996, El Paso acquired these remaining
business operations and renamed the Company EPTPC. During 1998, El Paso
completed a tax-free internal reorganization of its businesses. In the
reorganization, EPTPC became a direct subsidiary of El Paso. In addition,
through a series of transfers, the merchant services operations of Merchant
Energy, the international operations of International, and the field services
operations of Field Services all became subsidiaries of EPTPC. Also, as part of
the reorganization, EPTPC transferred certain assets and liabilities of
corporate and discontinued operations to El Paso. EPTPC continues to own the
interstate pipeline systems known as the TGP system, the East Tennessee system,
and the Midwestern system, as well as certain discontinued operations not
included in the transfer to El Paso. On December 31, 1999, as part of a similar
internal reorganization, the power services businesses of El Paso and the
merchant operations of Sonat Inc. acquired by El Paso in its October 1999 merger
with Sonat Inc., were transferred to EPTPC from El Paso in the form of a
tax-free capital contribution. At December 31, 1999, El Paso owns 100 percent of
the common equity and greater than 80 percent of the combined equity value of
EPTPC. The remaining combined equity value of EPTPC consists of $300 million of
outstanding preferred stock that is traded on the New York Stock Exchange.
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;
and the development and operation of energy infrastructure facilities worldwide.
The Company owns or has interests in over 17,800 miles of interstate and
intrastate pipeline connecting the nation's principal natural gas supply regions
to three of the largest consuming regions in the United States, namely the Gulf
Coast, the Northeast and the Midwest. The Company's natural gas transmission
operations are comprised of three wholly owned interstate pipeline systems: the
Tennessee Gas pipeline, the Midwestern Gas Transmission pipeline, and the East
Tennessee Natural Gas pipeline; as well as interests in the Portland Natural Gas
Transmission pipeline system and a storage facility.
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,
1
5
Louisiana. In addition, the Company has an 8 percent ownership interest in El
Paso Energy Partners, a publicly traded limited partnership which conducts
natural gas and oil gathering, transmission, midstream and other related
services offshore in the Gulf of Mexico.
PURCHASE OF TEXAS MIDSTREAM OPERATIONS
In January 2000, Field Services 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 four segments: Natural
Gas Transmission, Merchant Energy, International, and Field Services. 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
11, 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, mid-west and mid-Atlantic sections
of the United States, including the New York City, Chicago, and Boston
metropolitan areas, and various northern Mexico markets. It conducts these
activities through three wholly owned and one partially owned interstate systems
along with a storage facility. 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.
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.
2
6
Bear Creek Storage. The Company and Southern Natural Gas Company, a wholly
owned subsidiary of El Paso, each own a 50 percent interest in Bear Creek
Storage Company ("Bear Creek") which 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 Southern Natural Gas Company
under long-term contracts.
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 sale of
East Tennessee to comply with a Federal Trade Commission order related to El
Paso's October 1999 merger with Sonat Inc.
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. These FERC
approved tariffs 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.
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.
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
3
7
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.
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.
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. In December 1999, El Paso contributed its power business
to EPTPC. The power business 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.
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
4
8
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, Inc. 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.
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.
5
9
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:
1999 1998 1997
------ ------ ------
Natural gas volumes marketed (BBtu/d)...................... 6,713 7,315 8,013
Power volumes marketed (Thousand megawatt hours)........... 79,361 55,210 21,735
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 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
6
10
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.
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.
7
11
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 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 March 2000, the Company
completed an agreement with a third party to equally own International's
interests in EAPRC. 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
8
12
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.
Senkang 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 Senkang, 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 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
9
13
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.
In June 1999, the Company acquired an 8 percent ownership interest in El
Paso Energy Partners, a publicly traded master limited partnership in which a
subsidiary of El Paso is the general partner, by transferring 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.
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:
AVERAGE THROUGHPUT
MILES THROUGHPUT (BBTU/D)
OF CAPACITY ---------------------
GATHERING & TREATING PIPELINE(1) (MMCF/D)(2) 1999 1998 1997
-------------------- ----------- ----------- ----- ----- -----
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
10
14
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
----------------- ----------- ---- ---- ---- ----- ----- -----
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
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 1997(3) OIL/D(2) 1999
- ------------------ ---------- ----------- ----------- ------- ------- ------- ---------- ----------
El Paso Energy
Partners........... 8 1,382 413 136 -- -- 24 4
Oasis................ 35 608 350 263 289 338 -- --
Coyote Gulch......... 50 -- 120 97 69 42 -- --
Viosca Knoll(4)...... 1 125 10 142 287 205 -- --
- ------------
(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 Oasis Pipeline was reported in the Merchant Energy segment in
1997.
(4) Field Services sold a 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 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.
CORPORATE AND OTHER OPERATIONS
Corporate and other operations include certain liabilities of EPTPC's
discontinued operations and businesses.
ENVIRONMENTAL
A description of the Company's environmental activities is included in Item
8, Financial Statements and Supplementary Data, Note 8, and is incorporated
herein by reference.
11
15
EMPLOYEES
The Company had approximately 2,200 full-time employees on December 31,
1999. The Company has no collective bargaining arrangements, and no significant
changes in the workforce have occurred since December 31, 1999.
EXECUTIVE OFFICERS OF THE REGISTRANT
The executive officers of EPTPC as of March 10, 2000, are set forth below.
NAME OFFICE AGE
---- ------ ---
William A. Wise........................ Chairman of the Board, President and Chief Executive 54
Officer
H. Brent Austin........................ Executive Vice President and Chief Financial Officer 45
Joel Richards III...................... Executive Vice President 53
Britton White Jr....................... Executive Vice President and General Counsel 56
Mr. Wise became the Chairman of the Board, President and Chief Executive
Officer of EPTPC in December 1996. Mr. Wise has been Chief Executive Officer of
El Paso 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 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
EPTPC since June 1997. From December 1996 until June 1997, he was Senior Vice
President and Chief Financial Officer. Mr. Austin has been Executive Vice
President of 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. Richards has been Executive Vice President of EPTPC since June 1997.
From December 1996 until June 1997, he was Senior Vice President. Mr. Richards
has been Executive Vice President of 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. White has been Executive Vice President and General Counsel of EPTPC
since June 1997. From December 1996 until June 1997, he was Senior Vice
President and General Counsel. Mr. White has been Executive Vice President of El
Paso since December 1996 and General Counsel of El Paso from 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.
Executive officers hold offices until their successors are elected and
qualified, subject to their earlier removal.
12
16
ITEM 2. PROPERTIES
A description of the Company's properties is included in Item 1, Business,
and is incorporated herein by reference.
The Company is of the opinion that it has satisfactory title to the
properties owned and used in its businesses, subject to the liens for current
taxes, liens incident to minor encumbrances, and easements and restrictions that
do not materially detract from the value of such property or the interests
therein or the use of such properties in its businesses. The Company believes
that its physical properties are adequate and suitable for the conduct of its
business in the future.
ITEM 3. LEGAL PROCEEDINGS
See Item 8, Financial Statements and Supplementary Data, Note 8, which is
incorporated herein by reference.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
13
17
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED
STOCKHOLDER MATTERS
All of EPTPC's common stock, par value $.01 per share (the "Common Stock"),
is owned by El Paso and, accordingly, there is no public trading market for such
securities. The Series A Preferred Stock is listed for trading on the New York
Stock Exchange under the trading symbol "EPG_p".
The declaration of dividends on EPTPC capital stock is at the discretion of
its Board of Directors. The Board of Directors has not adopted a dividend policy
as such; subject to legal and contractual restrictions, its decisions regarding
dividends are based on all considerations that in its business judgment are
relevant at the time, including past and projected earnings, cash flows,
economic, business and securities market conditions and anticipated developments
concerning EPTPC's business and operations.
Dividends on the Series A Preferred Stock are payable when, as, and if
declared by EPTPC's Board of Directors. Dividends on such Series A Preferred
Stock accrue, whether or not declared, on a daily basis. The dividend rate on
the Series A Preferred Stock is 8 1/4% of $50 per share, per annum (2.0625% per
quarter). The dividend payment dates on such shares are March 31, June 30,
September 30, and December 31, in each year. All dividends payable on
outstanding shares of the Series A Preferred Stock of quarterly periods ending
on or prior to December 31, 1999, have been paid in full.
14
18
ITEM 6. SELECTED FINANCIAL DATA
During 1998 and again in 1999 following El Paso's October 1999 merger with
Sonat Inc., El Paso completed tax-free internal reorganizations of its assets
and operations and those of its subsidiaries. As a result of the 1998
reorganization, the merchant services operations of Merchant Energy, the
operations of International, and the operations of Field Services became
subsidiaries of EPTPC. Also, as part of the reorganization, EPTPC transferred
certain assets and liabilities of corporate and discontinued operations to El
Paso. In 1999, the power business of El Paso along with all merchant operations
of Sonat Inc., became subsidiaries of EPTPC. These reorganizations were treated
as transfers of ownership between entities under common control and have been
accounted for in a manner similar to a pooling of interests. Accordingly, the
financial information presented below has been restated to reflect the
reorganizations for all periods presented.
YEAR ENDED DECEMBER 31,
------------------------------------------
1999 1998 1997 1996 1995
------ ------ ------ ------ ------
(IN MILLIONS)
Operating Results Data:(a)
Operating revenues.............................. $9,595 $8,513 $8,850 $7,554 $3,729
Merger-related and asset impairment
charges(b)................................... 75 -- -- -- --
Income before extraordinary item and cumulative
effect of accounting change.................. 186 221 135 170 156
Net income (loss)(c)............................ 173 221 135 (64) 156
AS OF DECEMBER 31,
------------------------------------------
1999 1998 1997 1996 1995
------ ------ ------ ------ ------
(IN MILLIONS)
Financial Position Data:(a)
Total assets.................................... $9,754 $8,378 $9,200 $8,457 $6,723
Long-term debt, less current maturities......... 1,459 1,467 1,083 1,152 1,811
Stockholders' equity............................ 2,430 2,172 1,935 1,797 1,243
- ---------------
(a)Reflects the acquisition in September 1995 of Eastex Energy, Inc., in
December 1995 of Premier Gas Company and in December 1996 of EPTPC by El
Paso. These acquisitions were accounted for as purchases and therefore
operating results are included prospectively from the date of acquisition.
