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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
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FORM 10-K
(MARK ONE)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2003
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
FOR THE TRANSITION PERIOD FROM TO .
COMMISSION FILE NUMBER 1-14365
EL PASO CORPORATION
(Exact Name of Registrant as Specified in Its Charter)
DELAWARE 76-0568816
(State or Other Jurisdiction of (I.R.S. Employer
Incorporation or Organization) Identification No.)
EL PASO BUILDING
1001 LOUISIANA STREET
HOUSTON, TEXAS 77002
(Address of Principal Executive Offices) (Zip Code)
TELEPHONE NUMBER: (713) 420-2600
INTERNET WEBSITE: WWW.ELPASO.COM
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
NAME OF EACH EXCHANGE
TITLE OF EACH CLASS ON WHICH REGISTERED
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Common Stock, par value $3 per share 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 [ ] No [X].
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]
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Act). Yes [X] No [ ].
STATE THE AGGREGATE MARKET VALUE OF THE VOTING AND NON-VOTING COMMON EQUITY
HELD BY NON-AFFILIATES OF THE REGISTRANT.
Aggregate market value of the voting stock (which consists solely of shares
of common stock) held by non-affiliates of the registrant as of June 30, 2003
computed by reference to the closing sale price of the registrant's common stock
on the New York Stock Exchange on such date: $4,838,867,717.
INDICATE THE NUMBER OF SHARES OUTSTANDING OF EACH OF THE REGISTRANT'S
CLASSES OF COMMON STOCK, AS OF THE LATEST PRACTICABLE DATE.
Common Stock, par value $3 per share. Shares outstanding on September 24,
2004: 643,441,738
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: None
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EL PASO CORPORATION
TABLE OF CONTENTS
CAPTION PAGE
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PART I
Item 1. Business.................................................... 2
Item 2. Properties.................................................. 30
Item 3. Legal Proceedings........................................... 30
Item 4. Submission of Matters to a Vote of Security Holders......... 32
PART II
Item 5. Market for Registrant's Common Equity and Related
Stockholder Matters....................................... 33
Item 6. Selected Financial Data..................................... 34
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations................................. 36
Risk Factors and Cautionary Statement for Purposes of the
"Safe Harbor" Provisions
of the Private Securities Litigation Reform Act of 1995... 78
Item 7A. Quantitative and Qualitative Disclosures About Market
Risk...................................................... 87
Item 8. Financial Statements and Supplementary Data................. 91
Item 9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure.................................. 195
Item 9A. Controls and Procedures..................................... 195
Item 9B. Other Information........................................... 197
PART III
Item 10. Directors and Executive Officers of the Registrant.......... 198
Item 11. Executive Compensation...................................... 201
Item 12. Security Ownership of Certain Beneficial Owners and
Management and Related Stockholder Matters................ 214
Item 13. Certain Relationships and Related Transactions.............. 217
Item 14. Principal Accountant Fees and Services...................... 217
PART IV
Item 15. Exhibits, Financial Statement Schedules, and Reports on Form
8-K....................................................... 219
Signatures.................................................. 310
Below is a list of terms that are common to our industry and used
throughout this document:
/d = per day
Bbl = barrels
BBtu = billion British thermal units
BBtue = billion British thermal unit
equivalents
Bcf = billion cubic feet
Bcfe = billion cubic feet of natural gas
equivalents
MBbls = thousand barrels
Mcf = thousand cubic feet
Mcfe = thousand cubic feet of natural gas
equivalents
Mgal = thousand gallons
MMBbls = million barrels
MMBtu = million British thermal units
MMcf = million cubic feet
MMcfe = million cubic feet of natural gas
equivalents
MMWh = thousand megawatt hours
MTons = thousand tons
MW = megawatt
TBtu = trillion British thermal units
Tcfe = trillion cubic feet of natural gas
equivalents
When we refer to natural gas and oil in "equivalents," we are doing so to
compare quantities of oil with quantities of natural gas or to express these
different commodities in a common unit. In calculating equivalents, we use a
generally recognized standard in which one Bbl of oil is equal to six Mcf of
natural gas. Oil includes natural gas liquids unless otherwise specified. Also,
when we refer to cubic feet measurements, all measurements are at a pressure of
14.73 pounds per square inch.
When we refer to "us", "we", "our", "ours", or "El Paso", we are describing
El Paso Corporation and/or our subsidiaries.
i
RESTATEMENT OF HISTORICAL FINANCIAL INFORMATION
In February 2004, we completed the December 31, 2003 reserve estimation
process for the proved natural gas and oil reserves in our Production segment.
The results of this process indicated that a significant downward revision to
our proved reserve estimates was needed. In August 2004, we also determined that
we had not properly accounted for certain derivatives, primarily those
associated with many of the historical hedges of our anticipated natural gas
production. After investigations into the factors that caused these issues, we
determined that a material portion of the downward reserve revisions should be
reflected in historical periods and that the historical accounting for our
production and certain other hedges should be corrected. Accordingly, we
restated our historical financial information for the years from 1999 to 2002
and for the first nine months of 2003.
In the restatement for our reserve revisions, an investigation determined
that certain personnel used aggressive, and at times, unsupportable methods to
book proved reserves. In some instances, certain personnel provided historical
proved reserve estimates that they knew or should have known were incorrect at
the time they were reported. The investigation also found that we did not, in
some cases, maintain adequate documentation and records to support historically
booked proved natural gas reserves.
In the restatement for certain hedges, we determined that we had not
properly applied generally accepted accounting principles for many of our
production hedges, certain other hedge transactions related to pipeline capacity
and hedges of the production owned by one of our pipeline subsidiaries. Most of
these hedging transactions were entered into from 1999 to 2002 under Master
International Swaps and Derivatives Association, or ISDA, swap agreements and
the restatement involved transactions where we entered into an identical,
offsetting trading position at the same time we entered into the hedge. In
reaching the conclusion to restate, we concluded that the business purpose for
the offsetting transactions was not alone sufficient to satisfy the standards
for separate accounting treatment from the hedge transaction. Generally accepted
accounting principles, or GAAP, requires that the objective of the two
transactions is not one that could have been accomplished through a single,
though less efficient, transaction. In addition, we considered two additional
factors in reaching this conclusion. First, we determined that some of the
offsetting transactions had not been completed at market prices. Second, we had
originally concluded that there was separate economic substance in the hedge and
the offsetting transactions, based on our view that there was credit risk
associated with the separate enforcement of the transactions. Upon further
review, we determined that there was insufficient credit risk associated with
enforcing these transactions to support that original conclusion.
As a result of these conclusions, we restated our historical proved natural
gas and oil reserve estimates, the financial information derived from those
estimates, and financial information related to our historical accounting for
certain hedges for the periods from 1999 through 2002, and for the first nine
months of 2003. The total cumulative impact of the restatement was a reduction
of our previously reported stockholders' equity as of September 30, 2003 of
approximately $2.4 billion. Of this amount, approximately $1.7 billion related
to the restatement of our historical reserve estimates and approximately $0.7
billion related to the restatement of our historical accounting for hedges.
These restated amounts have been reflected only in this Annual Report on Form
10-K, and we did not revise our historically filed reports for the impacts of
the restatements. Consequently, you should not rely on historical information
contained in those prior filings since this filing replaces and revises those
historically reported amounts.
For a further discussion of the impact of the restatements on our selected
financial information, see Part II, Item 6, Selected Financial Data; for a more
detailed discussion of the factors leading to the restatements, the restatement
methods used and the financial impacts of the restatements, see Item 8,
Financial Statements and Supplementary Data, Note 1; and for a discussion of
control weaknesses that contributed to these issues and changes we have made or
are in the process of making to our control procedures, see Item 9A, Controls
and Procedures.
1
PART I
ITEM 1. BUSINESS
We are an energy company originally founded in 1928 in El Paso, Texas. For
many years, we served as a regional pipeline company conducting business mainly
in the western United States. From 1996 through 2001, we expanded to become an
international energy company through a number of mergers and acquisitions as
well as internal growth initiatives. By 2001, our operations extended from
natural gas production to power generation, and included many new ventures and
businesses, in addition to our traditional natural gas businesses. During this
period, our total assets grew from approximately $7 billion at December 31, 1995
to over $44 billion following the completion of The Coastal Corporation merger
in January 2001. During this same time period, we incurred substantial amounts
of debt and other obligations.
In the latter part of 2001 and in 2002, our industry and business were
adversely impacted by a number of significant events, including (i) the
bankruptcy of a number of energy sector participants, (ii) the general decline
in the energy trading industry, (iii) performance in some areas of our business
that did not meet our expectations, (iv) credit rating downgrades of us and
other industry participants and (v) regulatory and political pressures arising
out of the western energy crisis of 2000 and 2001.
These events adversely affected our operating results, our financial
condition and our liquidity, requiring us to re-prioritize our businesses
throughout 2002 and 2003. Over this two year period, we refocused on our natural
gas assets, and divested or otherwise sold our interests in a significant number
of assets, generating proceeds in excess of $6 billion. As a result of these
sales activities and the performance of our businesses during this time period,
we have also experienced significant losses.
In 2003, we appointed a new chief executive officer. Following an
assessment period by our executive management team, we publicly announced our
2003 Long-Range Plan (Long-Range Plan) in December 2003. This Long-Range Plan
establishes the roadmap for the future direction and focus of our company. The
Long-Range Plan, among other things:
- defines our core businesses;
- establishes timetables for debt reduction; and
- sets a timeline for exiting from non-core businesses and assets.
