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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 8-K
CURRENT REPORT
PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
DATE OF REPORT: SEPTEMBER 23, 2003
(Date of Earliest Event Reported: September 23, 2003)
EL PASO CORPORATION
(Exact name of registrant as specified in its charter)
DELAWARE 1-14365 76-0568816
(State or other jurisdiction of (Commission File Number) (I.R.S. Employer
incorporation) Identification No.)
EL PASO BUILDING
1001 LOUISIANA STREET
HOUSTON, TEXAS 77002
(Address of principal executive offices)(Zip Code)
Registrant's telephone number, including area code (713) 420-2600
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ITEM 5. OTHER EVENTS
In June 2003, our Board of Directors authorized the sale of substantially
all of our petroleum markets operations, including our Aruba refinery, our
Unilube blending operations, our domestic and international terminalling
facilities and our petrochemical and chemical plants. The Board's actions were
in addition to previous actions taken when they approved the sales of our Eagle
Point refinery, our asphalt business and our lease crude operations. As a result
of the Board's actions, we reported these operations as discontinued operations
in our Form 10-Q for the quarterly period ended June 30, 2003.
This Current Report on Form 8-K presents revised financial information that
segregates our businesses as continued and discontinued operations for all
periods presented in our Annual Report on Form 10-K for the year ended December
31, 2002. It should be noted that our net income was not affected by the
reclassification of the petroleum markets business as a discontinued operation.
Also, the information contained in this filing has only been updated for the
treatment of our petroleum markets business as discontinued operations and has
not been otherwise updated for activities occurring in our business after the
date these consolidated financial statements were originally presented in our
2002 Form 10-K. You should read our Form 10-Q's for the periods ended March 31,
2003 and June 30, 2003, for this additional updating information.
This filing includes the following information:
- Business and properties;
- Management's discussion and analysis of financial condition and results
of operations;
- Selected financial data; and
- Financial statements and supplementary data. (Presented under Item 7 of
this Current Report on Form 8-K).
The following list of terms 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 gas equivalents
MBbls = thousand barrels
Mcf = thousand cubic feet
Mcfe = thousand cubic feet of gas equivalents
Mgal = thousand gallons
MMBbls = million barrels
MMBtu = million British thermal units
MMcf = million cubic feet
MMcfe = million cubic feet of gas equivalents
MMDth = million dekatherm
MTons = thousand tons
MW = megawatt
MWh = megawatt hours
MMWh = thousand megawatt hours
Tcfe = trillion cubic feet of gas equivalents
When we refer to natural gas and oil in "equivalents," we are doing so to
compare quantities of oil with quantities of natural gas or to express these
different commodities in a common unit. In calculating equivalents, we use a
generally recognized standard in which one Bbl of oil is equal to six Mcf of
natural gas. 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.
BUSINESS AND PROPERTIES
General
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. Since 1996, we have grown into an international
energy company whose operations extend from natural gas production and
extraction to power generation. Our growth during this period has been
accomplished through several
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significant acquisitions and internal growth initiatives, each of which has
expanded our competitive abilities in energy markets in the United States and
abroad. Some of the significant highlights during this period were:
YEAR TRANSACTION IMPACT
---- ----------- ------
1996 Acquisition of the energy businesses Expanded our U.S. interstate pipeline
of Tenneco Inc. system from coast to coast and
signaled our entry into the
international energy market.
1998 Acquisition of DeepTech International, Expanded our U.S. onshore and offshore
Inc. gathering capabilities. Established us
as the general partner for El Paso
Energy Partners, L.P.
1999 Merger with Sonat Inc. Expanded our pipeline operations into
the southeast portion of the U.S. and
signaled our entrance into the
exploration and production business.
2001 Merger with The Coastal Corporation Placed us as a top tier participant in
every aspect of the wholesale energy
marketplace.
Since the fourth quarter of 2001, our industry and business have been
adversely impacted by a number of industry changing events, including:
- The bankruptcy of Enron Corp.;
- The decline in the energy trading industry;
- Credit ratings downgrades of us and other industry participants by
Moody's and Standard & Poor's to "below investment grade" status, and we
remain on negative outlook; and
- Regulatory and political pressure arising out of the western energy
crisis of 2000 and 2001.
Beginning in December 2001 and continuing throughout 2002 and the first
quarter of 2003, we responded to these industry developments by focusing on
activities that would enhance our liquidity and strengthen our capital
structure. These activities involved:
- selling marginally performing assets and businesses that were not core to
our fundamental base business of natural gas and pipelines;
- exiting complex areas that require higher credit support, such as energy
trading, and focusing instead on core cash generating businesses; and
- pursuing resolution of regulatory and litigation matters, which led to a
March 2003 agreement in principle to settle our primary exposure to the
western energy crisis (Western Energy Settlement).
In February 2003 we announced what we refer to as our 2003 Operational and
Financial Plan. This plan is based upon five key principles:
- Preserving and enhancing the value of our core businesses;
- Exiting non-core businesses quickly, but prudently;
- Strengthening and simplifying our balance sheet while maximizing
liquidity;
- Aggressively pursuing additional cost reductions; and
- Continuing to work diligently to resolve litigation and regulatory
matters.
Our ongoing critical areas of focus are:
- Pipelines: Protecting and enhancing asset value in our natural gas
transportation business through continuous efficiency gains and prudent
and necessary capital spending.
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- Production: Developing production opportunities in North America that
maximize volumes produced and minimize costs, thereby optimizing cash
flow per unit produced.
- Field Services: Optimizing stable cash flows from our investment in El
Paso Energy Partners, L.P.
- Global Power: Enhancing cash flows from existing projects, while selling
non-strategic power generation facilities.
We will also continue to focus on winding down our non-core businesses
including energy trading and petroleum markets as well as other capital
intensive businesses such as liquefied natural gas (LNG) operations.
Segments
Our operations are segregated into four primary business segments:
Pipelines, Production, Field Services and Merchant Energy. These segments are
strategic business units that provide a variety of energy products and services.
We manage each segment separately, and each segment requires different
technology and marketing strategies. As future developments in our businesses
occur, and as we carry out our ongoing strategy and plans, we will continue to
assess the appropriateness of our business segments. For the operating results
and identifiable assets by segment, you should see Item 7, Note 24 of this
Current Report on Form 8-K.
Our Pipelines segment owns or has interests in approximately 60,000 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 five largest consuming regions in the U.S.: the Gulf Coast, California, the
Northeast, the Midwest and the Southeast. These pipelines represent one of the
largest integrated coast-to-coast mainline natural gas transmission systems in
the U.S. Our U.S. pipeline systems also own or have interests in approximately
440 Bcf of storage capacity used to provide a variety of services to our
customers and own and operate an LNG terminal at Elba Island, Georgia. Our
international pipeline operations include access between our U.S. based systems
and Canada and Mexico as well as interests in three operating natural gas
transmission systems in Australia.
Our Production segment conducts our natural gas and oil exploration and
production activities. Domestically, we lease approximately 4 million net acres
in 16 states, including Louisiana, Oklahoma, Texas and Utah, and in the Gulf of
Mexico. We also have exploration and production rights in Australia, Bolivia,
Brazil, Canada, Hungary, Indonesia and Turkey. During 2002, daily equivalent
natural gas production exceeded 1.6 Bcfe/d, and our reserves at December 31,
2002, were approximately 5.2 Tcfe.
Our Field Services segment conducts our midstream activities. As part of
our plan to strengthen our capital structure and enhance our liquidity, we
completed a number of asset sales during 2002, 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 in 2000, to El Paso Energy Partners. El
Paso Energy Partners is a publicly traded master limited partnership for which
our subsidiary serves as general partner. As a result of asset sales to the
partnership and others during 2002, our remaining Field Services assets consist
of 23 processing plants and related gathering facilities located in the south
Texas, Louisiana, Mid-Continent and Rocky Mountain regions, as well as our
interests in El Paso Energy Partners. The partnership provides natural gas,
natural gas liquids (NGL) and oil gathering, transportation, processing,
fractionation, storage and other related services.
Our Merchant Energy segment consists of a global power division, an energy
trading division and other merchant operations (which consist primarily of our
LNG activities). We are a significant owner of electric generating capacity and
own or have interests in 88 power plants in 18 countries. On November 8, 2002,
we announced our plan to exit the energy trading business and pursue an orderly
liquidation of our trading portfolio as a result of diminishing business
opportunities and higher capital costs for this activity. During 2002 and the
first part of 2003, we also completed or announced the sale of our interests in
several power projects.
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PIPELINES SEGMENT
Our Pipelines segment provides natural gas transmission, storage, gathering
and related services in the U.S. and internationally. We conduct our activities
primarily through seven wholly owned and seven partially owned interstate
transmission systems along with six underground natural gas storage entities and
an 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, 2002
------------------------------ AVERAGE THROUGHPUT(1)
TRANSMISSION SUPPLY AND MILES OF DESIGN STORAGE ------------------------
SYSTEM MARKET REGION PIPELINE CAPACITY CAPACITY 2002 2001 2000
------------ ------------- -------- -------- -------- ----- -------- -----
(MMCF/D) (BCF) (BBTU/D)
Tennessee Gas Extends from Louisiana, the 14,200 6,487 97 4,596 4,405 4,354
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 6,450 207 3,691 3,776 3,807
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.
El Paso Natural Gas Extends from the San Juan, 10,600 5,330(2) -- 3,799 4,253 3,937
(EPNG) Permian and Anadarko Basins to
California, which is EPNG's
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 2,963 60 2,020 1,877 2,132
(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.
---------------
(1) Includes throughput transported on behalf of affiliates.
(2) This capacity is comprised of 4,530 MMcf/d of west-flow capacity (which
includes 230 MMcf/d added by our Line 2000 expansion project) and 800 MMcf/d
of east-end delivery capacity.
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AS OF DECEMBER 31, 2002
------------------------------ AVERAGE THROUGHPUT(1)
TRANSMISSION SUPPLY AND MILES OF DESIGN STORAGE ------------------------
SYSTEM MARKET REGION PIPELINE CAPACITY CAPACITY 2002 2001 2000
------------ ------------- -------- -------- -------- ----- -------- -----
(MMCF/D) (BCF) (BBTU/D)
Colorado Interstate Extends from most production 4,000 3,100 29 1,563 1,448 1,383
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 1,860 -- 1,194 1,017 832
(WIC) and the Powder River Basin to
various pipeline
interconnections near Cheyenne,
Wyoming.
Mojave Pipeline (MPC) Connects with the EPNG and 400 400 -- 266 283 407
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.
---------------
(1) Includes throughput transported on behalf of affiliates.
Partially Owned Interstate Transmission Systems
AS OF DECEMBER 31, 2002 AVERAGE
---------------------------------- THROUGHPUT(1)
TRANSMISSION SUPPLY AND OWNERSHIP MILES OF DESIGN ---------------------
SYSTEM MARKET REGION INTEREST PIPELINE CAPACITY(1) 2002 2001 2000
------------ ------------- --------- -------- ----------- ----- ----- -----
(PERCENT) (MMCF/D) (BBTU/D)
Florida Gas Extends from south Texas to Florida. 50 4,804 1,950 2,004 1,616 1,524
Transmission
Alliance Pipeline(2) Extends from western Canada to 2 2,345 1,537 1,476 1,479 105
Chicago.
Great Lakes Gas Extends from the Manitoba-Minnesota 50 2,115 2,895 2,378 2,224 2,477
Transmission border to the Michigan-Ontario border
at St. Clair, Michigan.
Dampier-to-Bunbury Extends from Dampier to Bunbury in 33 1,152 570 573 555 523
pipeline system western Australia.
Moomba-to-Adelaide Extends from Moomba to Adelaide in 33 685 383 271 261 231
pipeline system southern Australia.
Ballera-to- Extends from Ballera to Wallumbilla in 33 470 115 72 71 71
Wallumbilla southwestern Queensland, Australia.
pipeline system
Portland Natural Gas Extends from the Canadian border near 30(3) 294 214 144 123 110
Transmission Pittsburg, New Hampshire to Dracut,
Massachusetts.
---------------
(1) Volumes represent the systems' total design capacity and average throughput
and are not adjusted for our ownership interest.
(2) The Alliance pipeline project commenced operations in the fourth quarter of
2000. We sold 12.3 percent of our equity interest in the system during the
fourth quarter of 2002, and the remaining 2.1 percent equity interest in the
first quarter of 2003.
(3) Our ownership interest increased from 19 percent to 30 percent effective
June 2001.
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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, 2002
-----------------------
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............................... 75 47 Michigan
Eaton Rapids Gas Storage............................ 50 13 Michigan
Steuben Gas Storage................................. 50 6 New York
Young Gas Storage................................... 48 6 Colorado
---------------
(1) Includes a total of 139 Bcf contracted to affiliates. Storage capacity is
under long-term contracts and is not adjusted for our ownership interest.
In addition to our operations of natural gas 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 send-out of 675
MMcf/d and a base load send-out of 446 MMcf/d. The terminal was placed in
service and began receiving deliveries in December 2001. The capacity at the
terminal is currently contracted to our affiliate, El Paso Merchant Energy,
under a contract that extends through 2023. In September 2001, we announced
plans to expand the peak send out capacity of the Elba Island facility by 540
MMcf/d and the base load send out by 360 MMcf/d (for a total peak send out
capacity once completed of 1,215 MMcf/d and a base load send out of 806 MMcf/d).
The expansion will cost approximately $145 million and has a planned in-service
date of late 2005.
6
We have a number of transmission system expansion projects that have been
approved by the Federal Energy Regulatory Commission (FERC) as follows:
TRANSMISSION ANTICIPATED
SYSTEM PROJECT CAPACITY DESCRIPTION(1) COMPLETION DATE
------------ ------- -------- -------------- ---------------
(MMCF/D)
TGP CanEast 127 Extend TGP's mainline system through a April 2003
combination of lease capacity and
facilities modifications, to the Leidy
Hub.
TGP South Texas 312 Construct pipeline, compression and September 2003
Expansion border crossing facilities to fuel four
electric power generation plants in the
Northern Mexico Municipalities of Rio
Bravo and Valle Hermoso, State of
Tamaulipas.
ANR Westleg Wisconsin 218 To increase capacity of ANR's existing November 2004
Expansion system by looping the Madison lateral
and by enlarging the Beloit lateral
through abandonment and replacement.
SNG South System I (Phase 196 Installation of compression and June 2003
2) pipeline looping to increase firm
transportation capacity along SNG's
south mainline in Alabama, Georgia and
South Carolina.
SNG South System II 330 Installation of compression and June 2003,
pipeline looping to increase firm November 2003
transportation capacity along SNG's and May 2004
south mainline to Alabama, Georgia and
South Carolina.
SNG North System II 33 Installation of compression and June 2003
additional pipeline looping to increase
capacity along SNG's north mainline in
Alabama.
CIG Valley Line 92 Installation of additional natural gas December 2003
compression and air blending facilities
to expand the deliverability of the
Front Range system.
---------------
(1) Pipeline 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.
Our transportation, storage and related services (transportation services)
revenues consist of reservation and usage revenues. In 2002, approximately 87
percent of our transportation services revenues were attributable to a capacity
reservation or a demand charge paid by firm customers. These firm customers are
obligated to pay a monthly demand charge, regardless of the amount of natural
gas they transport or store, for the term of their contracts. The remaining 13
percent of our transportation services revenue was attributable to usage
charges, based largely on the volumes of gas actually transported or stored on
our pipeline systems.
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 marketing affiliates;
- terms and conditions of service;
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- 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. Consequently, 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.
In Canada, our pipeline activities are regulated by the National Energy
Board. Similar to the FERC, the National Energy Board governs tariffs and rates,
and the construction and operation of natural gas pipelines in Canada. In
Australia, various regional and national agencies regulate the tariffs, rates
and operating activities of natural gas pipelines.
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. We believe that our systems
are in material compliance with the applicable requirements.
A discussion of significant rate and regulatory matters is included in Item
7, Note 20 of this Current Report on Form 8-K.
Markets and Competition
The following table details our markets and competition on each of our
wholly owned pipeline systems as of December 31, 2002:
TRANSMISSION
SYSTEM CUSTOMER INFORMATION(1) CONTRACT INFORMATION COMPETITION
------------ ---------------------------- ------------------------------- ----------------------------------------
TGP Approximately 434 firm and Approximately 436 firm TGP faces strong competition in the
interruptible customers contracts Northeast, Appalachian, Midwest and
Contracted capacity: 93% Southeast market areas. It competes with
Major Customers: Weighted average remaining other interstate and intrastate
None of which individually contract term of approximately pipelines for deliveries to
represents more than 10 five years multiple-connection customers who can
percent of revenues take deliveries at multiple connection
points. Natural gas delivered on the TGP
system competes with alternative energy
sources such as electricity,
hydroelectric power, coal and fuel oil.
It also competes with pipelines and
local distribution companies to deliver
increased quantities of natural gas to
our market areas. In addition, TGP
competes with pipelines and gathering
systems for connection to new supply
sources in Texas, the Gulf of Mexico and
at the Canadian border.
ANR Approximately 238 firm and Approximately 643 firm In the Midwest markets, ANR competes
interruptible customers contracts with other interstate and intrastate
Contracted capacity: 98% pipeline companies and local
Weighted average remaining distribution companies in the
Major Customer: contract term of approximately transportation and storage of natural
We Energies four years gas. In the Northeast markets, ANR
(1,138 BBtu/d) competes with other interstate pipelines
Contract terms expire in serving electric generation and local
2003-2010. distribution companies. Also, Wisconsin
Gas, which operates under the name We
Energies, is a sponsor of Guardian
Pipeline, which was placed in service in
December 2002. Guardian will serve a
portion of We Energies transportation
requirements and will compete directly
with ANR.
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TRANSMISSION
SYSTEM CUSTOMER INFORMATION(1) CONTRACT INFORMATION COMPETITION
------------ ---------------------------- ------------------------------- ----------------------------------------
EPNG Approximately 230 firm and Approximately 180 firm EPNG faces competition from other
interruptible customers contracts pipelines that deliver natural gas to
Contracted capacity:(2) California and the southwestern U.S., as
Weighted average remaining well as alternative energy sources that
contract term of approximately generate electricity such as
Major Customer: five years hydroelectric power, nuclear, coal and
Southern California Gas fuel oil.
Company
(1,235 BBtu/d)
(95 BBtu/d) Contract term expires in 2006.
Contract terms expire in
2004-2007.
SNG Approximately 260 firm Approximately 170 firm Competition is strong in a number of
and interruptible contracts SNG's key markets. SNG's three largest
customers Contracted capacity: 100% customers are able to obtain a
Weighted average remaining significant portion of their natural gas
contract term of approximately requirements through transportation from
Major Customers: five years other pipelines. Also, SNG competes with
Atlanta Gas Light several pipelines for the transportation
Company (959 BBtu/d) business of many of its other customers.
Alabama Gas Corporation
(394 BBtu/d) Scana Contract terms expire in
Resources Inc. (253 2005-2007.
BBtu/d)
Contract terms expire in
2005-2008.
Contract terms expire in
2003-2017.
---------------
(1)Includes natural gas producers, marketers, end-users and other natural gas
transmission, distribution and electric generation companies.
(2)A discussion of significant rate and regulatory matters regarding EPNG's
capacity is included in Item 7, Note 20 of this Current Report on Form 8-K.
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TRANSMISSION
SYSTEM CUSTOMER INFORMATION(1) CONTRACT INFORMATION COMPETITION
------------ ---------------------------- ------------------------------- -------------------------------------
CIG Approximately 125 firm Approximately 170 firm CIG serves two major markets, the
and interruptible contracts "on-system" market, consisting of
customers Contracted capacity: 100% 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: seven years and the "off- system" market,
Public Service Company of consisting of the transportation of
Colorado (1,095 BBtu/d) Rocky Mountain production from
(462 BBtu/d) multiple supply basins to
Contract term expires in 2007. interconnections with other pipelines
Contract terms expire bound for the Midwest, the Southwest,
2008-2025. California and the Pacific Northwest.
Competition for the 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 the off-system market
consists of other interstate
pipelines that are directly connected
to CIG's supply sources and transport
these volumes to markets in the West,
Northwest, Southwest and Midwest.
WIC Approximately 43 firm Approximately 47 firm contracts WIC competes with eight interstate
and interruptible Contracted capacity: 100% pipelines and one intrastate pipeline
customers Weighted average remaining for its mainline supply. The
contract term of approximately Overthrust supply basin, which
six years historically supplies the WIC
mainline, has been declining and
Major Customers: there has been increased competition
Williams Energy Marketing from the pipelines serving the West
and Trading (340 and Northwest market areas for this
BBtu/d) Contract terms expire in gas supply. To replace these volumes,
Western Gas Resources 2003-2013. WIC is pursuing access to new supply
(272 BBtu/d) sources. Additionally, WIC's one Bcf
Colorado Interstate Gas Contract terms expire in expandable Medicine Bow lateral is
Company 2003-2013. the primary source of transportation
(247 BBtu/d) for increasing volumes of Powder
CMS Field Services River Basin supply. Currently there
(234 BBtu/d) Contract terms expire in are two other interstate pipelines
2003-2007. that transport limited volumes out of
this basin. Upon the approval and
Contract terms expire in construction of the new Cheyenne
2004-2013. Plain project(2), WIC will have an
increased outlet to mid-continent
markets.
MPC Approximately 35 firm and Eight firm contracts MPC faces competition from other
interruptible customers Contracted capacity: 98% pipelines that deliver natural gas to
Weighted average remaining California and the southwestern U.S.
contract term of approximately as well as alternative energy sources
four years that generate electricity such as
Major Customers: hydroelectric power, nuclear, coal
Texaco Natural Gas Inc. and fuel oil.
(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.
---------------
(1)Includes natural gas producers, marketers, end-users and other natural gas
transmission, distribution and electric generation companies.
(2)The Cheyenne Plain project is a new 30-inch diameter pipeline proposed by us
to transport natural gas from the Cheyenne hub to the confluence of several
pipelines near Greensburg, Kansas. This pipeline is anticipated to be in
service in mid-2005 depending on the timing of regulatory approval.
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Electric power generation is one of the fastest growing demand sectors 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 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 will result in lower growth in the gas demand in those regions associated
with new power generation facilities.
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.
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.
As a result of the rating agencies downgrading the credit rating of several
members of the energy sector, including energy trading companies, and placing
them on negative credit watch, the creditworthiness of some customers has
deteriorated. We have taken actions to mitigate our exposure by requesting these
companies provide us with letters of credit or prepayments as permitted by our
tariffs. Our tariffs permit us to request additional credit assurance from our
shippers equal to the cost of performing transportation services for various
periods as specified in each tariff. If these companies experience financial
difficulties, or file for Chapter 11 bankruptcy protection, and our contracts
are not assumed by other counterparties, or if the capacity is unavailable for
resale, it could have a material adverse effect on our financial position,
operating results or cash flows.
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 have onshore and coal seam
operations and properties in 16 states and offshore operations and properties in
federal and state waters in the Gulf of Mexico. Internationally, we have
exploration and production rights in Australia, Bolivia, Brazil, Canada,
Hungary, Indonesia and Turkey.
Strategically, Production emphasizes disciplined investment criteria and
manages its existing production portfolio to maximize volumes and minimize
costs. It employs geophysical technology and seismic data processing to identify
economic hydrocarbon reserves. Production's deep drilling capabilities and
hydraulic fracturing technology allow it to optimize production with high-rate
completions at competitive reserve replacement costs. Production maintains an
active drilling program that capitalizes on its land and seismic holdings. It
also acquires production properties subject to acceptable investment return
criteria.
Natural Gas and Oil Reserves
The table below details Production's proved reserves at December 31, 2002.
Information in this table is based on the reserve report dated January 1, 2003,
prepared internally by Production and reviewed by Huddleston & Co., Inc. 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. These reserves include 465,783
11
MMcfe of production delivery commitments under financing arrangements that
extend through 2042. The financing arrangement supported by these reserves
matures in 2006. Total proved reserves on the fields with this dedicated
production were 919,265 MMcfe. In addition, the table excludes the following
equity interests: Production's interest in UnoPaso (Pescada in Brazil); Merchant
Energy's interests in Sengkang in Indonesia, CAPSA and CAPEX in Argentina and
Aguaytia in Peru; and Field Services' interest in El Paso Energy Partners.
Combined proved natural gas reserves balances for these equity interests were
435,713 MMcf, liquids reserves were 39,693 MBbls and natural gas equivalents
were 673,871 MMcfe, all net to our ownership interests.
NET PROVED RESERVES(1)
------------------------------------
NATURAL GAS LIQUIDS(2) TOTAL
----------- ---------- ---------
(MMCF) (MBBLS) (MMCFE)
United States
Producing...................................... 2,235,877 50,712 2,540,145
Non-Producing.................................. 448,303 20,094 568,868
Undeveloped.................................... 1,528,726 45,923 1,804,267
--------- ------- ---------
Total proved.............................. 4,212,906 116,729 4,913,280
========= ======= =========
Canada
Producing...................................... 89,144 4,213 114,422
Non-Producing.................................. 14,555 233 15,953
Undeveloped.................................... 26,701 1,694 36,865
--------- ------- ---------
Total proved.............................. 130,400 6,140 167,240
========= ======= =========
Other Countries(3)
Producing...................................... -- -- --
Non-Producing.................................. -- -- --
Undeveloped.................................... 76,032 12,652 151,944
--------- ------- ---------
Total proved.............................. 76,032 12,652 151,944
========= ======= =========
Worldwide
Producing...................................... 2,325,021 54,925 2,654,567
Non-Producing.................................. 462,858 20,327 584,821
Undeveloped.................................... 1,631,459 60,269 1,993,076
--------- ------- ---------
Total proved.............................. 4,419,338 135,521 5,232,464
========= ======= =========
---------------
(1) Net proved reserves exclude royalties and interests owned by others and
reflects contractual arrangements and royalty obligations in effect at the
time of the estimate.
(2) Includes oil, condensate and natural gas liquids.
(3) Includes international operations in Brazil, Hungary and Indonesia.
During 2002, as a result of our efforts to enhance our liquidity position,
we sold reserves totaling 1.8 Tcfe to various third parties. The reserves sold
were primarily located in Colorado, Texas, Utah and western Canada.
There are numerous uncertainties inherent in estimating quantities of
proved reserves and in projecting future rates of production and timing of
development expenditures, including many factors beyond Production's control.
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
12
highly dependent on the accuracy of the assumptions on which they were based. In
general, the volume of production from natural gas and oil properties owned by
Production declines as reserves are depleted. Except to the extent Production
conducts successful exploration and development activities or acquires
additional properties containing proved reserves, or both, the proved reserves
of Production will decline as reserves are produced. For further discussion of
our reserves, see Item 7, Note 28 of this Current Report on Form 8-K.
Wells and Acreage
The following table details Production's gross and net interest in
developed and undeveloped onshore, offshore, coal seam and international acreage
at December 31, 2002. Any acreage in which Production's 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)
--------- --------- ---------- ---------- ---------- ----------
United States
Onshore............. 1,142,805 445,427 1,278,683 928,135 2,421,488 1,373,562
Offshore............ 626,705 407,121 1,026,358 952,736 1,653,063 1,359,857
Coal Seam........... 217,412 119,674 1,204,020 781,462 1,421,432 901,136
--------- --------- ---------- ---------- ---------- ----------
Total.......... 1,986,922 972,222 3,509,061 2,662,333 5,495,983 3,634,555
--------- --------- ---------- ---------- ---------- ----------
International
Australia........... -- -- 1,770,364 677,350 1,770,364 677,350
Bolivia............. -- -- 154,840 19,355 154,840 19,355
Brazil.............. -- -- 6,757,164 4,690,446 6,757,164 4,690,446
Canada.............. 338,971 174,533 881,353 698,905 1,220,324 873,438
Hungary............. -- -- 568,100 568,100 568,100 568,100
Indonesia........... -- -- 1,213,170 378,397 1,213,170 378,397
Turkey.............. -- -- 4,047,508 2,023,754 4,047,508 2,023,754
--------- --------- ---------- ---------- ---------- ----------
Total............. 338,971 174,533 15,392,499 9,056,307 15,731,470 9,230,840
--------- --------- ---------- ---------- ---------- ----------
Worldwide Total... 2,325,893 1,146,755 18,901,560 11,718,640 21,227,453 12,865,395
========= ========= ========== ========== ========== ==========
---------------
(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.
The U.S. domestic net developed acreage is concentrated primarily in the
Gulf of Mexico (42 percent), Oklahoma (15 percent), Utah (14 percent), Texas (12
percent), and Louisiana (10 percent). Approximately 20 percent, 21 percent and
12 percent of our total U.S. net undeveloped acreage is held under leases that
have minimum remaining primary terms expiring in 2003, 2004 and 2005. During
2002, we sold approximately 421,316 net developed and 887,391 net undeveloped
acres primarily in Colorado, Texas, Utah and western Canada as a result of our
efforts to enhance our liquidity position.
13
The following table details Production's working interests in onshore,
offshore, coal seam and international natural gas and oil wells at December 31,
2002:
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)
-------- ------ -------- ------ -------- ------ --------- -------
United States
Onshore........... 1,937 1,502 335 257 2,272 1,759 47 36
Offshore.......... 386 167 93 36 479 203 11 9
Coal Seam......... 1,756 1,001 -- -- 1,756 1,001 6 4
----- ----- --- --- ----- ----- -- --
Total........ 4,079 2,670 428 293 4,507 2,963 64 49
----- ----- --- --- ----- ----- -- --
International
Canada............ 267 170 135 77 402 247 6 5
Other............. 1 1 -- -- 1 1 -- --
----- ----- --- --- ----- ----- -- --
Total........ 268 171 135 77 403 248 6 5
----- ----- --- --- ----- ----- -- --
Worldwide
Total........ 4,347 2,841 563 370 4,910 3,211 70 54
===== ===== === === ===== ===== == ==
---------------
(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.
During 2002, as a result of our efforts to enhance our liquidity position,
we sold approximately 2,055 net wells located primarily in Colorado, Texas, Utah
and western Canada.
The following table details Production's exploratory and development wells
drilled during the years 2000 through 2002:
NET EXPLORATORY NET DEVELOPMENT
WELLS DRILLED WELLS DRILLED
------------------ ------------------
2002 2001 2000 2002 2001 2000
---- ---- ---- ---- ---- ----
United States
Productive.................................... 15 17 16 523 449 424
Dry........................................... 10 8 17 9 23 18
-- -- -- --- --- ---
Total.................................... 25 25 33 532 472 442
-- -- -- --- --- ---
Canada
Productive.................................... 18 21 3 5 38 10
Dry........................................... 27 35 3 1 3 1
-- -- -- --- --- ---
Total.................................... 45 56 6 6 41 11
-- -- -- --- --- ---
Other Countries(1)
Productive.................................... 1 -- -- -- -- --
Dry........................................... 1 9 1 -- 1 --
-- -- -- --- --- ---
Total.................................... 2 9 1 -- 1 --
-- -- -- --- --- ---
Worldwide
Productive.................................... 34 38 19 528 487 434
Dry........................................... 38 52 21 10 27 19
-- -- -- --- --- ---
Total.................................... 72 90 40 538 514 453
-- -- -- --- --- ---
---------------
(1) Includes international operations in Australia, Brazil, 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.
14
Net Production, Sales Prices, Transportation and Production Costs
The following tables detail Production's net production volumes, average
sales prices received, average transportation costs, average production costs
and production taxes associated with the sale of natural gas and oil for each of
the three years ended December 31:
2002 2001 2000
------ ------ ------
Net Production Volumes
United States
Natural Gas (Bcf)..................................... 470 552 516
Oil, Condensate and Liquids (MMBbls).................. 17 13 12
Total (Bcfe)..................................... 569 634 586
Canada
Natural Gas (Bcf)..................................... 17 13 1
Oil, Condensate and Liquids (MMBbls).................. 1 1 --
Total (Bcfe)..................................... 23 17 1
Worldwide
Natural Gas (Bcf)..................................... 487 565 517
Oil, Condensate and Liquids (MMBbls).................. 18 14 12
Total (Bcfe)..................................... 592 651 587
Natural Gas Average Sales Price (per Mcf)(1)
United States
Price excluding hedges................................ $ 3.19 $ 4.26 $ 3.97
Price including hedges................................ $ 3.64 $ 3.57 $ 2.73
Canada
Price excluding hedges................................ $ 2.85 $ 2.86 $ 4.27
Price including hedges................................ $ 2.84 $ 2.85 $ 4.27
Worldwide
Price excluding hedges................................ $ 3.16 $ 4.23 $ 3.97
Price including hedges................................ $ 3.61 $ 3.56 $ 2.73
Oil, Condensate, and Liquids Average Sales Price (per
Bbl)(1)
United States
Price excluding hedges................................ $21.38 $23.08 $28.39
Price including hedges................................ $21.28 $22.39 $21.97
Canada
Price excluding hedges................................ $21.56 $17.68 $ --
Price including hedges................................ $21.55 $18.52 $ --
Worldwide
Price excluding hedges................................ $21.39 $22.87 $28.39
Price including hedges................................ $21.30 $22.24 $21.97
---------------
(1) Prices are stated before transportation costs.
15
2002 2001 2000
----- ----- -----
Average Transportation Cost (per Mcfe)
United States
Natural gas............................................ $0.18 $0.11 $0.11
Oil, condensate and liquids............................ $0.97 $0.57 $0.15
Canada
Natural gas............................................ $0.19 $0.17 $0.17
Oil, condensate and liquids............................ $0.39 $0.26 $ --
Worldwide
Natural gas............................................ $0.18 $0.12 $0.11
Oil, condensate and liquids............................ $0.93 $0.56 $0.15
Average Production Cost and Production Taxes (per Mcfe)(1)
United States
Average Production Cost................................ $0.50 $0.51 $0.41
Average Production Taxes............................... $0.08 $0.14 $0.12
Canada
Average Production Cost................................ $0.80 $0.74 $0.66
Worldwide
Average Production Cost................................ $0.51 $0.52 $0.41
Average Production Taxes............................... $0.08 $0.14 $0.12
---------------
(1) Production costs include direct lifting costs (labor, repairs and
maintenance, materials and supplies) and the administrative costs of field
offices, insurance and property and severance taxes.
Acquisition, Development and Exploration Expenditures
The following table details information regarding Production's costs
incurred in its development, exploration and acquisition activities for each of
the three years ended December 31:
2002 2001 2000
------ ------ ------
(IN MILLIONS)
United States
Acquisition Costs:
Proved.............................................. $ 362 $ 91 $ 201
Unproved............................................ 29 44 171
Development Costs..................................... 1,520 1,529 1,229
Exploration Costs:
Delay Rentals....................................... 7 14 12
Seismic Acquisition and Reprocessing................ 35 37 64
Drilling............................................ 204 126 214
------ ------ ------
Total............................................ $2,157 $1,841 $1,891
====== ====== ======
Canada
Acquisition Costs:
Proved.............................................. $ 6 $ 232 $ 3
Unproved............................................ 7 16 6
Development Costs..................................... 80 105 69
Exploration Costs:
Seismic Acquisition and Reprocessing................ 21 10 10
Drilling............................................ 49 9 32
------ ------ ------
Total............................................ $ 163 $ 372 $ 120
====== ====== ======
16
2002 2001 2000
------ ------ ------
(IN MILLIONS)
Other Countries(1)
Acquisition Costs:
Proved.............................................. $ -- $ -- $ --
Unproved............................................ 10 26 --
Development Costs..................................... 3 14 --
Exploration Costs:
Seismic Acquisition and Reprocessing................ 34 6 18
Drilling............................................ 24 97 17
------ ------ ------
Total............................................ $ 71 $ 143 $ 35
====== ====== ======
Worldwide
Acquisition Costs:
Proved.............................................. $ 368 $ 323 $ 204
Unproved............................................ 46 86 177
Development Costs..................................... 1,603 1,648 1,298
Exploration Costs:
Delay Rentals....................................... 7 14 12
Seismic Acquisition and Reprocessing................ 90 53 92
Drilling............................................ 277 232 263
------ ------ ------
Total............................................ $2,391 $2,356 $2,046
====== ====== ======
---------------
(1) Includes international operations in Australia, Brazil, Hungary, Indonesia
and Turkey.
The table below details approximate amounts spent to develop proved
undeveloped reserves that were included in our reserve report as of January 1 of
each year:
2002 2001 2000
---- ---- ----
Cost to Develop Proved Undeveloped Reserves (IN MILLIONS)
United States............................................... $482 $559 $286
Canada...................................................... 11 17 24
---- ---- ----
Total..................................................... $493 $576 $310
==== ==== ====
Regulatory and Operating Environment
Production's natural gas and oil activities are regulated at the federal,
state and local levels, as well as internationally by the countries around the
world in which Production does 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. Production is also
subject to governmental safety regulations in the jurisdictions in which it
operates.
Production's 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.
Production's 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 Production's
natural gas and oil operations through their effect on the construction and
operation of facilities, drilling operations, production or the delay or
prevention of future offshore lease sales. We believe that our operations are in
material compliance with the applicable requirements. In addition, we maintain
insurance on behalf of Production for sudden and accidental spills and oil
pollution liability.
17
Production's 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. Offshore operations may encounter usual marine perils, including
hurricanes and other adverse weather conditions, 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 Production with respect to potential losses
resulting from these operating hazards.
Markets and Competition
Our Production segment primarily sells its natural gas to third parties
through our Merchant Energy segment at spot market prices. As a result of our
plan to exit the energy trading business announced in November 2002, our
Production segment is currently evaluating how it will sell its production in
the future. Alternatives being considered include whether to cancel its
agreement with Merchant Energy and assume responsibility for natural gas sales
to third parties or enter into new marketing agreements with third parties
engaged in the marketing of natural gas. Production sells its natural gas
liquids at market prices under monthly or long-term contracts and its oil
production at posted prices, subject to adjustments for gravity and
transportation. Production also engages in hedging activities on its natural gas
and oil production to stabilize its cash flows and reduce the risk of downward
commodity price movements on sales of its production. This is achieved primarily
through natural gas and oil swaps. Under our hedging program, we may hedge up to
50 percent of our anticipated production for a rolling 12-month forward period.
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. Production's competitors include major and intermediate
sized natural gas and oil companies, independent natural gas and oil operations
and individual producers or operators with varying scopes of operations and
financial resources. Competitive factors include price, contract terms and
quality of service. 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.
FIELD SERVICES SEGMENT
Our Field Services segment provides customers with wellhead-to-mainline
services, including natural gas gathering, products extraction, fractionation,
dehydration, purification, compression and transportation of natural gas and
NGL. It also provides well-ties and real-time information services, including
electronic wellhead gas flow measurement.
Field Services' assets include natural gas gathering and NGL pipelines,
treating, processing and fractionation facilities, in the south Texas,
Louisiana, Mid-Continent and Rocky Mountain regions.
El Paso Energy Partners Company, a subsidiary in our Field Services segment
serves as the sole general partner of El Paso Energy Partners. We currently own
26.5 percent, or 11,674,245 of the partnership's common units and the one
percent general partner interest. The remaining 73.5 percent of the common units
of the limited partnership are owned by public unit holders (including small
amounts owned by the general partner's management and employees), none of which
exceeds a 10 percent ownership interest. Field Services also owns all 125,392 of
the outstanding Series B preference units and all 10,937,500 of the outstanding
Series C units issued in November 2002, which are non-voting. Our overall voting
interest in El Paso Energy Partners is 26.5 percent.
As the general partner, Field Services manages the partnership's daily
operations. Employees of Field Services perform all of the limited partnership's
administrative and operational activities under a general and administrative
services agreement or, in some cases, separate operational agreements. El Paso
Energy Partners contributes to our income through our general partner interest
and our ownership of common and preference units. We do not have any loans to or
from El Paso Energy Partners. In addition, we have not provided any guarantees,
either monetary or performance, on behalf of or for the benefit of El Paso
Energy Partners nor do
18
we have any other liabilities other than those arising in the normal course of
business or those arising out of our role as the general partner in El Paso
Energy Partners.
El Paso Energy Partners provides a capital-efficient means of expanding our
midstream business, and through our general partner relationship, we have used
the partnership as our primary means of growth of our midstream natural gas
business. El Paso Energy Partners manages a balanced, diversified portfolio of
interests and assets related to the midstream energy sector, which includes:
- offshore oil and natural gas pipelines, platforms, processing facilities
and other energy infrastructure in the Gulf of Mexico, primarily offshore
Louisiana and Texas;
- onshore natural gas pipelines and processing facilities in Alabama,
Colorado, Louisiana, Mississippi, New Mexico and Texas;
- onshore NGL pipelines and fractionation facilities in Texas; and
- onshore natural gas and NGL storage facilities in Mississippi, Louisiana
and Texas.
We enter into transactions with El Paso Energy Partners in the normal
course of business for the purchase of natural gas and for services such as
transportation and fractionation, storage, processing and other types of
operational services. For a further discussion of these activities and the
impact of El Paso Energy Partners on our Field Services operations, see
Management's Discussion and Analysis of Financial Condition and Results of
Operations.
The following tables provide information on Field Services' natural gas
gathering and transportation facilities, its processing facilities and the
facilities of its equity method investees:
AS OF DECEMBER 31, 2002
----------------------- AVERAGE THROUGHPUT
MILES OF THROUGHPUT ------------------------
GATHERING & TREATING PIPELINE CAPACITY 2002 2001 2000
-------------------- -------- ------------ ------ ------ ------
(MMCFE/D) (BBTUE/D)
El Paso Field Services........................ 4,048 1,563 3,023(1) 6,109(2) 3,868
El Paso Energy Partners(3).................... 15,764 10,345 6,686(1) 1,946 1,714
AS OF
DECEMBER 31,
2002 AVERAGE NATURAL GAS
------------ AVERAGE INLET VOLUME LIQUIDS SALES
INLET ------------------------- --------------------------
PROCESSING PLANTS CAPACITY 2002 2001 2000 2002 2001 2000
----------------- ------------ ----- --------- ----- ------ -------- ------
(MMCFE/D) (BBTUE/D) (MGAL/D)
El Paso Field Services... 4,911 3,920 4,360 2,930 6,635(1) 7,122(2) 4,664
El Paso Energy
Partners(3)............ 950 729 -- -- 266 -- --
---------------
(1) During 2002, we sold a number of assets to El Paso Energy Partners including
gathering and processing assets in the San Juan Basin of New Mexico and our
Texas midstream assets, most of which we acquired in December 2000.
(2) The increase in activity from 2000 to 2001 is a result of our acquisition of
PG&E's Texas Midstream operations in December 2000.
(3) All volumetric information for El Paso Energy Partners reflects 100 percent
of El Paso Energy Partners' interest. Mileage and volumetric information
have not been reduced to reflect our net ownership.
Regulatory Environment
Some of Field Services' operations 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 Field Services' operations 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.
19
In addition, some of Field Services' operations, owned directly or through
equity investments, are subject to the Natural Gas Pipeline Safety Act of 1968,
the Hazardous Liquid Pipeline Safety Act and various environmental statutes and
regulations. Each of the pipelines has continuing programs designed to keep the
facilities in compliance with pipeline safety and environmental requirements,
and Field Services believes that these systems are in material compliance with
the applicable requirements.
Markets and Competition
Field Services competes with major interstate and intrastate pipeline
companies in transporting natural gas and NGL. Field Services also competes with
major integrated energy companies, independent natural gas gathering and
processing companies, natural gas marketers and oil and natural gas producers in
gathering and processing natural gas and NGL. 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.
MERCHANT ENERGY SEGMENT
Our Merchant Energy segment consists of a global power division, an energy
trading division and other merchant operations (which consist primarily of our
LNG activities).
Global Power
Our global power division includes the ownership and operation of domestic
and international power generation facilities. Our commercial focus in the power
generation business has been to either develop projects in which new long-term
power purchase agreements allow for an acceptable return on capital, or to
acquire projects with existing attractive power purchase agreements. Under this
strategy, we have become a significant U.S.-based independent power generator
and currently own or have interests in 88 power plants in 18 countries. These
plants represent 20,665 gross megawatts of generating capacity, 72 percent of
which is sold under power purchase or tolling agreements with terms in excess of
five years. Of these facilities, 60 percent are natural gas fired, 11 percent
are geothermal and the remaining 29 percent use coal or NGL as fuel or are
hydroelectric plants. As part of our 2003 Operational and Financial Plan, we
have announced the planned sales of some of these power generation assets. Most
of our power plants are partially owned by us through either a direct equity
investment or through our unconsolidated affiliates, Chaparral Investors, L.L.C.
(Chaparral) and Gemstone. As of December 31, 2002, we had a direct investment in
the following power plants:
EL PASO
GROSS OWNERSHIP
PROJECT MEGAWATTS(1) INTEREST
------- ------------ ---------
(PERCENT)
Aguaytia Energy............................................. 155 24
Bastrop Company, LLC........................................ 534 50
Berkshire Power Company L.L.C.(2)........................... 261 25
CAPSA/CAPEX................................................. 650 27
CDECCA(2)................................................... 62 50
CE Generation(3)............................................ 823 50
Costanera................................................... 2,302 12
Eagle Point Cogeneration Partnership(2)..................... 233 84
East Asia Power............................................. 236 46
EGE Fortuna................................................. 300 25
EGE Itabo................................................... 513 25
Enfield Power............................................... 378 25
Fauji Kabirwala............................................. 157 42
---------------
(1) Gross megawatts represent tested generating capacity of these facilities.
(2) Chaparral also owns an interest in these projects.
(3) These projects were sold in 2003.
20
EL PASO
GROSS OWNERSHIP
PROJECT MEGAWATTS(1) INTEREST
------- ------------ ---------
(PERCENT)
Habibullah Power............................................ 136 50
Kladno Power(2)............................................. 365 18
Korea Independent Energy Corporation........................ 1,720 50
Manaus(3)................................................... 238 100
MASSPOWER(4)................................................ 270 18
Meizhou Wan Generating...................................... 734 25
Mid-Georgia Cogeneration.................................... 308 50
Midland Cogeneration Venture................................ 1,575 44
Milford Power Company(4)(5)................................. 540 25
Nejapa Power................................................ 144 87
PPN......................................................... 325 26
Rio Negro(3)................................................ 158 100
Saba Power Company.......................................... 128 93
Sengkang.................................................... 135 48
Other projects.............................................. 1,271 various
------
Total............................................. 14,651
======
---------------
(1) Gross megawatts represent tested generating capacity of these facilities.
(2) These projects were sold in 2003.
(3) Gemstone also owns an interest in these projects.
(4) Chaparral also owns an interest in these projects.
(5) This plant is under construction.
We conduct a significant portion of our domestic power activity through our
investment in Chaparral. At December 31, 2002, we owned 20 percent of Chaparral,
and Limestone Electron Trust (Limestone), an unrelated party capitalized by
private equity and debt, owned the remaining 80 percent. Limestone is controlled
by investment affiliates of Credit Suisse First Boston Corporation. In March
2003, we notified Limestone that we will exercise our right under the
partnership agreements to acquire all of the outstanding third party equity in
Limestone. On March 17, 2003, we contributed $1 billion to Limestone in exchange
for a non-controlling interest. Limestone used the proceeds from the
contribution to pay off $1 billion of the Limestone notes that matured on that
date. Following our additional investment of $1 billion in Limestone, our
effective ownership of Chaparral increased to approximately 90 percent, but
neither our rights nor the rights of Limestone to participate in the operating
decisions of Chaparral changed. As a result, we continue to account for our
investment in Chaparral as an equity investment. We will consolidate Chaparral
upon the purchase of the remaining third party equity interest in Limestone,
which we expect to occur in May 2003.
Chaparral was formed during 1999 to obtain low-cost financing to fund the
growth of our unregulated domestic power generation and related businesses.
During 2002, Chaparral's primary focus was on restructuring power contracts. A
power contract restructuring is accomplished typically by amending an
above-market power contract that requires delivery of power from a dedicated
power plant and replacing it with low-cost power obtained from the market.
Chaparral also operates power plants whose contracts have been previously
restructured on a merchant basis, which means that these plants operate and sell
power to the wholesale market in periods where power prices are high enough that
it is economical to do so. Through Chaparral, we have investments in 34 U.S.
power generation facilities with a total generating capacity of approximately
5,592 gross megawatts. Most of Chaparral's plants provide power under long-term
contracts. We serve as the manager of Chaparral under a management agreement
that expires in 2006, and we were paid a management fee for the services we
performed under this agreement through the end of 2002. This fee was based on
how well we performed as the manager of Chaparral, and was determined by
evaluating the present value of the portfolio of power assets held by Chaparral.
Our management fee is subject to the approval of our
21
joint venture partner annually. In 2002, the management fee was $205 million
consisting of a $185 million performance fee plus a $20 million annual cost
reimbursement. We will not earn a fee from Chaparral in 2003.
As of December 31, 2002, Chaparral owned or had interests in the following
power plants:
CHAPARRAL
GROSS OWNERSHIP
PROJECT MEGAWATTS(1) INTEREST
------- ------------ ---------
(PERCENT)
Berkshire Power Company L.L.C.(2)........................... 261 31
Cambria Cogen Company, G.P.................................. 80 100
CDECCA(2)................................................... 62 50
Dartmouth Power Associates, L.P. ........................... 68 100
Eagle Point Cogeneration Partnership(2)..................... 233 16
East Coast Power L.L.C.(3) ................................. 1,131 82
El Paso Golden Power, L.L.C.(3)............................. 435 32
Front Range(4).............................................. 500 50
Juniper Generation, L.L.C.(3)............................... 682 25
Linden 6 Expansion.......................................... 169 99
MASSPOWER(2)................................................ 270 33
Milford Power Company(2)(4)................................. 540 70
Nevada Cogeneration Associates #1........................... 85 50
Newark Bay Cogeneration Partnership L.P. ................... 147 100
Orlando CoGen Limited, L.P. ................................ 115 50
Pawtucket Power Associates L.P. ............................ 69 100
Prime Energy Limited Partnership............................ 52 50
San Joaquin CoGen L.L.C. ................................... 48 100
Vandolah.................................................... 645 100
------
Total............................................. 5,592
======
---------------
(1) Gross megawatts represent the tested generating capacity of these
facilities.
(2) We also own a direct interest in these projects.
(3) These project companies own interests in multiple plants.
(4) These plants are under construction.
Internationally, our focus has been on building and acquiring energy
infrastructure in developed economies, and to a lesser degree in selected
emerging markets. Our primary areas of focus historically have included Brazil,
Europe and Asia. We principally conduct our Brazilian development activities
within an investment that we refer to as Gemstone. We own approximately 50
percent of Gemstone, and Gemstone Investors, an unrelated party capitalized by
private equity (Rabobank International) and debt, owns the remaining 50 percent.
Gemstone Investor Limited also indirectly purchased preferred interests in two
of our consolidated power projects in Brazil. The Gemstone structure owns or has
interests in five Brazilian power generation facilities with a total generating
capacity of approximately 2,184 gross megawatts. We serve as the manager of
Gemstone under a management agreement that expires in 2004, under which we are
paid a fee that reimburses us for the cost to provide the management services,
which cannot exceed $2 million on an annual basis. Our activities as manager of
Gemstone include:
- management of the operations and commercial activities of the facilities;
- project financings, sales and acquisitions; and
- daily administration activities of accounting, tax, legal and treasury
functions.
22
As of December 31, 2002, Gemstone owned or had interests in the following power
plants:
GEMSTONE
GROSS OWNERSHIP
PROJECT MEGAWATTS(1) INTEREST
------- ------------ ---------
Macae....................................................... 895 100%
Porto Velho(2).............................................. 409 50%
Araucaria................................................... 484 60%
Rio Negro................................................... 158 (3)
Manaus...................................................... 238 (3)
-----
Total............................................. 2,184
=====
---------------
(1) Gross megawatts represent the tested generating capacity of these
facilities.
(2) The second phase of this project is under construction.
(3) These are consolidated power projects in which Gemstone owns a preferred
ownership interest.
Rabobank International, the third party investor in Gemstone, has the right
to remove us as manager of Gemstone. In January 2003, Rabobank notified us that
it planned to remove us as manager. We retained our management rights by
agreeing to purchase Rabobank's $50 million of equity in Gemstone on or before
April 17, 2003. We will consolidate Gemstone, its related power plants and its
debt on the purchase date, unless we replace Rabobank with another partner.
For a further discussion of both Chaparral's and Gemstone's activities, see
Management's Discussion and Analysis of Financial Condition and Results of
Operations beginning on page 31 and Item 7, Note 26 of this Current Report on
Form 8-K.
Detailed below are our power generation projects, by region (segregated by
those that are consolidated and those that are not) as of December 31, 2002:
CONSOLIDATED POWER PROJECTS
--------------------------- NUMBER OF GROSS NET
REGION PROJECT STATUS FACILITIES MEGAWATTS(1) MEGAWATTS(2)
------ -------------- ---------- ------------ ------------
North America
East Coast Operational.................. 4 429 429
South America Operational.................. 2 396 396
Asia Operational.................. 2 108 95
Central America Operational.................. 1 144 125
Europe Operational.................. 1 69 35
-- ----- -----
Total........................................ 10 1,146 1,080
== ===== =====
---------------
(1) Gross megawatts represent the tested generating capacity of these
facilities.
(2) Net megawatts represent our net ownership in the facilities.
23
UNCONSOLIDATED POWER PROJECTS
----------------------------- NUMBER OF GROSS NET
REGION PROJECT STATUS FACILITIES MEGAWATTS(1) MEGAWATTS(2)
------ -------------- ---------- ------------ ------------
North America
East Coast Operational................ 20 4,050 2,891
Under Construction......... 1 540 513
Central Operational................ 3 2,309 1,052
Under Construction......... 1 500 250
West Coast Operational................ 25 1,363 514
South America Operational................ 6 4,698 1,780
Under Construction......... 1 197 99
Asia Operational................ 13 4,023 1,842
Central America Operational................ 5 1,046 294
Under Construction......... 1 50 11
Europe Operational................ 2 743 159
--- ------ -----
Total...................................... 78 19,519 9,405
=== ====== =====
---------------
(1) Gross megawatts represent the tested generating capacity of these
facilities.
(2) Net megawatts represent our net ownership in the facilities.
Energy Trading
At the beginning of 2002, we were one of the largest energy marketers in
North America. Our trading activities included providing both short and
long-term supplies of energy commodities to a broad range of wholesale customers
worldwide. We traded natural gas, power, crude oil, other energy commodities and
related financial instruments in North America and Europe and provided pricing
and valuation analysis for the entire Merchant Energy segment. Detailed below is
our marketed and traded energy commodity sales volumes that were settled during
each of the three years ended December 31:
Volumes 2002 2001 2000
------- ------- -------
Physical
Natural gas (BBtu/d)............................... 11,879 9,230 7,768
Power (MMWh)....................................... 469,477 217,387 115,303
Financial settlements (BBtue/d)....................... 188,467 143,095 98,630
Due to deterioration of the energy trading environment, we decided in
November 2002 to exit the energy trading business and pursue an orderly
liquidation of our trading portfolio. We anticipate this liquidation will
continue through 2004. Our liquidation strategy is intended to:
- maximize cash flow from the trading portfolio;
- reduce our risk in an uncertain environment; and
- avoid inefficient sales of the portfolio in the current distressed
environment.
We will execute this strategy in several ways, including:
- negotiating early settlements pursuant to contractual terms with
counterparties;
- actively pursuing the sales of transactions or the entire portfolio with
third parties;
- matching and transferring offsetting positions with different
counterparties;
- transferring activities to other El Paso segments or divisions; and
- liquidating through scheduled settlements.
In late 2002, we began actively liquidating our trading portfolio. As of
December 31, 2002, we had approximately 40,000 transactions to be settled in the
future. Included in our portfolio at that time was
24
approximately 4.4 Bcf/d of natural gas transportation capacity and natural gas
storage rights of approximately 125 Bcf. As of December 31, 2002, we had
contracted to sell 2.1 Bcf/d of this transportation capacity and 70 Bcf of those
gas storage rights. Additionally, in the first quarter of 2003, we sold our
European natural gas trading portfolio and completed the liquidation of all of
our open trading positions in Europe. We are continuing to work with numerous
counterparties to liquidate the remainder of our portfolio through 2004.
Historically, our energy trading division purchased a significant portion
of the Production segment's natural gas production and a smaller amount of the
Field Services segment's natural gas and NGL volumes, as well as power generated
from the global power division's merchant power plants. These purchases
comprised approximately 20 percent and 1 percent of the energy trading
division's 2002 natural gas and power volumes included in the above table. With
our announcement that we will exit the trading business, these affiliated
activities are being evaluated to determine if they should be assumed by the
individual segment or whether each segment will separately contract for those
services with third parties that are actively engaged in that business.
Other Merchant Operations
Our other merchant operations consist primarily of our LNG activities. In
February 2003, we announced our intent to minimize our involvement in these
activities because the significant capital and credit requirements associated
with this business were in excess of our current financial capacity.
Our LNG business contracts for LNG terminalling and regasification
capacity, coordinates short and long-term LNG supply deliveries and, prior to
our announced intent to minimize our involvement in this business, was
developing international LNG supply, marketing and infrastructure operations. As
of December 31, 2002, our LNG business had contracted for 163 Bcf per year of
LNG regasification capacity at Southern Natural Gas' Elba Island location in
Georgia, which is contracted through 2023.
We have contracted for 103 Bcf per year of LNG supplies at market sensitive
prices, under the terms of a long-term Caribbean supply agreement. Initial
deliveries under this agreement are scheduled to commence in June 2003. In May
2002, we received final approval from the Norwegian and United States
governments for an LNG purchase and sale agreement signed in October 2001 with
Snohvit, which is a consortium of natural gas production companies led by
Statoil ASA. In the fourth quarter of 2002, we completed a sale of our position
in the LNG purchase and sale agreement and an assignment of our capacity rights
at the Cove Point LNG regasification facility to Statoil for $210 million.
During 2001 and 2002, we contracted to charter four LNG tankers, with an
option to charter a fifth ship, to transport LNG from supply areas to domestic
and international market centers. In February 2003, following our announced plan
to minimize our involvement in the LNG business, we entered into various
agreements with the ship owners under which all four of the ship charters and
our option for chartering the fifth ship were cancelled in consideration of
payments by us totaling $24 million. On two of the ship charters, the ship
owners assumed responsibility for the charter of those vessels, and we paid $20
million for the capital costs associated with fitting those two ships with
regasification capabilities. In connection with transferring the chartering
responsibilities back to the ship owners, we agreed to provide letters of
credit, fully collateralized by cash, equal to $120 million that could be drawn
on by the ship owners. These letters of credit are intended to cover additional
capital costs and any shortfalls in the rates at which they are able to charter
the vessels, compared to the rates provided for in the original charter
agreements, as adjusted for capital costs we have already paid. In the event
that the ship owners are able to charter the ships at rates in excess of the
original rates, as adjusted, we will share in the benefits. We also retained
rights to charter some of the vessels for our use in potential future LNG
activities. In connection with these transactions, our future exposure to the
ship arrangements is limited to $120 million. We also transferred our interest
in our Baja LNG development project to an unaffiliated third party in connection
with these transactions. We are exploring our options with respect to the
remainder of our LNG business, including the sales of assets and supply and
sales contracts, and participating in joint ventures that would use our Energy
Bridge technology (technology which uses regasification capability on board the
LNG transport ships in combination with or instead of using land-based
facilities).
25
Regulatory Environment
Merchant Energy's domestic power generation activities are regulated by the
FERC under the Federal Power Act with respect to its rates, terms and conditions
of service. In addition, exports of electricity outside of the U.S. must be
approved by the Department of Energy. Merchant Energy's cogeneration power
production activities are regulated by the FERC under the Public Utility
Regulatory Policies Act (PURPA) with respect to rates, procurement and provision
of services and operating standards. Its power generation activities are also
subject to federal, state and local environmental regulations. We believe that
our operations are in material compliance with the applicable requirements.
Merchant Energy's foreign operations are regulated by numerous governmental
agencies in the countries in which these projects are located. Many of the
countries in which Merchant Energy conducts and will conduct business have
recently developed or are developing new regulatory and legal structures to
accommodate private and foreign-owned businesses. These regulatory and legal
structures and their interpretation and application by administrative agencies
are relatively new and sometimes limited. Many detailed rules and procedures are
yet to be issued, and we expect that the interpretation of existing rules in
these jurisdictions will evolve over time. We believe that our operations are in
material compliance with all environmental laws and regulations in the
applicable foreign jurisdictions.
Markets and Competition
During 2002, Merchant Energy's activities served over 1,700 suppliers and
2,200 customers around the world.
Merchant Energy's businesses operate in a highly competitive environment.
Its primary competitors include:
- affiliates of major oil and natural gas producers;
- multi-national energy infrastructure companies;
- large domestic and foreign utility companies;
- affiliates of large local distribution companies;
- affiliates of other interstate and intrastate pipelines; and
- independent energy marketers and power producers with varying scopes of
operations and financial resources.
Merchant Energy competes on the basis of price, operating efficiency,
technological advances, experience in the marketplace and counterparty credit.
Each market served by Merchant Energy is influenced directly or indirectly by
energy market economics.
Many of Merchant Energy's power generation facilities sell power pursuant
to long-term agreements with investor-owned utilities in the U.S. The terms of
its power purchase agreements for its facilities are such that Merchant Energy's
revenues from these facilities 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, these
facilities will be required to compete in a significantly different market in
which operating efficiency and other economic factors will determine success.
Merchant Energy is likely to face intense competition from generation companies
as well as from the wholesale power markets.
As a part of our strategy to exit the energy trading business, we will seek
to sell a portion or all of our trading price risk management assets and
liabilities to other energy marketers or financial institutions which engage in
energy trading activities. With the deterioration of the profitability and
credit standing of entities in the energy trading business, many industry
participants have announced their decision to exit the energy trading business.
We may face competition for limited resources in liquidating our trading price
risk
26
management assets and liabilities from these other energy trading companies, and
this competition may impact the amounts we will be able to realize through our
liquidation efforts.
CORPORATE AND OTHER OPERATIONS
Through our corporate group, we perform management, legal, accounting,
financial, tax, consulting, administrative and other services for our operating
business segments. The costs of providing these services are allocated to our
business segments. Our telecommunications business, a retail business (which was
sold in 2001 and 2002) and our discontinued operations, which include our
petroleum markets and coal businesses, are also included in Corporate and Other
Operations.
Telecommunications
Our on-going telecommunication business, which we conduct through our
subsidiary, El Paso Global Networks, focuses on providing Texas-based metro
transport services and collocation and cross-connect services in Chicago. Our
Texas-based metro transport services business provides bandwidth transport
services to wholesale and commercial customers in Austin, San Antonio, Dallas,
Ft. Worth and Houston. Our collocation and cross-connect services are available
through space we lease in Lakeside Technology Center, a Chicago-based
telecommunications facility. This facility provides space for telecommunication
carriers that is designed for their unique equipment needs and provides access
to multiple network connections of various telecommunication carriers.
Regulatory Environment
The passage of the 1996 Telecommunications Act created a legal framework
for competitive telecommunications companies to provide local, analog and
digital communications services in competition with the traditional telephone
companies. The 1996 Telecommunications Act eliminated a substantial barrier to
entry for competitive telecommunications companies by enabling them to leverage
the existing infrastructure built by the traditional telephone companies rather
than constructing a competing infrastructure at significant and uneconomic cost.
A critical aspect of our Texas-based metro business is our interconnection
agreement with SBC Communications Inc. (SBC). We have pending arbitration
proceedings in Texas relating to the various terms of our new interconnection
arrangements. Although we have received a favorable decision from an
administrative law judge (ALJ) that supports the requirements needed in our
current business plan, the Public Utility Commission of Texas (PUC) is reviewing
the new language of the interconnection arrangement and is having ongoing
proceedings to determine the rates, charges and terms, and conditions for
collocation and unbundled network elements. Unbundled network elements are the
various portions of a traditional telephone company's network that a competitive
telecommunications company can lease for purposes of building a facilities-based
competitive network, including end loops, central office collocation space, and
interoffice transport. The interconnection agreement is ultimately subject to
PUC, Federal Communications Commission (FCC) and judicial oversight. These
government authorities may modify the terms of the interconnection agreements in
a way that significantly disadvantages our business.
The FCC has commenced a rulemaking proceeding as part of its triennial
review of its unbundling rules. In this proceeding, the FCC has undertaken a
reexamination of its unbundling rules. These rules provide the legal means by
which we obtain access to collocation, interoffice transport, and other
unbundled network elements that are vital to our business plan and our ability
to serve current and future customers. In particular, we rely on unbundled
network elements, leased from SBC pursuant to FCC rules, in order to reach
customers. Should the FCC decide to change its rules to limit our access to such
elements, our ability to provide our Texas-based metro services could be
significantly impacted. Additionally, legislative changes, either from Congress
or the Texas legislature, may occur, which could also limit our access to
unbundled network elements and significantly impact our business.
27
Markets and Competition
The markets for wholesale and commercial telecommunication services are
intensely competitive, and we expect that these markets will continue to be
competitive in the future. In the Texas markets, SBC offers similar services to
ours and represents competition in all of our target service areas.
Not many competitive telecommunications companies offer services using a
business strategy similar to ours. However, some competitive telecommunications
companies have adopted the same or modified versions of our interconnection
agreement, and other companies may continue to do so in the future. As a result,
some of these competitors offer similar services and are likely to do so in the
future.
Discontinued Operations
Our discontinued operations consist of our petroleum markets and coal
mining businesses.
Petroleum Markets. In 2003, we announced our intent to sell substantially
all of our petroleum markets business since it is not core to our primary
natural gas business. Our existing petroleum markets business: (i) owns or has
interests in four crude oil refineries and five chemical production facilities;
(ii) has petroleum terminalling and related marketing operations; and (iii) has
blending and packaging operations that produce and distribute a variety of
lubricants and automotive related products. Of the four refineries we own, we
operate three of them. The three refineries we operate have a throughput
capability of approximately 438 MBbls of crude oil per day to produce a variety
of gasolines, diesel fuels, asphalt, industrial fuels and other products. Our
chemical facilities have a production capability of 3,800 tons per day and
produce various industrial and agricultural products.
In 2002, our refineries operated at 64 percent of their average combined
capacity, at 70 percent in 2001 and at 93 percent in 2000. The aggregate sales
volumes at our wholly owned refineries were approximately 110 MMBbls in 2002,
131 MMBbls in 2001 and 182 MMBbls in 2000. Of our total refinery sales in 2002,
38 percent was gasoline, 41 percent was middle distillates, such as jet fuel,
diesel fuel and home heating oil, and 21 percent was heavy industrial fuels and
other products.
The following table presents average daily throughput and storage capacity
at our wholly owned refineries at December 31:
AVERAGE AT DECEMBER 31,
DAILY 2002
THROUGHPUT -------------------
------------------ DAILY STORAGE
REFINERY LOCATION 2002 2001 2000 CAPACITY CAPACITY
-------- -------- ---- ---- ---- -------- --------
(IN MBBLS)
Aruba Aruba.......................... 146 178 229 280 15,320
Eagle Point Westville, New Jersey.......... 127 118 143 140 8,492
Corpus
Christi(1) Corpus Christi, Texas.......... -- 38 99 -- --
Mobile Mobile, Alabama................ 9 10 12 18 600
--- --- --- --- -------
Total....................................... 282 344 483 438 24,412
=== === === === =======
---------------
(1) In June 2001, we leased our Corpus Christi refinery to Valero Energy
Corporation for 20 years. In February 2003, Valero exercised its option to
purchase the plant and related assets. These volumes only reflect those
produced prior to our lease of the facilities.
28
Our chemical plants produce agricultural fertilizers, gasoline additives
and other industrial products from facilities in Nevada, Oregon and Wyoming. The
following table presents sales volumes from our wholly owned chemical facilities
in the U.S. for each of the three years ended December 31:
2002 2001 2000
----- ----- -----
(MTONS)
Industrial.................................................. 512 492 547
Agricultural................................................ 380 378 389
Gasoline additives.......................................... 199 173 214
----- ----- -----
Total............................................. 1,091 1,043 1,150
===== ===== =====
Since January 2003, we have sold the majority of our interests in petroleum
terminals in Florida, our tug and barge operations, our leasehold crude business
and asphalt operations and all of our interests in the Corpus Christi refinery.
We expect to sell the rest of the assets associated with our petroleum business
in 2003 and 2004.
Our petroleum markets business is subject to federal, state and local
environmental regulations and its customers are principally independent energy
marketers and retailers.
Coal Mining. Our coal mining business controlled reserves totaling 524
million recoverable tons and produced high-quality bituminous coal from reserves
in Kentucky, Virginia and West Virginia. The extracted coal was primarily sold
under long-term contracts to power generation facilities in the eastern U.S.
During late 2002 and early 2003, these operations were sold.
SELECTED FINANCIAL DATA
The following historical selected financial data reflects the
reclassification of our petroleum markets business as discontinued operations in
all periods presented. These selected historical results are not necessarily
indicative of results to be expected in future periods.