Also includes the 1996 transfer of EPNG's non-regulated gathering and
processing operations.
(b)Reflects charges in 1999 of $75 million pretax associated with El Paso's
October 1999 merger with Sonat Inc. and certain other asset impairment
charges.
(c)Includes a $13 million charge relating to the adoption of the American
Institute of Certified Public Accountants Statement of Position 98-5,
Reporting on the Costs of Start-Up Activities in 1999 and a $234 million
charge relating to an extraordinary loss as a result of the retirement of
long-term debt in a debt realignment immediately prior to the acquisition of
EPTPC by El Paso in 1996.
15
19
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
GENERAL
During 1998 and again in 1999, following El Paso's October 1999 merger with
Sonat Inc., El Paso completed tax-free reorganizations of its assets and
operations and those of its subsidiaries. As a result of its 1998
reorganization, EPTPC became a direct subsidiary of El Paso. In addition,
through a series of transfers, the merchant services operations of Merchant
Energy, the operations of International, and the operations of Field Services
all became subsidiaries of EPTPC. The value of the transfers associated with the
tax-free reorganization was $667 million, which represented the book value of
those items exchanged at the date of transfer. Also, as part of the 1998
reorganization, EPTPC transferred certain assets and liabilities of corporate
and discontinued operations to El Paso. Following this transaction, EPTPC
continued to own the interstate pipeline systems known as the TGP system, the
East Tennessee system, and the Midwestern system, as well as certain
discontinued operations not included in the transfer to El Paso. In its 1999
reorganization, El Paso contributed its power business and the merchant
operations of Sonat Inc. to EPTPC. The transaction had a total value of $98
million, representing the book value of the items contributed. The internal
reorganizations have been treated as a transfer of ownership between entities
under common control and accounted for in a manner similar to a pooling of
interests. Accordingly, all information included herein has been restated as
though the transactions occurred at the beginning of the earliest period
presented. At December 31, 1999, El Paso owns 100 percent of the common equity
and greater than 80 percent of the combined equity value of EPTPC. The remaining
combined equity value of EPTPC consists of $300 million of outstanding preferred
stock that is traded on the New York Stock Exchange.
During the first quarter of 2000, the Company will complete the sale of
East Tennessee to comply with a Federal Trade Commission order related to El
Paso's merger with Sonat Inc. The Company will treat the expected gain arising
from the sale as an extraordinary item. After reflecting the expected gain, the
Company believes that the future impact of this disposition will not,
individually or in the aggregate, have a material effect on the Company's
overall financial position, results of operations, or cash flows.
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 11.
During 1999, the Company incurred significant charges related to El Paso's
October 1999 merger with Sonat Inc. along with certain other asset impairment
charges. These charges impacted certain 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
16
20
business strategy and operations. The table below provides a summary of these
charges for the year ended December 31, 1999 by business segment and in total:
YEAR ENDED
DECEMBER 31,
1999
-------------
(IN MILLIONS)
Merger-related and asset impairment charges
Merchant Energy........................................... 67
Field Services............................................ 8
----
Total.................................................. $ 75
====
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:
YEAR ENDED DECEMBER 31,
-------------------------
1999 1998 1997
----- ---- ----
(IN MILLIONS)
EARNINGS BEFORE INTEREST EXPENSE AND INCOME TAXES
Natural Gas Transmission.................................... $ 384 $356 $317
Merchant Energy............................................. (50) 3 (21)
International............................................... 45 25 2
Field Services.............................................. 85 78 75
----- ---- ----
Segment EBIT.............................................. 464 462 373
----- ---- ----
Corporate income (expenses), net............................ (17) 2 (21)
----- ---- ----
Consolidated EBIT......................................... $ 447 $464 $352
===== ==== ====
EBIT year to year variances are discussed in the segment results below.
NATURAL GAS TRANSMISSION
YEAR ENDED DECEMBER 31,
------------------------------
1999 1998 1997
------ ------ ------
(IN MILLIONS)
Operating revenues.......................................... $ 773 $ 766 $ 798
Operating expenses.......................................... (413) (434) (494)
Other income................................................ 24 24 13
------ ------ ------
EBIT...................................................... $ 384 $ 356 $ 317
====== ====== ======
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 primarily due to the favorable resolution of
regulatory issues during 1999 related to TGP's New England rates, coupled with a
downward revision in 1998 of the amount of recoverable interest on GSR costs and
new contracts and services in 1999. These increases were partially offset by
lower system throughput, fewer contract buyouts and lower other operating
revenues in 1999.
Operating expenses for the year ended December 31, 1999, were $21 million
lower than 1998. The decrease was primarily due to the favorable resolution of
TGP's customer imbalance mechanism and lower fuel costs associated with lower
throughput in 1999. The decrease was partially offset by an increase in shared
services allocations.
17
21
YEAR ENDED DECEMBER 31, 1998 COMPARED TO YEAR ENDED DECEMBER 31, 1997
Operating revenues for the year ended December 31, 1998, were $32 million
lower than 1997, primarily due to lower throughput from warmer average
temperatures in the northeastern and midwestern markets and a downward revision
in 1998 of recoverable interest on GSR costs.
Operating expenses for the year ended December 31, 1998, were $60 million
lower than 1997, primarily due to lower system fuel usage associated with
operating efficiencies attained as a result of lower throughput and reduced
general and administrative expenses largely due to lower payroll costs.
Other income for the year ended December 31, 1998, was $11 million higher
than 1997, primarily due to the interest component of a favorable sales and use
tax settlement and gains on the sale of miscellaneous, non-operating assets.
MERCHANT ENERGY
YEAR ENDED DECEMBER 31,
-----------------------
1999 1998 1997
----- ----- -----
(IN MILLIONS)
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)
==== ==== ====
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
18
22
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.
INTERNATIONAL
YEAR ENDED DECEMBER 31,
------------------------
1999 1998 1997
------ ----- -----
(IN MILLIONS)
Operating revenues.......................................... $ 73 $ 58 $ 13
Operating expenses.......................................... (105) (85) (37)
Other income................................................ 77 52 26
----- ---- ----
EBIT...................................................... $ 45 $ 25 $ 2
===== ==== ====
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
19
23
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.
FIELD SERVICES
YEAR ENDED DECEMBER 31,
---------------------------
1999 1998 1997
----- ----- -----
(IN MILLIONS)
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.......................................... (167) (142) (118)
Other income................................................ 33 12 8
----- ----- -----
EBIT...................................................... $ 85 $ 78 $ 75
===== ===== =====
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 $25 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 El Paso's October 1999 merger
with Sonat Inc., and an increase in amortization and depreciation expense
attributable to acquisitions.
Other income for the year ended December 31, 1999, was $21 million higher
than 1998 due to net gains on the sale of several assets, primarily Viosca Knoll
during the second quarter of 1999 along with an increase in equity earnings from
El Paso Energy Partners and EnCap. This increase was partially offset by a
decrease in equity earnings on Viosca Knoll.
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 $24 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 $4 million higher
than 1997 primarily due to higher earnings from equity investments, primarily
from Oasis Pipeline.
20
24
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 $19
million higher than 1998. The change was primarily due to the receipt of
dividends from Oil Casualty Insurance Limited ("OCIL") and the gains on sales of
investing assets 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 $23
million lower than 1997. The decrease results from lower benefits costs, an
increase in investment income and the receipt of dividends from OCIL in 1998.
INTEREST AND DEBT EXPENSE
YEAR ENDED DECEMBER 31, 1999 COMPARED TO YEAR ENDED DECEMBER 31, 1998
Non-affiliated Interest and Debt Expense
Interest and debt expense for the year ended December 31, 1999, was $13
million higher than 1998 due to increased borrowings to fund capital
expenditures, acquisitions, and other investing expenditures offset by higher
interest capitalized in 1999 from project investment and development activities
primarily in the Merchant Energy segment.
Affiliated Interest and Debt Expense
Affiliated interest expense, net for the year ended December 31, 1999, was
$12 million higher than 1998, primarily due to an increase in affiliated average
debt balance.
YEAR ENDED DECEMBER 31, 1998 COMPARED TO YEAR ENDED DECEMBER 31, 1997
Non-affiliated Interest and Debt Expense
Interest and debt expense for the year ended December 31, 1998, was $10
million lower than 1997 primarily due to lower net borrowings in 1998, interest
on a rate refund to TGP's customers in 1997, and higher capitalized interest in
1998.
Affiliated Interest and Debt Expense
Affiliated interest expense, net for the year ended December 31, 1998, was
$20 million higher than 1997, primarily due to an increase in average affiliated
debt balances in 1998.
INCOME TAX EXPENSE
YEAR ENDED DECEMBER 31, 1999 COMPARED TO YEAR ENDED DECEMBER 31, 1998
Income tax expense of $85 million in 1999 and $92 million in 1998 resulted
in effective tax rates of 31 percent and 29 percent, respectively. The higher
rate is primarily due to merger-related costs incurred in 1999 and prior year
tax adjustments recorded in 1998 under Statement of Financial Accounting
Standards ("SFAS") No. 109, Accounting for Income Taxes. The higher rate is
partially 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, and lower state income taxes.