BUSINESS SEGMENTS
For the years ended December 31, 2003, we operated through four business
segments -- Pipelines, Production, Field Services and Merchant Energy. Through
these segments, we provided the following energy related services:
CONTINUING OPERATIONS
Interstate Natural Gas Our interstate pipeline system is the largest in the
Transmission and Storage U.S., and owns or has interests in approximately
58,000 miles of pipeline and approximately 430 Bcf of
storage capacity. We provide customers with interstate
natural gas transmission and storage services from a
diverse group of supply regions to major markets
around the country, serving many of the largest market
areas.
Production Our production business holds interests in
approximately 8.1 million net developed and
undeveloped acres and had over 2.6 Tcfe of proved
natural gas and oil reserves worldwide at the end of
2003. During 2003, our production averaged
approximately 1.1 Bcfe/d. During the first eight
months of 2004, daily production averaged 855 MMcfe/d.
2
Midstream Services Our midstream business owns a 50 percent interest in
the general partner of a large publicly traded master
limited partnership, GulfTerra Energy Partners, L.P.
(GulfTerra), as well as a significant limited partner
interest in GulfTerra. GulfTerra provides onshore and
offshore midstream services to a diverse base of
customers. Our midstream businesses also provide
gathering and processing services, primarily in south
Texas and south Louisiana. We sold a substantial
portion of our limited and general partnership
interests in GulfTerra and our south Texas gathering
and processing assets in 2004.
Energy Marketing and Our energy marketing and trading business markets our
Trading natural gas and oil production and is managing and/or
liquidating our historical energy trading portfolio.
Power Generation and Supply Our power businesses own or manage almost 15,000 MW of
gross generating capacity in 16 countries. Our plants
serve customers under long-term and market-based
contracts or sell to the open market in spot market
transactions. This business also manages power supply
arrangements with electric utility customers to meet
their peak electricity requirements. We have sold or
expect to sell substantially all of our domestic power
business in 2004.
DISCONTINUED OPERATIONS
Petroleum Markets Our petroleum markets business owns and operates
refineries in the northeastern U.S. and in Aruba, with
a capacity to refine over 430,000 Bbls of oil per day.
We completed the sale of substantially all of this
business in early 2004.
Our Long-Range Plan did not impact our segment structure as of December 31,
2003, but will impact our reported segments going forward. Under our Long-Range
Plan, we will provide natural gas and related energy products and services
through two primary business lines: a regulated business line and an unregulated
business line. Below is a chart that outlines the composition of those business
lines:
(CHART)
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(1) In the long-term, we intend to dispose of substantially all of our assets
and investments in our international power business, except in Brazil.
3
Our long-term strategy will focus on:
BUSINESS OBJECTIVE AND STRATEGY
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Pipelines Protecting and enhancing asset value through successful
recontracting, continuous efficiency gains through cost
management, and prudent capital spending in the U.S. and
Mexico.
Production Growing our production business in a way that creates
shareholder value through disciplined capital allocation,
cost leadership and superior portfolio management.
Midstream Optimizing our remaining investment in GulfTerra and our
remaining gathering and processing assets.
Marketing and Trading Marketing and physical trading of our natural gas and oil
production.
Power Managing power generation assets to maximize value.
Below is a description of each of our existing business segments. Our
current business segments of Pipelines, Production, Field Services and Merchant
Energy are strategic business units that provide a variety of energy products
and services. We managed each segment separately through the end of 2003 and
into early 2004, and each segment requires different technology and marketing
strategies. As we implement our Long-Range Plan, these segments will change to
reflect the way our operations will be managed in the future. For additional
discussion of our business segments, see Part II, Item 7, Management's
Discussion and Analysis of Financial Condition and Results of Operations. For
our segment operating results and identifiable assets, see Part II, Item 8,
Financial Statements and Supplementary Data, Note 26, which is incorporated
herein by reference.
REGULATED BUSINESS -- PIPELINES SEGMENT
Our Pipelines segment provides natural gas transmission, storage and
related services and owns or has interests in approximately 58,000 miles of
interstate natural gas pipelines in the U.S. and internationally. In the U.S.,
our systems connect the nation's principal natural gas supply regions to the six
largest consuming regions in the U.S.: the Gulf Coast, California, the
Northeast, the Midwest, the Southwest and the Southeast. These pipelines
represent the largest integrated coast-to-coast mainline natural gas
transmission system in the U.S. Our U.S. pipeline systems also own or have
interests in approximately 430 Bcf of storage capacity used to provide a variety
of flexible services to our customers and a liquefied natural gas (LNG) terminal
at Elba Island, Georgia. Our international pipeline operations include access to
systems in Canada and Mexico and until June 2004, interests in three operating
natural gas transmission systems in Australia, two of which were sold in June
2004. The remaining Australian investment was placed into receivership in the
second quarter of 2004.
Our Pipelines segment conducts its business activities primarily through
seven wholly owned and five partially owned interstate transmission systems
along with five underground natural gas storage entities and the entity that
owns the Elba Island LNG terminalling facility. The tables below detail our
wholly owned and partially owned interstate transmission systems:
Wholly Owned Interstate Transmission Systems
AS OF DECEMBER 31, 2003
------------------------------ AVERAGE THROUGHPUT(1)
TRANSMISSION SUPPLY AND MILES OF DESIGN STORAGE ------------------------
SYSTEM MARKET REGION PIPELINE CAPACITY CAPACITY 2003 2002 2001
------------ ------------- -------- -------- -------- ----- -------- -----
(MMCF/D) (BCF) (BBTU/D)
Tennessee Gas Extends from Louisiana, the 14,200 6,937 90 4,710 4,596 4,405
Pipeline (TGP) Gulf of Mexico and south Texas
to the northeast section of the
U.S., including the
metropolitan areas of New York
City and Boston.
ANR Pipeline (ANR) Extends from Louisiana, 10,600 6,414 202 4,232 4,130 4,531
Oklahoma, Texas and the Gulf of
Mexico to the midwestern and
northeastern regions of the
U.S., including the
metropolitan areas of Detroit,
Chicago and Milwaukee.
4
AS OF DECEMBER 31, 2003
------------------------------ AVERAGE THROUGHPUT(1)
TRANSMISSION SUPPLY AND MILES OF DESIGN STORAGE ------------------------
SYSTEM MARKET REGION PIPELINE CAPACITY CAPACITY 2003 2002 2001
------------ ------------- -------- -------- -------- ----- -------- -----
(MMCF/D) (BCF) (BBTU/D)
El Paso Natural Gas Extends from the San Juan, 10,600 5,650(2) -- 3,874 3,799 4,253
(EPNG) Permian and Anadarko Basins to
California, its single largest
market, as well as markets in
Arizona, Nevada, New Mexico,
Oklahoma, Texas and northern
Mexico.
Southern Natural Gas Extends from Texas, Louisiana, 8,000 3,296 60 2,101 2,151 2,027
(SNG) Mississippi, Alabama and the
Gulf of Mexico to Louisiana,
Mississippi, Alabama, Florida,
Georgia, South Carolina and
Tennessee, including the
metropolitan areas of Atlanta
and Birmingham.
Colorado Interstate Extends from most production 4,000 3,100 29 1,685 1,687 1,569
Gas (CIG) areas in the Rocky Mountain
region and the Anadarko Basin
to the front range of the Rocky
Mountains and multiple
interconnects with pipeline
systems transporting gas to the
Midwest, the Southwest,
California and the Pacific
Northwest.
Wyoming Interstate Extends from western Wyoming 600 1,880 -- 1,213 1,194 1,017
(WIC) and the Powder River Basin to
various pipeline
interconnections near Cheyenne,
Wyoming.
Mojave Pipeline (MPC) Connects with the EPNG and 400 400 -- 192 266 283
Transwestern transmission
systems at Topock, Arizona, and
the Kern River Gas Transmission
Company transmission system in
California, and extends to
customers in the vicinity of
Bakersfield, California.
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(1) Includes throughput transported on behalf of affiliates.
(2) This capacity reflects winter-sustainable west-flow capacity (including 320
MMcf/d due to the completion of our Line 2000 compression added in 2004) and
800 MMcf/d of east-end delivery capacity.
5
We also have six pipeline expansion projects underway as of September 2004
that have been approved by the Federal Energy Regulatory Commission (FERC):
TRANSMISSION ANTICIPATED
SYSTEM PROJECT CAPACITY DESCRIPTION(1) COMPLETION DATE
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(MMCF/D)
ANR WestLeg Wisconsin 218 To increase capacity of ANR's existing November 2004
expansion system by looping the Madison lateral
line and by enlarging the Beloit lateral
line through abandonment and replacement.
EastLeg Wisconsin 142 To replace 4.7 miles of an existing November 2005
expansion 14-inch natural gas pipeline with a
30-inch line in Washington County, add
3.5 miles of 8-inch looping on the
Denmark Lateral in Brown County, and
modify ANR's existing Mountain Compressor
Station in Oconto County, Wisconsin.
NorthLeg Wisconsin -- To add 6,000 horsepower of electric November 2005
expansion powered compression at ANR's Weyauwega
Compressor station in Waupaca County,
Wisconsin.
SNG South System II 138 Installation of compression and pipeline August 2004(2)
(Phase 2) looping to increase firm transportation
capacity along SNG's south mainline to
Alabama, Georgia and South Carolina.
