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Compensation Plan
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8: EX-21 Subsidiaries of El Paso Corporation HTML 385K
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Securities registered pursuant to Section 12(b) of
the Act:
Name of Each Exchange
Title of Each Class
on which Registered
Common Stock, par value $3 per share
New York Stock Exchange
Securities registered pursuant to Section 12(g) of
the Act: None
Indicate by check mark if the registrant
is a well-known seasoned issuer, as defined in Rule 405 of
the Securities Act.
Yes þ No o.
Indicate by check mark if the registrant
is not required to file reports pursuant to Section 13 or
Section 15(d) of the
Act. Yes o No þ.
Indicate by check mark whether the
registrant (1) has filed all reports required to be filed by
Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter
period that the registrant was required to file such
reports), and (2) has been subject to such filing
requirements for the past 90 days.
Yes þ No o.
Indicate by check mark if disclosure of
delinquent filers pursuant to Item 405 of
Regulation S-K is
not contained herein, and will not be contained, to the best of
registrant’s knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this
Form 10-K or any
amendment to this
Form 10-K. þ
Indicate by check mark whether the
registrant is a large accelerated filer, an accelerated filer,
or a non-accelerated filer. See definition of “accelerated
filer and large accelerated filer” in Rule 12b-2 of
the Exchange Act. (Check one):
Large accelerated filer þ
Accelerated filer o
Non-accelerated filer o
Indicate by check mark whether the
registrant is a shell company (as defined in Rule 12b-2 of the
Exchange Act).
Yes o No þ.
State the aggregate market value of
the voting and non-voting common equity held by non-affiliates
of the registrant.
Aggregate market value of the
voting stock (which consists solely of shares of common stock)
held by non-affiliates of the registrant as of June 30,2005 computed by reference to the closing sale price of the
registrant’s common stock on the New York Stock
Exchange on such date: $7,594,102,633.
Indicate the number of shares
outstanding of each of the registrant’s classes of common
stock, as of the latest practicable date.
Common Stock, par value
$3 per share. Shares outstanding on February 24, 2006:
659,210,298
List hereunder the following
documents if incorporated by reference and the part of the
Form 10-K (e.g.,
Part I, Part II, etc.) into which the document is
incorporated: Portions of our definitive proxy statement for the
2006 Annual Meeting of Stockholders are incorporated by
reference into Part III of this report. These will be filed
no later than April 30, 2006.
Below is a list of terms that are common to our industry and
used throughout this document:
/d
= per day
Bbl
= barrel
BBtu
= billion British thermal units
Bcf
= billion cubic feet
Bcfe
= billion cubic feet of natural gas equivalents
LNG
= liquefied natural gas
MBbls
= thousand barrels
Mcf
= thousand cubic feet
Mcfe
= thousand cubic feet of natural gas equivalents
MDth
= thousand dekatherms
MMBtu
= million British thermal units
MMcf
= million cubic feet
MMcfe
= million cubic feet of natural gas equivalents
MMWh
= thousand megawatt hours
MW
= megawatt
NGL
= natural gas liquids
TBtu
= trillion British thermal units
Tcfe
= trillion cubic feet of natural gas equivalents
When we refer to natural gas and oil in “equivalents,”
we are doing so to compare quantities of oil with quantities of
natural gas or to express these different commodities in a
common unit. In calculating equivalents, we use a generally
recognized standard in which one Bbl of oil is equal to six Mcf
of natural gas. 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”, “the Company”, or
“El Paso”, we are describing El Paso
Corporation and/or our subsidiaries.
We are an energy company, originally founded in 1928 in
El Paso, Texas, with a stated purpose to provide natural
gas and related energy products in a safe, efficient and
dependable manner. Our long-term business strategy is focused on
participating in the energy industry through a rate regulated
natural gas transmission business in North America and a large,
independent exploration and production business operating both
domestically and internationally.
Natural Gas Transmission. We own North America’s
largest interstate pipeline system, which has approximately
55,500 miles of pipe that connect North America’s
major producing basins to its major consuming markets. We also
own approximately 420 Bcf of storage capacity and an LNG
import facility with 806 MMcf of daily base load sendout
capacity.
Exploration and Production. Our exploration and
production business is focused on the exploration for and the
acquisition, development and production of natural gas, oil and
NGL in the United States and Brazil and related marketing
activities. As of December 31, 2005, we held an estimated
2.4 Tcfe of proved natural gas and oil reserves in the
United States and Brazil, exclusive of our equity share in the
proved reserves of an unconsolidated affiliate of 253 Bcfe.
Other. We currently own or have owned other non-core
assets acquired as part of a number of mergers and acquisitions
and growth initiatives when we expanded from a regional gas
pipeline company in the
mid-1990’s to an
international energy company by early 2001. Since 2003, a
substantial portion of these assets have been sold, have pending
sales contracts or are in the process of being sold. The
divestiture of these assets was targeted at improving our
operating results, financial condition and liquidity, which were
negatively impacted by the decline of the energy trading
industry, bankruptcy of several energy industry participants and
our credit downgrades.