YEAR ENDED DECEMBER 31,
------------------------------------------------
2002 2001 2000 1999 1998
-------- ------- ------- ------- -------
(IN MILLIONS, EXCEPT PER COMMON SHARE AMOUNTS)
Operating Results Data:
Operating revenues............................. $ 7,598 $8,939 $7,188 $5,243 $4,981
Income (loss) from continuing operations before
preferred stock dividends(1)................ (1,048) 152 1,113 226 113
Income (loss) from continuing operations
available to common stockholders(1)......... (1,048) 152 1,113 226 107
Basic earnings (loss) per common share from
continuing operations....................... $ (1.87) $ 0.30 $ 2.25 $ 0.46 $ 0.22
Diluted earnings (loss) per common share from
continuing operations....................... $ (1.87) $ 0.30 $ 2.19 $ 0.46 $ 0.22
Cash dividends declared per common share(2).... $ 0.87 $ 0.85 $ 0.82 $ 0.80 $ 0.76
Basic average common shares outstanding........ 560 505 494... 490 487
Diluted average common shares outstanding...... 560 516 513 497 495
29
AS OF DECEMBER 31,
-----------------------------------------------
2002 2001 2000 1999 1998
------- ------- ------- ------- -------
(IN MILLIONS)
Financial Position Data:
Total assets..................................... $46,224 $48,546 $46,903 $32,090 $26,759
Long-term financing obligations(3)............... 16,106 12,840 11,193 9,610 7,510
Non-current notes payable to affiliates.......... 201 368 343 -- --
Securities of subsidiaries....................... 3,420 4,013 3,707 2,444 999
Stockholders' equity............................. 8,377 9,356 8,119 6,884 6,913
---------------
(1) In March 2003, we entered into an agreement in principle to settle claims
associated with the western energy crisis of 2000 and 2001. We also incurred
losses related to impairments of assets and equity investments and incurred
restructuring charges related to industry changes. We also incurred a
ceiling test charge on our full cost natural gas and oil properties. During
2001, we merged with The Coastal Corporation and incurred costs and asset
impairments related to this merger. In 1999, we incurred $557 million of
merger charges primarily related to our merger with Sonat, Inc. and incurred
$352 million of ceiling test charges. In 1998, we incurred $1,035 million of
ceiling test charges. For a further discussion of events affecting
comparability of our results in 2002, 2001 and 2000, See Item 7, Notes 2, 4,
5, 6 and 7 of this Current Report on Form 8-K.
(2) Cash dividends declared per share of common stock represent the historical
dividends declared by El Paso for all periods presented.
(3) These amounts exclude long-term financing obligations of $51 million for
2001, $410 million for 2000, $411 million for 1999 and $181 million for 1998
related to discontinued operations.
30
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS
Our Management's Discussion and Analysis includes forward-looking
statements that are subject to risks and uncertainties. Actual results may
differ substantially from the statements we make in this section due to a number
of factors that are discussed beginning on page 77 of this Current Report on
Form 8-K. The information contained in this discussion presents our petroleum
markets business as discontinued operations for all periods presented.
OVERVIEW
We are an energy company whose operations encompass natural gas and oil
production; gathering, processing and interstate and intrastate transmission of
natural gas; power generation; petroleum refining; and energy trading. Our
business is divided into four distinct business segments: Pipelines, Production,
Field Services and Merchant Energy.
During the last five years, we experienced substantial growth from mergers
and acquisitions, and organic growth of our marketing and trading and global
power businesses. Growth through mergers and acquisitions has included
significant transactions, such as our DeepTech International acquisition in
1998, Sonat merger in 1999, and the Coastal merger in 2001. These transactions,
the growth of trading and power activities and the capital needs of our other
businesses required substantial financial resources. During this five-year
period, we frequently accessed the capital markets to fund our growth through a
wide variety of financings.
During 2002, we experienced dramatic changes in our industry as well as in
the financial markets on which we rely, and we continue to operate in a very
challenging environment. In response to industry events, the credit rating
agencies, including Moody's and Standard & Poor's, re-evaluated the ratings of
companies involved in energy trading activities. As a result, the ratings of
many of the largest participants in the energy trading industry, including us,
were downgraded to below investment grade. Several experienced significant
financial distress. Also impacting us was a preliminary decision reached by a
FERC ALJ that one of our subsidiaries withheld pipeline capacity from the
California market during 2000 and 2001. Reacting to the changes in the market,
our leverage and a preliminary decision related to our California matters,
Moody's and Standard & Poor's initiated a series of ratings actions lowering our
senior unsecured debt rating to Caa1 and B (both "below investment grade"
ratings), and we remain on negative outlook.
Several negative outcomes resulted from these downgrades. First, cash
generated in 2002 from the sales of assets, which had originally been identified
for debt reductions, was instead: required to be posted as additional cash
collateral in connection with our commercial trading activities; paid to satisfy
financial guarantees; and used to retire other arrangements. Additionally, our
access to capital markets and commercial paper markets became much more
restricted because of our lower credit ratings. Finally, the credit downgrades
resulted in the net cash generated by assets and businesses that collateralize
two of our minority interest financing arrangements being largely unavailable to
us for general corporate purposes. Instead, we were required to use this cash to
redeem preferred securities issued in connection with those arrangements and for
the operation of those assets and businesses. In March 2003, we issued a $1.2
billion two-year term loan. The proceeds were used to retire the outstanding
amounts under the Trinity River preferred interest financing arrangement,
partially freeing up these cash usage restrictions. For a further discussion of
this redemption, see Item 7, Note 19 of this Current Report on Form 8-K.
Since the fourth quarter of 2001, we have taken several steps to address
the issues affecting us, and we have made significant progress in our plans to
meet the demands on our liquidity and to strengthen our capital structure.
Some of our more significant accomplishments include:
- The sale of over $2.5 billion of equity or equity-linked securities;
- The completion or execution of contracts for the sale of over $5.5
billion of non-core assets and investments;
31
- The removal of rating triggers from over $4 billion of our investment and
financing programs, which, because of our credit rating downgrades, would
have resulted in the issuance of our stock or the liquidation of assets,
the proceeds from which would have been used to repay those arrangements;
- The issuance of $700 million in senior unsecured notes at Southern
Natural Gas Company ($400 million) and ANR Pipeline Company ($300
million);
- The completion in March 2003 of a new $1.2 billion term loan, which
enabled the retirement of our Trinity River preferred interest financing
arrangement and eliminated the cash restrictions and accelerated
amortization of that arrangement;
- The establishment of an exit strategy for our trading business, including
the planned orderly liquidation of our existing trading portfolio;
- The substantial reduction of our credit exposure to our LNG business;
- The repayment of over $1.9 billion of financial obligations, including
Electron and Trinity River; and
- The achievement of the Western Energy Settlement in March 2003, which was
designed to resolve our principal exposure relating to the western energy
crisis while minimizing the impact on our current liquidity.
On February 5, 2003, we announced our 2003 Operational and Financial Plan.
This plan is based on five key principles:
- Preserve and enhance the value of our core businesses;
- Exit non-core businesses quickly but prudently;
- Strengthen and simplify the balance sheet while maximizing liquidity;
- Aggressively pursue additional cost reductions; and
- Continue to work diligently to resolve litigation and regulatory matters.
In the following sections of our Management's Discussion and Analysis, we
address these events and our outlook in greater detail. In the section entitled
Liquidity and Capital Resources, we discuss the impact of changes in our credit
standing and our current liquidity, including our ability to generate cash from
operations and capital market transactions. In the section entitled Off-Balance
Sheet Arrangements and Contractual Obligations, we discuss the various financing
and contractual arrangements in which we are involved that commit us under
guarantees and other commercial and contractual obligations. In Results of
Operations, we analyze operating results for each of our business segments as
well as for our discontinued operations, and identify unusual and infrequent
events that have impacted and, in some cases, may continue to impact, the
operations of these business segments and operations.
Our discussions of Liquidity and Capital Resources, Off-Balance Sheet
Arrangements and Contractual Obligations and Results of Operations are based on
our consolidated financial statements, which have been prepared through the
application of accounting principles that are generally accepted in the U.S. The
preparation of our financial statements reflect the selection and application of
accounting policies, many of which require us to use assumptions, estimates and
judgments that involve complex processes. Actual results can, and often do,
differ from these estimates. Also included is a discussion of our Critical
Accounting Policies, which discuss those policies that are significant to our
financial position and operating results that are presented in our financial
statements. You should also read our significant accounting policies in Item 7,
Note 1 of this Current Report on Form 8-K, to understand all of the policies
that impact our financial presentation included in this discussion and analysis
and in the presentation of our financial statements as a whole.
32
LIQUIDITY AND CAPITAL RESOURCES
LIQUIDITY
Overview of Current Liquidity
We rely on cash generated from our internal operations as our primary
source of liquidity, as well as available credit facilities, bank financings,
asset sales and the issuance of long-term debt, preferred securities and equity
securities. From time to time, we have also used structured financings sometimes
referred to as off-balance sheet arrangements. We expect that our future funding
for working capital needs, capital expenditures, long-term debt repayments,
dividends and other financing activities will continue to be provided from some
or all of these sources. Each of these sources are impacted by factors that
influence the overall amount of cash generated by us and the capital available
to us. For example, cash generated by our business operations may be impacted by
changes in commodity prices or demands for our commodities or services due to
weather patterns, competition from other providers or alternative energy
sources. Collateral demands or recovery of collateral posted are impacted by
natural gas prices, hedging levels and our credit quality and that of our
counterparties. Liquidity generated by future asset sales may depend on the
overall economic conditions of the industry served by these assets, the
condition and location of the assets and the number of interested buyers. In
addition, our credit ratings or general market conditions can restrict our
ability to access capital markets, which can have a significant impact on our
liquidity.
The following tables, which reflect our available liquidity at the
beginning of the year and estimated sources and uses of liquidity throughout
2003, indicate the adequacy of our liquidity to meet our immediate needs.
At the beginning of 2003, our available liquidity was as follows (in
billions):
Sources
Available cash............................................ $1.1
Availability under 364-day bank facility(1)............... 1.5
Availability under multi-year bank facility(1)(2)......... 0.5
----
Net available liquidity..................................... $3.1
====
---------------
(1) Our 364-day bank facility matures in May 2003, with amounts outstanding
at that time becoming due in May 2004, and our multi-year bank facility
matures in August 2003.
(2) An additional $0.5 billion was drawn in February 2003.
Other sources of cash we expect for 2003 include (in billions):
Cash flow from operating activities before working capital
and non-working capital changes........................... $2.1 - $2.4
Return of working capital................................... 0.3
Debt issuances(1)........................................... 3.1
Other financings............................................ 0.4
Asset sales(2).............................................. 3.1 - 3.3
-----------
Total.................................................. $9.0 - $9.5
===========
---------------
(1) Issuances of $1.9 billion occurred in March 2003.
(2) As of March 31, 2003, we have completed or executed contracts for the
sale of over $1.7 billion of non-core assets and investments.
33
For 2003, our anticipated cash needs include (in billions):
Debt repayments............................................. $3.0
Minority interest redemptions(1)............................ 1.6
Other financing obligations(2).............................. 1.2
Maintenance capital(3)...................................... 1.8
Discretionary capital....................................... 0.7
Dividends................................................... 0.2
----
Anticipated cash needs................................. $8.5
====
---------------
(1) Includes redemption of Trinity River preferred interest of $980 million that
occurred in the first quarter of 2003.
(2) Includes repayment of Limestone notes of $1 billion that occurred in March
2003 and the purchase of Limestone's equity for $175 million that is
expected to occur in May 2003.
(3) Includes $156 million of maintenance capital related to our discontinued
petroleum markets operations.
Our anticipated requirements may change significantly, and our analysis is
intended to provide you with an understanding of our cash needs, both required
and discretionary, to better understand our liquidity outlook.
Overview of Cash Flow Activities for 2002
For the years ended December 31, 2002 and 2001, our cash flows are
summarized as follows:
2002 2001
------- -------
(IN MILLIONS)
Cash flows from continuing operating activities
Net income (loss) from continuing operations.............. $(1,102) $ 178
Non-cash income adjustments............................... 3,032 2,103
------- -------
Cash flows before working capital and non-working
capital changes....................................... 1,930 2,281
Working capital changes................................... (1,077) 1,818
Non-working capital changes and other..................... (146) (170)
------- -------
Cash flows from continuing operating activities........ 707 3,929
------- -------
Cash flows from continuing investing activities............. (1,054) (4,811)
------- -------
Cash flows from continuing financing activities............. 790 1,285
------- -------
Increase in cash and cash equivalents from continuing
operations............................................ 443 403
------- -------
Discontinued operations
Cash flows from operating activities...................... (271) 191
Cash flows from investing activities...................... (201) (212)
Cash flows from financing activities...................... 482 15
------- -------
Change in cash and cash equivalents related to
discontinued operations............................... 10 (6)
------- -------
Overall change in cash................................. $ 453 $ 397
======= =======
During the year ended December 31, 2002, our cash and cash equivalents
increased by approximately $0.5 billion to approximately $1.6 billion. We
generated a substantial amount of cash from various sources, including cash
flows from our principal operations, sales of assets and financing transactions,
including long-term debt and equity securities issuances. We also used a major
portion of that cash to fund our capital expenditures, to repay maturing
financial obligations and to meet the increased demand for cash collateral as a
result of our credit downgrade.
In summary, we generated cash from our business operations (before working
capital demands and other changes) of $2.0 billion. We also raised $5.4 billion
of cash through the issuance of debt and equity securities and borrowings under
our revolving credit facility. Cash proceeds from the sale of assets and
investments amounted to approximately $2.9 billion. With the cash we received
from these sources, we invested approximately $4.0 billion in our property,
plant and equipment and equity investments and we paid
34
$2.8 billion on maturing long-term debt and other obligations. Additionally we
paid $0.5 billion in dividends and $0.9 billion to redeem minority and preferred
interests. We also met net working capital and other demands of $1.6 billion
primarily for margin payments related to our energy trading activities, hedging
activities on our natural gas production and other collateral requirements. A
more detailed analysis of our continuing and discontinued cash flows from
operating, investing and financing activities follows.
Cash From Continuing Operating Activities
We generated $1.9 billion in cash from continuing operations in 2002 before
working capital and other changes, as compared to $2.3 billion in 2001. Net cash
provided by continuing operating activities was $0.7 billion for the year ended
December 31, 2002, compared to net cash provided by continuing operating
activities of $3.9 billion for the same period in 2001.
Margin call requirements and trading activities have been a volatile
source, or use, of working capital for us, and are the primary reasons for the
significant differences in our 2002 operating cash flows compared to 2001. Where
we had substantial net cash outflows for margins in 2002 of $0.9 billion, we had
net cash inflows in 2001 for margins of almost $0.3 billion. Operating cash
flows in 2002 also reflected significantly lower cash inflows from settlements
of trading positions of $0.4 billion compared to $1.4 billion in 2001.
Our margin positions are significantly impacted by two factors: credit and
commodity prices. Following our downgrade, credit extended to us by our
counterparties was lowered requiring us to post additional margins. Many of our
counterparties also posted letters of credit with us requiring us to return
their margin deposits. In addition, the impact on our operating cash flows from
changes in commodity prices depends on whether our hedged prices are above or
below market prices. For most of 2001, our hedged prices were above market,
which resulted in margins being deposited with us. When our hedged prices go
below market, as they did in 2002, we are required to make margin deposits.
However, the margin deposits will be recovered when we sell the underlying
commodities and settle the positions or when natural gas prices decrease. At
December 31, 2002, we held $0.1 billion of cash and $0.4 billion of letters of
credit as collateral from third parties related to our price risk management
activities and have provided $1.0 billion of cash and $0.2 billion letters of
credit to third parties related to those activities.
Cash From Continuing Investing Activities
Net cash used in our continuing investing activities was $1.1 billion for
the year ended December 31, 2002. Our continuing investing activities consisted
primarily of capital expenditures and equity investments of $3.7 billion offset
by net proceeds from sale of assets and investments and cash received for
repayment of notes receivable of $2.9 billion. Our capital expenditures and
equity investments included the following (in billions):
Production exploration, development and acquisition
expenditures.............................................. $2.2
Pipeline expansion, maintenance and integrity projects...... 0.9
Investments in and net advances to unconsolidated
affiliates................................................ 0.3
Other (primarily power projects)............................ 0.3
----
Total capital expenditures and equity
investments....................................... $3.7
====
Cash received from our continuing investing activities includes $2.9
billion from the sale of assets and investments. Our asset sales proceeds are
primarily attributable to the sale of natural gas and oil properties in Texas,
Colorado, Utah and western Canada for $1.3 billion, the sales of Texas and New
Mexico midstream assets for $0.5 billion and San Juan assets of $0.4 billion to
El Paso Energy Partners and the sale of other power and processing assets of
$0.7 billion.
Cash From Continuing Financing Activities
Net cash provided by our continuing financing activities was $0.8 billion
for the year ended December 31, 2002. Cash provided from our continuing
financing activities included the net proceeds from the
35
issuance of long-term debt of $4.3 billion, including $0.8 billion of
nonrecourse debt issued in connection with our Utility Contract Funding, L.L.C.
(UCF) power contract restructuring and $0.6 million associated with an equity
security units issuance. Additionally, we issued $1.0 billion of common stock.
We also received net proceeds under our commercial paper and short-term credit
facilities of $0.2 billion. Cash used by our continuing financing activities
included payments made to retire third party long-term debt of $1.8 billion. We
also redeemed $700 million of preferred securities previously issued by our
subsidiaries and made other minority interest payments of $161 million,
primarily to Chaparral which holds a 16 percent minority interest in the UCF
project. Further, we repaid $513 million of notes payable to affiliates, paid
dividends of $470 million and used $1.0 billion in cash generated by our
continuing activities to fund our discontinued operating activities (for
purposes of preparing the cash flow statement, our continuing operations either
fund through contributions or receive a benefit through distributions, the net
cash generated by or used in the operating, investing and financing activities
of our discontinued operations). Also, during the year ended December 31, 2002,
El Paso Tennessee Pipeline Co., our subsidiary, paid dividends of approximately
$25 million on our Series A cumulative preferred stock that accrues at a rate of
8 1/4% per year (2.0625% per quarter).
Cash Flows of Discontinued Operations
During the year ended December 31, 2002, operating cash used in our
discontinued operations was approximately $0.3 billion, primarily due to higher
purchases of inventories at our refineries. Cash used in discontinued investing
activities was approximately $0.2 billion, primarily related to capital
expenditures at our refineries. In discontinued financing activities, we repaid
long-term debt of our discontinued operations of approximately $0.5 billion.
Overall, our discontinued operations used approximately $1.0 billion of cash,
which was funded through a cash contribution from our continuing operations.
Borrowing Activities
A summary of our significant borrowing and repayment activities during 2002
and 2003 (through March 2003) for our continuing and discontinued operations is
presented below. These amounts do not include borrowings or repayments on our
short-term financing instruments with an original maturity of three months or
less, which are referred to above under cash from financing activities.
36
Issuances
NET
COMPANY INTEREST RATE PRINCIPAL PROCEEDS(1) DUE DATE
------- ------------- --------- ----------- ---------
(IN MILLIONS)
2002
El Paso............................ 6.14%-7.875% $2,707(2) $2,580 2007-2032
SNG................................ 8.00% 300 297 2032
EPNG............................... 8.375% 300 297 2032
TGP................................ 8.375% 240 238 2032
Mohawk River Funding IV(3)......... 7.75% 92 90 2008
Utility Contract Funding(3)........ 7.944% 829 792 2016
------ ------
Total from continuing
operations.................... $4,468 $4,294
====== ======
2003
ANR................................ 8.875% $ 300 $ 288 2010
SNG................................ 8.875% 400 385 2010
EPC(4)............................. LIBOR+4.25% 1,200 1,179 2004-2005
------ ------
Total from continuing
operations.................... $1,900 $1,852
====== ======
---------------
(1) Net proceeds were primarily used to repay maturing long-term debt,
short-term borrowings, for repayment of intercompany borrowings, to meet
capital requirements of the borrower, to redeem preferred interests in
consolidated subsidiaries and for general corporate purposes.
(2) Includes $82 million change in value on our E500 million Euro notes from May
2002 to December 2002 due to a change in the Euro to U.S. dollar foreign
currency exchange rate.
(3) These notes are collateralized solely by the cash flows and contracts of
these consolidated subsidiaries, and are non-recourse to our other
consolidated subsidiaries. The Mohawk River Funding IV financing relates to
our Capitol District Energy Center Cogeneration Associates power
restructuring transaction, and the Utility Contract Funding financing
relates to our Eagle Point Cogeneration power restructuring transaction.
(4) We have collateralized this term loan with natural gas and oil reserves of
approximately 2.3 Tcfe. The minimum LIBOR rate is 3.5%.
37
Retirements
NET
COMPANY INTEREST >RATE PRINCIPAL PAYMENTS DUE DATE
------- -------------- --------- -------- --------
(IN MILLIONS)
2002
El Paso.......................... 6.75%-8.78% $ 109 $ 89(1) 2002-2011
El Paso CGP...................... 6.20%-8.125% 720 284(2) 2002-2004
El Paso CGP...................... Variable 711 711 2002-2028
El Paso Tennessee................ 7.88% 12 12 2002
SNG.............................. 7.85%-8.625% 200 200 2002
EPNG............................. 7.75% 215 215 2002
El Paso Oil and Gas Resources.... Variable 215 216 2002-2005
Other............................ Various 51 50 2002
------ ------
Total from continuing
operations.................. 2,233 1,777
Discontinued operations....... Variable 551 551 2002-2028
------ ------
Total.................... $2,784 $2,328
====== ======
2003
El Paso CGP...................... 4.49% $ 240 $ 240 2004
Other............................ Various 47 47 2003
------ ------
Total from continuing
operations.................. $ 287 $ 287
====== ======
---------------
(1) We bought back $109 million of our bonds in the open market during the
second half of the year for $89 million. We anticipate we will continue to
repurchase debt, subject to available liquidity and ongoing market
opportunities.
(2) Includes exchange of $435 million of senior debentures for common stock as
discussed below.
In June 2002, we issued 51.8 million shares of our common stock at a public
offering price of $19.95 per share. Net proceeds from the offering were
approximately $1 billion and were used to repay short-term borrowings and other
financing obligations and for general corporate purposes.
In June 2002, we issued 11.5 million, 9% equity security units. Equity
security units consist of two securities: (i) a purchase contract on which we
pay quarterly contract adjustment payments at an annual rate of 2.86% and that
requires its holder to buy our common stock to be settled on August 16, 2005,
and (ii) a senior note due August 16, 2007, with a principal amount of $50 per
unit, and on which we pay quarterly interest payments at an annual rate of 6.14%
beginning August 16, 2002. The senior notes we issued had a total principal
value of $575 million and are pledged to secure the holders' obligation to
purchase shares of our common stock under the purchase contracts.
When the purchase contracts are settled in 2005, we will issue common
stock. At that time, the proceeds will be allocated between common stock and
additional paid-in capital. The number of common shares issued will depend on
the prior consecutive 20-trading day average closing price of our common stock
determined on the third trading day immediately prior to the stock purchase
date. We will issue a minimum of approximately 24 million shares and up to a
maximum of 28.8 million shares on the settlement date, depending on our average
stock price. We recorded approximately $43 million of other non-current
liabilities to reflect the present value of the quarterly contract adjustment
payments that we are required to make on these units at an annual rate of 2.86%
of the stated amount of $50 per purchase contract with an offsetting reduction
in additional paid-in capital. The quarterly contract adjustment payments are
allocated between the liability recognized at the date of issuance and
additional paid-in capital based on a constant rate over the term of the
purchase contracts.
Fees and expenses incurred in connection with the equity security units
offering were allocated between the senior notes and the purchase contracts
based on their respective fair values on the issuance date. The amount allocated
to the senior notes is recognized as interest expense over the term of the
senior notes. The amount allocated to the purchase contracts is recorded as
additional paid-in capital.
38
In August 2002, we issued 12,184,444 shares of common stock to satisfy
purchase contract obligations under our FELINE PRIDES(sm) program. In return for
the issuance of the stock, we received approximately $25 million in cash from
the maturity of a zero coupon bond and the return of $435 million of our
existing 6.625% senior debentures due August 2004 that were issued in 1999. The
zero coupon bond and the senior debentures had been held as collateral for the
purchase contract obligations. The $25 million received from the maturity of the
zero coupon bond was used to retire additional senior debentures. Total debt
reduction from the issuance of the common stock was approximately $460 million.
Credit Facilities
We have historically used commercial paper programs to manage our
short-term cash requirements. Under our programs we could borrow up to $3
billion through a combination of individual corporate, TGP and EPNG commercial
paper programs of $1 billion each. However, as a result of our credit downgrade,
we are not currently issuing commercial paper to meet our liquidity needs.
In May 2002, we renewed our existing $3 billion 364-day revolving credit
and competitive advance facility. EPNG and TGP are also designated borrowers
under this facility and, as such, are jointly and severally liable for any
amounts outstanding. This facility matures in May 2003 and provides that amounts
outstanding on that date are not due until May 2004. We also maintain a 3-year,
$1 billion, revolving credit and competitive advance facility under which we can
conduct short-term borrowings and other commercial credit transactions. In June
2002, we amended this facility to permit us to issue up to $500 million in
letters of credit and to adjust pricing terms. This facility matures in August
2003. Our subsidiaries, El Paso CGP Company (formerly Coastal), EPNG and TGP,
are designated borrowers under the facility and, as such, are jointly and
severally liable for any amounts outstanding. The interest rate under both of
these facilities varies based on our senior unsecured debt rating, and as of
December 31, 2002, borrowings under the facility have a rate of LIBOR plus 1.00%
plus a 0.25% utilization fee. At December 31, 2002, we had $1.5 billion
outstanding under the $3 billion facility and issued approximately $456 million
letters of credit under the $1 billion facility. In February 2003, we borrowed
$500 million under the $1 billion facility.
We are currently negotiating an amendment to our $3 billion 364-day
revolving credit facility. If we are successful in negotiating this amendment,
we expect the terms and conditions of the amended revolving credit facility to
include an extension of the maturity date, an increase in the unused commitment
fee and margin, collateral to support the financing, and new and amended
financial ratios and covenants. It is expected that ANR, TGP and EPNG would also
be borrowers under this facility. We are also currently negotiating an amendment
to our $1 billion multi-year facility, which we expect to be conformed to the
amended $3 billion 364-day revolver, except for the commitment amount, the
identity of lenders and the maturity.
The availability of borrowings under our credit and borrowing agreements is
subject to specified conditions, which we currently meet. These conditions
include compliance with the financial covenants and ratios required by such
agreements, absence of default under such agreements, and continued accuracy of
the representations and warranties contained in such agreements.
Restrictive Covenants. We and our subsidiaries have entered into debt
instruments and guaranty agreements that contain covenants such as restrictions
on debt levels, restrictions on liens securing debt and guarantees, restrictions
on mergers and on the sales of assets, capitalization requirements, dividend
restrictions and cross-payment default and cross-acceleration provisions. A
breach of any of these covenants could result in acceleration of our debt and
other financial obligations and that of our subsidiaries. Under our revolving
credit facilities, the significant debt covenants and cross defaults are:
(a) the ratio of consolidated debt and guarantees to capitalization
(excluding certain project financing and securitization programs and
other miscellaneous items as defined in the agreement) cannot exceed 70
percent;
(b) the consolidated debt and guarantees (other than excluded items) of our
subsidiaries cannot exceed the greater of $600 million or 10 percent of
our consolidated net worth;
39
(c) we or our principal subsidiaries cannot permit liens on the equity
interest in our principal subsidiaries or create liens on assets
material to our consolidated operations securing debt and guarantees
(other than excluded items) exceeding the greater of $300 million or 10
percent of our consolidated net worth, subject to certain permitted
exceptions; and
(d) the occurrence of an event of default for any non-payment of principal,
interest or premium with respect to debt (other than excluded items) in
an aggregate principal amount of $200 million or more; or the
occurrence of any other event of default with respect to such debt that
results in the acceleration thereof.
We were in compliance with the above covenants as of the date of this
filing, including our ratio of debt to capitalization (as defined in our credit
facilities), which was 63.2% at December 31, 2002.
We have also issued various guarantees securing financial obligations of
our subsidiaries and unconsolidated affiliates with similar covenants as in the
above credit facilities.
With respect to guarantees issued by our subsidiaries, the most significant
debt covenant, in addition to the covenants discussed above, is that El Paso CGP
must maintain a minimum net worth of $1.2 billion. If breached, the amounts
guaranteed by the guaranty agreements could be accelerated. The guaranty
agreements also maintain a $30 million cross-acceleration provision. El Paso
CGP's net worth at December 31, 2002, was $4.3 billion.
In addition, three of our subsidiaries have indentures associated with
their public debt that contain $5 million cross-acceleration provisions. These
cross-acceleration provisions generally state that if an event of default occurs
that exceeds $5 million, then amounts outstanding for the securities that
contain these indentures also become due and payable.
Available Capacity Under Shelf Registration Statements
In February 2002, we filed a new shelf registration statement with the SEC
that allows us to issue up to $3 billion in securities. Under this registration
statement, we can issue a combination of debt, equity and other instruments,
including trust preferred securities of two wholly owned trusts, El Paso Capital
Trust II and El Paso Capital Trust III. If we issue securities from these
trusts, we will be required to issue full and unconditional guarantees on these
securities. As of December 31, 2002, we had $818 million remaining capacity
under this shelf registration statement.
Letters of Credit
We enter into letters of credit in the ordinary course of our operating
activities. As of December 31, 2002, we had outstanding letters of credit of
approximately $852 million (including $170 million related to our discontinued
petroleum markets operations) versus $465 million (including $11 million related
to our discontinued petroleum markets operations) as of December 31, 2001. The
increase is primarily due to the issuance of letters of credit in connection
with the management of our trading activities. At December 31, 2002, $456
million of our outstanding letters of credit were supported by our revolving
credit facility, including $150 million related to our discontinued petroleum
markets operations.
OFF-BALANCE SHEET ARRANGEMENTS AND CONTRACTUAL OBLIGATIONS
In the course of our business activities, we enter into a variety of
financing arrangements and contractual obligations. The following discusses
first those contingent obligations, often referred to as off-balance sheet
arrangements, that are not part of the consolidated obligations reflected in our
financial statements. Second, we present aggregated information on our
contractual cash obligations, some of which are reflected in our financial
statements, such as short and long-term debt, and others, such as operating
leases and capital commitments, which are not reflected in our financial
statements.
40
OFF-BALANCE SHEET ARRANGEMENTS
The following table summarizes our off-balance sheet arrangements by date
of expiration as of December 31, 2002. These commitments are discussed in
further detail below:
TOTAL
AMOUNTS
COMMITTED
-------------
(IN MILLIONS)
Credit facilities........................................... $ 300
Guarantees(1)............................................... 2,508
Residual value guarantees(1)................................ 570
------
Total.................................................. $3,378
======
---------------
(1) Includes $63 million of guarantees and $333 million of residual value
guarantees associated with our discontinued petroleum markets business.
Credit Facilities
We have a credit facility with Gemstone that allows Gemstone to borrow up
to $300 million from us at a variable interest rate, which was 6.8% at December
31, 2002. Gemstone owed us $25 million under this facility as of December 31,
2002, and did not utilize this facility in 2001. We earned less than $1 million
of interest income from this facility in 2002 and 2001.
Guarantees
We are involved in various joint ventures and other ownership arrangements
that sometimes require additional financial support that results in the issuance
of financial and performance guarantees. In a financial guarantee, we are
obligated to make payments if the guaranteed party fails to make payments under,
or violates the terms of, the financial arrangement. In a performance guarantee,
we provide assurance that the guaranteed party will execute on the terms of the
contract. If they do not, we are required to perform on their behalf. For
example, if the guaranteed party is required to deliver natural gas to a third
party and then fails to do so, we would be required to either deliver that
natural gas or make payments to the third party equal to the difference between
the contract price and the market value of the natural gas.
As of December 31, 2002, we had approximately $2.5 billion of both
financial and performance guarantees outstanding. Of this amount, approximately
$1.0 billion relates to our Chaparral investment and $950 million relates to our
Gemstone investment, both of which are discussed below. The remaining $558
million relates to other global power equity investments, including some of the
projects under Chaparral and Gemstone, pipeline activities, and petroleum
activities (included as discontinued operations).
Chaparral. We entered into the Chaparral investment (also referred to as
Electron) in 1999 to expand our domestic power generation business. At the time
Chaparral was formed, we were interested in participating in the deregulation of
the power industry that was occurring across the U.S. Our objective was to
acquire a number of nonregulated power plants that were built because of PURPA.
With these plants and their related power contracts, there were opportunities to
improve existing income and cash flows by lowering the cost of power sold to the
regulated utility under the plant's power sales agreement. This was accomplished
by purchasing the power supplied to the utility from the wholesale power market,
rather than generating power at the plant. Consequently, Chaparral's investors,
and our shareholders would benefit from these improved economics. In
establishing this business, there were a number of objectives we hoped to
achieve, including:
- Portfolio management. Our goal was to establish an investment, not
unlike a mutual fund or other investment portfolio, that held a number of
assets, and on which we could earn a performance-based management fee
determined by the value we delivered to all investors. Furthermore, this
portfolio approach allowed us to reduce the volatility of earnings and
enhance the cash flows in this business.
41
- Flexibility and efficiency. Given the complexity of acquiring, managing
and renegotiating existing power contracts, we sought investors whose
business strategies were aligned with ours, to allow us maximum
flexibility and efficiency.
- Liability segregation and separation of non-recourse financing and other
liabilities from our balance sheet. Many of the power projects in which
we would hold interests were funded through partnerships and non-recourse
project financings which, on average, had higher leverage in terms of
their debt to total equity. Had this business been developed on our
balance sheet, it could have negatively impacted our ratios and possibly
our credit ratings. Consequently, we did not want to reflect this higher
leverage in our overall capitalization given that the debt is
non-recourse to us. Furthermore, separation of these entities and their
related debt and other obligations more appropriately reflected the
nature of the recourse, which was solely to the projects.
Chaparral's corporate structure is a limited liability company that, at
December 31, 2002, was owned approximately 20 percent by us and approximately 80
percent by an unaffiliated investor, Limestone. Limestone is capitalized by
private equity contributions of $150 million from a group of unrelated financial
investors through Credit Suisse First Boston Corporation and $1 billion of
senior secured notes issued to institutional investors. Limestone is controlled
by subsidiaries or affiliates of Credit Suisse First Boston Corporation.
In March 2003, we notified Limestone that we will exercise our right under
the partnership agreements to purchase all of the outstanding third party equity
in Limestone on May 31, 2003, for $175 million. On March 31, 2003, we
contributed $1 billion to Limestone in exchange for a non-controlling interest.
Limestone used the proceeds from the contribution to pay off $1 billion of the
notes that matured on that date. With this note repayment, we cancelled our $1
billion guarantee related to our Chaparral investment. Following our additional
investment of $1 billion in Limestone, our effective ownership of Chaparral
increased to approximately 90 percent, but neither our rights nor the rights of
Limestone to participate in the operating decisions of Chaparral changed. As a
result, we continue to account for our investment in Chaparral under the equity
method. We will consolidate Chaparral upon the purchase of the remaining third
party equity interest in Limestone, which we expect to occur in May 2003. At
that time, we will record the acquired assets and liabilities at their fair
values. The fair value of assets and liabilities acquired will be impacted by
changes in the unregulated power industry as a whole, as well as by changes in
regional power prices in the U.S. Any excess of the proceeds paid over the fair
value of net assets acquired will be reflected as goodwill. Goodwill is not
subject to amortization but it will be tested for impairment. While we cannot
currently estimate the ultimate amount of goodwill that will be recorded, we
believe goodwill of up to $450 million may result. If goodwill were to be fully
impaired we would report a charge to earnings of approximately $300 million
after income taxes. If, on the other hand, the carrying amount of the acquired
assets and liabilities, when aggregated with our other power assets and
liabilities, is below the fair value of the reporting unit (reporting unit being
defined as the entire global power business), there would be no impairment of
goodwill.
As of December 31, 2002, Chaparral had $4.2 billion of total assets and
$1.8 billion of consolidated third party debt. Chaparral's debt is related to
specific assets it owns or has interests in, and is recourse solely to those
assets. Our equity investment in Chaparral at December 31, 2002 was $256
million, but we also had additional net receivables from Chaparral which totaled
$448 million, resulting in a total net investment in Chaparral of $704 million
at December 31, 2002.
For a further discussion of Chaparral and its activities, see Item 7, Note
26 of this Current Report on Form 8-K.
Gemstone. We entered into the Gemstone investment in 2001 to finance five
major power plants in Brazil. Gemstone was established to accomplish the
following objectives:
- Portfolio management. Like Chaparral, our goal was to establish an
investment portfolio that held a number of assets in which we participate
in the earnings of these equity investments. Unlike Chaparral's
performance-based management fee, however, our primary objective in this
investment
42
was to have the flexibility to acquire or sell additional assets into or
out of the overall portfolio of projects.
- Flexibility and efficiency. Given the complexity of acquiring,
operationally managing and negotiating power contracts with foreign
governments, we sought investors whose interests were primarily financial
(return driven), to allow us maximum flexibility and efficiency.
Furthermore, this allowed us to share risk in a foreign country and
partially mitigate our foreign investment risk.
Gemstone is a generic term used to describe several entities. The first is
the joint venture in which we have an equity investment named Diamond Power
Ventures, LLC (Diamond). Diamond is owned by us and Gemstone Investor. Gemstone
Investor is 100 percent owned by a subsidiary of Rabobank International, which,
in addition to its $50 million equity investment, issued $950 million of senior
secured notes to institutional investors. Gemstone Investor used the entire $1
billion to (a) invest up to $700 million in Diamond, and (b) purchase a $300
million preferred interest in a company called Topaz Power Ventures LLC (Topaz),
our consolidated subsidiary. Topaz indirectly owns and operates two Brazilian
power plants. We account for Gemstone Investor's preferred investment in Topaz
as minority interest. We do not consolidate Diamond, which owns three power
plants in Brazil.
Gemstone owns interests in five power generation facilities in Brazil with
a total power generation capacity of 2,184 megawatts. As of December 31, 2002,
Gemstone had total assets of $1.7 billion, including a $304 million investment
in Topaz, and $122 million in receivables from us. Our total investment in
Gemstone at December 31, 2002, was $663 million, excluding the payables of $304
million and minority interest of $122 million mentioned above.
Our consolidated subsidiary, Gemstone Administracao Ltda, serves as the
managing member of Diamond and provides management services to Diamond under a
fixed-fee administrative services agreement. The fixed fee reimburses us for
legal, accounting and general and administrative expenses incurred on behalf of
Diamond.
In January 2003, Rabobank notified us that they planned to remove us as
manager of Gemstone, in accordance with their rights under our partnership
agreements. We, in turn, notified Rabobank that we were exercising our right
under the partnership agreements to purchase all of Rabobank's $50 million of
equity in Gemstone. We will consolidate Gemstone upon the purchase of Rabobank's
equity in Gemstone by April 2003, unless we replace them with a new partner.
For a further discussion of Gemstone and its activities, see Item 7, Note
26 of this Current Report on Form 8-K.
Residual Value Guarantees
Under two of our operating leases, we have provided residual value
guarantees to the lessor. Under the leases, we can either choose to purchase the
asset at the end of the lease term for a specified amount, which is typically
equal to the outstanding loan amounts owed by the lessor, or we can choose to
assist in the sale of the leased asset to a third party. Should the asset not be
sold for a price that equals or exceeds the amount of the guarantee, we would be
obligated for the shortfall. The levels of our residual value guarantees range
from 86.2 percent to 89.9 percent of the original cost of the leased assets.
Accounting for these residual value guarantees will be impacted effective July
1, 2003, by our adoption of the new accounting rules on consolidations. For a
discussion of the accounting impact of these new rules, see New Accounting
Pronouncements Issued But Not Yet Adopted beginning on page 75.
43
As of December 31, 2002, we had purchase options and residual value
guarantees associated with operating leases for the following assets:
PURCHASE RESIDUAL VALUE LEASE
ASSET DESCRIPTION OPTION GUARANTEE EXPIRATION
----------------- -------- -------------- ----------
(IN MILLIONS)
Lakeside Technology Center telecommunications
facility.......................................... $275 $237 2006
Facility at Aruba refinery(1)....................... 370 333 2006
---------------
(1) This leased asset is part of our petroleum markets business that has been
reclassified as discontinued operations.
CONTRACTUAL CASH OBLIGATIONS
The following table summarizes our contractual cash obligations as of
December 31, 2002, for each of the years presented.
CONTRACTUAL CASH OBLIGATIONS 2003 2004 2005 2006 2007 THEREAFTER TOTAL
---------------------------- ------ ------ ------ ------ ------ ---------- -------
(IN MILLIONS)
Long-term debt(1).................... $ 575 $ 586 $ 610 $1,234 $1,133 $12,590 $16,728
Preferred interests of consolidated
subsidiaries(2).................... 400 900 380 950 -- 625 3,255
Western Energy Settlement(3)......... 100 132 129 67 67 1,072 1,567
Operating leases(4).................. 174 147 113 89 56 265 844
Transportation and storage
capacity(5)........................ 169 175 151 139 126 674 1,434
Commodity purchases(6)............... 4 3 3 3 3 20 36
Obligations to affiliates(7)......... 189 10 12 6 -- 173 390
Other commitments and purchase
obligations(8)(9).................. 462 190 59 19 9 86 825
------ ------ ------ ------ ------ ------- -------
Total contractual cash
obligations..................... $2,073 $2,143 $1,457 $2,507 $1,394 $15,505 $25,079
====== ====== ====== ====== ====== ======= =======
---------------
(1) See Item 7, Note 18 of this Current Report on Form 8-K.
(2) See Item 7, Note 19 of this Current Report on Form 8-K.
(3) See Item 7, Notes 2 and 20 of this Current Report on Form 8-K.
(4) We maintain operating leases in the ordinary course of our business
activities. These leases include those for office space and operating
facilities and office and operating equipment, and the terms of the
agreements vary from 2003 until 2053. Amounts include operating lease
commitments associated with our discontinued operations as follows: $81
million in 2003, $58 million in 2004, $28 million in 2005, $16 million in
2006, $6 million in 2007 and $46 million thereafter.
(5) Amounts include payments for firm access to natural gas transportation and
storage capacity.
(6) Amounts include purchase commitments for electricity that are not part of
our trading activities.
(7) Amounts include obligations of $252 million to Chaparral, $122 million to
Gemstone and $16 million to other affiliates. Our obligation to Chaparral
consists of $79 million of debt securities and $173 million of contingent
interest promissory notes. The debt securities are payable on demand and
carry a fixed interest rate of 7.443%. The contingent interest promissory
notes carry a variable interest rate not to exceed 12.75% and mature in 2019
through 2021. Our obligation to Gemstone consists of $122 million of debt
securities, which are payable on demand and carry a fixed interest rate of
5.25%.
(8) Amounts include primarily other purchase and capital commitments such as
maintenance contracts, engineering, procurement and construction costs.
Amounts include $29 million for 2003 which relates to our discontinued
petroleum markets operations.
(9) Other commitments exclude $2.5 billion associated with our LNG ship charter
agreement. These obligations were restructured in March 2003 and resulted in
issuance of letters of credit equal to $120 million, which was fully
collateralized by cash.
44
Results of Operations
We use earnings before interest and income taxes (EBIT) to assess the
operating results and effectiveness of our business segments. We define EBIT as
net income (loss) adjusted for (i) items that do not impact our income (loss)
from continuing operations, such as extraordinary items, discontinued operations
and the impact of accounting changes, (ii) income taxes, (iii) interest and debt
expense and (iv) distributions on preferred interests of consolidated
subsidiaries. We exclude interest and debt expenses and distributions on
preferred interests of consolidated subsidiaries so that investors may evaluate
our operating results without regard to our financing methods or capital
structure. Our business operations consist of both consolidated businesses as
well as substantial investments in unconsolidated affiliates. The following is a
reconciliation of our operating results to EBIT and to net income (loss) for the
years ended December 31:
2002 2001 2000
------- ------- -------
(IN MILLIONS)
Operating revenues.......................................... $ 7,598 $ 8,939 $ 7,188
Operating expenses.......................................... (7,343) (7,796) (4,933)
------- ------- -------
Operating income.......................................... 255 1,143 2,255
Earnings (losses) from unconsolidated affiliates............ (226) 437 423
Minority interest in consolidated subsidiaries.............. (58) (2) --
Other income................................................ 201 288 206
Other expenses.............................................. (180) (126) (52)
------- ------- -------
EBIT...................................................... (8) 1,740 2,832
Interest and debt expense................................... (1,388) (1,129) (1,001)
Returns on preferred interests of consolidated
subsidiaries.............................................. (159) (217) (204)
Income taxes................................................ 507 (242) (514)
------- ------- -------
Income (loss) from continuing operations.................. (1,048) 152 1,113
Discontinued operations, net of income taxes................ (365) (85) 123
Extraordinary items, net of income taxes.................... -- 26 70
Cumulative effect of accounting changes, net of income
taxes..................................................... (54) -- --
------- ------- -------
Net income (loss)......................................... $(1,467) $ 93 $ 1,306
======= ======= =======
We believe EBIT is a useful measurement for our investors because it
provides information that can be used to evaluate the effectiveness of our
businesses and investments from an operational perspective, exclusive of the
costs to finance those activities and exclusive of income taxes, neither of
which are directly relevant to the efficiency of those operations. This
measurement may not be comparable to measurements used by other companies and
should not be used as a substitute for net income or other performance measures
such as operating cash flow.
45
OVERVIEW OF RESULTS OF OPERATIONS
Below are our results of operations (as measured by EBIT), by segment for
each of the years ended December 31. These results include the impacts of
restructuring and merger-related costs, asset impairments, and other charges
(including our estimated Western Energy Settlement) and gains on sales of
assets, which are discussed further in Item 7, Notes 2, 4, 5 and 26 of this
Current Report on Form 8-K. See Item 7, Note 24, for a reconciliation of our
operating results to EBIT by segment.
EBIT BY SEGMENT 2002 2001 2000
--------------- ------- ------- ------
(IN MILLIONS)
Pipelines................................................... $ 818 $ 1,038 $1,323
Production.................................................. 534 920 609
Field Services.............................................. 287 195 214
Merchant Energy............................................. (1,421) 1,015 749
------- ------- ------
Segment EBIT.............................................. 218 3,168 2,895
Corporate and other......................................... (226) (1,428) (63)
------- ------- ------
Consolidated EBIT from continuing operations.............. $ (8) $ 1,740 $2,832
======= ======= ======
46
SEGMENT RESULTS
Our four segments: Pipelines, Production, Field Services and Merchant
Energy are strategic business units that offer a variety of different energy
products and services, each requires different technology and marketing
strategies. Below is a discussion and analysis of the operating results of each
of our business segments. These results include the impact of our significant
acquisitions and dispositions, the restructuring and merger-related costs, asset
impairments and other charges discussed above for all years presented.
PIPELINES
Our Pipelines segment consists of interstate natural gas transmission,
storage, gathering and related services in the U.S. and internationally. Our
interstate natural gas transportation systems face varying degrees of
competition from other pipelines, as well as from alternate energy sources used
to generate electricity, such as hydroelectric power, nuclear, coal and fuel
oil. In addition, some of our customers have shifted from a traditional
dependence solely on long-term contracts to a portfolio approach which balances
short-term opportunities with long-term commitments. The shift is due to changes
in market conditions and competition driven by state utility deregulation, local
distribution company mergers, new supply sources, volatility in natural gas
prices, demand for short-term capacity and new markets to supply power plants.
We are regulated by the FERC, which regulates the rates we can charge our
customers. These rates are a function of our costs of providing services to our
customers, and include a return on our invested capital. As a result, our
financial results have historically been relatively stable; however, they can be
subject to volatility due to factors such as weather, changes in natural gas
prices and market conditions, regulatory actions, competition and the
credit-worthiness of our customers. In addition, our ability to extend our
existing customer 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.
As discussed in Item 7, Note 20 under the subheading Rates and Regulatory
Matters, of this Current Report on Form 8-K, the FERC issued an order related to
the allocation of capacity on the EPNG system. This order required EPNG to:
- give reservation charge credits prospectively to its firm shippers if it
fails to schedule the shippers' confirmed volumes (except in the case of
force majeure);
- refrain from entering into new firm contracts or remarketing turned back
capacity under contracts terminating or expiring after May 31, 2002; and
- add additional compression to its Line 2000 project increasing the
capacity by 320 MMcf/d without the opportunity to recover these costs in
its rates until its next rate case which will be effective January 1,
2006.
Our Pipelines segment's future results of operations will be impacted as a
result of the capacity allocation proceeding. The order prohibits EPNG from
remarketing approximately 471 MMDth/d of its capacity, of which approximately
200 MMDth/d was rejected by Enron Corp. in May 2002 in its bankruptcy
proceeding. The remaining 271 MMDth/d relates to capacity that EPNG is unable to
remarket from contracts that expired within the time frame specified under the
FERC's order. Prior to the rejection and expiration of the 471 MMDth/d
contracts, EPNG was earning approximately $3.5 million per month, net of revenue
credits, related to this capacity. EPNG has requested rehearing of the September
20 FERC order relating to this and other aspects of the order. This request for
rehearing is pending before the FERC.
In December 2001, Enron Corp. and a number of its subsidiaries, including
Enron North America Corp. and Enron Power Marketing, Inc., filed for Chapter 11
bankruptcy protection in the United States Bankruptcy
47
Court for the Southern District of New York. Enron's subsidiaries had
transportation contracts on several of our pipeline systems (including the EPNG
contract discussed above). All these transportation contracts have now been
rejected, and our pipeline subsidiaries have filed proofs of claim totaling
approximately $137 million. EPNG filed the largest proof of claim in the amount
of approximately $128 million, which included $18 million for amounts due for
services provided through the date the contracts were rejected and $110 million
for damage claims arising from the rejection of its transportation contracts,
which EPNG is prohibited from remarketing under the capacity allocation orders
discussed above. We have fully reserved for all amounts due from Enron through
the date the contracts were rejected, and we have not recognized any revenues
from these contracts since the rejection date.
In November 2002, we sold 12.3 percent of our 14.4 percent equity interest
in the Alliance pipeline system, and net proceeds were $141 million. We
completed the sale of our remaining equity interest in Alliance during the first
quarter of 2003. Income earned on our investment in Alliance for the year ended
December 31, 2002 and 2001, was approximately $21 million and $23 million.
Results of operations of the Pipelines segment were as follows for each of
the three years ended December 31:
PIPELINES SEGMENT RESULTS 2002 2001 2000
------------------------- ------- ------- -------
(IN MILLIONS, EXCEPT VOLUME
AMOUNTS)
Operating revenues.......................................... $ 2,605 $ 2,748 $ 2,741
Operating expenses.......................................... (1,815) (1,862) (1,591)
------- ------- -------
Operating income.......................................... 790 886 1,150
Other income................................................ 28 152 173
------- ------- -------
EBIT...................................................... $ 818 $ 1,038 $ 1,323
======= ======= =======
Throughput volumes (BBtu/d)(1)
TGP....................................................... 4,596 4,405 4,354
EPNG and MPC.............................................. 4,065 4,535 4,310
ANR....................................................... 3,691 3,776 3,807
CIG and WIC............................................... 2,644 2,341 2,106
SNG....................................................... 2,020 1,877 2,132
Equity investments (our ownership share).................. 2,731 2,470 2,315
------- ------- -------
Total throughput.................................. 19,747 19,404 19,024
======= ======= =======
---------------
(1) Throughput volumes exclude those related to pipeline systems sold in
connection with Federal Trade Commission orders related to our Coastal and
Sonat mergers including the Midwestern Gas Transmission, East Tennessee
Natural Gas and Sea Robin systems; and the Destin, Empire State and Iroquois
pipeline investments. Throughput volumes exclude intrasegment activities.
Year Ended December 31, 2002 Compared to Year Ended December 31, 2001
Operating revenues for the year ended December 31, 2002, were $143 million
lower than in 2001. The decrease was due to lower natural gas and liquids sales
of $49 million resulting from lower prices in 2002 and $67 million due to the
impact of lower natural gas prices in 2002 on net natural gas recovered and used
in operations. Also contributing to the decrease were lower revenues of $49
million from natural gas sales and from gathering and processing activities due
to the sale of CIG's Panhandle field in July 2002, lower transportation revenues
of $49 million due to lower revenues from capacity sold under short-term
contracts and lower throughput due to lower electric generation demand and
milder winter weather in 2002. In addition, an $11 million decrease in operating
revenues was due to the favorable resolution of regulatory issues related to
natural gas purchase contracts in 2001, a $4 million decrease was due to lower
rates on the Mojave pipeline system as a result of a rate case settlement
effective October 2001, and a $6 million decrease due to the sale of our
Midwestern Gas Transmission system in April 2001. These decreases were partially
offset by $51 million of additional revenues due largely to transmission system
expansion projects placed in service in 2001 and 2002, $13 million due to a
larger portion of EPNG's capacity contracted at maximum tariff rates in 2002,
48
$32 million from the Elba Island LNG facility placed in service in December 2001
and $18 million from the favorable resolution of measurement issues at a
processing plant serving the TGP system in 2002.
Operating expenses for the year ended December 31, 2002, were $47 million
lower than in 2001 primarily as a result of $41 million lower fuel and system
supply purchases costs resulting from lower natural gas volumes and prices in
2002, $22 million from the impact of price changes in natural gas imbalances,
$27 million due to lower employee benefit costs in 2002 due to cost efficiencies
following the merger with Coastal, lower amortization of goodwill of $18 million
due to the adoption of SFAS No. 142 in January 2002, $22 million decrease
related to the sale of CIG's Panhandle field in July 2002 and $27 million from
lower electricity, legal, environmental and overhead costs. Also contributing to
lower operating expenses was $11 million due to a gain on the sale of pipeline
expansion rights in February 2002. Offsetting these lower costs were charges of
$7 million to our reserve for bad debts in 2002 related to the bankruptcy of
Enron Corp., $10 million in contributions to a charitable foundation associated
with EPNG's pipeline rupture, $13 million of higher amortization of additional
acquisition costs assigned to a utility plant in 2002 and higher operating
expenses of $16 million due to the Elba Island LNG facility returning to service
in 2002. Also during 2002, we accrued $412 million for our Western Energy
Settlement, and in 2001 we had merger-related costs of $291 million in
connection with our Coastal merger. For a discussion of these charges, see Item
7, Notes 2 and 4 of this Current Report on Form 8-K.
Other income for the year ended December 31, 2002, was $124 million lower
than in 2001 primarily due to a $153 million asset impairment charge associated
with our western Australia investment. Offsetting this charge was $11 million
due to the resolution of uncertainties associated with the sales of our
interests in the Empire State, Iroquois pipeline systems, and our Gulfstream
pipeline project in 2001 offset by lower equity earnings of $6 million on Empire
State and Iroquois pipeline systems due to the sale of our interests in 2001.
Also offsetting the lower income were higher equity earnings in 2002 of $16
million primarily due to higher equity earnings from our investment in Great
Lakes Gas Transmission.
Year Ended December 31, 2001 Compared to Year Ended December 31, 2000
Operating revenues for the year ended December 31, 2001, were $7 million
higher than in 2000. The increase was due to higher reservation revenues of $67
million on the EPNG system as a result of a larger portion of its capacity sold
at maximum tariff rates versus the same period in 2000 and the impact of
completed system expansions and new storage and transportation contracts during
2001 on CIG of $33 million. Also contributing to the increase were the impact of
higher natural gas prices in the first and second quarters on sales of
segment-owned production of $29 million, sales of excess natural gas and sales
under regulated natural gas sales contracts of $27 million, as well as higher
throughput from increased deliveries to California and other western states of
$6 million. These increases were partially offset by lower 2001 revenues of $44
million from contract remarketing in the TGP system in late 2000 and $42 million
from the impact of the sales of the Midwestern Gas Transmission system in April
2001, Crystal Gas Storage in September 2000 and the East Tennessee Natural Gas
and Sea Robin systems in the first quarter of 2000. Also partially offsetting
the increase were lower 2001 sales of $22 million related to base gas from
abandoned storage fields, the favorable resolution in 2000 of natural gas
price-related contingencies on CIG of $28 million, $11 million from lower
transportation revenues in 2001 on TGP as a result of higher proportion of
throughput earnings from short versus long hauls compared to 2000 and $6 million
from lower remarketed rates on seasonal turned-back capacity in 2001 as a result
of SNG's 2000 rate case settlement allowing some customers to partially reduce
their firm transportation capacity.
Operating expenses for the year ended December 31, 2001, were $271 million
higher than in 2000 primarily as a result of the merger-related and other
charges of $334 million in 2001 discussed previously. Also contributing to the
increase was the impact of higher natural gas prices in the first half of 2001
on natural gas purchase contracts of $12 million, higher purchase gas costs of
$8 million due to a natural gas imbalance revaluation in 2001 as a result of
falling gas prices during the second half of the year, increases to our reserve
for bad debts as a result of our exposure in connection with the bankruptcy of
Enron Corp., and a one-time favorable adjustment to depreciation expense during
the first quarter of 2000 of $10 million resulting from the FERC approval to
reactivate the Elba Island LNG facility. Also contributing to the increase was
the impact of
49
gains in 2000 from the sales of non-pipeline assets of $8 million. Partially
offsetting the increase were lower operating and maintenance expenses of $83
million due to cost efficiencies following the merger with Coastal and reduced
operating and lower depreciation expenses of $19 million due to the sales of the
Midwestern Gas Transmission system in April 2001, Crystal Gas Storage in
September 2000 and East Tennessee and Sea Robin in the first quarter of 2000.
Other income for the year ended December 31, 2001, was $21 million lower
than in 2000 due to lower equity earnings of $13 million on our Australian
pipelines and Citrus Corp., which owns the Florida Gas Transmission System. Also
contributing to the decrease was the impact on equity earnings due to the sales
of our investments in the Empire State and Iroquois pipeline systems in 2001 of
$8 million and the sale of our one-third interest in Destin Pipeline Company in
2000 of $2 million. Partially offsetting the decrease was increased earnings
from our investment in the Alliance pipeline project of $9 million which
commenced operations in the fourth quarter of 2000.
PRODUCTION
The Production segment conducts our natural gas and oil exploration and
production activities. Our operating results are driven by a variety of factors
including the ability to locate and develop economic natural gas and oil
reserves, extract those reserves with minimal production costs, sell the
products at attractive prices and operate at the lowest total cost level
possible.
Production has historically engaged in hedging activities on its natural
gas and oil production to stabilize cash flows and reduce the risk of downward
commodity price movements on its sales. This is achieved primarily through
natural gas and oil swaps. In the past, our stated goal was to hedge
approximately 75 percent of our anticipated current year production,
approximately 50 percent of our anticipated succeeding year production and a
lesser percentage thereafter. As a component of our strategic repositioning plan
in May 2002, we modified this hedging strategy. Under our modified strategy, we
may hedge up to 50 percent of our anticipated production for a rolling 12-month
forward period. This modification of our hedging strategy will increase our
exposure to changes in commodity prices which could result in significant
volatility in our reported results of operations, financial position and cash
flows from period to period. As of December 31, 2002, we have hedged
approximately 215 million MMBtu's of our anticipated natural gas production for
2003 at a NYMEX Henry Hub price of $3.43 per MMBtu before regional price
differentials and transportation costs.
During 2002, we continued an active onshore and offshore development
drilling program to capitalize on our land and seismic holdings. This
development drilling was done to take advantage of our large inventory of
drilling prospects and to develop our proved undeveloped reserve base. We also
completed asset dispositions in Colorado, Utah, western Canada and Texas as part
of our balance sheet enhancement plan. Primarily due to our asset dispositions,
we have a lower reserve base at January 1, 2003 than we did at January 1, 2002.
See Item 7, Note 28 of this Current Report on Form 8-K, for a discussion of our
natural gas and oil reserves. Since our depletion rate is determined under the
full cost method of accounting, a lower reserve base coupled with additional
capital expenditures in the full cost pool will result in a higher depletion
rate in future periods. For the first quarter of 2003, we expect our domestic
unit of production depletion rate to be approximately $1.59 per Mcfe.
We currently expect to reduce our total capital expenditures from
approximately $2.4 billion in 2002 to approximately $1.4 billion in 2003. We
continually evaluate our capital expenditure program and this estimate is
subject to change based on market conditions. We will continue to pursue
strategic acquisitions of production properties and the development of projects
subject to acceptable returns. In July 2002, we acquired natural gas properties
in the Raton Basin for approximately $140 million. These properties were
acquired to expand our interest in the current coal seam project in the area.
50
Below are the operating results and analysis of these results for each of
the three years ended December 31:
PRODUCTION SEGMENT RESULTS 2002 2001 2000
-------------------------- ------------ ------------ ------------
(IN MILLIONS, EXCEPT VOLUMES AND PRICES)
Operating Revenues:
Natural gas................................................. $ 1,758 $ 2,005 $ 1,412
Oil, condensate and liquids................................. 373 320 255
Other....................................................... (5) 22 19
-------- -------- --------
Total operating revenues.......................... 2,126 2,347 1,686
Transportation and net product costs........................ (113) (97) (78)
-------- -------- --------
Total operating margin............................ 2,013 2,250 1,608
Operating expenses(1)....................................... (1,484) (1,331) (995)
-------- -------- --------
Operating income.......................................... 529 919 613
Other income (loss)......................................... 5 1 (4)
-------- -------- --------
EBIT...................................................... $ 534 $ 920 $ 609
======== ======== ========
Volumes and Prices:
Natural gas
Volumes (MMcf)......................................... 486,923 564,740 516,917
======== ======== ========
Average realized prices with hedges ($/Mcf)(2)......... $ 3.61 $ 3.56 $ 2.73
======== ======== ========
Average realized prices without hedges ($/Mcf)(2)...... $ 3.16 $ 4.23 $ 3.97
======== ======== ========
Average transportation costs ($/Mcf)................... $ 0.18 $ 0.12 $ 0.11
======== ======== ========
Oil, condensate and liquids
Volumes (MBbls)........................................ 17,514 14,382 11,626
======== ======== ========
Average realized prices with hedges ($/Bbl)(2)......... $ 21.30 $ 22.24 $ 21.97
======== ======== ========
Average realized prices without hedges ($/Bbl)(2)...... $ 21.39 $ 22.87 $ 28.39
======== ======== ========
Average transportation costs ($/Bbl)................... $ 0.93 $ 0.56 $ 0.15
======== ======== ========
---------------
(1) Includes production costs, depletion, depreciation and amortization, ceiling
test charges, merger-related costs, asset impairments, changes in accounting
estimates, corporate overhead, general and administrative expenses and
severance and other taxes.
(2) Prices are stated before transportation costs.
Year Ended December 31, 2002 Compared to Year Ended December 31, 2001
For the year ended December 31, 2002 operating revenues were $221 million
lower than in 2001. A 14 percent decrease in natural gas volumes and a 25
percent decrease in natural gas prices before hedges and transportation costs
account for $848 million of the decrease in revenues, offset by a $599 million
favorable variance from natural gas hedging activity in 2002 when compared to
2001. The decline in natural gas volumes is primarily attributable to the sale
of properties in Colorado, Utah, and Texas. The decrease in operating revenues
is partially offset by a 22 percent increase in oil, condensate and liquids
volumes, net of a six percent decrease in their prices before hedges and
transportation costs, resulting in a $46 million increase in revenues. In
addition, oil hedging activity had a $7 million favorable variance in 2002 when
compared to 2001. Further decreasing operating revenues was a loss of $13
million in 2002 resulting from a mark-to-market adjustment of derivative
positions that no longer qualify as cash flow hedges. These hedges no longer
qualify for hedge accounting treatment since they were designated as hedges of
anticipated future production from natural gas and oil properties that were sold
in March 2002.
Transportation and net product costs for the year ended December 31, 2002,
were $16 million higher than in 2001 primarily due to a higher percentage of gas
volumes subject to transportation fees, offset by lower costs incurred to meet
minimum payment obligations under pipeline agreements.
51
Operating expenses for the year ended December 31, 2002, were $153 million
higher than in 2001. Contributing to the increase in expenses were non-cash full
cost ceiling test charges totaling $269 million incurred in 2002 for our
Canadian full cost pool and other international properties, primarily in Brazil,
Turkey and Australia, offset by 2001 non-cash full cost ceiling test charges on
international properties totaling $135 million. The unit of production depletion
expense was higher by $93 million with $153 million due to higher depletion
rates in 2002, offset by a $60 million decrease resulting from lower production
volumes in 2002. The higher depletion rate resulted from higher capitalized
costs in the full cost pool and a lower reserve base. Also contributing to the
increase in 2002 expenses were increased oilfield service costs of $9 million
due primarily to higher labor, workovers and production processing fees, asset
impairments of $4 million and higher corporate overhead allocations of $34
million. Partially offsetting the increase in expenses were merger-related costs
of $63 million incurred in 2001 relating to our combined production operations
and $10 million for write-downs of materials and supplies recognized in 2001
resulting from the reduction in inventory values due to the implementation of
consistent operating standards, strategies and plans following the Coastal
merger. For a discussion of these merger-related costs and changes in accounting
estimates, see Item 7, Notes 4 and 6 of this Current Report on Form 8-K. In
addition, the increase in expenses was offset by $49 million of lower severance
and other taxes in 2002. The severance taxes decreased primarily because of
lower natural gas volumes and prices, and for tax credits taken in 2002 for
qualified natural gas wells.
Other income for the year ended December 31, 2002, was $4 million higher
than in 2001 primarily due to higher earnings in 2002 from Pescada, an equity
investment in Brazil.
Year Ended December 31, 2001 Compared to Year Ended December 31, 2000
Operating revenues for the year ended December 31, 2001, were $661 million
higher than in 2000. A nine percent increase in natural gas volumes and a six
percent increase in natural gas prices before hedges and transportation costs,
account for $335 million of the increase in revenues. In addition, natural gas
hedging activity had a $261 million favorable impact in 2001 when compared to
2000. A 19 percent decrease in oil, condensate and liquids prices before hedges
and transportation costs, net of a 24 percent increase in oil, condensate and
liquids volumes, decreased revenues by $1 million. This decrease was offset by a
$66 million favorable impact from oil hedging activities in 2001 versus 2000.
Transportation and net product costs for the year ended December 31, 2001,
were $19 million higher than in 2000 primarily due to a higher percentage of gas
volumes subject to transportation fees and costs incurred to meet minimum
payments on pipeline agreements.
Operating expenses for the year ended December 31, 2001, were $336 million
higher than in 2000. Contributing to the increase were full cost ceiling test
charges of $135 million on international properties, higher depletion expense of
$80 million, with $64 million resulting from increased production and $16
million from higher depletion rates due to higher capitalized costs in the cost
pool. Also contributing to the higher expenses in 2001 were merger-related costs
of $63 million related to our combined production operations and $10 million for
write downs of materials and supplies resulting from the reduction in inventory
values due to the implementation of consistent operating standards, strategies
and plans following the Coastal merger. Also increasing expenses in 2001 were
higher oilfield service costs of $8 million and higher severance and other
production taxes of $40 million, resulting from higher production volumes and
higher natural gas prices.
FIELD SERVICES
Assets in our Field Services segment primarily consist of our investment in
El Paso Energy Partners and gathering and processing facilities in the south
Texas, Louisiana, Mid-Continent and Rocky Mountain regions.
As the general partner of El Paso Energy Partners, we manage the
partnership's day-to-day operations. In addition, we own through various
subsidiaries 26.5 percent of the partnership's common units, all of the Series B
preference units and all of the Series C units acquired for $350 million in
November 2002. We recognize earnings and receive cash from the partnership in
several ways, including through a share of the partnership's cash distributions
and through our ownership of limited, preferred and general partner interests.
We are also reimbursed for costs we incur to provide various operational and
administrative services to the
52
partnership. In addition, we are reimbursed for other costs paid directly by us
on the partnership's behalf. During 2002, we were reimbursed approximately $59
million for expenses incurred on behalf of the partnership. At December 31,
2002, our common units had a market value of $325 million, our preference units
had a liquidation value of $158 million, and our Series C units had a value of
$351 million. During 2002, our earnings and cash from El Paso Energy Partners
were as follows:
EARNINGS CASH
RECOGNIZED RECEIVED
---------- --------
(IN MILLIONS)
General partner's share of distributions.................... $42 $43
Proportionate share of income available to common unit
holders................................................... 10 30
Series B preference units................................... 15 --(1)
Series C units.............................................. 2 --(2)
--- ---
$69 $73
=== ===
---------------
(1) The partnership is not obligated to pay distributions on these units until
2010.
(2) We received our first cash distributions in February 2003 for the Series C
units since we acquired these units in November 2002.
During 2000 through 2002, we entered into several asset sales transactions
with El Paso Energy Partners. Specific procedures have been instituted for
evaluating these transactions to ensure that they are in the best interests of
us and the partnership and are based on fair values. These procedures require
our Board of Directors to evaluate and approve, as appropriate, transactions
with the partnership. In addition, a special committee comprised of the general
partner's independent directors evaluates the transactions on the partnership's
behalf. This typically involves engaging an independent financial advisor to
assist with the evaluation and to opine on its fairness.
In 2000, we sold an intrastate pipeline system in Alabama and storage
facilities in Mississippi for $197 million, which included $170 million of
Series B preference units issued to us in exchange for the storage facilities.
During 2001, we also sold several assets to the partnership, including NGL
transportation and fractionation assets we acquired from PG&E and an investment
in Deepwater Holdings, an entity that owned several pipeline gathering systems
in the Gulf of Mexico. During 2001, the partnership also acquired rights to the
Chaco processing facility from its previous owners, and we leased this facility
under an agreement that expired in December 2002.
In 2002, as part of our plan to strengthen our capital structure and
enhance our liquidity, we entered into additional transactions to sell various
midstream assets to El Paso Energy Partners. In April 2002, we sold gathering
and processing assets, including the intrastate natural gas pipeline system we
acquired in our acquisition of PG&E's midstream operations in December 2000. We
also sold substantially all our natural gas gathering, processing and treating
assets in the San Juan Basin in November 2002. One of the San Juan Basin assets
included in this transaction was our remaining interests in the Chaco cryogenic
natural gas processing plant. As part of this transaction, we have an agreement
that requires us to repurchase the Chaco processing plant from El Paso Energy
Partners for $77 million in October 2021, and at that time, El Paso Energy
Partners has the right to lease the plant from us for a period of ten years with
the option to renew the lease annually thereafter. In addition to $416 million
of cash, we received approximately 11 million Series C units valued at $350
million. The Series C units represent a new class of the partnership's limited
partner interests and have no voting rights. Including the Series C units, our
limited partner ownership interest in El Paso Energy Partners has increased to
approximately 41 percent. For a discussion of our other transactions with El
Paso Energy Partners, see Item 7, Note 26 of this Current Report on Form 8-K.