CPG Cheyenne Plains Gas 576 To construct a 36-inch pipeline to December 2004
Pipeline (CPG) transport gas from the Cheyenne hub in
Colorado to a hub near Greensburg,
Kansas.
Cheyenne Plains 176 To add approximately 10,300 horsepower of December 2005
expansion compression to the Cheyenne Plains
project.
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(1) Looping is the installation of a pipeline, parallel to an existing pipeline,
with tie-ins at several points along the existing pipeline. Looping
increases the transmission system's capacity.
(2) Placed in service in August 2004.
Partially Owned Interstate Transmission Systems
AS OF DECEMBER 31, 2003 AVERAGE
---------------------------------- THROUGHPUT(2)
TRANSMISSION SUPPLY AND OWNERSHIP MILES OF DESIGN ---------------------
SYSTEM(1) MARKET REGION INTEREST PIPELINE CAPACITY(2) 2003 2002 2001
------------ ------------- --------- -------- ----------- ----- ----- -----
(PERCENT) (MMCF/D) (BBTU/D)
Domestic
Florida Gas Extends from south Texas to south 50 4,886 1,980 1,963 2,004 1,616
Transmission(3) Florida.
Great Lakes Gas Extends from the Manitoba-Minnesota 50 2,115 2,895 2,366 2,378 2,224
Transmission border to the Michigan-Ontario border
at St. Clair, Michigan.
Portland Natural Extends from the Canadian border near -- -- -- 130 144 123
Gas Pittsburg, New Hampshire to Dracut,
Transmission(4) Massachusetts.
International
Extends from Dampier to Bunbury in 33 1,152 570 584 573 555
Dampier-to-Bunbury Western Australia.
pipeline
system(5)
Extends from Moomba to Adelaide in 33 685 383 238 271 261
Moomba-to-Adelaide South Australia.
pipeline
system(6)
Ballera-to- Extends from Ballera to Wallumbilla 33 470 115 73 72 71
Wallumbilla in Queensland, Australia.
pipeline
system(6)
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(1) These systems are accounted for as equity investments.
(2) Volumes represent the systems' total design capacity and average throughput
and are not adjusted for our ownership interest.
(3) We have an investment in Citrus Corporation, which owns this system.
(4) We sold our equity interest in the Portland Natural Gas Transmission System
in the fourth quarter of 2003.
6
(5) Our investment in this system was placed in receivership in the second
quarter of 2004.
(6) Our interests in these systems were sold in June 2004.
In addition to the storage capacity on our transmission systems, we own or
have interests in the following natural gas storage entities:
Underground Natural Gas Storage Entities
AS OF DECEMBER 31, 2003
-----------------------
OWNERSHIP STORAGE
STORAGE ENTITY INTEREST CAPACITY(1) LOCATION
- -------------- --------- ----------- --------
(PERCENT) (BCF)
Bear Creek Storage.................................. 100 58 Louisiana
ANR Storage......................................... 100 56 Michigan
Blue Lake Gas Storage(2)............................ 75 47 Michigan
Eaton Rapids Gas Storage(2)......................... 50 13 Michigan
Young Gas Storage(2)................................ 48 6 Colorado
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(1) Includes a total of 133 Bcf contracted to affiliates. Storage capacity is
under long-term contracts and is not adjusted for our ownership interest.
(2) These systems were accounted for as equity investments as of December 31,
2003.
In addition to our pipeline systems and storage facilities, we own an LNG
receiving terminal located on Elba Island, near Savannah, Georgia. The facility
is capable of achieving a peak sendout of 675 MMcf/d and a base load sendout of
446 MMcf/d. The terminal was placed in service and began receiving deliveries in
December 2001. The capacity at the terminal was initially contracted with our
affiliate, El Paso Merchant Energy L.P. (EPME), under a contract that extends
through 2023. This contract was assigned by EPME to a subsidiary of British Gas,
BG LNG Services, LLC in December 2003. In 2003, the FERC approved our plan to
expand the peak sendout capacity of the Elba Island facility by 540 MMcf/d and
the base load sendout by 360 MMcf/d (for a total peak sendout capacity once
completed of 1,215 MMcf/d and a base load sendout of 806 MMcf/d). The expansion
is estimated to cost approximately $159 million and has a planned in-service
date of February 2006.
Regulatory Environment
Our interstate natural gas transmission systems and storage operations are
regulated by the FERC under the Natural Gas Act of 1938 and the Natural Gas
Policy Act of 1978. Each of our pipeline systems and storage facilities operates
under FERC-approved tariffs that establish rates, terms and conditions for
services to our customers. Generally, the FERC's authority extends to:
- rates and charges for natural gas transportation, storage, terminalling
and related services;
- certification and construction of new facilities;
- extension or abandonment of facilities;
- maintenance of accounts and records;
- relationships between pipeline and energy affiliates;
- terms and conditions of service;
- depreciation and amortization policies;
- acquisition and disposition of facilities; and
- initiation and discontinuation of services.
The fees or rates established under our tariffs are a function of our costs
of providing services to our customers, including a reasonable return on our
invested capital. Our revenues from transportation, storage and related services
(transportation services revenues) consist of reservation revenues and usage
revenues.
7
Reservation revenues are from customers (referred to as firm customers) whose
contracts (which are for varying terms) reserve capacity on our pipeline systems
or storage facilities. These firm customers are obligated to pay a monthly
reservation or demand charge, regardless of the amount of natural gas they
transport or store, for the term of their contracts. Usage revenues are from
both firm customers and interruptible customers (those without reserved
capacity) who pay usage charges based on the volume of gas actually transported,
stored, injected or withdrawn. In 2003, approximately 84 percent of our
transportation services revenues were attributable to charges paid by firm
customers. The remaining 16 percent of our transportation services revenues were
attributable to usage charges paid by both firm and interruptible customers. Due
to our regulated nature, our financial results have historically been relatively
stable. However, these results can be subject to volatility due to factors such
as weather, changes in natural gas prices and market conditions, regulatory
actions, competition and the creditworthiness of our customers.
Our interstate pipeline systems are also subject to federal, state and
local pipeline and LNG plant safety and environmental statutes and regulations.
Our systems have ongoing programs designed to keep our facilities in compliance
with pipeline safety and environmental requirements, and we believe that our
systems are in material compliance with the applicable requirements.
Markets and Competition
We provide natural gas services to a variety of customers including natural
gas producers, marketers, end-users and other natural gas transmission,
distribution and electric generation companies. In performing these services, we
compete with other pipeline service providers as well as alternative energy
sources such as coal, nuclear and hydroelectric power for power generation and
fuel oil for heating.
Other Matters Impacting Our Markets
Electric power generation is the fastest growing demand sector of the
natural gas market. The potential consequences of proposed and ongoing
restructuring and deregulation of the electric power industry are currently
unclear. Restructuring and deregulation potentially benefit the natural gas
industry by creating more demand for natural gas turbine generated electric
power, but this effect is offset, in varying degrees, by increased generation
efficiency and more effective use of surplus electric capacity as a result of
open market access. In addition, in several regions of the country, new capacity
additions have exceeded load growth and transmission capabilities out of those
regions. This may inhibit owners of new power generation facilities from signing
firm contracts with pipelines and may impair their creditworthiness.
Imported LNG is one of the fastest growing supply sectors of the natural
gas market. Terminals and other regasification facilities can serve as important
sources of supply for pipelines, enhancing the delivery capabilities and
operational flexibility and complementing traditional supply and market areas.
These LNG delivery systems also may compete with pipelines for transportation of
gas into market areas.
Our existing contracts mature at various times and in varying amounts of
throughput capacity. As our pipeline contracts expire, our ability to extend our
existing contracts or re-market expiring contracted capacity is dependent on the
competitive alternatives, the regulatory environment at the federal, state and
local levels and market supply and demand factors at the relevant dates these
contracts are extended or expire. The duration of new or re-negotiated contracts
will be affected by current prices, competitive conditions and judgments
concerning future market trends and volatility. Subject to regulatory
constraints, we attempt to re-contract or re-market our capacity at the maximum
rates allowed under our tariffs, although we, at times, discount these rates to
remain competitive. The level of discount varies for each of our pipeline
systems.
8
The following table details the markets we serve and the competition on
each of our wholly owned pipeline systems as of December 31, 2003:
TRANSMISSION
SYSTEM CUSTOMER INFORMATION CONTRACT INFORMATION COMPETITION
- --------------------------------------------------------------------------------------------------------------------
TGP Approximately 406 firm and Approximately 481 firm TGP faces strong competition in the
interruptible customers contracts Northeast, Appalachian, Midwest and
Contracted capacity: 87% Southeast market areas. It competes
Weighted average remaining with other interstate and intrastate
contract term of approximately pipelines for deliveries to
five years. multiple-connection customers who can
Major Customers: take deliveries at alternative
None of which individually points. Natural gas delivered on the
represents more than 10 TGP system competes with alternative
percent of revenues energy sources such as electricity,
hydroelectric power, coal and fuel
oil. In addition, TGP competes with
pipelines and gathering systems for
connection to new supply sources in
Texas, the Gulf of Mexico and from
the Canadian border.