Business Objective and Strategy
As of December 31, 2005, we conduct our core natural gas
transmission and exploration and production operations through
our Pipelines, Exploration and Production and Marketing and
Trading segments. We also have Power and Field Services
segments. Our business segments provide a variety of energy
products and services and are managed separately as each segment
requires different technology and marketing strategies. For
further discussion of our business segments, see the information
below and in Part II, Item 7, Management’s
Discussion and Analysis of Financial Condition and Results of
Operations. For our segment operating results and assets, see
Part II, Item 8, Financial Statements and
Supplementary Data, Note 20, which is incorporated herein
by reference. Our business strategy in each of our operating
segments can be summarized as follows:
Pipelines
Enhancing the value of our transmission business through
successful recontracting, continuous efficiency improvements
through cost management and prudent capital spending in the
United States and Mexico, while providing outstanding
customer service through safe operations.
Exploration and Production
Growing our reserve base in a manner that creates shareholder
value through disciplined capital allocation, cost control and
portfolio management.
Marketing and Trading
Marketing our natural gas and oil production at optimal prices
and managing associated price risks.
The assets remaining in our Power segment are used to serve
customers under long-term power sales contracts or sell power to
the open market in spot market transactions. Additionally,
through the remaining assets in our Field Services segment, we
provide processing and gathering services through two facilities
that support our Rocky Mountain production activities.
Our Pipelines segment provides natural gas transmission and
related services through eight separate, wholly owned pipeline
systems and four 50 percent owned systems that, combined, own or
have interests in approximately 55,500 miles of interstate
natural gas pipelines, representing the largest integrated
natural gas transmission system in the United States. Our system
connects the nation’s principal natural gas supply regions
to the six largest consuming regions in the United States: the
Gulf Coast, California, the northeast, the midwest, the
southwest and the southeast. Our pipeline operations include
access to systems in Canada and assets in Mexico. The size,
connectivity and diversity of our U.S. pipeline system
provides growth opportunities through infrastructure development
or large scale expansion projects and gives us the capability to
adapt to the dynamics of shifting supply and demand.
We also own or have interests in approximately 420 Bcf of
storage capacity through our wholly owned transmission systems
and two wholly owned and three partially owned storage systems
used to provide a variety of flexible services to our customers.
We also have one LNG receiving terminal and related facilities
at Elba Island, Georgia.
Each of our U.S. pipeline systems and storage facilities operate
under Federal Energy Regulatory Commission (FERC) approved
tariffs that establish rates, cost recovery mechanisms, terms
and conditions of service to our customers. The fees or rates
established under our tariffs are a function of our costs of
providing services to our customers, including a reasonable
return on our invested capital. Our revenues from
transportation, storage, LNG terminalling and related services
consist of two types of revenues:
Reservation revenues. Reservation revenues are from
customers (referred to as firm customers) that reserve capacity
on our pipeline system, storage facilities or LNG terminalling
facilities. These firm customers are obligated to pay a monthly
reservation or demand charge, regardless of the amount of
natural gas they transport or store, for the term of their
contracts.
Usage revenues. Usage revenues are from both firm
customers and interruptible customers (those without reserved
capacity) that pay usage charges based on the volume of gas
actually transported, stored, injected or withdrawn.
In 2005, approximately 79 percent of our revenues were
attributable to reservation charges paid by firm customers. The
remaining 21 percent of our revenues were variable. Because
of our regulated nature and the
high percentage of our revenues attributable to reservation
charges, our revenues have historically been relatively stable.
However, our financial results can be subject to volatility due
to factors such as changes in natural gas prices and market
conditions, regulatory actions, competition, weather and the
creditworthiness of our customers. We also experience volatility
when the amounts of natural gas utilized in our operations
differ from the amounts we recover from our customers for that
purpose.
Our strategy is to enhance the value of our transmission
business through:
•
Seeking to expand our systems by attracting new customers,
markets or supply sources while leveraging our existing assets
to the extent possible;
•
Recontracting or contracting available or expiring capacity and
resolving open rate cases;
•
Focusing on efficiency in our operations and cost control,
including efficiencies that may be available across our systems
or due to the
coast-to-coast scale of
our operations;
•
Investing in maintenance and pipeline integrity projects to
maintain the value and ensure the safety of our pipeline systems
and assets;
•
Providing outstanding customer service; and
•
Providing natural gas transmission and related services through
safe operations.
Wholly Owned Interstate Transmission Systems
Below is a further discussion of our wholly owned pipeline
systems.
Extends from Louisiana, the Gulf of Mexico and south Texas to
the northeast section of the U.S., including the metropolitan
areas of New York City and Boston.
14,100
6,876
90
4,443
4,469
4,710
ANR Pipeline (ANR)
Extends from Louisiana, 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.
10,500
6,775
192
4,100
4,067
4,232
El Paso Natural Gas (EPNG)
Extends from the San Juan, Permian and Anadarko basins to
California, its single largest market, as well as markets in
Arizona, Nevada, New Mexico, Oklahoma, Texas and northern Mexico.
10,700
5,650
(2)
—
(3)
4,053
4,074
3,874
Southern Natural Gas (SNG)
Extends from natural gas fields in Texas, Louisiana,
Mississippi, Alabama and the Gulf of Mexico to markets in
Louisiana, Mississippi, Alabama, Florida, Georgia, South
Carolina and Tennessee, including the metropolitan areas of
Atlanta and Birmingham.