YEAR ENDED DECEMBER 31, 1998 COMPARED TO YEAR ENDED DECEMBER 31, 1997
Income tax expense of $92 million in 1998 and $76 million in 1997 resulted
in effective tax rates of 29 percent and 36 percent, respectively. The lower
rate is primarily due to prior year tax adjustments recorded in 1998 under SFAS
No. 109, increased equity income from unconsolidated foreign affiliates recorded
net of foreign income taxes for which no provision for U.S. income tax is
required, and lower state income taxes.
21
25
LIQUIDITY AND CAPITAL RESOURCES
CASH FROM OPERATING ACTIVITIES
Net cash provided by operating activities was $325 million for the year
ended December 31, 1999, compared to $275 million for the same period of 1998.
The increase was primarily attributable to cash settlements of historical
affiliated activity in 1998 and working capital changes offset by net income tax
refunds received in 1998 and a reduction in GSR collections in 1999.
CASH FROM INVESTING ACTIVITIES
Net cash used in investing activities was approximately $1.5 billion for
the year ended December 31, 1999. Amounts paid for joint ventures and equity
investment activities included the purchase of a 50 percent ownership interest
in CE Generation LLC, an ownership interest in EAPRC and investments in
international projects in China, India, Pakistan and the Philippines. Amounts
paid for acquisitions included a 35 percent interest in each of Sonat Marketing
Company L.P. and Sonat Power Marketing L.P. from AGL, the acquisitions of the
Rio Negro power plant and EnCap. Capital expenditures were 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 $1 billion are primarily intended for expansion of international
operations and domestic unregulated operations, pipeline systems 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,
the issuance of other long-term debt or equity, and/or contributions from El
Paso.
CASH FROM FINANCING ACTIVITIES
Net cash provided by financing activities was approximately $1.1 billion
for the year ended December 31, 1999. Commercial paper borrowings, fundings and
contributions from El Paso, and proceeds from the issuance of notes payable,
supplemented by internally generated funds, were used to fund capital and equity
investments, 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,
the issuance of other long-term debt or equity, and/or contributions from El
Paso. 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 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 since the specified dates). For a discussion of the Company's
financing arrangements, see Item 8, Financial Statements and Supplementary Data,
Note 7 which is incorporated herein by reference.
COMMITMENTS AND CONTINGENCIES
See Item 8, Financial Statements and Supplementary Data, Note 8, for a
discussion of the Company's Commitments and Contingencies which is incorporated
herein by reference.
22
26
At December 31, 1999, the Company had capital and investment commitments of
$368 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, 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, Field Services 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. 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.
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 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 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.
Year 2000
To coordinate the phases of the Year 2000 project, El Paso 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 Company participated in El Paso's Year 2000 project as described below. The
goal of the Year 2000 project was to
23
27
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 $10 million and has capitalized costs of approximately
$5 million.
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.
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.
24
28
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 is 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 other alternative
energy sources;
- price competition;
- drilling activity and supply availability; and
- service area competition.
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. 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 we serve;
- 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.
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
25
29
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.
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.
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 5.
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,
26
30
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.
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 8.
OUR ACTIVITIES INVOLVE OPERATING HAZARDS AND UNINSURED RISKS
While we maintain insurance against certain of the risks normally
associated with the transportation, 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 of EPTPC, assumed as a
result of its merger with El Paso, 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 El Paso 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 El Paso's acquisition of EPTPC and the distributions
made by EPTPC prior to that acquisition, the IRS issued a private letter ruling
to old Tenneco Inc. (Tenneco Inc., prior to its acquisition by
27
31
El Paso), 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.
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, EPTPC or El Paso, or our
credit ratings.
28
32
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 El Paso's risk
management committee which 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 El Paso's Board of
Directors.
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. El Paso's risk management
committee also continually reviews these policies to ensure they are responsive
to changing business conditions.
Merchant Energy measures the risk in its commodity and energy related
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 through the use of non-trading financial instruments, including
forward contracts and swaps. In addition, Merchant Energy functions as an agent
for Field Services and El Paso Production Holding Company, a wholly owned
subsidiary of El Paso, hedging a portion of their commodity risk by entering
into derivative financial instruments with third parties.
29
33
The estimated potential one-day unfavorable impact on income before income
taxes, 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. 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 and 1998, 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
fixed rate long-term debt has been estimated based on quoted market prices for
the same or similar issues.
For the Company's equity swap, notional amounts and weighted average
interest rates are presented by expected or contractual maturity date. Notional
amounts are used to calculate the contractual payments to be exchanged under the
contact. The fair value of the equity swap is the estimated amount at which
management believes it could be liquidated over a reasonable period of time,
based on quoted market prices, current market conditions, or other estimates
obtained from third-party dealers.
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)
LIABILITIES:
Short-term debt -- variable
rate............................ $649 $ 649 $ 649 $ 190 $ 190
Average interest rate....... 6.3%
Long-term debt, including
current portion -- fixed
rate........................ $ 8 $ 38 $ 12 $ -- $ -- $1,437 $1,495 $1,405 $1,471 $1,563
Average interest rate....... 9.7% 9.5% 7.9% -- -- 7.2%
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(c)..... $ (8) (9)
- ---------------
(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 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.
30
34
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 counterparty of all foreign currency
forward purchase and sell contracts is a subsidiary of El Paso. The following
table summarizes the notional amounts, average settlement rates, and fair value
for foreign currency forward purchase and sale contracts as of December 31,
1999:
NOTIONAL AMOUNT FAIR VALUE
IN FOREIGN AVERAGE IN
CURRENCY SETTLEMENT U.S. DOLLARS
(IN MILLIONS) RATES (IN MILLIONS)
--------------- ---------- -------------
Canadian Dollars Purchase................................ 411 .645 $16
Sell.................................... 189 .686 --
---
$16
===
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:
EXPECTED MATURITY DATES
---------------------------------------------
2000 2001 2002 2003 2004 THEREAFTER TOTAL
---- ---- ---- ---- ---- ---------- -----
(IN MILLIONS)
Canadian Dollars Purchase....................... $ 6 $35 $35 $35 $ 34 $ 120 $ 265
Sell........................... 27 27 27 27 22 -- 130
--- --- --- --- ---- ----- -----
Net cash flow effect........... $21 $(8) $(8) $(8) $(12) $(120) $(135)
=== === === === ==== ===== =====
31
35
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
EL PASO TENNESSEE PIPELINE CO.
CONSOLIDATED STATEMENTS OF INCOME
(IN MILLIONS)
YEAR ENDED DECEMBER 31,
--------------------------
1999 1998 1997
------ ------ ------
Operating revenues
Transportation............................................ $ 716 $ 717 $ 740
Energy commodities........................................ 8,458 7,570 7,841
Gathering and processing.................................. 285 141 204
Other..................................................... 136 85 65
------ ------ ------
9,595 8,513 8,850
------ ------ ------
Operating expenses
Cost of gas and other products............................ 8,331 7,384 7,806
Operation and maintenance................................. 582 519 496
Merger-related and asset impairment charges............... 75 -- --
Depreciation, depletion, and amortization................. 247 208 183
Taxes, other than income taxes............................ 62 56 63
------ ------ ------
9,297 8,167 8,548
------ ------ ------
Operating income............................................ 298 346 302
------ ------ ------
Other income
Equity investment earnings................................ 61 45 32
Interest income........................................... 30 15 9
Net gain on sale of assets................................ 24 34 1
Other, net................................................ 34 24 8
------ ------ ------
149 118 50
------ ------ ------
Income before interest, income taxes, and other charges..... 447 464 352
------ ------ ------
Non-affiliated interest and debt expense.................... 136 123 133
Affiliated interest expense, net............................ 40 28 8
Income tax expense.......................................... 85 92 76
------ ------ ------
261 243 217
------ ------ ------
Income before cumulative effect of accounting change........ 186 221 135
Cumulative effect of accounting change, net of income
taxes..................................................... (13) -- --
------ ------ ------
Net income.................................................. $ 173 $ 221 $ 135
====== ====== ======
The accompanying Notes are an integral part of these Consolidated Financial
Statements.
32
36
EL PASO TENNESSEE PIPELINE CO.
CONSOLIDATED BALANCE SHEETS
(IN MILLIONS, EXCEPT SHARE AMOUNTS)
DECEMBER 31,
---------------
1999 1998
------ ------
ASSETS
Current assets
Cash and cash equivalents................................. $ 32 $ 28
Accounts and notes receivable, net
Customer............................................... 582 651
Receivables from affiliates............................ 91 79
Other.................................................. 223 130
Materials and supplies.................................... 23 21
Deferred income taxes..................................... 107 75
Assets from price risk management activities.............. 231 444
Deposits in escrow........................................ 101 --
Other..................................................... 114 87
------ ------
Total current assets.............................. 1,504 1,515
Property, plant, and equipment, net......................... 6,004 5,733
Investments in unconsolidated affiliates.................... 1,509 622
Other....................................................... 737 508
------ ------
Total assets...................................... $9,754 $8,378
====== ======
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities
Accounts and notes payable
Trade.................................................. $ 868 $ 708
Payables to affiliates................................. 1,434 981
Other.................................................. 233 145
Short-term borrowings (including current maturities of
long-term debt)........................................ 657 194
Liabilities from price risk management activities......... 234 355
Other..................................................... 266 333
------ ------
Total current liabilities......................... 3,692 2,716
------ ------
Long-term debt, less current maturities..................... 1,459 1,467
------ ------
Deferred income taxes....................................... 1,409 1,276
------ ------
Other....................................................... 676 673
------ ------
Commitments and contingencies (See Note 8)
Minority interest........................................... 88 74
------ ------
Stockholders' equity
Preferred stock, 20,000,000 shares authorized; Series A,
no par; 6,000,000 shares issued; stated at liquidation
value.................................................. 300 300
Common stock, par value $0.01 per share; authorized
100,000 shares; issued 1,971 shares.................... -- --
Additional paid-in capital................................ 1,707 1,580
Retained earnings......................................... 451 306
Accumulated other comprehensive income.................... (28) (14)
------ ------
Total stockholders' equity........................ 2,430 2,172
------ ------
Total liabilities and stockholders' equity........ $9,754 $8,378
====== ======
The accompanying Notes are an integral part of these Consolidated Financial
Statements.