- --------------------------------------------------------------------------------------------------------------------
ANR Approximately 228 firm and Approximately 537 firm In the Midwest, ANR competes with
interruptible customers contracts other interstate and intrastate
Contracted capacity: 97% pipeline companies and local
Weighted average remaining distribution companies in the
contract term of approximately transportation and storage of natural
four years. gas. In the Northeast, ANR competes
Major Customer: with other interstate pipelines
We Energies serving electric generation and local
(1,050 BBtu/d) distribution companies. ANR also
Contract terms expire in competes directly with other
2004-2010. interstate pipelines, including
Guardian Pipeline, for markets in
Wisconsin. We Energies owns an
interest in Guardian, which is
currently serving a portion of its
firm transportation requirements.
- --------------------------------------------------------------------------------------------------------------------
EPNG Approximately 215 firm and Approximately 215 firm EPNG faces competition in the West
interruptible customers contracts and Southwest from other existing
Contracted capacity: 97% pipelines, storage facilities and
Weighted average remaining newly proposed pipeline and LNG
contract term of approximately projects as well as alternative
five years(1). energy sources that generate
Major Customer: electricity such as hydroelectric
Southern California Gas power, nuclear, coal and fuel oil.
Company
(1,243 BBtu/d)
(95 BBtu/d) Contract terms expire in 2006.
Contract terms expire in
2004-2007.
- ---------------
(1) Approximately 1,567 MMcf/d currently under contract is subject to early
termination in August 2006 provided shippers give timely notice of an intent
to terminate. If all of these rights were exercised, the weighted average on
the remaining contract terms would decrease to approximately three years.
9
TRANSMISSION
SYSTEM CUSTOMER INFORMATION CONTRACT INFORMATION COMPETITION
- --------------------------------------------------------------------------------------------------------------------
SNG Approximately 270 firm Approximately 170 firm Competition is strong in a number of
and interruptible contracts SNG's key markets. SNG's four largest
customers Contracted capacity: 100% customers are able to obtain a
Weighted average remaining significant portion of their natural
contract term of approximately gas requirements through
Major Customers: five years. transportation from other pipelines.
Atlanta Gas Light Company Also, SNG competes with several
(972 BBtu/d) pipelines for the transportation
Southern Company Services Contract terms expire in business of many of its other
(418 BBtu/d) 2005-2007. customers.
Alabama Gas Corporation
(425 BBtu/d) Scana Contract terms expire in
Corporation (251 BBtu/d) 2010-2018.
Contract terms expire in
2005-2013.
Contract terms expire in
2005-2017.
- --------------------------------------------------------------------------------------------------------------------
CIG Approximately 130 firm Approximately 190 firm CIG serves two major markets. Its
and interruptible contracts "on-system" market, consists of
customers Contracted capacity: 97% utilities and other customers located
Weighted average remaining along the front range of the Rocky
contract term of approximately Mountains in Colorado and Wyoming.
Major Customer: five years. Its "off-system" market consists of
Public Service Company of the transportation of Rocky Mountain
Colorado (187 BBtu/d) production from multiple supply
(970 BBtu/d) basins to interconnections with other
(261 BBtu/d) Contract term expires in 2005. pipelines bound for the Midwest, the
Contract term expires in 2007. Southwest, California and the Pacific
Contract terms expire in Northwest. Competition for its
2009-2014. on-system market consists of local
production from the Denver-Julesburg
basin, an intrastate pipeline, and
long-haul shippers who elect to sell
into this market rather than the
off-system market. Competition for
its off-system market consists of
other interstate pipelines that are
directly connected to its supply
sources and transport these volumes
to markets in the West, Northwest,
Southwest and Midwest.
- --------------------------------------------------------------------------------------------------------------------
WIC Approximately 40 firm Approximately 50 firm contracts WIC competes with eight interstate
and interruptible Contracted capacity: 98% pipelines and one intrastate pipeline
customers Weighted average remaining for its mainline supply from several
contract term of approximately producing basins. WIC's one Bcf/d
six years. Medicine Bow lateral is the primary
source of transportation for
Major Customers: increasing volumes of Powder River
Williams Power Company Basin supply and can readily be
(303 BBtu/d) Contract terms expire in expanded as supply increases.
Colorado Interstate Gas 2008-2013. Currently, there are two other
Company interstate pipelines that transport
(247 BBtu/d) limited volumes out of this basin.
Cantera Gas Company Contract terms expire in
(243 BBtu/d) 2004-2007.
Western Gas Resources
(235 BBtu/d) Contract terms expire in
2004-2013.
Contract terms expire in
2007-2013.
- --------------------------------------------------------------------------------------------------------------------
10
TRANSMISSION
SYSTEM CUSTOMER INFORMATION CONTRACT INFORMATION COMPETITION
- --------------------------------------------------------------------------------------------------------------------
MPC Approximately 35 firm and Eight firm contracts MPC faces competition from other
interruptible customers Contracted capacity: 96% existing pipelines, proposed LNG
Weighted average remaining projects and alternative energy
contract term of approximately sources that generate electricity
three years. such as hydroelectric power, nuclear,
Major Customers: coal and fuel oil.
Texaco Natural Gas Inc.
(185 BBtu/d) Contract term expires in 2007.
Burlington Resources
Trading Inc.
(76 BBtu/d) Contract term expires in 2007.
Los Angeles Department
of Water and Power
(50 BBtu/d) Contract term expires in 2007.
UNREGULATED BUSINESSES -- PRODUCTION SEGMENT
Our Production segment is engaged in the exploration for, and the
acquisition, development and production of natural gas, oil and natural gas
liquids, primarily in North America. In the U.S., we controlled over 3 million
net acres of leasehold acreage through our onshore and coal seam operations in
20 states, including New Mexico, Louisiana, Texas, Oklahoma, Alabama and Utah,
and through our offshore operations in federal and state waters in the Gulf of
Mexico. As of December 31, 2003, we have international exploration and
production rights in Australia, Bolivia, Brazil, Canada, Hungary, Indonesia and
Turkey. During 2003, daily production averaged 1.1 Bcfe/d, and our proved
natural gas and oil reserves at December 31, 2003, were approximately 2.6 Tcfe.
Our December 31, 2003 proved reserve estimates reflect a 1.8 Tcfe downward
revision to our proved natural gas and oil reserves. Following an investigation
into the factors that caused this significant revision, we determined that a
material portion of these revisions should be reflected in prior years and, as a
result, we restated our historical proved reserve estimates and our historical
financial information derived from these proved reserve estimates. In August
2004, we also determined that we had not properly applied the accounting related
to many of our historical hedges, primarily those associated with hedges of our
anticipated natural gas production. Following an investigation into this matter,
we concluded that our historical financial statements should be further
restated. See Part II, Item 6, Selected Financial Data and Item 8, Financial
Statements and Supplementary Data, Note 1 for a further discussion of these
restatements.
As part of our Long-Range Plan, our strategy in this segment will focus on
developing production opportunities from our asset base in the U.S. and Brazil.
We will continue to divest our non-core assets, including international
properties in Canada, Hungary and Indonesia. As of September 2004, we have sold
substantially all of our production operations in Canada and Indonesia.
In June 2004, we announced a back-to-basics plan for our business. This
plan emphasizes strict capital discipline designed to improve capital efficiency
through the use of standardized risk analysis, a heightened focus on cost
control, and a rigorous process for booking proved natural gas and oil reserves.
This back-to-basics approach is designed to stabilize production by improving
the production mix across our operating areas, thereby generating more
predictable income and cash flows in this business.
Our U.S. operations are divided into the following areas: onshore, offshore
and coal seam. The onshore area includes operations in three regions: Texas
Onshore, Central and Rocky Mountains. The Texas Onshore region includes our
operations along the Texas Gulf Coast, the Central region includes primarily our
operations in north Louisiana and the Rocky Mountain region includes our
interests in Utah. The offshore area includes our interests in the Gulf of
Mexico primarily in state and federal waters along the coast of Texas and
Louisiana. Our coal seam area consists of operations in the Black Warrior Basin
in Alabama, the Arkoma Basin in Oklahoma and the Raton Basin in New Mexico. In
each of our domestic operating areas, we have extensive acreage and/or seismic
holdings, which allow us to be competitive.
11
In Brazil, our operations are concentrated in the Camamu, Santos, and
Potiguar Basins. We have been successful with our drilling programs in the
Santos and Camamu Basins and are seeking a strategic partner with a strong
interest in Brazil to contribute near-term development capital in these two
basins. Through our UnoPaso Ltda., or UnoPaso, investment, in which we owned a
50 percent interest at December 31, 2003, we continue to work with Petrobras,
the Brazilian national oil company, in growing our presence in the Potiguar
Basin with increased production and planned exploratory activity. In July 2004,
we acquired the remaining 50 percent interest in UnoPaso.
Natural Gas and Oil Reserves
The tables below provide information on our proved reserves at December 31,
2003. Reserve information in these tables is based on the reserve report dated
January 1, 2004, prepared internally by us. Ryder Scott Company and Huddleston &
Co., Inc., independent petroleum engineering firms, performed independent
reserve estimates for 90 percent and 10 percent of our properties, respectively.