7,700
3,450
60
1,984
2,163
2,101
Colorado Interstate Gas (CIG)
Extends from production areas in the Rocky Mountain region and
the Anadarko Basin to the front range of the Rocky Mountains and
multiple interconnections with pipeline systems transporting gas
to the midwest, the southwest, California and the Pacific
northwest.
Extends from western Wyoming and the Powder River Basin to
various pipeline interconnections near Cheyenne, Wyoming.
600
1,997
—
1,479
1,201
1,213
Mojave Pipeline (MPC)
Connects with the EPNG system near Cadiz, California, the EPNG
and Transwestern systems at Topock, Arizona and to the Kern
River Gas Transmission Company system in California. This system
also extends to customers in the vicinity of Bakersfield,
California.
400
407
—
161
161
192
Cheyenne Plains Gas Pipeline (CPG)
Extends from the Cheyenne hub in Colorado to various pipeline
interconnections near Greensburg, Kansas.
400
757
—
433
89
—
(1)
Includes throughput transported on behalf of affiliates.
(2)
This capacity reflects winter-sustainable west-flow capacity of
4,850 MMcf/d and approximately 800 MMcf/d of east-end
delivery capacity.
(3)
Effective January 1, 2006, EPNG began offering
interruptible storage service from a storage facility that has a
maximum working capacity of up to approximately 44 Bcf.
We also have a number of pipeline expansion projects underway as
of December 31, 2005, which are in various stages of
certification and approval. Below are the more significant
projects that have been approved by the FERC:
Anticipated
Project
Capacity
Description
Completion Date
(MMcf/d)
ANR
Wisconsin 2006 expansion
164
To construct and operate a 3.8 mile, 30-inch pipeline extension
of the Madison Lateral Loop, a 3.1 mile, 16-inch pipeline
loop(1)
of the Little Chute Lateral in Outagamie County, a 20,620
horsepower compressor station, a 2,370 horsepower compressor
unit at the Janesville compressor station, and upgrades of five
existing meter stations in various counties in Wisconsin.
November 2006
TGP
Triple-T expansion
200
To construct 6.2 miles of 24-inch pipeline to extend its
existing 30-inch Triple-T Line, beginning in Eugene Island
Block 349, to interconnect with Enterprise Products
Partners’ Anaconda System on the EI 371 platform,
as well as associated piping and other appurtenant facilities.
August 2006
Northeast ConneXion-NY/NJ
49
To modify an existing dehydration tower, filed jointly with
National Fuel, serving the Hebron Storage Field in Potter
County, Pennsylvania, expand capacity on Line 300, located
in Bradford and Susquehanna Counties, Pennsylvania by building
6 miles of
loop(1)
line, add compression facilities at Compressor Station 313
in Potter County, Pennsylvania, and at Station 317 in Bradford
County, Pennsylvania, upgrade Ramsey Meter Station in Bergen
County, New Jersey, and use additional incremental capacity
resulting from the replacement of compression facilities at
Station 325 in Sussex County, New Jersey.
November 2006
Louisiana Deepwater Link
850
To construct a 300 foot extension of its 20-inch Grand Isle
supply lateral, construct 2,100 feet of 24-inch West Delta
supply lateral, abandon 3,100 feet of the 20-inch line
connected to the Grand Isle platform, and install appurtenant
facilities on Enterprise’s Independence Hub platform
located in Mississippi Canyon Block 920.
October 2006
WIC
Piceance Basin expansion
333
To construct and operate approximately 142 miles of 24-inch
pipeline, compression and metering facilities to move additional
supplies into the WIC system.
March 2006
(1)
A loop is the installation of a pipeline, parallel to an
existing pipeline, with
tie-ins at several
points along the existing pipeline. Looping increases a
transmission system’s capacity.
Extends from the Manitoba-Minnesota border to the
Michigan-Ontario border at St. Clair, Michigan.
50
2,115
2,500
2,376
2,200
2,366
Samalayuca Pipeline and Gloria a Dios Compression Station
Extends from U.S.-Mexico border to the State of Chihuahua,
Mexico.
50
23
460
423
433
409
San Fernando Pipeline
Extends from Pemex Compression Station 19 to the Pemex metering
station in San Fernando, Mexico in the State of Tamaulipas.
50
71
1,000
951
951
130
(1)
These systems are accounted for as equity investments.
(2)
Miles, volumes and average throughput represent the
systems’ totals and are not adjusted for our ownership
interest.
(3)
We have a 50 percent equity interest in Citrus Corporation,
which owns this system.
We also have a 50 percent interest in Wyco Development, L.L.C.
Wyco owns the Front Range Pipeline, a state-regulated gas
pipeline extending from the Cheyenne Hub to Public Service
Company of Colorado’s (PSCo) Fort St. Vrain electric
generation plant, and compression facilities on WIC’s
Medicine Bow lateral. These facilities are leased to PSCo and
WIC, respectively, under long-term leases.
Underground Natural Gas Storage Entities
In addition to the storage capacity on our transmission systems,
we own or have interests in the following natural gas
storage entities:
Includes a total of 133 Bcf contracted to affiliates. Storage
capacity is under long-term contracts and is not adjusted for
our ownership interest.
(2)
These systems were accounted for as equity investments as of
December 31, 2005.