33
37
EL PASO TENNESSEE PIPELINE CO.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN MILLIONS)
YEAR ENDED DECEMBER 31,
---------------------------
1999 1998 1997
------- ----- -------
Cash flows from operating activities
Net income................................................ $ 173 $ 221 $ 135
Adjustments to reconcile net income to net cash from
operating activities
Depreciation, depletion, and amortization.............. 247 208 183
Deferred income taxes.................................. 69 93 191
Net gain on sale of assets............................. (24) (34) (1)
Undistributed earnings in equity investees............. (30) (29) (3)
Non-cash merger-related and asset impairment charges... 75 -- --
Cumulative effect of accounting changes, net of income
taxes................................................ 13 -- --
Working capital changes, net of non-cash transactions
Accounts and notes receivable........................ (76) 402 447
Net price risk management activities................. (178) (45) 5
Accounts and notes payable........................... 92 (440) (153)
Other working capital changes........................ (67) 168 (381)
Other.................................................. 31 (269) (14)
------- ----- -------
Net cash provided by operating activities......... 325 275 409
------- ----- -------
Cash flows from investing activities
Capital expenditures...................................... (458) (309) (192)
Investment in joint ventures and equity investees......... (790) (547) (249)
Cash paid for acquisitions, net of cash received.......... (165) (30) (197)
Proceeds from sales of assets............................. 31 60 57
Return of investment in joint ventures and equity
investees.............................................. 33 153 --
Cash deposited in escrow related to equity investee....... (101) -- --
Other..................................................... (6) (4) (39)
------- ----- -------
Net cash used in investing activities............. (1,456) (677) (620)
------- ----- -------
Cash flows from financing activities
Net commercial paper borrowings........................... 459 190 --
Issuance of Series B Preferred Stock...................... -- -- 150
Revolving credit borrowings............................... -- -- 417
Revolving credit repayments............................... -- (417) (1,600)
Long-term debt retirements................................ (4) (46) (15)
Net proceeds from issuance of long-term debt.............. -- 391 883
Dividends paid on preferred stock......................... (25) (25) (36)
Net proceeds from issuance of notes payable............... 101 -- --
Net change in other affiliated advances payable........... 496 275 433
Capital contributions..................................... 108 20 --
Other..................................................... -- (2) (4)
------- ----- -------
Net cash provided by financing activities......... 1,135 386 228
------- ----- -------
Increase (decrease) in cash and cash equivalents............ 4 (16) 17
Cash and cash equivalents
Beginning of period....................................... 28 44 27
------- ----- -------
End of period............................................. $ 32 $ 28 $ 44
======= ===== =======
The accompanying Notes are an integral part of these Consolidated Financial
Statements.
34
38
EL PASO TENNESSEE PIPELINE CO.
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
(IN MILLIONS)
FOR THE YEARS ENDED DECEMBER 31,
---------------------------------------------------
1999 1998 1997
--------------- --------------- ---------------
SHARES AMOUNT SHARES AMOUNT SHARES AMOUNT
------ ------ ------ ------ ------ ------
SERIES A PREFERRED STOCK:
Balance at beginning of year............... 6 $ 300 6 $ 300 6 $ 296
Other...................................... 4
-- ------ -- ------ -- ------
Balance at end of year.................. 6 300 6 300 6 300
== ------ == ------ == ------
COMMON STOCK: -- -- -- -- -- --
== ------ == ------ == ------
ADDITIONAL PAID-IN CAPITAL:
Balance at beginning of year............... 1,580 1,529 1,482
Capital contributions...................... 120 47 44
Allocated tax benefit of El Paso's equity
plans................................... 7 4 --
Other...................................... -- -- 3
------ ------ ------
Balance at end of year.................. 1,707 1,580 1,529
------ ------ ------
RETAINED EARNINGS:
Balance at beginning of year............... 306 114 19
Net income................................. 173 221 135
Dividends to parent........................ (1) (3) (4)
Preferred dividends........................ (25) (25) (36)
Other...................................... (2) (1) --
------ ------ ------
Balance at end of year.................. 451 306 114
------ ------ ------
ACCUMULATED OTHER COMPREHENSIVE INCOME:
Balance at beginning of year............... (14) (7) --
Cumulative translation adjustment.......... (12) (7) (7)
Net change in unrealized loss on securities
(net of tax benefit of $1.3 in 1999).... (2) -- --
------ ------ ------
Balance at end of year.................. (28) (14) (7)
------ ------ ------
Total stockholders' equity................... $2,430 $2,172 $1,936
====== ====== ======
Comprehensive income......................... $ 159 $ 214 $ 128
====== ====== ======
The accompanying Notes are an integral part of these Consolidated Financial
Statements.
35
39
EL PASO TENNESSEE PIPELINE CO.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Change in Company Structure
In 1998 and again in 1999, El Paso completed a series of steps to effect a
tax-free internal reorganization. In the 1998 reorganization, certain merchant
energy operations were transferred to EPTPC in exchange for 934,000 shares of
Series C Preferred Stock, in a transaction valued at $47 million. Following that
initial step, the operations of Field Services and International were
transferred and became subsidiaries of EPTPC. EPTPC issued 971 shares of its
common stock as consideration for these transferred assets and operations and
for the redemption of outstanding Series B and Series C Preferred Stock. This
transaction had a total value of $667 million at December 31, 1998. In the 1999
reorganization, the power operations of El Paso, along with the merchant
operations acquired by El Paso in its October 1999 merger with Sonat Inc., were
transferred to, and became subsidiaries of, EPTPC through a tax-free capital
contribution. The transaction had a total value of $98 million. These
restructuring transactions have been treated as transfers of ownership between
entities under common control and were accounted for in a manner similar to a
pooling of interests. Accordingly, all information in these financial statements
has been restated as though the transactions occurred in the earliest period
presented.
The following table reflects the operating revenues and net income,
excluding the effects of the tax-free internal reorganizations, for the periods
ended December 31:
1999 1998 1997
------ ------ ------
(IN MILLIONS)
Operating revenues.......................................... $4,487 $5,059 $3,602
Net income.................................................. 167 209 112
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.
Use of Estimates
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that effect the reported amounts of assets, liabilities, revenues
and expenses and disclosure of contingent assets and liabilities that exist at
the date of the financial statements. Actual results are likely to differ from
those estimates.
Accounting for Regulated Operations
The Company's 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 Statement of Financial Accounting Standards ("SFAS")
No. 71, Accounting for the Effects of Certain Types of Regulation, which may
differ from the accounting requirements of 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
36
40
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
or 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 $32 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 $18 million and $16
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. At December 31, 1999
and 1998, the allowance for gas imbalances was less than $2 million and $4
million, respectively.
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 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
37
41
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 24
percent. This results in remaining economic lives of groups ranging from 2 to 30
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. 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 $462 million and $249 million at December 31,
1999, and 1998, respectively. The capitalized allowance for debt and equity
funds used during construction for the years ended December 31, 1999 and 1998,
was $9 million and $4 million, 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.
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
$33 million and $13 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 income of the Company
for the year ended December 31, 1999, would have been $192 million.
38
42
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.
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,
39
43
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 5 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.
El Paso maintains a tax sharing policy which provides, among other things,
that (i) each company in a taxable income position will be currently charged
with an amount equivalent to its federal income tax computed on a separate
return basis, and (ii) each company in a tax loss position will be reimbursed
currently to the extent its deductions, including general business credits, were
utilized in the consolidated return. Under the policy, El Paso pays all federal
income taxes directly to the IRS and will bill or refund, as applicable, its
subsidiaries for their applicable portion of such income tax payments. Beginning
with the 1999 tax return, the Company joined the El Paso consolidated federal
tax return. Prior to 1999, the Company filed a separate tax return and was not
subject to El Paso's tax sharing policy.
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, 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
40
44
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
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 March 2000, the Company completed an agreement
with a third party to equally own International's interests in EAPRC. In the
transaction, the Company exchanged 50 percent of its ownership in EAPRC with the
third party for cash totaling $87 million. The Company expects to record a gain
relating to this transaction in the first quarter of 2000. 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 Deposits in escrow and the loan is reflected in Accounts and notes
payable in the Consolidated Balance Sheets. The Company used the proceeds from
the March 2000 transaction to repay the loan.
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 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.
41
45
During 1999, El Paso 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. El Paso 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 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, El Paso 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. The additional interest was contributed to the
Company in January 2000.
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 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.
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.
Pending Mergers and Acquisitions
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 October 1999, El Paso completed its $6 billion merger with Sonat Inc. in
a transaction accounted for as a pooling of interests. As a result of this
transaction, certain of El Paso's and Sonat Inc.'s subsidiaries incurred
merger-related as well as certain asset impairment charges. Charges included in
the Company's Consolidated Statements of Income reflect the effect of the Sonat
Inc. merger on the Company and its
42
46
subsidiaries. Total charges were $75 million, and included $63 million of
merger-related asset impairment charges for duplicate systems and facilities
identified as impaired following the merger and $9 million related to conforming
accounting practices and policies of El Paso and Sonat Inc.'s merchant
operations. In addition, the Company incurred $3 million during the year in
asset impairment charges related to discontinued capital projects.
In connection with El Paso's October 1999 merger with Sonat Inc., El Paso
was ordered by the Federal Trade Commission ("FTC") to sell East Tennessee
Natural Gas Company. The sale is anticipated to close in the first quarter of
2000 pending FTC approval. The Company will treat the gain from this sale, if
material, as an extraordinary item, net of income taxes in the Consolidated
Statements of Income.