The total estimate of proved reserves prepared independently by Ryder Scott
Company and Huddleston & Co., Inc. was within five percent of our internally
prepared estimates. This information is consistent with estimates of reserves
filed with other federal agencies, except for differences of less than five
percent resulting from actual production, acquisitions, property sales,
necessary reserve revisions and additions to reflect actual experience. The
tables below exclude reserve information related to our equity ownership
interests in UnoPaso; the Merchant Energy segment's interests in Sengkang in
Indonesia and Aguaytia in Peru; and the Field Services segment's interest in
GulfTerra. Combined proved reserve balances for these equity investment
interests were 255,278 MMcf of natural gas and 7,105 MBbls of oil or natural gas
equivalents of 297,909 MMcfe, all net to our ownership interests. Our estimated
proved reserves as of December 31, 2003, and our 2003 production, by area, are
as follows:
NET PROVED RESERVES(1)
----------------------------------------------
NATURAL 2003
GAS LIQUIDS(2) TOTAL PRODUCTION
--------- ---------- --------------------- ----------
(MMCF) (MBBLS) (MMCFE) (PERCENT) (MMCFE)
U.S.
Onshore
Texas Onshore.......................... 538,681 14,310 624,538 24 133,533
Central................................ 342,932 3,314 362,816 14 64,423
Rocky Mountains........................ 13,015 12,458 87,763 3 6,411
--------- ------ --------- --- -------
Total Onshore.......................... 894,628 30,082 1,075,117 41 204,367
Offshore.................................. 330,505 18,273 440,141 17 163,012
Coal Seam................................. 836,206 1 836,214 32 42,053
--------- ------ --------- --- -------
Total U.S................................. 2,061,339 48,356 2,351,472 90 409,432
--------- ------ --------- --- -------
International
Canada(3)................................. 97,431 2,986 115,347 4 16,986
Hungary................................... 4,401 -- 4,401 -- 401
Brazil.................................... -- 20,543 123,258 4 --
Indonesia(3).............................. 30,520 1,742 40,972 2 --
--------- ------ --------- --- -------
Total International....................... 132,352 25,271 283,978 10 17,387
--------- ------ --------- --- -------
Total....................................... 2,193,691 73,627 2,635,450 100 426,819
========= ====== ========= === =======
- ---------------
(1) Net proved reserves exclude royalties and interests owned by others
(including net profits interests) and reflects contractual arrangements and
royalty obligations in effect at the time of the estimate.
(2) Includes oil, condensate and natural gas liquids.
(3) As of September 2004, we have sold our production operations in Canada and
substantially all of our operations in Indonesia.
12
The table below summarizes our estimated proved producing reserves, proved
non-producing reserves, and proved undeveloped reserves by country as of
December 31, 2003:
NET PROVED RESERVES(1)
------------------------------------ RELATIVE
NATURAL GAS LIQUIDS(2) TOTAL PERCENTAGE
----------- ---------- --------- ----------
(MMCF) (MBBLS) (MMCFE)
U.S.
Producing.............................. 1,185,046 25,588 1,338,570 57
Non-Producing.......................... 243,380 11,321 311,305 13
Undeveloped............................ 632,913 11,447 701,597 30
--------- ------ --------- ---
Total proved...................... 2,061,339 48,356 2,351,472 100
========= ====== ========= ===
Canada(3)
Producing.............................. 78,944 1,645 88,812 77
Non-Producing.......................... 7,835 64 8,218 7
Undeveloped............................ 10,652 1,277 18,317 16
--------- ------ --------- ---
Total proved...................... 97,431 2,986 115,347 100
========= ====== ========= ===
Brazil
Undeveloped............................ -- 20,543 123,258 100
--------- ------ --------- ---
Total proved...................... -- 20,543 123,258 100
========= ====== ========= ===
Other Countries(3)(4)
Producing.............................. 4,401 -- 4,401 10
Undeveloped............................ 30,520 1,742 40,972 90
--------- ------ --------- ---
Total proved...................... 34,921 1,742 45,373 100
========= ====== ========= ===
Worldwide
Producing.............................. 1,268,391 27,233 1,431,783 54
Non-Producing.......................... 251,215 11,385 319,523 12
Undeveloped............................ 674,085 35,009 884,144 34
--------- ------ --------- ---
Total proved................... 2,193,691 73,627 2,635,450 100
========= ====== ========= ===
- ---------------
(1) Net proved reserves exclude royalties and interests owned by others
(including net profits interests) and reflects contractual arrangements and
royalty obligations in effect at the time of the estimate.
(2) Includes oil, condensate and natural gas liquids.
(3) As of September 2004, we have sold our production operations in Canada and
substantially all of our operations in Indonesia.
(4) Includes international operations in Hungary and Indonesia.
There are considerable uncertainties inherent in estimating quantities of
proved reserves and in projecting future rates of production and the timing of
development expenditures, including many factors beyond our control,
particularly where such reserves are not currently producing or developed. The
reserve data represents only estimates. Reservoir engineering is a subjective
process of estimating underground accumulations of natural gas and oil that
cannot be measured in an exact manner. The accuracy of any reserve estimate is a
function of the quality of available data and of engineering and geological
interpretations and judgment. As a result, estimates of different engineers
often vary. Estimates are subject to revision based upon a number of factors,
including reservoir performance, prices, economic conditions and government
restrictions. In addition, results of drilling, testing and production
subsequent to the date of an estimate may justify revision of that estimate.
Reserve estimates are often different from the quantities of natural gas and oil
that are ultimately recovered. The meaningfulness of reserve estimates is highly
dependent on the accuracy of the assumptions on which they were based. In
general, the volume of production from the natural gas and oil properties we own
declines as reserves are depleted. Except to the extent we conduct successful
exploration and development drilling or acquire additional properties containing
proved reserves, or both, our proved reserves will decline as reserves are
produced.
13
In addition, during 2003, we sold reserves totaling over 500 Bcfe to
various third parties. The reserves sold were primarily located in Oklahoma, New
Mexico, Texas, Louisiana, the Gulf of Mexico and western Canada. See Part II,
Item 8, Financial Statements and Supplementary Data, Note 30, for a further
discussion of our reserves.
Acreage and Wells
The following table details our gross and net interest in developed and
undeveloped onshore, offshore, coal seam and international lease and mineral
acreage at December 31, 2003. Any acreage in which our interest is limited to
owned royalty, overriding royalty and other similar interests is excluded.
DEVELOPED UNDEVELOPED TOTAL
--------------------- ---------------------- ----------------------
GROSS(1) NET(2) GROSS(1) NET(2) GROSS(1) NET(2)
--------- --------- ---------- --------- ---------- ---------
U.S.
Onshore............... 931,658 288,500 1,253,666 874,713 2,185,324 1,163,213
Offshore.............. 601,973 415,661 686,892 639,028 1,288,865 1,054,689
Coal Seam............. 245,200 176,240 1,254,971 1,032,453 1,500,171 1,208,693
--------- --------- ---------- --------- ---------- ---------
Total............ 1,778,831 880,401 3,195,529 2,546,194 4,974,360 3,426,595
--------- --------- ---------- --------- ---------- ---------
International
Australia............. -- -- 355,000 177,500 355,000 177,500
Bolivia............... -- -- 154,840 15,484 154,840 15,484
Brazil(3)............. -- -- 2,137,770 1,468,371 2,137,770 1,468,371
Canada(4)............. 79,068 61,824 799,250 633,940 878,318 695,764
Hungary............... 77,376 77,376 -- -- 77,376 77,376
Indonesia(4).......... -- -- 1,213,170 378,397 1,213,170 378,397
Turkey................ -- -- 3,653,483 1,826,742 3,653,483 1,826,742
--------- --------- ---------- --------- ---------- ---------
Total............... 156,444 139,200 8,313,513 4,500,434 8,469,957 4,639,634
--------- --------- ---------- --------- ---------- ---------
Worldwide Total..... 1,935,275 1,019,601 11,509,042 7,046,628 13,444,317 8,066,229
========= ========= ========== ========= ========== =========
- ---------------
(1) Gross interest reflects the total acreage we participated in, regardless of
our ownership interests in the acreage.
(2) Net interest is the aggregate of the fractional working interest that we
have in our gross acreage.
(3) In April 2004, we announced the sale of 174,679 gross and net acres
associated with our Brazilian offshore operations.
(4) As of September 2004, we have sold our production operations in Canadian and
substantially all of our operations in Indonesia.
The U.S. net developed acreage is concentrated primarily in the Gulf of
Mexico (47 percent), Utah (15 percent), Texas (9 percent), Louisiana (8
percent), and Oklahoma (8 percent). The domestic net undeveloped acreage is
concentrated primarily in the Gulf of Mexico (25 percent), New Mexico (21
percent), and Louisiana (11 percent). Approximately 20 percent, 14 percent and 7
percent of our total U.S. net undeveloped acreage is held under leases that have
minimum remaining primary terms expiring in 2004, 2005 and 2006, respectively.
During 2003, we sold approximately 956,513 net acres primarily located in
Oklahoma, New Mexico, Texas, Louisiana, the Gulf of Mexico and western Canada.
14
The following table details our gross and net interests in productive
onshore, offshore, coal seam and international natural gas and oil wells and the
number of wells being drilled at December 31, 2003:
PRODUCTIVE PRODUCTIVE TOTAL NUMBER OF
NATURAL GAS WELLS OIL WELLS PRODUCTIVE WELLS WELLS BEING DRILLED
----------------- ----------------- ----------------- -------------------
GROSS(1) NET(2) GROSS(1) NET(2) GROSS(1) NET(2) GROSS(1) NET(2)
-------- ------ -------- ------ -------- ------ --------- -------
U.S.