LNG Facility
In addition to our pipeline systems and storage facilities, we
own an LNG receiving terminal located on Elba Island, near
Savannah, Georgia. The recently completed expansion of the Elba
Island facility increased the peak sendout capacity to 1,215
MMcf/d and the base load sendout capacity to 806 MMcf/d. The
capacity at the terminal is contracted with subsidiaries of
British Gas Group and Royal Dutch Shell PLC.
We provide natural gas services to a variety of customers,
including natural gas producers, marketers,
end-users and other
natural gas transmission, distribution and electric generation
companies. In performing these services, we compete with other
pipeline service providers as well as alternative energy sources
such as coal, nuclear and hydroelectric power generation and
fuel oil for heating.
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 their delivery capabilities and operational
flexibility and complementing traditional supply transported
into market areas. However, these LNG delivery systems also may
compete with our pipelines for transportation of gas into market
areas we serve.
Electric power generation is the fastest growing demand sector
of the natural gas market. The growth of the electric power
industry potentially benefits the natural gas industry by
creating more demand for natural gas turbine generated electric
power. This effect is offset, in varying degrees, by increased
generation efficiency, the more effective use of surplus
electric capacity and increased natural gas prices. In addition,
in several regions of the country, new additions in electric
generating capacity have exceeded load growth and electric
transmission capabilities out of those regions. These
developments may inhibit owners of new power generation
facilities from signing firm contracts with pipelines.
Our existing contracts mature at various times and in varying
amounts of throughput capacity. Our ability to extend our
existing contracts or remarket expiring capacity is dependent on
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 renegotiated contracts will be
affected by current prices, competitive conditions and judgments
concerning future market trends and volatility. Subject to
regulatory requirements, we attempt to recontract or remarket
our capacity at the rates allowed under our tariffs although, at
times, we discount these rates to remain competitive. The level
of discount varies for each of our pipeline systems. The table
below shows the contracted capacity that expires by year over
the next five years and thereafter.
The following table details the markets we serve and the
competition faced by each of our wholly owned pipeline
transmission systems as of December 31, 2005:
Approximately 466 firm and interruptible customers, none of
which individually represents more than 10 percent of
revenues
Approximately 481 firm transportation contracts. Weighted
average remaining contract term of approximately five years.
TGP faces strong competition in the northeast, Appalachian,
midwest and southeast market areas. It competes with other
interstate and intrastate pipelines for deliveries to
multiple-connection customers who can take deliveries at
alternative points. Natural gas delivered on the TGP system
competes with alternative energy sources such as electricity,
hydroelectric power, coal and fuel oil. In addition, TGP
competes with pipelines and gathering systems for connection to
new supply sources in Texas, the Gulf of Mexico and from the
Canadian border.
In the offshore areas of the Gulf of Mexico, factors such as the
distance of the supply fields from the pipeline, relative basis
pricing of the pipeline receipt points, and costs of
intermediate gathering or required processing of the natural gas
to be transported may influence determinations of whether
natural gas is ultimately attached to our system.
ANR’s principal markets are in the midwest where it
competes with other interstate and intrastate pipeline companies
and local distribution companies to provide natural gas
transportation and storage services. ANR competes directly with
other interstate pipelines, including Guardian Pipeline, for
markets in Wisconsin. We Energies owns an interest in Guardian,
which is currently serving a portion of its firm transportation
requirements. ANR also competes directly with other interstate
pipelines in the midwest market to serve electric generation and
local distribution companies.
ANR also competes directly with numerous pipelines and gathering
systems for access to new supply sources. ANR’s principal
supply sources are the Rockies and mid-continent production
accessed in Kansas and Oklahoma, western Canadian production
delivered to Wisconsin and the Chicago area and Gulf of Mexico
sources, including deepwater production and LNG imports.
Approximately 163 firm and interruptible
customers
Major Customers: Southern California
Gas Company (453 BBtu/d) (93 BBtu/d) (768
BBtu/d)
Approximately 251 firm transportation contracts. Weighted
average remaining contract term of approximately four years.
Contract term expires in 2006. Contract term expire in 2007. Contract terms expire in 2009-2011.
EPNG faces competition in the west and southwest from other
existing and proposed pipelines, from California storage
facilities, and alternative energy sources that are used to
generate electricity such as hydroelectric power, nuclear, coal
and fuel oil. In addition, initiatives to bring LNG into
California and northern Mexico are underway.
Southwest Gas Corporation (12
BBtu/d) (470 BBtu/d) (74
BBtu/d)
Approximately 225 firm and
interruptible customers
Major Customers: Atlanta Gas Light
Company (959 BBtu/d)
Southern Company Services (418 BBtu/d)
Alabama Gas Corporation (415 BBtu/d) Scana
Corporation (346 BBtu/d)
Approximately 181 firm transportation contracts. Weighted
average remaining contract term of approximately six years.
SNG faces strong competition in a number of its key markets. SNG
competes with other interstate and intrastate pipelines for
deliveries to multiple-connection customers who can take
deliveries at alternative points. Natural gas delivered on our
system competes with alternative energy sources used to generate
electricity, such as hydroelectric power, coal and fuel oil.
SNG’s four largest customers are able to obtain a
significant portion of their natural gas requirements through
transportation from other pipelines. Also, SNG competes with
several pipelines for the transportation business of their other
customers. In addition, SNG competes with pipelines and
gathering systems for connection to new supply services.