4. INCOME TAXES
The following table reflects the components of income tax expense for the
years ended December 31:
1999 1998 1997
---- ---- -----
(IN MILLIONS)
Current
Federal.................................................. $ 21 $ 10 $ (80)
State.................................................... (16) (15) (35)
Foreign.................................................. 11 4 --
---- ---- -----
16 (1) (115)
---- ---- -----
Deferred
Federal.................................................. 64 86 155
State.................................................... 6 9 36
Foreign.................................................. (1) (2) --
---- ---- -----
69 93 191
---- ---- -----
Total income tax expense......................... $ 85 $ 92 $ 76
==== ==== =====
Income tax expense of the Company differs from the amount computed by
applying the statutory federal income tax rate (35 percent) to income before
taxes and cumulative effect of accounting change. The following table outlines
the reasons for the differences for the periods ended December 31:
1999 1998 1997
---- ----- ----
(IN MILLIONS)
Income tax expense at the statutory federal rate of 35%..... $ 95 $ 110 $ 74
Increase (decrease)
State income tax, net of federal income tax benefit....... (7) (4) 1
Dividend exclusion........................................ (6) (1) --
Merger-related costs...................................... 5 -- --
Foreign income taxed at different rates and foreign equity
investment earnings.................................... (4) (6) --
Other..................................................... 2 (7) 1
---- ----- ----
Income tax expense.......................................... $ 85 $ 92 $ 76
==== ===== ====
Effective tax rate.......................................... 31% 29% 36%
==== ===== ====
43
47
The following table reflects the components of the net deferred tax
liability at December 31:
1999 1998
------ ------
(IN MILLIONS)
Deferred tax liabilities
Accumulated tax depreciation over book depreciation....... $1,671 $1,635
Regulatory issues......................................... 62 74
Other..................................................... 109 99
------ ------
Total deferred tax liability...................... 1,842 1,808
------ ------
Deferred tax assets
U.S. net operating loss and tax credit carryovers......... 135 60
Accrual for regulatory issues............................. 68 111
Postretirement benefit obligations........................ 111 114
Environmental reserve..................................... 71 63
Other..................................................... 162 265
Valuation allowance....................................... (4) (5)
------ ------
Total deferred tax asset.......................... 543 608
------ ------
Net deferred tax liability(a)............................... $1,299 $1,200
====== ======
- ---------------
(a) As of December 31, 1999, and December 31, 1998, $3 million and $1 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.
Under El Paso's tax sharing policy with the Company, the Company is
allocated the tax benefit associated with its employees' exercise of
non-qualified stock options and the vesting of restricted stock as well as
restricted stock dividends. This allocation reduced taxes payable by $7 million
and $4 million in 1999 and 1998, respectively. Such benefits are included in
additional paid-in capital in the Consolidated Balance Sheets. See Note 1 for
further discussion of the tax sharing policy.
As of December 31, 1999, the Company has $17 million of alternative minimum
tax credit carryovers, $332 million of net operating loss carryovers and $6
million of capital loss carryovers. The alternative minimum tax credits carry
forward indefinitely. The net operating loss carry forward periods end as
follows -- approximately $3 million in 2004, $4 million in 2005, $9 million in
2006, $15 million in 2007, $14 million in the years 2008 through 2011, $181
million in 2012, $16 million in 2018 and $90 million in 2019. The carry forward
period for the capital loss ends in 2003. 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. Any tax benefits subsequently recognized
from the reversal of the allowance will be allocated to additional acquisition
cost assigned to utility plant.
Prior to 1999, 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 1998 tax-free
44
48
reorganization described in Note 1, El Paso and its subsidiaries, including
EPTPC and its subsidiaries, will file one consolidated federal income tax return
beginning in 1999.
In connection with the acquisition of EPTPC by El Paso, 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.
5. 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:
1999 1998
--------------------- ---------------------
CARRYING CARRYING
AMOUNT FAIR VALUE AMOUNT FAIR VALUE
-------- ---------- -------- ----------
(IN MILLIONS)
Balance sheet financial instruments:
Long-term debt, excluding project financing....... $1,467 $1,405 $1,471 $1,563
Other financial instruments:
Trading
Futures contracts................................. $ (24) $ (24) $ (10) $ (10)
Option contracts(1)............................... 264 264 80 80
Swap and forward contracts........................ (69) (69) (6) (6)
Non-Trading
Equity swap....................................... $ 10 $ 10 $ 3 $ 3
Commodity option contracts........................ -- -- -- 1
Commodity swap and forward contracts.............. -- 18 -- (14)
- ---------------
(1) Excludes transportation capacity and natural gas in storage held for trading
purposes.
45
49
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.
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, $425 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.
AVERAGE FAIR
VALUE FOR THE
YEAR ENDED
ASSETS LIABILITIES DECEMBER 31,(1)
------ ----------- ---------------
(IN MILLIONS)
1999
Futures contracts.................................. $ 2 $ (26) $(12)
Option contracts................................... 455 (35) 184
Swap and forward contracts......................... 200 (269) 90
1998
Futures contracts.................................. $(72) $ 62 $ (9)
Option contracts................................... 224 (60) 55
Swap and forward contracts......................... 409 (415) (14)
- ---------------
(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):
FIXED PRICE FIXED PRICE MAXIMUM
PAYOR RECEIVER TERMS IN YEARS
----------- ----------- --------------
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
- ---------------
(1) Liquids include crude oil, condensate and other petroleum based products.
46
50
The notional amount and terms of foreign currency forward purchases and
sales at December 31, 1999, were as follows:
NOTIONAL VOLUME
------------------------- MAXIMUM
BUY SELL TERM IN YEARS
----------- ----------- --------------
Foreign Currency (in millions)
Canadian Dollars................................. 411 189 12
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.
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:
ASSETS FROM PRICE RISK MANAGEMENT ACTIVITIES
AS OF DECEMBER 31, 1999
---------------------------------------------
INVESTMENT BELOW
GRADE(A) INVESTMENT GRADE TOTAL(B)
----------- ----------------- ---------
(IN MILLIONS)
Energy marketers......................................... $226 $ 1 $227
Financial institutions................................... 16 -- 16
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................................... $674 $ 3 $677
==== === ====
47
51
ASSETS FROM PRICE RISK MANAGEMENT ACTIVITIES
AS OF DECEMBER 31, 1998
---------------------------------------------
INVESTMENT BELOW
GRADE(A) INVESTMENT GRADE TOTAL(B)
----------- ----------------- ---------
(IN MILLIONS)
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
==== === ====
- ---------------
(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.
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 of Field Services, as well as the production activities of El Paso.
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.
1999 1998
-------------------- ---------------------
NOTIONAL NOTIONAL
VOLUME VOLUME
---------- MAXIMUM ---------- MAXIMUM
BUY SELL TERM BUY SELL TERM
--- ---- ------- --- ---- --------
Commodity
Natural Gas (TBtu)............................. -- 13 1 year -- 27 2 years
Power (Thousands of MWh)....................... -- -- -- 39 45 4 months
Liquids (TBtu)................................. -- 33 1 year 3 9 1 year
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.
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.
48
52
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 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.
6. PROPERTY, PLANT, AND EQUIPMENT
Property, plant, and equipment consisted of the following at December 31:
1999 1998
------ ------
(IN MILLIONS)
Property, plant, and equipment, at cost
Natural Gas Transmission.................................. $2,608 $2,438
Merchant Energy........................................... 199 98
International............................................. 316 162
Field Services............................................ 1,220 1,179
Corporate and Other....................................... 79 73
------ ------
4,422 3,950
Less accumulated depreciation............................... 789 617
------ ------
3,633 3,333
Additional acquisition cost assigned to utility plant, net
of accumulated amortization............................... 2,371 2,400
------ ------
Total property, plant, and equipment, net................... $6,004 $5,733
====== ======
7. DEBT AND OTHER CREDIT FACILITIES
The average interest rate of short-term borrowings was 6.6% and 5.8% 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:
1999 1998
---- ----
(IN MILLIONS)
Commercial paper............................................ $649 $190
Current maturities of long-term debt........................ 8 4
---- ----
$657 $194
==== ====
49
53
Long-term debt outstanding consisted of the following at December 31:
1999 1998
------ ------
(IN MILLIONS)
Long-term debt
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
6% Debentures due 2011................................. 86 86
7.5% Debentures due 2017............................... 300 300
7% Debentures due 2027................................. 300 300
7% Debentures due 2028................................. 400 400
7.625% Debentures due 2037............................. 300 300
EPEC Corporation
Note, 9.625% due 2001.................................. 13 13
Other....................................................... 3 4
------ ------
1,495 1,499
Less: Unamortized discount................................ 28 28
Current maturities.................................. 8 4
------ ------
Long-term debt, less current maturities................... $1,459 $1,467
====== ======
The following are aggregate maturities of the principal amounts of
long-term debt for the next 5 years and in total thereafter:
(IN MILLIONS)
-------------
2000........................................................ $ 8
2001........................................................ 38
2002........................................................ 12
2003........................................................ --
2004........................................................ --
Thereafter.................................................. 1,437
------
Total long-term debt, including current
maturities....................................... $1,495
======
Other Financing Arrangements
TGP is designated as a borrower under El Paso's $1,250 million 364-day, and
$750 million, five-year revolving credit facilities (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. 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 borrowings under the Revolving Credit Facility
was equal to LIBOR plus 50 basis points, and no amounts were outstanding.
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.
In November 1999, EPTPC retired its 8% notes with an aggregate principal of
$3 million.
50
54
8. 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
$368 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. El Paso unconditionally guaranteed all
obligations of EPNC under this lease.