In 2002, we also identified midstream assets to be sold to third parties as
part of our plan to strengthen our capital structure and enhance our liquidity.
We have also received interest from a number of parties interested in merging
with and/or purchasing all or a portion of our general partner interest in El
Paso Energy Partners. At this time, we cannot predict the outcome of these
discussions.
53
In December 2002, we announced the sale of our gathering systems located in
Wyoming to Western Gas Resources, Inc. This transaction was completed in January
2003. In March 2003, we received approval from our Board of Directors to sell
our assets in the Mid-Continent and north Louisiana regions. Our Mid-Continent
assets primarily include our Greenwood, Hugoton, Keyes and Mocane natural gas
gathering systems, our Sturgis, Mocane and Lakin processing plants and our
processing arrangements at three additional processing plants. Our north
Louisiana assets primarily include our Dubach processing plant and Gulf States
interstate natural gas transmission system. We expect this sale to close before
the end of 2003. After this sale is completed, our remaining assets will consist
primarily of processing facilities in the south Texas, Louisiana and Rocky
Mountain regions. See Item 7, Financial Statements and Supplementary Data, Note
3 of this Current Report on Form 8-K for a discussion of our other asset sales
to third parties during 2002.
As a result of our asset sales and the resulting decline in our gathering
and treating activities, we expect our future EBIT to decrease considerably.
However, we expect the increase in earnings from our interests in El Paso Energy
Partners to partially offset the anticipated decrease in EBIT.
We attempt to balance our earnings from our operating activities through a
combination of fixed-fee based and market-based services. A majority of our
gathering and transportation operations earn margins from fixed-fee-based
services. However, some of our operations earn margins from market-based rates.
Revenues from these market-based rate services are the product of the market
price, usually related to the monthly natural gas price index and the volume
gathered.
Processing and fractionation operations earn a margin based on fixed-fee
contracts, percentage-of-proceeds contracts and make-whole contracts.
Percentage-of-proceeds contracts allow us to retain a percentage of the product
as a fee for processing or fractionation service. Make-whole contracts allow us
to retain the extracted liquid products and return to the producer a Btu
equivalent amount of natural gas. Under our percentage-of-proceeds contracts and
make-whole contracts, we may have more sensitivity to price changes during
periods when natural gas and NGL prices are volatile.
We provide a variety of midstream services, including gathering and
transportation of natural gas, and processing and fractionation of natural gas,
NGL and natural gas derivative products, such as butane, ethane and propane.
Our operating results and an analysis of those results are as follows for
each of the three years ended December 31:
FIELD SERVICES SEGMENT RESULTS 2002 2001 2000
------------------------------ -------- -------- --------
(IN MILLIONS, EXCEPT VOLUMES
AND PRICES)
Gathering, transportation and processing gross margins...... $ 349 $ 561 $ 437
Operating expenses.......................................... (78) (437) (271)
------ ------ ------
Operating income.......................................... 271 124 166
Other income................................................ 16 71 48
------ ------ ------
EBIT...................................................... $ 287 $ 195 $ 214
====== ====== ======
Volumes and prices
Gathering and transportation
Volumes (BBtu/d)....................................... 3,023 6,109 3,868
====== ====== ======
Prices ($/MMBtu)....................................... $ 0.17 $ 0.14 $ 0.16
====== ====== ======
Processing
Volumes (inlet BBtu/d)................................. 3,920 4,360 2,930
====== ====== ======
Prices ($/MMBtu)....................................... $ 0.10 $ 0.15 $ 0.18
====== ====== ======
54
Year Ended December 31, 2002 Compared to Year Ended December 31, 2001
Total gross margins for the year December 31, 2002, were $212 million lower
than in 2001. Margins decreased by approximately $134 million due to our sales
of midstream assets to El Paso Energy Partners in April 2002 and November 2002.
In addition, processing margins decreased $58 million due to lower NGL prices in
2002, which primarily impacted our margins and volumes in the San Juan Basin,
south Louisiana, south Texas and Rocky Mountain regions. Higher processing costs
associated with a new processing arrangement at the Chaco processing facility
entered into in the fourth quarter of 2001 with El Paso Energy Partners and the
sale of the Dragon Trail processing plant in May 2002 also reduced our
processing margins by $18 million and $6 million. This processing agreement with
El Paso Energy Partners was terminated in November 2002 in connection with El
Paso Energy Partners' acquisition of our San Juan Basin assets. Lower natural
gas prices in the San Juan Basin in 2002 also resulted in a $22 million decrease
in our gathering and treating margins. Partially offsetting these decreases were
favorable resolutions of fuel, rate and volume matters of $13 million in the
first quarter of 2002, $8 million of unfavorable resolutions of fuel matters
which occurred in 2001 and $14 million due to higher realized transportation
rates and increased system efficiency related to the pipeline system acquired in
our acquisition of PG&E's midstream operation in December 2000. This pipeline
system was one of the assets sold to El Paso Energy Partners in April 2002.
Operating expenses for the year ended December 31, 2002, were $359 million
lower than in 2001. This decrease was primarily due to the sales of our San Juan
Basin assets, our Natural Buttes and Ouray gathering systems and our Dragon
Trail processing plant, resulting in a net gain of $245 million, lower operating
costs of $48 million and lower depreciation expense of $35 million. Also
contributing to the decrease was $46 million of merger-related costs in 2001,
which included payments to El Paso Energy Partners related to Federal Trade
Commission ordered sales of assets owned by the partnership, and a $9 million
increase in our estimated environmental remediation liabilities in 2001. In
addition, our 2002 cost reduction plan contributed $17 million to our lower
operating costs. Our depreciation expense was also lower by $9 million due to
the assets held for sale classification of the San Juan Basin assets in 2002 and
$9 million associated with lower amortization of goodwill due to the adoption of
SFAS No. 142 in January 2002 (see Item 7, Note 1 of this Current Report on Form
8-K). Partially offsetting these decreases was an impairment charge of our north
Louisiana facilities in the fourth quarter of 2002 of $66 million. We believe
that these facilities are likely to be sold before the end of their estimated
useful lives. For a further discussion of the asset sales and merger-related
costs, see Item 7, Notes 3 and 4 of this Current Report on Form 8-K.
Other income for the year ended December 31, 2002, was $55 million lower
than in 2001. The decrease was due to the losses on the sale in 2002 of our
investment in the Aux Sable NGL plant and our investment in the Blacks Fork
natural gas processing plant of $47 million and $3 million. Also contributing to
the decrease in other income for 2002 was a $13 million gain on the sale of our
investment in Deepwater Holdings in October 2001, a gain of $8 million recorded
in May 2001 from the sale of our 1.01 percent non-managing interest in El Paso
Energy Partners and $6 million of lower equity earnings from Deepwater Holdings
as a result of the sale of our interest to El Paso Energy Partners in October
2001. Offsetting these decreases were higher earnings of $22 million in 2002
from our interests in El Paso Energy Partners.
Year Ended December 31, 2001 Compared to Year Ended December 31, 2000
Total gross margins for the year ended December 31, 2001, was $124 million
higher than in 2000. An increase of $133 million was due to higher gathering and
processing volumes following our acquisition of PG&E's Texas Midstream
operations in December 2000. Higher volumes also increased our margin by $14
million as a result of our acquisition of the Indian Basin processing plant in
the second quarter of 2000 combined with an increase in Indian Basin's treating
capacity by 23 percent in 2001. The increase in margin was partially offset by
higher processing costs of $5 million associated with the new processing
arrangement with El Paso Energy Partners at the Chaco processing facility in the
fourth quarter of 2001. For the year ended December 31, 2001, lower average
gathering, treating and processing rates resulted in a reduction in total
margins of $17 million compared to 2000 due primarily to the different mix of
assets and contract terms resulting from the acquisition of PG&E's Texas
Midstream operations.
55
Operating expenses for the year ended December 31, 2001, were $166 million
higher than in 2000. The increase was due to higher operating, depreciation and
other expenses of $117 million primarily resulting from the acquisition of
PG&E's Texas Midstream operations, as well as merger-related costs and other
charges of $45 million. For a discussion of merger-related costs, see Item 7,
Note 4 of this Current Report on Form 8-K.
Other income for the year ended December 31, 2001, was $23 million higher
than in 2000. The increase was primarily due to increased earnings from El Paso
Energy Partners of $27 million and $13 million from a gain on the sale of our
interest in Deepwater Holdings in October 2001, partially offset by lower 2001
equity earnings from Deepwater Holdings of $3 million as a result of the sale.
The increase was also partially offset by equity investment losses of $7 million
from our Mobile Bay and Aux Sable liquids processing facilities due to lower
natural gas liquids prices and a decrease in equity earnings in other projects
of $8 million.
MERCHANT ENERGY
Our Merchant Energy segment consists of a global power division, an energy
trading division and other merchant operations (which consist primarily of our
LNG activities). In May 2002, we announced plans to limit our energy trading and
mitigate our exposure to working capital demands. Our credit downgrades in the
third and fourth quarter and a further deterioration of the energy trading
environment led to our decision in November 2002 to exit the energy trading
business and pursue an orderly liquidation of our trading portfolio. We
anticipate this liquidation may occur through 2004. Our liquidation strategy is
intended to maximize cash flow from the trading portfolio and reduce our cash
liquidity risk in an uncertain environment. Early in 2003, we also announced our
intent to reduce our involvement in the LNG business.
Below are Merchant Energy's operating results and an analysis of those
results for each of the three years ended December 31:
DIVISION TOTAL
--------------------------------------- MERCHANT
GLOBAL ENERGY ENERGY
MERCHANT ENERGY SEGMENT RESULTS POWER TRADING OTHER ELIMINATIONS SEGMENT
------------------------------- ------ ------- ----- ------------ --------
(IN MILLIONS)
2002
Gross margin.......................... $1,139 $ (862) $141 $(35) $ 383
Operating expenses.................... (716) (678) (33) 35 (1,392)
------ ------- ---- ---- -------
Operating income (loss)............. 423 (1,540) 108 -- (1,009)
Other income (expense)................ (429) 15 2 -- (412)
------ ------- ---- ---- -------
EBIT................................ $ (6) $(1,525) $110 $ -- $(1,421)
====== ======= ==== ==== =======
2001
Gross margin.......................... $ 421 $ 604 $ 87 $ -- $ 1,112
Operating expenses.................... (329) (137) (26) -- (492)
------ ------- ---- ---- -------
Operating income (loss)............. 92 467 61 -- 620
Other income.......................... 369 26 -- -- 395
------ ------- ---- ---- -------
EBIT................................ $ 461 $ 493 $ 61 $ -- $ 1,015
====== ======= ==== ==== =======
2000
Gross margin.......................... $ 367 $ 441 $(53) $ -- $ 755
Operating expenses.................... (271) (64) (1) -- (336)
------ ------- ---- ---- -------
Operating income.................... 96 377 (54) -- 419
Other income.......................... 298 21 11 -- 330
------ ------- ---- ---- -------
EBIT................................ $ 394 $ 398 $(43) $ -- $ 749
====== ======= ==== ==== =======
56
GLOBAL POWER
Our global power division includes the ownership and operation of domestic
and international power generating facilities. In most cases, we partially own
our power generating facilities and account for them using the equity method. We
conduct most of our domestic power business through Chaparral. Internationally,
we have invested in the Brazil power market through our equity investment in
Gemstone. For a further discussion of our Chaparral and Gemstone investments,
see Off-Balance Sheet Arrangements and Contractual Obligations and Item 7, Note
26 of this Current Report on Form 8-K. We also have interests in a number of
other power facilities in Asia, Central America and Europe.
Power Contract Restructuring Activities. Many of our domestic power
plants, and the power plants owned by Chaparral, have long-term power sales
contracts with regulated utilities that were entered into under PURPA. The power
sold to the utility under these PURPA contracts is required to be delivered from
a specified power generation plant at power prices that are usually
significantly higher than the cost of power in the wholesale power market. Our
cost of generating power at these PURPA power plants is typically higher than
the cost we would incur by obtaining the power in the wholesale power market,
principally because the PURPA power plants are less efficient than newer power
generation facilities.
In the past, we have been successful at renegotiating or restructuring
these long-term power contracts. Typically, in a power contract restructuring,
the PURPA power sales contract is amended so that the power sold to the utility
does not have to be provided from the specific power plant. Because we have been
able to buy lower cost power in the wholesale power market, we had the ability
to reduce the cost paid by the utility, thereby inducing the utility to enter
into the power contract restructuring transaction. Following a contract
restructuring, the power plant operates on a merchant basis, which means that it
is no longer dedicated to one buyer and will operate only when power prices are
high enough to make operations economical. In addition, we may assume, and in
the case of Eagle Point Cogeneration we did assume, the business and economic
risks of supplying power to the utility to satisfy the delivery requirements
under the restructured power contract over its term. When we assume this risk,
we manage these obligations by entering into transactions to buy power from
third parties that mitigate our risk over the life of the contract. These
activities are reflected as part of our trading activities and reduce our
exposure to changes in power prices from period to period. Power contract
restructurings generally result in a higher rate of return on our investment in
our power generation business because we can deliver reliable power at lower
prices than our cost to generate power at these PURPA power plants. In addition,
we can use the restructured contracts as collateral to obtain financing at a
cost that is comparable to, or lower than, our existing financing costs.
During the last three years, we have successfully completed the
restructuring of a number of long-term power contracts held by unconsolidated
affiliates or, in some cases, held by us. As a result of our credit downgrades,
our decision to exit the energy trading business, and disruption in the capital
markets, it is unlikely we will pursue additional power contract restructurings
in the near term. For a further discussion of these activities, see Item 7, Note
13 of this Current Report on Form 8-K.
GLOBAL POWER DIVISION RESULTS 2002 2001 2000
----------------------------- ------ ----- -----
(IN MILLIONS)
Gross margin................................................ $1,139 $ 421 $ 367
Operating expenses.......................................... (716) (329) (271)
------ ----- -----
Operating income.......................................... 423 92 96
Other income (expense)...................................... (429) 369 298
------ ----- -----
EBIT................................................... $ (6) $ 461 $ 394
====== ===== =====
Year Ended December 31, 2002 Compared to Year Ended December 31, 2001
Gross margin consists of revenues from our power plants and the net results
from our power restructuring activities. The cost of fuel used in the power
generation process is included in operating expenses. For the year ended
December 31, 2002, gross margin for the global power division was $718 million
higher than in 2001. Gross margin from power contract restructurings comprised
$628 million of the increase. During 2002, we
57
completed power contract restructurings or contract terminations at our Eagle
Point Cogeneration, Mount Carmel and Nejapa power plants. The Eagle Point
restructuring transaction, completed in March 2002, was our most significant
power contract restructuring transaction and contributed $476 million to our net
2002 results.
The Eagle Point restructuring involved several steps and all revenues,
expenses, fees and impairments were reported in our 2002 gross margin. First, we
amended the existing PURPA power sales contract with Public Service Electric and
Gas (PSEG) to eliminate the requirement that power be delivered specifically
from the Eagle Point power plant. This amended contract has fixed prices with
stated increases over the 14-year term that range from $85 per MWh to $126 per
MWh. We entered into the amended power sales contract through a consolidated
subsidiary, UCF. UCF was created to hold and execute the restructured power
sales contract, to enter into a supply contract to meet the requirements of the
restructured agreement and to monetize the net cash flows of these contracts by
issuing debt. In keeping with its purpose, UCF entered into a power supply
agreement with our energy trading division (EPME) who usually participates in
our power restructuring activities by taking on the obligation to supply power.
The terms of the EPME power supply contract were identical to the amended power
sales contract, with the exception of price, which was set at $37 per MWh over
its 14-year term.
For credit enhancement purposes, in anticipation of the financing
transaction associated with the restructuring, UCF terminated the EPME supply
contract in the second quarter of 2002 and replaced it with a supply contract
with a Morgan Stanley affiliate. UCF entered into the Morgan Stanley contract
solely for the purpose of reducing the cost of debt UCF would issue. EPME
continued to supply power for the restructured transaction by entering into a
power supply agreement with the Morgan Stanley affiliate. As a result of the
steps we have taken in this transaction, we have replaced the high-cost of the
power generated from the Eagle Point plant, which had averaged over $75 per MWh,
with power that we purchased in the open market at an average cost of $31 per
MWh. We have also shifted the collection and credit risks to third parties over
the term of the restructured power sales agreement. The estimated improvement in
margins associated with this restructuring is approximately $136 million over
the life of the contracts.
The actions taken to restructure the contract required us to mark the
contract to its fair value. As a result, we recorded non-cash revenue
representing the estimated fair value of the derivative contract of
approximately $978 million. We also amended or terminated other ancillary
agreements associated with the cogeneration facility, such as gas supply and
transportation agreements, a steam contract and existing financing agreements.
We also paid $103 million to the utility to terminate the original PURPA
contract. Also included in our operating results for 2002 were a $98 million
non-cash charge to adjust the Eagle Point Cogeneration plant to fair value based
on its new status as a peaking merchant plant and a non-cash charge of $230
million to write off the book value of the original PURPA contract. The
transaction included closing and other costs of $21 million and the minority
interest owner's share of this transaction of $50 million. Total operating cash
flows from this transaction amounted to approximately $124 million of cash paid
to the utility to amend the original contract and other costs and total
financing cash flows included $829 million of proceeds from the issuance of
7.944% senior notes collateralized solely by the contracts and cash flows of
UCF.
The other two power restructuring transactions during 2002 were the Nejapa
and the Mount Carmel transactions. In 2002, an arbitration award panel approved
the termination of the power purchase agreement between Comision Ejecutiva
Hydroelectrica del Rio Lempa and the Nejapa Power Company, one of our
consolidated subsidiaries, in exchange for a cash payment of $90 million. We
recorded, as gross margin, a $90 million gain and also recorded $13 million in
other expense for the minority owner's share of this gain. We applied the
proceeds of the award to retire a portion of Nejapa's debt. The Mount Carmel
restructuring involved the termination of the existing PURPA power purchase
contract for a fee from the utility of $50 million. In addition, we recorded a
non-cash adjustment to reflect fair value of the Mount Carmel facility of $25
million, resulting in a total net benefit on the restructuring transaction of
$25 million.
Due to increasing market power prices in 2002, the net increase in gross
margin from power contract restructurings of $628 million from our initial power
restructuring transactions was partially offset by a decrease in the fair value
of our restructured power contracts and related power supply contracts of
58
$114 million from the initial gains through December 31, 2002. In addition to
the net increase in gross margin relating to restructuring activities discussed
above, gross margin increases of $147 million were realized from domestic and
international power facilities that were consolidated in the fourth quarter of
2001 and the first quarter of 2002, partially offset by decreased revenues from
the sale of the ManChief facility in 2001 to Chaparral. Also contributing to the
increase were higher management fees in 2002 of $42 million primarily from
Chaparral. Partially offsetting these increases were increased losses in other
investments of $22 million during 2002.
Operating expenses include the cost of fuel used in the power generation
processes, asset impairments and other costs we incur in operating and
maintaining our power plants. Operating expenses for the year ended December 31,
2002, were $387 million higher than in 2001 primarily as a result of asset
impairments that were recorded in 2002. In 2002, we wrote down our capitalized
turbine costs by $162 million as we reduced our capital expenditure plans
related to future power development as a result of our liquidity concerns, and
accordingly our ability and intent to use the turbines in international and
domestic power development projects changed. These reduced capital expenditure
plans also impacted our ability to fund future financial investments, resulting
in a $44 million impairment of goodwill by EnCap and Enerplus, our investment
management subsidiaries. Plant operation and maintenance expenses increased by
$156 million primarily resulting from the consolidation of international and
domestic power-related entities in the fourth quarter of 2001 and the first
quarter of 2002, and the expansion of our South America, Central America and
Mexico operations in 2002.
Other income for the year ended December 31, 2002, was $798 million lower
than in 2001 primarily due to higher write downs on our equity investments over
those that were recorded in 2001. Due to weak economic conditions in Argentina
in 2002, we recorded a $342 million impairment of our CAPSA/CAPEX equity
investment and Costanera cost investment. Also in 2002, we recorded a writedown
of our PPN equity investment in India of $41 million due to PPN's sole customer
failing to pay for power generated by the plant and significant difficulties
encountered with operating the plant, and a $17 million impairment of our
Milford equity investment where construction problems and disputes with our
contractors and lenders have further delayed completion of the plant. In
addition, we recognized a $74 million writedown of our CE Generation equity
investment in December 2002 resulting from the sale of the underlying power
plants, which was completed in the first quarter of 2003. The 2002 write downs
were partially offset by impairments of $74 million on our Fife and East Asia
equity investments in 2001. Contributing to the overall decrease was a decrease
in equity earnings from Chaparral of $136 million, from Enfield due to
unexpected plant shutdowns of $22 million, and from projects consolidated in the
fourth quarter of 2001 and first quarter of 2002 of $52 million. Other income
also decreased by $51 million due to the minority owner's interest in income of
projects consolidated by us in 2002, and a $22 million decrease in operating
lease income as a result of the consolidation of Nejapa in 2002. Other income
also decreased due to $75 million in fees earned for engineering, construction
management and other services for the Macae power project during 2001 that did
not recur in 2002 because the power plant became operational after it was
contributed to Gemstone in late 2001. These decreases were partially offset by
higher equity earnings of $107 million from Gemstone during 2002.
Year Ended December 31, 2001 Compared to Year Ended December 31, 2000
Gross margin for the year ended December 31, 2001, was $54 million higher
than in 2000. This increase was primarily due to an increase of $67 million in
management fees earned from Chaparral during 2001. Also contributing to the
increase were higher margins of $55 million from a Philippine power project that
was consolidated in the first quarter of 2001. Partially offsetting these
increases was a decrease of $61 million in margins associated with our West
Georgia facility, which we sold to Chaparral in the fourth quarter of 2000.
Operating expenses for the year ended December 31, 2001, were $58 million
higher than in 2000. This increase was primarily due to an increase in plant
operation and maintenance expenses of $100 million resulting from the
consolidation of a Philippine power project in 2001 and expansion of our
operations in Mexico and Brazil during 2001. In addition, we recorded $12
million in merger-related costs and other charges in 2001 associated with
combining our operations with Coastal's operations. See Item 7, Notes 4 and 5 of
this
59
Current Report on Form 8-K, for a discussion of these merger-related costs and
asset impairments of our long-lived assets. These increases were partially
offset by lower costs of $33 million at our West Georgia facility, which was
sold in the fourth quarter of 2000.
Other income for the year ended December 31, 2001, was $71 million higher
than in 2000. This increase was primarily due to $75 million of fees earned for
engineering, construction management and other services related to the
development of the Macae power project in Brazil in 2001. Also contributing to
this increase was an increase in equity earnings from Chaparral of $80 million
during 2001 and from other equity investments of $28 million during 2001.
Partially offsetting these increases were an impairment of $74 million of our
Fife and East Asia equity investments in 2001 and gains of $36 million from the
sale of our interests in East Asia and Guatemalan power projects in 2000.
ENERGY TRADING
Our energy trading activities have historically included actively managing
the inherent risk across Merchant Energy's asset portfolios as well as providing
customers with risk management solutions involving natural gas, power, crude
oil, refined products, chemicals and coal. This division also conducted a
substantial energy trading business that executed proprietary trading strategies
and managed the segment's risk across multiple commodities and over seasonally
fluctuating energy demands using consistent methodologies. In November 2002 we
announced that we would exit the energy trading business due to the increasing
and volatile cash demands inherent in that business, which were magnified by our
credit downgrade. We are in the process of liquidating our trading price risk
management portfolio and anticipate that this effort will continue through 2004.
Our liquidation strategy is being executed in a variety of ways including:
- negotiating early settlements pursuant to contractual terms with our
counterparties;
- actively pursuing the sale of transactions or the entire portfolio to
third parties;
- matching and transferring offsetting positions with different
counterparties;
- transferring transactions to other El Paso segments or divisions; and
- liquidating through scheduled settlements.
In late 2002, we began actively liquidating our trading portfolio. As of
December 31, 2002, we had approximately 40,000 transactions to be settled in the
future. Included in our portfolio at that time was approximately 4.4 Bcf/d of
natural gas transportation capacity and natural gas storage rights of
approximately 125 Bcf. As of December 31, 2002, we had contracted to sell 2.1
Bcf/d of that transportation capacity and 70 Bcf of those gas storage rights.
The sale resulted in a loss of approximately $25 million. Additionally, in the
first quarter of 2003, we sold our European natural gas trading portfolio and
completed the liquidations of all of our open trading positions in Europe. We
incurred a loss of approximately $4 million on this sale and liquidation. We are
continuing to work with numerous counterparties to liquidate the remainder of
our portfolio through 2004.
FAIR VALUE OF PRICE RISK MANAGEMENT CONTRACTS AS OF DECEMBER 31, 2002
The following table details the net estimated fair value of our energy
contracts (both trading and non-trading) by year of maturity and valuation
methodology as of December 31, 2002. We classify as trading activities those
price risk management activities that we enter into with the objective of
generating profits or benefiting from exposure to shifts or changes in market
prices. Our trading contracts include those entered into in the trading division
of Merchant Energy as well as contracts related to our petroleum markets
operations
60
which are treated as discontinued operations. We classify all other
derivative-related activities, including those related to power restructuring
activities, as non-trading price risk management activities.
MATURITY MATURITY MATURITY MATURITY MATURITY TOTAL
LESS THAN 1 TO 3 4 TO 5 6 TO 10 BEYOND FAIR
SOURCE OF FAIR VALUE 1 YEAR YEARS YEARS YEARS 10 YEARS VALUE
-------------------- --------- -------- -------- -------- -------- -----
(IN MILLIONS)
Trading contracts(1)
Exchange-traded positions(2)...... $ (16) $(80) $ 3 $ 3 $ -- $(90)
Non-exchange traded
positions(3).................... 42 77 (12) (52) (24) 31
----- ---- ---- ---- ---- ----
Total trading contracts,
net........................ 26 (3) (9) (49) (24) (59)
----- ---- ---- ---- ---- ----
Non-trading contracts(4)
Non-exchange traded
positions(3).................... (148) (35) 122 329 191 459
----- ---- ---- ---- ---- ----
Total energy contracts............ $(122) $(38) $113 $280 $167 $400
===== ==== ==== ==== ==== ====
---------------
(1) Trading contracts include a liability of $14 million associated with
petroleum markets-related price risk management activities included in
liabilities from discontinued operations. These contracts are primarily
exchange-traded positions with a maturity of less than one year.
(2) Exchange-traded positions include positions that are traded on active
exchanges such as the New York Mercantile Exchange, International Petroleum
Exchange and London Clearinghouse.
(3) Non-exchange traded positions include positions based on exchange prices,
third party pricing data and valuation techniques that incorporate specific
contractual terms, statistical and simulation analysis and present value
concepts.
(4) Non-trading energy contracts include derivatives from our power contract
restructuring activities of $968 million and derivatives related to our
natural gas and oil producing activities of $(509) million. Earnings related
to the natural gas and oil producing activities are included in our
Production segment results.
The energy trading industry experienced dramatic changes during 2002,
especially in the fourth quarter. These changes included the credit downgrades
of many of the major industry participants and actions taken by most of the
major industry participants to reduce their trading activities or completely
exit the business. Because of our own actions to limit our trading activities
and exit the trading business, our accessibility to reliable forward market data
for purposes of estimating fair value was significantly limited in late 2002. As
a result, we obtained valuation assistance from a third party valuation
specialist in determining the fair value of our trading and non-trading price
risk management activities as of December 31, 2002. Based upon the specialist's
input, our estimates of fair value are based upon price curves derived from
actual prices observed in the market, pricing information supplied by the
specialist and independent pricing sources and models that rely on this forward
pricing information. These estimates also reflect factors for time value and
volatility underlying the contracts, the potential impact of liquidating our
position in an orderly manner over a reasonable time under present market
conditions, modeling risk, credit risk of our counterparties and operational
risks, as needed. We have discontinued applying our ten-year liquidity valuation
allowance that we had instituted during the first quarter of 2002 in
circumstances where there was uncertainty related to our forward prices in less
liquid markets. To the extent that the forward market data received from the
third party specialist indicates value beyond ten years, we now include that
value in the fair value of our trading and non-trading price risk management
activities.
61
The income impacts of both our trading and non-trading price risk
management activities are included in all divisions of our Merchant Energy
segment and our Production segment. A reconciliation of these trading and
non-trading activities for the years ended December 31, 2002 and 2001, is as
follows:
TOTAL
DISCONTINUED COMMODITY
TRADING NON-TRADING OPERATIONS BASED
------- ----------- ------------ ---------
(IN MILLIONS)
Fair value of contracts outstanding at December
31, 2000...................................... $ 2,200 $ -- $ -- $ 2,200
------- ------- ----- -------
Cumulative effect of accounting change(1)....... -- (1,921) -- (1,921)
Fair value of contract settlements during the
period........................................ (1,973) 744 -- (1,229)
Initial recorded value of new contracts......... 160 -- -- 160
Change in fair value of contracts(2)............ 722 1,636 (42) 2,316
Other(3)........................................ 228 -- -- 228
------- ------- ----- -------
Net change in contracts outstanding during the
period..................................... (863) 459 (42) (446)
------- ------- ----- -------
Fair value of contracts outstanding at December
31, 2001...................................... 1,337 459 (42) 1,754
------- ------- ----- -------
Cumulative effect of accounting change.......... (343) -- -- (343)
Inventory-related reclassifications as a result
of accounting change.......................... (254) -- -- (254)
Fair value of contract settlements during the
period........................................ (347) (274) 162 (459)
Initial recorded value of new contracts(4)...... 84 991 -- 1,075
Change in fair value of contracts(5)............ (532) (717) (103) (1,352)
Other(3)........................................ 10 -- (31) (21)
------- ------- ----- -------
Net change in contracts outstanding during the
period..................................... (1,382) -- 28 (1,354)
------- ------- ----- -------
Fair value of contracts outstanding at December
31, 2002...................................... $ (45) $ 459 $ (14) $ 400
======= ======= ===== =======
---------------
(1) On January 1, 2001, we adopted SFAS No. 133 and recorded a cumulative effect
of accounting change of $1,921 million related to our hedging price risk
management activities.
(2) Our continuing operations include a net loss of $109 million related to
changes in the market values of contracts transferred to our trading
portfolio as a result of a change in the manner in which these contracts
were managed following the Coastal merger.
(3) Includes option premiums and storage capacity transactions.
(4) The initial recorded value of new contracts for trading primarily comes from
completing our Snohvit LNG supply contract in the second quarter of 2002 and
for non-trading primarily comes from our Eagle Point Cogeneration
restructuring transaction completed in the first quarter of 2002. See the
discussion of these transactions under results of operations in our global
power and other merchant operations divisions.
(5) As a result of the discontinuance of our ten-year liquidity valuation
allowance on contracts in our continuing operations, we have reversed $29
million which represents the remaining balance of our initial valuation
allowance of $61 million.
Our trading price risk management assets and liabilities changed
significantly in the fourth quarter of 2002 partly because we adopted EITF Issue
No. 02-3, Issues Related to Accounting for Contracts Involved in Energy Trading
and Risk Management Activities. The adoption of EITF Issue No. 02-3 had the
following impacts on our financial statements:
- We eliminated the mark-to-market value for contracts that do not meet the
definition of a derivative, including transportation, storage and other
contracts, which we reported as a cumulative effect of change in
accounting principle of $225 million;
- We adjusted the carrying value of our natural gas inventory to its
weighted average cost and the value of inventory exchanges to their
expected settlement price assuming they had been accounted for under
62
that basis since their acquisition, which we reported as a cumulative
effect of change in accounting principle of $118 million; and
- We reclassified $254 million of our natural gas inventory and inventory
exchanges from price risk management assets to inventory and accounts
receivable and payable on our balance sheet.
Overall, the adoption of EITF Issue No. 02-3 reduced our net assets from
price risk management activities by approximately $597 million, lowered our
pre-tax net income by $343 million and lowered our net income by $222 million.
Those contracts for which the mark-to-market value was eliminated are now
accounted for under the accrual method of accounting.
The fair value of contract settlements during the period represents the
amounts of traded contracts settled in cash, through physical delivery of a
commodity or by a claim to cash as accounts receivable or payable. The initial
recorded value of new contracts includes the fair value of origination
transactions at the time the transaction is initiated.
The change in fair value of contracts during the year represents the change
in value of contracts from the beginning of the period, or the date of their
origination, until their settlement or, if not settled, until the end of the
period. One of the most significant factors affecting the declines in fair value
of our trading and non-trading price risk management activities was the decrease
in option value, especially in longer-dated and complex transactions. Despite
the commodity price volatility seen in the market over recent months, we are
finding that the remaining market participants are ascribing very little option
value to these types of transactions. Additionally, because of the significant
reductions in the creditworthiness of many of our counterparties, we were
required to adjust our valuation allowances. Because of these and other market
changes, particularly those experienced in the fourth quarter, we recognized a
loss in our energy trading activities due to changes in fair value of $532
million in 2002.
In accordance with generally accepted accounting principles, we have
reflected our trading portfolio at estimated fair value, which is the amount at
which the contracts in our portfolio could be bought or sold in a current
transaction between willing buyers and sellers. However, the value we ultimately
receive in settlement of our trading activities may be less than our estimates.
As disclosed previously, we are actively liquidating our trading portfolio,
which included approximately 40,000 transactions as of December 31, 2002. We
believe the net realizable value of our trading portfolio may be less than their
currently estimated fair value. Our belief is based on recent transactions
completed at values below estimated fair value and bids received on transactions
that were also below their fair value. Additionally, because of the adoption of
EITF Issue No. 02-3, a portion of the transactions that we plan to liquidate are
accounted for under the accrual method and are not recorded on our balance
sheet. We believe that the amount we may ultimately realize from the liquidation
of our total portfolio (including our accrual-based portfolio) could result in
future losses of up to $200 million.
See Item 7, Note 1 of this Current Report on Form 8-K for our revenue
recognition policy related to these activities. The operating results of our
energy trading division are presented below:
ENERGY TRADING DIVISION RESULTS 2002 2001 2000
------------------------------- ------- ----- -----
(IN MILLIONS)
Gross margin................................................ $ (862) $ 604 $ 441
Operating expenses.......................................... (678) (137) (64)
------- ----- -----
Operating income (loss)................................ (1,540) 467 377
Other income................................................ 15 26 21
------- ----- -----
EBIT................................................... $(1,525) $ 493 $ 398
======= ===== =====
Year Ended December 31, 2002 Compared to Year Ended December 31, 2001
Gross margin consists of revenues from commodity trading and origination
activities less the costs of commodities sold, including changes in the fair
value of our energy trading portfolio. For the year ended December 31, 2002,
gross margin was $1.5 billion lower than in 2001. The decrease was due to a
combination of factors related to changes in the energy trading environment.
Approximately $1.3 billion of this decrease
63
relates to a general market decline in energy trading resulting from lower price
volatility in the natural gas and power markets and a generally weaker trading
and credit environment in 2002. Additionally, in the fourth quarter of 2002,
many of the participants in the trading industry, including us, publicly
announced their intent to discontinue or significantly reduce trading
operations, which we believe, along with other factors caused a further
deterioration of the market valuations of trading and marketing assets. The
decrease in fair value of our trading and non-trading price risk management
activities was largely related to reduced option value, with the remainder of
the decrease resulting from the volatility of forward prices and reductions in
creditworthiness of our counterparties. The decline in the energy trading
environment caused us to reduce our trading and origination operations which
resulted in a decrease of $135 million in the gains from transactions we
originated in 2002 compared to 2001 primarily associated with transportation,
storage and gas supply contracts.
Operating expenses for the year ended December 31, 2002, were $541 million
higher than in 2001. This significant increase relates primarily to a charge of
$487 million related to our Western Energy Settlement and a charge of $20
million related to our Commodities Futures Trading Commission (CFTC) settlement.
See Item 7, Note 2 of this Current Report on Form 8-K for a description of our
Western Energy Settlement and Item 7, Note 20 of this Current Report on Form 8-K
for a description of our CFTC settlement. Adding to this increase were
additional costs of $5 million to expand our London operations in early 2002 and
an $18 million increase in staffing and infrastructure costs in 2002. During
2003, we liquidated our European trading assets and will close these offices.
Other income for the year ended December 31, 2002, was $11 million lower
than in 2001 primarily due lower interest rates and lower average outstanding
balances on our interest-bearing margin deposits and notes receivable during
2002.
Year Ended December 31, 2001 Compared to Year Ended December 31, 2000
For the year ended December 31, 2001, gross margin was $163 million higher
than in 2000. The increase was due to higher trading margins in natural gas and
power as a result of increased trading volumes and price volatility, net of the
reserves established as a result of the bankruptcy of Enron Corp. in December
2001.
Operating expenses for the year ended December 31, 2001, were $73 million
higher than in 2000. The increase was partially the result of $27 million of
merger-related asset impairments in 2001. The remaining increase of $46 million
related to increased personnel costs to support increased origination activity
and expansion of our European operations in 2001 compared to 2000.
Other income for the year ended December 31, 2001, was $5 million higher
than in 2000. This increase was primarily due to a $16 million increase in other
income resulting from higher interest rates and higher average outstanding
balances on our interest-bearing margin deposits and notes receivable during
2001. These increases were offset by $11 million of equity earnings in 2000 no
longer being recorded upon termination of the Engage joint venture in October
2000.
Other Merchant Operations
Our other merchant operations consist primarily of our LNG business. In
February 2003, we announced our intent to reduce our involvement in this
business.
OTHER MERCHANT OPERATIONS RESULTS 2002 2001 2000
--------------------------------- ---- ---- ----
(IN MILLIONS)
Gross margin................................................ $141 $ 87 $(53)
Operating expenses.......................................... (33) (26) (1)
---- ---- ----
Operating income (loss)................................ 108 61 (54)
Other income................................................ 2 -- 11
---- ---- ----
EBIT................................................... $110 $ 61 $(43)
==== ==== ====
64
Year Ended December 31, 2002 Compared to Year Ended December 31, 2001
Gross margin consists of revenues from commodity trading activities, less
costs of the commodities sold. For the year ended December 31, 2002, our gross
margin was $54 million higher than in 2001. This increase was primarily due to a
gain of $210 million from the sale of a long-term LNG supply contract and
capacity rights at a regasification terminal to Snohvit during 2002. This
increase was partially offset by a $67 million decline in the fair value of our
LNG supply contract derivatives in 2002 compared to an $86 million increase in
the fair value of these contracts in 2001.
Operating expenses for the year ended in December 31, 2002, were $7 million
higher than in 2001. The increase was primarily due to a $7 million increase in
operating costs associated with the expansion of our LNG operations during early
2002.
Year Ended December 31, 2001 Compared to Year Ended December 31, 2000
For the year ended December 31, 2001, our gross margin was $140 million
higher than in 2000. The increase from year to year was due to an $86 million
increase in the fair value of our LNG supply contract derivatives during 2001
compared to a $53 million decrease in the fair value of these contracts in 2000.
Operating expenses for the year ended in December 31, 2001, were $25
million higher than in 2000. The increase was primarily due to a $26 million
increase in operating expenses associated with our LNG business in 2001.
Other income for the year ended December 31, 2001, was $11 million lower
than in 2000. The decrease was due to a $11 million decrease in equity earnings
primarily from our equity investment in a natural gas liquid processing plant.
The decrease resulted from a decline in the spread between the price of natural
gas liquids and the underlying natural gas feedstocks during 2001.
CORPORATE AND OTHER EXPENSES, NET
Our Corporate and Other operations includes our general and administrative
activities, as well as the operations of our telecommunications and other
miscellaneous businesses. During 2001, there was a significant downturn in the
telecommunications market. As a result, we refocused our telecommunications
strategy and reduced our capital investment in this start-up business. Our
current business strategy involves primarily the development of wholesale
metropolitan transport services, primarily in Texas. At December 31, 2002, our
net investment in the telecommunications business was $388 million, which
includes $163 million of goodwill.
Our telecommunications business consists of Texas-based metro transport
services and collocation and cross-connect services. Our Texas-based metro
transport services business provides bandwidth transport services to wholesale
customers in Austin, San Antonio, Dallas, Ft. Worth and Houston. There are
several new initiatives aimed at expanding our market share within existing
markets. In 2003, we are expanding our business model to include commercial
customers through the launch of our channel partners program, which utilizes
third party entities as outside sales representatives in order to market our
existing products to commercial customers. We will also offer to both wholesale
and commercial customers additional products designed specifically to leverage
our existing asset infrastructure, including gigabit ethernet. We provide a
cost-effective service because of our ability to use parts of the
telecommunications infrastructure of SBC under our interconnection agreement
with them. We are currently involved in proceedings with SBC that could impact
our cost of using their infrastructure, and possibly our ability to use this
infrastructure in the future. For an additional discussion of this proceeding,
see Item 7, Note 20 of this Current Report on Form 8-K under the subheading
Southwestern Bell Proceeding. Because of the continuing decline in the
telecommunications industry, we evaluate the fair value of our Texas-based
assets, including our goodwill of $163 million, each quarter to determine if
they are impaired. As of December 31, 2002, these assets were not impaired. We
did, however, write off $15 million of right-of-way assets, primarily in the
Northeast, due to decisions not to construct along these rights-of-way or expand
the business into these market areas. There are a number of factors that could
impact the valuation of our Texas-based metro transport business in the future,
including a negative outcome of our SBC proceeding, judicial or legislative
changes affecting the current
65
regulatory framework, a decline in our forecasted demand for services in the
areas we serve or a further decline in the telecommunications industry impacting
our ability to expand this business.
In December 2002, we decided to exit our long-haul and metro dark fiber
business because of the minimal contribution of the activities and the high cost
of maintaining it. Under these circumstances, the value of our inventory is
impaired and, accordingly, in the fourth quarter we reduced the carrying value
of our inventory by $153 million to $5 million. This is in addition to a third
quarter reduction of $8 million. The market value was determined by an
independent appraiser who evaluated the dark fiber value based on market
conditions existing in the fourth quarter of 2002 and recent liquidation values
for dark fiber. Our remaining $4 million of value is attributable to our route
from Houston, Texas to Los Angeles, California, which is the center of an
arbitration proceeding between us and Broadwing Communications Services. For a
further discussion of this matter, see Item 7, Note 20 of this Current Report on
Form 8-K.
Our collocation and cross-connect services are available through our
Lakeside Technology Center, a Chicago-based telecommunications facility that
provides space for telecommunications carriers designed for their unique
equipment needs, as well as access to multiple network connections of various
telecommunications carriers. We operate this facility under an operating lease
that has a residual value guarantee of $237 million. In the second quarter of
2002, we reached a final settlement of a lease agreement at the facility with
Exodus Communications, Inc., who has now filed for bankruptcy. Although we
received some consideration, the settlement resulted in the termination of the
lease and the loss of a significant tenant at the facility. The building design,
which is beneficial for the heavy equipment, low staffing needs of a
telecommunications provider, also limits the alternative uses for the facility
putting pressure on the fair value of the building during this significant
downturn in the telecommunications industry. Consequently, we analyzed the fair
value of the building. Our analysis was completed in the third quarter of 2002,
and we estimated that the fair value of the building was $162 million, which is
significantly below the expected residual value originally anticipated and
guaranteed under our lease agreement and results in a contingent loss of $113
million. Consequently, we are amortizing this deficiency over the remaining
lease term. This resulted in a charge of $11 million in 2002, and will result in
a charge of $8 million for each remaining quarter through May 2006. Upon the
adoption of the new accounting pronouncement, Financial Accounting Standards
Board Interpretation (FIN) No. 46, in July 2003, we anticipate that we will
consolidate the lessor of this facility which will likely require an adjustment
to the fair value of the facility (see New Accounting Pronouncements Issued But
Not Yet Adopted beginning on page 75).
Year Ended December 31, 2002 Compared to Year Ended December 31, 2001
Corporate and other net expenses for the year ended December 31, 2002, were
$1,202 million lower than in 2001. The decrease was primarily a result of $1,175
million in merger-related charges and asset impairments incurred in 2001, in
connection with our merger with Coastal and additional costs of $144 million
incurred in 2001 related to increased estimates of environmental remediation
costs, legal obligations and reductions in the fair value of spare parts
inventories to reflect changes in usability of spare parts inventories in our
corporate operations based on an ongoing evaluation of our operating standards
and plans following the Coastal merger. For a discussion of these costs, see
Item 7, Notes 4 and 6 of this Current Report on Form 8-K. Also contributing to
the decrease was a reduction in telecommunication expenses of $25 million in
2002 due to our 2001 telecommunication organizational restructuring and losses
of $34 million in 2001 on our retail gas stations, substantially all of which
were sold in 2001. In addition, in 2002, we recorded a $21 million gain on the
early extinguishment of debt. Partially offsetting the decrease for the year
ended December 31, 2002, were charges of $50 million for severance payments
related to our second quarter 2002 employee restructuring, costs associated with
the elimination of rating and stock-price triggers in the second quarter of 2002
in our Gemstone and Chaparral investments and a $21 million decrease in pre-tax
pension income as a result of a reduced expected rate of return on our pension
plan assets. In addition, in our telecommunication operations, in 2002, we
recorded a $153 million valuation adjustment of our dark fiber inventory, a $15
million impairment of our right-of-way assets and a $11 million contingent loss
on the Lakeside Technology Center facility, as discussed above.
66
Year Ended December 31, 2001 Compared to Year Ended December 31, 2000
Corporate and other expenses for the year ended December 31, 2001, were
$1,365 million higher than in 2000. The increase was primarily a result of
additional $1,082 million incurred in 2001 compared to 2000 of merger-related
costs and asset impairments incurred in 2001 in connection with our mergers with
Coastal and Sonat and additional costs of $144 million incurred in 2001 related
to increased estimates of environmental remediation costs, legal obligations and
usability of spare parts inventories and $39 million in lower margins due to the
sale of substantially all of our retail gas stations in 2001. Also contributing
to our higher costs were operating losses associated with our telecommunications
business during 2001 which were approximately $40 million.
INTEREST AND DEBT EXPENSE
Over the past three years, our interest and debt expense has increased as a
result of debt issued to finance the growth of our business segments. During
this period, our average debt balances have increased from approximately $10.8
billion in 2000 to $16 billion as of December 31, 2002. During this growth
period, we have raised funds in both domestic and international capital markets,
the majority of which was fixed rate debt. In the future, our ability to access
the capital markets and issue debt securities will be a function of market
conditions at that time and our credit ratings. Based on rating actions during
the latter part of 2002 and early 2003, we anticipate that the cost of future
debt issuances will be higher for us. Furthermore, since some of our debt
offerings have been in foreign markets, currency fluctuations can impact that
cost of our debt. For example, in 2002, as a result of a weaker U.S. dollar, we
incurred incremental interest costs of approximately $95 million on our Euro
denominated debt.
Year Ended December 31, 2002 Compared to Year Ended December 31, 2001
Interest and debt expense for the year ended December 31, 2002, was $259
million higher than in 2001. Below is an analysis of our interest expense during
the year ended December 31 (in millions):
2002 2001 2000
------ ------ ------
Long term debt, including current maturities............... $1,248 $ 949 $ 858
Commercial paper........................................... 42 98 89
Other interest............................................. 130 145 129
Less: Capitalized interest................................. (32) (63) (75)
------ ------ ------
Total interest expense.............................. $1,388 $1,129 $1,001
====== ====== ======
Interest expense on long-term debt for the year ended December 31, 2002,
was $299 million higher than in 2001. The increase was due to a higher average
debt balance. During 2002, we issued long-term debt of approximately $4.4
billion that had an average interest rate of 7.9%. These issuances increased
interest on long-term debt by approximately $233 million. During the same year,
we retired approximately $1.5 billion of long-term debt that had an average
interest rate of 5.19%, resulting in a decrease to interest expense from these
retirements of approximately $35 million. In addition, we incurred $95 million
of interest expense in 2002 related to foreign currency losses on
Euro-denominated debt that was unhedged in 2002. The remaining increase was
primarily due to various debt issuances during 2001 that were outstanding for
the entire year in 2002.
Interest expense on commercial paper for the year ended December 31, 2002,
was $56 million lower than in 2001. The decrease was due to lower average
short-term interest rates on commercial paper activities and lower average
short-term borrowings in 2002. The average short-term interest rate, which is
based on daily ending rates, was 2.7% in 2002 versus 4.6% in 2001, and the
average commercial paper and other short-term debt balances, which were based on
daily ending balances, were approximately $963 million in 2002 versus $1.45
billion in 2001.
67
Other interest for the year ended December 31, 2002, was $15 million lower
than in 2001. The decrease was primarily due to an $8 million decrease in
interest resulting from retirement of our other financing obligations, an $8
million decrease in interest of receivable factoring, and an $8 million decrease
in interest due to termination of a marketing sales contract during 2002. These
decreases were partially offset by a $9 million increase in interest from the
debt securities issued to Gemstone in November 2001.
Capitalized interest for the year ended December 31, 2002, was $31 million
lower than in 2001 primarily due to the lower interest rates in 2002 than in
2001.
We expect to incur higher interest and debt expense on debt issuances in
2003 due to our credit downgrades below investment grade status.
Year Ended December 31, 2001 Compared to Year Ended December 31, 2000
Interest and debt expense for the year ended December 31, 2001, was $128
million higher than in 2000.
Interest expense on long-term debt for the year ended December 31, 2001,
was $91 million higher than in 2000. The increase was due to a higher average
debt balance. During 2001, we issued long-term debt of approximately $4.1
billion that had an average interest rate of 6.1%. These issuances increased
interest on long-term debt by approximately $125 million. During the same year,
we retired approximately $1.6 billion of long-term debt that had an average
interest rate of 6.8%, resulting in a decrease to interest expense from these
retirements of approximately $68 million. The remaining increase was primarily
due to fourth quarter 2000 debt issuances that were outstanding for the entire
year in 2001.
Interest expense on commercial paper for the year ended December 31, 2001,
was $9 million higher than in 2000. The increase was due to the higher average
commercial paper balances. Average commercial paper and other short-term debt
balances, which were based on daily ending balances, were approximately $1.45
billion in 2001. This increase was offset by lower average rates on commercial
paper and other short-term borrowings during the year. The average interest
rate, which is based on daily ending rates, was 4.6% in 2001.
Other interest for the year ended December 31, 2001, was $16 million higher
than in 2000 primarily due to the interest expense associated with a swap
agreement.
Capitalized interest for the year ended December 31, 2001, was $12 million
lower than in 2000 due to the completion of the West Georgia facility during the
middle of 2000.
MINORITY INTEREST IN CONSOLIDATED SUBSIDIARIES
Expense associated with minority interests of consolidated subsidiaries for
the year ended December 31, 2002, was $56 million higher than in 2001. This
increase was primarily due to 2002 income of the minority owners of Eagle Point
Cogeneration, Utility Contract Funding, CDECCA and Mohawk River Funding IV as a
result of our consolidation of these companies during 2002. These consolidations
contributed $38 million of the 2002 increase. An additional $13 million of the
increase related to the minority owner's share of the gain from the termination
of the Nejapa power purchase agreement.
RETURNS ON PREFERRED INTERESTS OF CONSOLIDATED SUBSIDIARIES
Year Ended December 31, 2002 Compared to Year Ended December 31, 2001
Returns on preferred interests of consolidated subsidiaries for the year
ended December 31, 2002, were $58 million lower than in 2001, primarily due to
the redemptions of the preferred interests related to El Paso Oil & Gas
Resources, El Paso Oil & Gas Associates, Coastal Limited Ventures and Capital
Trust IV and the partial redemption of Clydesdale. The decrease was also due to
lower interest rates in 2002. Most of the preferred returns are based on
variable short-term rates, which were lower on average in 2002 than the same
periods in 2001. Partially offsetting these decreases were higher returns on
preferred interests issued as part of our Gemstone investment completed in
November 2001.
68
Year Ended December 31, 2001 Compared to Year Ended December 31, 2000
Returns on preferred interests of consolidated subsidiaries for the year
ended December 31, 2001, were $13 million higher than in 2000. Higher balances
in minority interests as a result of the issuance of additional preferred
interests in Clydesdale and Topaz (part of our Gemstone transaction) in 2001 and
a full year of costs on Clydesdale and Capital Trust IV, were significantly
offset by lower interest rates. Clydesdale and Capital Trust IV were formed in
May 2000.
For a further discussion of our borrowings and other financing activities
related to our consolidated subsidiaries, see Item 7, Note 19 of this Current
Report on Form 8-K.
INCOME TAX EXPENSE
Income tax benefit for the year ended December 31, 2002, was $507 million
resulting in an effective tax rate of 33 percent. For the year ended December
31, 2001, income tax expense was $242 million, resulting in an effective tax
rate of 61 percent. Of this amount, $115 million related to non-deductible
merger charges and changes in our estimate of additional tax liabilities. The
majority of these estimated additional liabilities were paid in 2001 and are
being contested by us. The effective tax rate excluding these charges was 32
percent in 2001. For the year ended December 31, 2000, income tax expense was
$514 million, resulting in an effective tax rate of 32 percent. Differences in
our effective tax rates from the statutory tax rate of 35 percent in all years
were primarily a result of the following factors:
- state income taxes;
- earnings from unconsolidated affiliates where we anticipate receiving
dividends;
- non-deductible portion of merger-related costs and other tax adjustments
to provide for revised estimated liabilities;
- foreign income taxed at different rates;
- utilization of deferred credits on loss carryovers;
- non-deductible dividends on the preferred stock of a subsidiary;
- non-conventional fuel tax credits; and
- depreciation, depletion and amortization.
DISCONTINUED OPERATIONS
Our discontinued operations consist of our petroleum markets and our coal
businesses. For each of the three years ended December 31, 2002, the after-tax
income (loss) related to these operations was as follows (in millions):
YEAR ENDED DECEMBER 31,
-------------------------
2002 2001 2000
------- ------ ------
Petroleum markets........................................... $(241) $(80) $124
Coal........................................................ (124) (5) (1)
----- ---- ----
Total discontinued operations............................. $(365) $(85) $123
===== ==== ====
Petroleum Markets. In our petroleum businesses, we own or have interests
in oil refineries, chemical production facilities, petroleum terminalling and
marketing operations, and blending and packaging operations for lubricants and
automotive products. Our refinery operations are cyclical in nature and
sensitive to movements in the price of crude oil. During the last two years, we
have operated in an environment where the differences in the price of our crude
oil input and the price we can realize for the resulting products output has
been so narrow that we have experienced losses in our refinery operations. While
the condition has improved during the first quarter of 2003, our results in the
future may continue to be volatile. Also contributing to losses in 2002 and 2001
were operational difficulties following a fire at our Aruba facility in April
2001.
69
For the year ended December 31, 2002, the after-tax loss in our petroleum
markets operations was $161 million higher than 2001. This increased loss was a
result of lower refining margins (which is revenues less costs of raw materials
and direct refining costs) of $84 million from lower throughput at our Aruba
refinery. Also contributing to the increased loss were $57 million of insurance
claims and recoveries in 2001 related to our refinery losses associated with a
fire at our Aruba facility in April 2001, a decrease of $143 million in marine
revenues resulting from lower marine freight rates and number of operating
vessels and a decrease of $86 million associated with the lease of our Corpus
Christi refinery and related assets to Valero in June 2001. These decreases were
partially offset by increased refining margins of $74 million at our Eagle Point
refinery. Operating expenses for the year ended in December 31, 2002, were $156
million lower than in 2001. The decrease was primarily due to $244 million of
merger-related costs, asset impairments and other charges in 2001 primarily
associated with combining our operations with Coastal's operations. See Item 7,
Notes 4 and 5 of this Current Report on Form 8-K for a discussion of our
merger-related costs and asset impairments. This decrease was partially offset
by a $91 million impairment of our MTBE chemical processing plant in 2002. Other
income for the year ended December 31, 2002, was $1 million lower than in 2001
primarily due to an $11 million decrease in interest income during 2002 due to
lower average cash balances held by us. The decrease was partially offset by $46
million of insurance claims and recoveries from our insurers recorded in 2002
compared to $40 million, net of writeoffs of damaged properties in 2001,
primarily associated with the assets destroyed in a fire at our Aruba facility
in April 2001. Income taxes in 2002 were $70 million higher than 2001 due to
higher realized losses in 2001 versus 2002. The effective tax rate was (5)
percent in 2002 compared to 42 percent in 2001 primarily due to changes in state
income taxes and foreign income taxed at different rates.
For the year ended December 31, 2001, the after-tax loss in our petroleum
markets operations was $80 million compared to the after-tax income in 2000 of
$124 million. This decline in 2001 was a result of lower margins of $105 million
in crude based refined products and lower margins and throughput at the Eagle
Point refinery as a result of decreased demand for jet fuel following the events
of September 11, 2001. Also contributing to the decline was a $48 million
decrease in margins in 2001 associated with the lease of our Corpus Christi
refinery and related assets to Valero in June 2001. Partially offsetting these
decreases were $57 million of insurance claims and recoveries from our insurers
on losses incurred related primarily to a fire at our Aruba facility in April
2001. This fire was the primary reason for a 25 percent decrease in output
between 2000 and 2001 at that facility resulting in a $53 million reduction,
year over year, in refining margins. Also partially offsetting these decreases
was $22 million of margins earned on Coastal Liquid Partners, which was
consolidated during early 2001. Operating expenses for the year ended December
31, 2001, were $234 million higher in 2001 versus 2000. The increase was
primarily due to $244 million of merger-related costs, asset impairments and
other charges in 2001. See Item 7, Notes 4 and 5 of this Current Report on Form
8-K for a discussion of our merger-related costs and asset impairments of our
long-lived assets. Also contributing to this increase in operating expenses were
higher fuel costs of $29 million at our refineries due to higher natural gas
prices. These increases were partially offset by lower operating expenses of $64
million resulting from the lease of our Corpus Christi refinery and related
assets to Valero in June 2001. Other income for the year ended December 31,
2001, was $97 million higher than in 2000. The increase was primarily the result
of $77 million of insurance claims and recoveries, net of writeoffs of damaged
properties of $37 million, from our insurers associated primarily with the
assets destroyed in the Aruba fire. Income taxes in 2001 were $83 million lower
than 2000 due to pre-tax losses incurred during 2001. The effective tax rate was
42 percent in 2001 compared to 17 percent in 2000 primarily due to changes in
state income taxes and foreign income taxed at different rates.
Coal. For the year ended December 31, 2002, the after-tax loss in our coal
mining operations was $119 million lower than 2001. The decrease was primarily
the result of after-tax impairment charges totaling $116 million incurred during
2002 because the carrying value of the underlying assets was higher than the
estimated net sales proceeds of our coal operations.
70
CRITICAL ACCOUNTING POLICIES
The selection and application of accounting policies is an important
process that has developed as our business activities have evolved and as the
accounting rules have developed. Accounting rules generally do not involve a
selection among alternatives, but involve an implementation and interpretation
of existing rules and the use of judgment to the specific set of circumstances
existing in our business. We make every effort to properly comply with all
applicable rules on or before their adoption, and we believe the proper
implementation and consistent application of the accounting rules is critical.
However, not all situations are specifically addressed in the accounting
literature. In these cases, we must use our best judgment to adopt a policy for
accounting for these situations. We accomplish this by analogizing to similar
situations and the accounting guidance governing them, and often consult with
our independent accountants about the appropriate interpretation and application
of these policies. The preparation of our financial statements requires the
selection and application of a number of accounting policies. For a discussion
of our significant accounting policies, see Item 7, Note 1 of this Current
Report on Form 8-K. We have defined our critical accounting policies as those
significant accounting policies that involve critical accounting estimates in
the preparation of our financial statements.
We consider a critical accounting estimate to be an accounting estimate
recognized in the financial statements that requires us to make assumptions
about matters that may be highly uncertain at the time the estimate is made. We
believe that an accounting estimate is only considered a critical accounting
estimate if changes in those estimates are reasonably likely to occur or if we
reasonably could have selected a different estimate, and either of these
differences would have resulted in a material impact on our financial condition
or results of operations.
Estimates and assumptions about future events and their effects cannot be
determined with certainty. We base our estimates on historical experience and on
various other assumptions that are believed to be reasonable under the
circumstances. These estimates may change as new events occur and as additional
information is obtained. In addition, management is periodically faced with
uncertainties, the outcomes of which are not within our control and will not be
known for prolonged periods of time. We have discussed the development and
selection of the critical accounting policies and related disclosures with the
audit committee of the Board of Directors.
Our critical accounting policies include policies that are related to
specific business units, such as price risk management activities and accounting
for natural gas and oil producing activities, as well as broad policies that
include accounting for environmental reserves and pension and other post
retirement benefits. Each of these areas involves complex situations and a high
degree of judgment in both the application and interpretation of existing
literature and in the development of estimates that impact our financial
statements. These critical accounting policies have been identified for the
current year, and there may be additional critical accounting policies as and
when new accounting pronouncements are adopted. New accounting pronouncements
are discussed in the section below entitled New Accounting Pronouncements Issued
But Not Yet Adopted.
Price Risk Management Activities. We account for our price risk management
activities in accordance with the requirements of SFAS No. 133, which requires
that we determine the fair value of the derivative instruments we use and
reflect them in our balance sheet at their fair values. Changes in the fair
value from period to period of all derivative instruments, except cash flow
hedges, are recorded in our income statement. Changes in the fair value of
derivative instruments used to hedge our cash flows are generally recognized in
our income statement when the hedge is settled. Over time, these methods will
derive similar results. However, from period to period, income under these
methods can differ significantly.
Some of our derivative instruments are traded on active exchanges such as
the New York Mercantile Exchange, while others are valued using exchange prices,
third party pricing data and valuation techniques that incorporate specific
contractual terms, statistical and simulation analysis and present value
concepts. One of the primary factors that can have an impact on our results each
period is the price assumptions used to value our derivative instruments.
Because of our actions to limit our trading activities and exit the trading
business, our accessibility to reliable forward market pricing data for purposes
of estimating fair value was
71
significantly limited in late 2002. As a result, we obtained valuation
assistance from a third party valuation specialist in determining the fair value
of our trading and non-trading price risk management activities as of December
31, 2002. Based upon the specialist's input, our estimates of fair value are
based upon price curves derived from actual prices observed in the market,
pricing information supplied by the specialist and independent pricing sources
and models that rely on this forward pricing information. These estimates also
reflect factors for time value and volatility underlying the contracts, the
potential impact of liquidating our position in an orderly manner over a
reasonable time under present market conditions, modeling risk, credit risk of
our counterparties and operational risks, as needed. We have discontinued
applying our ten-year liquidity valuation allowance that we had instituted
during the first quarter of 2002 in circumstances where there was uncertainty
related to our forward prices in less liquid markets. To the extent that the
forward market data received from the third party specialist indicates value
beyond ten years, we now include that value in the fair value of our trading and
non-trading price risk management activities.
The amounts we report in our financial statements change as these estimates
are revised to reflect actual results, changes in market conditions or other
factors, many of which are beyond our control.
Another factor that can impact our results each period is our ability to
estimate the level of correlation between future changes in the fair value of
the hedge instrument and the transaction being hedged, both at the time we enter
into the transaction and on an ongoing basis. By hedging risk, the derivative
instrument's value is intended to offset value changes in the item being hedged.
However, this is complicated in hedging energy commodities, because energy
commodity prices have qualitative and locational differences that can be
difficult to hedge effectively. Our estimates of fair value and our assessment
of correlation of our hedging derivatives are impacted by actual results and
changes in market conditions.
We evaluate the risk in our trading and non-trading price risk management
activities using a Value-at-Risk model to determine the maximum expected one-day
unfavorable impact on our financial performance due to normal market movement.
For a discussion of our methodology in calculating Value-at-Risk, see
Quantitative and Qualitative Disclosures About Market Risk beginning on page 84.
We believe that using this Value-at-Risk methodology captures many of the
uncertainties associated with the estimates in our trading and non-trading
activities.
We have reflected our trading portfolio at estimated fair value which is
the amount at which the contracts in our portfolio could be bought or sold in a
current transaction between willing buyers and sellers. However, the value we
ultimately receive in settlement of our trading activities may be less than our
fair value estimates. As disclosed previously, we are actively liquidating our
trading portfolio, which include approximately 40,000 transactions as of
December 31, 2002. We believe the net realizable value of our trading portfolio
may be less than their currently estimated fair value. Our belief is based on
recent transactions completed at values below estimated fair value and bids
received on transactions that were also below their fair value. Additionally,
because of the adoption of EITF Issue No. 02-3, a portion of the transactions
that we plan to liquidate are accounted for under the accrual method and are not
recorded on our balance sheet. Should we have to pay counterparties to assume
these transactions, future losses will result. We believe that the amount we may
ultimately realize from the liquidation of our total portfolio (including our
accrual-based portfolio) could result in future losses up to $200 million.
Asset Impairments. The asset impairment accounting rules require us to
determine if an event has occurred indicating that a long-lived asset may be
impaired. In some cases, these events are clear. In most cases, however, a
clearly identifiable triggering event does not occur. Rather, a series of
individually insignificant events occur over time leading to an indication that
an asset may be impaired. This can be further complicated where we have
investments in foreign countries or where we have projects where we are not the
operator. We continually monitor our businesses and the market and business
environments in which we operate and make judgments and assessments about
whether a triggering event has occurred. If an event occurs, we make an estimate
of our future cash flows from these assets to determine if the asset is
impaired. For investments, we evaluate whether events and possible outcomes
indicate that a decline in the value of our investment has occurred that is
other than temporary. The impairment analysis generally involves an assessment
of project level cash flows that requires us to make projections and assumptions
for many years
72
into the future for pricing, demand, competition, operating costs, legal and
regulatory issues and other factors and these variables can, and often do,
differ from our estimates. These changes can have either a positive or negative
impact on our estimates of impairment. In addition, further changes in the
economic and business environment can impact our original and ongoing
assessments of potential impairment.
Accounting for Environmental Reserves. We accrue for environmental
reserves when our assessments indicate that it is probable that a liability has
been incurred or an asset will not be recovered, and an amount can be reasonably
estimated. Estimates of our liabilities are based on 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 onsite, offsite and groundwater
technical studies, and legal costs. These amounts also consider prior experience
in remediating contaminated sites, other companies' clean-up experience and data
released by the Environmental Protection Agency or other organizations. These
estimates are subject to revision in future periods based on actual costs or new
or changing circumstances and are included in our balance sheet in other current
and long-term liabilities at their undiscounted amounts. Actual results may
differ from our estimates, and our estimates can be, and often are, revised in
the future, either negatively or positively, depending upon actual outcomes or
changes in expectations based on the facts surrounding each exposure.
As of December 2002, we had accrued approximately $482 million for
environmental matters, including approximately $463 million for expected
remediation costs at current and former operating sites and associated onsite,
offsite and groundwater technical studies, and approximately $19 million for
related environmental legal costs, which we anticipate incurring through 2027.
Approximately $109 million of the accrual was related to discontinued petroleum
markets and coal mining operations. The high end of our reserve estimates was
approximately $620 million and the low end was approximately $427 million, and
our accrual at December 31, 2002 was based on the estimated most likely
reasonable amount of liability. By type of site, our reserves are based on the
following estimates of reasonably possible outcomes:
DECEMBER 31,
2002
-------------
SITES LOW HIGH
----- ----- -----
(IN MILLIONS)
Operating................................................... $208 $287
Non-operating............................................... 193 286
Superfund................................................... 26 47
Accounting for Natural Gas and Oil Producing Activities. We use the full
cost method to account for our natural gas and oil producing activities. Under
this accounting method, we capitalize substantially all of the costs incurred in
connection with the exploration, acquisition and development of natural gas and
oil reserves in full cost pools maintained by geographic areas, regardless of
whether reserves are actually located. This method differs from the successful
efforts method of accounting for these activities. The primary differences
between these two methods are the treatment of exploratory dry hole costs and
geological and geophysical costs and the recognition of gains or losses when
properties are sold. Exploratory dry hole costs include exploration, acquisition
and development costs on wells that do not yield measurable reserves. Under the
successful efforts method, these costs are generally expensed when the
determination is made that measurable reserves do not exist. Geological and
geophysical costs are also expensed under the successful efforts. Under the full
cost method, both dry hole costs and geological costs are capitalized into the
full cost pool. As a result, our financial statements will differ from companies
that apply the successful efforts method since we could potentially reflect a
higher level of capitalized costs as well as a higher depletion rate.
Under the full cost accounting method, we are required to conduct quarterly
impairment tests of our capitalized costs in each of our full cost pools. This
impairment test is referred to as a ceiling test. Our total capitalized costs,
net of related income tax effects, are limited to a ceiling based on the present
value of future net revenues using end of period spot prices, discounted at 10
percent, plus the lower of cost or fair market value of unproved properties, net
of related income tax effects. If these discounted revenues are not equal to or
greater than total capitalized costs, we are required to write-down our
capitalized costs to this level. The
73
primary factors that could result in a ceiling test write-down include lower
prices, higher capitalized costs in the full cost pool, a lower reserve base,
and the impact of our hedging program.
The ceiling test calculation assumes that the price in effect on the last
day of the quarter is held constant over the life of the reserves. As a result
of this pricing assumption, the resulting value is not indicative of the true
fair value of the reserves. The prices of natural gas and oil are volatile and
change from period to period. We attempt to realize more determinable cash flows
through the use of hedges, but a decline in commodity prices can impact the
results of our ceiling test. Ceiling test charges due to fluctuating prices, as
opposed to reductions to the underlying reserve quantities, should not be
considered an absolute indicator of the value of the related reserves.
The process of estimating natural gas and oil reserves is very complex,
requiring significant decisions in the evaluation of all available geological,
geophysical, engineering and economic data. The data for a given field may also
change substantially over time as a result of numerous factors, including
additional development activity, evolving production history and a continual
reassessment of the viability of production under changing economic conditions.