Approximately 111 firm and interruptible
customers
Major Customer: Public Service Company
of Colorado (970 BBtu/d) (187 BBtu/d) (261
BBtu/d)
Approximately 184 firm transportation contracts. Weighted
average remaining contract term of approximately five years.
Contract terms expire in 2007. Contract term expires in 2008. Contract terms expires in 2009-2014.
CIG serves two major markets. Its “on-system” market
consists of utilities and other customers located along the
front range of the Rocky Mountains in Colorado and Wyoming. Its
“off-system” market consists of the transportation of
Rocky Mountain production from multiple supply basins to
interconnections with other pipelines bound for the midwest, the
southwest, California and the Pacific northwest. Competition for
its on-system market consists of an intrastate pipeline, local
production from the Denver- Julesburg basin, and long-haul
shippers who elect to sell into this market rather than the
off-system market. Competition for its off-system market
consists of other existing and proposed interstate pipelines
that are directly connected to its supply sources.
WIC competes with pipelines that are existing, proposed and
currently under construction to provide transportation services
to delivery points in northeast Colorado and western Wyoming.
WIC’s one Bcf/d Medicine Bow lateral is the primary
source of transportation for increasing volumes of Powder River
Basin supply and can readily be expanded as supply increases.
Currently, there are two other interstate pipelines that
transport limited volumes out of this basin.
MPC faces competition from other existing and proposed
pipelines, and alternative energy sources that are used to
generate electricity such as hydroelectric power, nuclear, coal
and fuel oil. In addition, initiatives to bring LNG into
California and northern Mexico are underway.
Major Customers: Oneok Energy
Services Company
L.P. (195 BBtu/d) Anadarko
Energy
Service Company (112
BBtu/d) Encana Marketing (USA)
Inc. (170 BBtu/d) Kerr
McGee (83 BBtu/d)
Approximately 16 firm transportation contracts Weighted
average remaining contract term of approximately nine years.
CPG competes directly with other interstate pipelines serving
the mid-continent region. Indirectly, CPG competes with other
existing and proposed interstate pipelines that transport Rocky
Mountain gas to other markets.
Our Exploration and Production segment’s long-term business
strategy focuses on the exploration for and the acquisition,
development and production of natural gas, oil and NGL in the
United States and internationally. As of December 31, 2005,
we controlled over 3 million net leasehold acres. During
2005, daily equivalent natural gas production averaged
approximately 743 MMcfe/d and our proved natural gas and
oil reserves at December 31, 2005, were approximately
2.4 Tcfe, excluding amounts related to our unconsolidated
investment in Four Star Oil & Gas Company (Four Star).
Our consolidated operations are divided into the following
regions:
Region
Operating Areas/Basins
United States
Onshore
East Texas and North Louisiana Rocky Mountains
Black Warrior
Arkoma
Raton
Illinois
Texas Gulf Coast
South Texas
Gulf of Mexico and south Louisiana
Gulf of Mexico (Federal and State waters)
South Louisiana
Internationally
Brazil
Camamu, Santos, Espirito Santo and Potiguar
In addition to our consolidated operations, we own a
43.1 percent interest in Four Star, which was acquired in
connection with our acquisition of Medicine Bow Energy
Corporation (Medicine Bow). Four Star operates onshore in the
San Juan, Permian, Hugoton and South Alabama Basins and the Gulf
of Mexico. During 2005, our proportionate share of Four
Star’s daily equivalent natural gas production averaged
approximately 24 MMcfe/d and at December 31, 2005, proved
natural gas and oil reserves, net to our interest, were 253 Bcfe.
Our business strategy has been to create value through our
drilling activities and through acquisitions of assets and
companies. For 2006, we expect our growth to occur principally
through drilling activities. However, we believe strategic
acquisitions can support our corporate objectives by:
Natural Gas, Oil and Condensate and NGL Reserves and
Production
The tables below present our estimated proved reserves as of
December 31, 2005 and our 2005 production by region and
summarizes our estimated proved reserves by classification as of
December 31, 2005:
Net Proved Reserves(1)
Total
2005
Natural Gas
Oil/Condensate
NGL
Production
(MMcf)
(MBbls)
(MBbls)
(MMcfe)
(Percent)
(MMcfe)
Reserves and Production by Region
United
States(2)
Onshore
1,258,329
32,007
1,207
1,457,615
60
%
109,361
Texas Gulf Coast
392,783
2,765
9,702
467,580
20
%
77,014
Gulf of Mexico and south Louisiana
179,654
8,456
1,653
240,311
10
%
65,432
Total United States
1,830,766
43,228
12,562
2,165,506
90
%
251,807
Brazil
56,388
32,250
—
249,890
10
%
19,300
Total
1,887,154
75,478
12,562
2,415,396
100
%
271,107
Unconsolidated investment in
Four Star(3)(4)
192,895
3,349
6,668
252,996
100
%
8,844
Reserves by Classification
United
States(2)
Producing
1,175,838
19,831
9,503
1,351,841
63
%
Non-Producing
228,173
8,750
1,507
289,716
13
%
Undeveloped
426,755
14,647
1,552
523,949
24
%
Total proved
1,830,766
43,228
12,562
2,165,506
100
%
Brazil
Producing
17,260
632
—
21,052
9
%
Non-Producing
10,162
512
—
13,234
5
%
Undeveloped
28,966
31,106
—
215,604
86
%
Total proved
56,388
32,250
—
249,890
100
%
Worldwide
Producing
1,193,098
20,463
9,503
1,372,893
57
%
Non-Producing
238,335
9,262
1,507
302,950
12
%
Undeveloped
455,721
45,753
1,552
739,553
31
%
Total proved
1,887,154
75,478
12,562
2,415,396
100
%
Unconsolidated investment in
Four Star(3)
Producing
154,979
3,246
5,371
206,677
82
%
Non-Producing
3,105
20
28
3,395
1
%
Undeveloped
34,811
83
1,269
42,924
17
%
Total Four Star
192,895
3,349
6,668
252,996
100
%
(1)
Net proved reserves exclude our Power segment’s equity
interests in proved reserves in Indonesia and in Peru of
162,254 MMcf of natural gas and 2,058 MBbls of oil,
condensate and NGL for total natural gas equivalents of
174,600 MMcfe, all net to our ownership interests. Our
Power segment has completed or expects to complete the sale of
these equity interests in 2006.