51
55
Minimum annual rental commitments at December 31, 1999, were as follows:
YEAR ENDING
DECEMBER 31, OPERATING LEASES
- ------------------------------------------------------------ ----------------
(IN MILLIONS)
2000..................................................... $ 6
2001..................................................... 6
2002..................................................... 5
Thereafter............................................... --
---
Total............................................. $17
===
Rental expense for operating leases for the years ended December 31, 1999,
1998, and 1997 was $13 million, $16 million, and $12 million, respectively.
Guarantees
At December 31, 1999, the Company had parental guarantees of approximately
$17 million in connection with various projects. El Paso has issued guarantees
and letters of credit associated with a number of the Company's projects,
including certain international projects.
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. In
addition, these pipelines have various pending regulatory proceedings. 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. TGP 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.
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 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.
52
56
Legal Proceedings
In February 1998, the United States and the State of Texas filed in a
United States District Court a Comprehensive Environmental Response,
Compensation and Liability Act ("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 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 the Company, 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 the Company, 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 $131 million for expected remediation costs, including
approximately $126 million for associated onsite, offsite and groundwater
technical studies, and approximately $5 million for other costs which the
Company anticipates incurring through 2027.
53
57
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 $94 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 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 11 sites under the Comprehensive Environmental Response, Compensation and
Liability Act (CERCLA or Superfund) or state equivalents. The Company has sought
to resolve its liability as a PRP with respect to these Superfund sites through
indemnification by third parties and/or settlements which provide for payment of
the Company's allocable share of remediation costs. As of December 31, 1999, the
Company has estimated its share of the remediation costs at these sites to be
between $3 million and $6 million and has provided reserves that it believes are
adequate for such costs. Since the clean-up costs are estimates and are subject
to revision as more information becomes available about the extent of
remediation required, and because in some cases the Company has asserted a
defense to any liability, the Company's estimate of its share of remediation
costs could change. Moreover, liability under the federal Superfund statute is
joint and several, meaning that the Company could be required to pay in excess
of its pro rata share of remediation costs. The Company's understanding of the
financial strength of other PRPs has been considered, where appropriate, in its
determination of its estimated liability as described herein. The Company
presently believes that the costs associated with the current status of such
entities as PRPs at the Superfund sites referenced above will not have a
material adverse effect on the Company's financial position, results of
operations, or cash flows.
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.
9. RETIREMENT BENEFITS
Pension and Retirement Benefits
El Paso maintains a pension plan to provide benefits as determined by a
cash balance formula covering substantially all of its employees, including
employees of the Company. Also, El Paso maintains a defined contribution plan
covering its employees, including employees of the Company. El Paso matches 75
percent of
54
58
participant basic contributions of up to 6 percent, with the matching
contribution being made in El Paso common stock. El Paso is responsible for
benefits accrued under its plan and allocates the related costs to its
affiliates. See Note 14 for a summary of transactions with affiliates.
During 1997, El Paso offered special termination benefits to former Tenneco
Inc. employees who were at least 55 years old and who were eligible to retire
under the Tenneco Retirement Plan on December 31, 1996. Eligible employees
accepting this offer and retiring by July 1, 1997, received a cash balance
credit based on an enhanced formula not to exceed one year's base salary. The
cost associated with the special termination benefits was accrued at December
31, 1996, as part of the liabilities assumed in the acquisition by EPEC. In
1997, the Company funded $11 million for these special termination benefits.
Other Postretirement Benefits
Following the acquisition of the Company by El Paso in 1996, the Company
retained responsibility for certain postretirement medical and life insurance
benefits for its former employees and employees who were eligible to retire on
December 31, 1996, and did so by July 1, 1997. Medical benefits for this closed
group of retirees are subject to deductibles, co-payment provisions, and other
limitations and dollar caps on the amount of employer costs. The Company has
reserved the right to change these benefits. Employees who retired after July 1,
1997, will continue to receive limited postretirement life insurance benefits.
Medical benefits are prefunded to the extent such costs are recoverable through
rates. Effective February 1, 1992, TGP began recovering through its rates the
other postretirement benefits ("OPEB") costs included in the June 1993 rate case
settlement. To the extent actual OPEB costs differ from the amounts funded, a
regulatory asset or liability is recorded.
The following table sets forth the change in benefit obligation, change in
plan assets, reconciliation of funded status, components of net periodic benefit
cost and assumptions used in determining other postretirement benefits as of and
for the twelve month periods ended September 30:
POSTRETIREMENT
BENEFITS
--------------
1999 1998
----- -----
(IN MILLIONS)
Change in benefit obligation
Benefit obligation at beginning of period................. $ 318 $ 350
Interest cost............................................. 20 21
Participant contributions................................. 7 4
Plan amendments........................................... -- (16)
Actuarial gain............................................ (18) --
Benefits paid............................................. (54) (41)
----- -----
Benefit obligation at end of period....................... $ 273 $ 318
===== =====
Change in plan assets
Fair value of plan assets at beginning of period.......... $ 8 $ 6
Employer contributions.................................... 45 39
Participant contributions................................. 7 4
Benefits paid............................................. (54) (41)
----- -----
Fair value of plan assets at end of period................ $ 6 $ 8
===== =====
Reconciliation of funded status
Funded status at end of period............................ $(267) $(310)
Fourth quarter contributions and income................... 11 13
Unrecognized net actuarial (gain) or loss................. (4) 14
Unrecognized prior service cost........................... (11) (12)
----- -----
Net accrued benefit cost at December 31................... $(271) $(295)
===== =====
55
59
The current liability portion of the postretirement benefits was $46
million as of December 31, 1999 and 1998.
POSTRETIREMENT BENEFITS
-----------------------
YEAR ENDED
DECEMBER 31,
-----------------------
1999 1998 1997
----- ----- -----
(IN MILLIONS)
Benefit cost for the plans includes the following components
Interest cost............................................. $20 $21 $25
Amortization of prior service cost........................ (1) (1) --
--- --- ---
Net benefit cost.......................................... $19 $20 $25
=== === ===
POSTRETIREMENT
BENEFITS
--------------
1999 1998
----- -----
Weighted average assumptions
Discount rate............................................. 7.50% 6.75%
Expected return on plan assets............................ 7.50% 7.50%
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. Assumed health care cost trends have a significant
effect on the amounts reported for other postretirement benefit plans. A
one-percentage point change from assumed health care cost trend rates would have
the following effects:
1999 1998
----- -----
(IN MILLIONS)
One Percentage Point Increase(a)
Accumulated Postretirement Benefit Obligation............. $ 1 $ 3
One Percentage Point Decrease(a)
Accumulated Postretirement Benefit Obligation............. $(1) $(2)
- ---------------
(a) A one percent increase or decrease would have effected the aggregate of
service cost and interest cost by an amount less than $.5 million.
10. PREFERRED STOCK
At December 31, 1999, EPTPC had authorized 20 million shares of preferred
stock. In November 1996, the Company issued 6 million shares of Series A
Preferred Stock. The Series A Preferred Stock is not convertible into shares of
any other class or series of stock of the Company and it has no maturity date.
Holders of shares of Series A Preferred Stock are entitled to receive cash
dividends payable quarterly at the rate of 8 1/4% of the stated value of $50 per
share. It is not redeemable at the option of EPTPC prior to December 31, 2001,
unless one or more amendments to the Internal Revenue Code are enacted that
reduce the percentage of the dividends received deduction as specified in
Section 243(a)(1) of the Internal Revenue Code. On or after December 31, 2001,
the Series A Preferred Stock is redeemable at the option of the Company, in
whole or in part, upon not less than 30 days' notice at a redemption price of
$50 per share, plus unpaid dividends.
11. SEGMENT INFORMATION
The Company has adopted the provisions of SFAS No. 131, Disclosures about
Segments of an Enterprise and Related Information. The Company has segregated
its business activities into four segments: Natural Gas Transmission, Merchant
Energy, International, and Field Services. 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.
56
60
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 income 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.
SEGMENTS
AS OF OR FOR THE YEAR ENDED DECEMBER 31, 1999
------------------------------------------------------------
NATURAL
GAS MERCHANT FIELD
TRANSMISSION ENERGY INTERNATIONAL SERVICES TOTAL
------------ -------- ------------- -------- -------
(IN MILLIONS)
Revenue from external customers
Domestic.................................... $ 739 $7,902 $ -- $ 361 $ 9,002
Foreign..................................... -- 518 73 -- 591
Intersegment revenue.......................... 34 20 -- 73 127
Merger-related and asset impairment charges... -- 67 -- 8 75
Depreciation, depletion, and amortization..... 146 32 14 52 244
Operating income (loss)....................... 360 (65) (32) 52 315
Other income.................................. 24 15 77 33 149
Earnings before interest and taxes............ 384 (50) 45 85 464
Assets
Domestic.................................... 5,042 1,881 166 1,109 8,198
Foreign..................................... -- 127 1,209 -- 1,336
Capital expenditures and investments in joint
ventures and equity investees............... 231 550 444 141 1,366
Equity investments............................ 124 479 791 115 1,509
SEGMENTS
AS OF OR FOR THE YEAR ENDED DECEMBER 31, 1998
------------------------------------------------------------
NATURAL
GAS MERCHANT FIELD
TRANSMISSION ENERGY INTERNATIONAL SERVICES TOTAL
------------ -------- ------------- -------- -------
(IN MILLIONS)
Revenue from external customers
Domestic.................................... $ 728 $7,188 $ -- $ 212 $ 8,128
Foreign..................................... -- 323 58 -- 381
Intersegment revenue.......................... 38 21 -- 65 124
Depreciation, depletion and amortization...... 143 8 9 46 206
Operating income (loss)....................... 332 (10) (27) 65 360
Other income.................................. 24 13 52 12 101
Earnings before interest and taxes............ 356 3 25 78 462
Assets
Domestic.................................... 4,927 1,313 249 1,029 7,518
Foreign..................................... -- 73 581 -- 654
Capital expenditures and investments in joint
ventures and equity investees............... 144 46 536 104 830
Equity investments............................ 74 43 436 69 622
57
61
SEGMENTS
FOR THE YEAR ENDED OF DECEMBER 31, 1997
-----------------------------------------------------------
NATURAL
GAS MERCHANT FIELD
TRANSMISSION ENERGY INTERNATIONAL SERVICES TOTAL
------------ -------- ------------- -------- ------
(IN MILLIONS)
Revenue from external customers
Domestic...................................... $765 $7,470 $ -- $381 $8,616
Foreign....................................... -- 218 13 -- 231
Intersegment revenue............................ 33 25 -- 27 85
Depreciation, depletion and amortization........ 137 7 1 35 180
Operating income (loss)......................... 304 (22) (24) 67 325
Other income.................................... 13 1 26 8 48
Earnings before interest and taxes.............. 317 (21) 2 75 373
The reconciliations of revenues for reportable segments to total
consolidated revenues are presented below.