As a result, material revisions to existing reserve estimates occur from time to
time. Although every reasonable effort is made to ensure that reserve estimates
reported represent the most accurate assessments possible, the subjective
decisions and variances in available data for various fields increases the
likelihood of significant changes in these estimates. Our reserve estimates
impact several financial calculations. If all other factors are held constant,
an increase in estimated proved reserves decreases our unit of production
depletion rate. Higher reserves can also reduce the likelihood of ceiling test
impairments. Estimated reserves are used to calculate projected future cash
flows from our natural gas and oil properties, which can often be used as
collateral to secure financing for our operations. For further discussion of our
reserves, see the discussion of Business and Properties in this Current Report
on Form 8-K, under our Production segment and Item 7, Note 28 of this Current
Report on Form 8-K.
Accounting for Pension and Other Postretirement Benefits
Our accruals related to our pension and other postretirement benefits are
based on actuarial calculations. In performing these calculations, our actuaries
must use assumptions, including those related to the return that we expect to
earn on our plan assets, discount rates used in calculating benefit obligations,
the rate at which we expect the compensation of our employees will increase over
the plan term, the cost of health care when benefits are provided under our
plans and other factors.
Actual results may differ from the assumptions included in these actuarial
calculations, and as a result our estimates associated with our pension and
other postretirement benefits can be, and often are, revised in the future, with
either a negative or positive effect on the costs we recognize and the accruals
we make. The following table shows the impact of a one percent change in our
primary assumptions used in our actuarial calculations associated with our
pension and other postretirement benefits for the year ended December 31, 2002
(in millions):
PENSION BENEFITS POSTRETIREMENT BENEFITS
----------------------------- -------------------------------------
PROJECTED ACCUMULATED
NET BENEFIT BENEFIT NET BENEFIT POSTRETIREMENT
EXPENSE (INCOME) OBLIGATION EXPENSE (INCOME) BENEFIT OBLIGATION
---------------- ---------- ---------------- ------------------
One percent increase in:
Discount rates............... $ 1 $(186) $-- $(40)
Expected return on plan
assets.................... (30) -- (1) --
Rate of compensation
increase.................. 2 5 -- --
Health care cost trends...... -- -- 1 20
One percent decrease in:
Discount rates............... $ (2) $ 222 $-- $ 42
Expected return on plan
assets.................... 30 -- 1 --
Rate of compensation
increase.................. (1) (5) -- --
Health care cost trends...... -- -- (1) (19)
74
Our estimates for our net benefit expense (income) are partially based on
the expected return on pension plan assets. We use a market-related value of
plan assets to determine the expected return on pension plan assets. In
determining the market-related value of plan assets, differences between
expected and actual asset returns are deferred and recognized over three years.
Due to recent losses in our pension plan assets, the fair value of plan assets
used to determine the 2002 net benefit expense (income) was less than the
market-related value of plan assets. If we used the fair value of our plan
assets instead of the market-related value of plan assets in determining the
expected return on pension plan assets, our net benefit income would have been
$51 million lower for the year ended December 31, 2002.
We have not recorded an additional pension liability for our primary
pension plan because the fair value of plan assets exceeded the accumulated
benefit obligation in that plan as of September 30, 2002, by approximately $130
million. Plan assets exceeded accumulated benefit obligations as of December 31,
2002, by a similar margin. If the accumulated benefit obligation exceeded plan
assets under this primary pension plan as of September 30, 2002, we would have
recorded a pre-tax additional pension liability of approximately $900 million
plus an amount equal to the excess of the accumulated benefit obligation over
plan assets of the primary pension plan. We would have also recorded an amount
equal to this additional pension liability to accumulated other comprehensive
loss, net of taxes, in our balance sheet.
For further details on these and our other significant accounting policies,
and the estimates, assumptions and judgments we use in applying these policies,
see Item 7, Note 1 of this Current Report on Form 8-K.
NEW ACCOUNTING PRONOUNCEMENTS ISSUED BUT NOT YET ADOPTED
As of December 31, 2002, there were a number of accounting standards and
interpretations that had been issued, but not yet adopted by us. Below is a
discussion of the more significant standards that could impact us.
Accounting for Asset Retirement Obligations
In June 2001, the Financial Accounting Standards Board (FASB) issued SFAS
No. 143, Accounting for Asset Retirement Obligations. This statement requires
companies to record a liability for the estimated retirement and removal costs
of long-lived assets used in their business. The liability is recorded at its
fair value, with a corresponding asset which is depreciated over the remaining
useful life of the long-lived asset to which the liability relates. An ongoing
expense will also be recognized for changes in the value of the liability as a
result of the passage of time. The provisions of SFAS No. 143 are effective for
fiscal years beginning after June 15, 2002. We expect that we will record a
charge as a cumulative effect of accounting change of approximately $23 million,
net of income taxes, upon our adoption of SFAS No. 143 on January 1, 2003. We
also expect to record non-current retirement assets of $184 million and
non-current retirement liabilities of $214 million on January 1, 2003. Our
liability relates primarily to our obligations to plug abandoned wells in our
Production and Pipelines segments over the next one to 101 years.
Accounting for Costs Associated with Exit or Disposal Activities
In July 2002, the FASB issued SFAS No. 146, Accounting for Costs Associated
with Exit or Disposal Activities. This statement will require us to recognize
costs associated with exit or disposal activities when they are incurred rather
than when we commit to an exit or disposal plan. Examples of costs covered by
this guidance include lease termination costs, employee severance costs
associated with a restructuring, discontinued operations, plant closings or
other exit or disposal activities. The statement is effective for fiscal years
beginning after December 31, 2002, and will impact any exit or disposal
activities we initiate after January 1, 2003.
Accounting for Guarantees
In November 2002, the FASB issued FIN No. 45, Guarantor's Accounting and
Disclosure Requirements for Guarantees, Including Indirect Guarantees of
Indebtedness of Others. This interpretation requires that companies record a
liability for all guarantees issued after January 31, 2003, including financial,
performance and fair value guarantees. This liability is recorded at its fair
value upon issuance and does not affect any
75
existing guarantees issued before January 31, 2003. This standard also requires
expanded disclosures on all existing guarantees at December 31, 2002. We have
included these required disclosures in Item 7, Note 20 of this Current Report on
Form 8-K.
Consolidation of Variable Interest Entities
In January 2003, the FASB issued FIN No. 46, Consolidation of Variable
Interest Entities, an Interpretation of ARB No. 51. This interpretation defines
a variable interest entity as a legal entity whose equity owners do not have
sufficient equity at risk and/or a controlling financial interest in the entity.
This standard requires that companies consolidate a variable interest entity if
it is allocated a majority of the entity's losses and/or returns, including fees
paid by the entity. The provisions of FIN No. 46 are effective for all variable
interest entities created after January 31, 2003, and are effective on July 1,
2003, for all variable interest entities created before January 31, 2003. We are
currently evaluating the effects of this pronouncement, but have reached several
tentative conclusions about the possible impact of this interpretation on us.
See Item 7, Note 1 of this Current Report on Form 8-K, for a discussion of the
conclusions reached.
76
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 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. All of our forward-looking
statements, whether written or oral, are expressly qualified by these cautionary
statements and any other cautionary statements that may accompany such
forward-looking statements. In addition, we disclaim any obligation to update
any forward-looking statements to reflect events or circumstances after the date
of this report.
With this in mind, you should consider the risks discussed elsewhere in
this report and other documents we file with the Commission from time to time
and 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.
WE HAVE SUBSTANTIAL DEBT. THE DOWNGRADES OF OUR CREDIT RATINGS TO BELOW
INVESTMENT GRADE HAVE SIGNIFICANTLY IMPACTED AND WILL CONTINUE TO SIGNIFICANTLY
IMPACT OUR LIQUIDITY.
We have substantial debt. As of December 31, 2002, we had total long-term
capital market debt, bank debt and other financing obligations of approximately
$16.7 billion, including approximately $8.5 billion of subsidiary debt. We also
have guarantees of approximately $2.5 billion (including $63 million associated
with our discontinued petroleum markets operations) and preferred interests of
consolidated subsidiaries of approximately $3.3 billion.
The ratings assigned to our outstanding senior unsecured indebtedness have
been downgraded to below investment grade, currently rated Caa1 by Moody's and B
by Standard & Poor's, and we remain on negative outlook at both agencies. These
ratings have increased and will increase our cost of capital and collateral
requirements, and could impede our access to capital markets. As a result of
these recent downgrades, we have realized substantial demands on our liquidity,
which demands have included:
- application of cash required to be withheld from our cash management
program in order to redeem preferred membership interests at one of our
minority interest financing structures; and
- cash collateral or margin requirements associated with contractual
commitments of our subsidiaries.
These downgrades may subject us to additional liquidity demands in the future.
These downgrades are a result, at least in part, of the outlook generally for
our consolidated businesses and our liquidity needs.
In order to meet our short-term liquidity needs, we have embarked on our
2003 Operational and Financial Plan that contemplates drawing all or part of our
availability under our existing bank facilities and consummating significant
asset sales. In addition, we may take additional steps, such as entering into
other financing activities, renegotiating our credit facilities and further
reducing capital expenditures, which should provide additional liquidity. There
can be no assurance that these actions will be consummated on favorable terms,
if at all, or that even if consummated, that such actions will be successful in
satisfying our liquidity needs. In the event our liquidity needs are not
satisfied, we could be forced to seek protection from our creditors in
bankruptcy. Such a development could materially adversely affect our financial
condition.
ONGOING LITIGATION AND INVESTIGATIONS COULD SIGNIFICANTLY ADVERSELY AFFECT OUR
BUSINESS.
On March 20, 2003, we entered into an agreement in principle (the Western
Energy Settlement) with various public and private claimants, including the
states of California, Washington, Oregon, and Nevada, to
77
resolve the principal litigation, claims, and regulatory proceedings against us
and our subsidiaries relating to the sale or delivery of natural gas and
electricity from September 1996 to the date of the Western Energy Settlement.
For further information on these matters, see Item 7, Notes 2 and 20 of this
Current Report on Form 8-K. If we are unable to negotiate definitive settlement
agreements, or if the settlement is not approved by the courts or the FERC, the
proceedings and litigation will continue.
Since July 2002, twelve purported shareholder class action suits alleging
violations of federal securities laws have been filed against us and several of
our officers. Eleven of these suits are now consolidated in federal court in
Houston before a single judge. The suits generally challenge the accuracy or
completeness of press releases and other public statements made during 2001 and
2002. The twelfth shareholder class action lawsuit was filed in federal court in
New York City in October 2002 challenging the accuracy or completeness of our
February 27, 2002 prospectus for an equity offering that was completed on June
21, 2002. It has since been dismissed, in light of similar claims being asserted
in the consolidated suits in Houston. Four shareholder derivative actions have
also been filed. One shareholder derivative lawsuit was filed in federal court
in Houston in August 2002. This derivative action generally alleges the same
claims as those made in the shareholder class action, has been consolidated with
the shareholder class actions pending in Houston and has been stayed. A second
shareholder derivative lawsuit was filed in Delaware State Court in October 2002
and generally alleges the same claims as those made in the consolidated
shareholder class action lawsuit. A third shareholder derivative suit was filed
in state court in Houston in March 2002, and a fourth shareholder derivative
suit was filed in state court in Houston in November 2002. The third and fourth
shareholder derivative suits both generally allege that manipulation of
California gas supply and gas prices exposed us to claims of antitrust
conspiracy, FERC penalties and erosion of share value. In December 2002, another
action was filed in federal court in Houston on behalf of participants in the El
Paso Corporation Retirement Savings Plan. At this time, our legal exposure
related to these lawsuits and claims is not determinable.
If we do not prevail in these cases (or any of the other litigation,
administrative or regulatory matters to which we are, or may be, a party
described in Item 7, Note 20 of this Current Report on Form 8-K), and if the
remedy adopted in these cases substantially impairs our financial position, the
long-term adverse impact on our credit rating, liquidity and our ability to
raise capital to meet our ongoing and future investing and financing needs could
be substantial.
WE MAY NOT ACHIEVE ALL OF THE OBJECTIVES SET FORTH IN OUR 2003 OPERATIONAL AND
FINANCIAL PLAN IN A TIMELY MANNER OR AT ALL.
Our ability to achieve the stated objectives of our 2003 Operational and
Financial Plan, as well as the timing of their achievement, if at all, is
subject to factors beyond our control, including our ability to raise cash from
asset sales, which may be impacted by our ability to locate potential buyers in
a timely fashion and obtain a reasonable price or by competing assets sales
programs by our competitors. If we fail to timely achieve that plan, or if the
plan, even if achieved, fails to have the effects on our liquidity and financial
position that we anticipate, our liquidity or financial position could be
materially adversely affected.
OUR OBJECTIVES IN EXITING THE ENERGY TRADING BUSINESS AND THE PETROLEUM MARKETS
BUSINESS MAY NOT BE ACHIEVED IN THE TIME PERIOD OR IN THE MANNER WE EXPECT, IF
AT ALL.
In November 2002, we announced our intention to exit the energy trading
business and pursue an orderly liquidation of our trading portfolio. In 2003, we
announced our intention to sell substantially all of our petroleum markets
business. If we are unable to achieve these objectives in the time period or the
manner that we expect, it could have a substantial negative impact on our cash
flows, liquidity and financial position. The ability to achieve our goals in the
liquidation of our trading portfolio is subject to factors beyond our control,
including, among others, liquidity constraints experienced by the counterparties
in our energy trading business, obtaining maximum cash flow from our trading
portfolio and isolating the credit and liquidity needs of the energy trading
business from the rest of our business. Additionally, any amounts actually
realized from the liquidation of the energy trading business could be
significantly less than the amounts we currently expect from such liquidations.
Ongoing losses from our trading business are expected to be incurred as
positions are liquidated. The ability to achieve our goals in the sale of our
petroleum assets is subject to factors beyond our
78
control, including, among others, our ability to locate potential buyers in a
timely fashion and obtain a reasonable price, and competing asset sales programs
by our competitors.
THE PROXY CONTEST INITIATED BY SELIM ZILKHA TO REPLACE OUR BOARD OF DIRECTORS
COULD HAVE A MATERIAL ADVERSE EFFECT ON US.
On February 18, 2003, Selim Zilkha, one of our stockholders, announced his
intention to initiate a proxy solicitation to replace our entire board of
directors with his own nominees, and on March 11, 2003, Mr. Zilkha filed his
preliminary proxy statement to that effect with the SEC. This proxy contest may
be disruptive and may negatively impact our ability to achieve the stated
objectives of our 2003 Operational and Financial Plan. In addition, we may have
difficulty attracting and retaining key personnel until such proxy contest is
resolved. Therefore, this proxy contest, whether or not successful, could have a
material adverse effect on our liquidity and financial condition.
RESULTS OF INVESTIGATIONS INTO REPORTING OF TRADING INFORMATION COULD ADVERSELY
AFFECT OUR BUSINESS.
In response to an October 2002 data request from the FERC, we conducted an
investigation into the accuracy of information that employees of El Paso
Merchant Energy, our subsidiary, voluntarily reported to trade publications. As
a part of that investigation, we discovered that inaccurate information was
submitted to the trade publications. One of El Paso Merchant Energy's former
employees has been arrested and charged with knowingly submitting inaccurate
data to a trade publication. We have continued our policy of cooperation with
the office of the U.S. Attorney and the FERC and intend to take whatever
remedial steps are necessary to ensure that our operations are conducted with
integrity. However, these investigations are continuing, and there can be no
assurance that penalties or sanctions will not be imposed on us, which, in turn,
could adversely affect our business.
THE SUCCESS OF OUR PIPELINE AND FIELD SERVICES BUSINESSES DEPENDS ON FACTORS
BEYOND OUR CONTROL.
Most of the natural gas and natural gas liquids we transport, gather,
process and store are owned by third parties. As a result, the volume of natural
gas and natural gas liquids 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, may unfavorably impact our
ability to maintain or increase current throughput, to renegotiate existing
contracts as they expire or to remarket unsubscribed capacity:
- future weather conditions, including those that favor alternative energy
sources;
- price competition;
- drilling activity and supply availability;
- expiration and/or turn back of significant capacity;
- service area competition;
- changes in regulation and action of regulatory bodies;
- credit risk of customer base;
- increased cost of capital; and
- natural gas and liquids prices.
THE REVENUES OF OUR PIPELINE BUSINESSES ARE GENERATED UNDER CONTRACTS THAT MUST
BE RENEGOTIATED PERIODICALLY.
Substantially all of our pipeline subsidiaries' revenues are generated
under contracts which expire periodically and must be renegotiated and extended
or replaced. We cannot assure that we will be able to extend or replace these
contracts when they expire or that the terms of any renegotiated contracts will
be as favorable as the existing contracts.
79
In particular, our ability to extend and/or replace contracts could be
adversely affected by factors we cannot control, including:
- the proposed construction by other companies of additional pipeline
capacity in markets served by our interstate pipelines;
- changes in state regulation of local distribution companies, which may
cause them to negotiate short-term contracts or turn back their capacity
when their contracts expire;
- reduced demand and market conditions;
- the availability of alternative energy sources or gas supply points; and
- regulatory actions.
If we are unable to renew, extend or replace these contracts or if we renew
them on less favorable terms, we may suffer a material reduction in our revenues
and earnings.
FLUCTUATIONS IN ENERGY COMMODITY PRICES COULD ADVERSELY AFFECT OUR PIPELINE AND
FIELD SERVICES BUSINESSES.
Revenues generated by our transmission, storage, gathering and processing
contracts depend on volumes and rates, both of which can be affected by the
prices of natural gas and natural gas liquids. Increased prices could result in
loss of load from our customers, such as power companies not dispatching gas
fired plants, industrial plant shutdown or load loss to competitive fuels and
local distribution companies' loss of customer base. The success of our
transmission, gathering and processing operations is subject to continued
development of additional oil and natural gas reserves and our ability to access
additional suppliers from interconnecting pipelines 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 transmission, gathering and
processing through our systems or facilities. Fluctuations in energy prices are
caused by a number of factors, including:
- regional, domestic and international supply and demand;
- availability and adequacy of transportation facilities;
- energy legislation;
- federal and state taxes, if any, on the sale or transportation of natural
gas and natural gas liquids;
- abundance of supplies of alternative energy sources; and
- political unrest among oil producing countries.
THE AGENCIES THAT REGULATE OUR PIPELINE BUSINESSES AND THEIR CUSTOMERS AFFECT
OUR PROFITABILITY.
Our pipeline businesses are regulated by the FERC, the U.S. Department of
Transportation, and various state and local regulatory agencies. Regulatory
actions taken by those agencies have the potential to adversely affect our
profitability. In particular, the FERC regulates the rates our pipelines are
permitted to charge their customers for their services. If our pipelines' tariff
rates were reduced in a future proceeding, if our pipelines' volume of business
under their currently permitted rates was decreased significantly, or if our
pipelines were required to substantially discount the rates for their services
because of competition, the profitability of our pipeline businesses could be
reduced.
Further, state agencies that regulate our pipelines' local distribution
company customers could impose requirements that could impact demand for our
pipelines' services.
80
THE SUCCESS OF OUR NATURAL GAS AND OIL EXPLORATION AND PRODUCTION BUSINESSES IS
DEPENDENT ON FACTORS THAT ARE BEYOND OUR CONTROL.
The performance of our natural gas and oil exploration and production
businesses is dependent upon a number of factors that we cannot control. These
factors include:
- fluctuations in natural gas and crude oil prices including basis
differentials;
- the results of future drilling activity;
- our ability to identify and precisely locate prospective geologic
structures and to drill and successfully complete wells in those
structures in a timely manner;
- our ability to expand our leased land positions in desirable areas, which
often are subject to intensely competitive leasing conditions;
- increased competition in the search for and acquisition of reserves;
- risks incident to operations of natural gas and oil wells;
- future drilling, production and development costs, including drilling rig
rates and oil field services costs;
- future tax policies, rates, and drilling or production incentives by
state, federal, or foreign governments;
- increased federal or state regulations, including environmental
regulations, that limit or restrict the ability to drill natural gas or
oil wells, reduce operational flexibility, or increase capital and
operating costs;
- decreased demand for the use of natural gas and oil because of market
concerns about global warming or changes in governmental policies and
regulations due to climate change initiatives; and
- continued access to sufficient capital to fund drilling programs to
develop and replace a reserve base with rapid depletion characteristics.
ESTIMATES OF NATURAL GAS AND OIL RESERVES MAY CHANGE.
Actual production, revenues, taxes, development expenditures, and operating
expenses with respect to our reserves will likely vary from our estimates of
proved reserves of natural gas and oil, and those variances may be material. The
process of estimating natural gas and oil reserves is complex, requiring
significant decisions and assumptions in the evaluation of available geological,
geophysical, engineering, and economic data for each reservoir or deposit. As a
result, these estimates are inherently imprecise. Actual future production,
natural gas and oil prices, revenues, taxes, development expenditures, operating
expenses and quantities of recoverable natural gas and oil reserves may vary
substantially from our estimates. In addition, we may be required to revise the
reserve information, downward or upward, based on production history, results of
future exploration and development, prevailing natural gas and oil prices and
other factors, many of which are beyond our control.
THE SUCCESS OF OUR POWER GENERATION ACTIVITIES DEPENDS ON MANY FACTORS BEYOND
OUR CONTROL.
The success of our domestic and international power projects 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;
- increases in the costs of generation, including increases in fuel costs;
- uncertain regulatory conditions resulting from the ongoing deregulation
of the electric industry in the U.S. and in foreign jurisdictions;
- our ability to negotiate successfully and enter into, restructure or
recontract advantageous long-term power purchase agreements;
81
- the possibility of a reduction in the projected rate of growth in
electricity usage as a result of factors such as regional economic
conditions, excessive reserve margins and the implementation of
conservation programs;
- risks incidental to the operation and maintenance of power generation
facilities;
- the inability of customers to pay amounts owed under power purchase
agreements; and
- the increasing price volatility due to deregulation and changes in
commodity trading practices.
OUR USE OF DERIVATIVE FINANCIAL INSTRUMENTS COULD RESULT IN FINANCIAL LOSSES.
Some of our subsidiaries use futures, swaps and option contracts traded on
the New York Mercantile Exchange, over-the-counter options and price and basis
swaps with other natural gas merchants and financial institutions. We could
incur financial losses in the future as a result of volatility in the market
values of the energy commodities we trade, or if one of our counterparties fails
to perform under a contract. The valuation of these financial instruments
involve estimates. Changes in the assumptions underlying these estimates can
occur, changing our valuation of these instruments and potentially resulting in
financial losses. To the extent we hedge our commodity price exposure and
interest rate exposure, we forego the benefits we would otherwise experience if
commodity prices were to increase, or interest rates were to change. The use of
derivatives also requires the posting of cash collateral with our counterparties
which can impact our working capital when commodity prices or interest rates
change. For additional information concerning our derivative financial
instruments, see our discussion of Quantitative and Qualitative Disclosures
About Market Risk beginning on page 84 and Item 7, Note 13 of this Current
Report on Form 8-K.
OUR FOREIGN OPERATIONS AND INVESTMENTS INVOLVE SPECIAL RISKS.
Our activities in areas outside the U.S. are subject to the risks inherent
in foreign operations, including:
- loss of revenue, property and equipment as a result of hazards such as
expropriation, nationalization, wars, insurrection and other political
risks;
- the effects of currency fluctuations and exchange controls, such as
devaluation of foreign currencies and other economic problems; and
- changes in laws, regulations and policies of foreign governments,
including those associated with changes in the governing parties.
COSTS OF ENVIRONMENTAL LIABILITIES, REGULATIONS AND LITIGATION COULD EXCEED OUR
ESTIMATES.
Our operations are subject to various environmental laws and regulations.
These laws and regulations obligate us to install and maintain pollution
controls and to clean up various sites at which regulated materials may have
been disposed of or released. Some of these sites have been designated Superfund
sites by the EPA under the Comprehensive Environmental Response, Compensation
and Liability Act. We are also party to legal proceedings involving
environmental matters pending in various courts and agencies.
It is not possible for us to estimate reliably the amount and timing of all
future expenditures related to environmental matters because of:
- the uncertainties in estimating clean up costs;
- the discovery of new sites or information;
- the uncertainty in quantifying liability under environmental laws that
impose joint and several liability on all potentially responsible
parties;
- the nature of environmental laws and regulations; and
- the possible introduction of future environmental laws and regulations.
82
Although we believe we have established appropriate reserves for
liabilities, including clean up costs, we could be required to set aside
additional reserves in the future due to these uncertainties. For additional
information concerning our environmental matters, see Item 7, Note 20 of this
Current Report on Form 8-K.
OUR OPERATIONS ARE SUBJECT TO OPERATIONAL HAZARDS AND UNINSURED RISKS.
Our operations are subject to the inherent risks normally associated with
those operations, including pipeline ruptures, explosions, pollution, release of
toxic substances, fires and adverse weather conditions, and other hazards, each
of which could result in damage to or destruction of our facilities or damages
to persons and property. In addition, our operations face possible risks
associated with acts of aggression on our domestic and foreign assets. If any of
these events were to occur, we could suffer substantial losses.
While we maintain insurance against many of these risks, our financial
condition and operations could be adversely affected if a significant event
occurs that is not fully covered by insurance.
TERRORIST ATTACKS AIMED AT OUR ENERGY OPERATIONS COULD ADVERSELY AFFECT OUR
BUSINESS.
On September 11, 2001, the U.S. was the target of terrorist attacks of
unprecedented scale. Since the September 11th attacks, the U.S. government has
issued warnings that energy assets, including our nation's pipeline
infrastructure, may be a future target of terrorist organizations. These
developments have subjected our energy operations to increased risks. Any future
terrorist attack on our facilities, those of our customers and, in some cases,
those of other energy companies, could have a material adverse effect on our
business.
A BREACH OF THE COVENANTS APPLICABLE TO OUR LONG-TERM DEBT AND OTHER FINANCIAL
OBLIGATIONS COULD ACCELERATE OUR LONG-TERM DEBT AND OTHER FINANCIAL OBLIGATIONS
AND THAT OF OUR SUBSIDIARIES.
Our long-term debt and other financial obligations contain restrictive
covenants and cross-acceleration provisions. A breach of any of these covenants
could accelerate our long-term debt and other financial obligations and that of
our subsidiaries. If this were to occur, we may not be able to repay such
long-term debt and other financing obligations upon such acceleration.
WE ARE SUBJECT TO FINANCING AND INTEREST RATE EXPOSURE RISKS.
Our future success depends on our ability to access capital markets and
obtain financing at cost effective rates. In addition, our recent downgrades and
current credit ratings have triggered higher cash requirements and operating
costs for our energy trading business, which we are in the process of exiting
pursuant to an orderly liquidation of our trading portfolio. Our ability to
access financial markets and obtain cost-effective rates in the future are
dependent on a number of factors, many of which we cannot control, including
changes in:
- our credit ratings;
- interest rates;
- the structured and commercial financial markets;
- market perceptions of us or the natural gas and energy industry;
- tax rates due to new tax laws; and
- our stock price.
WE WILL FACE COMPETITION FROM THIRD PARTIES TO PRODUCE, TRANSPORT, GATHER,
PROCESS, FRACTIONATE, STORE OR OTHERWISE HANDLE OIL, NATURAL GAS, NATURAL GAS
LIQUIDS AND OTHER PETROLEUM PRODUCTS.
The natural gas and oil business is highly competitive in the search for
and acquisition of reserves and in the gathering and marketing of natural gas
and oil production. Our competitors include the major oil companies, independent
oil and gas concerns, individual producers, gas marketers and major pipeline
companies, as well as participants in other industries supplying energy and fuel
to industrial, commercial and
83
individual consumers. If we are unable to compete effectively with services
offered by other energy enterprises, our future profitability may be negatively
impacted.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
We use derivative financial instruments and energy related contracts to
manage market risks associated with energy commodities, interest rates and
foreign currency exchange rates. Our primary market risk exposures are those
related to changing commodity prices. Our market risks are monitored by a
corporate risk management committee to ensure compliance with the stated risk
management policies approved by the Audit Committee of our Board of Directors.
This committee operates independently from the business segments that create or
manage these risks.
COMMODITY PRICE RISK
We are exposed to a variety of market risks in the normal course of our
business activities. The nature of these market price risks varies based on our
segments. Our Production segment has price risks related to the natural gas and
oil it produces. Our Field Services segment has price risks related to the
natural gas liquids it retains in its processing operations. The global power
division of our Merchant Energy segment is exposed to price risks in both the
fuel it uses, primarily natural gas and coal, as well as the power it sells. The
energy trading division of our Merchant Energy segment is exposed to market
price risks inherent in its contractual obligations to deliver or receive
commodities and in the financial instruments it uses for trading energy and
energy-related commodities. Our petroleum markets business (included in our
discontinued operations) is exposed to price risks in both the feedstocks it
uses, primarily crude oil and petroleum-based products, as well as the refined
products it sells.
We attempt to mitigate price risk associated with both our energy trading
activities (included in the energy trading division in our Merchant Energy
segment and in our discontinued petroleum markets business) and non-trading
activities (power and commodity hedging activities) through the use of trading
and non-trading financial instruments (including forwards, swaps, options and
futures). We measure risks from our commodity and energy-related contracts on a
daily basis using a Value-at-Risk model. This model allows us to determine the
maximum expected one-day unfavorable impact on the fair values of those
contracts due to normal market movements, and monitors our risk in comparison to
established thresholds. We use what is known as the historical simulation
technique for measuring Value-at-Risk. This technique values positions in every
iteration of the simulation and captures risk from all types of financial
positions. We also use other measures to monitor our risks on a daily basis,
including sensitivity analysis, stress testing, credit risk management and other
measures to monitor and measure risk exposure.
The following table presents our maximum expected one-day unfavorable
impact on the fair values of our commodity and energy-related contracts as
measured by Value-at-Risk based on a confidence level of 95 percent and a
one-day holding period. The high and low valuations represent the highest and
lowest of the month end values during 2002 (for both continuing and discontinued
operations). The average valuation represents the average of the 2002 month end
values. Actual losses in fair value may exceed those measured by Value-at-Risk:
VALUE-AT-RISK
-------------------------------------
2002 2001
----------------------------- ----
YEAR YEAR
END HIGH LOW AVERAGE END
---- ---- --- ------- ----
(IN MILLIONS)
Trading Value-at-Risk.................................... $ 8 $23 $8 $16 $18
Non-trading Value-at-Risk................................ 8 10 4 7 15
Portfolio Value-at-Risk(1)............................... 11 22 9 16 17
---------------
(1) Portfolio Value-at-Risk represents the combined Value-at-Risk for the
trading and non-trading commodity and energy-related contracts. The separate
calculation of Value-at-Risk for trading and non-trading commodity contracts
ignores the natural correlation that exists between traded and non-traded
commodity contracts and prices. As a result, the sum of the individually
determined values
84
will be higher than the combined Value-at-Risk in most instances. We manage
our risks through a portfolio approach that balances both trading and
non-trading risks.
The $10 million decrease in trading Value-at-Risk during 2002 is
attributable to our efforts to limit and liquidate our trading activities during
2002. Our non-trading Value-at-Risk decreased by $7 million in 2002 due to a
reduction of our hedged volumes of future natural gas production during 2002. We
reduced these hedged volumes to reduce the cash requirements of our non-trading
price risk management activities.
INTEREST RATE RISK
Many of our debt-related financial instruments and project financing
arrangements are sensitive to changes in interest rates. The table below shows
the maturity of the carrying amounts and related weighted average interest rates
on our interest-bearing securities, by expected maturity dates and the fair
values of those securities. As of December 31, 2002, the carrying amounts of
short-term borrowings are representative of fair values because of the
short-term maturity of these instruments. The fair value of the long-term
securities has been estimated based on quoted market prices for the same or
similar issues.
DECEMBER 31, 2002 DECEMBER 31, 2001
----------------------------------------------------------------------- ------------------
EXPECTED FISCAL YEAR OF MATURITY OF CARRYING AMOUNTS
------------------------------------------------------------- FAIR CARRYING FAIR
2003 2004 2005 2006 2007 THEREAFTER TOTAL VALUE AMOUNTS VALUE
------ ---- ---- ------ ------ ---------- ------- ------- -------- -------
(DOLLARS IN MILLIONS)
LIABILITIES:(1)
Short-term debt -- variable
rate.......................... $1,500 -- -- -- -- -- $ 1,500 $ 1,500 $ 1,440 $ 1,440
Average interest rate..... 2.7%
Long-term debt, including
current portion -- fixed
rate.......................... $ 362 $331 $497 $1,120 $1,122 $12,469 $15,901 $11,488 $12,533 $12,007
Average interest rate..... 7.8% 7.4% 8.5% 8.3% 7.7% 8.0%
Long-term debt, including
current portion-variable
rate.......................... $ 213 $253 $113 $ 113 $ 9 $ 79 $ 780 $ 780 $ 1,606 $ 1,606
Average interest rate..... 2.5% 4.4% 2.9% 2.7% 2.7% 6.1%
Notes payable to unconsolidated
affiliates -- fixed rate.... $ 189 $ 10 $ 12 $ 6 -- -- $ 216 $ 206 $ 515 $ 539
Average interest rate..... 4.4% 7.3% 7.3% 7.3%
Notes payable to unconsolidated
affiliates -- variable
rate...................... -- -- -- -- -- $ 174 $ 174 $ 174 $ 357 $ 357
Average interest rate..... 10.4%
COMPANY-OBLIGATED PREFERRED
SECURITIES:
El Paso Energy Capital Trust
I............................. -- -- -- -- -- $ 325 $ 325 $ 118 $ 325 $ 370
Average interest rate..... 4.8%
Coastal Finance I............... -- -- -- -- -- $ 300 $ 300 $ 160 $ 300 $ 378
Average fixed interest
rate.................... 8.4%
---------------
(1) As of December 31, 2001, the carrying amount of long-term debt with variable
rates related to discontinued petroleum markets operations was $551 million,
which was retired as of December 31, 2002, which has been excluded from the
above table.
The fair value of our long-term securities was significantly impacted by a
series of ratings actions initiated by Moody's and Standard & Poor's that
lowered our unsecured debt rating to Caa1 and B (both "below investment grade"
ratings), and we remain on negative outlook. These rating actions decreased the
fair value of all of our fixed rate long-term securities during 2002.
85
FOREIGN CURRENCY EXCHANGE RATE RISK
Our exposure to foreign currency exchange rates relates primarily to
changes in foreign currency rates on our Euro-denominated debt obligations. We
have Euro-denominated debt with a principal amount of 1,050 million euros, or
$1,100 million at a Euro/USD spot exchange rate of 1.0492 as of December 31,
2002. 550 million euros and 500 million euros of this debt mature in 2006 and
2009. We have a foreign currency swap that converts 275 million euros of this
debt to U.S. dollars at a fixed rate of 0.9275. The remaining principal of 775
million euros is unhedged and is subject to foreign currency exchange risk. A
ten percent increase or decrease in the Euro/USD exchange rate would increase or
decrease the carrying value of our unhedged Euro-denominated debt by
approximately $81 million.
86
ITEM 7. FINANCIAL STATEMENTS AND EXHIBITS
Below are our historical financial statements and financial statement
schedule that reflect the reclassification of our petroleum markets operations
as discontinued operations for all periods presented.
EL PASO CORPORATION
CONSOLIDATED STATEMENTS OF INCOME
(IN MILLIONS, EXCEPT PER COMMON SHARE AMOUNTS)
YEAR ENDED DECEMBER 31,
---------------------------
2002 2001 2000
------- ------- -------
Operating revenues
Pipelines................................................. $ 2,605 $ 2,748 $ 2,741
Production................................................ 2,126 2,347 1,686
Field Services............................................ 2,029 2,553 1,439
Merchant Energy........................................... 972 1,224 801
Corporate and eliminations................................ (134) 67 521
------- ------- -------
7,598 8,939 7,188
------- ------- -------
Operating expenses
Cost of products and services............................. 2,383 2,450 1,763
Operation and maintenance................................. 1,943 2,064 1,656
Restructuring and merger-related costs.................... 77 1,493 93
(Gain) loss on long-lived assets.......................... 185 77 (1)
Western Energy Settlement................................. 899 -- --
Ceiling test charges...................................... 269 135 --
Depreciation, depletion and amortization.................. 1,332 1,261 1,171
Taxes, other than income taxes............................ 255 316 251
------- ------- -------
7,343 7,796 4,933
------- ------- -------
Operating income............................................ 255 1,143 2,255
Earnings (losses) from unconsolidated affiliates............ (226) 437 423
Minority interest in consolidated subsidiaries.............. (58) (2) --
Other income................................................ 201 288 206
Other expenses.............................................. (180) (126) (52)
Interest and debt expense................................... (1,388) (1,129) (1,001)
Returns on preferred interests of consolidated
subsidiaries.............................................. (159) (217) (204)
------- ------- -------
Income (loss) before income taxes........................... (1,555) 394 1,627
Income taxes................................................ (507) 242 514
------- ------- -------
Income (loss) from continuing operations before
extraordinary items and cumulative effect of accounting
changes................................................... (1,048) 152 1,113
Discontinued operations, net of income taxes................ (365) (85) 123
Extraordinary items, net of income taxes.................... -- 26 70
Cumulative effect of accounting changes, net of income
taxes..................................................... (54) -- --
------- ------- -------
Net income (loss)........................................... $(1,467) $ 93 $ 1,306
======= ======= =======
Basic earnings per common share
Income (loss) from continuing operations before
extraordinary items and cumulative effect of accounting
changes................................................. $ (1.87) $ 0.30 $ 2.25
Discontinued operations, net of income taxes.............. (0.65) (0.17) 0.25
Extraordinary items, net of income taxes.................. -- 0.05 0.14
Cumulative effect of accounting changes, net of income
taxes................................................... (0.10) -- --
------- ------- -------
Net income (loss)......................................... $ (2.62) $ 0.18 $ 2.64
======= ======= =======
Diluted earnings per common share
Income (loss) from continuing operations before
extraordinary items and cumulative effect of accounting
changes................................................. $ (1.87) $ 0.30 $ 2.19
Discontinued operations, net of income taxes.............. (0.65) (0.17) 0.24
Extraordinary items, net of income taxes.................. -- 0.05 0.14
Cumulative effect of accounting changes, net of income
taxes................................................... (0.10) -- --
------- ------- -------
Net income (loss)......................................... $ (2.62) $ 0.18 $ 2.57
======= ======= =======
Basic average common shares outstanding..................... 560 505 494
======= ======= =======
Diluted average common shares outstanding................... 560 516 513
======= ======= =======
See accompanying notes.
87
EL PASO CORPORATION
CONSOLIDATED BALANCE SHEETS
(IN MILLIONS, EXCEPT SHARE AMOUNTS)
DECEMBER 31,
-----------------
2002 2001
------- -------
ASSETS
Current assets
Cash and cash equivalents................................. $ 1,591 $ 1,148
Accounts and notes receivable
Customer, net of allowance of $176 in 2002 and $117 in
2001.................................................. 4,123 3,770
Affiliates............................................. 774 851
Other.................................................. 451 609
Inventory................................................. 252 191
Assets from price risk management activities.............. 1,007 2,532
Margin and other deposits on energy trading activities.... 1,003 872
Assets of discontinued operations......................... 2,154 2,464
Other..................................................... 569 368
------- -------
Total current assets.............................. 11,924 12,805
------- -------
Property, plant and equipment, at cost
Pipelines................................................. 18,049 17,595
Natural gas and oil properties, at full cost.............. 14,940 14,466
Power facilities.......................................... 1,075 852
Gathering and processing systems.......................... 1,101 2,628
Other..................................................... 651 608
------- -------
35,816 36,149
Less accumulated depreciation, depletion and
amortization........................................... 14,052 13,670
------- -------
Total property, plant and equipment, net.......... 21,764 22,479
------- -------
Other assets
Investments in unconsolidated affiliates.................. 4,891 5,236
Assets from price risk management activities.............. 1,844 2,118
Goodwill and other intangible assets, net................. 1,367 1,422
Assets of discontinued operations......................... 1,911 2,322
Other..................................................... 2,523 2,164
------- -------
12,536 13,262
------- -------
Total assets...................................... $46,224 $48,546
======= =======
See accompanying notes.
88
EL PASO CORPORATION
CONSOLIDATED BALANCE SHEETS -- (CONTINUED)
(IN MILLIONS, EXCEPT SHARE AMOUNTS)
DECEMBER 31,
-----------------
2002 2001
------- -------
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities
Accounts payable
Trade.................................................. $ 3,581 $ 3,245
Affiliates............................................. 29 10
Other.................................................. 742 880
Short-term financing obligations, including current
maturities............................................. 2,075 2,739
Notes payable to affiliates............................... 189 504
Liabilities from price risk management activities......... 1,041 1,656
Margin and other deposits from customers on energy trading
activities............................................. 123 1,147
Western Energy Settlement................................. 100 --
Liabilities of discontinued operations.................... 1,373 2,670
Other..................................................... 1,097 1,085
------- -------
Total current liabilities......................... 10,350 13,936
------- -------
Debt
Long-term financing obligations........................... 16,106 12,840
Notes payable to affiliates............................... 201 368
------- -------
16,307 13,208
------- -------
Other
Liabilities from price risk management activities......... 1,374 1,231
Deferred income taxes..................................... 3,576 4,388
Western Energy Settlement................................. 799 --
Liabilities of discontinued operations.................... 87 155
Other..................................................... 1,934 2,259
------- -------
7,770 8,033
------- -------
Commitments and contingencies
Securities of subsidiaries
Preferred interests of consolidated subsidiaries.......... 3,255 3,955
Minority interests of consolidated subsidiaries........... 165 58
------- -------
3,420 4,013
------- -------
Stockholders' equity
Common stock, par value $3 per share; authorized
1,500,000,000 shares and issued 605,298,466 shares in
2002; authorized 750,000,000 shares and issued
538,363,664 shares in 2001............................. 1,816 1,615
Additional paid-in capital................................ 4,444 3,130
Retained earnings......................................... 2,942 4,902
Accumulated other comprehensive income (loss)............. (529) 157
Treasury stock (at cost); 5,730,042 shares in 2002 and
7,628,799 shares in 2001............................... (201) (261)
Unamortized compensation.................................. (95) (187)
------- -------
Total stockholders' equity........................ 8,377 9,356
------- -------
Total liabilities and stockholders' equity........ $46,224 $48,546
======= =======
See accompanying notes.
89
EL PASO CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN MILLIONS)
YEAR ENDED DECEMBER 31,
-----------------------------
2002 2001 2000
------- ------- -------
Cash flows from operating activities
Net income (loss)......................................... $(1,467) $ 93 $ 1,306
Less income (loss) from discontinued operations, net of
income taxes............................................ (365) (85) 123
------- ------- -------
Net income (loss) from continuing operations.............. (1,102) 178 1,183
Adjustments to reconcile net income (loss) to net cash
from operating activities
Depreciation, depletion and amortization................ 1,332 1,261 1,171
Western Energy Settlement............................... 899 -- --
Ceiling test charges.................................... 269 135 --
Deferred income tax expense (benefit)................... (551) 313 615
Non-cash portion of merger-related costs and changes in
estimates............................................. -- 1,066 (34)
(Gain) loss on long-lived assets........................ 185 77 (1)
Undistributed equity (earnings) losses from
unconsolidated affiliates............................. 533 (38) (106)
Non-cash gain from trading and power restructuring
activities............................................ (53) (852) (443)
Other non-cash income items............................. 418 141 (67)
Working capital changes, net of non-cash transactions... (1,077) 1,818 (2,313)
Non-working capital changes and other................... (146) (170) (104)
------- ------- -------
Cash provided by (used in) continuing operations...... 707 3,929 (99)
Cash provided by (used in) discontinued operations.... (271) 191 198
------- ------- -------
Net cash provided by operating activities.......... 436 4,120 99
------- ------- -------
Cash flows from investing activities
Additions to property, plant and equipment................ (3,400) (3,852) (3,249)
Purchases of interests in equity investments.............. (299) (956) (1,488)
Cash paid for acquisitions, net of cash acquired.......... (13) (299) (524)
Net proceeds from the sale of assets...................... 2,532 551 733
Proceeds from the sale of investments..................... 360 338 346
Net change in restricted cash............................. (260) 3 24
Net change in notes receivable from unconsolidated
affiliates.............................................. 4 (608) 466
Other..................................................... 22 12 (1)
------- ------- -------
Cash used in continuing operations.................... (1,054) (4,811) (3,693)
Cash used in discontinued operations.................. (201) (212) (141)
------- ------- -------
Net cash used in investing activities.............. (1,255) (5,023) (3,834)
------- ------- -------
Cash flows from financing activities
Net short-term borrowings (repayments).................... 60 (786) 309
Net long-term borrowings.................................. 2,008 1,163 2,746
Net proceeds from issuance of preferred securities........ -- -- 293
Payments to minority interest holders..................... (161) -- --
Payments to preferred interest holders.................... (700) -- --
Issuances of common stock................................. 1,053 915 141
Dividends paid............................................ (470) (387) (243)
Proceeds from issuance of minority interests.............. 33 281 995
Contributions from (distributions to) discontinued
operations.............................................. (1,033) 99 (271)
------- ------- -------
Cash provided by continuing operations.................. 790 1,285 3,970
Cash provided by (used in) discontinued operations...... 482 15 (56)
------- ------- -------
Net cash provided by financing activities.......... 1,272 1,300 3,914
------- ------- -------
Increase in cash and cash equivalents....................... 453 397 179
Less increase (decrease) in cash and cash equivalents
related to discontinued operations........................ 10 (6) 1
------- ------- -------
Increase in cash and cash equivalents from continuing
operations................................................ 443 403 178
Cash and cash equivalents
Beginning of period....................................... 1,148 745 567
------- ------- -------
End of period............................................. $ 1,591 $ 1,148 $ 745
======= ======= =======
See accompanying notes.
90
EL PASO CORPORATION
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
(IN MILLIONS)
FOR THE YEARS ENDED DECEMBER 31,
----------------------------------------------------
2002 2001 2000
---------------- --------------- ---------------
SHARES AMOUNT SHARES AMOUNT SHARES AMOUNT
------ ------- ------ ------ ------ ------
Common stock, $3.00 par:
Balance at beginning of year.............. 538 $ 1,615 514 $1,541 507 $1,520
Compensation related issuances............ 2 5 3 10 6 18
Equity offering........................... 52 155 20 61 -- --
Conversion of Coastal options............. -- -- 4 13 -- --
Conversion of FELINE PRIDES(SM)........... 12 37 -- -- -- --
Other..................................... 1 4 (3) (10) 1 3
--- ------- ---- ------ --- ------
Balance at end of year................. 605 1,816 538 1,615 514 1,541
--- ------- ---- ------ --- ------
Additional paid-in capital:
Balance at beginning of year.............. 3,130 1,925 1,667
Compensation related issuances............ 57 188 171
Tax benefit of equity plans............... 15 31 60
Equity offering........................... 846 802 --
Retirement of Coastal treasury shares..... -- (132)
Conversion of Coastal options............. -- 265 --
Conversion of FELINE PRIDES(SM)........... 423 -- --
Other..................................... (27) 51 27
------- ------ ------
Balance at end of year................. 4,444 3,130 1,925
------- ------ ------
Retained earnings:
Balance at beginning of year.............. 4,902 5,243 4,180
Net income (loss)......................... (1,467) 93 1,306
Dividends ($0.870, $0.850 and $0.824 per
share)................................. (493) (434) (243)
------- ------ ------
Balance at end of year................. 2,942 4,902 5,243
------- ------ ------
Accumulated other comprehensive income
(loss):
Balance at beginning of year.............. 157 (65) (37)
Other comprehensive income (loss)......... (686) 222 (28)
------- ------ ------
Balance at end of year................. (529) 157 (65)
------- ------ ------
Treasury stock, at cost:
Balance at beginning of year.............. (8) (261) (14) (400) (14) (405)
Compensation related issuances............ 3 79 1 11 -- 3
Retirement of Coastal treasury shares..... -- -- 5 132 -- --
Other..................................... (1) (19) -- (4) -- 2
--- ------- ---- ------ --- ------
Balance at end of year................. (6) (201) (8) (261) (14) (400)
--- ------- ---- ------ --- ------
Unamortized compensation:
Balance at beginning of year.............. (187) (125) (41)
Issuance of new restricted stock.......... (36) (144) (82)
Amortization of restricted stock.......... 73 67 13
Market price changes on variable
restricted stock awards................ 40 11 (15)
Forfeitures of restricted stock........... 15 4 --
------- ------ ------
Balance at end of year................. (95) (187) (125)
--- ------- ---- ------ --- ------
Total stockholders' equity.................. 599 $ 8,377 530 $9,356 500 $8,119
=== ======= ==== ====== === ======
See accompanying notes.
91
EL PASO CORPORATION
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(IN MILLIONS)
YEAR ENDED DECEMBER 31,
------------------------------
2002 2001 2000
------- ------- ------
Net income (loss)........................................... $(1,467) $ 93 $1,306
------- ------- ------
Foreign currency translation adjustments.................. (18) (33) (30)
Pension minimum liability accrual (net of income tax of
$20)................................................... (35) -- --
Net gains (losses) from cash flow hedging activities:
Cumulative-effect of transition adjustment (net of
income tax of $673).................................. -- (1,280) --
Unrealized mark-to-market gains (losses) arising during
period (net of income tax of $261 and $548 in 2002
and 2001)............................................ (459) 1,042 --
Reclassification adjustments for changes in initial
value to settlement date (net of income tax of $96
and $283 in 2002 and 2001)........................... (174) 494 --
Other..................................................... -- (1) 2
------- ------- ------
Other comprehensive income (loss).................... (686) 222 (28)
------- ------- ------
Comprehensive income (loss)................................. $(2,153) $ 315 $1,278
======= ======= ======
See accompanying notes.
92
EL PASO CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT EVENTS AND ACCOUNTING POLICIES
SIGNIFICANT EVENTS
Overview of Industry Developments
During 2002, we experienced dramatic changes in our industry as well as in
the financial markets on which we rely. In response to industry events, the
credit rating agencies, including Moody's and Standard & Poor's, re-evaluated
the ratings of companies involved in energy trading activities. As a result, the
ratings of many of the largest participants in the energy trading industry,
including us, were downgraded to below investment grade. Also impacting us was a
preliminary decision reached by a FERC administrative law judge (ALJ) that one
of our subsidiaries withheld pipeline capacity from the California market during
2000 and 2001. Reacting to the changes in the market, our leverage and a
preliminary decision by the FERC on our California matters, Moody's and Standard
& Poor's initiated a series of ratings actions lowering our senior unsecured
debt rating to Caa1 and B (both "below investment grade" ratings), and we remain
on negative outlook.
Several negative outcomes resulted from these downgrades. First, cash
generated in 2002 from the sales of assets, which had originally been identified
for debt reductions, was instead required to be posted as additional cash
collateral in connection with our commercial trading activities, paid to meet
financial guarantees and used to meet other arrangements. Additionally, our
access to capital markets and commercial paper markets became more restricted
because of our lower credit ratings. Finally, the credit downgrades have
resulted in the net cash generated by the assets in two of our minority interest
financing arrangements being largely unavailable to us for general corporate
purposes. Instead, we were required to use this cash to redeem preferred
securities issued in connection with those arrangements and for the operation of
the businesses that collateralize those arrangements. In March of 2003, we
redeemed the outstanding amounts under one of these financing arrangements,
partially freeing up these cash usage restrictions. For a further discussion of
this, see Note 19.
Liquidity Developments
We rely on cash generated from our operations as our primary source of
liquidity. We also expect to rely on borrowings under available credit
facilities, bank financings, asset sales and the issuance of long-term debt,
preferred and equity securities to provide liquidity as needed and for overall
flexibility. We believe that our future working capital needs, capital
expenditures, long-term debt repayments, dividends and other financing
activities will continue to be provided from some or all of these sources of
liquidity. Since the fourth quarter of 2001, we have taken a number of actions
to address our liquidity issues, and have made progress in our plans to meet the
demands on our liquidity and strengthen our capital structure.
Our accomplishments have included the sale of over $2.5 billion of equity
or equity-related securities, the completion or announcement of over $5.5
billion of asset sales, the removal of over $4 billion of rating triggers from
our investment and financing programs, which would have resulted in issuance of
common stock or the accelerated repayment of these obligations, and the
announcement of a plan to exit our trading business and minimize our involvement
in the LNG business. On February 5, 2003, we announced our 2003 Operational and
Financial Plan. This plan is based on five key principles:
- Preserving and enhancing the value of our core natural gas and pipeline
businesses;
- Exiting non-core businesses quickly, but prudently;
- Strengthening and simplifying our balance sheet, while maximizing
liquidity;
- Aggressively pursuing additional cost reductions; and
- Continuing to work diligently to resolve litigation and regulatory
matters.
93
Through March 2003, we have made further progress in accomplishing our
objectives under this plan, including (i) the finalization of a new $1.2 billion
term loan, which allowed us to retire our Trinity River preferred interest
financing arrangement and eliminate the cash restrictions and accelerated
amortization requirements of that arrangement (ii) the repayment of over $1.9
billion of financial obligations, including Electron and Trinity River, (iii)
the issuance of $700 million in bonds at two of our wholly owned subsidiaries
and (iv) the announcement of an agreement in principle to settle the principal
claims asserted against us in the western energy crisis of 2001.
We believe the accomplishment of this announced plan will enable us to
address our liquidity issues and simplify and improve our capital structure.
However, a number of factors could influence the timing and ultimate outcome of
our efforts.
SIGNIFICANT ACCOUNTING POLICIES
Basis of Presentation
Our consolidated financial statements include the accounts of all
majority-owned, controlled subsidiaries after the elimination of all significant
intercompany accounts and transactions. Our results for all periods presented
reflect our petroleum markets and coal mining businesses as discontinued
operations. Additionally, our financial statements for prior periods include
reclassifications that were made to conform to the current year presentation.
Those reclassifications did not impact our reported net income or stockholders'
equity.
Principles of Consolidation
We consolidate entities when we have the ability to control the operating
and financial decisions and policies of that entity. Where we can exert
significant influence over, but do not control, those policies and decisions, we
apply the equity method of accounting. We use the cost method of accounting
where we are unable to exert significant influence over the entity. The
determination of our ability to control or exert significant influence over an
entity involves the use of judgment of the extent of our control or influence
and that of the other equity owners or participants of the entity. Discussed
below as part of new accounting principles issued but not yet adopted is a
standard that, once effective, will impact our consolidation principles.
Use of Estimates
The preparation of financial statements in conformity with U.S. generally
accepted accounting principles requires the use of estimates and assumptions
that affect the amounts we report as assets, liabilities, revenues, and expenses
and our disclosures in these financial statements. Actual results can, and often
do, differ from those estimates.
Accounting for Regulated Operations
Our interstate natural gas systems and storage operations are subject to
the regulations and accounting procedures of the FERC in accordance with the
Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. Our interstate
systems, including TGP, EPNG, SNG and MPC, apply the provisions of Statement of
Financial Accounting Standards (SFAS) No. 71, Accounting for the Effects of
Certain Types of Regulation. ANR, CIG and WIC discontinued the application of
SFAS No. 71 in 1996. Accounting for regulated businesses that apply the
provisions of SFAS No. 71 differs from the accounting requirements for regulated
businesses that do not apply SFAS No. 71. Transactions that have been recorded
differently as a result of regulatory accounting requirements include the
capitalization of an equity return component on regulated capital projects,
employee related benefits, depreciation and other costs and taxes included in,
or expected to be included in, future rates.
94
Our application of SFAS No. 71 is based on the current regulatory
environment and our current tariff rates. Future regulatory developments and
rate cases could impact this accounting. Things that may influence our
assessment are:
- inability to recover cost increases due to rate caps and rate case
moratoriums;
- inability to recover capitalized costs, including an adequate return on
those costs through the ratemaking process and FERC proceedings;
- excess capacity;
- discounting rates in the markets we serve; and
- impacts of ongoing initiatives in, and deregulation of, the natural gas
industry.
We will continue to evaluate the application of regulatory accounting
principles based on on-going changes in the regulatory and economic environment.
Cash and Cash Equivalents
We consider short-term investments with an original maturity of less than
three months to be cash equivalents.
We maintain cash on deposit with banks and insurance companies that is
pledged for a particular use or restricted to support a potential liability. We
classify these balances as other current or non-current assets in our balance
sheet based on when we expect this cash to be used. As of December 31, 2002 and
2001, we reported $124 million and $17 million as other current assets and $212
million and $75 million as other non-current assets.
Allowance for Doubtful Accounts
We establish provisions for losses on accounts receivable and for natural
gas imbalances due from shippers and operators if we determine that we will not
collect all or part of the outstanding balance. We regularly review
collectibility and establish or adjust our allowance as necessary using the
specific identification method.
Inventory
Our inventory consists of crude oil, materials and supplies, natural gas in
storage, optic fiber and power turbines. Included in our assets from
discontinued operations is inventory related to refined products, crude oil
chemicals, and coal. We classify all inventory as current or non-current based
on whether it will be sold or used in the next twelve months. We report
non-current inventory as part of other non-current assets in our balance sheets.
We use the first-in, first-out and average cost methods to account for our
refined products, crude oil and chemicals inventories and the average cost
method to account for our other inventories. We value all inventory at the lower
of its cost or market value. On October 1, 2002, we adopted the provisions of
Emerging Issues Task Force (EITF) Issue No. 02-3, which required us to
reclassify all physical commodity inventory used in trading activities from net
assets from price risk management activities to inventory on our balance sheet
and to adjust this inventory to the lower of cost or market. See Price Risk
Management Activities below for a further discussion of this accounting change.
Natural Gas and Oil Imbalances and Exchanges
Natural gas and oil imbalances occur when the actual amount of natural gas
or oil delivered from or received by a pipeline system, processing plant or
storage facility differs from the contractual amount scheduled to be delivered
or received. Natural gas exchange transactions involve receiving or delivering
natural gas inventory that will be made up in-kind. We value these imbalances
and exchanges due to or from shippers and operators at an appropriate market
index price. Imbalances and exchanges are settled in cash or made up in-kind,
subject to the contractual terms of settlement and tariffs.
95
Imbalances and exchanges due from others are reported in our balance sheet
as either accounts receivable from customers or accounts receivable from
unconsolidated affiliates. Imbalances and exchanges owed to others are reported
on the balance sheet as either trade accounts payable or accounts payable to
unconsolidated affiliates. In addition, all imbalances and exchanges are
classified as current or long-term depending on when we expect to settle them.
On October 1, 2002, we adopted the provisions of EITF Issue No. 02-3, which
required us to reclassify all natural gas exchanges resulting from trading
activities from net assets from price risk management activities to accounts
receivable and accounts payable on our balance sheet. See Price Risk Management
Activities below for a further discussion of this accounting change.
Property, Plant and Equipment
Our property, plant and equipment is recorded at its original cost of
construction or, upon acquisition, at either the fair value of the assets
acquired or the cost to the entity that first placed the asset in service. We
capitalize direct costs, such as labor and materials, and indirect costs, such
as overhead, interest and in our regulated businesses that apply the provisions
of SFAS No. 71, an equity return component. We capitalize the major units of
property replacements or improvements and expense minor items. Included in our
pipeline property balances are additional acquisition costs, which represent the
excess purchase costs associated with purchase business combinations allocated
to our regulated interstate systems. These costs are amortized on a
straight-line basis, and we do not recover these excess costs in our rates.
The following table presents our property, plant and equipment by type,
depreciation method, remaining useful lives and depreciation rate:
REMAINING
TYPE METHOD USEFUL LIVES RATES
----------------------------------------------------- ------------- ------------ ------------
(IN YEARS)
Regulated interstate systems
SFAS No. 71(1)..................................... Composite 1-57 1% to 33%
Non-SFAS No. 71.................................... Straight-line 2-50 2% to 25%
Non-regulated systems(2)
Transmission and storage facilities................ Straight-line 60 1% to 3%
Power facilities................................... Straight-line 3-26 2% to 33%
Gathering and processing systems................... Straight-line 1-40 3% to 40%
Transportation equipment........................... Straight-line 1-30 3% to 33%
Buildings and improvements......................... Straight-line 1-19 2% to 50%
Office and miscellaneous equipment................. Straight-line 1-20 4% to 50%
---------------
(1) For our regulated interstate systems that apply SFAS No. 71, we use the
composite (group) method to depreciate property, plant and equipment. Under
this method, assets with similar useful lives and other characteristics are
grouped and depreciated as one asset. We apply the depreciation rate
approved in our tariff to the total cost of the group until its net book
value equals its salvage value. We re-evaluate depreciation rates each time
we redevelop our transportation rates when we file with the FERC for an
increase or decrease in rates.
(2) These amounts do not include refining, crude oil, and chemical facilities,
which have been included as assets from discontinued operations. These
facilities were being amortized on a straight-line basis over one to
thirty-three years prior to their classification as a discontinued
operation.
When we retire regulated property, plant and equipment accounted for under
SFAS No. 71, we charge accumulated depreciation and amortization for the
original cost, plus the cost to remove, sell or dispose, less its salvage value.
We do not recognize a gain or loss unless we sell an entire operating unit. We
include gains or losses on dispositions of operating units in income. When we
retire regulated property, plant and equipment not accounted for under SFAS No.
71 and non-regulated properties, we reduce property, plant and equipment for its
original cost, less accumulated depreciation, and salvage value. Any remaining
gain or loss is recorded in income.
We capitalize a carrying cost on funds invested in our construction of
long-lived assets. This carrying cost consists of (i) an interest cost on the
investment financed by debt, which applies to both regulated and non-regulated
transmission businesses and (ii) a return on the investment financed by equity,
which only applies to regulated transmission businesses that apply SFAS No. 71.
The debt portion is calculated based on
96
the average cost of debt. Interest cost on debt amounts capitalized during the
years ended December 31, 2002, 2001 and 2000, were $32 million, $63 million and
$75 million (excluding amounts related to discontinued operations of $1 million
for 2002, $2 million for 2001 and $7 million for 2000). These amounts are
included as a reduction of interest expense in our income statements. The equity
portion is calculated using the most recent FERC approved equity rate of return.
Equity amounts capitalized during the years ended December 31, 2002, 2001 and
2000 were $8 million, $8 million and $2 million. These amounts are included as
other non-operating income on our income statement. Capitalized carrying cost
for debt and equity are reflected as an increase in the cost of the asset on our
balance sheet.
Asset Impairments
We apply the provisions of SFAS No. 144, Accounting for the Impairment or
Disposal of Long-Lived Assets, to account for asset impairments. Under this
standard, we evaluate an asset for impairment when events or circumstances
indicate that a long-lived asset's carrying value may not be recovered. These
events include market declines, changes in the manner in which we intend to use
an asset or decisions to sell an asset and adverse changes in the legal or
business environment such as adverse actions by regulators. When we decide to
exit or sell a long-lived asset or group of assets, we adjust the carrying value
of these assets downward, if necessary, to the estimated sales price, less costs
to sell. We also reclassify the asset or assets as either held for sale or as
discontinued operations, depending on whether they have independently
determinable cash flows.
Natural Gas and Oil Properties
We use the full cost method to account for our natural gas and oil
properties. Under the full cost method, substantially all productive and
nonproductive costs incurred in connection with the acquisition, exploration and
development of natural gas and oil reserves are capitalized. These capitalized
amounts include the costs of all unproved properties, internal costs directly
related to acquisition, development and exploration activities and capitalized
interest.
We amortize these costs using the unit of production method over the life
of our proved reserves. Each quarter, we calculate the unit of production
depletion rate based on our estimated production and an estimate of proved
reserves. Capitalized costs associated with unproved properties are excluded
from amortizable costs until these properties are evaluated. Future development
costs and dismantlement, restoration and abandonment costs, net of estimated
salvage values, are included in costs subject to amortization.
Our capitalized costs, net of related income tax effects, are limited to a
ceiling based on the present value of future net revenues using end of period
spot prices discounted at 10 percent, plus the lower of cost or fair market
value of unproved properties, net of related income tax effects. If these
discounted revenues are not equal to or greater than total capitalized costs, we
are required to write-down our capitalized costs to this level. We perform this
ceiling test calculation each quarter. Any required write-downs are included in
our income statement as a ceiling test charge. Our ceiling test calculations
include the effects of derivative instruments we have designated as cash flow
hedges of our anticipated future natural gas and oil production.
We do not recognize a gain or loss on sales of our natural gas and oil
properties, unless those sales would significantly alter the relationship
between capitalized costs and proved reserves. We treat sales proceeds on
non-significant sales as an adjustment to the cost of our properties.
Planned Major Maintenance
Repair and maintenance costs are generally expensed as incurred, unless
they improve the operating efficiency or extend the useful life of an asset.
Included as assets and liabilities from discontinued operations are amounts
associated with planned major maintenance activities related to our petroleum
markets operations (see Note 10). Our petroleum markets operations own and have
interests in domestic and international refineries. In our domestic refining
business, repair and maintenance costs for planned major maintenance activities
are accrued as a liability in a
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systematic and rational manner over the period of time until the planned major
maintenance activities occur. Any difference between the accrued liability and
the actual costs incurred in performing the maintenance activities are charged
or credited to expense at the time the maintenance occurs. At our international
refineries, the cost of each major maintenance activity is capitalized and
amortized to expense in a systematic and rational manner over the estimated
period extending to the next planned major maintenance activity. The types of
costs we accrue in conjunction with major maintenance at our refineries are
outside contractor costs, materials and supplies, company labor and other
outside services. For our domestic operations, we had accruals for major
maintenance of $40 million and $36 million at December 31, 2002 and 2001, and
for our international operations, we capitalized $75 million and $51 million for
the years ended December 31, 2002 and 2001.
Goodwill and Other Intangible Assets
Our intangible assets consist of goodwill resulting from acquisitions and
other intangible assets. We apply SFAS No. 141, Business Combinations, and SFAS
No. 142, Goodwill and Other Intangible Assets to account for these intangibles.
Under these standards, we recognize goodwill separately from other intangible
assets. In addition, goodwill and intangibles that have indefinite lives are not
amortized. Also, goodwill and indefinite lived intangible assets are
periodically tested for impairment, at least annually, or whenever an event
occurs that indicates that an impairment may have occurred. We adopted these
standards on January 1, 2002 and stopped amortizing goodwill. We also recognized
a pretax and after-tax gain of $154 million related to the elimination of
negative goodwill. We reported this gain as a cumulative effect of an accounting
change in our income statement.
SFAS No. 142 requires that we perform impairment tests upon adoption of the
standard on January 1, 2002 and at least annually thereafter. The initial
impairment tests we performed as of January 1, 2002 indicated no impairment of
our goodwill. The impairment tests we performed as of December 31, 2002,
however, indicated a pre-tax impairment of our goodwill associated with our
Merchant Energy segment's financial services businesses, EnCap and Enerplus, of
$44 million. This impairment was recorded in 2002 and was the result of the
combined effects of weak financial services industry conditions and our decision
not to continue to invest capital in these financial services businesses. The
net carrying amounts of our goodwill as of January 1, 2002 and December 31, 2002
reported in net intangible assets in our balance sheets, and the changes in the
net carrying amounts of goodwill for the year ended December 31, 2002 for each
of our segments are as follows:
FIELD MERCHANT CORPORATE &
PIPELINES PRODUCTION SERVICES ENERGY OTHER TOTAL
--------- ---------- -------- -------- ----------- ------
(IN MILLIONS)
Balances as of January 1, 2002..... $413 $61 $393 $ 89 $249 $1,205
Impairments........................ -- -- -- (44) -- (44)
Other changes...................... -- 1 9 -- (5) 5
---- --- ---- ---- ---- ------
Balances as of December 31, 2002... $413 $62 $402 $ 45 $244 $1,166
==== === ==== ==== ==== ======
Our other intangible assets consist of customer lists, our general
partnership interest in El Paso Energy Partners, L.P. and other miscellaneous
intangible assets. We amortize all intangible assets on a straight-line basis
over their estimated useful life excluding our excess investment in our general
partnership interest in
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El Paso Energy Partners which has been determined to have an indefinite life.
The following are the gross carrying amounts and accumulated amortization of our
other intangible assets as of December 31:
2002 2001
----- -----
(IN MILLIONS)
Intangible assets subject to amortization................... $ 49 $ 56
Accumulated amortization.................................... (29) (20)
---- ----
20 36
Intangible assets not subject to amortization............... 181 181
---- ----
$201 $217
==== ====
Amortization expense of our intangible assets that were subject to
amortization was $9 million for the year ended December 31, 2002. For the year
ended December 31, 2001, amortization of all intangible assets, including
goodwill, was $55 million. Based on the current amount of intangible assets
subject to amortization, our estimated amortization expense is approximately $2
million for each of the next five years. These amounts may vary as a result of
future acquisitions, dispositions and any recorded impairments.
The following table presents our income from continuing operations before
extraordinary items and the cumulative effect of accounting changes, net income
and earnings per common share for the years ended December 31, 2001 and 2000, as
if goodwill and other indefinite-lived intangibles had not been amortized during
those periods, compared with those amounts reported for the year ended December
31, 2002:
YEAR ENDED DECEMBER 31,
------------------------
2002 2001 2000
------- ----- ------
(IN MILLIONS, EXCEPT PER
COMMON SHARE AMOUNTS)
Reported income (loss) from continuing operations before
extraordinary items and cumulative effect of accounting
changes(1)................................................ $(1,048) $ 152 $1,113
Amortization of goodwill and indefinite-lived intangibles... -- 35 44
------- ----- ------
Adjusted income (loss) from continuing operations before
extraordinary items and cumulative effect of accounting
changes................................................... $(1,048) $ 187 $1,157
======= ===== ======
Net income (loss):
Reported net income (loss).................................. $(1,467) $ 93 $1,306
Amortization of goodwill and indefinite-lived intangibles... -- 35 44
------- ----- ------
Adjusted net income (loss).................................. $(1,467) $ 128 $1,350
======= ===== ======
Basic earnings per common share:
Reported net income (loss).................................. $ (2.62) $0.18 $ 2.64
Amortization of goodwill and indefinite-lived intangibles... -- 0.07 0.09
------- ----- ------
Adjusted net income (loss).................................. $ (2.62) $0.25 $ 2.73
======= ===== ======
Diluted earnings per common share:
Reported net income (loss).................................. $ (2.62) $0.18 $ 2.57
Amortization of goodwill and indefinite-lived intangibles... -- 0.07 0.09
------- ----- ------
Adjusted net income (loss).................................. $ (2.62) $0.25 $ 2.66
======= ===== ======
---------------
(1) Amounts reflect the classification of the results of our petroleum markets
operations and coal business as discontinued operations.