(2)
Net proved reserves exclude royalties and interests owned by
others and reflect contractual arrangements and royalty
obligations in effect at the time of the estimate.
(3)
Our share of Four Star’s proved reserves has been estimated
based on an evaluation of those reserves by El Paso’s
internal reservoir engineers and not by engineers of Four Star.
An independent reservoir engineering firm, Ryder Scott, which
was engaged by us, prepared an estimate on 86 percent of
Four Star’s proved reserves. Based on the amount of Four
Star’s proved reserves determined by Ryder Scott, we
believe our reported reserve amounts are reasonable.
(4)
Represents our proportionate share of Four Star’s
production since the acquisition date.
Consolidated reserve information in the tables above is based on
our internal reserve report. Ryder Scott, an independent
petroleum engineering firm that reports to the Audit Committee
of our Board of Directors, prepared an estimate on 92 percent of
our natural gas and oil reserves. Based on the amount of proved
reserves determined by Ryder Scott, we believe our reported
reserve amounts are reasonable. 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.
There are numerous uncertainties inherent in estimating
quantities of proved reserves, projecting future rates of
production costs, and projecting the timing of development
expenditures, including many factors beyond our control.
Reservoir engineering is a subjective process of estimating
underground accumulations of natural gas and oil that cannot be
measured in an exact manner. The reserve data represents only
estimates which are often different from the quantities of
natural gas and oil that are ultimately recovered. The accuracy
of any reserve estimate is highly dependent on the quality of
available data, the accuracy of the assumptions on which they
are based, and on engineering and geological interpretations and
judgment.
All estimates of proved reserves are determined according to the
rules prescribed by the SEC. These rules indicate that the
standard of “reasonable certainty” be applied to
proved reserve estimates. This concept of reasonable certainty
implies that as more technical data becomes available, a
positive, or upward, revision is more likely than a negative, or
downward, revision. 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.
In general, the volume of production from natural gas and oil
properties we own declines as reserves are depleted. Except to
the extent we conduct successful exploration and development
activities or acquire additional properties containing proved
reserves, or both, our proved reserves will decline as reserves
are produced. Recovery of proved undeveloped reserves requires
significant capital expenditures and successful drilling
operations. The reserve data assumes that we can and will make
these expenditures and conduct these operations successfully,
but future events, including commodity price changes, may cause
these assumptions to change. In addition, estimates of proved
undeveloped reserves and proved non-producing reserves are
subject to greater uncertainties than estimates of proved
producing reserves. For further discussion of our reserves, see
Part II, Item 8, Financial Statements and
Supplementary Data, under the heading Supplemental Natural Gas
and Oil Operations.
Our properties are primarily in the United States and are
separated into the Onshore, Texas Gulf Coast and Gulf of Mexico
and south Louisiana regions. We also have properties
internationally in Brazil. The following tables detail
(i) our interest in developed and undeveloped acreage at
December 31, 2005, (ii) our interest in natural gas
and oil wells at December 31, 2005 and (iii) our
exploratory and development wells drilled during the years 2003
through 2005. Any acreage in which our interest is limited to
owned royalty, overriding royalty and other similar interests is
excluded.
Developed
Undeveloped
Total
Acreage
Gross(1)
Net(2)
Gross(1)
Net(2)
Gross(1)
Net(2)
United States
Onshore
867,392
518,892
1,591,543
1,216,552
2,458,935
1,735,444
Texas Gulf Coast
103,234
79,439
151,751
109,241
254,985
188,680
Gulf of Mexico and south Louisiana
530,464
362,938
540,972
494,481
1,071,436
857,419
Total
1,501,090
961,269
2,284,266
1,820,274
3,785,356
2,781,543
Brazil
49,262
17,242
1,157,268
346,788
1,206,530
364,030
Worldwide Total
1,550,352
978,511
3,441,534
2,167,062
4,991,886
3,145,573
In the United States, our net developed acreage is concentrated
primarily in the Gulf of Mexico (38 percent), Utah
(12 percent), Texas (10 percent), Oklahoma
(9 percent), Alabama (8 percent), New Mexico
(8 percent) and Louisiana (6 percent). Our net
undeveloped acreage is concentrated primarily in New Mexico
(27 percent), the Gulf of Mexico (22 percent), Wyoming
(10 percent), Louisiana (7 percent), Texas
(7 percent), West Virginia (7 percent), Indiana
(6 percent) and Alabama (5 percent). Approximately
14 percent, 13 percent and 10 percent of our
total United States net undeveloped acreage is held under leases
that have minimum remaining primary terms expiring in 2006, 2007
and 2008. Approximately 24 percent, 21 percent and
14 percent of our total Brazilian net undeveloped acreage
is held under leases that have minimum remaining primary terms
expiring in 2006, 2007 and 2008.