FOR THE YEAR ENDED
DECEMBER 31,
------------------------
1999 1998 1997
------ ------ ------
(IN MILLIONS)
Total revenues for segments................................. $9,720 $8,633 $8,932
Corporate revenues.......................................... 2 4 3
Elimination of intersegment revenue......................... (127) (124) (85)
------ ------ ------
Total consolidated revenues....................... $9,595 $8,513 $8,850
====== ====== ======
The reconciliations of other income for reportable segments to total
consolidated other income are presented below.
FOR THE YEAR ENDED
DECEMBER 31,
------------------
1999 1998 1997
---- ---- ----
(IN MILLIONS)
Total other income for segments............................. $149 $101 $48
Corporate other income...................................... -- 17 2
---- ---- ---
Total consolidated other income................... $149 $118 $50
==== ==== ===
The reconciliations of EBIT to income before cumulative effect of
accounting change are presented below.
FOR THE YEAR ENDED
DECEMBER 31,
------------------
1999 1998 1997
---- ---- ----
(IN MILLIONS)
Total EBIT for segments..................................... $464 $462 $373
Corporate income (expense), net............................. (17) 2 (21)
Interest and debt expense................................... 176 151 141
Income tax expense.......................................... 85 92 76
---- ---- ----
Income before cumulative effect of accounting
change........................................... $186 $221 $135
==== ==== ====
58
62
The reconciliations of assets for reportable segments to total consolidated
assets are presented below.
AS OF DECEMBER 31,
-------------------
1999 1998
-------- --------
(IN MILLIONS)
Total assets for segments................................... $9,534 $8,172
Corporate and other assets.................................. 220 206
------ ------
Total consolidated assets......................... $9,754 $8,378
====== ======
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.
12. SUPPLEMENTAL CASH FLOW INFORMATION
The following table contains supplemental cash flow information for the
years ended December 31:
1999 1998 1997
---- ---- ----
(IN MILLIONS)
Interest payments......................................... $208 $189 $141
Income tax refunds........................................ (1) (86) (78)
13. 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:
YEAR ENDED DECEMBER 31,
-----------------------
1999 1998 1997
----- ----- -----
(IN MILLIONS)
Operating results data:
Revenues and other income................................. $510 $275 $130
Costs and expenses........................................ 444 229 97
Income from continuing operations......................... 66 46 33
Net income................................................ 61 45 32
DECEMBER 31,
----------------
1999 1998
------ ------
Financial position data:
Current assets............................................ $ 455 $ 208
Non-current assets........................................ 3,866 1,999
Short-term debt........................................... 143 42
Other current liabilities................................. 287 104
Long-term debt............................................ 2,139 1,168
Other non-current liabilities............................. 305 200
Minority interest......................................... 9 --
Equity in net assets(1)................................... 1,438 693
- ---------------
(1) Investments in unconsolidated affiliates on the Consolidated Balance Sheets
include amounts associated with unamortized purchase price differences
relating to certain unconsolidated investees.
During 1999, El Paso formed Sabine River Investors, L.L.C., a wholly owned
limited liability company, and other separate legal entities, for the purpose of
generating funds for El Paso to invest in capital projects
59
63
and other assets. The proceeds are collateralized by certain assets of El Paso,
including 100 percent of the Company's investments in Bear Creek and El Paso
Energy Partners. At December 31, 1999, the Company's investment in Bear Creek
was $89 million and its investment in El Paso Energy Partners was $59 million.
14. TRANSACTIONS WITH AFFILIATES
El Paso allocated certain general administrative expenses to the Company.
The allocation is based on the estimated level of effort devoted to the
Company's operations and relative size based on revenues, gross property and
payroll. In 1997, the Company performed most of its own administrative
functions, and therefore, allocated general and administrative expenses were
lower. In addition, the Company enters into transactions with other El Paso
subsidiaries and unconsolidated affiliates in the ordinary course of its
business to transport, sell and purchase natural gas. Services provided by these
affiliates for the benefit of the Company are based on the same terms as
nonaffiliates. Charges from affiliates were $209 million, $180 million and $39
million for the years ended December 31, 1999, 1998 and 1997, respectively.
15. 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.
QUARTERS ENDED
-----------------------------------------------
DECEMBER 31 SEPTEMBER 30 JUNE 30 MARCH 31
----------- ------------ ------- --------
(IN MILLIONS)
1999
Operating revenues...................................... $2,184 $3,019 $2,360 $2,032
Merger-related and asset impairment charges............. 75 -- -- --
Operating income........................................ 50 27 116 105
Income before cumulative effect of accounting change.... 9 23 90 64
Cumulative effect of accounting change, net of income
taxes................................................. -- -- -- (13)
Net income.............................................. 9 23 90 51
1998
Operating revenues...................................... $1,834 $2,255 $1,975 $2,449
Operating income........................................ 108 65 66 107
Net income.............................................. 81 41 41 58
60
64
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors and Stockholders of
El Paso Tennessee Pipeline Co.:
In our opinion, the consolidated financial statements listed in the index
appearing under Item 14. (a) 1. present fairly, in all material respects, the
consolidated financial position of El Paso Tennessee Pipeline Co. as of December
31, 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. 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
61
65
SCHEDULE II
EL PASO TENNESSEE PIPELINE CO.
VALUATION AND QUALIFYING ACCOUNTS
YEARS ENDED DECEMBER 31, 1999, 1998, AND 1997
(IN MILLIONS)
BALANCE AT CHARGED TO CHARGED TO BALANCE
BEGINNING COSTS AND OTHER AT END
DESCRIPTION OF YEAR EXPENSES ACCOUNTS DEDUCTIONS OF YEAR
----------- ---------- ---------- ---------- ---------- --------
1999
Allowance for doubtful accounts....... $20 $ 5 $(2) $ (3)(a) $20
Allowance for price risk management
activities......................... 28 21 -- (10)(b) 39
Valuation allowance on deferred tax
assets............................. 5 -- -- (1) 4
1998
Allowance for doubtful accounts....... $30 $ 5 $ 5 $(20)(a) $20
Allowance for price risk management
activities......................... 25 23 -- (20)(b) 28
Valuation allowance on deferred tax
assets............................. 8 -- 4 (7)(c) 5
1997
Allowance for doubtful accounts....... $38 $ 9 $-- $(17)(a) $30
Allowance for price risk management
activities......................... 4 39 -- (18)(b) 25
Valuation allowance on deferred tax
assets............................. -- -- 8(d) -- 8
- ---------------
(a) Primarily accounts written off.
(b) Primarily liquidation of positions on which allowance was established.
(c) $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.
62
66
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The information appearing under the caption "Proposal No. 1 -- Nominee for
Election of Director by Series A Preferred Stockholders" and "Section 16(a)
Beneficial Ownership Reporting Compliance" in EPTPC's proxy statement for the
2000 Annual Meeting of Stockholders is incorporated herein by reference.
Information regarding executive officers of EPTPC is presented in Item 1 of this
Form 10-K under the caption "Executive Officers of the Registrant" and is
incorporated herein by reference.
ITEM 11. EXECUTIVE COMPENSATION
Information appearing under the caption "Executive Compensation" in EPTPC'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 captions "Security Ownership of Beneficial
Owners and Management of the Company" and "Security Ownership of a Beneficial
Owner and Management of EPEC" in EPTPC's proxy statement for the 2000 Annual
Meeting of Stockholders is incorporated herein by reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Information appearing under the caption "Relationship with El Paso Energy
Corporation" in EPTPC's proxy statement for the 2000 Annual Meeting of
Stockholders is incorporated herein by reference.
63
67
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 and combined financial statements of the Company
are included in Part II, Item 8 of this report:
PAGE
----
Consolidated Statements of Income...................... 32
Consolidated Balance Sheets............................ 33
Consolidated Statements of Cash Flows.................. 34
Consolidated Statements of Stockholders' Equity........ 35
Notes to Consolidated Financial Statements............. 36
Report of Independent Accountants...................... 61
2. Financial statement schedules and supplementary information required to
be submitted.
Schedule II -- Valuation and qualifying accounts....... 62
Schedules other than that listed above are omitted
because they are not applicable
3. Exhibit list............................................ 65
(b) Reports on Form 8-K:
None.
64
68
EL PASO TENNESSEE PIPELINE CO.
EXHIBIT LIST
DECEMBER 31, 1999
Exhibits not incorporated by reference to a prior filing are designated by
an asterisk; all exhibits not so designated are incorporated herein by reference
to a prior filing as indicated.
EXHIBIT
NUMBER DESCRIPTION
------- -----------
2.A -- Amended and Restated Merger Agreement dated as of June
19, 1996, among EPNG, El Paso Merger Company and EPTPC
(Exhibit 2.A to EPNG's Registration Statement on Form S-4
filed August 27, 1996, File No. 333-10911).