Pension and Other Postretirement Benefits
We maintain several pension and other postretirement benefit plans. These
plans require us to make contributions to fund the benefits to be paid out under
the plans. These contributions are invested until the benefits are paid out to
plan participants. We record benefit expense in our income statement. This
benefit expense is a function of many factors including benefits earned during
the year by plan participants (which is a
99
function of the employee's salary, the level of benefits provided under the
plan, actuarial assumptions, and the passage of time), expected return on plan
assets and recognition of certain deferred gains and losses as well as plan
amendments.
We compare the benefits earned, or the accumulated benefit obligation, to
the plan's fair value of assets on an annual basis. To the extent the plan's
accumulated benefit obligation exceeds the fair value of plan assets, we record
a minimum pension liability in our balance sheet equal to the difference in
these two amounts. We do not adjust this minimum liability if it is less than
the liability already accrued for the plan. If this difference is greater than
the pension liability recorded on our balance sheet, however, we record an
additional liability and an amount to other comprehensive loss, net of income
taxes, on our financial statements.
Revenue Recognition
Our business segments provide a number of services and sell a variety of
products. Our revenue recognition policies by segment are as follows:
Pipelines revenues. Our Pipelines segment derives revenues primarily from
transportation and storage services and sales under gas sales contracts. For our
transportation and storage services, we recognize reservation revenues on firm
contracted capacity ratably over the contract period. For interruptible or
volumetric based services, we record revenues when we complete the delivery of
natural gas to the agreed upon delivery point and when natural gas is injected
or withdrawn from the storage facility. Revenues under natural gas sales
contracts are recognized when physical deliveries of commodities are made at the
agreed upon delivery point. Revenues in all services are generally based on the
thermal quantity of gas delivered or subscribed at a price specified in the
contract or tariff. We are subject to FERC regulations and, as a result,
revenues we collect may possibly be refunded in a final order of a pending or
future rate proceeding or as a result of a rate settlement. We have established
reserves for these potential refunds.
Production revenues. Our Production segment's revenues are derived
principally through physical sales of natural gas, oil and natural gas liquids
produced. Revenues from sales of these products are recorded upon the passage of
title using the sales method, net of any royalty interests or other profit
interests in the produced product. When actual natural gas sales volumes exceed
our entitled share of sales volumes, an overproduced imbalance occurs. To the
extent the overproduced imbalance exceeds our share of the remaining estimated
proved natural gas reserves for a given property, we record a liability. Costs
associated with the transportation and delivery of production are included in
cost of sales.
Field Services revenues. Our Field Services segment derives revenues
principally from gathering, transportation and processing services and through
the sale of commodities that are retained from providing these services. There
are two general types of service: fee-based and make-whole. For fee-based
services we recognize revenues at the time service is rendered based upon the
volume of gas gathered, treated or processed at the contracted fee. For
make-whole services, our fee consists of retainage of natural gas liquids and
other by-products that are a result of processing, and we recognize revenues on
these services at the time we sell these products, which generally coincides
with when we provide the service.
Merchant Energy revenues. Merchant Energy derives revenues from a number
of sources including physical sales of natural gas, power and petroleum.
Revenues on these physical sales are recognized based on the volumes delivered
and the contracted or market price and are recognized at the time the commodity
is delivered to the specified delivery point. Revenues from commodities sold as
part of Merchant Energy's energy trading division are reflected net of the cost
of these sales. The energy trading division of Merchant Energy also enters into
derivative transactions which are recorded at their fair value. See a discussion
of our income recognition policies on derivatives below under Price Risk
Management Activities.
Corporate. Revenue producing activities in our corporate segment consist
principally of revenues from our telecommunications business. We recognize
revenues for our metro transport, collocation and cross-connect services in the
month that the services are actually used by the customer.
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Discontinued Petroleum Markets Operations. Our discontinued petroleum
markets operations derive their revenue from the sale of crude oil, refined
petroleum products and chemicals. Revenues from the products sold in this
business are based on the contractual terms of the sale, and are usually
referenced to the market price of the commodity sold.
Environmental Costs and Other Contingencies
We record liabilities when our environmental assessments indicate that
remediation efforts are probable, and the costs can be reasonably estimated. We
recognize a current period expense for the liability when clean-up efforts do
not benefit future periods. We capitalize costs that benefit more than one
accounting period, except in instances where separate agreements or legal or
regulatory guidelines dictate otherwise. Estimates of our liabilities are based
on 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 estimates are subject to revision in future periods based
on actual costs or new circumstances and are included in our balance sheet in
other current and long-term liabilities at their undiscounted amounts. We
evaluate recoveries from insurance coverage or government sponsored programs
separately from our liability and, when recovery is assured, we record and
report an asset separately from the associated liability in our financial
statements.
We recognize liabilities for other contingencies when we have an exposure
that, when fully analyzed, indicates it is both probable that an asset has been
impaired or that a liability has been incurred and the amount of impairment or
loss can be reasonably estimated. Funds spent to remedy these contingencies are
charged against a reserve, if one exists, or expensed. When a range of probable
loss can be estimated, we accrue the most likely amount or at least the minimum
of the range of probable loss.
Price Risk Management Activities
We engage in price risk management activities to manage market risks
associated with commodities we purchase and sell, interest rates and foreign
currency exchange rates. These price risk management activities include trading
activities that we enter into with the objective of generating profits or from
exposure to shifts or changes in market prices, non-trading activities related
to our power investment, generation and power contract restructuring activities,
and other non-trading activities that involve hedging the market price risk
exposures on our assets, liabilities, contractual commitments and forecasted
transactions of each of our business segments. Our trading and non-trading price
risk management activities involve the use of a variety of derivative financial
instruments, including:
- exchange-traded futures contracts that involve cash settlements;
- forward contracts that involve cash settlements or physical delivery of a
commodity;
- swap contracts that require payments to (or receipts from) counterparties
based on the difference between a fixed and a variable price, or two
variable prices, for a commodity; and
- exchange-traded and over-the counter options.
We account for our trading and non-trading derivative instruments under
SFAS No. 133, Accounting for Derivatives and Hedging Activities. Under SFAS No.
133, all derivatives are reflected in our balance sheet at their fair value as
price risk management activities. We classify our price risk management
activities as either current or non-current assets or liabilities based on our
overall position by counterparty and their anticipated settlement date. Cash
inflows and outflows associated with the settlement of our price risk management
activities are recognized in operating cash flows, and any receivables and
payables resulting from these settlements are reported separately from price
risk management activities in our balance sheet as trade receivables and
payables. The accounting for revenues and expenses associated with our price
risk management activities varies based on whether those activities are trading
activities or non-trading activities. See Note 13 for a further description of
our price risk management activities.
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During 2002, we adopted DIG Issue No. C-16, Scope Exceptions: Applying the
Normal Purchases and Sales Exception to Contracts that Combine a Forward
Contract and Purchased Option Contract. DIG Issue No. C-16 requires that if a
fixed-price fuel supply contract allows the buyer to purchase, at their option,
additional quantities at a fixed-price, the contract is a derivative that must
be recorded at its fair value. One of our unconsolidated affiliates, the Midland
Cogeneration Venture Limited Partnership, recognized a gain on one fuel supply
contract upon adoption of these new rules, and we recorded a gain of $14
million, net of income taxes, as a cumulative effect of an accounting change in
our income statement for our proportionate share of this gain.
During 2002, we also adopted the provisions of EITF Issue No. 02-3, Issues
Related to Accounting for Contracts Involved in Energy Trading and Risk
Management Activities. Prior to EITF Issue No. 02-3, we accounted for our
non-derivative trading instruments, such as contracts for transportation and
storage capacity and physical natural gas inventory and exchanges that were
actively traded as part of our trading business, at their fair value under EITF
Issue No. 98-10, Accounting for Contracts Involved in Energy Trading and Risk
Management Activities. EITF Issue No. 02-3 rescinded EITF Issue No. 98-10 and
reached two general conclusions:
- Contracts which do not meet the definition of a derivative under SFAS No.
133 should not be marked to fair market value, and
- Revenues and costs associated with trading activities should be shown net
in the income statement, whether or not they are physically settled.
As a result of our adoption of EITF Issue No. 02-3, we adjusted the
carrying value of our non-derivative trading instruments (principally
transportation and storage capacity contracts) to zero and now account for them
using the accrual basis of accounting. We also adjusted the physical natural gas
inventory and exchanges used in our trading business to their actual cost (which
was lower than market) and expected settlement amounts and reclassified these
amounts to inventory and accounts receivable and payable on our balance sheet.
The adoption of EITF Issue No. 02-3 had the following impacts on our financial
statements:
- The elimination of the mark-to-market value for contracts that do not
meet the definition of a derivative ($225 million), which is reported as
a cumulative effect of change in accounting principle;
- An adjustment of the carrying value of our natural gas inventory to its
weighted average cost and the value of exchanges to their expected
settlement price assuming they had been accounted for under that basis
since their acquisition ($118 million), which is reported as a cumulative
effect of change in accounting principle; and
- A balance sheet reclassification of natural gas inventory and exchanges
from price risk management assets to inventory and accounts receivable
and payable ($254 million).
In total, we recorded a cumulative effect of an accounting change in our
income statement of $343 million ($222 million net of income taxes) from the
adoption of EITF Issue No. 02-3. We also began to report our trading activity on
a net basis (revenues net of the expenses of the physically settled purchases)
as a component of revenues effective July 1, 2002. We applied this guidance to
all prior periods, which had no
102
impact on previously reported net income or stockholders' equity. Revenues and
costs for periods prior to the adoption of EITF Issue No. 02-3 are revised as
follows:
YEAR ENDED DECEMBER 31,
-----------------------
2001 2000
---------- ----------
(IN MILLIONS)
Gross operating revenues(1)................................. $ 36,825 $ 27,372
Costs reclassified(2)....................................... (27,886) (20,184)
-------- --------
Net operating revenues reported in the income
statements............................................. $ 8,939 $ 7,188
======== ========
---------------
(1) These amounts do not include petroleum markets revenues included as
discontinued operations of $20.3 billion for 2001 and $21.3 billion for
2000.
(2) These amounts do not include petroleum markets costs included as
discontinued operations of $15.6 billion for 2001 and $9.2 billion for 2000.
Income Taxes
We report current income taxes based on our taxable income, and we provide
for deferred income taxes to reflect estimated future tax payments and receipts.
Deferred taxes represent the tax impacts of differences between the financial
statement and tax bases of assets and liabilities and carryovers at each year
end. We account for tax credits under the flow-through method, which reduces the
provision for income taxes in the year the tax credits first become available.
We reduce deferred tax assets by a valuation allowance when, based on our
estimates, it is more likely than not that a portion of those assets will not be
realized in a future period. The estimates utilized in recognition of deferred
tax assets are subject to revision, either up or down, in future periods based
on new facts or circumstances.
We maintain a tax accrual policy to record both regular and alternative
minimum taxes for companies included in our consolidated federal income tax
return. The policy provides, among other things, that (i) each company in a
taxable income position will accrue a current expense equivalent to its federal
income tax, and (ii) each company in a tax loss position will accrue a benefit
to the extent its deductions, including general business credits, can be
utilized in the consolidated return. We pay all federal income taxes directly to
the IRS and, under a separate tax billing agreement, we may bill or refund our
subsidiaries for their portion of these income tax payments.
Foreign Currency Transactions and Translation
We record all currency transaction gains and losses in income. These gains
or losses are classified in our income statement based upon the nature of the
transaction that gives rise to the currency gain or loss. For sales and
purchases of commodities or goods, these gains or losses are included in
operating revenue or expense. For gains and losses arising through equity
investees, we record these gains or losses as equity earnings. For gains or
losses on foreign denominated debt, we include these gains or losses as a
component of interest expense. During 2002, the net currency gain recorded in
operating income was less than $1 million. Net currency losses recorded to
operating income in 2001 and 2000 were $13 million and less than $1 million. We
incurred currency losses in 2002 of approximately $95 million on our
euro-denominated debt which were included in interest expense. Gains and losses
were minimal on foreign denominated debt in 2001 and 2000. The U.S. dollar is
the functional currency for the majority of our foreign operations. For foreign
operations whose functional currency is deemed to be other than the U.S. dollar,
assets and liabilities are translated at year-end exchange rates and included as
a separate component of comprehensive income and stockholders' equity. The
cumulative currency translation loss recorded in accumulated other comprehensive
income was $115 million and $97 million at December 31, 2002 and 2001. Revenues
and expenses are translated at average exchange rates prevailing during the
year.
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Treasury Stock
We account for treasury stock using the cost method and report it in our
balance sheet as a reduction to stockholders' equity. Treasury stock sold or
issued is valued on a first-in, first-out basis. Included in treasury stock at
December 31, 2002, and 2001, were approximately 1.7 million shares and 5.5
million shares of common stock held in a trust under our deferred compensation
programs.
Stock-Based Compensation
We apply the provisions of Accounting Principles Board Opinion No. 25 (APB
No. 25) and its related interpretations to account for our stock-based
compensation plans. We have both fixed and variable compensation plans, and we
account for these plans using fixed and variable accounting as appropriate.
Compensation expense for variable plans, including restricted stock grants, is
measured using the market price of the stock on the date the number of shares in
the grant becomes determinable. This measured expense is amortized into income
over the period of service in which the grant is earned. Our stock options are
issued under a fixed plan. Accordingly, compensation expense is not recognized
for stock options unless the options were granted at an exercise price lower
than market on the grant date. Had we accounted for our stock option grants
using SFAS No. 123 Accounting for Stock-Based Compensation, rather than the
provisions of APB No. 25, the income and per share impacts of stock-based
compensation on our financial statements of stock-based compensation would have
been different. The following shows the impact on net income and earnings per
share had we applied the provisions of SFAS No. 123.
YEAR ENDED DECEMBER 31,
-------------------------------
2002 2001 2000
--------- -------- --------
(IN MILLIONS, EXCEPT PER COMMON
SHARE AMOUNTS)
Net income (loss), as reported............................ $(1,467) $ 93 $1,306
Deduct: Total stock-based employee compensation determined
under fair value based method for all awards, net of
related tax effects..................................... 143 157 43
------- ------ ------
Pro forma net income (loss)............................... $(1,610) $ (64) $1,263
======= ====== ======
Earnings (loss) per share:
Basic, as reported........................................ $ (2.62) $ 0.18 $ 2.64
======= ====== ======
Basic, pro forma.......................................... $ (2.88) $(0.13) $ 2.56
======= ====== ======
Diluted, as reported...................................... $ (2.62) $ 0.18 $ 2.57
======= ====== ======
Diluted, pro forma........................................ $ (2.88) $(0.12) $ 2.48
======= ====== ======
Accounting for Debt Extinguishments
We apply the provisions of SFAS No. 145, Rescission of FASB Statements No.
4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections, to
account for debt extinguishments. Under SFAS No. 145, we are required to
evaluate any gains or losses incurred when we retire debt early to determine
whether they are extraordinary in nature or whether they should be included as
ordinary income from continuing operations in the income statement. In the third
quarter of 2002, we retired debt totaling $94 million, which resulted in a gain
of $21 million. Because we believe that we will continue to retire debt in the
near term, we reported these gains as income from continuing operations, as part
of other income.
New Accounting Pronouncements Issued But Not Yet Adopted
As of December 31, 2002, there were a number of accounting standards and
interpretations that had been issued but not yet adopted by us. Below is a
discussion of the more significant standards that could impact us.
Accounting for Asset Retirement Obligations. In June 2001, the Financial
Accounting Standards Board (FASB) issued SFAS No. 143, Accounting for Asset
Retirement Obligations. This statement requires
104
companies to record a liability for the estimated retirement and removal costs
of long-lived assets used in their business. The liability is recorded at its
fair value, with a corresponding asset which is depreciated over the remaining
useful life of the long-lived asset to which the liability relates. An ongoing
expense will also be recognized for changes in the value of the liability as a
result of the passage of time. The provisions of SFAS No. 143 are effective for
fiscal years beginning after June 15, 2002. We expect that we will record a
charge as a cumulative effect of accounting change of approximately $23 million,
net of income taxes, upon our adoption of SFAS No. 143 on January 1, 2003. We
also expect to record non-current retirement assets of $184 million and
non-current retirement liabilities of $214 million on January 1, 2003. Our
liability relates primarily to our obligations to plug abandoned wells in our
Production and Pipelines segments over the next one to 101 years.
Accounting for Costs Associated with Exit or Disposal Activities. In July
2002, the FASB issued SFAS No. 146, Accounting for Costs Associated with Exit or
Disposal Activities. This statement will require us to recognize costs
associated with exit or disposal activities when they are incurred rather than
when we commit to an exit or disposal plan. Examples of costs covered by this
guidance include lease termination costs, employee severance costs associated
with a restructuring, discontinued operations, plant closings or other exit or
disposal activities. The statement is effective for fiscal years beginning after
December 31, 2002, and will impact any exit or disposal activities we initiate
after January 1, 2003.
Accounting for Guarantees. In November 2002, the FASB issued FASB
Interpretation (FIN) No. 45, Guarantor's Accounting and Disclosure Requirements
for Guarantees, Including Indirect Guarantees of Indebtedness of Others. This
interpretation requires that companies record a liability for all guarantees
issued after January 31, 2003, including financial, performance, and fair value
guarantees. This liability is recorded at its fair value upon issuance, and does
not affect any existing guarantees issued before January 31, 2003. This standard
also requires expanded disclosures on all existing guarantees at December 31,
2002. We have included these required disclosures in Note 20.
Consolidation of Variable Interest Entities. In January 2003, the FASB
issued FIN No. 46, Consolidation of Variable Interest Entities, an
Interpretation of ARB No. 51. This interpretation defines a variable interest
entity as a legal entity whose equity owners do not have sufficient equity at
risk and/or a controlling financial interest in the entity. This standard
requires that companies consolidate a variable interest entity if it is
allocated a majority of the entity's losses and/or returns, including fees paid
by the entity. The provisions of FIN No. 46 are effective for all variable
interest entities created after January 31, 2003, and are effective on July 1,
2003 for all variable interest entities created before January 31, 2003. We have
financial interests in several entities that we anticipate will be considered
variable interest entities. They fall into three categories:
- Operating leases with residual value guarantees;
- Consolidated subsidiaries with preferred interests held by third party
financial investors; and
- Equity investments.
Operating leases with residual value guarantees. We have two operating
leases where we provide a guarantee to the lessor for the residual value of the
facilities that we lease. These leases are for the following facilities:
- The Lakeside Technology Center, a telecommunications facility that
provides collocation and cross-connect services; and
- A facility at our Aruba refinery (which is classified as discontinued
operations).
We believe we will consolidate the lessors under these arrangements on July
1, 2003 because (i) the equity investment by the third party investors (which
are banks), is less than 10 percent of the total capitalization of the company
that leases the facilities to us, and (ii) because we guarantee a significant
portion of the funds that were borrowed by the lessor to buy the facilities from
us. When we consolidate the lessors of these facilities, the assets owned by the
lessors and the debt that supports the assets will be consolidated in our
financial statements. In addition, these assets, once consolidated, will be
subject to
105
impairment testing under SFAS No. 144. Based on our preliminary analysis, we
believe the impact on our financial statements will be as follows (in millions):
Increase in total assets.................................... $625(1)
Less: Impairments........................................... 113
----
Net increase in assets...................................... $512
Increase in long-term debt.................................. $625(1)
---------------
(1) Included in these amounts is $370 million related to the lease at our Aruba
refinery. The assets and liabilities related to this lease, once
consolidated, will be included in the assets and liabilities of our
discontinued operations (see Note 10).
Consolidated subsidiaries with preferred interests held by third party
investors. We currently have interests in and consolidate several entities in
which third party investors hold preferred interests. The preferred interests
held by the third party investors are reflected in our balance sheet as
preferred securities in consolidated subsidiaries. The third party investors are
capitalized with three percent equity, which is held by banks in these
arrangements, and 97 percent debt. We believe we would consolidate these third
party investors under these arrangements because (i) the equity investment in
these third party investors is less than the specified 10 percent of total
capitalization of the investors and (ii) the rights of the third party investors
to expected residual returns from these arrangements is limited. When we
consolidate these third party investors, the minority interest that is currently
classified as preferred securities in consolidated subsidiaries will be
classified as long-term debt. Clydesdale and Coastal Securities Company Limited
are our consolidated subsidiaries that will be impacted by this standard. If we
had not redeemed our Trinity River financing arrangement in March 2003, it would
also have been impacted by this standard. We believe the impact on our financial
statements will be (in millions):
Decrease in preferred securities of consolidated
subsidiaries.............................................. $1,050
Increase in long-term debt.................................. $1,050
For a further discussion of the consolidated subsidiaries potentially
impacted by this pronouncement, see Note 19.
Equity investments. We have equity investments in Chaparral and Gemstone.
These power investments involve a disproportionate allocation of income and
losses relative to the capital investments that are made by the equity holders.
To determine whether we would be required to consolidate these entities, we
evaluated the expected future losses of the entities, and how those losses would
be allocated to the owners. If we determined that we would be exposed to the
greatest level of the expected future losses, we would consolidate those
entities. Based on our analysis, we determined it is likely that we will
consolidate these investments because of our guarantee of the debt of the third
party investors which exposes us to a greater level of loss. However, we
anticipate that we will consolidate these investments prior to the effective
date of FIN No. 46 because we expect to purchase the third party investors'
interests in these investments. For a discussion of the equity investments we
hold, see Note 26.
2. WESTERN ENERGY SETTLEMENT
On March 20, 2003, we entered into an agreement in principle (Western
Energy Settlement) with various public and private claimants, including the
states of California, Washington, Oregon and Nevada, to resolve the principal
litigation, claims and regulatory proceedings against us and our subsidiaries
relating to the sale or delivery of natural gas and electricity from September
1996 to the date of the settlement. See Note 20 for a discussion of this matter.
The Western Energy Settlement resulted in a charge in the fourth quarter of
2002 of $899 million before tax and approximately $650 million after tax. These
amounts represent the present value of the components of the settlement
discounted at 10 percent. The settlement will include an initial payment of
cash, the issuance of our common stock and the payment of cash and delivery of
natural gas over a period of 20 years. The settlement will become payable
beginning with the execution of a definitive settlement agreement. Components of
the settlement were allocated among our Pipelines, Merchant Energy and Corporate
106
segments, based on the nature of the component and the segment's ability to
perform under the agreement. The components are as follows:
- a cash payment of $100 million to the settling parties;
- a $2 million cash payment from our officer bonus pool;
- the issuance of approximately 26.4 million shares of our common stock;
- the delivery to the California border of $45 million worth of natural gas
annually for 20 years, beginning in 2004;
- the reduction of the pricing of our long-term power supply contracts with
the California Department of Water Resources of $125 million over the
remaining term of those contracts, which run through the end of 2005;
- payment to the settling parties of $22 million a year in cash (or, at our
option, in cash and stock) for 20 years;
- for a period of five years, EPNG will make available at its California
delivery points, 3,290 MMcf/d of capacity on a primary delivery point
basis;
- for a period of five years, our affiliate will be subject to restrictions
in subscribing new capacity on the EPNG system; and
- no admission of wrongdoing.
The settlement is subject to review and approval by state courts and the
FERC.
The total obligation for the settlement is reflected in our balance sheet
at $0.9 billion, which represents the notional amount of approximately $1.7
billion, less a discount (at a rate of 10 percent) of approximately $0.8
billion. The components of the obligation for the settlement are as follows:
(IN MILLIONS)
Total Western Energy Settlement............................. $1,690
Discount at 10 percent...................................... (791)
------
Net present value at settlement............................. 899
Less: Current portion of obligation......................... 100
------
Non-current obligation for Western Energy Settlement........ $ 799
======
The discount will be amortized to interest expense annually at an amount
based on a constant rate of interest (10 percent) applied to the declining
obligation balance. This amortization is expected to be approximately $47
million for 2003, after income taxes.
107
3. MERGERS AND DIVESTITURES
Coastal Merger
In January 2001, we merged with Coastal. We accounted for the transaction
as a pooling of interests and converted each share of Coastal's common stock and
Class A common stock on a tax-free basis into 1.23 shares of our common stock.
We also exchanged Coastal's outstanding convertible preferred stock for our
common stock on the same basis as if the preferred stock had been converted into
Coastal common stock immediately prior to the merger. In the merger, we issued
approximately 271 million shares of our common stock, including 4 million shares
in exchange for Coastal stock options. The following table presents the
revenues, extraordinary items and net income for the previously separate
companies and the combined amounts presented in these audited combined financial
statements for the year ended December 31, 2000 (in millions). Several
adjustments were made to conform the accounting presentation of this financial
information.
Revenues
El Paso................................................... $21,950
Coastal................................................... 18,014
Conforming reclassifications(1)........................... 8,951
-------
Combined(2)............................................... $48,915
=======
Extraordinary items, net of income taxes
El Paso................................................... $ 70
Coastal................................................... --
-------
Combined.................................................. $ 70
=======
Net income
El Paso................................................... $ 652
Coastal................................................... 654
-------
Combined.................................................. $ 1,306
=======
---------------
(1) Conforming reclassifications primarily include a gross-up of revenues
associated with Coastal's physical petroleum marketing and trading
activities to be consistent with our method of reporting these revenues.
These revenues were reclassified as discontinued operations.
(2) Combined revenues do not take into account the adoption of a consensus
reached on EITF Issue No. 02-3, which requires us to report all physical
sales of energy commodities in our energy trading activities on a net basis
as a component of revenues. The impact of EITF Issue No. 02-3 on reported
2000 revenues was a reduction of these combined amounts by $29.4 billion.
These amounts also do not consider $12.7 billion of revenues related to
petroleum markets and coal mining businesses, which have been classified in
our financial statements as discontinued operations. See Notes 1 and 10 for
further discussion of these matters.
108
Divestitures
During 2002 and into 2003, we have completed or announced a number of asset
sales in order to rationalize our business and address liquidity issues and
changing market conditions. These sales occurred in all of our business segments
and in our discontinued operations as follows:
PRETAX
SEGMENT PROCEEDS GAIN (LOSS) SIGNIFICANT ASSETS AND INVESTMENTS SOLD
------- -------- ----------- ---------------------------------------
(IN MILLIONS)
Completed in 2002
Pipelines $ 303 $ 4 Natural gas and oil properties located in Texas, Kansas and
Oklahoma and their related contracts
12.3 percent equity interest in Alliance Pipeline and
related assets
Typhoon natural gas pipeline(3)
Production 1,297 --(1) Natural gas and oil properties located in:
East and south Texas
Colorado
Southeast Texas
Utah
Western Canada
Field Services 1,513 196 Texas and New Mexico midstream assets(2)
Dragon Trail processing plant
San Juan Basin gathering, treating and processing assets(3)
14.4 percent equity interest in Aux Sable NGL plant
Gathering facilities located in Utah
50 percent interest in Blacks Fork facility
Merchant Energy 90 2 40 percent equity interest in Samalayuca Power II power
project in Mexico
------ ----
Continuing
Operations $3,203 $202
====== ====
Discontinued
Operations $ 128 $ (3) Coal reserves and properties in West Virginia, Virginia and
====== ====
Kentucky(4)
50 percent equity interest in petroleum products terminal
14.4 percent equity interest in Alliance Canada Marketing
L.P.
Typhoon oil pipeline(3)
NGL pipelines and fractionation facilities(3)
---------------
(1) We did not recognize gains or losses on these completed sales of natural gas
and oil properties because individually they did not significantly alter the
relationship between capitalized costs and proved reserves at the time they
were sold.
(2) Proceeds of $735 million consisted of $539 million in cash, common units of
El Paso Energy Partners with a fair value of $6 million and the
partnership's interest in the Prince tension leg platform including its nine
percent overriding royalty interest in the Prince production field with a
combined fair value of $190 million.
(3) Proceeds from these sales of $766 million consisted of $416 million in cash
and $350 million of Series C units, a new non-voting class of the limited
partnership interest in El Paso Energy Partners.
(4) During 2002, we recorded impairment charges of $185 million since the
carrying value was higher than our estimated net sales proceeds. These
properties are presented in our financial statements as discontinued
operations. See Note 10 for further discussion.
109
PRETAX SIGNIFICANT ASSETS AND
SEGMENT PROCEEDS GAIN (LOSS) INVESTMENTS SOLD
------- -------- ----------- ----------------------
(IN MILLIONS)
Announced or Completed in 2003 (amounts are estimates)(1)
Pipelines $ 43 $ (1) Panhandle gathering system located in Texas
2.1 percent equity interest in Alliance pipeline and
related assets
Production 687 --(2) Natural gas and oil properties located in western Canada,
Oklahoma, New Mexico and offshore.
Field Services 35 -- Gathering systems located in Wyoming
Merchant Energy 295 6 50 percent equity interest in CE Generation L.L.C. power
investment (including the rights to a 50 percent interest
in a geothermal development project)(3)
Mt. Carmel power plant
Kladno power project
Enerplus Global Energy Management Company
Corporate and
Other 30 (8) Aircraft
------- -------
Continuing
Operations $ 1,090 $ (3)
======= =======
Discontinued
Operations $ 577 $ 63 Remaining coal reserves and properties in West Virginia,
======= ======= Virginia and Kentucky(5)
Corpus Christi refinery
Florida petroleum terminals and tug and barge operations(4)
Petroleum asphalt operations
---------------
(1) Sales that have been announced, but not completed, are subject to customary
regulatory approvals and other conditions.
(2) We do not anticipate recognizing gains or losses on these sales of natural
gas and oil properties because individually they will not significantly
alter the relationship between capitalized costs and proved reserves at the
time they are sold.
(3) During 2002, we recorded impairment charges of $74 million resulting from an
expected sale of our ownership interests.
(4) The amount includes $25 million receivable.
(5) Proceeds of $59 million consisted of $35 million in cash and $24 million in
notes receivable.
In December 2002, we reclassified several of Field Services' small
gathering systems located in Wyoming to assets held for sale. The total assets
being sold had a net book value in property, plant and equipment of
approximately $31 million. We reclassified these assets as other current assets
as of December 31, 2002, since we plan to sell them in the next twelve months.
Under a Federal Trade Commission order, as a result of our January 2001
merger with Coastal, we sold our Midwestern Gas Transmission system, our
Gulfstream pipeline project, our 50 percent interest in the Stingray and U-T
Offshore pipeline systems, and our investments in the Empire State and Iroquois
pipeline systems. For the year ended December 31, 2001, net proceeds from these
sales were approximately $279 million, and we recognized extraordinary net gains
of approximately $26 million, net of income taxes of approximately $27 million.
During 2000, we sold East Tennessee Natural Gas Company, Sea Robin Pipeline
Company and our one-third interest in Destin Pipeline Company to comply with an
FTC order related to our merger with Sonat. Net proceeds from these sales were
approximately $616 million, and we recognized an extraordinary gain of $89
million, net of income taxes of $59 million. In December 2000, we sold our
interest in Oasis Pipeline Company to comply with an FTC order. We incurred a
loss on this transaction of approximately $19 million, net of income taxes of $9
million. We recorded the gains and losses on these sales as extraordinary items
in our income statement.
110
4. RESTRUCTURING AND MERGER-RELATED COSTS
During each of the three years ended December 31, we incurred restructuring
costs, merger-related costs and asset impairment charges as follows:
2002 2001 2000
---- ------ ----
(IN MILLIONS)
Restructuring costs......................................... $77 $ -- $--
Merger-related costs........................................ -- 1,493 93
--- ------ ---
Total from continuing operations....................... $77 $1,493 $93
=== ====== ===
Discontinued operations..................................... $ 4 $ 27 $--
=== ====== ===
Restructuring Costs
Our restructuring costs were incurred in connection with organizational
restructurings in connection with our balance sheet and liquidity enhancement
actions taken in 2002. By segment, these charges were as follows:
CONTINUING OPERATIONS
------------------------------------------- TOTAL
FIELD MERCHANT CORPORATE CONTINUING DISCONTINUED
PIPELINES SERVICES ENERGY AND OTHER OPERATIONS OPERATIONS
--------- -------- -------- --------- ---------- ------------
(IN MILLIONS)
Employee severance,
retention and
transition costs....... $ 1 $ 1 $24 $11 $37 $ 4
Transaction costs........ -- -- -- 40 40 --
--- --- --- --- --- ---
$ 1 $ 1 $24 $51 $77 $ 4
=== === === === === ===
In December 2001, we announced a plan to strengthen our balance sheet,
reduce costs and focus our activities on our core natural gas businesses. During
2002, we completed an employee restructuring across all of our operating
segments which resulted in a reduction of approximately 772 full-time positions
through terminations. As a result of these actions, we incurred $41 million of
employee severance and termination costs, $30 million of which had been paid as
of December 31, 2002. We also incurred and paid fees of $40 million to eliminate
stock price and credit rating triggers related to our Chaparral and Gemstone
investments.
111
Merger-Related Costs
During the years ended 2001 and 2000, we incurred merger-related costs in
connection with our merger with Coastal completed in January 2001 as follows:
CONTINUING OPERATIONS
-------------------------------------------------------- TOTAL
FIELD MERCHANT CORPORATE CONTINUING DISCONTINUED
PIPELINES PRODUCTION SERVICES ENERGY AND OTHER OPERATIONS OPERATIONS
--------- ---------- -------- -------- --------- ---------- ------------
(IN MILLIONS)
2001
Employee severance,
retention and
transition costs.... $ 83 $ 7 $ 5 $ 2 $ 725 $ 822 $16
Transaction costs..... -- -- -- -- 70 70 --
Business and
operational
integration costs... 178 17 -- -- 188 383 --
Other................. 30 23 41 15 109 218 11
---- --- --- --- ------ ------ ---
$291 $47 $46 $17 $1,092 $1,493 $27
==== === === === ====== ====== ===
2000
Employee severance,
retention and
transition costs.... $ -- $-- $-- $-- $ 31 $ 31 $--
Transaction costs..... -- -- -- -- 60 60 --
Other................. -- -- -- -- 2 2 --
---- --- --- --- ------ ------ ---
$ -- $-- $-- $-- $ 93 $ 93 $--
==== === === === ====== ====== ===
Employee severance, retention and transition costs include direct payments
to, and benefit costs for, severed employees and early retirees that occurred as
a result of our merger-related workforce reduction and consolidation. Following
the Coastal merger, we completed an employee restructuring across all of our
operating segments, resulting in the reduction of 3,285 full-time positions
through a combination of early retirements and terminations. Employee severance
costs include actual severance payments and costs for pension and
post-retirement benefits settled and curtailed under existing benefit plans as a
result of these restructurings. Retention charges include payments to employees
who were retained following the mergers and payments to employees to satisfy
contractual obligations. Transition costs relate to costs to relocate employees
and costs for severed and retired employees arising after their severance date
to transition their jobs into the ongoing workforce.
Employee severance, retention and transition costs for 2001 were
approximately $838 million, which included pension and post-retirement benefits
of $214 million which were accrued on the merger date and will be paid over the
applicable benefit periods of the terminated and retired employees. All other
costs were expensed as incurred and have been paid. Also included in the 2001
employee severance, retention and transition costs was a charge of $278 million
resulting from the issuance of approximately 4 million shares of common stock on
the date of the Coastal merger in exchange for the fair value of Coastal
employees' and directors' stock options and restricted stock. A total of 339
employees and 11 directors received these shares.
Transaction costs include investment banking, legal, accounting, consulting
and other advisory fees incurred to obtain federal and state regulatory
approvals and take other actions necessary to complete our mergers. All of these
items were expensed in the periods in which they were incurred.
Business and operational integration costs include charges to consolidate
facilities and operations of our business segments. Total charges in 2001 were
$383 million, of which $153 million related to a charge resulting from a
mark-to-market loss on an energy-related contract for transportation capacity on
the Alliance Pipeline. Prior to the merger, this contract was managed by
Coastal's Production segment. Following the merger, it was determined that this
contract should be managed in our trading group, consistently with our
112
other energy-related pipeline capacity contracts. As a result, it was
transferred to Merchant Energy. The charge reflects the estimated realizable
value of the contract as an energy-related trading contract. Our integration
costs also include incremental fees under software and seismic license
agreements of $15 million which were recorded in our Production segment.
Additional integration costs included approximately $222 million in estimated
lease-related costs to relocate our pipeline operations from Detroit, Michigan
to Houston, Texas and from El Paso, Texas to Colorado Springs, Colorado, $13
million of which was recorded as an impairment of assets and was incurred in
both our Pipelines and Corporate segments. These charges were accrued at the
time we completed our relocations and closed these offices. The amounts accrued
will be paid over the term of the applicable non-cancelable lease agreements.
All other costs were expensed as incurred.
Other costs include payments made in satisfaction of obligations arising
from the FTC approval of our merger with Coastal and other miscellaneous
charges. As part of the FTC order related to our merger with Coastal, El Paso
Energy Partners, L.P. was required to sell its interests in seven natural gas
pipeline systems, a dehydration facility and two offshore platforms. Proceeds
from the sales of these assets were approximately $135 million and resulted in a
loss to the partnership of approximately $25 million. As consideration for these
sales, we committed to pay El Paso Energy Partners a series of payments totaling
$29 million, and were required to contribute $40 million to a trust related to
one of the assets sold by El Paso Energy Partners. We expensed these items at
the same time we committed to pay them.
5. (GAIN) LOSS ON LONG-LIVED ASSETS
(Gain) loss on long-lived assets from continuing operations consist of
realized gains and losses on sales of long-lived assets and impairments of
long-lived assets. During each of the years ended December 31, our (gains)
losses on long-lived assets were as follows:
2002 2001 2000
----- ---- ----
(IN MILLIONS)
Continuing operations
Realized (gain) loss...................................... $(259) $ 2 $(12)
Asset impairments......................................... 444 75 11
----- ---- ----
(Gain) loss on long-lived assets from continuing
operations........................................... $ 185 $ 77 $ (1)
===== ==== ====
Discontinued operations..................................... $ 281 $106 $ 4
===== ==== ====
Realized (Gain) Loss
Our realized (gain) loss on sales of long-lived assets from continuing
operations for the years ended December 31, 2002, 2001 and 2000, were $(259)
million, $2 million and $(12) million. Our 2002 gains were primarily a result of
asset sales to enhance our liquidity related to the sales of our San Juan
gathering assets, our Natural Buttes and Ouray gathering system, our Dragon
Trail processing plant and our Texas and New Mexico midstream assets in our
Field Services segment. See Note 3 for a further discussion of these
divestitures. Our 2001 losses related to miscellaneous asset sales across all
our segments and our 2000 gains relate to sales of non-regulated pipeline assets
in our Pipelines segment. Our 2002 and 2001 realized (gain) loss from
discontinued operations were $(9) million and $3 million, and related to
miscellaneous asset sales. In 2000, our realized gain from our discontinued
operations was approximately $17 million primarily related to a gain on the sale
of a portion of our Montreal paraxylene plant.
113
Asset Impairments
During the years ended December 31, we incurred asset impairment charges in
our business segments as presented in the following table:
SEGMENT AND ASSET DESCRIPTION AMOUNT CAUSE OF IMPAIRMENT
----------------------------- ------ -------------------
(IN MILLIONS)
2002
Continuing operations
Production
Intangible asset............................ $ 4
---- Sale of underlying properties
Total Production........................ 4
----
Field Services
North Louisiana gathering facilities........ 66
---- Decision to sell assets
Total Field Services.................... 66
----
Merchant Energy
162
Power turbines.............................. Scaled down capital spending in new power
facilities and weak economic conditions in the
power sector
Goodwill on investment management 44
business.................................. Decision to reduce future capital funding for
this business
----
206
Total Merchant Energy...................
----
Corporate and Other
Telecommunications dark fiber............... 168
---- Change in business strategy to focus on Texas
metro business and weak industry conditions for
long-haul fiber
168
Total Corporate and Other...............
----
Total 2002 asset impairments from $444
continuing operations.................
====
Discontinued operations
185
Coal mining business.......................... Decision to exit coal mining business and pursue
sale of this business
91
MTBE chemical processing plant................ MTBE was banned in our largest market. Decision
to eliminate future capital spending to refit
plant for alternative fuel uses
Solarc project................................ 14
---- Decision to discontinue future capital
investment
Total 2002 asset impairments from $290
discontinued operations...............
====
2001
Continuing operations
Pipelines
$ 9
Renaissance Center leasehold improvements... Relocation of Detroit headquarters
7
Supply Link projects........................ Decision following the Coastal merger not to
pursue these projects
Other projects.............................. 6
---- Decision following the Coastal merger not to
pursue these projects.
22
Total Pipelines.........................
----
Production
Australian and Indonesian assets............ 16
---- Decision following the Coastal merger not to
drill in these areas
16
Total Production........................
----
Merchant Energy
20
Capitalized development costs............... Decision not to pursue projects following
Coastal merger
1
Other merchant assets....................... Change in strategy and business decisions
following merger
----
21
Total Merchant Energy...................
----
Corporate and Other
12
Telecommunications assets................... Weak economic conditions and outlook in the
telecommunication business
Miscellaneous corporate assets.............. 4
---- Relocation of Detroit headquarters
16
Corporate and Other.....................
----
Total 2001 asset impairments from $ 75
continuing operations.................
====
114
SEGMENT AND ASSET DESCRIPTION AMOUNT CAUSE OF IMPAIRMENT
----------------------------- ------ -------------------
(IN MILLIONS)
Discontinued operations
Oyster Creek chemical refining facility....... 37 Refinery shut down following Coastal merger
Kansas refining operations.................... 35 Refinery closed as a result of sale of retail
outlets in the midwest
Other merchant assets......................... 23 Change in strategy and business decisions
following merger
Corpus Christi refinery....................... 8
---- Lease of Corpus Christi refinery to Valero
Energy Corporation
Total 2001 asset impairments from $103
discontinued operations...............
====
2000
Continuing operations
Field Services
Needle Mountain processing facility......... $ 11
---- Ongoing weak economic outlook in the markets
served by this plant
11
Total Field Services....................
----
Total 2000 asset impairments from $ 11
continuing operations.................
====
Discontinued operations
13
Florida and other refining assets............. Decision not to pursue development on these
projects
8
Coal mining business.......................... Decision to exit coal mining business and pursue
sale of this business
----
Total 2000 asset impairments from $ 21
discontinued operations...............
====
Our impairment charges were based on reducing the carrying value of these
assets to their estimated fair value. Fair value was determined through a
combination of estimating the proceeds from the sale of the asset, less
anticipated selling costs (if we intend to sell the asset), or the discounted
estimated cash flows of the asset based on current and anticipated future market
conditions (if we intend to hold the asset).
6. ACCOUNTING CHANGES
Changes in Accounting Principle
During the year ended December 31, 2002, we recorded the cumulative effects
in income of changes in accounting principles as follows (in millions):
BEFORE-TAX AFTER-TAX
---------- ---------
Adoption of EITF Issue No. 02-3.......................... $(343) $(222)
Adoption of SFAS No. 141 and 142......................... 154 154
Adoption of DIG Issue No. C-16........................... 23 14
----- -----
Total............................................... $(166) $ (54)
===== =====
For a discussion of each of the accounting principles we adopted during
2002, See Note 1.
Changes in Accounting Estimate
During 2001, we incurred approximately $316 million in costs related to
changes in accounting estimates which consist of $232 million in additional
environmental remediation liabilities, $47 million of additional accrued legal
obligations and a $37 million charge to reduce the value of our spare parts
inventories to reflect changes in the usability of these parts in our worldwide
operations. Of the overall amount, approximately $182 million of these costs
were included in our operation and maintenance costs and $134 million were
related to our discontinued petroleum markets and coal businesses included as
part of discontinued operations. Of the amount, included in our losses from
discontinued operations, $87 million was for additional environmental
remediation liabilities, $24 million was for additional accrued legal
obligations, and $23 million was to reduce the value of our spare parts
inventories. Our changes in estimates reduced our overall net income by
approximately $215 million.
115
The change in our estimated environmental remediation liabilities was due
to a number of events, including $109 million resulting from the sale of a
majority of our retail gas stations, $31 million related to our closure of our
Gulf Coast Chemical and Midwest refining operations, $10 million associated with
the lease of our Corpus Christi refinery to Valero, and $82 million associated
with conforming Coastal's methods of environmental identification, assessment
and remediation strategies and processes to our historical practices following
our merger with Coastal. This accounted for the remainder of the change in
estimated obligations. The change in estimate of our legal obligations was a
result of a review process to assess our legal exposures, strategies and plans
following the merger with Coastal. Finally, the charge related to our spare
parts inventories was primarily the result of several events that occurred as
part of and following our merger with Coastal, including the consolidation of
numerous operating locations, the sale of a majority of our retail gas stations,
the shutdown of our Midwest refining operations and the lease of our Corpus
Christi refinery. These changes were also a direct result of a fire at our Aruba
refinery whereby a portion of the plant was rebuilt following the fire rendering
many of these parts unusable. Also impacting these amounts was the evaluation of
the operating standards, strategies and plans of our combined company following
the merger.
7. CEILING TEST CHARGES
Under the full cost method of accounting for natural gas and oil
properties, we perform quarterly ceiling tests to evaluate whether the carrying
value of natural gas and oil properties exceeds the present value of future net
revenues, discounted at 10 percent, plus the lower of cost or fair market value
of unproved properties, net of related income tax effects.
For the year ended December 31, 2002, we recorded ceiling test charges of
$269 million, of which $33 million was charged during the first quarter, $234
million was charged during the second quarter, and $2 million was charged during
the fourth quarter. The write-down includes $226 million for our Canadian full
cost pool, $24 million for our Turkish full cost pool, $10 million for our
Brazilian full cost pool and $9 million for other international production
operations, primarily in Australia. The charge for the Canadian full cost pool
primarily resulted from a low daily posted price for natural gas at June 30,
2002, which was approximately $1.43 per MMBtu.
For the year ended December 31, 2001, we recorded ceiling test charges of
$135 million, including $87 million for our Canadian full cost pool, $28 million
for our Brazilian full cost pool, and $20 million for other international
production operations, primarily in Turkey. Our 2001 charges were based on the
daily posted natural gas and oil prices as of November 1, 2001, adjusted for
oilfield or natural gas gathering hub and wellhead price differences as
appropriate. Had we computed the third quarter 2001 ceiling test charges based
upon the daily posted natural gas and oil prices as of September 30, 2001, we
would have incurred a ceiling test charge of $275 million. This amount would
have included $227 million for our Canadian full cost pool and $48 million for
our Brazilian full cost pool and other international production operations,
primarily in Turkey.
We use financial instruments to hedge against the volatility of natural gas
and oil prices. The impact of these hedges was considered in determining our
ceiling test charges, and will be factored into future ceiling test
calculations. Had the impact of our hedges not been included in calculating our
third quarter 2001 ceiling test charges, we would have incurred a third quarter
charge of $576 million at September 30, 2001, relating to our domestic full cost
pool. The charges for our international cost pools would not have materially
changed since we do not significantly hedge our international production
activities.
116
8. OTHER INCOME AND OTHER EXPENSES
Following are the components of other income and other expenses from
continuing operations for each of the three years ended December 31:
2002 2001 2000
---- ---- ----
(IN MILLIONS)
Other Income
Interest income........................................... $ 84 $104 $ 77
Favorable resolution of non-operating contingent
obligations............................................ 38 6 3
Gain on early retirement of debt.......................... 21 -- 1
Rental income............................................. -- 22 19
Development, management and administrative services fees
on power projects...................................... 21 105 37
Income from retail operations............................. -- 7 15
Gains on non-trading derivatives.......................... 8 4 13
Property losses and insurance............................. 2 1 5
Other..................................................... 27 39 36
---- ---- ----
Total............................................. $201 $288 $206
==== ==== ====
Other Expenses
Steam contract termination fees(1)........................ $ 90 $ -- $ --
Impairment on cost basis investment(2).................... 56 66 --
Donations and contributions............................... 1 14 17
Foreign currency losses................................... -- 11 2
Penalty and legal expenses................................ 7 8 4
Amortization expense...................................... 1 10 8
Miscellaneous balancing adjustments....................... 10 4 --
Other..................................................... 15 13 21
---- ---- ----
Total............................................. $180 $126 $ 52
==== ==== ====
---------------
(1) A $90 million steam contract termination fee was paid to our Eagle Point
refinery (included in our discontinued petroleum markets operations) by our
Eagle Point Cogeneration facility (in our global power division of our
Merchant Energy segment) in the first quarter of 2002. These amounts
eliminate in consolidation since the income associated with the petroleum
markets division is reflected in discontinued operations while the power
division's expense is included as part of Merchant Energy's segment results.
(2) We impaired our investment in our Costanera power plant in 2002 and various
telecommunication investments in 2001.
9. INCOME TAXES
Pretax income (loss) from continuing operations before extraordinary items
and cumulative effect of accounting change are composed of the following for
each of the three years ended December 31:
2002 2001 2000
------- ---- ------
(IN MILLIONS)
United States.............................................. $(1,479) $443 $1,530
Foreign.................................................... (76) (49) 97
------- ---- ------
$(1,555) $394 $1,627
======= ==== ======
117
The following table reflects the components of income tax expense (benefit)
included in income from continuing operations before extraordinary items and
cumulative effect of accounting change for each of the three years ended
December 31:
2002 2001 2000
----- ---- -----
(IN MILLIONS)
Current
Federal................................................... $ (15) $(89) $ (99)
State..................................................... 27 (9) (13)
Foreign................................................... 32 27 12
----- ---- -----
44 (71) (100)
----- ---- -----
Deferred
Federal................................................... (458) 372 570
State..................................................... (1) (6) 44
Foreign................................................... (92) (53) --
----- ---- -----
(551) 313 614
----- ---- -----
Total income tax expense (benefit)................ $(507) $242 $ 514
===== ==== =====
Our tax expense (benefit), included in income (loss) from continuing
operations before extraordinary items and cumulative effect of accounting
change, differs from the amount computed by applying the statutory federal
income tax rate of 35 percent for the following reasons for each of the three
years ended December 31:
2002 2001 2000
----- ---- ----
(IN MILLIONS)
Tax expense (benefit) at the statutory federal rate of
35%....................................................... $(544) $137 $570
Increase (decrease)
State income tax, net of federal income tax benefit....... 17 (10) 20
Earnings from unconsolidated affiliates where we
anticipate receiving dividends......................... 2 (20) (25)
Non-deductible portion of merger-related costs and other
tax adjustments to provide for revised estimated
liabilities............................................ (3) 115 12
Foreign income taxed at different rates................... 37 18 (30)
Deferred credit on loss carryover......................... -- (7) (18)
Preferred stock dividends of a subsidiary................. 10 12 13
Non-conventional fuel tax credit.......................... (11) (6) (9)
Depreciation, depletion and amortization.................. 1 23 (14)
Other..................................................... (16) (20) (5)
----- ---- ----
Income tax expense (benefit)................................ $(507) $242 $514
===== ==== ====
Effective tax rate.......................................... 33% 61% 32%
===== ==== ====
118
The following are the components of our net deferred tax liability related
to continuing operations as of December 31:
2002 2001
------ ------
(IN MILLIONS)
Deferred tax liabilities
Property, plant and equipment............................. $4,769 $4,319
Investments in unconsolidated affiliates.................. 695 706
Price risk management activities.......................... -- 564
Regulatory and other assets............................... 575 884
------ ------
Total deferred tax liability...................... 6,039 6,473
------ ------
Deferred tax assets
Net operating loss and tax credit carryovers
U.S. Federal........................................... 1,080 1,051
State.................................................. 104 86
Foreign................................................ 22 --
Western Energy Settlement................................. 328 --
Price risk management activities.......................... 308 --
Environmental liability................................... 201 220
Other liabilities......................................... 707 890
Valuation allowance....................................... (37) (3)
------ ------
Total deferred tax asset.......................... 2,713 2,244
------ ------
Net deferred tax liability.................................. $3,326 $4,229
====== ======
At December 31, 2002, the portion of the cumulative undistributed earnings
of our foreign subsidiaries and foreign corporate joint ventures on which we
have not recorded U.S. income taxes was approximately $1,309 million. Since
these earnings have been or are intended to be indefinitely reinvested in
foreign operations, no provision has been made for any U.S. taxes or foreign
withholding taxes that may be applicable upon actual or deemed repatriation. If
a distribution of these earnings were to be made, we might be subject to both
foreign withholding taxes and U.S. income taxes, net of any allowable foreign
tax credits or deductions. However, an estimate of these taxes is not
practicable. For these same reasons, we have not recorded a provision for U.S.
income taxes on the foreign currency translation adjustment recorded in other
comprehensive income.
The tax benefit associated with the exercise of non-qualified stock options
and the vesting of restricted stock, as well as restricted stock dividends,
reduced taxes payable by $15 million in 2002, $31 million in 2001 and $60
million in 2000. These benefits are included in additional paid-in capital in
our balance sheets.
As of December 31, 2002, we have charitable contribution carryovers of $27
million for which the carryover periods end as follows: $1 million in 2003, $22
million in 2004 and $4 million in 2006; alternative minimum tax credits of $281
million that carryover indefinitely; and $2 million of general business credit
carryovers for which the carryover periods end at various times in the years
2009 through 2021. The table below presents the details of our federal net
operating loss carryover periods.
CARRYOVER PERIOD
--------------------------------------------
2004 - 2011 - 2016 -
2003 2010 2015 2021 TOTAL
---- ------ ------ ------ ------
(IN MILLIONS)
Federal net operating loss.................. $5 $65 $287 $1,892 $2,249
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.
119
As of December 31, 2002, we had $1,129 million of state net operating loss
carryovers. These carryovers will expire in varying amounts over the period from
2003 to 2021. We also had $73 million of foreign net operating loss carryovers
that carryover indefinitely.
We recorded a valuation allowance to reflect the estimated amount of
deferred tax assets which we may not realize due to the uncertain availability
of future taxable income or the expiration of net operating loss and tax credit
carryovers. As of December 31, 2002, approximately $14 million of the valuation
allowance relates to our foreign deferred tax assets for ceiling test charges,
$22 million relates to our foreign net operating loss carryovers and $1 million
relates to our U.S. Federal general business credit carryovers. As of December
31, 2001, approximately $1 million of the valuation allowance relates to U.S.
Federal net operating loss carryovers of an acquired company and $2 million
relates to U.S. Federal general business credit carryovers.
10. DISCONTINUED OPERATIONS
In June 2003, our Board of Directors authorized the sale of substantially
all of our petroleum markets operations, including our Aruba refinery, our
Unilube blending operations, our domestic and international terminalling
facilities and our petrochemical and chemical plants. The Board's actions were
in addition to previous actions taken when they approved the sales of our Eagle
Point refinery, our asphalt business and our lease crude operations.
In June 2002, our Board of Directors authorized the sale of our coal mining
operations. These operations, which were historically included in our Merchant
Energy segment, consist of fifteen active underground and two surface mines
located in Kentucky, Virginia and West Virginia. Following the authorization of
the sale by our Board of Directors, we compared the carrying value of the
underlying assets to our estimated sales proceeds, net of estimated selling
costs, based on bids received in the sales process in the second and third
quarters of 2002. Because this carrying value was higher than our estimated net
sales proceeds, we recorded impairment charges of $148 million in the second
quarter of 2002 and $37 million in the third quarter of 2002.
In December 2002, we sold substantially all of our reserves and properties
in West Virginia, Virginia and Kentucky to an affiliate of Natural Resources
Partners, L.P. for $57 million in cash. In January 2003, we sold our remaining
coal operations, which consists of mining operations, businesses, properties and
reserves in Kentucky, West Virginia and Virginia, to subsidiaries of Alpha
Natural Resources, LLC, an affiliate of First Reserve Corporation, for $59
million which includes $35 million in cash and $24 million in notes receivable.
Our petroleum markets and coal mining operations have been classified as
discontinued operations in our financial statements for all periods presented.
The summarized financial results of discontinued operations for each of the
three years ended December 31, are as follows:
PETROLEUM COAL
MARKETS MINING TOTAL
--------- ------ --------
(IN MILLIONS)
Operating Results
YEAR ENDED DECEMBER 31, 2002
Revenues(1)................................................. $ 4,724 $ 309 $ 5,033
Costs and expenses(1)....................................... (4,954) (327) (5,281)
Loss on long-lived assets................................... (97) (184) (281)
Other income................................................ 110 5 115
Interest and debt expense................................... (12) -- (12)
-------- ----- --------
Loss before income taxes.................................... (229) (197) (426)
Income taxes................................................ (12) 73 61
-------- ----- --------
Loss from discontinued operations, net of income taxes...... $ (241) $(124) $ (365)
======== ===== ========
---------------
(1) These amounts include intercompany activities between our discontinued
petroleum markets operations and our continuing operating segments.
120
PETROLEUM COAL
MARKETS MINING TOTAL
--------- ------ --------
(IN MILLIONS)
YEAR ENDED DECEMBER 31, 2001
Revenues(1)................................................. $ 4,900 $ 277 $ 5,177
Costs and expenses(1)....................................... (5,016) (286) (5,302)
Loss on long-lived assets................................... (106) -- (106)
Other income................................................ 111 2 113
Interest and debt expense................................... (27) -- (27)
-------- ----- --------
Loss before income taxes.................................... (138) (7) (145)
Income taxes................................................ 58 2 60
-------- ----- --------
Loss from discontinued operations, net of income taxes...... $ (80) $ (5) $ (85)
======== ===== ========
YEAR ENDED DECEMBER 31, 2000
Revenues(1)................................................. $ 12,402 $ 276 $ 12,678
Costs and expenses(1)....................................... (12,246) (270) (12,516)
Gain (loss) on long-lived assets............................ 4 (8) (4)
Other income................................................ 28 1 29
Interest and debt expense................................... (39) -- (39)
-------- ----- --------
Income (loss) before income taxes........................... 149 (1) 148
Income taxes................................................ (25) -- (25)
-------- ----- --------
Income (loss) from discontinued operations, net of income
taxes..................................................... $ 124 $ (1) $ 123
======== ===== ========
---------------
(1) These amounts include intercompany activities between our discontinued
petroleum markets operations and our continuing operating segments.
Financial Position Data
DECEMBER 31, 2002
Assets of discontinued operations
Accounts and notes receivables............................ $ 1,229 $ 29 $ 1,258
Inventory................................................. 636 14 650
Other current assets...................................... 79 1 80
Property, plant and equipment, net........................ 1,950 46 1,996
Other non-current assets.................................. 65 16 81
-------- ----- --------
Total assets........................................... $ 3,959 $ 106 $ 4,065
======== ===== ========
Liabilities of discontinued operations
Accounts payable.......................................... $ 1,153 $ 20 $ 1,173
Other current liabilities................................. 180 5 185
Environmental remediation reserve......................... 86 15 101
Other non-current liabilities............................. 1 -- 1
-------- ----- --------
Total liabilities...................................... $ 1,420 $ 40 $ 1,460
======== ===== ========
121
DECEMBER 31, 2001
Assets of discontinued operations
Accounts and notes receivables............................ $ 1,491 $ 35 $ 1,526
Inventory................................................. 624 11 635
Other current assets...................................... 313 -- 313
Property, plant and equipment, net........................ 1,926 301 2,227
Other non-current assets.................................. 80 5 85
-------- ----- --------
Total assets........................................... $ 4,434 $ 352 $ 4,786
======== ===== ========
Liabilities of discontinued operations
Accounts payable.......................................... $ 1,789 $ 27 $ 1,816
Short-term financing obligations.......................... 500 -- 500
Liabilities from price risk management activities......... 212 -- 212
Other current liabilities................................. 135 7 142
Environmental remediation reserve......................... 97 -- 97
Other non-current liabilities............................. 55 3 58
-------- ----- --------
Total liabilities...................................... $ 2,788 $ 37 $ 2,825
======== ===== ========
11. EARNINGS PER SHARE
We calculated basic and diluted earnings per share amounts as follows for
each of the three years ended December 31:
2002 2001 2000
----------------- ---------------- ----------------
BASIC DILUTED BASIC DILUTED BASIC DILUTED
------- ------- ------ ------- ------ -------
(IN MILLIONS, EXCEPT PER COMMON SHARE AMOUNTS)
Income (loss) from continuing
operations........................... $(1,048) $(1,048) $ 152 $ 152 $1,113 $1,113
Preferred stock dividend............. -- -- -- -- -- --
------- ------- ------ ------ ------ ------
Income (loss) from continuing
operations available to common
stockholders...................... (1,048) (1,048) 152 152 1,113 1,113
Trust preferred securities(1)........ -- -- -- -- -- 10
Convertible debentures(1)............ -- -- -- -- -- --
------- ------- ------ ------ ------ ------
Adjusted income from continuing
operations........................ (1,048) (1,048) 152 152 1,113 1,123
Discontinued operations, net of
income taxes...................... (365) (365) (85) (85) 123 123
Extraordinary items, net of income
taxes............................. -- -- 26 26 70 70
Cumulative effect of accounting
change, net of income taxes....... (54) (54) -- -- -- --
------- ------- ------ ------ ------ ------
Adjusted net income (loss)........... $(1,467) $(1,467) $ 93 $ 93 $1,306 $1,316
======= ======= ====== ====== ====== ======
---------------
(1) Due to its antidilutive effect on earnings per share, approximately 7
million shares related to our convertible debentures were excluded from 2001
dilutive shares, and approximately 8 million shares related to our trust
preferred securities were excluded in 2001.
122
2002 2001 2000
----------------- ---------------- ----------------
BASIC DILUTED BASIC DILUTED BASIC DILUTED
------- ------- ------ ------- ------ -------
(IN MILLIONS, EXCEPT PER COMMON SHARE AMOUNTS)
Average common shares outstanding...... 560 560 505 505 494 494
Effect of dilutive securities
Restricted stock..................... -- -- -- 1 -- --
Stock options(2)..................... -- -- -- 5 -- 7
FELINE PRIDES(sm).................... -- -- -- 5 -- 3
Preferred stock...................... -- -- -- -- -- 1
Trust preferred securities(1)(2)..... -- -- -- -- -- 8
Equity security units................ -- -- -- -- -- --
Convertible debentures(1)(2)......... -- -- -- -- -- --
------- ------- ------ ------ ------ ------
Average common shares outstanding...... 560 560 505 516 494 513
======= ======= ====== ====== ====== ======
Earnings per common share
Adjusted (loss) income from
continuing operations............. $ (1.87) $ (1.87) $ 0.30 $ 0.30 $ 2.25 $ 2.19
Discontinued operations, net of
income taxes...................... (0.65) (0.65) (0.17) (0.17) 0.25 0.24
Extraordinary items, net of income
taxes............................. -- -- 0.05 0.05 0.14 0.14
Cumulative effect of accounting
change, net of income taxes....... (0.10) (0.10) -- -- -- --
------- ------- ------ ------ ------ ------
Adjusted net income (loss)........... $ (2.62) $ (2.62) $ 0.18 $ 0.18 $ 2.64 $ 2.57
======= ======= ====== ====== ====== ======
---------------
(1) Due to its antidilutive effect on earnings per share, approximately 7
million shares related to our convertible debentures were excluded from 2001
dilutive shares, and approximately 8 million shares related to our trust
preferred securities were excluded in 2001.
(2) Due to its antidilutive effect on earnings per share, approximately 1
million shares related to our stock options, approximately 8 million shares
related to our convertible debentures and approximately 8 million shares
related to our trust preferred securities were excluded in 2002.
12. FINANCIAL INSTRUMENTS
Following are the carrying amounts and estimated fair values of our
financial instruments included in continuing operations as of December 31:
2002 2001
--------------------- ---------------------
CARRYING CARRYING
AMOUNT FAIR VALUE AMOUNT FAIR VALUE
-------- ---------- -------- ----------
(IN MILLIONS)
Investments.................................... $ 44 $ 44 $ 28 $ 28
Long-term debt and other obligations, including
current maturities........................... 16,681 12,268 14,139 13,613
Notes payable to unconsolidated affiliates..... 390 380 872 896
Company obligated preferred securities of
subsidiaries................................. 625 278 925 1,048
Trading derivative price risk management
activities(2)................................ (45) (45) 282(1) 282(1)
Non-trading commodity-based price risk
management activities........................ 459 459 459 459
Non-trading foreign currency and interest rate
swaps........................................ 22 22 (33) (33)
---------------
(1) Does not include $1,055 million of non-derivative contracts as of December
31, 2001 including transportation capacity, tolling agreements and natural
gas in storage held for trading purposes since these do not constitute
financial instruments.
(2) Does not include trading price risk management liabilities of $14 million
and $42 million as of December 31, 2002 and 2001 in our discontinued
petroleum markets operations.
As of December 31, 2002 and 2001, our carrying amounts of cash and cash
equivalents, short-term borrowings, and trade receivables and payables are
representative of fair value because of the short-term
123
nature of these instruments. The fair value of long-term debt with variable
interest rates approximates its carrying value because of the market-based
nature of the debt's interest rates. We estimated the fair value of debt with
fixed interest rates based on quoted market prices for the same or similar
issues. We estimated the fair value of all derivative financial instruments
based on quoted market prices, current market conditions, estimates we obtained
from third-party brokers or dealers, or amounts derived using valuation models.
13. PRICE RISK MANAGEMENT ACTIVITIES
The following table summarizes the carrying value of our trading and
non-trading price risk management assets and liabilities included in continuing
operations as of December 31:
2002 2001
----- ------
(IN MILLIONS)
Net assets (liabilities)
Energy contracts
Trading contracts(1)(2)................................ $ (45) $1,337
Non-trading contracts
Derivatives designated as hedges..................... (500) 459
Other derivatives.................................... 959 --
----- ------
Total energy contracts................................. 414 1,796
----- ------
Interest rate and foreign currency contracts.............. 22 (33)
----- ------
Net assets from price risk management activities(3).... $ 436 $1,763
===== ======
---------------
(1) Trading contracts are those that are entered into for purposes of generating
a profit or benefiting from movements in market prices.
(2) Does not include trading price risk management liabilities of $14 million
and $42 million as of December 31, 2002 and 2001 in our discontinued
petroleum markets operations.
(3) Net assets from price risk management activities include current and
non-current assets and current and non-current liabilities from price risk
management activities on the balance sheet.
Included in other derivatives as of December 31, 2002, are $968 million of
derivative contracts related to the power restructuring activities of our
consolidated subsidiaries. Of this amount, $878 million relates to a power
restructuring that occurred during the first quarter of 2002 at our Eagle Point
Cogeneration power plant, and $90 million relates to a power restructuring at
our Capitol District Energy Center Cogeneration Associates plant. The remaining
balance in other derivatives, an unrealized loss of $9 million, relates to
derivative positions that no longer qualify as cash flow hedges under SFAS No.
133 because they were designated as hedges of anticipated future production on
natural gas and oil properties that were sold during 2002.
Trading Activities and Contracts. Our trading activities include the
services we provide in the energy sector that we enter into with the objective
of generating profits on or benefiting from movements in market prices,
primarily related to the purchase and sale of energy commodities. In the fourth
quarter of 2002, we announced our intent to exit our trading activities and to
pursue an orderly liquidation of our trading price risk management activities
through 2004.
The derivative instruments we use in our trading activities are either
traded on active exchanges such as the New York Mercantile Exchange or are
valued using exchange prices, third party pricing data and valuation techniques
that incorporate specific contractual terms, statistical and simulation analysis
and present value concepts. Because of our actions to limit our trading
activities and exit the trading business, our accessibility to reliable forward
market data for purposes of estimating fair value was significantly limited in
late 2002. As a result, we obtained valuation assistance from a third party
valuation specialist in determining the fair value of our trading and
non-trading price risk management activities as of December 31, 2002. Based upon
the specialist's input, our estimates of fair value are based upon price curves
derived from actual prices observed in the market, pricing information supplied
by the specialist and independent pricing sources and models that rely on this
forward pricing information. These estimates also reflect factors for time value
and volatility underlying the contracts, the potential impact of liquidating our
position in an orderly manner over a
124
reasonable time under present market conditions, modeling risk, credit risk of
our counterparties and operational risks, as needed. We have discontinued
applying our ten-year liquidity valuation allowance that we had instituted
during the first quarter of 2002 in circumstances where there was uncertainty
related to our forward prices in less liquid markets. To the extent that the
forward market data received from the third party specialist indicates value
beyond ten years, we now include that value in the fair value of our trading and
non-trading price risk management activities.
We have reflected our trading portfolio at estimated fair value which is
the amount at which the contracts in our portfolio could be bought or sold in a
current transaction between willing buyers and sellers. However, the value we
ultimately receive in settlement of our trading activities may be less than our
fair value estimates. As disclosed previously, we are actively liquidating our
trading portfolio, which includes approximately 40,000 transactions as of
December 31, 2002. We believe the net realizable value of our trading portfolio
may be less than its currently estimated fair value. Our belief is based on
recent transactions completed at values below estimated fair value and bids
received on transactions that were also below their fair value. Additionally,
because of the adoption of EITF Issue No. 02-3, a portion of the transactions
that we plan to liquidate are accounted for under the accrual method and are not
recorded in our balance sheet. Should we have to pay counterparties to assume
these transactions, future losses will result.
Until we complete our exit of the energy trading business, we will continue
to serve a diverse group of customers that require a wide variety of financial
structures, products and terms. This diversity requires us to manage, on a
portfolio basis, the resulting market risks inherent in our trading price risk
management activities subject to parameters established by our risk management
committee. We monitor market risks through a risk control committee operating
independently from the units that create or actively manage these risk exposures
to ensure compliance with our stated risk management policies. We measure and
adjust the risk in accordance with mark-to-market and other risk management
methodologies which utilize forward price curves in the energy markets to
estimate the size and probability of future potential exposure.