Number of Wells
Productive
Being Drilled at
Natural Gas
Productive Oil
Total Productive
December 31,
Wells
Wells
Wells
2005
Productive Wells
Gross(1)
Net(2)
Gross(1)
Net(2)
Gross(1)
Net(2)(3)
Gross(1)
Net(2)
United States
Onshore
3,424
2,614
514
363
3,938
2,977
36
29
Texas Gulf Coast
831
702
—
—
831
702
—
—
Gulf of Mexico and south Louisiana
175
115
53
35
228
150
4
1
Total United States
4,430
3,431
567
398
4,997
3,829
40
30
Brazil
4
3
6
5
10
8
—
—
Worldwide Total
4,434
3,434
573
403
5,007
3,837
40
30
Net Exploratory
Net Development
Wells Drilled(2)
Wells Drilled(2)
Wells Drilled
2005
2004
2003
2005
2004
2003
United States
Productive
86
13
54
279
298
272
Dry
2
10
22
4
3
1
Total
88
23
76
283
301
273
Brazil
Productive
—
—
2
—
—
—
Dry
—
1
4
—
—
—
Total
—
1
6
—
—
—
Worldwide
Productive
86
13
56
279
298
272
Dry
2
11
26
4
3
1
Total
88
24
82
283
301
273
(1)
Gross interest reflects the total acreage or wells we
participated in, regardless of our ownership interest in the
acreage or wells.
(2)
Net interest is the aggregate of the fractional working
interests that we have in the gross acreage, gross wells or
gross drilled wells.
(3)
At December 31, 2005, we operated 3,541 of the 3,841 net
productive wells.
The drilling performance above should not be considered
indicative of future drilling performance, nor should it be
assumed that there is any correlation between the number of
productive wells drilled and the amount of natural gas and oil
that may ultimately be recovered.
Net Production, Sales Prices, Transportation and Production
Costs
The following table details our net production volumes, average
sales prices received, average transportation costs, average
production costs and production taxes associated with the sale
of natural gas and oil for each of the three years ended
December 31:
2005
2004
2003
Net Production Volumes
United States
Natural gas (MMcf)
206,714
238,009
338,762
Oil, condensate and NGL (MBbls)
7,516
8,498
11,778
Total (MMcfe)
251,807
288,994
409,432
Brazil
Natural gas (MMcf)
15,578
6,848
—
Oil, condensate and NGL (MBbls)
620
320
—
Total (MMcfe)
19,300
8,772
—
Worldwide
Natural gas (MMcf)
222,292
244,857
338,762
Oil, condensate and NGL (MBbls)
8,136
8,818
11,778
Total (MMcfe)
271,107
297,766
409,432
Natural Gas Average Realized Sales Price
($/Mcf)(1)
United States
Excluding hedges
$
7.92
$
6.02
$
5.51
Including hedges
$
6.69
$
5.94
$
5.40
Brazil
Excluding hedges
$
2.33
$
2.01
$
—
Including hedges
$
2.33
$
2.01
$
—
Worldwide
Excluding hedges
$
7.53
$
5.90
$
5.51
Including hedges
$
6.39
$
5.83
$
5.40
Oil, Condensate, and NGL Average Realized Sales Price
($/Bbl)(1)
Production costs include lease operating costs and production
related taxes (including ad valorem and severance taxes).
Acquisition, Development and Exploration Expenditures
The following table details information regarding the costs
incurred in our acquisition, development and exploration
activities for each of the three years ended December 31:
2005
2004
2003
(In millions)
United States
Acquisition Costs:
Proved
$
643
$
33
$
10
Unproved
143
32
35
Development Costs
503
395
668
Exploration Costs:
Delay rentals
3
7
6
Seismic acquisition and reprocessing
7
29
56
Drilling
133
149
405
Asset Retirement
Obligations(1)
1
30
124
Total full cost pool expenditures
1,433
675
1,304
Non-full cost pool expenditures
22
11
17
Total cost
incurred(2)
$
1,455
$
686
$
1,321
Acquisition of unconsolidated investment in Four Star
(2)
Acquisition of unconsolidated investment in Four Star
(2)
$
769
$
—
$
—
(1)
Includes an increase to our property, plant and equipment of
approximately $114 million in 2003 associated with our
adoption of Statement of Financial Accounting Standards (SFAS)
No. 143.
(2)
Includes $179 million of deferred income tax adjustments
related to the acquisition of full-cost pool properties and
$217 million related to the acquisition of our
unconsolidated investment in Four Star.
We spent approximately $247 million in 2005,
$156 million in 2004, and $220 million in 2003 to
develop proved undeveloped reserves that were included in our
reserve report as of January 1 of each year.