Onshore................ 1,320 1,051 271 202 1,591 1,253 16 8
Offshore............... 360 248 75 42 435 290 5 3
Coal Seam.............. 1,720 1,277 -- -- 1,720 1,277 65 47
----- ----- --- --- ----- ----- -- --
Total............. 3,400 2,576 346 244 3,746 2,820 86 58
----- ----- --- --- ----- ----- -- --
International
Canada(3).............. 88 74 7 5 95 79 1 1
Other.................. 1 1 -- -- 1 1 -- --
----- ----- --- --- ----- ----- -- --
Total............. 89 75 7 5 96 80 1 1
----- ----- --- --- ----- ----- -- --
Worldwide Total... 3,489 2,651 353 249 3,842 2,900 87 59
===== ===== === === ===== ===== == ==
- ---------------
(1) Gross interest reflects the total number of wells we participated in,
regardless of our ownership interests in the wells.
(2) Net interest is the aggregate of the fractional working interest that we
have in our gross wells.
(3) As of September 2004, we have sold our production operations in Canada.
During 2003, we sold approximately 715 net productive wells located
primarily in Oklahoma, New Mexico, Texas, Louisiana, the Gulf of Mexico and
western Canada. At December 31, 2003, we operated 2,774 of the 2,900 net
productive wells.
The following table details our net exploratory and development wells
drilled for each of the three years ended December 31. As a result of the
restatement of our proved natural gas and oil reserves, some wells drilled that
were previously reported as development wells have been reclassified as
exploratory wells in 2002 and 2001. See Part II, Item 8, Financial Statement and
Supplementary Data, Note 1 for a further discussion of this restatement.
NET EXPLORATORY WELLS DRILLED(1) NET DEVELOPMENT WELLS DRILLED(1)
--------------------------------- ---------------------------------
2002 2001 2002 2001
2003 (RESTATED) (RESTATED) 2003 (RESTATED) (RESTATED)
----- ----------- ----------- ----- ----------- -----------
U.S.
Productive.................. 54 27 24 272 511 442
Dry......................... 22 14 10 1 5 21
-- -- --- --- --- ---
Total.................. 76 41 34 273 516 463
== == === === === ===
Canada(2)
Productive.................. 10 18 21 3 5 38
Dry......................... 6 27 35 1 1 3
-- -- --- --- --- ---
Total.................. 16 45 56 4 6 41
== == === === === ===
Brazil
Productive.................. 3 -- -- -- -- --
Dry......................... -- -- 5 -- -- --
-- -- --- --- --- ---
Total.................. 3 -- 5 -- -- --
== == === === === ===
Other Countries(2)(3)
Productive.................. -- 1 -- -- -- --
Dry......................... 1 1 5 -- -- --
-- -- --- --- --- ---
Total............... 1 2 5 -- -- --
== == === === === ===
15
NET EXPLORATORY WELLS DRILLED(1) NET DEVELOPMENT WELLS DRILLED(1)
--------------------------------- ---------------------------------
2002 2001 2002 2001
2003 (RESTATED) (RESTATED) 2003 (RESTATED) (RESTATED)
----- ----------- ----------- ----- ----------- -----------
Worldwide
Productive.................. 67 46 45 275 516 480
Dry......................... 29 42 55 2 6 24
-- -- --- --- --- ---
Total............... 96 88 100 277 522 504
== == === === === ===
- ---------------
(1) Net interest is the aggregate of the fractional working interest that we
have in our gross wells drilled.
(2) As of September 2004, we have sold our production operations in Canada and
substantially all of our operations in Indonesia.
(3) Includes international operations in Australia, Hungary, Turkey and
Indonesia.
The information above should not be considered indicative of future
drilling performance, nor should it be assumed that there is any correlation
between the number of productive wells drilled and the amount of natural gas and
oil that may ultimately be recovered.
Net Production, Sales Prices, Transportation and Production Costs
The following table details our net production volumes, average sales
prices received, average transportation costs, average production costs and
average production taxes associated with the sale of natural gas and oil for
each of the three years ended December 31. See our Production segment in Part
II, Item 7, Management's Discussion and Analysis of Financial Condition and
Results of Operations for a further discussion of volumes, prices and production
costs.
2003 2002 2001
------ ---------- ----------
(RESTATED) (RESTATED)
Net Production Volumes
U.S.
Natural Gas (Bcf)................................... 339 470 552
Oil, Condensate and Liquids (MMBbls)................ 12 17 13
Total (Bcfe)................................... 410 569 634
Canada(1)
Natural Gas (Bcf)................................... 15 17 13
Oil, Condensate and Liquids (MMBbls)................ -- 1 1
Total (Bcfe)................................... 17 23 17
Worldwide
Natural Gas (Bcf)................................... 354 487 565
Oil, Condensate and Liquids (MMBbls)................ 12 18 14
Total (Bcfe)................................... 427 592 651
Natural Gas Average Sales Price (per Mcf)(2)
U.S.
Price, excluding hedges............................. $ 5.51 $ 3.17 $ 4.26
Price, including hedges(3).......................... $ 5.40 $ 3.35 $ 3.81
Canada(1)
Price, excluding hedges............................. $ 4.87 $ 2.85 $ 2.86
Price, including hedges............................. $ 4.87 $ 2.84 $ 2.85
Worldwide
Price, excluding hedges............................. $ 5.48 $ 3.16 $ 4.23
Price, including hedges(3).......................... $ 5.38 $ 3.33 $ 3.79
Oil, Condensate, and Liquids Average Sales Price (per
Bbl)(2)
U.S.
Price, excluding hedges............................. $26.64 $21.38 $23.08
Price, including hedges(3).......................... $25.96 $21.28 $22.83
16
2003 2002 2001
------ ---------- ----------
(RESTATED) (RESTATED)
Canada(1)
Price, excluding hedges............................. $28.38 $21.56 $17.68
Price, including hedges............................. $28.38 $21.55 $18.52
Worldwide(1)
Price, excluding hedges............................. $26.69 $21.39 $22.87
Price, including hedges(3).......................... $26.02 $21.30 $22.66
Average Transportation Cost
U.S.
Natural gas (per Mcf)............................... $ 0.18 $ 0.18 $ 0.11
Oil, condensate and liquids (per Bbl)............... $ 1.05 $ 0.97 $ 0.57
Canada(1)
Natural gas (per Mcf)............................... $ 0.86 $ 0.19 $ 0.17
Oil, condensate and liquids (per Bbl)............... $ 0.72 $ 0.39 $ 0.26
Worldwide
Natural gas (per Mcf)............................... $ 0.21 $ 0.18 $ 0.12
Oil, condensate and liquids (per Bbl)............... $ 1.05 $ 0.93 $ 0.56
Average Production Cost (per Mcfe)
U.S.
Average lease operating cost........................ $ 0.42 $ 0.42 $ 0.37
Average production taxes............................ 0.14 0.08 0.14
------ ------ ------
Total production cost(4).......................... $ 0.56 $ 0.50 $ 0.51
====== ====== ======
Canada(1)
Average production cost............................. $ 0.48 $ 0.80 $ 0.74
====== ====== ======
Worldwide
Average lease operating cost........................ $ 0.42 $ 0.43 $ 0.38
Average production taxes............................ 0.14 0.08 0.14
------ ------ ------
Total production cost(4).......................... $ 0.56 $ 0.51 $ 0.52
====== ====== ======
- ---------------
(1) As of September 2004, we have sold our production operations in Canada.
(2) Prices are stated before transportation costs.
(3) These amounts have been restated as a result of our determination that a
number of our hedges in historical periods did not qualify as hedges for
consolidated reporting purposes.
(4) Production costs include lease operating costs and production related taxes
(including ad valorem and severance taxes).
17
Acquisition, Development and Exploration Expenditures
The following table details information regarding the costs incurred in our
acquisition, development and exploration activities for each of the three years
ended December 31. As a result of the restatement of our proved natural gas and
oil reserves, some costs that were previously reported as development costs have
been reclassified as exploratory drilling costs for the years 2002 and 2001. See
Part II, Item 8, Financial Statements and Supplementary Data, Notes 1 and 30,
for a further discussion of this restatement.
2002 2001
2003 (RESTATED) (RESTATED)
------ ------------ ------------
(IN MILLIONS)
U.S.
Acquisition Costs:
Proved....................................... $ 10 $ 362 $ 91
Unproved..................................... 35 29 44
Development Costs............................... 668 1,242 1,374
Exploration Costs:
Delay Rentals................................ 6 7 14
Seismic Acquisition and Reprocessing......... 56 35 37
Drilling..................................... 405 482 281
------ ------ ------
Total................................... $1,180 $2,157 $1,841
====== ====== ======
Canada(1)
Acquisition Costs:
Proved....................................... $ 1 $ 6 $ 232
Unproved..................................... 10 7 16
Development Costs............................... 57 80 102
Exploration Costs:
Seismic Acquisition and Reprocessing......... 9 21 10
Drilling..................................... 35 49 12
------ ------ ------
Total................................... $ 112 $ 163 $ 372
====== ====== ======
Brazil
Acquisition Costs:
Unproved..................................... $ 4 $ 9 $ 24
Exploration Costs:
Seismic Acquisition and Reprocessing......... 11 32 6
Drilling..................................... 84 13 53
------ ------ ------
Total...................................... $ 99 $ 54 $ 83
====== ====== ======
Other Countries(1)(2)
Acquisition Costs:
Unproved..................................... $ -- $ 1 $ 2
Development Costs............................... 2 2 --
Exploration Costs:
Seismic Acquisition and Reprocessing......... 2 2 --
Drilling..................................... 9 12 58
------ ------ ------
Total...................................... $ 13 $ 17 $ 60
====== ====== ======
18
2002 2001
2003 (RESTATED) (RESTATED)
------ ------------ ------------
(IN MILLIONS)
Worldwide
Acquisition Costs:
Proved....................................... $ 11 $ 368 $ 323
Unproved..................................... 49 46 86
Development Costs............................... 727 1,324 1,476
Exploration Costs:
Delay Rentals................................ 6 7 14
Seismic Acquisition and Reprocessing......... 78 90 53
Drilling..................................... 533 556 404
------ ------ ------
Total...................................... $1,404 $2,391 $2,356
====== ====== ======
- ---------------
(1) As of September 2004, we have sold our production operations in Canada and
substantially all of our operations in Indonesia.