Credit risk relates to the risk of loss that we would incur as a result of
non-performance by counterparties pursuant to the terms of their contractual
obligations. We maintain credit policies with regard to our counterparties in
both our trading and non-trading price risk management activities 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 that allow for
the netting of positive and negative exposures associated with a single
counterparty. The following table presents a summary of our counterparties in
which we have net asset exposure from our trading and non-trading price risk
management activities:
NET ASSET EXPOSURE FROM PRICE RISK MANAGEMENT ACTIVITIES AS
OF DECEMBER 31, 2002
-------------------------------------------------------------
BELOW
INVESTMENT GRADE(1) INVESTMENT GRADE(1)(2) TOTAL
-------------------- ---------------------- -----------
(IN MILLIONS)
Counterparty
Energy marketers....................... $ 485 $212 $ 697
Financial institutions................. 16 -- 16
Natural gas and oil producers.......... 30 4 34
Natural gas and electric utilities..... 1,275 86 1,361
Industrials............................ -- 1 1
Municipalities......................... 49 -- 49
------ ---- ------
Net asset exposure from price
risk management
activities(3).............. $1,855 $303 $2,158
====== ==== ======
125
NET ASSET EXPOSURE FROM PRICE RISK MANAGEMENT ACTIVITIES AS
OF DECEMBER 31, 2001
-------------------------------------------------------------
BELOW
INVESTMENT GRADE(1) INVESTMENT GRADE(1)(2) TOTAL
-------------------- ---------------------- -----------
(IN MILLIONS)
Counterparty
Energy marketers....................... $1,330 $419 $1,749
Financial institutions................. 161 -- 161
Natural gas and oil producers.......... 106 11 117
Natural gas and electric utilities..... 1,033 82 1,115
Industrials............................ 13 18 31
Municipalities......................... 231 -- 231
------ ---- ------
Net asset exposure from price
risk management
activities(3).............. $2,874 $530 $3,404
====== ==== ======
---------------
(1) "Investment Grade" and "Below Investment Grade" are primarily determined
using publicly available credit ratings, or if a counterparty is not
publicly rated, a minimum implied credit rating through internal credit
analysis. "Investment Grade" includes counterparties with a minimum Standard
& Poor's rating of BBB- or Moody's rating of Baa3. "Below Investment Grade"
includes counterparties with a credit rating that do not meet the criteria
of "Investment Grade".
(2) As of December 31, 2002, we required collateral, which encompasses margins
and standby letters of credit for $170 million of the $303 million, or 56
percent, from counterparties included in "Below Investment Grade".
(3) Net asset exposure from price risk management activities have been prepared
by netting assets against liabilities on counterparties where we have a
contractual right to offset. The positions netted include both current and
non-current amounts. As a result, these amounts do not agree to our total
assets from price risk management activities in our balance sheet. In
addition, in 2001, the counterparty total does not include assets for
natural gas in storage and marketable securities held for trading purposes
of $196 million.
In the tables above, we had one customer that comprised greater than 5
percent of our net asset exposure from price risk management activities as of
December 31, 2002 and 2001. This customer as of December 31, 2002, Public
Service Electric and Gas Company, comprised approximately 41 percent of the net
asset exposure from price risk management activities by counterparty and was
considered an investment grade company as of December 31, 2002. This
concentration of counterparties may impact our overall exposure to credit risk,
either positively or negatively, in that the counterparties may be similarly
affected by changes in economic, regulatory or other conditions.
Non-trading Activities -- Derivatives Designated as Hedges.
We use derivative financial instruments to hedge the impact of our market
price risk exposures on our assets, liabilities, contractual commitments and
forecasted transactions related to our natural gas and oil production, refining,
natural gas transmission, power generation, financing and international business
activities. We engage in two types of hedging activities: hedges of cash flow
exposure and hedges of fair value exposure. Hedges of cash flow exposure are
entered into to hedge a forecasted transaction or the variability of cash flows
to be received or paid related to a recognized asset or liability. Hedges of
fair value exposure are entered into to hedge the fair value of a recognized
asset, liability or firm commitment. On the date that we enter into the
derivative contract, we designate the derivative as either a cash flow hedge or
a fair value hedge. Changes in derivative fair values that are designated as
cash flow hedges are deferred to the extent that they are effective and are
recorded as a component of accumulated other comprehensive income until the
hedged transactions occur and are recognized in earnings. The ineffective
portion of a cash flow hedge's change in value is recognized immediately in
earnings as a component of operating revenues in our income statement. Changes
in the derivative fair values that are designated as fair value hedges are
recognized in earnings as offsets to the changes in fair values of related
hedged assets, liabilities or firm commitments.
As required by SFAS No. 133, we formally document all relationships between
hedging instruments and hedged items, as well as our risk management objectives,
strategies for undertaking various hedge transactions and our methods for
assessing and testing correlation and hedge ineffectiveness. All hedging
instruments are linked to the hedged asset, liability, firm commitment or
forecasted transaction. We also assess, both at the inception of the hedge and
on an on-going basis, whether the derivatives that are used in our hedging
126
transactions are highly effective in offsetting changes in cash flows or fair
values of the hedged items. We discontinue hedge accounting prospectively if we
determine that a derivative is no longer highly effective as a hedge or if we
decide to discontinue the hedging relationship.
The fair value of our hedging instruments reflects our best estimate and is
based on exchange or over-the-counter quotations when they are available. Quoted
valuations may not be available due to location differences or terms that extend
beyond the period for which quotations are available. Where quotes are not
available, we utilize other valuation techniques or models to estimate market
values. These modeling techniques require us to make estimations of future
prices, price correlation and market volatility and liquidity. Our actual
results may differ from our estimates, and these differences can be positive or
negative.
On January 1, 2001, we adopted the provisions of SFAS No. 133 and recorded
a cumulative-effect adjustment of $1,280 million, net of income taxes, in
accumulated other comprehensive income to recognize the fair value of all
derivatives designated as hedging instruments. The majority of the initial
charge related to hedging cash flows from anticipated sales of natural gas for
2001 and 2002. During the year ended December 31, 2001, $1,063 million, net of
income taxes, of this initial transition adjustment was reclassified to earnings
as a result of hedged sales and purchases during the year. A discussion of our
hedging activities is as follows:
Fair Value Hedges. Included in assets and liabilities from discontinued
operations are crude oil and refined products inventories that change in value
daily due to changes in the commodity markets. We use futures and swaps to
protect the value of these inventories. For the years ended December 31, 2002
and 2001, the financial statement impact of our hedges of the fair value of
these inventories was immaterial.
Cash Flow Hedges. A majority of our commodity sales and purchases are at
spot market or forward market prices. We use futures, forward contracts and
swaps to limit our exposure to fluctuations in the commodity markets and allow
for a fixed cash flow stream from these activities. As of December 31, 2002 and
2001, the value of cash flow hedges included in accumulated other comprehensive
income was a net unrealized loss of $377 million and a net unrealized gain of
$256 million, net of income taxes. We estimate that unrealized losses of $124
million, net of income taxes, will be reclassified from accumulated other
comprehensive income during 2003. Reclassifications occur upon physical delivery
of the hedge commodity and the corresponding expiration of the hedge. The
maximum term of our cash flow hedges is 10 years; however, most of our cash flow
hedges expire within the next 24 months. We had a net liability from price risk
management activities of $500 million as of December 31, 2002 and a net asset
from price risk management activities of $459 million as of December 31, 2001
associated with our cash flow hedges. This net change of $959 million during
2002 resulted from net settlements of $222 million during 2002 and a decrease in
fair value of $737 million in our cash flow hedge positions during 2002.
Our accumulated other comprehensive income as of December 31, 2002 and 2001
also includes a loss of $65 million and $23 million, net of income taxes,
representing our proportionate share of amounts recorded in other comprehensive
income by our unconsolidated affiliates who use derivatives as cash flow hedges.
Included in this loss is a $7 million loss that we estimate will be reclassified
from accumulated other comprehensive income during 2003. The maximum term of
these cash flow hedges is two years, excluding hedges related to interest rates
on variable debt.
For the years ended December 31, 2002 and 2001, we recognized a net loss of
$15 million and a net gain of $3 million, net of income taxes, related to the
ineffective portion of all cash flow hedges.
In May 2002, we announced a plan to reduce the volumes of natural gas that
we have hedged for our Production segment, and we removed the hedging
designation on derivatives that had a fair value loss of $105 million at
December 31, 2002. This amount, net of income taxes of $38 million, is reflected
in accumulated other comprehensive income and will be reclassified to income as
the original hedged transactions are settled through 2004. Of the net loss of
$67 million in accumulated other comprehensive income, we estimate that
unrealized losses of $42 million, net of income taxes, related to these
derivatives will be reclassified to income over the next twelve months.
127
Foreign Currency Hedges. In our international activities, we have fixed
rate foreign currency denominated debt that exposes us to changes in exchange
rates between the foreign currency and U.S. dollar. In 2002 and 2001, we used
currency swaps to effectively convert the fixed amounts of foreign currency due
under foreign currency denominated debt to U.S. dollar amounts. In December
2002, we decided to reduce the volumes of foreign currency exchange risk that we
have hedged for our debt, and we removed the hedging designation on derivatives
that had a net fair value loss of $1 million at December 31, 2002. Of this
amount, a $14 million loss, net of income taxes of $5 million, is reflected in
accumulated other comprehensive income and a $8 million gain is reflected in the
unamortized discount on long-term debt. These amounts will be reclassified to
income as the interest and principal on the debt are settled through 2009. Of
the net loss of $9 million included in accumulated other comprehensive income
and $8 million deferred gain included in long-term debt, we estimate that
unrealized losses of $1 million and unrealized gains of $2 million related to
these derivatives will be reclassified to income over the next twelve months.
Non-trading Activities -- Power Restructuring Activities.
Our Merchant Energy segment's power restructuring activities involved
amending or terminating a power plant's existing power purchase contract to
eliminate the requirement that the plant provide power from its own generation
to the regulated utility and replacing that requirement with the ability to
provide power to the utility from the wholesale power market. In conjunction
with our power restructuring activities, we generally entered into new
market-based contracts with third parties to provide the power to the utility
from the wholesale power market, which effectively "locks in" our margin on the
restructuring transaction as the difference between the contracted rate in the
restructured contract and the wholesale market rates at the time.
Prior to a restructuring, the power plant and its related power purchase
contract are generally accounted for at their historical cost, which is either
the cost of construction or, if acquired, the acquisition cost. Revenues and
expenses prior to the restructuring are, in most cases, accounted for on an
accrual basis as power is generated and sold to the utility.
Following a restructuring, the accounting treatment for the power purchase
agreement must change if the restructured contract meets the definition of a
derivative and is therefore required to be marked to its fair value under SFAS
No. 133. In addition, since the power plant no longer has the exclusive right to
provide power under the original, dedicated power purchase contract, it operates
as a peaking merchant plant, generating power only when it is economical to do
so. Because of this significant change in its use, the fair value of the plant
may be less than its historical value. These changes may also require us to
terminate or amend any related fuel supply and steam agreements, and enter into
other third party and intercompany contracts such as transportation agreements,
associated with the operations of the facility.
Our power restructuring activities had the following effects to our
financial statements:
- The restructured contract (if it meets the definition of a derivative) is
shown as an asset from price risk management activities in our balance
sheet.
- The difference between the fair value of the restructured contract and
the carrying value of the original contract is shown as operating
revenues in our income statement. Any subsequent changes in this fair
value are also recorded in operating revenues.
- The new third party wholesale power supply and other contracts are
recorded at their fair value as assets or liabilities from price risk
management activities in our balance sheet. Any subsequent changes in the
fair value are also recorded in operating revenues.
- The carrying value of the underlying power plant and any related
intangible assets are evaluated for impairment and, if required, are
written down to their fair value as a merchant power plant, which is
recorded as operating expenses in our income statement.
- Any contract termination fees and closing costs are also recorded as
operating expenses in our income statement.
128
- As we purchase power under the wholesale power supply contracts, we
record the cost of the power we purchase as operating expenses in our
income statement.
- As we sell that power to the utility under the restructured contract, we
record the amounts received under the contract as operating revenues.
We classify our restructured contracts as non-trading price risk management
activities in our disclosures. We classify our third party and other contracts
as trading price risk management activities because they are actively managed by
our trading operations.
We have historically conducted the majority of our power restructuring
activities through our unconsolidated affiliate, Chaparral, and therefore our
share of the revenues and expenses of these activities is recognized through
earnings from unconsolidated affiliates.
In 2002 we completed a power restructuring on our Eagle Point Cogeneration
facility, which we consolidate, and applied the accounting described above to
that transaction. Power restructuring activities can also involve contract
terminations that result in a cash payment by the utility to cancel the
underlying power contract, as in our Mount Carmel transaction. We also employed
the principles of our power restructuring business in reaching a settlement in
2002 of the dispute under our Nejapa power contract which included a cash
payment to us. We recorded these payments as operating revenues. As of and for
the year ended December 31, 2002, our consolidated power restructuring
activities had the following effects on our consolidated financial statements
(in millions):
ASSETS FROM LIABILITIES FROM PROPERTY, PLANT INCREASE
PRICE RISK PRICE RISK AND EQUIPMENT (DECREASE)
MANAGEMENT MANAGEMENT AND INTANGIBLE OPERATING OPERATING IN MINORITY
ACTIVITIES ACTIVITIES ASSETS REVENUES EXPENSES INTEREST
----------- ---------------- --------------- --------- ---------- -----------
Initial gain on restructured
contracts..................... $978 $1,118 $ 172
Writedown of power plants and
intangibles and other fees.... $(352) $476 (109)
Change in value of restructured
contracts during 2002......... 8 (96) (20)
Change in value of third party
wholesale power supply
contracts..................... $18 (18) (3)
Purchase of power under power
supply contracts.............. 47 (11)
Sale of power under restructured
contracts..................... 111 28
---- --- ----- ------ ---- -----
Total...................... $986 $18 $(352) $1,115 $523 $ 57
==== === ===== ====== ==== =====
The fair value of the derivatives related to our power restructuring
activities is determined based on the expected cash receipts and payments under
the contracts using future power prices compared to the contractual prices under
these contracts. We discount these cash flows at an interest rate commensurate
with the term of each contract and the credit risk of each contract's
counterparty. We make adjustments to this discount rate when we believe that
market changes in the rates result in changes in fair values that can be
realized. Future power prices are based on the forward pricing curve of the
appropriate power delivery and receipt points in the applicable power market.
This forward pricing curve is derived from available market data and pricing
information supplied by a third party. The timing of cash receipts and payments
are based on the expected timing of power delivered under these contracts. The
fair value of our derivatives may change each period based on changes in actual
and projected market prices, fluctuations in the credit ratings of our
counterparties, significant changes in interest rates, and changes to the
assumed timing of deliveries.
As a result of credit downgrades, our decision to exit the energy trading
business, and disruptions in the capital markets, it is unlikely we will pursue
additional power restructurings in the near term.
129
14. INVENTORY
Our inventory consisted of the following at December 31:
2002 2001
----- -----
(IN MILLIONS)
Current
Materials and supplies and other.......................... $174 $150
NGL and natural gas in storage............................ 78 41
---- ----
Total current inventory(1)........................ 252 191
---- ----
Non-current
Dark fiber................................................ 5 152
Turbines.................................................. 222 231
---- ----
Total non-current inventory....................... 227 383
---- ----
Total inventory................................... $479 $574
==== ====
---------------
(1) As a result of our intent to dispose of our petroleum and chemical assets,
inventory balances totaling $636 million and $624 million as of December 31,
2002 and 2001, have been classified as assets of discontinued operations
(see Note 10).
Effective October 1, 2002, we adopted the provisions of EITF Issue No.
02-3. EITF Issue No. 02-3 requires, among other things, that we account for all
inventory used in our trading activities at the lower of its cost or fair value,
rather than using mark-to-market accounting as was previously allowed under EITF
Issue No. 98-10. Effective October 1, 2002, we adjusted the fair value of these
inventories in our balance sheet to their historical cost using a weighted
average cost methodology and reclassified those amounts from price risk
management activities to inventory as natural gas in storage. See Note 1 for a
further discussion of the impact of EITF No. 02-3.
130
15. REGULATORY ASSETS AND LIABILITIES
Our regulatory assets are included in other current and non-current
regulatory assets, and regulatory liabilities are included in other current and
non-current regulatory liabilities. These balances are presented in our balance
sheets on a gross basis. Below are the details of our regulatory assets and
liabilities, which represent our regulated interstate systems that apply the
provisions of SFAS No. 71, at December 31:
REMAINING
RECOVERY
DESCRIPTION 2002 2001 PERIOD
----------- ---- ---- ---------
(IN MILLIONS) (YEARS)
Current regulatory assets
Other(1).................................................. $ 3 $ 2 1
---- ----
Non-current regulatory assets
Grossed-up deferred taxes on capitalized funds used during
construction(2)........................................ 59 59 11-15
Under-collected state tax................................. 8 11 2-3
Postretirement benefits(1)(3)............................. 26 28 10
Unamortized net loss on reacquired debt(1)................ 29 31 15-19
Other(1).................................................. 7 23 1-10
---- ----
Total non-current regulatory assets.................... 129 152
---- ----
Total regulatory assets................................ $132 $154
==== ====
Current regulatory liabilities
Cashout imbalance settlement(1)........................... $ 8 $ 13 N/A
---- ----
Non-current regulatory liabilities
Environmental liability(1)................................ 55 46 3
Excess deferred federal taxes............................. 14 21 2-3
Property and plant depreciation........................... 22 24 various
Plant regulatory liability(1)............................. 12 7 N/A
Postretirement benefits(1)................................ 9 7 N/A
---- ----
Total non-current regulatory liabilities............... 112 105
---- ----
Total regulatory liabilities........................... $120 $118
==== ====
---------------
(1) These amounts are not included in a rate base on which we earn a current
return.
(2) These amounts are recovered over the remaining depreciable lives of
property, plant and equipment.
(3) The amount is to be recovered in future rate proceeding.
131
16. OTHER ASSETS AND LIABILITIES
Below is the detail of our other current and non-current assets and
liabilities on our balance sheets as of December 31:
2002 2001
------ ------
(IN MILLIONS)
Other current assets
Deferred income taxes..................................... $ 221 $ 159
Prepaid assets............................................ 110 81
Restricted cash........................................... 124 17
Assets held for sale...................................... 31 --
Other..................................................... 83 111
------ ------
Total(1)............................................... $ 569 $ 368
====== ======
Other non-current assets
Pension assets............................................ $ 866 $ 775
Notes receivable from affiliates.......................... 466 346
Turbine inventory......................................... 222 231
Restricted cash........................................... 212 75
Unamortized debt expenses................................. 180 145
Other investments......................................... 167 97
Regulatory assets......................................... 129 152
Notes receivable.......................................... 48 50
Insurance receivables..................................... 49 18
Dark fiber inventory...................................... 5 152
Other..................................................... 179 123
------ ------
Total(2)............................................... $2,523 $2,164
====== ======
Other current liabilities
Accrued interest.......................................... $ 327 $ 228
Accrued taxes, other than income.......................... 154 188
Environmental, legal and rate reserves.................... 138 67
Dividends payable......................................... 130 108
Accrued liabilities....................................... 28 103
Deposits.................................................. 66 13
Deferred risk-sharing revenue............................. 32 32
Postretirement benefits................................... 35 46
Income taxes.............................................. 19 146
Other..................................................... 168 154
------ ------
Total(3)............................................... $1,097 $1,085
====== ======
---------------
(1) Excludes $269 million for 2002 and $179 million for 2001 related to
discontinued petroleum markets operations.
(2) Excludes $46 million for 2002 and $332 million for 2001 related to
discontinued petroleum markets operations.
(3) Excludes $188 million for 2002 and $169 million for 2001 related to
discontinued petroleum markets operations.
132
Other non-current liabilities
Environmental and legal reserves.......................... $ 409 $ 584
Postretirement and employment benefits.................... 322 358
Deferred gain on sale of assets to El Paso Energy
Partners............................................... 268 10
Obligations under swap agreement.......................... 255 393
Other deferred credits.................................... 155 230
Accrued lease obligations................................. 124 85
Unearned revenues......................................... 8 125
Regulatory liabilities.................................... 112 105
Deferred compensation..................................... 105 237
Insurance reserves........................................ 104 109
Other..................................................... 72 23
------ ------
Total(1)............................................... $1,934 $2,259
====== ======
---------------
(1) Excludes $85 million for 2002 and $104 million for 2001 related to
discontinued petroleum markets operations.
17. PROPERTY, PLANT AND EQUIPMENT
At December 31, 2002 and 2001, we had approximately $1,368 million and
$1,974 million of construction work in progress included in our property, plant
and equipment. In our discontinued petroleum markets operations, our
construction work in progress was $497 million for 2002 and $356 million for
2001.
In June 2001, we entered into a 20-year lease agreement related to our
Corpus Christi refinery and related assets with Valero. Under the lease, Valero
pays us a quarterly amount that increases after the second year of the lease.
For the years ended December 31, 2002 and 2001, we recorded $19 million and $11
million in lease income related to this lease. In February 2003, Valero
exercised its option to purchase the plant and related assets for $289 million
in cash. We recorded a gain of $8 million. The lease income recorded in 2002 and
2001 has been included in income from discontinued operations (see Note 10).
As of December 31, 2002, TGP, EPNG and ANR have excess purchase costs
associated with their acquisition. Total excess costs on these pipelines were
approximately $5 billion and accumulated depreciation was approximately $1
billion. These excess costs are being amortized over the life of the related
pipeline assets, and our amortization expense during 2002 was approximately $71
million. The adoption of SFAS No. 142 did not impact these amounts since they
were included as part of our property, plant and equipment, rather than as
goodwill.
We have goodwill recorded as a result of the acquisitions of ANR and CIG.
This goodwill was $723 million at December 31, 2002, and $310 million of
accumulated amortization. In conjunction with adoption of SFAS 142, on January
1, 2002, we ceased our amortization of this goodwill and performed the required
impairment tests on this goodwill. No impairment of this goodwill was indicated
as of January 1, 2002 and December 31, 2002.
18. DEBT, OTHER FINANCING OBLIGATIONS AND OTHER CREDIT FACILITIES
At December 31, 2002, our weighted average interest rate on our commercial
paper and short-term credit facilities was 2.69%, and at December 31, 2001, it
was 3.2%. We had the following short-term borrowings and other financing
obligations from continuing operations, at December 31:
2002 2001
------ ------
(IN MILLIONS)
Short-term credit facilities................................ $1,500 $ 111
Commercial paper............................................ -- 1,265
Current maturities of long-term debt and other financing
obligations............................................... 575 1,299
Notes payable............................................... -- 64
------ ------
Total(1).......................................... $2,075 $2,739
====== ======
-------------------------
(1) Excludes $500 million of short-term debt that is classified as discontinued
operations as of December 31, 2001.
133
Credit Facilities
We have historically used commercial paper programs to manage our
short-term cash requirements. Under our programs we can borrow up to $3 billion
through a combination of individual corporate, TGP and EPNG commercial paper
programs of $1 billion each. However, as a result of our credit downgrade, we
are not currently issuing commercial paper to meet our liquidity needs.
In May 2002, we renewed our existing 364-day, $3 billion revolving credit
and competitive advance facility. EPNG and TGP are also designated borrowers
under this new facility and, as such, are jointly and severally liable for any
amounts outstanding. This facility matures in May 2003 and provides that amounts
outstanding on that date are not due until May 2004. We also maintain a 3-year,
$1 billion, revolving credit and competitive advance facility under which we can
conduct short-term borrowings and other commercial credit transactions. In June
2002, we amended this facility to permit us to issue up to $500 million in
letters of credit and to adjust pricing terms. This facility matures in August
2003, and El Paso CGP (formerly Coastal), EPNG and TGP, our subsidiaries, are
designated borrowers under the facility and, as such, are jointly and severally
liable for any amounts outstanding. The interest rate under both of these
facilities varies based on our senior unsecured debt rating, and as of December
31, 2002, borrowings under these facilities have a rate of LIBOR plus 1.00% plus
a 0.25% utilization fee. At December 31, 2002, we had $1.5 billion outstanding
under the $3 billion facility and issued approximately $456 million letters of
credit under the $1 billion facility. In February 2003, we borrowed $500 million
under the $1 billion facility.
The availability of borrowings under our credit and borrowing agreements is
subject to specified conditions, which we currently meet. These conditions
include compliance with the financial covenants and ratios required by such
agreements, absence of default under such agreements, and continued accuracy of
the representations and warranties contained in such agreements.
Restrictive Covenants
We and our subsidiaries have entered into debt instruments and guaranty
agreements that contain covenants such as restrictions on debt levels,
restrictions on liens securing debt and guarantees, restrictions on mergers and
on the sales of assets, capitalization requirements, dividend restrictions and
cross-payment default and cross-acceleration provisions. A breach of any of
these covenants could result in acceleration of our debt and other financial
obligations and that of our subsidiaries.
Under our revolving credit facilities, the significant debt covenants and
cross defaults are:
(a) the ratio of consolidated debt and guarantees to capitalization
(excluding certain project financing and securitization programs
and other miscellaneous items as defined in the agreement) cannot
exceed 70 percent;
(b) the consolidated debt and guarantees (other than excluded items)
of our subsidiaries cannot exceed the greater of $600 million or
10 percent of our consolidated net worth;
(c) we or our principal subsidiaries cannot permit liens on the
equity interest in our principal subsidiaries or create liens on
assets material to our consolidated operations securing debt and
guarantees (other than excluded items) exceeding the greater of
$300 million or 10 percent of our consolidated net worth, subject
to certain permitted exceptions; and
(d) the occurrence of an event of default for any non-payment of
principal, interest or premium with respect to debt (other than
excluded items) in an aggregate principal amount of $200 million
or more; or the occurrence of any other event of default with
respect to such debt that results in the acceleration thereof.
We were in compliance with the above covenants as of the date of this
filing, including our ratio of debt to capitalization (as defined under our
agreements), which was 63.2 percent at year end. At December 31, 2002, we had
$1.5 billion outstanding under the $3 billion facility and issued approximately
$456 million letters of credit under the $1 billion facility. In February 2003,
we borrowed $500 million under the $1 billion facility.
134
We have also issued various guarantees securing financial obligations of
our subsidiaries and unconsolidated affiliates with similar covenants as in the
above credit facilities.
With respect to guarantees issued by our subsidiaries, the most significant
debt covenant, in addition to the covenants discussed above, is that El Paso CGP
must maintain a minimum net worth of $1.2 billion. If breached, the amounts
guaranteed by the guaranty agreements could be accelerated. The guaranty
agreements also have a $30 million cross-acceleration provision. El Paso CGP's
net worth at December 31, 2002, was $4.3 billion.
In addition, three of our subsidiaries have indentures associated with
their public debt that contain $5 million of cross-acceleration provisions.
135
Our long-term debt and other financing obligations outstanding consisted of
the following at December 31:
2002 2001
------- -------
(IN MILLIONS)
Long-term debt(3)
El Paso Corporation
Senior notes, 5.75% through 7.125%, due 2006 through
2009................................................. $ 1,597 $ 989
Equity Security Units, 6.14% due 2007.................. 575 --
Notes, 6.625% through 7.875%, due 2005 through 2018.... 2,021 1,600
Medium-term notes, 7.002% through 9.25%, due 2004
through 2031......................................... 2,812 1,600
Zero coupon convertible debentures due 2021............ 848 812
El Paso Tennessee Pipeline
Notes, 7.25% through 10.0%, due 2008 through 2025...... 51 51
Debentures, 6.5% through 7.875%, due 2002 through
2005................................................. -- 12
Tennessee Gas Pipeline
Debentures, 6.0% through 7.625%, due 2011 through
2037................................................. 1,386 1,386
Notes, 8.375%, due 2032................................ 240 --
El Paso Natural Gas
Notes, 6.75% through 8.375%, due 2002 through 2032..... 500 415
Debentures, 7.5% and 8.625%, due 2022 and 2026......... 460 460
Southern Natural Gas
Notes, 6.125% through 8.625%, due 2002 through 2032.... 800 700
Field Services(1)
Medium term notes, 7.41% through 9.25% due 2002 through
2012................................................. -- 164
El Paso CGP(2)
Senior notes, 6.2% through 8.125%, due 2002 through
2010................................................. 1,305 1,565
Floating rate senior notes, due 2002 through 2003...... 200 600
Senior debentures, 6.375% through 10.75%, due 2003
through 2037......................................... 1,497 1,497
FELINE PRIDES, 6.625%, due 2004........................ -- 460
Valero lease financing loan due 2004(2)................ 240 240
Power
Non-recourse senior notes, 7.75% and 7.944%, due 2008
and 2016............................................. 915 --
Non-recourse notes 8.5%, due 2005...................... 126 --
El Paso Production Company
Floating rate notes, due 2005 and 2006................. 200 200
ANR Pipeline
Debentures, 7.0% through 9.625%, due 2021 through
2025................................................. 500 500
Notes, 13.75% due 2010................................. 13 --
Colorado Interstate Gas
Debentures, 6.85% through 10.0%, due 2005 and 2037..... 280 280
Other..................................................... 145 432
------- -------
16,711 13,963
------- -------
Other Financing Obligations(3)
Natural gas production payment......................... -- 215
Other.................................................. 17 --
------- -------
17 215
------- -------
Subtotal.......................................... 16,728 14,178
136
2002 2001
------- -------
(IN MILLIONS)
Less:
Unamortized discount on long-term debt................. 47 39
Current maturities..................................... 575 1,299
------- -------
Total long-term and other financing obligations,
less current maturities......................... $16,106 $12,840
======= =======
---------------
(1) The company holding these notes was merged into El Paso Corporation in 2002.
(2) The Valero lease financing loan, a general corporate obligation, was
collateralized by the lease payments from Valero under their lease from our
Corpus Christi refinery. This loan was repaid in February 2003.
(3) Excluded from these amounts as of December 31, 2001, are $51 million of
other long-term debt and $500 million of crude oil prepayments (that were
secured by our agreement to deliver a fixed quantity of crude oil to a
specified delivery point in the future). As of December 31, 2002, all of the
crude oil prepayment obligations had been paid. These amounts have been
classified as liabilities from discontinued operations (see Note 10).
Aggregate maturities of the principal amounts of long-term debt and other
financing obligations for the next 5 years and in total thereafter are as
follows (in millions):
2003........................................................ $ 575
2004........................................................ 586
2005........................................................ 610
2006........................................................ 1,234
2007........................................................ 1,133
Thereafter.................................................. 12,590
-------
Total long-term debt and other financing
obligations, including current maturities........ $16,728
=======
Our zero coupon convertible debentures have a maturity value of $1.8
billion, are due 2021 and have a yield to maturity of 4%. The holders can cause
us to repurchase these at their option in years 2006, 2011 and 2016, at which
time we can elect to settle in cash or common stock. These debentures are
convertible into 8,456,589 shares of our common stock, which is based on a
conversion rate of 4.7872 shares per $1,000 principal amount at maturity. This
rate is equal to a conversion price of $94.604 per share of our common stock.
In June 2002, we issued 51.8 million shares of our common stock at a public
offering price of $19.95 per share. Net proceeds from the offering were
approximately $1 billion.
In June 2002, we issued 11.5 million, 9% equity security units. Equity
security units consist of two securities: i) a purchase contract on which we pay
quarterly contract adjustment payments at an annual rate of 2.86% and that
requires its holder to buy our common stock to be settled on August 16, 2005,
and ii) a senior note due August 16, 2007, with a principal amount of $50 per
unit, and on which we pay quarterly interest payments at an annual rate of 6.14%
beginning August 16, 2002. The senior notes we issued had a total principal
value of $575 million and are pledged to secure the holders obligation to
purchase shares of our common stock under the purchase contracts.
When the purchase contracts are settled in 2005, we will issue common
stock. At that time, the proceeds will be allocated between common stock and
additional paid-in capital. The number of common shares issued will depend on
the prior consecutive 20-trading day average closing price of our common stock
determined on the third trading day immediately prior to the stock purchase
date. We will issue a minimum of approximately 24 million shares and up to a
maximum of 28.8 million shares on the settlement date, depending on our average
stock price. We recorded approximately $43 million of other non-current
liabilities to reflect the present value of the quarterly contract adjustment
payments that we are required to make on these units at an annual rate of 2.86%
of the stated amount of $50 per purchase contract with an offsetting reduction
in additional paid-in capital. The quarterly contract adjustment payments are
allocated between the liability
137
recognized at the date of issuance and additional paid-in capital based on a
constant rate over the term of the purchase contracts.
Fees and expenses incurred in connection with the equity security units
offering were allocated between the senior notes and the purchase contracts
based on their respective fair values on the issuance date. The amount allocated
to the senior notes is recognized as interest expense over the term of the
senior notes. The amount allocated to the purchase contracts is recorded as
additional paid-in capital.
In July 2002, Utility Contract Funding issued $829 million of 7.944% senior
secured notes due in 2016. This financing is non-recourse to other El Paso
companies, as it is independently supported only by the cash flows and contracts
of Utility Contract Funding including obligations of Public Service Electric and
Gas under a restructured power contract and of Morgan Stanley under a power
supply agreement. In connection with the credit enhancement provided by Morgan
Stanley's participation, we paid them $36 million in consideration for entering
into the supply agreement.
In July 2002, we entered into two cross-currency swap transactions which
effectively hedged E400 million of our euro currency risk on our E500 million
Euro-denominated debt. In the first transaction, E250 million of our 7.125%
fixed rate was swapped for $252.5 million of floating rate debt at a rate of the
six-month LIBOR plus a spread of 2.195%. A second transaction swapped E150
million of our 7.125% fixed rate euro based debt for $151.5 million, 7.08% fixed
dollar based debt. In December 2002, we terminated cross-currency swap
transactions which had effectively hedged E675 million euro currency risk. Our
E275 million exposure remains hedged at an effective rate of 6.59% through its
maturity in 2006.
In August 2002, we issued 12,184,444 shares of common stock to satisfy
purchase contract obligations under our FELINE PRIDES(SM) program. In return for
the issuance of the stock, we received approximately $25 million in cash from
the maturity of a zero coupon bond and the return of $435 million of our
existing 6.625% senior debentures due August 2004 that were issued in 1999. The
zero coupon bond and the senior debentures had been held as collateral for the
purchase contract obligations. The $25 million received from the maturity of the
zero coupon bond was used to retire additional senior debentures. Total debt
reduction from the issuance of the common stock was approximately $460 million.
In January 2003, we retired various debt obligations of approximately $47
million. In February 2003, El Paso CGP retired $240 million 3.07% long-term debt
related to the Valero lease.
In March 2003, our subsidiaries, Southern Natural Gas and ANR Pipeline
issued senior notes in concurrent offerings totaling $700 million:
- Southern Natural Gas Company issued $400 million of 8 7/8% senior
unsecured notes due 2010, raising net proceeds of $385 million. Proceeds
from the offering were used, in part, to repay intercompany obligations
of $290 million and Southern Natural Gas retained $95 million of net
proceeds to fund its future capital expenditures.
- ANR Pipeline Company issued $300 million of 8 7/8% senior unsecured notes
due 2010, raising net proceeds of $288 million. ANR used $263 million of
cash proceeds from the offering to reduce existing intercompany payables.
ANR also retained $25 million to fund its future capital expenditures.
In March 2003, we closed a $1.2 billion two-year term loan and used the
proceeds to retire the approximately $913 million net balance of the Trinity
River financing. Trinity River (also known as Red River) was formed in 1999 to
invest in capital projects and other assets. The new $1.2 billion loan has
scheduled payments of $300 million in June 2004, $300 million in September 2004,
and the $600 million balance in March 2005. The loan facility is collateralized
by a direct pledge of natural gas and oil properties that were previously in the
Trinity River financing. The loan facility carries a floating interest rate of
LIBOR plus 4.25%. The floating interest rate can be based on a LIBOR rate of no
less than 3.50%. Additionally, the loan facility requires us to pay a facility
fee equal to 2% per annum on the average daily aggregate outstanding principal
amount of the loan. The natural gas and oil properties that collateralize this
financing agreement have reserves of approximately 2.3 Tcfe.
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Available Capacity Under Shelf Registration Statements
In April 2001, we filed a shelf registration statement with the Securities
and Exchange Commission (SEC) to sell, from time to time, up to a total of $3
billion in debt securities, preferred and common stock, medium term notes, or
trust securities. At December 31, 2001, we had approximately $920 million
remaining from this shelf registration statement under which we issued
additional securities in January 2002, fully utilizing the remaining capacity.
In February 2002, we filed a new shelf registration statement with the SEC
that allows us to issue up to $3 billion in securities. Under this registration
statement, we can issue a combination of debt, equity and other instruments,
including trust preferred securities of two wholly owned trusts, El Paso Capital
Trust II and El Paso Capital Trust III. If we issue securities from these
trusts, we will be required to issue full and unconditional guarantees on these
securities. As of December 31, 2002, we had $818 million remaining capacity
under this shelf registration statement.
As of December 31, 2002, TGP and SNG had no available capacity under shelf
registration statements on file with the SEC.
19. PREFERRED INTERESTS OF CONSOLIDATED SUBSIDIARIES
In the past, we entered into financing transactions that have been
accomplished through the sale of preferred interests in consolidated
subsidiaries. Total amounts outstanding under these programs at December 31,
2002 and 2001, were as follows (in millions):
2002 2001
------ ------
Consolidated trusts(1)...................................... $ 625 $ 925
Trinity River(2)............................................ 980 980
Clydesdale.................................................. 950 1,000
Preferred stock of subsidiaries............................. 400 465
Gemstone.................................................... 300 300
Consolidated partnership.................................... -- 285
------ ------
$3,255 $3,955
====== ======
---------------
(1) The consolidated trusts are composed of Capital Trust I, Coastal Finance I
and Capital Trust IV. In November 2002, we repurchased all of the preferred
securities for Capital Trust IV for $300 million plus accrued and unpaid
dividends.
(2) This preferred interest was redeemed in March 2003 with the proceeds from a
$1.2 billion debt facility with scheduled maturities of $300 million in June
2004, $300 million in September 2004 and the $600 million in March 2005.
Capital Trust I. In March 1998, we formed El Paso Energy Capital Trust I,
a wholly owned subsidiary, which issued 6.5 million of 4 3/4% trust convertible
preferred securities for $325 million. We own all of the Common Securities of
Trust I. Trust I exists for the sole purpose of issuing preferred securities and
investing the proceeds in 4 3/4% convertible subordinated debentures we issued
due 2028, their sole asset. Trust I's sole source of income is interest earned
on these debentures. This interest income is used to pay the obligations on
Trust I's preferred securities. We provide a full and unconditional guarantee of
Trust I's preferred securities. Distributions paid on the preferred securities
are included as return on preferred interests of consolidated subsidiaries in
our income statement.
Trust I's preferred securities are non-voting (except in limited
circumstances), pay quarterly distributions at an annual rate of 4 3/4%, carry a
liquidation value of $50 per security plus accrued and unpaid distributions and
are convertible into our common shares at any time prior to the close of
business on March 31, 2028, at the option of the holder at a rate of 1.2022
common shares for each Trust I preferred security (equivalent to a conversion
price of $41.59 per common share). As of December 31, 2002, we had approximately
6.5 million Trust I preferred securities outstanding.
Coastal Finance I. Coastal Finance I is an indirect wholly owned business
trust formed in May 1998. Coastal Finance I completed a public offering of 12
million mandatory redemption preferred securities for
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$300 million. Coastal Finance I holds subordinated debt securities issued by our
wholly owned subsidiary, El Paso CGP, that it purchased with the proceeds of the
preferred securities offering. Cumulative quarterly distributions are being paid
on the preferred securities at an annual rate of 8.375% of the liquidation
amount of $25 per preferred security. Coastal Finance I's only source of income
is interest earned on these subordinated debt securities. This interest income
is used to pay the obligations on Coastal Finance I's preferred securities. The
preferred securities are mandatorily redeemable on the maturity date, May 13,
2038, and may be redeemed at our option on or after May 13, 2003, or earlier if
various events occur. The redemption price to be paid is $25 per preferred
security, plus accrued and unpaid distributions to the date of redemption. El
Paso CGP provides a guarantee of the payment of obligations of Coastal Finance I
related to its preferred securities to the extent Coastal Finance I has funds
available. El Paso has no obligation to provide funds to Coastal Finance I for
the payment of or redemption of the preferred securities outside of our
obligation to pay interest and principal on the subordinated debt securities.
Capital Trust IV. In May 2000, we formed El Paso Energy Capital Trust IV,
a wholly owned subsidiary which issued $300 million of preferred securities to
an affiliate of Banc of America. These preferred securities paid cash
distributions at a floating rate equal to the three-month LIBOR plus 75 basis
points. As of December 31, 2001, the floating rate was 2.83%. In November 2002,
we purchased all of the preferred securities of Trust IV for $300 million plus
accrued and unpaid dividends and terminated obligations to issue equity
securities under this agreement.
Trinity River (also known as Red River). During 1999, we formed a series
of companies that we refer to as Trinity River. Trinity River is a subsidiary
that was formed to provide financing to invest in various capital projects and
other assets. Red River Investors, L.L.C., an entity owned by three investors,
West LB, Stonehurst and Ambac, raised funds from a consortium of banks that
contributed cash of $980 million into Trinity River during 1999 in exchange for
the preferred securities. Red River Investors is entitled to an adjustable
preferred return derived from Trinity River's net income. The preferred
interest, which has limited voting rights, was collateralized by a combination
of notes payable from us and various El Paso entities, including our Mojave
Pipeline Company, Bear Creek Storage Company, various natural gas and oil
properties and 5.75 million of our El Paso Energy Partners common units. The
assets, liabilities and operations of Trinity River are included in our
financial statements and we account for the investor's preferred interest in our
consolidated subsidiary as preferred interests of consolidated subsidiaries in
our balance sheet and the preferred return as return on preferred securities of
subsidiary in our income statement. As a result of El Paso's and its
subsidiaries' credit rating downgrades by both Moody's and Standard & Poor's,
restrictions resulted on our use of excess cash generated by these operating
businesses for purposes other than their own operating needs or to redeem the
preferred interests of Trinity River. In the first quarter of 2003, we redeemed
the preferred interests of Trinity River, eliminating these cash restrictions.
Clydesdale (also known as Mustang). During 2000, we formed a series of
companies that we refer to as Clydesdale. Clydesdale is a subsidiary that was
formed to provide financing to invest in various capital projects and other
assets. Mustang Investors LLC, an entity owned by two investors West LB and
Ambac, raised funds from a consortium of banks, which contributed cash of $1
billion into Clydesdale in exchange for preferred securities. Mustang is
entitled to an adjustable preferred return derived from Clydesdale's net income.
The preferred interest, which has limited voting rights, is collateralized by a
combination of notes payable from us, a production payment from us, various
natural gas and oil properties and various companies, including our ownership in
Colorado Interstate Gas Company. We have the option to acquire Mustang
Investors' interest in Clydesdale at any time prior to June 2006. If we do not
exercise this option or if the agreement is not extended, we could be required
to liquidate the assets supporting this transaction. The assets, liabilities,
and operations of Clydesdale are included in our financial statements and we
account for the investor's preferred interest in our consolidated subsidiary as
preferred interests of consolidated subsidiaries in our balance sheet and the
preferred return as return on preferred stock of consolidated subsidiaries in
our income statement. In July 2002, we completed the amendments to the
Clydesdale agreements to remove the rating trigger that could have required us
to liquidate the assets supporting the transaction in the event we were
downgraded to below investment grade by both Standard & Poor's and Moody's. As a
result of El Paso's and its subsidiaries credit rating downgrades by both
Moody's and Standard & Poor's, restrictions resulted on use of excess cash
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generated by these assets for purpose other than their own operating needs or to
redeem the preferred interests of Clydesdale. A portion of these funds were used
to redeem the preferred interests of Clydesdale, including $50 million as of
December 31, 2002, and an additional $189 million in February and March 2003.
These payments are reflected as reductions of preferred interests of
consolidated subsidiaries. Quarterly payments will be made to reduce the
minority interests.
El Paso Tennessee Preferred Stock. In 1996, El Paso Tennessee Pipeline
Co., our subsidiary, issued 6 million shares of publicly registered 8.25%
cumulative preferred stock with a par value of $50 per share for $300 million.
The preferred stock is redeemable, at the option of El Paso Tennessee, at a
redemption price equal to $50 per share, plus accrued and unpaid dividends, at
any time after January 2002. During the three years ended December 31, 2002,
dividends of approximately $25 million were paid each year on the preferred
stock.
Coastal Securities Company Preferred Stock. In 1996, Coastal Securities
Company Limited, our wholly owned subsidiary, issued 4 million shares of
preferred stock for $100 million to Cannon Investors Trust, which is an entity
comprised of a consortium of banks. Quarterly cash dividends are being paid on
the preferred stock at a rate based on LIBOR plus a margin of 2.11% based on the
long-term unsecured debt rating of our subsidiary, El Paso CGP. The holders of
the preferred securities have a right to reset the dividend rate on December 20,
2003 and every seven years thereafter. If the new rate is not acceptable to the
preferred holders, they have a right to require us to redeem the preferred
securities. The preferred holders are also entitled to participating dividends
based on refining margins of our Aruba refinery. Coastal Securities may redeem
the preferred stock for cash at the liquidation price of $100 million plus
accrued and unpaid dividends.
El Paso Oil & Gas Resources Preferred Units. In 1999, El Paso Oil & Gas
Resources Company, L.P. (formerly Coastal Oil & Gas Resources, Inc.), our wholly
owned subsidiary, issued 50,000 units of preferred units for $50 million to
UAGC, Inc., a subsidiary of Rabobank International. The preferred shareholders
were entitled to quarterly cash dividends at a rate based on LIBOR. In July
2002, we repurchased the entire 50,000 units for $50 million plus accrued and
unpaid dividends.
Coastal Limited Ventures Preferred Stock. In 1999, Coastal Limited
Ventures, Inc., our wholly owned subsidiary, issued 150,000 shares of preferred
stock for $15 million to JP Morgan Chase Bank (formerly Chase Manhattan Bank).
The preferred shareholders were entitled to quarterly cash dividends at an
annual rate of 6%. In July 2002, we repurchased the entire 150,000 shares for
$15 million plus accrued and unpaid dividends.
Gemstone. As part of the Gemstone transaction, our wholly owned subsidiary,
Topaz issued a minority member interest to Gemstone Investor, an entity
indirectly owned by Rabobank, for $300 million. Gemstone Investor is entitled to
a cumulative preferred return of 8.03% on its interest. The agreements
underlying this transaction expire in 2004, or earlier if we sell the
international power assets owned indirectly by Topaz. Gemstone Investor's
preferred interest is redeemable at liquidation value plus accrued and unpaid
dividends. In January 2003, we notified Rabobank that we were exercising our
right under the partnership agreements to purchase all of Rabobank's $50 million
of equity in Gemstone. Unless we find a new partner, we will consolidate
Gemstone upon our purchase of Rabobank's third party equity in Gemstone. At that
time we will consolidate this minority member interest in Topaz.
Consolidated Partnership. In December 1999, Coastal Limited Ventures
contributed assets to a limited partnership in exchange for a controlling
general partnership interest. Limited interests in the partnership were issued
to RBCC, an unaffiliated investor for $285 million. The limited partners were
entitled to a cumulative priority return based on LIBOR. In July 2002, we
repurchased the limited partnership interest in El Paso Production Oil & Gas
Associates, L.P., formerly known as Coastal Oil and Gas Associates and a
partnership formed with Coastal Limited Ventures, Inc. The payment of
approximately $285 million to the unaffiliated investor was equal to the sum of
the limited partner's outstanding capital plus unpaid priority returns.
El Paso Energy Capital Trust I, Coastal Finance I, El Paso Energy Capital
Trust IV, Coastal Securities Company Limited, Trinity River, Clydesdale, Topaz
and El Paso Tennessee Pipeline Co. are all either business trusts we control or
companies in which we own all of the voting stock. Consequently, each of these
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entities is consolidated in our financial statements. However, each of these
entities has issued preferred securities, and these preferred interests that are
held by various unaffiliated investors are presented in our balance sheet as
preferred interests of consolidated subsidiaries. The preferred distributions
paid on these preferred interests are presented in our income statement as
return of preferred interests of consolidated subsidiaries. Our accounting for
some of these preferred interests of consolidated subsidiaries will be impacted
by our adoption of the new accounting rules on consolidations in July 2003. For
a discussion of the accounting impact, see Note 1 under New Accounting
Pronouncements Issued But Not Yet Adopted.
20. COMMITMENTS AND CONTINGENCIES
Legal Proceedings
Western Energy Settlement. On March 20, 2003, we entered into an agreement
in principle (the Western Energy Settlement) with various public and private
claimants, including the states of California, Washington, Oregon, and Nevada,
to resolve the principal litigation, claims, and regulatory proceedings, which
are more fully described below, against us and our subsidiaries relating to the
sale or delivery of natural gas and electricity from September 1996 to the date
of the Western Energy Settlement. The Western Energy Settlement resulted in an
after-tax charge of approximately $650 million in the fourth quarter of 2002.
Among other things, the components of the settlement include:
- a cash payment of $100 million;
- a $2 million cash payment from our officer bonus pool;
- the issuance of approximately 26.4 million shares of El Paso common
stock;
- delivery to the California border of $45 million worth of natural gas
annually for 20 years beginning in 2004;
- a reduction of the pricing of our long-term power supply contracts with
the California Department of Water Resources of $125 million over the
remaining term of those contracts, which run through the end of 2005;
- payments of $22 million per year for 20 years;
- for a period of five years, EPNG will make available at its California
delivery points 3,290 MMcf per day of capacity on a primary delivery
point basis;
- for a period of five years, our affiliates will be subject to
restrictions in subscribing for new capacity on the EPNG system; and
- no admission of wrongdoing.
The agreement in principle is subject to the negotiation of a formal settlement
agreement, portions of which will then be filed with the courts and the FERC for
approval. Upon approval, the parties will release us from covered claims that
they may have against us and our subsidiaries for the period covered by the
Western Energy Settlement, and the litigation, claims, and regulatory
proceedings against us and our subsidiaries will be dismissed with prejudice.
California Lawsuits. We and several of our subsidiaries have been named as
defendants in fifteen purported class action, municipal or individual lawsuits,
filed in California state courts. These suits contend that our entities acted
improperly to limit the construction of new pipeline capacity to California
and/or to manipulate the price of natural gas sold into the California
marketplace. Specifically, the plaintiffs argue that our conduct violates
California's antitrust statute (Cartwright Act), constitutes unfair and unlawful
business practices prohibited by California statutes, and amounts to a violation
of California's common law restrictions against monopolization. In general, the
plaintiffs are seeking (i) declaratory and injunctive relief regarding allegedly
anticompetitive actions, (ii) restitution, including treble damages, (iii)
disgorgement of profits, (iv) prejudgment and post-judgment interest, (v) costs
of prosecuting the actions and (vi) attorney's fees. All fifteen cases have been
consolidated before a single judge, under two omnibus complaints, one of which
has
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been set for trial in September 2003. All of the class action and municipal
lawsuits and all but one of the individual lawsuits will be resolved upon
finalization and approval of the Western Energy Settlement.
In November 2002, a lawsuit titled Gus M. Bustamante v. The McGraw-Hill
Companies was filed in the Superior Court of California, County of Los Angeles
by several individuals, including Lt. Governor Bustamante acting as a private
citizen, against numerous defendants, including our subsidiary EPNG, alleging
the creation of artificially high natural gas index prices via the reporting of
false price and volume information. This purported class action on behalf of
California consumers alleges various unfair business practices and seeks
restitution, disgorgement of profits, compensatory and punitive damages, and
civil fines. This lawsuit will be resolved upon finalization and approval of the
Western Energy Settlement.
In September 2001, we received a civil document subpoena from the
California Attorney General, seeking information said to be relevant to the
department's ongoing investigation into the high electricity prices in
California. We have cooperated in responding to the Attorney General's discovery
requests. This proceeding will be resolved upon finalization and approval of the
Western Energy Settlement.
In May 2002, two lawsuits challenging the validity of long-term power
contracts entered into by the California Department of Water Resources in early
2001 were filed in California state court against 26 separate companies,
including our subsidiary El Paso Merchant Energy, L.P. (EPME or Merchant
Energy). In general, the plaintiffs allege unfair business practices and seek
restitution damages and an injunction against the enforcement of the contract
provisions. These cases have been removed to federal court. Our costs and legal
exposure related to these lawsuits and claims are not currently determinable.
In January 2003, a lawsuit titled IMC Chemicals v. EPME, et al. was filed
in California state court against us, EPNG and EPME. The suit arises out of a
gas supply contract between IMC Chemicals (IMCC) and EPME and seeks to void the
Gas Purchase Agreement between IMCC and EPME for gas purchases until December
2003. IMCC contends that EPME and its affiliates manipulated market prices for
natural gas and, as part of that manipulation, induced IMCC to enter into the
contract. In furtherance of its attempt to void the contract, IMCC repeats the
allegations and claims of the California lawsuits described above. EPME intends
to enforce the terms of the contract and counterclaim for contract damages. Our
costs and legal exposure related to this lawsuit are not currently determinable.
Other Energy Market Lawsuits. The state of Nevada and two individuals
filed a class action lawsuit in Nevada state court naming us and a number of our
subsidiaries and affiliates as defendants. The allegations are similar to those
in the California cases. The suit seeks monetary damages and other relief under
Nevada antitrust and consumer protection laws. This lawsuit will be resolved
upon finalization and approval of the Western Energy Settlement.
In December 2002, two class action complaints were filed, one in the state
court of Oregon and the other in the federal court in the State of Washington,
naming El Paso and more than forty other unrelated industry entities. In each
case, the complaint makes general allegations that purchasers of natural gas
and/or electricity, within the respective state, were overcharged during the
period 2000 through 2002 by the defendants, who allegedly withheld supplies of
energy, exercised improper control of the energy market and manipulated prices.
These lawsuits allege violation of state statutes prohibiting unlawful trade
practices, fraud and negligence. The relief sought includes injunctive relief,
unspecified damages, and attorneys fees. The Washington complaint also seeks
treble damages. Our costs and legal exposure related to these lawsuits and
claims are not currently determinable.
A purported class action suit was filed in federal court in New York City
in December 2002 alleging that El Paso, EPME, EPNG, and other defendants
manipulated California's natural gas market by manipulating the spot market of
gas traded on the NYMEX. We have not yet been served with the complaint. Our
costs and legal exposure related to this lawsuit are not currently determinable.
In March 2003, the State of Arizona sued us, EPNG, EPME and other unrelated
entities on behalf of Arizona consumers. The suit alleges that the defendants
conspired to artificially inflate prices of natural gas and electricity during
2000 and 2001. Making factual allegations similar to those alleged in the
California
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cases, the suit seeks relief similar to the California cases as well, but under
Arizona antitrust and consumer fraud statutes. Our costs and legal exposure
related to this lawsuit are not currently determinable.
Shareholder Class Action Suits. Beginning in July 2002, twelve purported
shareholder class action suits alleging violations of federal securities laws
have been filed against us and several of our officers. Eleven of these suits
are now consolidated in federal court in Houston before a single judge. The
suits generally challenge the accuracy or completeness of press releases and
other public statements made during 2001 and 2002. The twelfth shareholder class
action lawsuit was filed in federal court in New York City in October 2002
challenging the accuracy or completeness of our February 27, 2002 prospectus for
an equity offering that was completed on June 21, 2002. It has since been
dismissed, in light of similar claims being asserted in the consolidated suits
in Houston. Four shareholder derivative actions have also been filed. One
shareholder derivative lawsuit was filed in federal court in Houston in August
2002. This derivative action generally alleges the same claims as those made in
the shareholder class action, has been consolidated with the shareholder class
actions pending in Houston and has been stayed. A second shareholder derivative
lawsuit was filed in Delaware State Court in October 2002 and generally alleges
the same claims as those made in the consolidated shareholder class action
lawsuit. A third shareholder derivative suit was filed in state court in Houston
in March 2002, and a fourth shareholder derivative suit was filed in state court
in Houston in November 2002. The third and fourth shareholder derivative suits
both generally allege that manipulation of California gas supply and gas prices
exposed El Paso to claims of antitrust conspiracy, FERC penalties and erosion of
share value. Our costs and legal exposure related to these lawsuits and claims
are not currently determinable.
ERISA Class Action Suit. In December 2002, a purported class action
lawsuit was filed in federal court in Houston alleging generally that our direct
and indirect communications with participants in the El Paso Corporation
Retirement Savings Plan included misrepresentations and omissions that caused
members of the class to hold and maintain investments in El Paso stock in
violation of the Employee Retirement Income Security Act (ERISA). Our costs and
legal exposure related to this lawsuit are not currently determinable.
Carlsbad. In August 2000, a main transmission line owned and operated by
EPNG ruptured at the crossing of the Pecos River near Carlsbad, New Mexico.
Twelve individuals at the site were fatally injured. On June 20, 2001, the U.S.
Department of Transportation's Office of Pipeline Safety issued a Notice of
Probable Violation and Proposed Civil Penalty to EPNG. The Notice alleged five
violations of DOT regulations, proposed fines totaling $2.5 million and proposed
corrective actions. EPNG has fully accrued for these fines. The alleged five
probable violations of the regulations of the Department of Transportation's
Office of Pipeline Safety are: (1) failure to develop an adequate internal
corrosion control program, with an associated proposed fine of $500,000; (2)
failure to investigate and minimize internal corrosion, with an associated
proposed fine of $1,000,000; (3) failure to conduct continuing surveillance on
its pipelines and consider, and respond appropriately to, unusual operating and
maintenance conditions, with an associated proposed fine of $500,000; (4)
failure to follow company procedures relating to investigating pipeline failures
and thereby to minimize the chance of recurrence, with an associated proposed
fine of $500,000; and (5) failure to maintain elevation profile drawings, with
an associated proposed fine of $25,000. In October 2001, EPNG filed a response
with the Office of Pipeline Safety disputing each of the alleged violations.
On February 11, 2003, the National Transportation Safety Board conducted a
public meeting on its investigation into the Carlsbad rupture at which the NTSB
adopted Findings, Conclusions and Recommendations based upon its investigation.
In a synopsis of the Safety Board's report, the NTSB stated that it had
determined that the probable cause of the August 19, 2000 rupture was a
significant reduction in pipe wall thickness due to severe internal corrosion,
which occurred because EPNG's corrosion control program "failed to prevent,
detect, or control internal corrosion" in the pipeline. The NTSB also determined
that ineffective federal preaccident inspections contributed to the accident by
not identifying deficiencies in EPNG's internal corrosion control program. The
NTSB's final report is pending.
On November 1, 2002, EPNG received a federal grand jury subpoena for
documents related to the Carlsbad rupture. EPNG is cooperating with the grand
jury.
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A number of personal injury and wrongful death lawsuits were filed against
EPNG in connection with the rupture. All but one of these suits have been
settled, with settlement payments fully covered by insurance. The remaining case
is Geneva Smith, et al. vs. EPEC and EPNG filed October 23, 2000 in Harris
County, Texas. In connection with the settlement of the cases, EPNG contributed
$10 million to a charitable foundation as a memorial to the families involved.
The contribution was not covered by insurance.
Parties to five settled lawsuits have since filed an additional lawsuit
titled Diane Heady et al. v. EPEC and EPNG in Harris County, Texas on November
20, 2002 seeking an additional $180 million based upon their interpretation of
earlier settlement agreements. In addition, plaintiffs' counsel for the settled
New Mexico state court cases have notified EPNG that they intend to file suit on
behalf of about twenty-three firemen and EMS personnel who responded to the fire
and who allegedly have suffered psychological trauma. We have not been served
with such a lawsuit. Our costs and legal exposure related to these lawsuits and
claims are not currently determinable. However, we believe these matters will be
fully covered by insurance.
Grynberg. In 1997, a number of our subsidiaries were named defendants in
actions brought by Jack Grynberg on behalf of the U.S. Government under the
False Claims Act. Generally, these complaints allege an industry-wide conspiracy
to underreport the heating value as well as the volumes of the natural gas
produced from federal and Native American lands, which deprived the U.S.
Government of royalties. The plaintiff in this case seeks royalties that he
contends the government should have received had the volume and heating value of
natural gas produced from royalty properties been differently measured,
analyzed, calculated and reported, together with interest, treble damages, civil
penalties, expenses and future injunctive relief to require the defendants to
adopt allegedly appropriate gas measurement practices. No monetary relief has
been specified in this case. These matters have been consolidated for pretrial
purposes (In re: Natural Gas Royalties Qui Tam Litigation, U.S. District Court
for the District of Wyoming, filed June 1997). In May 2001, the court denied the
defendants' motions to dismiss. Discovery is proceeding. Our costs and legal
exposure related to these lawsuits and claims are not currently determinable.
Will Price (formerly Quinque). A number of our subsidiaries were named as
defendants in Quinque Operating Company, et al. v. Gas Pipelines and Their
Predecessors, et al., filed in 1999 in the District Court of Stevens County,
Kansas. Quinque has been dropped as a plaintiff and Will Price has been added.
This class action complaint alleges that the defendants mismeasured natural gas
volumes and heating content of natural gas on non-federal and non-Native
American lands. The plaintiff in this case seeks certification of a nationwide
class of natural gas working interest owners and natural gas royalty owners to
recover royalties that the plaintiff contends these owners should have received
had the volume and heating value of natural gas produced from their properties
been differently measured, analyzed, calculated and reported, together with
prejudgment and postjudgment interest, punitive damages, treble damages,
attorney's fees, costs and expenses, and future injunctive relief to require the
defendants to adopt allegedly appropriate gas measurement practices. No monetary
relief has been specified in this case. Plaintiffs' motion for class
certification has been argued and we are awaiting a ruling. Our costs and legal
exposure related to this lawsuit are not currently determinable.
MTBE. In compliance with the 1990 amendments to the Clean Air Act, we use
the gasoline additive, methyl tertiary-butyl ether (MTBE), in some of our
gasoline. We also produce, buy, sell and distribute MTBE. A number of lawsuits
have been filed throughout the U.S. regarding MTBE's potential impact on water
supplies. We are currently one of several defendants in one such lawsuit in New
York. The plaintiffs seek remediation of their groundwater and prevention of
future contamination, compensatory damages for the costs of replacement water
and for diminished property values, as well as punitive damages, attorney's
fees, court costs, and, in some cases, future medical monitoring. Our costs and
legal exposure related to this lawsuit and claims are not currently
determinable.
In addition to the above matters, we and our subsidiaries and affiliates
are named defendants in numerous lawsuits and governmental proceedings that
arise in the ordinary course of our business.
For each of our outstanding legal matters, we evaluate the merits of the
case, our exposure to the matter, possible legal or settlement strategies and
the likelihood of an unfavorable outcome. If we determine that an unfavorable
outcome is probable and can be estimated, we establish the necessary accruals.
As of
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December 31, 2002, we had approximately $1,040 million accrued for all
outstanding legal matters. Approximately $29 million of the accrual was related
to discontinued operations.
Environmental Matters
We are subject to federal, state and local laws and regulations governing
environmental quality and pollution control. These laws and regulations require
us to remove or remedy the effect on the environment of the disposal or release
of specified substances at current and former operating sites. As of December
31, 2002, we had accrued approximately $482 million, including approximately
$463 million for expected remediation costs at current and former operated sites
and associated onsite, offsite and groundwater technical studies, and
approximately $19 million for related environmental legal costs, which we
anticipate incurring through 2027.
Below is a reconciliation of our accrued liability as of December 31, 2001
to our accrued liability as of December 31, 2002:
2002 2001
----- -----
(IN MILLIONS)
Balance as of January 1..................................... $565 $318
Additions/adjustments for remediation activities............ 2 247
Payments for remediation activities......................... (70) (30)
Other changes, net.......................................... (15) 30
---- ----
Balance as of December 31(1)................................ $482 $565
==== ====
---------------
(1) Approximately $109 million for 2002 and $97 million for 2001 of the accrual
was related to discontinued petroleum markets and coal mining operations.
In addition, we expect to make capital expenditures for environmental
matters of approximately $305 million in the aggregate for the years 2003
through 2007. These expenditures primarily relate to compliance with clean air
regulations. For 2003, we estimate that our total remediation expenditures will
be approximately $87 million, of which $3 million we estimate will be for
capital related expenditures. In addition, approximately $64 million of this
amount will be expended under government directed clean-up plans. The remaining
$20 million will be self-directed or in connection with facility closures.
Internal PCB Remediation Project. Since 1988, TGP, our subsidiary, has
been engaged in an internal project to identify and address the presence of
polychlorinated biphenyls (PCBs) and other substances, including those on the
Environmental Protection Agency's (EPA) List of Hazardous Substances, at
compressor stations and other facilities it operates. While conducting this
project, TGP has been in frequent contact with federal and state regulatory
agencies, both through informal negotiation and formal entry of consent orders,
to ensure that its efforts meet regulatory requirements. TGP executed a consent
order in 1994 with the EPA, governing the remediation of the relevant 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.
Kentucky PCB Project. In November 1988, the Kentucky environmental agency
filed a complaint in a Kentucky state court alleging that TGP discharged
pollutants into the waters of the state and disposed of PCBs without a permit.
The agency sought an injunction against future discharges, an order to remediate
or remove PCBs and a civil penalty. TGP entered into agreed orders with the
agency to resolve many of the issues raised in the complaint. The relevant
Kentucky compressor stations are being remediated under a 1994 consent order
with the EPA. Despite TGP's remediation efforts, the agency may raise additional
technical issues or seek additional remediation work in the future.
PCB Cost Recoveries. In May 1995, following negotiations with its
customers, TGP filed an agreement with the FERC that established a mechanism for
recovering a substantial portion of the environmental costs identified in its
internal remediation project. The agreement, which was approved by the FERC in
November 1995, provided for a PCB surcharge on firm and interruptible customers'
rates to pay for eligible costs under
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the PCB remediation project, with these surcharges to be collected over a
defined collection period. TGP has twice received approval from the FERC to
extend the collection period, which is now currently set to expire in June 2004.
The agreement also provided for bi-annual audits of eligible costs. As of
December 31, 2002, TGP has pre-collected PCB costs by approximately $115
million. The pre-collection will be reduced by future eligible costs incurred
for the remainder of the remediation project. TGP is required to the extent
actual expenditures are less than the amounts pre-collected, to refund to its
customers the unused pre-collection amount, plus carrying charges incurred up to
the date of the refunds. As of December 31, 2002, TGP has recorded a regulatory
liability (included in other non-current liabilities on our balance sheet) for
future refund obligations of approximately $55 million.
Coastal Eagle Point. From May 1999 to March 2001, our Coastal Eagle Point
Oil Company received several Administrative Orders and Notices of Civil
Administrative Penalty Assessment from the New Jersey Department of
Environmental Protection (DEP). All of the assessments are related to alleged
noncompliance with the New Jersey Air Pollution Control Act pertaining to excess
emissions from the first quarter 1998 through the fourth quarter 2000 reported
by our Eagle Point refinery in Westville, New Jersey. The DEP has assessed
penalties totaling approximately $1.3 million for these alleged violations. The
DEP has indicated a willingness to accept a reduced penalty and a supplemental
environmental project. Our Eagle Point refinery has been granted an
administrative hearing on issues raised by the assessments. Under its global
refinery enforcement initiative, the Environmental Protection Agency (EPA)
referred several Clean Air Act issues to the DEP. Our Eagle Point refinery
expects to resolve these issues along with the DEP assessments. On February 24,
2003, EPA Region 2 issued a Compliance Order based on a 1999 EPA inspection of
the refinery's leak detection and repair program. Alleged violations include
failure to monitor all components, and failure to timely repair leaking
components. During an August 2000 follow-up inspection, the EPA confirmed our
Eagle Point refinery had improved implementation of the program. The Compliance
Order requires documentation of compliance with the program. Our Eagle Point
refinery has requested a conference with EPA to discuss the Order and the
alleged violations. The EPA may seek a monetary penalty.
CERCLA Matters. We have received notice that we could be designated, or
have been asked for information to determine whether we could be designated, as
a Potentially Responsible Party (PRP) with respect to 58 active sites under the
Comprehensive Environmental Response, Compensation and Liability Act (CERCLA) or
state equivalents. We have sought to resolve our liability as a PRP at these
sites through indemnification by third parties and settlements which provide for
payment of our allocable share of remediation costs. As of December 31, 2002, we
have estimated our share of the remediation costs at these sites to be between
$29 million and $41 million. Since the clean-up costs are estimates and are
subject to revision as more information becomes available about the extent of
remediation required, and because in some cases we have asserted a defense to
any liability, our estimates could change. Moreover, liability under the federal
CERCLA statute is joint and several, meaning that we could be required to pay in
excess of our pro rata share of remediation costs. Our understanding of the
financial strength of other PRPs has been considered, where appropriate, in
determining our estimated liabilities.
It is possible that new information or future developments could require us
to reassess our potential exposure related to environmental matters. We may
incur significant costs and liabilities in order to comply with existing
environmental laws and regulations. It is also possible that other developments,
such as increasingly strict environmental laws and regulations and claims for
damages to property, employees, other persons and the environment resulting from
our current or past operations, could result in substantial costs and
liabilities in the future. As this information becomes available, or other
relevant developments occur, we will adjust our accrual amounts accordingly.
While there are still uncertainties relating to the ultimate costs we may incur,
based upon our evaluation and experience to date, we believe our current
reserves are adequate.