2.B -- Distribution Agreement, dated as of November 1, 1996,
among EPTPC, new Tenneco Inc. and Newport News
Shipbuilding Inc. (Exhibit 2.2 to EPNG's Form 8-K filed
December 26, 1996, File No. 1-2700); Amendment No. 1 to
Distribution Agreement entered into as of December 11,
1996, by and among EPTPC, new Tenneco Inc. and Newport
News Shipbuilding Inc. (Exhibit 2.3 to EPNG's Form 8-K/A
filed January 21, 1997, File No. 1-2700).
3.A -- Certificate of Incorporation as amended and supplemented
as of March 1, 1995 (Exhibit 3(a)(1) to EPTPC Form 10-K
for 1994, File No. 1-9864); Certificate of Retirement of
Preferred Stock Redeemed or Purchased, dated February 16,
1996; Certificate of Elimination of the Series A
Cumulative Preferred Stock of Tenneco Inc. dated February
27, 1996; Certificate of Elimination of the Variable Rate
Preferred Stock of Tenneco Inc. dated February 27, 1996;
Certificate of Elimination of the Participating Preferred
Stock of Tenneco Inc. dated February 27, 1996;
Certificate of Designation, Preferences and Rights of
8 1/4% Cumulative Junior Preferred Stock, Series A, dated
November 18, 1996; Certificate of Amendment of
Certificate of Incorporation, dated December 11, 1996;
Certificate of Merger dated December 11, 1996; and
Certificate of Designation, Preferences and Rights of
8 1/2% Cumulative Junior Preferred Stock, Series B, dated
March 5, 1997 (Exhibit 3.A to EPTPC's Form 10-K for 1996,
File No. 1-9864); Certificate of Designation, Preferences
and Rights of 6 1/4% Cumulative Junior Preferred Stock,
Series C, dated March 4, 1998 (Exhibit 3.A.1 to EPTPC's
Form 10-K for 1997, File No. 1-9864 (the "EPTPC 1997
10-K")).
3.A .1 -- Certificate of Elimination of 8 1/2% Cumulative Junior
Preferred Stock, Series B, dated January 14, 1999,
Certificate of Elimination of 6 1/4% Cumulative Junior
Preferred Stock, Series C, dated January 14, 1999
(Exhibit 3.A.1 to the EPTPC 1998 10-K).
3.B -- By-laws of EPTPC, as amended March 1, 1998 (Exhibit 3.B
to the EPTPC 1997 10-K).
4.A -- Indenture dated as of March 4, 1997, between TGP and The
Chase Manhattan Bank (Exhibit 4.1 to the EPTPC 1997
10-K); First Supplemental Indenture dated as of March 13,
1997, between TGP and The Chase Manhattan Bank (Exhibit
4.2 to the EPTPC 1997 10-K); Second Supplemental
Indenture dated as of March 13, 1997, between TGP and The
Chase Manhattan Bank (Exhibit 4.3 to the EPTPC 1997
10-K); Third Supplemental Indenture dated as of March 13,
1997, between TGP and The Chase Manhattan Bank (Exhibit
4.4 to the EPTPC 1997 10-K); Fourth Supplemental
Indenture dated as of October 9, 1998, between TGP and
The Chase Manhattan Bank (Exhibit 4.2 to TGP's Form 8-K
filed October 9, 1998, File No. 1-4101).
65
69
EXHIBIT
NUMBER DESCRIPTION
------- -----------
10.A -- $1,250,000,000 364-Day Revolving Credit and Competitive
Advance Facility ("CAF") 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 EPTPC's Form 10-Q filed November 15,
1999, File No. 1-9864)
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 El Paso's
Form 10-Q filed November 12, 1998, File No. 1-4101 (the
"El Paso 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, 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.E to the El Paso 1998
Third Quarter 10-Q).
*21 -- List of Subsidiaries.
*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.
UNDERTAKING
The undersigned Registrant hereby undertakes, pursuant to Regulation S-K,
Item 601(b), paragraph (4)(iii), to furnish to the Securities and Exchange
Commission upon request all constituent instruments defining the rights of
holders of long-term debt of Registrant and its consolidated subsidiaries not
filed herewith for the reason that the total amount of securities authorized
under any of such instruments does not exceed 10 percent of the total
consolidated assets of Registrant and its consolidated subsidiaries.
66
70
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, as amended, El Paso Tennessee Pipeline Co. has duly caused
this report to be signed on its behalf by the undersigned, thereunto duly
authorized on the 10th day of March 2000.
EL PASO TENNESSEE PIPELINE CO.
By: /s/ WILLIAM A. WISE
------------------------------------
William A. Wise
Chairman of the Board, President
and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1933, as
amended, this report has been signed below by the following persons on behalf of
El Paso Tennessee Pipeline Co. and in the capacities and on the dates as
indicated.
SIGNATURE TITLE DATE
--------- ----- ----
/s/ WILLIAM A. WISE Chairman of the Board, President, March 10, 2000
- -------------------------------------------- Chief Executive Officer and
(William A. Wise) Director
/s/ H. BRENT AUSTIN Executive Vice President, Chief March 10, 2000
- -------------------------------------------- Financial Officer and Director
(H. Brent Austin)
/s/ JOEL RICHARDS III Executive Vice President and March 10, 2000
- -------------------------------------------- Director
(Joel Richards III)
/s/ BRITTON WHITE JR. Executive Vice President, General March 10, 2000
- -------------------------------------------- Counsel and Director
(Britton White Jr.)
/s/ JEFFREY I. BEASON Senior Vice President, Controller March 10, 2000
- -------------------------------------------- and Director
(Jeffrey I. Beason)
/s/ KENNETH L. SMALLEY Director March 10, 2000
- --------------------------------------------
(Kenneth L. Smalley)
67
71
INDEX TO EXHIBITS
Exhibits not incorporated by reference to a prior filing are designated by
an asterisk, all exhibits not so designated are incorporated herein by reference
to a prior filing as indicated.
EXHIBIT
NUMBER DESCRIPTION
------- -----------
2.A -- Amended and Restated Merger Agreement dated as of June
19, 1996, among EPNG, El Paso Merger Company and EPTPC
(Exhibit 2.A to EPNG's Registration Statement on Form S-4
filed August 27, 1996, File No. 333-10911).
2.B -- Distribution Agreement, dated as of November 1, 1996,
among EPTPC, new Tenneco Inc. and Newport News
Shipbuilding Inc. (Exhibit 2.2 to EPNG's Form 8-K filed
December 26, 1996, File No. 1-2700); Amendment No. 1 to
Distribution Agreement entered into as of December 11,
1996, by and among EPTPC, new Tenneco Inc. and Newport
News Shipbuilding Inc. (Exhibit 2.3 to EPNG's Form 8-K/A
filed January 21, 1997, File No. 1-2700).
3.A -- Certificate of Incorporation as amended and supplemented
as of March 1, 1995 (Exhibit 3(a)(1) to EPTPC Form 10-K
for 1994, File No. 1-9864); Certificate of Retirement of
Preferred Stock Redeemed or Purchased, dated February 16,
1996; Certificate of Elimination of the Series A
Cumulative Preferred Stock of Tenneco Inc. dated February
27, 1996; Certificate of Elimination of the Variable Rate
Preferred Stock of Tenneco Inc. dated February 27, 1996;
Certificate of Elimination of the Participating Preferred
Stock of Tenneco Inc. dated February 27, 1996;
Certificate of Designation, Preferences and Rights of
8 1/4% Cumulative Junior Preferred Stock, Series A, dated
November 18, 1996; Certificate of Amendment of
Certificate of Incorporation, dated December 11, 1996;
Certificate of Merger dated December 11, 1996; and
Certificate of Designation, Preferences and Rights of
8 1/2% Cumulative Junior Preferred Stock, Series B, dated
March 5, 1997 (Exhibit 3.A to EPTPC's Form 10-K for 1996,
File No. 1-9864); Certificate of Designation, Preferences
and Rights of 6 1/4% Cumulative Junior Preferred Stock,
Series C, dated March 4, 1998 (Exhibit 3.A.1 to EPTPC's
Form 10-K for 1997, File No. 1-9864 (the "EPTPC 1997
10-K")).
*3.A .1 -- Certificate of Elimination of 8 1/2% Cumulative Junior
Preferred Stock, Series B, dated January 14, 1999,
Certificate of Elimination of 6 1/4% Cumulative Junior
Preferred Stock, Series C, dated January 14, 1999.
3.B -- By-laws of EPTPC, as amended March 1, 1998 (Exhibit 3.B
to the EPTPC 1997 10-K).
4.A -- Indenture dated as of March 4, 1997, between TGP and The
Chase Manhattan Bank (Exhibit 4.1 to the EPTPC 1997
10-K); First Supplemental Indenture dated as of March 13,
1997, between TGP and The Chase Manhattan Bank (Exhibit
4.2 to the EPTPC 1997 10-K); Second Supplemental
Indenture dated as of March 13, 1997, between TGP and The
Chase Manhattan Bank (Exhibit 4.3 to the EPTPC 1997
10-K); Third Supplemental Indenture dated as of March 13,
1997, between TGP and The Chase Manhattan Bank (Exhibit
4.4 to the EPTPC 1997 10-K); Fourth Supplemental
Indenture dated as of October 9, 1998, between TGP and
The Chase Manhattan Bank (Exhibit 4.2 to TGP's Form 8-K
filed October 9, 1998, File No. 1-4101).
72
EXHIBIT
NUMBER DESCRIPTION
------- -----------
10.A -- $1,250,000,000 364-Day Revolving Credit and Competitive
Advance Facility ("CAF") 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 EPTPC's Form 10-Q filed November 15,
1999, File No. 1-9864)
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 El Paso's
Form 10-Q filed November 12, 1998, File No. 1-4101 (the
"El Paso 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, 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.E to the El Paso 1998
Third Quarter 10-Q).
*21 -- List of Subsidiaries.
*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.