(2) Includes international operations in Australia, Hungary, Indonesia and
Turkey.
The following table details approximate amounts spent to develop proved
undeveloped reserves that were included in our reserve report for each of the
three years:
2002 2001
2003 (RESTATED) (RESTATED)
------ ------------ ------------
(IN MILLIONS)
U.S. ............................................. $ 220 $ 275 $ 49
Canada............................................ -- 3 3
------ ------ ------
Total................................... $ 220 $ 278 $ 52
====== ====== ======
Regulatory and Operating Environment
Our natural gas and oil production activities are regulated at the federal,
state and local levels, as well as internationally by the countries around the
world where we do business. These regulations include, but are not limited to,
the drilling and spacing of wells, conservation, forced pooling and protection
of correlative rights among interest owners. We are also subject to governmental
safety regulations in the jurisdictions in which we operate.
Our domestic operations under federal natural gas and oil leases are
regulated by the statutes and regulations of the U.S. Department of the Interior
that currently impose liability upon lessees for the cost of environmental
impacts resulting from their operations. Royalty obligations on all federal
leases are regulated by the Minerals Management Service, which has promulgated
valuation guidelines for the payment of royalties by producers. Our
international operations are subject to environmental regulations administered
by foreign governments, which include political subdivisions and international
organizations. These domestic and international laws and regulations relating to
the protection of the environment affect our natural gas and oil operations
through their effect on the construction and operation of facilities, drilling
operations, production or the delay or prevention of future offshore lease
sales. We believe that our operations are in material compliance with the
applicable requirements. In addition, we maintain insurance on our production
business for sudden and accidental spills and oil pollution liability.
Our production business has operating risks normally associated with the
exploration for and production of natural gas and oil, including blowouts,
cratering, pollution and fires, each of which could result in damage to life or
property. In addition, offshore operations may encounter usual marine perils,
including hurricanes and other adverse weather conditions, damage from
collisions with vessels, governmental regulations and interruption or
termination by governmental authorities based on environmental and other
considerations. Customary with industry practices, we maintain insurance
coverage on behalf of our production activities with respect to potential losses
resulting from these operating hazards.
19
Markets and Competition
We primarily sell our natural gas and oil to third parties through our
Merchant Energy segment at spot market prices, subject to customary adjustments.
As part of our Long-Range Plan, we will continue to sell our natural gas and oil
production to this segment. We sell our natural gas liquids at market prices
under monthly or long-term contracts, subject to customary adjustments. We also
engage in hedging activities on a portion of our natural gas and oil production
to stabilize our cash flows and reduce the risk of downward commodity price
movements on sales of our production.
The natural gas and oil business is highly competitive in the search for
and acquisition of additional reserves and in the sale of natural gas, oil and
natural gas liquids. Our competitors include major and intermediate sized
natural gas and oil companies, independent natural gas and oil operators and
individual producers or operators with varying scopes of operations and
financial resources. Competitive factors include price and contract terms.
Ultimately, our future success in the production business will be dependent on
our ability to find or acquire additional reserves at costs that allow us to
remain competitive.
UNREGULATED BUSINESSES -- FIELD SERVICES SEGMENT
Our Field Services segment conducts our midstream activities which includes
gathering and processing of natural gas. Our Field Services assets principally
consist of our consolidated processing assets in south Texas and south
Louisiana, and our general and limited partner holdings of GulfTerra, a publicly
traded master limited partnership in which our subsidiary serves as the general
partner. GulfTerra provides services that include gathering, transportation,
separation, handling, processing, fractionation and storage of natural gas, oil
and natural gas liquids.
Until the fourth quarter of 2003, we owned 100 percent of the general
partner of GulfTerra. In December 2003, we sold 50 percent of this ownership
interest to Enterprise Products Partners, L.P. (Enterprise) as discussed below.
We will sell our remaining interest in the general partner to Enterprise upon
the completion of the merger described below for $370 million in cash and a 9.9
percent interest in the general partner of the combined entity.
Gathering and Processing Operations
Our gathering and processing operations provide gathering and processing
services to natural gas producers, primarily in the south Texas and south
Louisiana production areas. The following tables provide information regarding
operational capacity and volumes of these gathering and processing facilities:
DECEMBER 31, 2003
--------------------- AVERAGE THROUGHPUT
MILES OF THROUGHPUT --------------------
GATHERING PIPELINE CAPACITY 2003 2002 2001
- --------- -------- ---------- ---- ----- -----
(MMCFE/D) (BBTUE/D)
South Texas(1)..................................... 127 966 188 1,089 3,542
Other areas........................................ 835 35 169 1,934 2,567
--- ----- --- ----- -----
Total.................................... 962 1,001 357 3,023 6,109
=== ===== === ===== =====
AVERAGE NATURAL GAS
INLET CAPACITY AVERAGE INLET VOLUME LIQUIDS SALES
----------------- --------------------- ---------------------
PROCESSING PLANTS DECEMBER 31, 2003 2003 2002 2001 2003 2002 2001
- ----------------- ----------------- ----- ----- ----- ----- ----- -----
(MMCFE/D) (BBTUE/D) (MGAL/D)
South Texas(1).................. 2,030 1,491 1,637 1,557 2,418 2,956 2,895
South Louisiana................. 2,550 1,627 1,407 1,712 1,726 1,604 1,619
Other areas..................... 56 88 876 1,091 193 2,178 2,608
----- ----- ----- ----- ----- ----- -----
Total................. 4,636 3,206 3,920 4,360 4,337 6,738 7,122
===== ===== ===== ===== ===== ===== =====
- ---------------
(1) Substantially all of these assets will be sold in 2004 as part of the
Enterprise transaction discussed below.
20
During 2002 and 2003, we completed a number of sales of our midstream
assets, including the sale of our San Juan Basin gathering, treating and
processing assets and our Texas and New Mexico midstream assets, including the
intrastate natural gas pipeline system we acquired from Pacific Gas & Electric
Company in 2000, to GulfTerra. Under our Long-Range Plan, we intend to divest
the remaining processing assets or manage them as part of our unregulated
businesses.
Investment in GulfTerra
We currently serve as the managing member of GulfTerra's general partner.
As the managing member of the general partner, we manage the partnership's daily
operations and perform all of GulfTerra's administrative and operational
activities under a general and administrative services agreement or, in some
cases, separate operational agreements. The following table provides information
on the facilities of GulfTerra:
DECEMBER 31, 2003
----------------------- AVERAGE THROUGHPUT
MILES OF THROUGHPUT -------------------------
PIPELINE CAPACITY 2003 2002 2001
-------- ---------- ----- ----- -----
(MMCFE/D) (BBTUE/D)
Gathering assets(1).................... 15,536 10,905 6,820 6,686 1,946
AVERAGE NATURAL GAS
INLET CAPACITY AVERAGE INLET VOLUME LIQUIDS SALES
----------------- ---------------------- -------------------
DECEMBER 31, 2003 2003 2002 2001 2003 2002 2001
----------------- ----- ----- ------ ----- ---- ----
(MMCFE/D) (BBTUE/D) (MGAL/D)
Processing assets(1)................ 950 791 729 -- 2,072 266 --
- ---------------
(1) All volumetric information reflects 100 percent of GulfTerra's interest.
As of December 31, 2003, we owned 17.8 percent, or 10,384,245, of
GulfTerra's voting common units and a 50 percent ownership interest in
GulfTerra's one percent general partner. We also owned all 10,937,500 of the
partnership's outstanding Series C units, which are non-voting but are
convertible into common units. Until October 2003, we owned all of the Series B
preference units of the partnership, which GulfTerra redeemed for $156 million
at that time. The remaining 82.2 percent of the partnership's common units are
owned by public unit holders (including small amounts owned by management and
employees of the general partner), none of which exceeds a 10 percent ownership
interest.
GulfTerra Merger with Enterprise
In December 2003, Enterprise and GulfTerra announced that they had executed
definitive merger agreements to form the second largest publicly traded energy
partnership in the United States. The general partner of the combined
partnership was to be jointly owned by us and affiliates of privately held
Enterprise Products Company, with each owning a 50 percent interest. In 2004, we
amended our agreement with Enterprise Products Company whereby we will sell our
remaining interest in the general partner of GulfTerra, in exchange for an
additional payment to us of $370 million and a 9.9 percent interest in the
general partner of the combined entity. In conjunction with the merger, we will
also sell to Enterprise a portion of our common units, all of our Series C units
in GulfTerra and substantially all of our south Texas gathering and processing
assets. Following the completion of these transactions, our Field Services
segment will own a 9.9 percent interest in the general partner of Enterprise,
approximately four percent of Enterprise's common units and processing plants
located primarily in south Louisiana.