Rates and Regulatory Matters
Wholesale Power Customers' Complaints. In late 2001 and early 2002,
several wholesale power customers filed complaints with the FERC against EPME
and other wholesale power marketers (a list of the complaints is included below
for which the primary customers are: Nevada Power Co. and Sierra Pacific Power
Co. (NPSP), PacifiCorp, City of Burbank, the California Public Utilities
Commission and the
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California Electricity Oversight Board (CPUC/CEOB). These customers entered into
contracts with EPME and other wholesale power suppliers for the purchase of
power to be delivered in the future. In these complaints, the customers have
asked the FERC to reform the contracts they entered into with EPME and other
wholesale power marketers on the grounds that they involve rates and terms that
are "unjust and unreasonable" or "contrary to" the public interest within the
meaning of the Federal Power Act (FPA). EPME and other respondents believe the
allegations in the complaint are without merit and have asked the FERC to
dismiss these complaints. In the NPSP matter, the ALJ issued an initial decision
concluding that the contracts at issue should not be modified, and the
complaints should be dismissed. In the CPUC/CEOB matter, the ALJ issued a
decision finding the public interest standard applies to the contract at issue,
which finding is consistent with the initial decision of the ALJ in the NPSP
case. The CPUC/CEOB matter will be fully resolved upon finalization and approval
of the Western Energy Settlement. In the PacifiCorp matter, the ALJ issued an
initial decision concluding that the complaint filed by PacifiCorp against EPME
(and other respondents) should be dismissed with prejudice. The decisions of the
ALJs will be submitted to the FERC for its review. On March 11, 2003, the City
of Burbank matter was set for hearing.
CPUC Complaint Proceeding. In April 2000, the Public Utilities Commission
of the State of California (CPUC) filed a complaint under Section 5 of the
Natural Gas Act (NGA) with the FERC alleging that the sale of approximately 1.2
billion cubic feet per day of capacity by EPNG to EPME, both of whom are our
wholly owned subsidiaries, raised issues of market power and violation of FERC's
marketing affiliate regulations and asked that the contracts be voided. Although
the FERC held that EPNG did not violate its marketing affiliate requirements, it
established a hearing before an ALJ to address the market power issue. In the
spring and summer of 2001, two hearings were held before the ALJ to address the
market power issue and, at the request of the ALJ, the affiliate issue. In
October 2001, the ALJ issued an initial decision on the two issues, finding that
the record did not support a finding that either EPNG or EPME had exercised
market power and that accordingly the market power claims should be dismissed.
The ALJ found, however, that EPNG had violated FERC's marketing affiliate rule.
EPNG and other parties filed briefs on exceptions and briefs opposing exceptions
to the October initial decision.
Also in October 2001, the FERC's Office of Market Oversight and Enforcement
filed comments stating that the record at the hearings was inadequate to
conclude that EPNG had complied with FERC regulations in the transportation of
gas to California. In December 2001, the FERC remanded the proceeding to the ALJ
for a supplemental hearing on the availability of capacity at EPNG's California
delivery points. On September 23, 2002, the ALJ issued his initial decision,
again finding that there was no evidence that EPME had exercised market power
during the period at issue to drive up California gas prices and therefore
recommending that the complaint against EPME be dismissed. However, the ALJ
found that EPNG had withheld at least 345 MMcf/d of capacity (and perhaps as
much as 696 MMcf/d) from the California market during the period from November
1, 2000 through March 31, 2001. The ALJ found that this alleged withholding
violated EPNG's certificate obligations and was an exercise of market power that
increased the gas price to California markets. He therefore recommended that the
FERC initiate penalty procedures against EPNG. EPNG and others filed briefs on
exceptions to the initial decision on October 23, 2002; briefs opposing
exceptions were filed on November 12, 2002. This proceeding will be resolved
upon finalization and approval of the Western Energy Settlement.
Systemwide Capacity Allocation Proceeding. In July 2001, several of EPNG's
contract demand or CD customers filed a complaint against EPNG at the FERC
claiming, among other things, that EPNG's full requirements contracts or FR
contracts (contracts with no volumetric limitations) should be converted to CD
contracts, and that EPNG should be required to expand its system and give demand
charge credits to CD customers when it is unable to meet its full contract
demands. In July 2001, several of EPNG's FR customers filed a complaint alleging
that EPNG had violated the Natural Gas Act and its contractual obligations to
them by not expanding its system, at its cost, to meet their increased
requirements.
On May 31, 2002, the FERC issued an order on the complaints in which it
required that (i) FR service, for all FR customers except small volume
customers, be converted to CD service; (ii) firm customers be assigned specific
receipt point rights in lieu of their existing systemwide receipt point rights;
(iii) reservation charge credits be given to all firm customers for failure to
schedule confirmed volumes except in cases of force
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majeure; (iv) no new firm contracts be executed until EPNG has demonstrated
there is adequate capacity on the system; and (v) a process be implemented to
allow existing CD customers to turn back capacity for acquisition by FR
customers in which process EPNG would remain revenue neutral. These changes were
to be made effective November 1, 2002. The order also stated that the FERC
expected EPNG to file for certificate authority to add compression to Line 2000
to increase its system capacity by 320 MMcf/d without cost coverage until its
next rate case (i.e. January 1, 2006). EPNG had previously informed the FERC
that it was willing to add compression to Line 2000 provided it was assured of
rate coverage in the next rate case. On July 1, 2002, EPNG and other parties
filed for clarification and/or rehearing of the May 31 order.
On September 20, 2002, at the urging of the FR shippers, the FERC issued an
order postponing until May 1, 2003 the effective date of the FR conversions.
That order also required EPNG to allocate among FR customers (i) the 320 MMcf/d
of capacity that will be available from the addition of compression to Line
2000, and (ii) any firm capacity that expires under existing contracts between
May 31, 2002, and May 1, 2003, thereby precluding it from reselling that
capacity. In total, the September 20 order required that EPNG's FR customers pay
only their current aggregate reservation charges for existing unsubscribed
capacity, for the 230 MMcf/d of capacity made available in November 2002 by
EPNG's Line 2000 project, for the 320 MMcf/d of capacity from the addition of
compression to Line 2000, and for all capacity subject to contracts expiring
before May 1, 2003. Beginning May 1, 2003, EPNG will be required to pay
reservation charge credits when it is unable to schedule confirmed volumes
except in cases of force majeure. Until May 1, 2003, it is required to pay
partial reservation charge credits to CD customers when it is unable to schedule
95 percent of their monthly confirmed volumes except for reasons of force
majeure and provided that there is no capacity available from other supply
basins on its system.
Several pleadings have been filed in response to the September 20 order,
including rehearing requests and requests by several customers to modify the
order based on the ALJ's decision in the CPUC Complaint Proceeding discussed
above. All such pleadings remain pending before the FERC. In the interim, EPNG
is proceeding with the directives contained in the September 20 order.
On October 7, 2002, EPNG filed tariff sheets in compliance with the
September 20 order to implement a partial demand charge credit for the period
November 1, 2002 to May 31, 2003, and to allow California delivery points to be
used as secondary receipt points to the extent of its backhaul displacement
capabilities. EPNG proposed both a reservation and a usage charge for this
service. On December 26, 2002, the FERC issued an order (i) denying EPNG's
request to charge existing CD customers a reservation rate for California
receipt service for the remaining term of the settlement, i.e., through December
31, 2005; (ii) allowing EPNG to charge its maximum IT rate for the service;
(iii) approving EPNG's proposed usage rate for the service until its next rate
case; and (iv) requiring it to make a showing that capacity is available for any
new shippers utilizing this service. EPNG made a revised tariff filing on
January 10, 2003, in compliance with the December 26 order. On January 27, 2003,
EPNG filed a request for rehearing on certain aspects of the December 26 order.
That request is pending.
Rate Settlement. EPNG's current rate settlement establishes its base rates
through December 31, 2005. Under the settlement, EPNG's base rates began
escalating annually in 1998 for inflation. EPNG has the right to increase or
decrease its base rates if changes in laws or regulations result in increased or
decreased costs in excess of $10 million a year. In addition, all of EPNG's
settling customers participate in risk sharing provisions. Under these
provisions, EPNG received cash payments in total of $295 million for a portion
of the risk EPNG assumed from capacity relinquishments by its customers
(primarily capacity turned back to it by Southern California Gas Company and
Pacific Gas and Electric Company which represented approximately one-third of
the capacity of EPNG's system) during 1996 and 1997. The cash EPNG received was
deferred, and EPNG recognizes this amount in revenues ratably over the risk
sharing period. As of December 31, 2002, EPNG had unearned risk sharing revenues
of approximately $32 million and had $13 million remaining to be collected from
customers under this provision. Amounts received for relinquished capacity sold
to customers, above certain dollar levels specified in EPNG's rate settlement,
obligate it to refund a portion of the excess to customers. Under this
provision, EPNG refunded $46 million of 2001 revenues to customers during 2001
and 2002. During 2002, EPNG established an additional refund obligation of $46
million, of which $32 million was
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refunded in 2002. The remainder will be refunded in 2003. Both the risk and
revenue sharing provisions of the rate settlement extend through 2003.
Line 2000 Project. On July 31, 2000, EPNG applied with the FERC for a
certificate of public convenience and necessity for its Line 2000 project, which
was designed to replace old compression on the system with a converted oil
pipeline, resulting in no increase in system capacity. In response to demand
conditions on its system, however, EPNG filed in March 2001 to amend its
application to convert the project to an expansion project of 230 MMcf/d. On May
7, 2001, the FERC authorized the amended Line 2000 project. EPNG placed the line
in service in November 2002 at an approximate capital cost of $185 million. The
cost of the Line 2000 conversion will not be included in EPNG's rates until its
next rate case, which will be effective on January 1, 2006.
On October 3, 2002, pursuant to the FERC's May 31 and September 20 orders
in the systemwide capacity allocation proceeding, EPNG filed with the FERC for a
certificate of public convenience and necessity to add compression to its Line
2000 project to increase the capacity of that line by an additional 320 MMcf/d
at an estimated capital cost of approximately $173 million for all phases. That
application has been protested, and remains pending. In EPNG's request for
clarification of the September 20 order, EPNG asked for assurances from the FERC
that it will be able to begin cost recovery for this project at the time its
next rate case becomes effective. That request remains pending.
Marketing Affiliate NOPR. In September 2001, the FERC issued a Notice of
Proposed Rulemaking (NOPR). The NOPR proposes to apply the standards of conduct
governing the relationship between interstate pipelines and marketing affiliates
to all energy affiliates. The proposed regulations, if adopted by the FERC,
would dictate how all our energy affiliates conduct business and interact with
our interstate pipelines. In December 2001, we filed comments with the FERC
addressing our concerns with the proposed rules. A public hearing was held on
May 21, 2002, providing an opportunity to comment further on the NOPR. Following
the conference, additional comments were filed by our pipeline subsidiaries and
others. At this time, we cannot predict the outcome of the NOPR, but adoption of
the regulations in their proposed form would, at a minimum, place additional
administrative and operational burdens on us.
Negotiated Rate NOI. In July 2002, the FERC issued a Notice of Inquiry
(NOI) that seeks comments regarding its 1996 policy of permitting pipelines to
enter into negotiated rate transactions. Several of our pipelines have entered
into these transactions over the years, and the FERC is now reviewing whether
negotiated rates should be capped, whether or not the "recourse rate" (a
cost-of-service based rate) continues to safeguard against a pipeline exercising
market power, and other issues related to negotiated rate programs. On September
25, 2002, our pipelines and others filed comments. Reply comments were filed on
October 25, 2002. At this time, we cannot predict the outcome of this NOI.
Cash Management NOPR. On August 1, 2002, the FERC issued a NOPR requiring
that all cash management or money pool arrangements between a FERC regulated
subsidiary and a non-FERC regulated parent must be in writing, and set forth the
duties and responsibilities of cash management participants and administrators;
the methods of calculating interest and for allocating interest income and
expenses; and the restrictions on deposits or borrowings by money pool members.
The NOPR also requires specified documentation for all deposits into, borrowings
from, interest income from, and interest expenses related to, these
arrangements. Finally, the NOPR proposed that as a condition of participating in
a cash management or money pool arrangement, the FERC regulated entity maintain
a minimum proprietary capital balance of 30 percent, and the FERC regulated
entity and its parent maintain investment grade credit ratings. On August 28,
2002, comments were filed. The FERC held a public conference on September 25,
2002, to discuss the issues raised in the comments. Representatives of companies
from the gas and electric industries participated on a panel and uniformly
agreed that the proposed regulations should be revised substantially and that
the proposed capital balance and investment grade credit rating requirements
would be excessive. At this time, we cannot predict the outcome of this NOPR.
Also on August 1, 2002, the FERC's Chief Accountant issued an Accounting
Release which was effective immediately. The Accounting Release provides
guidance on how companies should account for money pool arrangements and the
types of documentation that should be maintained for these arrangements.
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However, it did not address the proposed requirements that the FERC regulated
entity maintain a minimum proprietary capital balance of 30 percent and that the
entity and its parent have investment grade credit ratings. Requests for
rehearing were filed on August 30, 2002. The FERC has not yet acted on the
rehearing requests.
Emergency Reconstruction of Interstate Natural Gas Facilities NOPR. On
January 17, 2003, FERC issued a NOPR proposing to (1) expand the scope of
construction activities authorized under a pipeline's blanket certificate to
allow replacement of mainline facilities; (2) authorize a pipeline to commence
reconstruction of the affected system without a waiting period; and (3)
authorize automatic approval of construction that would be above the normal cost
ceiling. Comments on the NOPR were filed on February 27, 2003. At this time, we
cannot predict the outcome of this rulemaking.
Pipeline Safety Notice of Proposed Rulemaking. On January 28, 2003, the
U.S. Department of Transportation issued a NOPR proposing to establish a rule
requiring pipeline operators to develop integrity management programs to
comprehensively evaluate their pipelines, and take measures to protect pipeline
segments located in what the notice refers to as "high consequence areas." The
proposed rule resulted from the enactment of the Pipeline Safety Improvement Act
of 2002, a new bill signed into law in December 2002. Our pipelines intend to
submit comments on the NOPR, which are due on or before April 30, 2003. At this
time, we cannot predict the outcome of this rulemaking.
FERC Inquiry. On February 26, 2003, we received a letter from the Office
of the Chief Accountant at the FERC requesting details of our announcement of
2003 asset sales and plans for our subsidiaries, SNG and ANR, to issue a
combined $700 million of long-term notes. The letter requested that we explain
how we intended to use the proceeds from SNG's and ANR's issuance of the notes
and if the notes will be included in the two regulated companies' capital
structure for rate-setting purposes. Our response to the FERC was filed on March
12, 2003, and we fully responded to the request.
Western Trading Strategies. EPME, our subsidiary, responded on May 22,
2002, to the FERC's May 8, 2002 request in Docket No. PA-02-2, seeking
statements of admission or denial with respect to trading strategies designed to
manipulate western power markets. EPME provided an affidavit stating that it had
not engaged in these trading strategies.
Wash Trade Inquiries. On May 21 and 22, 2002, the FERC issued data
requests in Docket PA-02-2, including requests for statements of admission or
denial with respect to so-called "wash" or "round trip" trades in western power
and gas markets. In May and June 2002, EPME responded, denying that it had
conducted any wash or round trip trades (i.e., simultaneous, prearranged trades
entered into for the purpose of artificially inflating trading volumes or
revenues, or manipulating prices).
On June 7, 2002, we received an informal inquiry from the SEC regarding the
issue of round trip trades. Although we do not believe any round trip trades
occurred, we submitted data to the SEC on July 15, 2002. On July 12, 2002, we
received a federal grand jury subpoena for documents concerning so-called round
trip or wash trades. We have complied with these requests.
Price Reporting to Indices. On October 22, 2002, the FERC issued a data
request in Docket PA-02-2 to all of the largest North American gas marketers,
including EPME, regarding price reporting of transactional data to the energy
trade press. We engaged an outside firm to investigate the matters raised in the
data request. EPME has provided information regarding its price reporting to
indices to the FERC, the Commodities Futures Trading Commission (CFTC), and to
the U.S. Attorney in response to their requests. The information provided
indicates inaccurate prices were reported to the trade publications. EPME has no
evidence that the reporting to the publications resulted in any unrepresentative
price index. On March 26,2003, we announced a settlement between EPME and CFTC
of the price reporting matter providing for the payment by EPME of a civil
monetary penalty of $20 million, $10 million of which is payable within three
years, without admitting or denying the findings made in the CFTC order
implementing the agreement.
Refunds Pricing. On August 13, 2002, the FERC issued a Notice Requesting
Comment on Method for Determining Natural Gas Prices for Purposes of Calculating
Refunds in ongoing California refund
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proceedings dealing with sales of electric power in which some of our companies
are involved. Referencing a Staff Report also issued on August 13, 2002, the
FERC requested comments on whether it should change the method for determining
the delivered cost of natural gas in calculating the mitigated market-clearing
price in the refund proceeding and, if so, what method should be used. Comments
were filed on October 15, 2002. On December 12, 2002, the ALJ issued an Initial
Decision, setting forth preliminary calculations of amounts owed. In the
aggregate, the ALJ found that $3 billion is owed to natural gas suppliers,
offset by an aggregate refund of $1.2 billion associated with prices charged in
excess of the mitigated market clearing prices. Upon the finalization and
approval of the Western Energy Settlement, claims by many of the claimants in
this proceeding for credits against amounts due EPME will be resolved; however,
the specific amount of the adjustment is indeterminable at this time. The full
FERC is expected to review the decision later in 2003. We cannot predict the
final outcome of this matter.
Australia. In June 2001, the Western Australia regulators issued a draft
rate decision at lower than expected levels for the Dampier-to-Bunbury pipeline
owned by EPIC Energy Australia Trust, in which we have a 33 percent ownership
interest and a total investment of approximately $200 million. EPIC Energy
Australia appealed a variety of issues related to the draft decision to the
Western Australia Supreme Court. The court directed the regulator to review its
position and comply with applicable regulatory law. During the fourth quarter of
2002, events in the business of Epic Energy Australia, including unanticipated
cash requirements, made it apparent that a cash equity infusion would be
required to refinance the debt of Epic Energy(WA) Nominee Pty. that matures and
is payable in full in 2003. With our fourth quarter credit downgrades by the
rating agencies and the demands on our liquidity, we concluded that we would not
contribute any further equity into our Epic Energy Western Australian
investment. As a result, we recognized an impairment of $153 million related to
our investment in Epic Energy's Dampier-to-Bunbury Pipeline.
Southwestern Bell Proceeding. We are engaged in proceedings with
Southwestern Bell involving disputes regarding our telecommunications
interconnection agreement in our metropolitan transport business. In July 2002,
we received a favorable ruling from the administrative law judge in Phase 1 of
the proceedings. We anticipate a determination from the PUC of Texas on the
administrative law judge's recommendation no later than the second quarter of
2003. Despite the favorable ruling from the administrative law judge, the PUC
retains the right to affirm or reject the award and any significant rejection of
the award could negatively impact our metro transport business. An adverse
resolution to the proceeding by the PUC could have a negative impact on our
ongoing operations and prospects in this business.
FCC Triennial Review. In this proceeding, the FCC, pursuant to its
Congressional mandate, is reexamining the entire list of Unbundled Network
Elements (UNEs), including high capacity loops and transport and dark fiber, to
determine if any should be removed or qualified. It is possible that the FCC may
either eliminate or set more stringent offering guidelines for some of the
existing UNE's. Although EPGN has no reason to assume that dark fiber or high
capacity loops or transport may be eliminated, any ruling that seriously
impaired its ability to access these UNEs would significantly affect its current
business model. EPGN has filed comments and an order is expected by April 2003.
FCC Broadband Docket. The FCC has issued a Notice of Proposed Rule Making
(NPRM) for Broadband Service and asked for general comments on a vast array of
issues. The NPRM indicates that the FCC is inclined to declare high-speed, DSL
internet access service as an information service. This would allow Incumbent
Local Exchange Carriers (ILECs) to stop leasing their DSL internet service to
third party competitors for resale to customers. ILECs have also submitted
proposals that would effectively deregulate all optical level and high-speed
copper based services. If the FCC adopted the NPRM proposal, the results would
critically affect EPGN's business. EPGN filed initial comments, in conjunction
with other CLEC's. EPGN also filed joint reply comments on July 3, 2002,
stressing both the illegality of the proposed finding and the national security
implications. Certain ILECs are advocating the position that all high capacity
copper and fiber lines should be found to be "information services", thereby
exempting them from having to lease their lines to EPGN. We have opposed such a
holding which we believe would be unlawful. A decision is expected sometime
during the first half of 2003.
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While the outcome of our outstanding legal matters, environmental matters,
and rates and regulatory matters cannot be predicted with certainty, based on
current information and our existing accruals, we do not expect the ultimate
resolution of these matters to have a material adverse effect on our financial
position, operating results or cash flows. However, it is possible that new
information or future developments could require us to reassess our potential
exposure related to these matters. It is also possible that these matters could
impact our debt rating and credit rating. See Item 7, Management's Discussion
and Analysis of Financial Condition and Results of Operations under the
subheading Recent Developments. Further, for environmental matters, it is also
possible that other developments, such as increasingly strict environmental laws
and regulations and claims for damages to property, employees, other persons and
the environment resulting from our current or past operations, could result in
substantial costs and liabilities in the future. As new information regarding
our outstanding legal matters, environmental matters and rates and regulatory
matters becomes available, or relevant developments occur, we will review our
accruals and make any appropriate adjustments. The impact of these changes may
have a material effect on our results of operations, our financial position, and
on our cash flows in the period the event occurs.
Other Matters
LNG Time Charters. During 2001 and 2002, we contracted to charter four LNG
tankers, with an option to charter a fifth ship, to transport LNG from supply
areas to domestic and international market centers. In February 2003, following
our announced plan to minimize our involvement in the LNG business, we entered
into various agreements with the ship owners under which all four of the ship
charters and our option for chartering the fifth ship were cancelled in
consideration of payments by us totaling $24 million. On two of the ship
charters, the ship owners assumed responsibility for the charter of those
vessels, and we paid $20 million for the capital costs associated with fitting
those two ships with regasification capabilities. In connection with
transferring the chartering responsibilities back to the ship owners, we agreed
to provide letters of credit, fully collateralized by cash, equal to $120
million that could be drawn on by ship owners to cover additional capital costs
and any shortfalls in the rates at which they are able to charter the vessels
compared to the rates provided for in the original charter agreements adjusted
for capital costs we have already paid. In the event that the ship owners are
able to charter the ships at rates in excess of the original rates, as adjusted,
we will share in the benefits. We also retained rights to charter some of the
vessels for use in our future LNG activities. In connection with these
transactions, our future exposure to the ship arrangements is limited to $120
million.
Enron Bankruptcy. In December 2001, Enron Corp. and a number of its
subsidiaries, including Enron North America Corp. and Enron Power Marketing,
Inc., (EPMI) filed for Chapter 11 bankruptcy protection in the United States
Bankruptcy Court for the Southern District of New York. We had contracts with
Enron North America, Enron Power Marketing and other Enron subsidiaries for,
among other things, the transportation of natural gas and NGL and the trading of
physical natural gas, power, petroleum and financial derivatives.
Our Merchant Energy positions are governed under a master International
Swap Dealers Association, Inc. agreement, various master natural gas agreements,
a master power purchase and sale agreement, and other commodity agreements. We
terminated most of these trading-related contracts, which we believe was proper
and in accordance with the terms of these contracts. In October 2002, we filed
proofs of claim for our domestic trading positions against Enron trading
entities in an amount totaling approximately $318 million. Also in October 2002,
our European trading business asserted $20 million in claims against Enron
Capital and Trade Resources Limited which is subject to proceedings in the
United Kingdom. After considering the cash margins Enron has deposited with us
as well as the reserves we have established, our overall Merchant Energy
exposure to Enron is $29 million, which is classified as current accounts and
notes receivable. We believe this amount is reasonable based on offers received
to purchase the claims.
In February 2003, Merchant Energy received a letter from EPMI demanding
payment under a March 2001 Power Purchase and Sale Agreement (Agreement) of
approximately $46 million. Merchant Energy responded to the February 2003 demand
letter denying that any sums were due EPMI under the Agreement. In addition,
EPMI has now made demand on us for this sum based on an August 2, 2001 guaranty
agreement. EPMI has now filed a lawsuit against Merchant Energy and El Paso in
the United States
153
Bankruptcy Court for the Southern District of New York seeking to collect these
sums. We have denied liability.
In addition, various Enron subsidiaries had transportation contracts on
several of our pipeline systems. Most of these transportation contracts have now
been rejected, and our pipeline subsidiaries have filed proofs of claim totaling
approximately $137 million. EPNG filed the largest proof of claim in the amount
of approximately $128 million, which included $18 million for amounts due for
services provided through the date the contracts were rejected and $110 million
for damage claims arising from the rejection of its transportation contracts.
The September 20 order in the EPNG capacity allocation proceeding discussed in
Rates and Regulatory Matters above prohibits EPNG from remarketing Enron
capacity that was not remarketed prior to May 31, 2002. EPNG has sought
rehearing of the September 20 order. We have fully reserved for the amounts due
through the date the contracts were rejected, and we have not recognized any
amounts under these contracts since the rejection date.
As a result of current circumstances surrounding the energy sector, the
creditworthiness of several industry participants has been called into question.
We have taken actions to mitigate our exposure to these participants; however,
should several industry participants file for Chapter 11 bankruptcy protection
and contracts with our various subsidiaries are not assumed by other
counterparties, it could have a material adverse effect on our financial
position, operating results or cash flows.
Broadwing Arbitration. In June 2000, El Paso Global Networks (EPGN),
formerly known as El Paso Communications Company, entered into an agreement with
Broadwing Communications Services (Broadwing) to construct and maintain a fiber
optic telecommunications system from Houston, Texas to Los Angeles, California.
In May 2002, EPGN terminated its agreements with Broadwing due to Broadwing's
failure to meet its contractual obligations. Broadwing disputed EPGN's right to
terminate the agreements. Subsequently, EPGN filed a demand for arbitration and
named its arbitrator. We have also sought and obtained injunctive relief to
require Broadwing to perform maintenance activity and prohibit it from removing
materials or equipment purchased for the project. If it is determined that we
properly terminated the contract, Broadwing is required to return all money paid
by us which is $62 million and transfer all of the work completed to date free
and clear of any liens. The arbitration is scheduled for the fourth quarter of
2003. In the fourth quarter of 2002, we wrote down the value of this long-haul
route by $4 million, leaving a total investment of $104 million.
Economic Conditions of Brazil. We have investments in power, pipeline and
production projects in Brazil, including an investment in Gemstone, with an
aggregate exposure, including financial guarantees, of approximately $1.8
billion. During 2002, Brazil experienced a significant decline in its financial
markets due largely to concerns over the refinancing of Brazil's foreign debt
and the presidential elections which were completed in late October 2002. These
concerns have contributed to higher interest rates on local debt for the
government and private sectors, have significantly decreased the availability of
funds from lenders outside of Brazil and have decreased the amount of foreign
investment in the country. These factors have contributed to a downgrade of
Brazil's foreign currency debt rating and a 52 percent devaluation of the local
currency against the U.S. dollar during 2002. These developments are likely to
delay the implementation of project financings underway in Brazil. The
International Monetary Fund announced in the fourth quarter a $30 billion loan
package for Brazil; however, the release of the majority of the money will
depend on Brazil committing to specified fiscal targets in 2003. In addition,
Brazil's newly elected President may impose changes affecting our business,
including imposing tariff controls on electricity and fuels. We currently
believe that the economic difficulties in Brazil will not have a material
adverse effect on our investment in the country, but we continue to monitor the
economic situation and any potential changes in governmental policy. Future
developments in Brazil could cause us to reassess our exposure.
Gemstone, our affiliate, owns a 60 percent interest in a 484 MW gas-fired
power project, known as the Araucaria project, located near Curitiba, Brazil.
Our investment in the Araucaria project was $176 million at December 31, 2002.
The project company in which we have an ownership interest has a 20 year power
purchase agreement (PPA) with Copel, a regional utility. Copel is approximately
60 percent owned by the State of Parana. After the recent elections in Brazil,
the new Governor of the State of Parana publicly
154
characterized the Araucaria project as unfavorable to Copel and the State of
Parana and promised a full review of the transaction. Subsequent to this
announcement, Copel informed us that they will not pay capacity payments due
under the PPA pending that review. Previous payments made under the PPA were
made with a reservation of rights with respect to the enforceability of the
contract. We are meeting with the government as well as new management at Copel
to discuss Copel's obligations under the power purchase agreement. If we are
unable to come to a satisfactory resolution of the current issues under the PPA,
we may be required to initiate enforcement of our remedies under the contract,
including filing an arbitration proceeding under the International Chamber of
Commerce rules in Paris. If we do not prevail in that proceeding, or are not
otherwise able to enforce our remedies under the contract, we could be required
to impair our investment in the project. Our losses would be limited to our
investment.
Meizhou Wan Power Project. We own a 25 percent equity interest in a 734
MW, coal-fired power generating project, Meizhou Wan Generating, located in
Fuzhou, People's Republic of China. Our investment in the project was $56
million at December 31, 2002, and we have also issued $34 million in guarantees
and letters of credit for equity support and debt service reserves for the
project. The project debt is collateralized only by the project's assets and is
non-recourse to us. The project declared that it was ready for commercial
operations in August 2001; however, the provincial government, who also buys all
power generated from the project, has not accepted the project for commercial
operations. In October 2002, we reached an interim agreement to allow the plant
to operate and sell power at reduced rates until March 2003 while a long-term
resolution to existing and past contract terms is negotiated. The price the
project receives from the sale of power in the interim agreement is expected to
be sufficient to provide for the operating costs and debt service of the
project, but does not provide for a return on investment to the project's
owners. If the project is unable to reach a long-term agreement with the
provincial government, with higher rates than in the interim agreement, we could
be required to impair our investment in the project, since cash flows from the
project would not be sufficient to provide us with a return of our investment,
and we may incur additional losses if our guarantees and letters of credit are
called upon. Our losses are limited to the extent of our investment, guarantees
and letters of credit. At December 31, 2002, we impaired $7 million of our
goodwill related to our investment in this project.
Milford Power Project. We own a 25 percent direct equity interest in a 540
MW power plant construction project located in Milford, Connecticut. Chaparral,
our affiliate, owns an additional 70 percent interest in this project. The
project has been financed through equity contributions, construction financing
from lenders that is recourse only to the project and through a construction
management services agreement that we funded. This project has experienced
significant construction delays, primarily associated with technological
difficulties with its turbines including the inability to operate on both gas
and fuel oil or to operate at its designed capacity as specified in the
construction contract. In October 2001, we entered into a construction
management services agreement providing additional funding through October 1,
2002. The construction contractor failed to complete construction of the plant
prior to October 1, 2002, in accordance with the terms and specifications of the
construction contract. As a result, the project was in default under its
construction lending agreement. On October 25, 2002, we entered into a
standstill agreement with the construction lending banks that expired on
December 2, 2002. We will continue negotiating with the contractor and with the
lending banks to attempt to reach agreements on contract disputes, including
resolution of liquidated damages that are due to the project under the terms of
the construction contract and for successful completion of plant construction.
On March 4, 2003, we provided a notice to Milford declaring an event of default
under the fuel supply agreement between us and Milford due to non-payment by
Milford. On March 6, 2003, Milford received a notice from its lenders stating
that the lenders intended to commence foreclosure on the project in accordance
with the lending agreement within 30 days. As a result of the default under the
construction lending agreement, we evaluated our investment and recorded an
impairment charge of $17 million while Chaparral recorded an impairment charge
of $44 million in the fourth quarter of 2002. At December 31, 2002, our direct
investment in the project was $67 million of loans to Milford under a
construction management services agreement. We have also provided a guarantee of
$8 million to fund a debt service account for Milford. We may be required to
fund the account should the facility not be financially able to do so within two
years from its commercial operations date. If we are unable to reach a
negotiated settlement of the disputes with the lending banks, the banks may have
the right to accelerate the construction
155
loan and foreclose on the project which may result in an impairment of our
construction loans, including the guaranteed amount in the project. If this
occurred, we could record an impairment charge of up to $75 million.
Berkshire Power Project. We own a 25 percent direct equity interest in a
261 MW power plant located in Massachusetts. Chaparral, our affiliate, owns an
additional 31.4 percent interest in this project. The construction contractor
failed to deliver a plant capable of operating on both gas and fuel oil, or
capable of operating at its designed capacity. Berkshire is negotiating with the
contractor with respect to its failure to deliver the project in accordance with
guaranteed specifications, including fuel oil firing capability. During the
third quarter of 2002, the project lenders asserted that Berkshire was in
default on its loan agreement. Berkshire is in the process of negotiating with
its lenders to resolve disputed contract terms. Failure to reach a satisfactory
resolution in these matters could have a material adverse effect on the value of
our investment in the project. At December 31, 2002, our direct investment in
Berkshire was $20 million, including receivables of $16 million under a
subordinated fuel agreement, and Chaparral's investment was $1 million. We
continue to discuss settlement opportunities with our construction contractor.
PPN Power Project. Our subsidiary owns a 26 percent minority equity
interest in a 325 MW dual fuel (naphtha and natural gas) fired generating plant
located in Tamil Nadu Province, India. The project achieved commercial
operations in April 2001 and obtained dual fuel capability in September 2002.
The project sells power to the Tamil Nadu Electricity Board (TNEB). The TNEB has
paid for power at a rate lower than the rate called for in the power purchase
agreement and at December 31, 2002 the project had overdue receivables of $36
million. The TNEB has requested an increase in the rates that it is permitted to
charge customers within its service territory in order to provide revenues
sufficient to make payments owed to us. Amounts currently being paid are
sufficient to cover debt service and normal operating expenses but are
insufficient to cover maintenance and a return on equity. If the project is
unable to reach a long-term agreement with the TNEB to collect rates higher than
those currently being paid, the project may incur losses as the plant continues
to operate. Recent events have also made the possibility of long term operations
on natural gas less likely which has the effect of increasing the operating cost
of the project because the use of naphtha makes electric generation more
expensive on a per kilowatt hour basis. At December 31, 2002, we impaired all of
our investment in this project, which totaled $41 million.
Cases
The California cases discussed above are five filed in the Superior Court of Los
Angeles County (Continental Forge Company, et al v. Southern California Gas
Company, et al, filed September 25, 2000*; Berg v. Southern California Gas
Company, et al, filed December 18, 2000*; County of Los Angeles v. Southern
California Gas Company, et al, filed January 8, 2002*; The City of Los Angeles,
et al v. Southern California Gas Company, et al and The City of Long Beach, et
al v. Southern California Gas Company, et al, both filed March 20, 2001*); two
filed in the Superior Court of San Diego County (John W.H.K. Phillip v. El Paso
Merchant Energy; and John Phillip v. El Paso Merchant Energy, both filed
December 13, 2000*); and two filed in the Superior Court of San Francisco
County(Sweetie's et al v. El Paso Corporation, et al, filed March 22, 2001*; and
California Dairies, Inc., et al v. El Paso Corporation, et al, filed May 21,
2001); and one filed in the Superior Court of the State of California, County of
Alameda (Dry Creek Corporation v. El Paso Natural Gas Company, et al, filed
December 10, 2001*); and five filed in the Superior Court of Los Angeles
County(The City of San Bernardino v. Southern California Gas Company, et al; The
City of Vernon v. Southern California Gas Company; The City of Upland v.
Southern California Gas Company, et al; Edgington Oil Company v. Southern
California Gas Company, et al; World Oil Corporation, et al. v. Southern
California Gas Company, et al, filed December 27, 2002*). The two long-term
power contract lawsuits are James M. Millar v. Allegheny Energy Supply Company,
et al. filed May 13, 2002 in the Superior Court, San Francisco County,
California and Tom McClintock et al. v. Vikram Budhrajaetal filed May 1, 2002 in
the Superior Court, Los Angeles County, California. The cases referenced in
Other Energy Market Lawsuits are: The State of Nevada, et al. v. El Paso
Corporation, El Paso Natural Gas Company, El Paso Merchant Energy Company, et
al. filed November 2002 in the District Court for Clark County, Nevada*; Sharon
Lynn
---------------
*Cases to be dismissed upon finalization and approval of the Western Energy
Settlement.
156
Lodewick v. Dynegy, Inc. et al. filed December 16, 2002 in the Circuit
Court for the County of Multnomah, State of Oregon; Nick A. Symonds v. Dynegy,
Inc. et al. filed December 20, 2002 in the United States District Court for the
Western District of Washington, Seattle; Henry W. Perlman, et al. v. San Diego
Gas & Electric et al. filed December 2002, in the United States District Court,
Southern District of New York. State of Arizona v El Paso Corporation, El Paso
Natural Gas Company, El Paso Merchant Energy Company, et al. filed March 10,
2003 in the Superior Court, Maricopa County, Arizona.
The purported shareholder class actions filed in the U.S. District Court
for the Southern District of Texas, Houston Division, are: Marvin Goldfarb, et
al v. El Paso Corporation, William Wise, H. Brent Austin, and Rodney D. Erskine,
filed July 18, 2002; Residuary Estate Mollie Nussbacher, Adele Brody Life
Tenant, et al v. El Paso Corporation, William Wise, and H. Brent Austin, filed
July 25, 2002; George S. Johnson, et al v. El Paso Corporation, William Wise,
and H. Brent Austin, filed July 29, 2002; Renneck Wilson, et al v. El Paso
Corporation, William Wise, H. Brent Austin, and Rodney D. Erskine, filed August
1, 2002; and Sandra Joan Malin Revocable Trust, et al v. El Paso Corporation,
William Wise, H. Brent Austin, and Rodney D. Erskine, filed August 1, 2002; Lee
S. Shalov, et al v. El Paso Corporation, William Wise, H. Brent Austin, and
Rodney D. Erskine, filed August 15, 2002; Paul C. Scott, et al v. El Paso
Corporation, William Wise, H. Brent Austin, and Rodney D. Erskine, filed August
22, 2002; Brenda Greenblatt, et al v. El Paso Corporation, William Wise, H.
Brent Austin, and Rodney D. Erskine, filed August 23, 2002; Stefanie Beck, et al
v. El Paso Corporation, William Wise, and H. Brent Austin, filed August 23,
2002; J. Wayne Knowles, et al v. El Paso Corporation, William Wise, H. Brent
Austin, and Rodney D. Erskine, filed September 13, 2002; The Ezra Charitable
Trust, et al v. El Paso Corporation, William Wise, Rodney D. Erskine and H.
Brent Austin, filed October 4, 2002. The purported shareholder action filed in
the Southern District of New York is IRA F.B.O. Michael Conner et al v. El Paso
Corporation, William Wise, H. Brent Austin, Jeffrey Beason, Ralph Eads, D.
Dwight Scott, Credit Suisse First Boston, J.P. Morgan Securities, filed October
25, 2002.
The shareholder derivative actions filed in Houston are Grunet Realty Corp.
v. William A. Wise, Byron Allumbaugh, John Bissell, Juan Carlos Braniff, James
Gibbons, Anthony Hall Jr., Ronald Kuehn Jr., J. Carleton MacNeil Jr., Thomas
McDade, Malcolm Wallop, Joe Wyatt and Dwight Scott, filed August 22, 2002. John
Gebhart v. Byron Allumbaugh, John Bissell, Juan Carlos Braniff, James Gibbons,
Anthony Hall Jr., Ronald Kuehn Jr., J. Carleton MacNeil Jr., Thomas McDade,
Malcolm Wallop, Joe Wyatt and William Wise, filed March 2002; Marilyn Clark v.
El Paso Natural Gas, El Paso Merchant Energy, Byron Allumbaugh, John Bissell,
Juan Carlos Braniff, James Gibbons, Anthony Hall Jr., Ronald Kuehn, Jr., J.
Carleton MacNeil, Jr., Thomas McDade, Malcolm Wallop, Joe Wyatt and William Wise
filed in November 2002. The shareholder derivative lawsuit filed in Delaware is
Stephen Brudno et al v. William A. Wise et al filed in October 2002.
The customer complaints filed at the FERC against EPME and other wholesale
power marketers are: Nevada Power Company and Sierra pacific Power Company vs.
El Paso Merchant Energy, L.P.; California Public Utilities Commission vs.
Sellers of Long-Term Contracts to the California Department of Water and
California Electricity Oversight Board vs. PacifiCorp vs. El Paso Merchant
Energy, L.P., and City of Burbank, California vs. Calpine Energy Services, L.P.,
Duke Energy Trading and Marketing, LLC, El Paso Merchant Energy.
The ERISA Class Action Suit is William H. Lewis III v. El Paso Corporation,
H. Brent Austin and unknown fiduciary defendants 1-100.
Commitments and Purchase Obligations
Operating Leases. We maintain operating leases in the ordinary course of
our business activities. These leases include those for office space and
operating facilities and office and operating equipment, and the terms of the
agreements vary from 2003 until 2053. As of December 31, 2002, our total
commitments under operating leases were approximately $844 million, including
$235 million related to our discontinued petroleum markets operations.
157
Under several of our leases, we have provided residual value guarantees to
the lessor. For the total outstanding residual value guarantees on our operating
leases at December 31, 2002, see Residual Value Guarantees below.
Minimum annual rental commitments at December 31, 2002, were as follows:
YEAR ENDING
DECEMBER 31, OPERATING LEASES
------------------------------------------------------------ ----------------
(IN MILLIONS)
2003..................................................... $174
2004..................................................... 147
2005..................................................... 113
2006..................................................... 89
2007..................................................... 56
Thereafter............................................... 265
----
Total(1).......................................... $844
====
---------------
(1) Includes operating lease commitments associated with our discontinued
operations as follows: $81 million in 2003, $58 million in 2004, $28 million
in 2005, $16 million in 2006, $6 million in 2007 and $46 million thereafter.
Aggregate minimum commitments have not been reduced by minimum sublease
rentals of approximately $13 million due in the future under noncancelable
subleases.
Rental expense on our operating leases for the years ended December 31,
2002, 2001 and 2000 was $146 million, $94 million, and $168 million (in our
discontinued operations, this expense was $50 million in 2002, $53 million in
2001, and $30 million in 2000).
Guarantees. We are involved in various joint ventures and other ownership
arrangements that sometimes require additional financial support that results in
the issuance of financial and performance guarantees. In a financial guarantee,
we are obligated to make payments if the guaranteed party fails to make payments
under, or violates the terms of, the financial arrangement. In a performance
guarantee, we provide assurance that the guaranteed party will execute on the
terms of the contract. If they do not, we are required to perform on their
behalf. For example, if the guaranteed party is required to deliver natural gas
to a third party and then fails to do so, we would be required to either deliver
that natural gas or make payments to the third party equal to the difference
between the contract price and the market value of the natural gas.
As of December 31, 2002, we had approximately $2.5 billion of both
financial and performance guarantees outstanding, including $63 million of
guarantees related to our petroleum markets discontinued operations. Of this
amount, approximately $1.0 billion relates to our Chaparral investment and $950
million relates to our Gemstone investment. The remaining $558 million relates
to other global power equity investments, including some of the projects under
Chaparral and Gemstone, pipeline activities, and petroleum activities (included
as discontinued operations).
Residual Value Guarantees. Under two of our operating leases, we have
provided residual value guarantees to the lessor. Under these guarantees, we can
either choose to purchase the asset at the end of the lease term for a specified
amount, which is typically equal to the outstanding loan amounts owed by the
lessor, or we can choose to assist in the sale of the leased asset to a third
party. Should the asset not be sold for a price that equals or exceeds the
amount of the guarantee, we would be obligated for the shortfall. The levels of
our residual value guarantees range from 86.2 percent to 89.9 percent of the
original cost of the leased assets. Accounting for these residual value
guarantees will be impacted effective July 1, 2003, by our adoption of the new
accounting rules on consolidations. For a discussion of the accounting impact of
these new rules, see Note 1.
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As of December 31, 2002, we had purchase options and residual value
guarantees associated with operating leases for the following assets:
PURCHASE RESIDUAL VALUE LEASE
ASSET DESCRIPTION OPTION GUARANTEE EXPIRATION
----------------- -------- -------------- ----------
(IN MILLIONS)
Lakeside Technology Center telecommunications
facility.......................................... $275 $237 2006
Facility at Aruba refinery(1)....................... 370 333 2006
---------------
(1) Associated with our discontinued operations (see Note 10).
Other Commercial Commitments. We have various other commercial commitments
and purchase obligations. At December 31, 2002, we had firm commitments under
transportation and storage capacity contracts of $1.4 billion, commodity
purchase commitments of $36 million that are not part of our trading activities
and other purchase and capital commitments (including maintenance, engineering,
procurement and construction contracts) of $825 million (including $29 million
related to our discontinued petroleum markets operations).
21. RETIREMENT BENEFITS
Pension Benefits
We maintain a defined benefit pension plan that covers substantially all of
our U.S. employees and provides benefits under a cash balance formula. Employees
who were participating in El Paso's defined benefit pension plan on December 31,
1996 receive the greater of cash balance benefits or prior plan benefits accrued
through December 31, 2001. Effective January 1, 2000, Sonat's pension plan was
merged into our pension plan. Sonat employees who were participants in the Sonat
pension plan on December 31, 1999 receive the greater of cash balance benefits
or the Sonat plan benefits accrued through December 31, 2004.
Prior to our merger with Coastal, Coastal provided non-contributory pension
plans covering substantially all of its U.S. employees. On April 1, 2001,
Coastal's primary plan was merged into our existing plan. Coastal employees who
were participants in Coastal's primary plan on March 31, 2001 receive the
greater of cash balance benefits or the Coastal plan benefits accrued through
March 31, 2006.
Following our mergers with Coastal and Sonat, we offered an early
retirement incentive program for eligible employees of these organizations.
These programs offered enhanced pension benefits to individuals who elected
early retirement. Charges incurred in connection with the Sonat program were $8
million and those in connection with the Coastal program were $152 million.
Separate plans were provided to employees of our coal and convenience store
operations. We also participate in one multi-employer pension plan for the
benefit of our employees who are union members. Our contributions to this plan
were not material for 2002 or 2001.
Retirement Savings Plan
We maintain a defined contribution plan covering all of our U.S. employees.
Prior to May 1, 2002, we matched 75 percent of participant basic contributions
up to 6 percent, with the matching contribution being made to the plan's stock
fund which participants could diversify at any time. After May 1, 2002, the plan
was amended to allow for company matching contributions to be invested in the
same manner as that of participant contributions. Effective March 1, 2003, we
suspended the matching contribution. Amounts expensed under this plan were
approximately $28 million, $30 million and $35 million for the years ended
December 31, 2002, 2001 and 2000.
Other Postretirement Benefits
We provide postretirement medical benefits for Coastal Coal and closed
groups of retired employees of EPNG, El Paso Tennessee, Sonat, and Coastal, and
limited postretirement life insurance benefits for current and retired
employees. As of January 31, 2003, the sale of the Coastal Coal operations were
completed. As a
159
result of the sale, Coastal Coal is now a closed group of retired employees. See
Note 9 for a further discussion of this matter. Other postretirement employee
benefits (OPEB) are prefunded to the extent such costs are recoverable through
rates. To the extent actual OPEB costs for TGP, EPNG or SNG differ from the
amounts recovered in rates, a regulatory asset or liability is recorded.
Medical benefits for these closed groups of retirees may be subject to
deductibles, co-payment provisions, and other limitations and dollar caps on the
amount of employer costs. We reserve the right to change these benefits.
The following table details our projected benefit obligation, accumulated
benefit obligation, fair value of plan assets as of September 30 and related
balance sheet accounts as of December 31:
PRIMARY OTHER
PENSION PLAN PENSION PLANS
--------------- -------------
2002 2001 2002 2001
------ ------ ----- -----
(IN MILLIONS)
Projected benefit obligation................................ $1,911 $1,831 $177 $135
Accumulated benefit obligation.............................. 1,857 1,773 167 124
Fair value of plan assets................................... 1,984 2,380 87 99
Accrued benefit liability................................... -- -- 75 61
Prepaid benefit cost........................................ 898 793 -- 28
Accumulated other comprehensive loss........................ -- -- 55 --
Intangible asset............................................ -- -- 1 --
We recorded a loss on our other pension plans as other comprehensive loss,
because the accumulated benefit obligation exceeded the fair value of plan
assets for each of those plans as of September 30, 2002. Included in other
pension plans as of September 30, 2001 are two pension plans whose accumulated
benefit obligation exceeded the fair value of plan assets. The projected benefit
obligation, accumulated benefit obligation, and accrued benefit liability
associated with these plans were $51 million, $47 million and $61 million at
September 30, 2001.
The following table sets forth the change in benefit obligation, change in
plan assets, reconciliation of funded status and components of net periodic
benefit cost for pension benefits and other postretirement benefits. Our
benefits are presented and computed as of and for the twelve months ended
September 30.
POSTRETIREMENT
PENSION BENEFITS BENEFITS
----------------- ---------------
2002 2001 2002 2001
------- ------- ------ ------
(IN MILLIONS)
Change in benefit obligation
Benefit obligation at beginning of period................. $1,966 $1,680 $ 560 $ 570
Service cost.............................................. 33 30 1 1
Interest cost............................................. 135 117 38 42
Participant contributions................................. -- -- 20 17
Plan amendments........................................... -- 4 -- (12)
Settlements, curtailments and special termination
benefits............................................... -- 137 -- 17
Actuarial (gain) or loss.................................. 129 135 17 (14)
Benefits paid............................................. (175) (137) (78) (61)
------ ------ ----- -----
Benefit obligation at end of period....................... $2,088 $1,966 $ 558 $ 560
====== ====== ===== =====
160
POSTRETIREMENT
PENSION BENEFITS BENEFITS
----------------- ---------------
2002 2001 2002 2001
------- ------- ------ ------
(IN MILLIONS)
Change in plan assets
Fair value of plan assets at beginning of period.......... $2,479 $3,190 $ 168 $ 188
Actual return on plan assets.............................. (246) (581) (14) (30)
Employer contributions.................................... 14 7 68 54
Participant contributions................................. -- -- 20 17
Benefits paid............................................. (175) (137) (78) (61)
------ ------ ----- -----
Fair value of plan assets at end of period................ $2,072 $2,479 $ 164 $ 168
====== ====== ===== =====
Reconciliation of funded status
Funded status at end of period............................ $ (16) $ 513 $(394) $(392)
Fourth quarter contributions and income................... 4 37 17 11
Unrecognized net actuarial loss (gain)(1)................. 921 252 25 (15)
Unrecognized net transition obligation.................... (1) (9) 23 31
Unrecognized prior service cost........................... (30) (32) (8) (9)
------ ------ ----- -----
Prepaid (accrued) benefit cost at December 31,............ $ 878 $ 761 $(337) $(374)
====== ====== ===== =====
---------------
(1) Our unrecognized net actuarial loss as of September 30, 2002, and for the
year ended December 31, 2002, was primarily the result of a decrease in the
discount rate used in the actuarial calculation and lower actual returns on
plan assets compared to our expected return during 2002. We recognize the
difference between the actual return and our expected return over a three
year period as permitted by SFAS No. 87.
The current liability portion of the postretirement benefits was $35
million as of December 31, 2002 and $46 million as of December 31, 2001. Benefit
obligations are based upon actuarial estimates as described below. Where these
assumptions differed, average rates have been presented.
PENSION BENEFITS POSTRETIREMENT BENEFITS
--------------------- ------------------------
YEAR ENDED DECEMBER 31,
------------------------------------------------
2002 2001 2000 2002 2001 2000
----- ----- ----- ------ ------ ------
(IN MILLIONS)
Benefit cost for the plans includes the
following components
Service cost........................... $ 33 $ 35 $ 38 $ 2 $ 1 $ 3
Interest cost.......................... 135 134 121 38 42 43
Expected return on plan assets......... (260) (311) (277) (9) (10) (8)
Amortization of net actuarial gain..... -- (41) (30) (1) (2) (2)
Amortization of transition
obligation.......................... (6) (6) (6) 8 8 13
Amortization of prior service cost..... (3) (2) (3) (1) (1) --
Settlements, curtailment, and special
termination benefits................ -- 137 -- -- 65 --
----- ----- ----- --- ---- ---
Net benefit cost (income).............. $(101) $ (54) $(157) $37 $103 $49
===== ===== ===== === ==== ===
The following table details the weighted average assumptions we used for
our pension and other postretirement plans for 2002 and 2001:
POSTRETIREMENT
PENSION BENEFITS BENEFITS
----------------- ---------------
2002 2001 2002 2001
------ ------ ----- -----
Discount rate.................................... 6.75% 7.25% 6.75% 7.25%
Expected return on plan assets................... 8.80% 10.00% 7.50% 7.50%
Rate of compensation increase.................... 4.00% 4.50% N/A N/A
161
Actuarial estimates for our postretirement benefits plans assumed a
weighted average annual rate of increase in the per capita costs of covered
health care benefits of 11.0 percent in 2002, gradually decreasing to 5.5
percent by the year 2008.
Assumed health care cost trends have a significant effect on the amounts
reported for other postretirement benefit plans. A one-percentage point change
in assumed health care cost trends would have the following effects:
2002 2001
----- -----
(IN MILLIONS)
One Percentage Point Increase
Aggregate of Service Cost and Interest Cost............... $ 1 $ 1
Accumulated Postretirement Benefit Obligation............. $ 20 $ 22
One Percentage Point Decrease
Aggregate of Service Cost and Interest Cost............... $ (1) $ (1)
Accumulated Postretirement Benefit Obligation............. $(19) $(21)
22. CAPITAL STOCK
Common Stock
In May 2002, we increased our authorized capitalization to 1.5 billion
shares of common equity. In June 2002, we issued approximately 51.8 million
additional shares of common stock for approximately $1 billion, net of issuance
costs of approximately $31 million.
In December 2001, we issued 20.3 million shares of common stock for
approximately $863 million (net of issuance costs).
Equity Security Units
In June 2002, we issued 11.5 million, 9% equity security units. Equity
security units consist of two securities: i) a purchase contract on which we pay
quarterly contract adjustment payments at an annual rate of 2.86% and that
requires its holder to buy El Paso common stock to be settled on August 16,
2005, and ii) a senior note due August 16, 2007, with a principal amount of $50
per unit, and on which we pay quarterly interest payments at an annual rate of
6.14% beginning August 16, 2002. The senior notes we issued had a total
principal value of $575 million and are pledged to secure the holders'
obligation to purchase shares of our common stock under the purchase contracts.
When the purchase contracts are settled in 2005, we will issue El Paso
common stock. At that time, the proceeds will be allocated between common stock
and additional paid-in capital. The number of common shares issued will depend
on the prior consecutive 20-trading day average closing price of our common
stock determined on the third trading day immediately prior to the stock
purchase date. We will issue a minimum of approximately 24 million shares and up
to a maximum of 28.8 million shares on the settlement date, depending on our
average stock price. We recorded approximately $43 million of other non-current
liabilities to reflect the present value of the quarterly contract adjustment
payments that we are required to make on these units at an annual rate of 2.86%
of the stated amount of $50 per purchase contract with an offsetting reduction
in additional paid-in capital. The quarterly contract adjustment payments are
allocated between the liability recognized at the date of issuance and
additional paid-in capital based on a constant rate over the term of the
purchase contracts. Fees and expenses incurred in connection with the equity
security units offering were allocated between the senior notes and the purchase
contracts based on their respective fair values on the issuance date. The amount
allocated to the senior notes is recognized as interest expense over the term of
the senior notes. The amount allocated to the purchase contracts is recorded as
additional paid-in capital.
FELINE PRIDES(SM)
In August 2002, we issued 12,184,444 shares of common stock to satisfy
purchase contract obligations under our FELINE PRIDES(SM) program. In return for
the issuance of stock, we received approximately
162
$25 million in cash from the maturity of a zero coupon bond and the return of
$435 million of our existing 6.625% senior debentures due August 2004, that were
issued in 1999. The zero coupon bond and the senior debentures had been held as
collateral for the purchase contract obligations. The $25 million received from
the maturity of the zero coupon bond was used to retire additional senior
debentures. Total debt reduction from the issuance of the common stock was
approximately $460 million.
Preferred Stock
As part of our balance sheet enhancement plan announced in December 2001,
we completed amendments to our Chaparral and Gemstone agreements in 2002 which
eliminated the Series B Mandatorily Convertible Single Reset Preferred Stock
issued in connection with the Chaparral third party notes, and eliminated all of
the Series C Mandatorily Convertible Single Reset Preferred Stock issued in
connection with the Gemstone third party notes.
Dividend
On February 5, 2003, we declared a quarterly dividend of $0.04 per share on
our common stock, payable on April 7, 2003, to stockholders of record on March
7, 2003. Also, during the year ended December 31, 2002, El Paso Tennessee
Pipeline Co., our subsidiary, paid dividends of $25 million on our Series A
cumulative preferred stock, which is 8 1/4% per annum (2.0625% per quarter).
23. STOCK-BASED COMPENSATION
We grant stock awards under various stock option plans. We account for our
stock option plans using Accounting Principles Board Opinion No. 25 and its
related interpretations. Under our employee plans, we may issue incentive stock
options on our common stock (intended to qualify under Section 422 of the
Internal Revenue Code), non-qualified stock options, restricted stock, stock
appreciation rights (SARs), phantom stock options, and performance units. Under
our non-employee director plans, we may issue non-qualified stock options and
deferred shares of common stock. We have reserved approximately 69 million
shares of common stock for existing and future stock awards. As of December 31,
2002, approximately 24 million shares remained unissued.
Non-qualified Stock Options
We granted non-qualified stock options to our employees in 2002, 2001, and
2000. Our stock options have contractual terms of 10 years and generally vest
after completion of one to five years of continuous employment from the grant
date. We also granted options to non-employee members of the Board of Directors
at fair market value on the grant date that are exercisable immediately except
in special circumstances. A summary of our stock options and stock options
outstanding as of December 31, 2002, 2001, and 2000 is presented below:
STOCK OPTIONS
------------------------------------------------------------------------
2002 2001 2000
---------------------- ---------------------- ----------------------
WEIGHTED WEIGHTED WEIGHTED
# SHARES OF AVERAGE # SHARES OF AVERAGE # SHARES OF AVERAGE
UNDERLYING EXERCISE UNDERLYING EXERCISE UNDERLYING EXERCISE
OPTIONS PRICES OPTIONS PRICES OPTIONS PRICES
----------- -------- ----------- -------- ----------- --------
Outstanding at beginning of the
year............................ 44,822,146 $50.02 19,664,151 $34.43 22,511,704 $32.80
Granted......................... 3,435,138 $35.41 28,327,468 $60.19 1,065,110 $41.35
Exercised....................... (310,611) $22.44 (1,396,409) $25.88 (3,648,752) $25.99
Forfeited....................... (4,738,299) $51.83 (1,773,064) $58.00 (263,911) $38.44
---------- ---------- ----------
Outstanding at end of year........ 43,208,374 $49.18 44,822,146 $50.02 19,664,151 $34.43
========== ========== ==========
Exercisable at end of year........ 25,493,152 $43.00 14,357,245 $33.58 12,431,102 $30.51
========== ========== ==========
163
OPTIONS OUTSTANDING OPTIONS EXERCISABLE
------------------------------------------------- -----------------------------
NUMBER WEIGHTED AVERAGE WEIGHTED NUMBER WEIGHTED
RANGE OF OUTSTANDING REMAINING AVERAGE EXERCISABLE AVERAGE
EXERCISE PRICES AT 12/31/02 CONTRACTUAL LIFE EXERCISE PRICE AT 12/31/02 EXERCISE PRICE
--------------- ----------- ---------------- -------------- ----------- --------------
$ 7.00 to $21.40 3,124,597 3.3 $16.01 2,582,018 $16.26
$21.41 to $42.90 14,327,024 5.5 $37.71 12,625,816 $37.44
$42.91 to $64.30 18,512,565 7.3 $55.28 8,872,672 $54.34
$64.31 to $71.50 7,244,188 7.6 $70.58 1,412,646 $70.44
---------- ----------
$ 7.00 to $71.50 43,208,374 6.4 $49.18 25,493,152 $43.00
========== ==========
The fair value of each stock option granted is estimated on the date of
grant using the Black-Scholes option-pricing model with the following
weighted-average assumptions:
ASSUMPTION: 2002 2001 2000
----------- ---- ---- ----
Expected Term in Years...................................... 6.95 7.25 7.00
Expected Volatility......................................... 43.4% 26.6% 23.9%
Expected Dividends.......................................... 1.8% 3.0% 3.0%
Risk-Free Interest Rate..................................... 3.2% 4.7% 5.0%
The Black-Scholes weighted average fair value of options granted during
2002, 2001 and 2000 was $14.23, $15.75 and $10.16.
Restricted Stock
Under our stock-based compensation plans, a limited number of shares of
restricted common stock may be granted to our officers and employees. These
shares carry voting and dividend rights; however, sale or transfer of the shares
is restricted. These restricted stock awards vest over a specific period of time
and/or if we achieve established performance targets. Restricted stock awards
representing 1.4 million, 2.3 million, and 0.4 million shares were granted
during 2002, 2001 and 2000 with a weighted average grant date fair value of
$38.45, $62.10 and $34.82 per share. At December 31, 2002, 4.4 million shares of
restricted stock were outstanding. The value of restricted shares subject to
performance vesting is determined based on the fair market value on the date
performance targets are achieved, and this value is charged to compensation
expense ratably over the required service or restriction period. The value of
time vested restricted shares is determined at their issuance date and this cost
is amortized to compensation expense over the period of service. For 2002, 2001,
and 2000, these charges totaled $73 million, $67 million, and $13 million.
Included in deferred compensation at December 31, 2000, is $69 million related
to options that will be converted automatically into common stock at the end of
their vesting period. These options met all performance targets in December
2000.
Performance Units
We award eligible officers performance units that are payable in cash or
stock at the end of the vesting period. The final value of the performance units
may vary according to the plan under which they are granted, but is usually
based on our common stock price at the end of the vesting period or total
shareholder return during the vesting period relative to our peer group. The
value of the performance units is charged ratably to compensation expense over
the vesting period with periodic adjustments to account for the fluctuation in
the market price of our stock or changes in expected total shareholder return.
Amounts charged to compensation expense in 2002, 2001 and 2000 were $10 million,
$64 million and $25 million. Our 2001 expense includes a $51 million charge to
pay out all of our outstanding phantom stock options. In June 2002, we reduced
the amount we were accruing for the performance units issued to executives. The
adjustment decreased our total liability by $21 million.
164
Employee Stock Purchase Program
In October 1999, we implemented an employee stock purchase plan under
Section 423 of the Internal Revenue Code. The plan allows participating
employees the right to purchase common stock on a quarterly basis at 85 percent
of the lower of the market price at the beginning of the plan period or at the
end of each calendar quarter. Five million shares of common stock are authorized
for issuance under this plan.
The following table presents the number of shares issued and the price per
share by quarter for the year ended December 31:
2002 2001 2000
--------------------- ------------------- -------------------
PRICE PRICE PRICE
SHARES PER SHARE SHARES PER SHARE SHARES PER SHARE
--------- --------- ------ --------- ------ ---------
1st Quarter........................... 205,118 $38.02 75,851 $55.10 90,718 $32.33
2nd Quarter........................... 414,546 $17.20 90,319 $44.22 87,622 $32.33
3rd Quarter........................... 466,655 $ 6.61 104,404 $34.58 84,780 $32.33
4th Quarter........................... 283,313(1) $ 5.95 42,570(1) $38.34 83,212 $32.33
--------- ------- -------
Total....................... 1,369,632 313,144 346,332
========= ======= =======
---------------
(1) Since many employees reached the maximum contribution that is imposed by
Section 423 of the Internal Revenue Code in the third quarter of 2001 and
2002, they were excluded from participating in the fourth quarter of 2001
and 2002.
Funds we receive under this program may be used for general corporate
purposes. However, we record a liability for the withholdings not yet applied
towards the purchase of common stock. We bear all expenses associated with
administering the plan, except for costs, including any applicable taxes,
associated with the participants' sale of common stock. Effective January 1,
2003, we have suspended our employee stock purchase program.
24. SEGMENT INFORMATION
We segregate our business activities into four distinct operating segments:
Pipelines, Production, Field Services and Merchant Energy. 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. We have reclassified our historical petroleum markets
and coal mining operations from our Merchant Energy segment to discontinued
operations in these financial statements for all periods presented. All periods
have been adjusted to reflect this change.
Our Pipelines segment provides natural gas transmission, storage, gathering
and related services in the U.S. and internationally. We conduct our activities
primarily through seven wholly owned and seven partially owned interstate
transmission systems along with six underground natural gas storage entities and
an LNG terminalling facility. Our pipeline operations also include access
between our U.S. based systems and Canada and Mexico as well as interests in
three operating natural gas transmission systems in Australia.
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., Production has onshore and
coal seam operations and properties in 16 states and offshore operations and
properties in federal and state waters in the Gulf of Mexico. Internationally,
we have exploration and production rights in Australia, Bolivia, Brazil, Canada,
Hungary, Indonesia and Turkey.
Our Field Services segment provides customers with wellhead-to-mainline
services, including natural gas gathering, products extraction, fractionation,
dehydration, purification, compression and transportation of natural gas and
natural gas liquids. Field Services' assets include 23 processing plants and
related gathering facilities located in the south Texas, Louisiana,
Mid-Continent and Rocky Mountain regions, as well as our interest in El Paso
Energy Partners.
Our Merchant Energy segment consists of a global power division, an energy
trading division and other merchant operations (which consist primarily of our
LNG activities). We buy, sell and trade natural gas,
165
power, crude oil, and other energy commodities throughout the world, and own or
have interests in 88 power plants in 18 countries.
We use EBIT to assess the operating results and effectiveness of our
business segments. We define EBIT as net income (loss) adjusted for (i) items
that do not impact our income (loss) from continuing operations, such as
extraordinary items, discontinued operations and the impact of accounting
changes, (ii) income taxes, (iii) interest and debt expense and (iv)
distributions on preferred interests of consolidated subsidiaries. We exclude
interest and debt expense and distributions on preferred interests of
consolidated subsidiaries so that investors may evaluate our operating results
without regard to our financing methods or capital structure. Our business
operations consist of both consolidated businesses as well as substantial
investments in unconsolidated affiliates. As a result, we believe EBIT, which
includes the results of both these consolidated and unconsolidated operations,
is useful to our investors because it allows them to more effectively evaluate
the performance of all of our businesses and investments. This measurement may
not be comparable to measurements used by other companies and should not be used
as a substitute for net income or other performance measures such as operating
cash flow. The following table presents are our segment results as of and for
the year ended December 31.
SEGMENTS
AS OF OR FOR THE YEAR ENDED DECEMBER 31, 2002
---------------------------------------------------------------------
FIELD MERCHANT CORPORATE
PIPELINES PRODUCTION SERVICES ENERGY AND OTHER(1) TOTAL
--------- ---------- -------- -------- ------------ ------
(IN MILLIONS)
Revenue from external customers
Domestic........................... $2,382 $ 432 $1,145 $ 2,617(2) $ 43 $6,619
Foreign............................ 3 71 3 542(2) -- 619
Intersegment revenue................. 220 1,623 881 (2,187)(2) (177) 360(3)
Restructuring and merger-related
costs.............................. 1 -- 1 25 50 77
(Gain) loss on long-lived assets..... (13) 3 (179) 204 170 185
Western Energy Settlement............ 412 -- -- 487 -- 899
Ceiling test charges................. -- 269 -- -- -- 269
Depreciation, depletion and
amortization....................... 374 773 56 56 73 1,332
Operating income (loss).............. $ 790 $ 529 $ 271 $(1,009) $(326) $ 255
Earnings (losses) from unconsolidated
affiliates......................... (2) 7 18 (256) 7 (226)
Minority interests in consolidated
subsidiaries....................... -- -- (5) (53) -- (58)
Other income......................... 33 1 3 61 103 201
Other expense........................ (3) (3) -- (164) (10) (180)
------ ------ ------ ------- ----- ------
EBIT................................. $ 818 $ 534 $ 287 $(1,421) $(226) $ (8)
====== ====== ====== ======= ===== ======
---------------
(1) Includes our Corporate and telecommunication activities and eliminations of
intercompany transactions. Our intersegment revenues, along with our
intersegment operating expenses, consist of normal course of business-type
transactions between our operating segments. We record an intersegment
revenue elimination, which is the only elimination included in the
"Corporate and Other" column, to remove intersegment transactions.
(2) Merchant Energy revenues take into account the adoption of a consensus
reached on EITF Issue No. 02-3, which requires us to report all physical
sales of energy commodities in our energy trading activities on a net basis
as a component of revenues. See Note 1 regarding the adoption of this Issue.
(3) This amount relates to intercompany activities between our continuing
operating segments and our discontinued petroleum markets operations.
166
SEGMENTS
AS OF OR FOR THE YEAR ENDED DECEMBER 31, 2002
----------------------------------------------------------------------
FIELD MERCHANT CORPORATE
PIPELINES PRODUCTION SERVICES ENERGY AND OTHER(1) TOTAL
--------- ---------- -------- -------- ------------ -------
(IN MILLIONS)
Discontinued operations, net of
income taxes...................... $ -- $ -- $ -- $ -- $ (365) $ (365)
Cumulative effect of accounting
change, net of income taxes....... 79 -- -- (133) -- (54)
Assets of continuing operations(2)
Domestic.......................... 14,743 7,354 2,666 8,782 4,029 37,574
Foreign........................... 59 703 14 3,567 242 4,585
Capital expenditures and investments
in unconsolidated affiliates...... 1,074 2,301 187 168 309 4,039
Total investments in unconsolidated
affiliates........................ 1,059 87 875 2,847 23 4,891
---------------
(1) Includes our Corporate and telecommunication activities and eliminations of
intercompany transactions.
(2) Excludes $4,065 million of assets from discontinued operations.