The combined partnership, which will retain the name Enterprise Products
Partners L.P., will provide transportation, gathering, processing, and treating
services in the largest producing basins of natural gas, crude oil and natural
gas liquids (NGL) in the U.S., including the Gulf of Mexico, Rocky Mountains,
San Juan Basin, Permian Basin, south Texas, east Texas, Mid-Continent, Louisiana
Gulf Coast and, through connections with third-party pipelines, Canada's western
sedimentary basin. The partnership will also serve the largest consuming regions
for natural gas, crude oil and NGL on the U.S. Gulf Coast.
21
In July 2004, the unitholders of both Enterprise and GulfTerra approved the
merger and related transactions. The merger and related transactions are
discussed more fully in Part II, Item 8, Financial Statements and Supplementary
Data, Note 28.
Regulatory Environment
Some of our operations, owned directly or through equity investments, are
subject to regulation by the FERC in accordance with the Natural Gas Act of 1938
and the Natural Gas Policy Act of 1978. Each entity subject to the FERC's
regulation operates under separate FERC approved tariffs with established rates,
terms and conditions of service.
Some of our operations, owned directly or through equity investments, are
also subject to regulation by the Railroad Commission of Texas under the Texas
Utilities Code and the Common Purchaser Act of the Texas Natural Resources Code.
Field Services files the appropriate rate tariffs and operates under the
applicable rules and regulations of the Railroad Commission.
In addition, some of our operations, owned directly or through equity
investments, are subject to the Natural Gas Pipeline Safety Act of 1968, the
Hazardous Liquid Pipeline Safety Act of 1979 and various environmental statutes
and regulations. Each of our pipelines has continuing programs designed to keep
the facilities in compliance with pipeline safety and environmental
requirements, and we believe that these systems are in material compliance with
the applicable requirements.
Markets and Competition
We compete with major interstate and intrastate pipeline companies in
transporting natural gas and NGL's. We also compete with major integrated energy
companies, independent natural gas gathering and processing companies, natural
gas marketers and oil and natural gas producers in gathering and processing
natural gas and NGL's. Competition for throughput and natural gas supplies is
based on a number of factors, including price, efficiency of facilities,
gathering system line pressures, availability of facilities near drilling
activity, service and access to favorable downstream markets.
UNREGULATED BUSINESSES -- MERCHANT ENERGY SEGMENT
Our Merchant Energy segment consists of a Global Power division, an Energy
Marketing and Trading division and an LNG division.
Global Power
Our Global Power division includes the ownership and operation of domestic
and international power generation facilities as well as the management of
restructured power contracts. As of December 31, 2003, we owned or had interests
in 68 power facilities in 16 countries with a total generating capacity of
14,898 gross MW. Our commercial focus has historically been either to develop
projects in which new long-term power purchase agreements allow for an
acceptable return on capital, or to acquire projects with existing above-market
power purchase agreements. During 2003, we actively pursued the sale of most of
our domestic plants and in December 2003, our Board of Directors authorized a
plan that included the sale of substantially all of our domestic power
generation plants. As of September 2004, we have sold 23 domestic power plants
with a total generating capacity of 2,480 gross MW. Following these sales, we
anticipate that we will continue to own interests in several domestic plants and
own several power purchase and supply contracts related to our power
restructuring business discussed below. We will also continue to seek
opportunities to sell or otherwise divest these remaining domestic assets and
some of our international assets, such that our long-term focus will be on
maximizing the value of our international power assets primarily in Brazil.
22
Domestic Power. As of December 31, 2003, we owned or had direct investment
interests in the following domestic power plants:
EL PASO EXPIRATION
OWNERSHIP GROSS YEAR OF POWER
PROJECT STATE INTEREST CAPACITY POWER PURCHASER SALES CONTRACTS FUEL TYPE
- ------- ----- --------- -------- --------------- --------------- ---------
(PERCENT) (MW)
SOLD IN 2004
Ace(1) CA 48 107 SOCAL Edison 2015 Coal
Bastrop(1) TX 50 534 --(2) --(2) Natural Gas
Bayonne NJ 100 186 --(2) --(2) Natural Gas
Bonneville/NCA(1) NV 50 85 Nevada Power 2023 Natural Gas
Camden NJ 100 149 --(2) --(2) Natural Gas
Dartmouth MA 100 68 N-Star 2017 Natural Gas
Fulton NY 100 48 --(2) --(2) Natural Gas
Juniper(1)(3) CA 51(3) 682 PG&E, SOCAL Edison 2009-2020 Natural Gas
Newark Bay NJ 100 147 --(2) --(2) Natural Gas
Orange(1) FL 50 104 FPC, TECO 2025 Natural Gas
Orlando(1) FL 50 115 FPC, Reedy Creek 2012, 2023 Natural Gas
Panther Creek(1) PA 50 82 Metropolitan Edison 2012 Coal
Polk Power (Mulberry)(1) FL 50 121 FPC 2024 Natural Gas
Prime Energy(1) NJ 50 52 GPU Energy, Marcal 2009 Natural Gas
UNDER CONTRACT FOR SALE
Cambria PA 100 80 GPU Energy 2011 Coal
Colver(1) PA 28 106 Penn Electric 2020 Coal
Front Range(1) CO 50 500 Colorado Springs Utilities 2023 Natural Gas
Gilberton(1) PA 10 82 Penn Power & Light 2007 Coal
MassPower(1) MA 50 270 BECO 2011 Natural Gas
Mid-Georgia(1) GA 50 308 Georgia Power 2028 Natural Gas
Mt. Poso(1) CA 16 58 PG&E 2009 Coal
Vandolah FL 100 645 Reliant 2012 Natural Gas
APPROVED FOR SALE(4)
CDECCA CT 100 62 --(2) --(2) Natural Gas
Pawtucket RI 100 69 --(2) --(2) Natural Gas
Rensselaer NY 100 86 --(2) --(2) Natural Gas
San Joaquin CA 100 48 --(2) --(2) Natural Gas
OTHER POWER PLANTS
Midland(1) MI 44 1,575 Consumers Power, Dow 2025 Natural Gas
Berkshire(1) MA 56 261 --(2) --(2) Natural Gas
Eagle Point(5) NJ 100 233 --(2) --(2) Natural Gas
- ---------------
(1) These power facilities are reflected as investments in unconsolidated
affiliates in our financial statements.
(2) These power facilities (referred to as merchant plants) do not have
long-term power purchase agreements with third parties. Our energy marketing
and trading division sells the power that a majority of these facilities
generate to the wholesale power market.
(3) Represents our ownership interest in the Juniper holding company. This
company owns equity interests in 10 domestic power facilities.
(4) In December 2003, our Board approved a plan for selling these power
facilities.
(5) This power facility is currently being leased to a third party who has an
option to purchase in 2005.
Prior to 2003, we conducted a significant portion of our domestic power
activity through our ownership in Chaparral, an unconsolidated joint venture
formed for the purpose of investing in the domestic power industry. During the
first six months of 2003, we acquired our joint venture partner's interest and
began consolidating Chaparral effective January 1, 2003.
In addition to our domestic power plants above, we were involved in
activities in 2001 and 2002 that we have referred to as our power restructuring
business. These activities involved restructuring above-market, long-term power
purchase agreements with utilities that were originally tied to older power
plants built under the Public Utility Regulatory Policies Act of 1978 (PURPA).
These PURPA facilities were typically less efficient and more costly to operate
than newer power generation facilities. Our power restructuring activities
included restructuring the contracts held by our consolidated power plants such
as our Eagle Point power facility, and restructuring of contracts at plants
owned by Chaparral, such as Chaparral's Newark Bay, Bayonne and Camden power
facilities. In a restructuring, the contracts were amended so that the power
sold to the utilities did not have to be provided from the specific power plant,
but could be obtained in the
23
wholesale power market. While we are no longer actively seeking to restructure
additional power purchase contracts, we continue to manage the physical purchase
and sale of electricity as required under the following previously restructured
power contracts:
EXPIRATION YEAR OF
MINIMUM POWER SALES POWER
PROJECT POWER PURCHASER ANNUAL VOLUME CONTRACT SUPPLIER
------- --------------- ------------- ------------------ --------
(MW)
Cedar Brakes I PSEG 394 2013 El Paso Merchant Energy
Cedar Brakes II PSEG 721 2013 El Paso Merchant Energy
Mohawk River Funding II Niagara Mohawk 663 2008 El Paso Merchant Energy
Mohawk River Funding IV(1) Connecticut Power and Light 97 2008 Constellation Power
Utility Contract Funding(1) PSEG 1,666 2016 Morgan Stanley
- ---------------
(1) We sold these restructured power contracts in 2004.
International Power. As of December 31, 2003, we owned or had a direct
investment in the following international power plants (only significant assets
and investments are listed):
EXPIRATION
EL PASO YEAR OF
OWNERSHIP GROSS POWER SALES
PROJECT COUNTRY INTEREST CAPACITY POWER PURCHASER CONTRACTS
- ------- ------- --------- -------- --------------- -----------
(PERCENT) (MW)
Brazil
Araucaria(1) Brazil 60 484 Copel --(2)
Macae Brazil 100 895 Petrobras(3) 2007
Manaus Brazil 100 238 Manaus Energia