SEGMENTS
AS OF OR FOR THE YEAR ENDED DECEMBER 31, 2001
----------------------------------------------------------------------
FIELD MERCHANT CORPORATE
PIPELINES PRODUCTION SERVICES ENERGY AND OTHER(1) TOTAL
--------- ---------- -------- -------- ------------ -------
(IN MILLIONS)
Revenue from external customers
Domestic............................ $ 2,451 $ 199 $1,809 $ 3,785(2) $ 379 $ 8,623
Foreign............................. 2 46 4 261(2) -- 313
Intersegment revenue.................. 295 2,102(3) 740 (2,822)(2) (312) 3(4)
Merger-related costs.................. 291 47 46 17 1,092 1,493
(Gain) loss on long-lived assets...... 21 16 -- 21 19 77
Ceiling test charges.................. -- 135 -- -- -- 135
Depreciation, depletion, and
amortization........................ 383 678 111 42 47 1,261
Operating income (loss)............... $ 886 $ 919 $ 124 $ 620 $(1,406) $ 1,143
Earnings (losses) from unconsolidated
affiliates.......................... 136 (1) 72 219 11 437
Minority interests in consolidated
subsidiaries........................ (1) -- -- (1) -- (2)
Other income.......................... 28 3 3 200 54 288
Other expense......................... (11) (1) (4) (23) (87) (126)
------- ------ ------ ------- ------- -------
EBIT.................................. $ 1,038 $ 920 $ 195 $ 1,015 $(1,428) $ 1,740
======= ====== ====== ======= ======= =======
Discontinued operations, net of income
taxes............................... $ -- $ -- $ -- $ -- $ (85) $ (85)
Extraordinary items, net of income
taxes............................... (27) -- (5) (7) 65 26
Assets of continuing operations(5)
Domestic............................ 14,345 7,584 3,564 9,108 3,991 38,592
Foreign............................. 98 874 17 4,147 32 5,168
Capital expenditures and investments
in unconsolidated affiliates........ 1,093 2,521 165 957 1,121 5,857
Total investments in unconsolidated
affiliates.......................... 1,104 77 554 3,482 19 5,236
---------------
(1) Includes our Corporate and telecommunication activities, eliminations of
intercompany transactions and in 2001, our retail business. Our intersegment
revenues, along with our intersegment operating expenses, consist of normal
course of business-type transactions between our operating segments. We
record an intersegment revenue elimination, which is the only elimination
included in the "Corporate and Other" column, to remove intersegment
transactions.
(2) Merchant Energy revenues take into account the adoption of a consensus
reached on EITF Issue No. 02-3, which requires us to report all physical
sales of energy commodities in our energy trading activities on a net basis
as a component of revenues. See Note 1 regarding the adoption of this Issue.
(3) The increase in intersegment revenue from 2000 to 2001 for our Production
segment is primarily due to the consolidation of Engage in September 2000.
(4) This amount relates to intercompany activities between our continuing
operating segments and our discontinued petroleum markets operations.
(5) Excludes $4,786 million of assets from discontinued operations.
167
SEGMENTS
AS OF OR FOR THE YEAR ENDED DECEMBER 31, 2000
----------------------------------------------------------------------
FIELD MERCHANT CORPORATE
PIPELINES PRODUCTION SERVICES ENERGY AND OTHER(1) TOTAL
--------- ---------- -------- -------- ------------ -------
(IN MILLIONS)
Revenue from external customers
Domestic............................ $ 2,521 $1,134 $1,307 $ 1,185(2) $ 990 $ 7,137
Foreign............................. -- 5 2 61(2) -- 68
Intersegment revenue.................. 220 547 130 (445)(2) (469) (17)(3)
Merger-related costs.................. -- -- -- -- 93 93
(Gain) loss on long-lived assets...... (7) -- 7 (2) 1 (1)
Depreciation, depletion, and
amortization........................ 376 611 76 42 66 1,171
Operating income (loss)............... $ 1,150 $ 613 $ 166 $ 419 $ (93) $ 2,255
Earnings from unconsolidated
affiliates.......................... 149 -- 47 226 1 423
Other income.......................... 27 -- 2 123 54 206
Other expense......................... (3) (4) (1) (19) (25) (52)
------- ------ ------ ------- ------ -------
EBIT.................................. $ 1,323 $ 609 $ 214 $ 749 $ (63) $ 2,832
======= ====== ====== ======= ====== =======
Discontinued operations, net of income
taxes............................... $ -- $ -- $ -- $ -- $ 123 $ 123
Extraordinary items, net of income
taxes............................... 89 -- (19) -- -- 70
Assets of continuing operations(4)
Domestic............................ 14,025 5,856 3,752 12,405 3,290 39,328
Foreign............................. 83 198 17 2,517 57 2,872
Capital expenditures and investments
in unconsolidated affiliates........ 725 2,067 505 886 773 4,956
Total investments in unconsolidated
affiliates.......................... 1,119 7 567 2,519 75 4,287
---------------
(1) Includes our Corporate and telecommunication activities, eliminations of
intercompany transactions. Our intersegment revenues, along with our
intersegment operating expenses, consist of normal course of business-type
transactions between our operating segments. We record an intersegment
revenue elimination, which is the only elimination included in the
"Corporate and Other" column, to remove intersegment transactions.
(2) Merchant Energy revenues take into account the adoption of a consensus
reached on EITF Issue No. 02-3, which requires us to report all physical
sales of energy commodities in our energy trading activities on a net basis
as a component of revenues. See Note 1 regarding the adoption of this Issue.
(3) This amount relates to intercompany activities between our continuing
operating segments and our discontinued petroleum markets operations.
(4) Excludes $4,703 million of assets from discontinued operations.
The reconciliations of EBIT to income (loss) from continuing operation
before extraordinary items and cumulative effect of accounting changes are
presented below for each of the three years ended December 31:
2002 2001 2000
------- ------- -------
(IN MILLIONS)
Total EBIT for segments................................. $ (8) $ 1,740 $ 2,832
Interest and debt expense............................... (1,388) (1,129) (1,001)
Returns on preferred interest of consolidated
subsidiaries.......................................... (159) (217) (204)
Income tax.............................................. 507 (242) (514)
------- ------- -------
Income (loss) from continuing operations
before extraordinary items and cumulative
effect of accounting changes................ $(1,048) $ 152 $ 1,113
======= ======= =======
We had no customers whose revenues exceeded 10 percent of our total
revenues in 2002, 2001 and 2000.
168
25. SUPPLEMENTAL CASH FLOW INFORMATION
The detail of our cash flow changes in working capital from continuing
operations for the three years ending December 31 are as follows:
2002 2001 2000
------- ------- -------
(IN MILLIONS)
Working capital changes
Accounts and notes receivable......................... $ (657) $ 1,305 $(3,036)
Inventory............................................. 248 30 (7)
Change in trading price risk management activities,
net................................................ 387 1,414 (1,373)
Accounts payable...................................... (128) (1,044) 2,110
Broker and other margins on deposit with others....... (257) 88 (893)
Broker and other margins on deposit with us........... (647) 210 936
Other working capital changes
Assets............................................. (85) (520) 731
Liabilities........................................ 62 335 (781)
------- ------- -------
Total......................................... $(1,077) $ 1,818 $(2,313)
======= ======= =======
Our non-working capital and other cash flow changes from continuing
operations for the three years ending December 31 are as follows:
2002 2001 2000
----- ----- -----
(IN MILLIONS)
Non-working capital changes and other
Assets.................................................... $ (1) $ 79 $ (20)
Liabilities............................................... (145) (249) (84)
----- ----- -----
Total............................................. $(146) $(170) $(104)
===== ===== =====
The following table contains supplemental cash flow information from
continuing operations for the three years ended December 31 for interest and
taxes, which are reflected in working capital and non-working capital changes
above:
2002 2001 2000
------ ------ ----
(IN MILLIONS)
Interest paid............................................... $1,291 $1,378 $930
Income tax payments (refunds)............................... (106) 56 110
169
Detail of our short-term and long-term borrowings and repayments for the
years ended December 31 is as follows:
2002 2001 2000
------- ------- ------
(IN MILLIONS)
Short-term borrowings and repayments
Net repayments of commercial paper and short-term
credit facilities................................... $ 154 $ (328) $ (64)
Borrowings under credit facilities..................... -- 245 455
Repayments on credit facilities........................ -- (700) --
Repayments of notes payable............................ (94) (3) (82)
------- ------- ------
Total.......................................... $ 60 $ (786) $ 309
======= ======= ======
Long-term borrowings and repayments
Net proceeds from the issuance of notes payable........ $ -- $ -- $ 58
Net proceeds from the issuance of long-term debt....... 4,294 3,110 2,619
Payments to retire long-term debt and other financing
obligations......................................... (1,777) (1,856) (538)
Increase in notes payable to affiliates................ 4 521 1,207
Decrease in notes payable to affiliates................ (513) (612) (600)
------- ------- ------
Total.......................................... $ 2,008 $ 1,163 $2,746
======= ======= ======
26. INVESTMENTS IN AND ADVANCES TO UNCONSOLIDATED AFFILIATES
We hold investments in various unconsolidated affiliates which are
accounted for using the equity method of accounting. Our principal equity method
investees are international pipelines, interstate pipelines, power generation
plants, and gathering systems. Our investment balance was greater than our
equity in the net assets of these investments as of December 31, 2002 and 2001
by $231 million and $561 million. In 2002, the primary differences related to
unamortized purchase price adjustments and asset impairment charges. In 2001,
the primary differences related to unamortized purchase price adjustments, power
contract restructurings and change in priority return on our investment in
Chaparral and a financial guarantee for an international investment. Our net
ownership interest, investments in and advances to our unconsolidated affiliates
are as follows as of December 31:
170
NET INVESTMENTS ADVANCES
TYPE OWNERSHIP --------------- -----------
OF ENTITY INTEREST 2002 2001 2002 2001
--------- --------- ------ ------ ---- ----
(PERCENT) (IN MILLIONS)
Alliance Pipeline Limited
Partnership(1)......................... LP(2) 2 $ 24 $ 160 $ -- $ --
Aux Sable Liquid(3)...................... LP(2) 14 -- 58 -- --
Bastrop Company.......................... LLC(4) 50 121 99 -- --
CE Generation(5)......................... LLC(4) 50 287 360 -- --
Chaparral Investors (Electron)(6)........ LLC(4) 20 256 341 700 895
Citrus Corporation(7).................... 50 606 512 -- --
Eagle Point Cogeneration
Partnership(8)......................... GP(9) 84 -- 85 -- --
El Paso Energy Partners.................. LP(2) --(10) 776 380 -- --
Great Lakes Gas Transmission(11)......... 50 312 297 -- --
Midland Cogeneration Venture(12)......... LP(2) 44 316 276 -- --
Portland Natural Gas Transmission
System................................. GP(9) 30 51 39 -- --
Other Domestic Investments(13)(16)....... various 387 537 67 40
------ ------ ---- ----
Domestic............................... 3,136 3,144 767 935
------ ------ ---- ----
NET INVESTMENTS ADVANCES
TYPE OWNERSHIP --------------- -------------
COUNTRY OF ENTITY INTEREST 2002 2001 2002 2001
------------------ ----------- --------- ------ ------ ---- ------
(PERCENT) (IN MILLIONS)
Aguaytia Energy.............. Peru LLC(4) 24 $ 52 $ 52 $ -- $ --
Bolivia to Brazil Pipeline... Bolivia/Brazil LLC(4) 8 53 50 -- --
CAPSA/CAPEX(14).............. Argentina Corporation -- -- 259 -- --
Diamond Power (Gemstone)..... Brazil LLC(4) 50 663 555 25 --
EGE Fortuna.................. Panama Corporation 25 61 56 -- --
EGE Itabo.................... Dominican Republic Corporation 25 87 101 -- --
Enfield Power................ United Kingdom LP(2) 25 50 53 -- --
Gasoducto del Pacifico
Pipeline (Argentina to
Chile)..................... Argentina/Chile Corporation 16 69 71 -- --
Habibullah Power............. Pakistan LLC(4) 50 57 53 99 --
Korea Independent Energy
Corporation................ Korea Corporation 50 206 104 -- --
Meizhou Wan Generating....... China LLC(4) 25 56 76 -- --
Pescada...................... Brazil LLC(4) 50 80 70 -- --
Saba Power Company........... Pakistan LLC(4) 94 55 48 -- --
Samalayuca(15)............... Mexico LLC(4) 50 22 103 -- --
Other Foreign
Investments(13)(16)........ various various 244 441 80 91
------ ------ ---- ------
Foreign.................... 1,755 2,092 204 91
------ ------ ---- ------
Total investments in and advances to unconsolidated affiliates $4,891 $5,236 $971 $1,026
====== ====== ==== ======
---------------
(1) We sold 12.3 percent interest in November 2002, and we sold the remaining
of 2.1 percent interest in March 2003.
(2) LP represents Limited Partnership.
(3) We sold 100 percent of our interest in November 2002.
(4) LLC represents Limited Liability Company.
(5) We sold 100 percent of our interest in January 2003.
(6) Mesquite Investors, LLC is included in Chaparral. We gave notice to our
partner in March 2003 of our intent to exercise our option to purchase
their interest. We anticipate the transaction will close in the second
quarter of 2003.
(7) Citrus corporation owns 100 percent of Florida Gas Transmission System.
(8) Consolidated in January 2002.
(9) GP represents General Partnership.
(10) Our ownership interest consists of a one percent general partner interest,
approximately 27 percent of the partnership's common units, all of the
outstanding Series B preference units with $158 million liquidation value
and all of the outstanding Series C units acquired for $350 million in
November 2002.
(11) Includes a 46 percent general partner interest in Great Lakes Gas
Transmission Limited Partnership and a 4 percent limited partner interest
through our ownership in Great Lakes Gas Transmission Company.
(12) Our ownership interest consists of a 38.1 percent general partner interest
and 5.4 percent limited partner interest.
(13) Denotes investments that are individually less than $50 million.
(14) Impaired in first quarter of 2002. Includes 45 percent of CAPSA, which owns
60 percent of CAPEX. This results in a 27 percent indirect ownership
interest in CAPEX.
(15) We sold 100 percent of our interest in Samalayuca II power plant in
December 2002.
(16) As a result of our intent to dispose of our petroleum and chemical assets,
we classified as discontinued operations, other domestic investment
balances totaling $4 million as of December 31, 2002, and $5 million as of
December 31, 2001, an advance balance of $23 million, as of December 31,
2002, and other foreign investment balances totaling $12 million as of
December 31, 2002, and $56 million as of December 31, 2001.
171
Earnings from our unconsolidated affiliates are as follows for each of the
three years ended December 31:
2002 2001 2000
----- ---- ----
(IN MILLIONS)
Aguaytia Energy............................................. $ 3 $ 4 $ 1
Alliance Pipeline Limited Partnership(1).................... 21 23 12
Aux Sable Liquid............................................ (3) (4) (2)
Bastrop Company, LLC........................................ (5) -- --
Bolivia to Brazil Pipeline.................................. 2 1 --
CAPSA/CAPEX................................................. -- (12) 4
CE Generation(2)............................................ 22 29 35
Chaparral Investors (Electron).............................. (62) 75 (5)
Citrus Corporation.......................................... 43 41 51
Diamond Power (Gemstone).................................... 109 2 --
Eagle Point Cogeneration Partnership(3)..................... -- 22 25
EGE Fortuna................................................. 5 3 7
EGE Itabo................................................... (2) 5 9
El Paso Energy Partners..................................... 70 47 20
Enfield Power............................................... (3) 18 2
Gasoducto del Pacifico Pipeline (Argentina to Chile)........ (2) 2 1
Great Lakes Gas Transmission................................ 63 55 52
Habibullah Power............................................ 10 2 9
Korea Independent Energy Corporation........................ 24 20 --
Meizhou Wan Generating...................................... (13) -- --
Midland Cogeneration Venture................................ 28 23 37
Pescada..................................................... 6 (1) --
Portland Natural Gas Transmission System.................... 4 -- (1)
Saba Power Company.......................................... 7 -- 1
Samalayuca(4)............................................... 19 12 17
Other(5).................................................... 52 116 112
----- ---- ----
Subtotal............................................... 398 483 387
Impairment charges and gains and losses on sale of
investments(6)............................................ (624) (46) 36
----- ---- ----
Total earnings (losses) from unconsolidated
affiliates........................................... $(226) $437 $423
===== ==== ====
---------------
(1) We sold 12.3 percent interest in November 2002, and we sold the remaining of
2.1 percent interest in March 2003.
(2) Sold in first quarter of 2003.
(3) Consolidated in January 2002.
(4) We sold our interest in Samalayuca II power plant in December 2002.
(5) These amounts exclude $5 million, $(13) million and $(5) million as of
December 31, 2002, 2001 and 2000, related to our discontinued petroleum
markets operations.
(6) This amount excludes $(3) million as of December 31, 2002, related to our
discontinued petroleum markets operations.
172
Our impairment charges and gains and losses on sales of our investments
during 2002, 2001 and 2000 consisted of the following:
PRE-TAX
INVESTMENT GAIN (LOSS) CAUSE OF IMPAIRMENT
---------- ------------- -------------------
(IN MILLIONS)
2002
Aqua de Cajon....................... $ (24) Weak economic conditions in
Argentina
Aux Sable........................... (47) Sale of investment
CAPSA/CAPEX......................... (262) Weak economic conditions in
Argentina
CE Generation....................... (74) Sale of investment
EPIC Australia...................... (153) Decision to discontinue further
capital investment
PPN................................. (41) Loss of economic fuel supply and
payment default
Other investments................... (23)
-----
Continuing operations............. $(624)
=====
Discontinued operations........... $ (3)
=====
2001
East Asia Power..................... $ (39) Weak economic conditions in the
Philippines and a decision to
discontinue further capital
investment
Deepwater Investors................. 13 Sale of investment
Fife Power.......................... (35) Weak economic conditions in the U.K.
power market and the decision to
discontinue further capital
investment
Other............................... 15
-----
Total 2001..................... $ (46)
=====
2000
East Asia Power..................... $ 20 Sale of a portion of our investment
Guatemala Power..................... 16 Sale of investment
-----
Total 2000..................... $ 36
=====
Summarized financial information of our proportionate share of
unconsolidated affiliates below includes affiliates in which we hold a less than
50 percent interest as well as those in which we hold a greater than 50 percent
interest. We received distributions and dividends of $234 million from
continuing operations and $22 million from discontinued operations in 2002 and
$236 million from continuing operations and $5 million from discontinued
operations in 2001 from our investments. Our proportional shares of the
unconsolidated affiliates in which we hold a greater than 50 percent interest
had net income from continuing operations of $26 million and $40 million in 2002
and 2001 (excluding net loss from discontinued operations of $2 million in each
of 2002 and 2001) and total assets of continuing operations of $389 million and
$715 million at December 31, 2002 and 2001 (excluding total assets of
discontinued operations of $61 million and $51 million at December 31, 2002 and
2001).
YEAR ENDED DECEMBER 31,
----------------------------
2002 2001 2000
------- ------- ------
(UNAUDITED)
(IN MILLIONS)
Operating results data from continuing operations:
Operating revenues................................... $ 2,486 $ 2,151 $4,722
Operating expenses................................... 1,632 1,391 4,140
Income from continuing operations.................... 422 436 329
Net income........................................... 445 461 346
173
YEAR ENDED DECEMBER 31,
----------------------------
2002 2001 2000
------- ------- ------
(UNAUDITED)
(IN MILLIONS)
Operating results data from discontinued operations:
Operating revenues................................... $ 395 $ 339 $ 412
Operating expenses................................... 386 327 478
Net income........................................... 5 12 6
DECEMBER 31,
------------------
2002 2001
------- -------
(UNAUDITED)
(IN MILLIONS)
Financial position data from continuing operations:
Current assets....................................... $ 1,334 $ 1,286
Non-current assets................................... 10,520 11,078
Short-term debt...................................... 777 352
Other current liabilities............................ 855 786
Long-term debt....................................... 4,448 4,814
Other non-current liabilities........................ 1,083 1,706
Minority interest.................................... 30 32
Equity in net assets................................. 4,661 4,674
DECEMBER 31,
------------------
2002 2001
------- -------
(UNAUDITED)
(IN MILLIONS)
Financial position data from discontinued operations:
Current assets....................................... $ 170 $ 64
Non-current assets................................... 75 74
Short-term debt...................................... 152 54
Other current liabilities............................ 1 2
Long-term debt....................................... 69 10
Equity in net assets................................. 23 72
The following table shows revenues and charges from our unconsolidated
affiliates from continuing operations:
2002 2001 2000
---- ---- ------
(IN MILLIONS)
Operating revenue(1)(2)..................................... $ 59 $215 $1,163
Other revenue -- management fees............................ 192 150 82
Cost of sales(1)(3)......................................... 142 92 286
Reimbursement for operating expenses........................ 186 164 102
Other income................................................ 18 20 14
Interest income............................................. 30 45 23
Interest expense............................................ 42 50 49
---------------
(1) The decrease in 2001 affiliated revenue and cost of sales is due primarily
to the consolidation of Engage in September 2000.
(2) Excludes net operating revenues (which is revenue less cost of products
sold) of $178 million for 2002, $299 million for 2001 and $178 million for
2000 related to discontinued operations. These net revenues take into
account EITF Issue No. 02-3, which required us to report all physical sales
of energy commodities in our energy trading activities net of the cost of
the product sold as a component of revenues. See Note 1 regarding the
adoption of this Issue.
(3) Excludes other cost of sales of $126 million for 2002, $83 million for 2001
and $3 million for 2000 related to discontinued operations.
Chaparral
We entered into the Chaparral investment (also referred to as Electron) in
1999 to expand our domestic power generation business. Chaparral's corporate
structure is a limited liability company that, at December 31, 2002, was owned
approximately 20% by us and approximately 80% by an unaffiliated investor,
174
Limestone. Limestone is capitalized by private equity contributions of $150
million from a group of unrelated financial investors through Credit Suisse
First Boston Corporation and $1 billion of senior secured notes issued to
institutional investors. Limestone is controlled by subsidiaries or affiliates
of Credit Suisse First Boston Corporation.
In March 2003, we notified Limestone that we would exercise our right under
the partnership agreements to purchase all of the outstanding third party equity
in Limestone on May 31, 2003, for $175 million. Also in March 2003, we
contributed $1 billion to Limestone in exchange for a non-controlling interest,
which Limestone then used to pay off the Limestone notes which matured on March
17, 2003. Following our investment of $1 billion in Limestone, our effective
ownership in Chaparral increased to approximately 90 percent. We continue to
account for our investment in Chaparral under the equity method since we do not
control Limestone, and therefore do not control Chaparral. We will, however,
consolidate Chaparral upon the purchase of the remaining Limestone equity
interest, which we anticipate will occur in May 2003. At that time, we will
record the acquired assets and liabilities at their fair values. The fair value
of assets and liabilities acquired will be impacted by changes in the
unregulated power industry as a whole, as well as by changes in regional power
prices in the U.S. Any excess of the proceeds paid over the fair value of net
assets acquired will be reflected as goodwill. Goodwill is not amortized, but it
will be tested for impairment.
Chaparral owns or has interests in approximately 34 power generation
facilities. As of December 31, 2002, Chaparral had $4.2 billion of total assets
and $1.8 billion of consolidated third party debt. Chaparral's debt is related
to specific projects it owns or has interests in, and is recourse solely to
those projects.
We have entered into various financing transactions with Chaparral and its
subsidiaries each year, which include capital contributions, debt issuances and
advances.
The following table summarizes the presentation of these transactions on
our balance sheet at December 31 (in millions):
2002 2001
----- -----
Debt securities payable..................................... $ (79) $(169)
Notes receivable............................................ 323 343
Credit facility receivable.................................. 377 552
Contingent interest promissory notes payable................ (173) (289)
----- -----
Subtotal............................................... 448 437
Equity investment........................................... 256 341
----- -----
Net investment.............................................. $ 704 $ 778
===== =====
The debt securities, notes payable and receivable, revolving credit
facility, and contingent interest promissory notes are included in current and
long-term receivables and payables from affiliates, as appropriate, with the
related interest as interest income or expense in our income statement.
The debt securities payable to Chaparral are payable on demand and carry a
fixed interest rate of 7.443%. The notes payable and receivable from Chaparral
are payable on demand and carry various fixed interest rates. The credit
facility was established in 1999 and allows Chaparral to borrow up to $925
million from us at a variable interest rate, which was 1.94%, 2.64% and 7.32% at
December 31, 2002, 2001 and 2000.
The contingent interest promissory notes carry a variable interest rate not
to exceed 12.75%, which was 10.0%, 11.0% and 10.9% at December 31, 2002, 2001
and 2000, and mature in 2019 through 2021. The interest payments are contingent
on cash flow distributions from five power plant investments we own. If we sell
these investments, the maturity date of the notes may be accelerated.
Chaparral has used our funds and the funds contributed by Limestone to
acquire the domestic power generation and related businesses described above. In
some cases, Chaparral acquired these power generation assets from us. Chaparral
did not acquire any power generation assets from us in 2002. Chaparral acquired
175
power generation assets from us with a value of $276 million in 2001, which we
determined to be a fair and reasonable amount. We did not recognize any gains or
losses on those transactions.
In addition to the financing transactions described above, we have also
entered into various contractual agreements with Chaparral related to management
and trading activities.
We serve as manager of Chaparral under a management agreement that expires
in 2006. We are compensated for the services we provide through an annual
management fee, which has performance based and fixed components. The
performance fee was determined based on how well we performed as manager of
Chaparral, and was determined by evaluating the changes in the value of the
portfolio of power assets held by Chaparral. Our management fee is evaluated for
reasonableness and is subject to the approval of our joint venture partner
annually. In 2002 and 2001, the management fee was $205 million and $167
million, consisting of a $185 million and $147 million performance fee recorded
in operating revenues plus a $20 million annual fixed fee in both years recorded
as a reimbursement of operating expenses. We do not expect to earn a
performance-based management fee or receive a cost reimbursement fee from
Chaparral in 2003. In addition, we have administrative services agreements with
many of the power plants in the Chaparral structure. We recorded approximately
$104 million, $95 million, and $47 million in 2002, 2001, and 2000 as a
reimbursement of operating expenses under these agreements.
We also enter into various contractual agreements with Chaparral and its
operating subsidiaries in conjunction with Chaparral's operations. These include
agreements to (i) supply natural gas or other fuels to power Chaparral's
facilities; (ii) purchase all or a portion of the power produced by Chaparral's
facilities; (iii) provide some or all of the power supply that Chaparral is
obligated to provide to fulfill agreements it has with third parties; (iv)
purchase tolling rights; and (v) provide other services to Chaparral related to
its operations. We recognized revenues of $65 million and $243 million in 2002
and 2001 related to these transactions. These activities are accounted for under
both the accrual method and the mark-to-market method of accounting, depending
on the contract.
Gemstone
We entered into the Gemstone investment in 2001 to finance five major power
plants in Brazil.
Gemstone is a generic term used to describe several entities. The first is
the joint venture in which we have an equity investment named Diamond Power
Ventures, LLC, (Diamond). Diamond is owned by us and a company called Gemstone
Investor Limited (Gemstone Investor). Gemstone Investor is 100 percent owned by
a subsidiary of Rabobank International, which, in addition to its $50 million
equity investment, issued $950 million of senior secured notes to institutional
investors. Gemstone Investor used the entire $1 billion to (a) invest up to $700
million in Diamond, and (b) purchase a $300 million preferred interest in a
company called Topaz Power Ventures LLC (Topaz), our consolidated subsidiary.
Topaz indirectly owns and operates two Brazilian power plants. We account for
Gemstone Investor's preferred investment in Topaz as minority interest. We do
not consolidate Diamond, which owns three power plants under development in
Brazil.
Gemstone owns interests in five power generation facilities in Brazil with
a total power generation capacity of 2,184 megawatts. As of December 31, 2002,
Gemstone had total assets of $1.7 billion, including a $304 million investment
in Topaz, which carries a preferred return of 8.03%, and $122 million in
receivables from us, which carry a fixed interest rate of 5.25%. Our total
investment in Gemstone at December 31, 2002, was $663 million, excluding the
payables of $122 million and minority interest of $304 million mentioned above.
Our consolidated subsidiary, Gemstone Administracao Ltda, serves as the
managing member of Diamond and provides management services to Diamond under a
fixed-fee administrative services agreement that has an original term of ten
years. The fixed fee reimburses us for legal, accounting and general and
administrative expenses incurred on behalf of Diamond. This fee was not
significant for 2002 or 2001.
176
The following summarizes our financial position with Gemstone at December
31 (in millions):
2002 2001
----- -----
Debt securities payable..................................... $(122) $(346)
Credit facility receivable.................................. 25 --
----- -----
Subtotal.................................................. (97) (346)
Equity investment........................................... 663 555
Net investment.............................................. $ 566 $ 209
===== =====
Minority interest........................................... $(304) $(300)
===== =====
We have a credit facility with Gemstone that allows Gemstone to borrow up
to $300 million from us at a variable interest rate, which was 6.8% at December
31, 2002. Gemstone owed us $25 million under this facility as of December 31,
2002, and did not utilize this facility in 2001. We earned less than $1 million
of interest income from this facility in 2002 and 2001.
Our investment in Gemstone as of December 31, 2002 and 2001, was $663
million and $555 million, and we account for our investment using the equity
method of accounting since we do not have the ability to exercise control over
the entity. The short-term notes we issued are included in short-term borrowings
in our balance sheet, with the related interest as interest expense in our
income statement. We account for the investor's preferred interest in our
consolidated subsidiary as a minority interest in our balance sheet and the
preferred return as minority interest expense in our income statement.
Under our management agreement with Gemstone, we earn a cost-based
management fee. This fee was not significant in 2002 or 2001. We have also
entered into a participation agreement with one of Gemstone's power generation
interests whereby we earn a fee for managing, constructing, and operating the
related facilities and marketing and distributing the energy produced by these
facilities. This fee was not significant in 2002.
Rabobank, the third party investor in Gemstone, has the right to remove us
as manager of Gemstone. In January 2003, Rabobank notified us that they planned
to remove us as manager. We, in turn, notified Rabobank that we were exercising
our right under the partnership agreements to purchase all of their $50 million
equity in Gemstone. We will consolidate Gemstone upon the purchase of Rabobank's
third party equity in Gemstone in April 2003, unless we replace them with a new
partner.
Gemstone owns interests in five power generation facilities in Brazil with
a total power generation capacity of 2,184 MW. Summarized financial position
data for our unconsolidated affiliate in Gemstone, Diamond Power Ventures LLC,
is as follows as of December 31:
2002 2001
------ ----
(UNAUDITED)
(IN MILLIONS)
Financial position data:
Current assets............................................ $ 110 $ 22
Non-current assets........................................ 1,197 901
Short-term debt........................................... -- --
Other current liabilities................................. 46 17
Long-term debt............................................ -- --
Other non-current liabilities............................. 12 --
Members' equity........................................... 1,249 906
Citrus
We own 50 percent of Citrus Corp. Enron Corp. owns the other 50 percent.
Citrus Corporation owns Florida Gas Transmission, a 4,804 mile regulated
pipeline system that extends from producing regions in Texas to markets in
Florida. Our investment in Citrus is limited to our ownership of the voting
stock of Citrus, and we have no financial obligations, commitments or
guarantees, either written or oral, to support Citrus. We
177
have one commercial contract with Citrus under which we provide natural gas to
the trading subsidiary of Citrus, and for which we are paid a fixed price.
The ownership agreements of Citrus provide each partner with a right of
first refusal to purchase the ownership interest of the other partner. We have
no obligations, either written or oral, to acquire Enron's ownership interest in
Citrus in the event Enron must sell its interest as a result of its current
bankruptcy proceedings.
Enron serves as the operator for Citrus. While Enron has filed for
bankruptcy, there have been minimal changes in the operations and management of
Citrus as a result of Enron's bankruptcy. Accordingly, Citrus has continued to
operate as a jointly owned investment, over which we have significant influence,
but not the ability to control.
Enron's bankruptcy has impacted the financial results of Citrus related to
energy contracts between Citrus and Enron's energy trading subsidiary. During
2001, we established reserves of $6.9 million related to the Enron bankruptcy.
During 2002, accounts receivable balances associated with contracts rejected by
the bankruptcy court were classified as uncollectable. We applied the $6.9
million reserve amount against the outstanding accounts receivable balance. None
of these charges are considered to be material to our financial statements.
El Paso Energy Partners
A subsidiary in our Field Services segment serves as the general partner of
El Paso Energy Partners, a master limited partnership that has limited
partnership units that trade on the New York Stock Exchange. We currently own
26.5 percent, or 11,674,245 of the partnership's common units and the one
percent general partner interest. The remaining 73.5 percent of the common units
of the limited partnership are owned by public unit holders (including small
amounts owned by the general partner's management and employees), none of which
exceeds a 10 percent ownership interest. In November 2002, as part of the
proceeds from the sale of our San Juan Basin assets to El Paso Energy Partners,
we received $350 million of Series C units, a new non-voting class of limited
partnership units. The Series C units receive the same level of distributions as
the common units and can be converted to common units. After April 30, 2003, we
will have the right to request a vote of the common unitholders as to whether
the Series C units should be converted into common units. If the common
unitholders approve the conversion, then each Series C unit will convert into a
common unit. If the common unitholders do not approve the conversion within 120
days after the vote is requested, then the distribution rate for the Series C
units will increase to 105 percent of the common unit distribution rate from
time to time. Thereafter, the Series C unit distribution rate can increase to
110 percent of the common unit distribution rate on April 30, 2004, and to 115
percent of the common unit distribution rate on April 30, 2005. Also, in the
third quarter of 2000, we received $170 million of Series B preference units in
exchange for the sale of the natural gas storage businesses of Crystal Gas
Storage, Inc., our wholly owned subsidiary, to El Paso Energy Partners. These
preference units accrue dividends at a rate of 10% on a cumulative basis, and
are redeemable at the option of El Paso Energy Partners. In October 2001, the
partnership redeemed $50 million liquidation value of the Series B preference
units we received in the Crystal transaction. At December 31, 2002, the
liquidation value of the remaining Series B preference units was $158 million. A
majority of the members of the Board of Directors governing El Paso Energy
Partners is independent of us and its audit and conflicts committee and
governance and compensation committee are completely comprised of independent
board members.
As the general partner, Field Services manages the partnership's day-to-day
operations and performs all of the partnership's administrative and operational
activities under a general and administrative services agreement or, in some
cases, separate operational agreements. El Paso Energy Partners contributes to
our income through our general partner interest and our ownership of common and
preference units. We do not have any loans to or from El Paso Energy Partners.
In addition, except for a nominal guarantee of lease obligations on behalf of a
subsidiary of El Paso Energy Partners, we have not provided any guarantees,
either monetary or performance, on behalf of or for the benefit of El Paso
Energy Partners nor do we have any other liabilities other than normal course of
business as a result of or arising out of our role as the general partner or
178
our ownership interest in El Paso Energy Partners. Our normal course of business
transactions with El Paso Energy Partners include sales of natural gas and
services, such as transportation and fractionation, storage, processing and
other types of operational services. These activities are based on the same
terms as our non-affiliates. Field Services recognized revenues of $1 million in
2002 and cost of sales of $97 million and $32 million in 2002 and 2001. Field
Services was also reimbursed $59 million, $34 million and $22 million in 2002,
2001 and 2000 for expenses incurred on behalf of the partnership. In addition,
Merchant Energy recognized revenues of $6 million, $28 million, and $14 million
in 2002, 2001 and 2000, and cost of sales of $80 million, $16 million, and $22
million in 2002, 2001 and 2000.
In 2001, as a result of our merger with Coastal, El Paso Energy Partners
sold its interest in several offshore assets including seven natural gas
pipeline systems, a dehydration facility and two offshore platforms. Proceeds
from these sales were approximately $135 million and resulted in a loss to the
partnership of approximately $25 million. As consideration for these sales, we
committed to pay El Paso Energy Partners a series of payments totaling $29
million, and were required to contribute $40 million to a trust related to one
of the assets sold by El Paso Energy Partners. These payments have been recorded
as merger-related costs.
In April 2002 and November 2002, we sold midstream assets to El Paso Energy
Partners for total consideration of $735 million and $766 million. See Note 3
for further discussion.
179
27. SUPPLEMENTAL SELECTED QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
Financial information by quarter is summarized below:
QUARTERS ENDED
-----------------------------------------------
DECEMBER 31 SEPTEMBER 30 JUNE 30 MARCH 31 TOTAL
----------- ------------ ------- -------- -----
(IN MILLIONS, EXCEPT PER COMMON SHARE AMOUNTS)
2002(1)
Operating revenues(2)....................... $ 1,169 $1,694 $1,821 $2,914 $ 7,598
Restructuring costs......................... 13 1 63 -- 77
(Gain) loss on long-lived assets............ 209 3 (12) (15) 185
Western Energy Settlement................... 899 -- -- -- 899
Ceiling test charges........................ 2 -- 234 33 269
Operating income (loss)(3).................. (1,336) 310 296 985 255
Income (loss) from continuing operations
before extraordinary items and cumulative
effect of accounting changes............. (1,298) 24 57 169 (1,048)
Discontinued operations, net of income
taxes.................................... (216) (93) (116) 60 (365)
Cumulative effect of accounting changes, net
of income taxes.......................... (222) -- 14 154 (54)
Net income (loss)........................... (1,736) (69) (45) 383 (1,467)
Basic earnings per common share
Income (loss) from continuing operations
before extraordinary items and
cumulative effect of accounting
changes................................ $ (2.19) $ 0.04 $ 0.11 $ 0.32 $ (1.87)
Discontinued operations, net of income
taxes.................................. (0.36) (0.16) (0.22) 0.12 (0.65)
Cumulative effect of accounting changes,
net of income taxes.................... (0.37) -- 0.03 0.29 (0.10)
------- ------ ------ ------ -------
Net income (loss)........................ $ (2.92) $(0.12) $(0.08) $ 0.73 $ (2.62)
======= ====== ====== ====== =======
Diluted earnings per common share
Income (loss) from continuing operations
before extraordinary items and
cumulative effect of accounting
changes................................ $ (2.19) $ 0.04 $ 0.11 $ 0.32 $ (1.87)
Discontinued operations, net of income
taxes.................................. (0.36) (0.16) (0.22) 0.11 (0.65)
Cumulative effect of accounting changes,
net of income taxes.................... (0.37) -- 0.03 0.29 (0.10)
------- ------ ------ ------ -------
Net income (loss)........................ $ (2.92) $(0.12) $(0.08) $ 0.72 $ (2.62)
======= ====== ====== ====== =======
---------------
(1) Our petroleum markets and coal mining operations are classified as
discontinued operations. See Note 10 for further discussion.
(2) Our operating revenues differ from those previously reported in our
September 30, 2002, June 30, 2002 and March 31, 2002 Form 10-Q's by $962
million, $1,166 million and $10,274 million due to income statement
reclassifications associated with our adoption of EITF Issue No. 02-3,
discontinued operations and other minor reclassifications, which had no
impact on previously reported net income or stockholders' equity.
(3) Our operating income (loss) differs from that previously reported in our
September 30, 2002, June 30, 2002 and March 31, 2002 Form 10-Q's by $99
million, $77 million and $360 million due to income statement
reclassifications associated with our discontinued operations,
reclassifications of gains and losses on asset sales and asset impairments
to operating income and other minor reclassifications which had no impact on
previously reported net income or stockholders' equity.
180
QUARTERS ENDED
-----------------------------------------------
DECEMBER 31 SEPTEMBER 30 JUNE 30 MARCH 31 TOTAL
----------- ------------ ------- -------- ------
(IN MILLIONS, EXCEPT PER COMMON SHARE AMOUNTS)
2001(1)
Operating revenues(2)........................ $2,004 $2,071 $2,347 $2,517 $8,939
Merger-related costs......................... (8) 27 464 1,010 1,493
Loss on long-lived assets.................... 16 7 12 42 77
Ceiling test charges......................... -- 135 -- -- 135
Operating income (loss)(3)................... 710 498 125 (190) 1,143
Income (loss) from continuing operations
before extraordinary items and cumulative
effect of accounting changes.............. 361 245 (82) (372) 152
Discontinued operations, net of income
taxes..................................... 14 (29) (52) (18) (85)
Extraordinary items, net of income taxes..... -- (5) 41 (10) 26
Net income (loss)............................ 375 211 (93) (400) 93
Basic earnings per common share
Income (loss) from continuing operations
before extraordinary items and
cumulative effect of accounting
changes................................. $ 0.71 $ 0.49 $(0.16) $(0.74) $ 0.30
Discontinued operations, net of income
taxes................................... 0.03 (0.06) (0.10) (0.04) (0.17)
Extraordinary items, net of income
taxes................................... -- (0.01) 0.08 (0.02) 0.05
------ ------ ------ ------ ------
Net income (loss)......................... $ 0.74 $ 0.42 $(0.18) $(0.80) $ 0.18
====== ====== ====== ====== ======
Diluted earnings per common share
Income (loss) from continuing operations
before extraordinary items and
cumulative effect of accounting
changes................................. $ 0.70 $ 0.47 $(0.16) $(0.74) $ 0.30
Discontinued operations, net of income
taxes................................... 0.02 (0.05) (0.10) (0.04) (0.17)
Extraordinary items, net of income
taxes................................... -- (0.01) 0.08 (0.02) 0.05
------ ------ ------ ------ ------
Net income (loss)......................... $ 0.72 $ 0.41 $(0.18) $(0.80) $ 0.18
====== ====== ====== ====== ======
---------------
(1) Our petroleum markets and coal mining operations are classified as
discontinued operations. See Note 10 for further discussion.
(2) Our operating revenues differ from those previously reported in our
September 30, 2001, June 30, 2001 and March 31, 2001 Form 10-Q's by $11,774
million, $11,016 million and $15,237 million due to income statement
reclassifications associated with our adoption of EITF Issue No. 02-3,
discontinued operations and other minor reclassifications, which had no
impact on previously reported net income or stockholders' equity.
(3) Our operating income (loss) differs from that previously reported in our
September 30, 2001, June 30, 2001 and March 31, 2001 Form 10-Q's by $18
million, $201 million and $22 million due to income statement
reclassifications associated with our discontinued operations,
reclassification of gains and losses on asset sales and asset impairments to
operating income and other minor reclassifications, which had no impact on
previously reported net income or stockholders' equity.
28. SUPPLEMENTAL NATURAL GAS AND OIL OPERATIONS (UNAUDITED)
At December 31, 2002, we had interests in natural gas and oil properties in
16 states and offshore operations and properties in federal and state waters in
the Gulf of Mexico. Internationally, we have a limited number of natural gas and
oil properties in Brazil, Canada, Hungary and Indonesia. We also have
exploration and production rights in Australia, Bolivia, Brazil, Canada,
Hungary, Indonesia and Turkey.
For purposes of the Supplemental Natural Gas and Oil Operations disclosure,
we have presented reserves, standardized measure of discounted future net cash
flows and the related changes in standardized measure separately for natural gas
systems operations which includes the regulated natural gas and oil properties
owned by Colorado Interstate Gas Company and its subsidiaries that were sold in
2002. The Supplemental Natural Gas and Oil Operations disclosure does not
include any value for natural gas systems storage gas and liquids volumes
managed by our Pipelines segment.
181
Capitalized costs relating to natural gas and oil producing activities and
related accumulated depreciation, depletion and amortization were as follows at
December 31 (in millions):
UNITED OTHER
STATES CANADA COUNTRIES(1) WORLDWIDE
------- ------ ------------ ---------
2002
Natural gas and oil properties:
Costs subject to amortization........... $13,283 $608 $ 92 $13,983
Costs not subject to amortization....... 594 177 103 874
------- ---- ---- -------
13,877 785 195 14,857
Less accumulated depreciation, depletion and
amortization............................... 7,002 435 44 7,481
------- ---- ---- -------
Net capitalized costs........................ $ 6,875 $350 $151 $ 7,376
======= ==== ==== =======
2001
Natural gas and oil properties:
Costs subject to amortization........... $12,933 $415 $ 72 $13,420
Costs not subject to amortization....... 629 250 49 928
------- ---- ---- -------
13,562 665 121 14,348
Less accumulated depreciation, depletion and
amortization............................... 6,956 170 31 7,157
------- ---- ---- -------
Net capitalized costs........................ $ 6,606 $495 $ 90 $ 7,191
======= ==== ==== =======
---------------
(1) Includes international operations in Brazil, Hungary and Indonesia.
182
Costs incurred in natural gas and oil producing activities, whether
capitalized or expensed, were as follows at December 31 (in millions):
UNITED OTHER
STATES CANADA COUNTRIES(1) WORLDWIDE
------ ------ ------------ ---------
2002
Property acquisition costs
Proved properties........................ $ 362 $ 6 $-- $ 368
Unproved properties...................... 29 7 10 46
Exploration costs........................... 246 70 45 361
Development costs........................... 1,520 80 3 1,603
------ ---- --- ------
Total costs incurred................ $2,157 $163 $58 $2,378
====== ==== === ======
2001
Property acquisition costs
Proved properties........................ $ 91 $232 $-- $ 323
Unproved properties...................... 44 16 25 85
Exploration costs........................... 177 19 58 254
Development costs........................... 1,529 105 14 1,648
------ ---- --- ------
Total costs incurred................ $1,841 $372 $97 $2,310
====== ==== === ======
2000
Property acquisition costs
Proved properties........................ $ 201 $ 3 $-- $ 204
Unproved properties...................... 171 6 -- 177
Exploration costs........................... 290 42 11 343
Development costs........................... 1,229 69 -- 1,298
------ ---- --- ------
Total costs incurred................ $1,891 $120 $11 $2,022
====== ==== === ======
---------------
(1) Includes international operations in Brazil, Hungary and Indonesia.
Per our January 1, 2003 reserve report, the amounts estimated to be spent
in 2003, 2004 and 2005 to develop our worldwide booked proved undeveloped
reserves are $570 million, $483 million and $178 million.
Presented below is an analysis of the capitalized costs of natural gas and
oil properties by year of expenditure that are not being amortized as of
December 31, 2002, pending determination of proved reserves. Capitalized
interest of $16 million, $18 million, and $7 million for the years ended
December 31, 2002, 2001 and 2000 is included in the presentation below (in
millions):
COSTS EXCLUDED FOR
CUMULATIVE YEARS ENDED CUMULATIVE
BALANCE DECEMBER 31, BALANCE
DECEMBER 31, ------------------ DECEMBER 31,
2002 2002 2001 2000 1999
------------ ---- ---- ---- ------------
Worldwide(1)
Acquisition............................ $406 $108 $149 $ 94 $55
Exploration............................ 255 177 33 36 9
Development............................ 213 69 95 26 23
---- ---- ---- ---- ---
$874 $354 $277 $156 $87
==== ==== ==== ==== ===
---------------
(1) Includes operations in the United States, Brazil, Canada, Hungary and
Indonesia.
Projects presently excluded from amortization are in various stages of
evaluation. The majority of these costs are expected to be included in the
amortization calculation in the years 2003 through 2006. Total amortization
expense per Mcfe, including ceiling test charges, was $1.71, $1.22, and $1.00 in
2002, 2001, and 2000. Excluding ceiling test charges, amortization expense would
have been $1.31, $1.04 and $1.00 per Mcfe
183
in 2002, 2001, and 2000. Depreciation, depletion, and amortization excludes
provisions for the impairment of international projects of $15 million in 2000.
All of our proved properties, with the exception of the proved reserves in
Brazil, Hungary and Indonesia, are located in North America (U.S. and Canada).
Net quantities of proved developed and undeveloped reserves of natural gas
and liquids, including condensate and crude oil, and changes in these reserves
are presented below. Information in this table is based on the reserve report
dated January 1, 2003, prepared internally by Production and reviewed by
Huddleston & Co., Inc. 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. These
reserves include 465,783 MMcfe of production delivery commitments under
financing arrangements that extend through 2042. The financing arrangement
supported by these reserves matures in 2006. Total proved reserves on the fields
with this dedicated production were 919,265 MMcfe. In addition, this table
excludes the following equity interests: Production's interest in UnoPaso
(Pescada in Brazil); Merchant Energy's interests in Sengkang in Indonesia; CAPSA
and CAPEX in Argentina and Aguaytia in Peru; interest in El Paso Energy
Partners. Combined proved natural gas reserves balances for these equity
interests were 435,713 MMcf, liquids reserves were 39,693 MBbls, and natural gas
equivalents were 673,871 MMcfe, all net to our ownership interests.
NATURAL GAS (IN BCF)
-------------------------------------------------------
NATURAL
UNITED OTHER GAS
STATES CANADA COUNTRIES(1) WORLDWIDE SYSTEMS(2)
------ ------ ------------ --------- ----------
Net proved developed and undeveloped
reserves(3)
January 1, 2000............................ 4,540 73 -- 4,613 198
Revisions of previous estimates......... (249) (62) -- (311) 11
Extensions, discoveries and other....... 1,239 155 91 1,485 --
Purchases of reserves in place.......... 577 2 -- 579 --
Sales of reserves in place.............. (19) -- -- (19) --
Production.............................. (516) (1) -- (517) (33)
------ ---- ----- ------ ----
---------------
(1) Includes international operations in Brazil, Hungary and Indonesia.
(2) Includes natural gas and oil properties owned by Colorado Interstate Gas
Company and its subsidiaries that were sold in 2002.
(3) Net proved reserves exclude royalties and interests owned by others and
reflects contractual arrangements and royalty obligations in effect at the
time of the estimate.
184
NATURAL GAS (IN BCF)
-------------------------------------------------------
NATURAL
UNITED OTHER GAS
STATES CANADA COUNTRIES(1) WORLDWIDE SYSTEMS(2)
------ ------ ------------ --------- ----------
December 31, 2000.......................... 5,572 167 91 5,830 176
Revisions of previous estimates......... (874) (136) (51) (1,061) 42
Extensions, discoveries and other....... 1,244 85 -- 1,329 --
Purchases of reserves in place.......... 116 83 -- 199 --
Sales of reserves in place.............. (46) -- -- (46) --
Production.............................. (552) (13) -- (565) (35)
------ ---- ----- ------ ----
December 31, 2001.......................... 5,460 186 40 5,686 183
Revisions of previous estimates......... (392) (70) 31 (431) --
Extensions, discoveries and other....... 766 56 5 827 --
Purchases of reserves in place.......... 513 5 -- 518 --
Sales of reserves in place.............. (1,664) (30) -- (1,694) (183)
Production.............................. (470) (17) -- (487) --
------ ---- ----- ------ ----
December 31, 2002.......................... 4,213 130 76 4,419 --
====== ==== ===== ====== ====
Proved developed reserves
December 31, 2000....................... 2,877 112 -- 2,989 176
December 31, 2001....................... 2,967 138 -- 3,105 183
December 31, 2002....................... 2,684 104 -- 2,788 --
---------------
(1) Includes international operations in Brazil, Hungary and Indonesia.
(2) Includes natural gas and oil properties owned by Colorado Interstate Gas
Company and its subsidiaries that were sold in 2002.
185
LIQUIDS(1) (IN MBBLS)
--------------------------------------------------------
NATURAL
UNITED OTHER GAS
STATES CANADA COUNTRIES(2) WORLDWIDE SYSTEMS(3)
------- ------ ------------ --------- ----------
Net proved developed and undeveloped reserves(4)
January 1, 2000............................... 87,316 867 -- 88,183 249
Revisions of previous estimates............ (576) (544) -- (1,120) 7
Extensions, discoveries and other.......... 13,196 3,600 4,862 21,658 --
Purchases of reserves in place............. 7,589 13 -- 7,602 --
Sales of reserves in place................. (609) -- -- (609) --
Production................................. (11,614) (13) -- (11,627) (25)
------- ------ ------ ------- ----
December 31, 2000............................. 95,302 3,923 4,862 104,087 231
Revisions of previous estimates............ 26,085 (4,224) (4,862) 16,999 (118)
Extensions, discoveries and other.......... 38,536 1,173 7,771 47,480 --
Purchases of reserves in place............. 132 10,570 -- 10,702 --
Sales of reserves in place................. (71) -- -- (71) --
Production................................. (13,821) (560) -- (14,381) (16)
------- ------ ------ ------- ----
December 31, 2001............................. 146,163 10,882 7,771 164,816 97
Revisions of previous estimates............ (13,496) (1,798) (5,660) (20,954) --
Extensions, discoveries and other.......... 17,567 282 10,541 28,390 --
Purchases of reserves in place............. 1,521 362 -- 1,883 --
Sales of reserves in place................. (18,566) (2,535) -- (21,101) (97)
Production................................. (16,460) (1,053) -- (17,513) --
------- ------ ------ ------- ----
December 31, 2002............................. 116,729 6,140 12,652 135,521 --
======= ====== ====== ======= ====
---------------
(1) Includes oil, condensate and natural gas liquids.
(2) Includes international operations in Brazil, Hungary and Indonesia.
(3) Includes natural gas and oil properties owned by Colorado Interstate Gas
Company and its subsidiaries that were sold in 2002.
(4) Net proved reserves exclude royalties and interests owned by others and
reflects contractual arrangements and royalty obligations in effect at the
time of the estimate.
LIQUIDS(1) (IN MBBLS)
--------------------------------------------------------
NATURAL
UNITED OTHER GAS
STATES CANADA COUNTRIES(2) WORLDWIDE SYSTEMS(3)
------- ------ ------------ --------- ----------
Proved developed reserves
December 31, 2000.......................... 55,044 2,723 -- 57,767 231
December 31, 2001.......................... 92,060 7,341 -- 99,401 97
December 31, 2002.......................... 70,805 4,445 -- 75,250 --
---------------
(1) Includes oil, condensate and natural gas liquids.
(2) Includes international operations in Brazil, Hungary and Indonesia.
(3) Includes natural gas and oil properties owned by Colorado Interstate Gas
Company and its subsidiaries that were sold in 2002.
There are numerous uncertainties inherent in estimating quantities of
proved reserves and in projecting future rates of production and timing of
development expenditures, including many factors beyond our control. The reserve
data represents only estimates. Reservoir engineering is a subjective process of
estimating underground accumulations of natural gas and oil that cannot be
measured in an exact manner.
The significant changes to reserves, other than purchases, sales or
production, are due to reservoir performance in existing fields and from
drilling additional wells in existing fields. There have been no major
discoveries or other events, favorable or adverse, that may be considered to
have caused a significant change in the estimated proved reserves since December
31, 2002.
186
Results of operations from producing activities by fiscal year were as
follows at December 31 (in millions):
UNITED OTHER
STATES CANADA COUNTRIES(1) WORLDWIDE
------ ------ ------------ ---------
2002
Net Revenues
Sales to external customers................. $ 339 $ 47 $ -- $ 386
Affiliated sales............................ 1,595 20 -- 1,615
------ ----- ---- ------
Total............................... 1,934 67 -- 2,001
Production costs(2)........................... (284) (18) (1) (303)
Depreciation, depletion and amortization...... (748) (28) -- (776)
Ceiling test charges.......................... -- (226) (10) (236)
------ ----- ---- ------
902 (205) (11) 686
Income tax (expense) benefit.................. (307) 83 4 (220)
------ ----- ---- ------
Results of operations from producing
activities.................................. $ 595 $(122) $ (7) $ 466
====== ===== ==== ======
2001
Net Revenues
Sales to external customers................. $ 139 $ 45 $ -- $ 184
Affiliated sales............................ 2,259 1 -- 2,260
------ ----- ---- ------
Total............................... 2,398 46 -- 2,444
Production costs(2)........................... (323) (12) -- (335)
Depreciation, depletion and amortization...... (660) (17) -- (677)
Ceiling test charges.......................... -- (87) (28) (115)
------ ----- ---- ------
1,415 (70) (28) 1,317
Income tax (expense) benefit.................. (490) 25 (9) (474)
------ ----- ---- ------
Results of operations from producing
activities.................................. $ 925 $ (45) $(37) $ 843
====== ===== ==== ======
---------------
(1) Includes international operations in Brazil, Hungary and Indonesia.
(2) Production costs include direct lifting costs (labor, repairs and
maintenance, materials and supplies) and the administrative costs of field
offices, insurance and property and severance taxes.
UNITED OTHER
STATES CANADA COUNTRIES(1) WORLDWIDE
------ ------ ------------ ---------
2000
Net Revenues
Sales to external customers................. $1,165 $ 6 $ -- $1,171
Affiliated sales............................ 438 -- -- 438
------ --- ----- ------
Total............................... 1,603 6 -- 1,609
Production costs(2)........................... (310) (1) -- (311)
Depreciation, depletion and amortization...... (584) (1) -- (585)
------ --- ----- ------
709 4 -- 713
Income tax expense............................ (237) (2) -- (239)
------ --- ----- ------
Results of operations from producing
activities.................................. $ 472 $ 2 $ -- $ 474
====== === ===== ======
---------------
(1) Includes international operations in Brazil, Hungary and Indonesia.
(2) Production costs include direct lifting costs (labor, repairs and
maintenance, materials and supplies) and the administrative costs of field
offices, insurance and property and severance taxes.
187
The standardized measure of discounted future net cash flows relating to
proved natural gas and oil reserves follows at December 31 (in millions):
NATURAL
UNITED OTHER GAS
STATES CANADA COUNTRIES(1) WORLDWIDE SYSTEMS(2)
------- ------ ------------ --------- ----------
2002
Future cash inflows(3)............ $21,948 $ 671 $ 542 $23,161 $ --
Future production costs........... (3,822) (127) (124) (4,073) --
Future development costs.......... (1,922) (16) (133) (2,071) --
Future income tax expenses........ (4,541) (21) (50) (4,612) --
------- ----- ----- ------- -----
Future net cash flows............. 11,663 507 235 12,405 --
10% annual discount for estimated
timing of cash flows............ (4,969) (220) (127) (5,316) --
------- ----- ----- ------- -----
Standardized measure of discounted
future net cash flows........... $ 6,694 $ 287 $ 108 $ 7,089 $ --
======= ===== ===== ======= =====
Standardized measure of discounted
future net cash flows, including
effects of hedging activities... $ 6,310 $ 287 $ 108 $ 6,705 $ --
======= ===== ===== ======= =====
---------------
(1) Includes international operations in Brazil, Hungary and Indonesia.
(2) Includes natural gas and oil properties owned by Colorado Interstate Gas
Company and its subsidiaries that were sold in 2002.
(3) Excludes $708 million of future net cash outflows attributable to hedging
activities.
NATURAL
UNITED OTHER GAS
STATES CANADA COUNTRIES(1) WORLDWIDE SYSTEMS(2)
-------- ------ ------------ --------- ----------
2001
Future cash inflows(3)........... $ 15,832 $ 641 $ 253 $ 16,726 $ 313
Future production costs.......... (3,284) (196) (51) (3,531) (34)
Future development costs......... (2,067) (83) (73) (2,223) (30)
Future income tax expenses....... (2,228) (8) (23) (2,259) (83)
-------- ------ ----- -------- -----
Future net cash flows............ 8,253 354 106 8,713 166
10% annual discount for estimated
timing of cash flows........... (3,453) (143) (52) (3,648) (72)
-------- ------ ----- -------- -----
Standardized measure of
discounted future net cash
flows.......................... $ 4,800 $ 211 $ 54 $ 5,065 $ 94
======== ====== ===== ======== =====
Standardized measure of
discounted future net cash
flows, including effects of
hedging activities............. $ 5,369 $ 211 $ 54 $ 5,634 $ 94
188
NATURAL
UNITED OTHER GAS
STATES CANADA COUNTRIES(1) WORLDWIDE SYSTEMS(2)
-------- ------ ------------ --------- ----------
2000
Future cash inflow(4)............ $ 44,459 $1,597 $ 397 $ 46,453 $ 474
Future production costs.......... (5,451) (136) (70) (5,657) (59)
Future development costs......... (1,743) (35) (139) (1,917) (51)
Future income tax expenses....... (11,885) (599) (60) (12,544) (116)
-------- ------ ----- -------- -----
Future net cash flows............ 25,380 827 128 26,335 248
10% annual discount for estimated
timing of cash flows........... (10,392) (469) (109) (10,970) (89)
-------- ------ ----- -------- -----
Standardized measure of
discounted future net cash
flows.......................... $ 14,988 $ 358 $ 19 $ 15,365 $ 159
======== ====== ===== ======== =====
Standardized measure of
discounted future net cash
flows, including effects of
hedging activities............. $ 13,839 $ 358 $ 19 $ 14,216 $ 159
======== ====== ===== ======== =====
---------------
(1) Includes international operations in Brazil, Hungary and Indonesia.
(2) Includes natural gas and oil properties owned by Colorado Interstate Gas
Company and its subsidiaries that were sold in 2002.
(3) Excludes $973 million of future net cash inflows attributable to hedging
activities.
(4) Excludes $1,995 million of future net cash outflows attributable to hedging
activities.
For the calculations in the preceding table, estimated future cash inflows
from estimated future production of proved reserves were computed using year-end
market natural gas and oil prices. We may receive amounts different than the
standardized measure of discounted cash flow for a number of reasons, including
price changes and the effects of our hedging activities.
We do not rely upon the standardized measure when making investment and
operating decisions. These decisions are based on various factors including
probable and proved reserves, different price and cost assumptions, actual
economic conditions, capital availability and corporate investment criteria.
189
The following are the principal sources of change in the standardized
measure of discounted future net cash flows (in millions):
YEARS ENDED DECEMBER 31,(1)
----------------------------------------------------------------
2002 2001 2000
------------- ------------------------ ---------------------
EXPLORATION EXPLORATION NATURAL EXPLORATION NATURAL
AND AND GAS AND GAS
PRODUCTION(2) PRODUCTION SYSTEMS(3) PRODUCTION SYSTEMS
------------- ----------- ---------- ----------- -------
Sales and transfers of natural gas
and oil produced net of production
costs.............................. $(1,697) $ (2,108) $(255) $(1,748) $(52)
Net changes in prices and production
costs.............................. 6,524 (16,115) 10 12,095 150
Extensions, discoveries and improved
recovery, less related costs....... 1,660 1,338 -- 5,938 --
Changes in estimated future
development costs.................. (199) (17) 13 (422) --
Previously estimated development
costs incurred during the period... 499 503 -- 263 --
Revisions of previous quantity
estimates.......................... (1,139) (866) 39 (976) 34
Accretion of discount................ 613 2,208 23 347 4
Net change in income taxes........... (1,413) 5,642 25 (6,009) (42)
Purchases of reserves in place....... 1,015 232 -- 1,735 --
Sales of reserves in place........... (3,328) 16 -- (14) --
Change in production rates, timing
and other.......................... (511) (1,133) 80 151 --
------- -------- ----- ------- ----
Net change......................... $ 2,024 $(10,300) $ (65) $11,360 $ 94
======= ======== ===== ======= ====
---------------
(1) This disclosure reflects changes in the standardized measure calculation
excluding the effects of hedging activities.
(2) Includes operations in the United States, Canada, Brazil, Hungary and
Indonesia.
(3) Includes natural gas and oil properties owned by Colorado Interstate Gas
Company and its subsidiaries that were sold in 2002.
190
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors and Stockholders of
El Paso Corporation:
In our opinion, based upon our audits and the report of other auditors, the
accompanying consolidated balance sheets and related consolidated statements of
income, comprehensive income, stockholders' equity and cash flows present
fairly, in all material respects, the consolidated financial position of El Paso
Corporation and its subsidiaries (the "Company") at December 31, 2002 and 2001,
and the consolidated results of their operations and their cash flows for each
of the three years in the period ended December 31, 2002 in conformity with
accounting principles generally accepted in the United States of America. In
addition, in our opinion, based on our audits and the report of other auditors,
the financial statement schedule 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 financial
statement schedule of valuation and qualifying accounts are the responsibility
of the Company's management; our responsibility is to express an opinion on
these financial statements and financial statement schedule based on our audits.
The consolidated financial statements and financial statement schedule give
retroactive effect to the merger of El Paso CGP Company (formerly The Coastal
Corporation) on January 29, 2001 in a transaction accounted for as a pooling of
interests, as described in Note 3 to the consolidated financial statements. We
did not audit the consolidated financial statements and financial statement
schedule of El Paso CGP Company as of December 31, 2000 and for the year then
ended, which statements reflect total revenues of $3,533 million for the year
ended December 31, 2000. Those statements were audited by other auditors whose
report thereon has been furnished to us, and our opinion expressed herein,
insofar as it relates to the amounts included for El Paso CGP Company as of
December 31, 2000 and for the year then ended, is based solely on the report of
the other auditors. We conducted our audits of these statements in accordance
with auditing standards generally accepted in the United States of America,
which require that we plan and perform the audit to obtain reasonable assurance
about whether the financial statements are free of material misstatement. An
audit includes examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements, assessing the accounting principles
used and significant estimates made by management, and evaluating the overall
financial statement presentation. We believe that our audits and the report of
other auditors provide a reasonable basis for our opinion.
As discussed in Notes 1 and 6, the Company adopted Statement of Financial
Accounting Standards No. 142, Goodwill and Other Intangible Assets and Statement
of Financial Accounting Standards No. 144, Accounting for the Impairment or
Disposal of Long-Lived Assets on January 1, 2002; DIG Issue No. C-16, Scope
Exceptions: Applying the Normal Purchases and Sales Exception to Contracts that
Combine a Forward Contract and Purchased Option Contract in the second quarter
of 2002, and EITF Issue No. 02-3, Accounting for Contracts Involved in Energy
Trading and Risk Management Activities, Consensus 1 and 2, in the third and
fourth quarter of 2002; respectively.
As discussed in Notes 1 and 13, the Company adopted Statement of Financial
Accounting Standards, No. 133, Accounting for Derivatives and Hedging
Activities, on January 1, 2001.
/s/ PRICEWATERHOUSECOOPERS LLP
Houston, Texas
March 28, 2003, except as to the reclassification of the petroleum markets
business as discontinued operations discussed in Note 10 as to which the date is
September 12, 2003.
191
INDEPENDENT AUDITORS' REPORT
Board of Directors and Stockholders
El Paso CGP Company
Houston, Texas
We have audited the consolidated statements of income, stockholders'
equity, cash flows and comprehensive income of El Paso CGP Company (formerly The
Coastal Corporation) and subsidiaries, for the year ended December 31, 2000 (not
presented separately herein). Our audit also included the El Paso CGP schedule
of valuation and qualifying accounts for the year ended December 31, 2000 (not
presented separately herein). These financial statements and financial statement
schedule are the responsibility of the Company's management. Our responsibility
is to express an opinion on these financial statements based on our audit.
We conducted our audit in accordance with auditing standards generally
accepted in the United States of America. Those standards 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. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audit provides a
reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in
all material respects, El Paso CGP Company's results of operations and cash
flows for the year ended December 31, 2000, in conformity with accounting
principles generally accepted in the United States of America. Also, in our
opinion, such financial statement schedule, when considered in relation to the
basic consolidated financial statements taken as a whole, presents fairly in all
material respects the information set forth therein.
/s/ DELOITTE & TOUCHE LLP
Houston, Texas
March 19, 2001
(March 28, 2003 as to the effects of reclassifications related to the adoption
of net reporting for trading activities and accounting for coal mining
operations as discontinued operations as discussed in notes 1 and 9,
respectively, and September 23, 2003 as to the effects of reclassifications
related to accounting for petroleum operations as discontinued operations as
discussed in note 9)
192
SCHEDULE II
EL PASO CORPORATION
VALUATION AND QUALIFYING ACCOUNTS
YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000
(IN MILLIONS)
CHARGED
BALANCE AT TO COSTS CHARGED BALANCE
BEGINNING AND TO OTHER AT END
DESCRIPTION OF PERIOD EXPENSES ACCOUNTS DEDUCTIONS OF PERIOD
----------- ---------- -------- -------- ---------- ---------
2002
Allowance for doubtful accounts(10)... $117 $ 30 $ 43 $(14) $ 176
Valuation allowance on deferred tax
assets............................. 3 36 -- (2) 37
Legal reserves(10).................... 149 936 (1) -- (74)(2) 1,011
Environmental reserves(10)............ 468 (18) (14) (63)(3) 373
Regulatory reserves................... 34 48 1 (59)(4) 24
2001
Allowance for doubtful accounts(10)... $ 48 $ 77 $ (1) $ (7)(5) $ 117
Valuation allowance on deferred tax
assets............................. 3 -- -- -- 3
Legal reserves(10).................... 259 43 (123)(6) (30) 149
Environmental reserves(10)............ 303 156 (7) 30 (21) 468
Regulatory reserves................... 48 (1) (11) (2) 34
2000
Allowance for doubtful accounts(10)... $ 56 $ 16 $ (17) $ (7)(5) $ 48
Valuation allowance on deferred tax
assets............................. 6 -- -- (3) 3
Legal reserves(10).................... 70 (17) 210 (9) (4) 259
Environmental reserves(10)............ 276 51 1 (25) 303
Regulatory reserves................... 95 (2) -- (45) 48
---------------
(1) Relates to our Western Energy Settlement of $899 million
(2) Payments for various litigation reserves.
(3) Payments for various environmental remediation reserves.
(4) Payments for revenue crediting and rate settlement reserves.
(5) Primarily accounts written off.
(6) In 2001, we finalized our purchase price adjustment for the legal reserves
related to our PG&E acquisition.
(7) Of this amount, $232 million relates to additional environmental
remediation liabilities recorded in connection with the events described in
Note 20.
(8) We accrued $23 million in 2001 and reversed $24 million of reserves for the
Corpus Christi refinery leased to Valero in June.
(9) Of this amount, $53 million was the legal reserve we acquired in connection
with our purchase of PG&E's Texas Midstream operations. We recorded an
additional $159 million for legal reserves, related to purchase price
adjustments on our PG&E acquisition.
(10) Excludes amounts related to our discontinued petroleum markets and coal
mining operations.
193
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
EL PASO CORPORATION
By: /s/ JEFFERY I. BEASON
------------------------------------
Jeffery I. Beason
Senior Vice President and Controller
(Principal Accounting Officer)
Date: September 23, 2003
194
EXHIBIT INDEX
EXHIBIT
NUMBER DESCRIPTION
------- -----------
23.A Consent of Independent Accountants, PricewaterhouseCoopers
LLP.
23.B Consent of Independent Auditors, Deloitte & Touche LLP.