Markets and Competition
We primarily sell our domestic natural gas and oil to third
parties through our Marketing and Trading segment at spot market
prices, subject to customary adjustments. As part of our
long-term business strategy, we will continue this practice. We
sell our NGL at market prices under monthly or long-term
contracts, subject to customary adjustments. In Brazil, we sell
the majority of our natural gas and oil to Petrobras, a
Brazilian energy company. We also engage in hedging activities
on a portion of our production to stabilize our cash flows and
to reduce the risk of downward commodity price movements on
sales of our production. As of December 31, 2005, in this
segment we had hedged approximately 85,000 BBtu of our
anticipated natural gas production in 2006 and approximately
26,000 BBtu of our anticipated natural gas production during
2007 through 2012. For a further discussion of the prices at
which we have hedged our natural gas and oil production, see
Part II, Item 7 Management’s Discussion and
Analysis of Financial Condition and Results of Operations.
The exploration and production business is highly competitive in
the search for and acquisition of additional natural gas and oil
reserves and in the sale of natural gas, oil and NGL. Our
competitors include major and intermediate sized natural gas and
oil companies, independent natural gas and oil operators and
individual producers or operators with varying scopes of
operations and financial resources. Competitive factors include
price and contract terms, our ability to access drilling and
other equipment and our ability to hire and retain skilled
personnel on a timely and cost effective basis. Ultimately, our
future success in the exploration and production business will
be dependent on our ability to find or acquire additional
reserves at costs that yield acceptable returns on the capital
invested.
Our Marketing and Trading segment’s primary focus is to
market our Exploration and Production segment’s natural gas
and oil production and to manage the company’s price risks
related to its anticipated production, primarily through the use
of natural gas and oil derivative contracts. In addition, we
also continue to manage and liquidate various transportation,
power and other contracts remaining from our legacy trading
operations, primarily entered into prior to the deterioration of
the energy trading environment in 2002. We enter into contracts
in this segment with both third parties and with affiliates that
require physical delivery of a commodity or financial settlement
which are further described below.
Production-related Natural Gas and Oil Derivatives
Our natural gas and oil contracts include options and swaps
designed to provide price protection to El Paso from
fluctuations in natural gas and oil prices. As of
December 31, 2005, these contracts provided El Paso
with floor prices, ceiling prices and fixed prices on the
following volumes of future natural gas and oil production:
Natural gas transportation-related contracts. Our
transportation contracts give us the right to transport natural
gas using pipeline capacity for a fixed reservation charge plus
variable transportation costs. We typically refer to the fixed
reservation cost as a demand charge. Our ability to utilize our
transportation capacity under these contracts is dependent on
several factors, including the difference in natural gas prices
at receipt and delivery locations along the pipeline system, the
amount of working capital needed to use this capacity and the
capacity required to meet our other long-term obligations. The
following table details our transportation contracts as of
December 31 2005:
Alliance Pipeline
Enterprise Texas Pipeline
Other Pipelines
Daily capacity (MMBtu/d)
160,000
435,000
918,000(1)
Expiration
2015
May 2006
2006 to 2028
Receipt points
AECO Canada
South Texas
Various
Delivery points
Chicago
Houston Ship Channel
Various
(1)
Approximately 700,000 MMBtu/ d of this capacity is
contracted with our pipeline affiliates.
Other natural gas derivative contracts. As of
December 31, 2005, we have eight significant physical
natural gas contracts with power plants associated with our
legacy trading operations. These contracts obligate us to sell
gas to these plants and have various expiration dates ranging
from 2009 to 2028, with expected obligations under individual
contracts with third parties ranging from 32,000 to
142,000 MMBtu/d.
Power contracts. As of December 31, 2005, we held
derivative contracts with Constellation Energy Commodities Group
(Constellation) that swap locational differences in power prices
between the Pennsylvania-New Jersey-Maryland (PJM) eastern
region with those in the west PJM hub through 2013.
We also held a number of other power contracts that obligate us
to supply power or manage the price risk associated with those
supply contracts. These include a power supply agreement
associated with our formerly-
owned Utility Contract Funding (UCF) facility for approximately
1,700 MMWh per year through 2016. During 2005, we entered
into contracts that substantially offset the commodity risk
associated with these power supply and power price risk
management contracts. We will terminate or assign a portion of
these contracts to Morgan Stanley in 2006; however, we will
retain some contracts (including those related to UCF) that will
expose us primarily to locational price risk in the future as
any fixed price exposure is largely offset by the new contracts
we entered into in 2005.
Markets and Competition
Our Marketing and Trading segment operates in a highly
competitive environment, competing on the basis of price,
operating efficiency, technological advances, experience in the
marketplace and counterparty credit. Each market served is
influenced directly or indirectly by energy market economics.
Our primary competitors include:
•
Affiliates of major oil and natural gas producers;
•
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.
Our Power segment includes the ownership and operation of our
remaining international and domestic power generation
facilities. A number of our power assets have either been sold
or are under sales agreements that are expected to close in the
first half of 2006. These facilities primarily sell power under
long-term power purchase agreements with power transmission and
distribution companies owned by local governments which subject
us to certain political risks. As of December 31, 2005, we
owned or had interests in 23 power facilities in
11 countries with a total generating capacity of
approximately 6,334 gross MW (only significant assets and
investments are listed):
Our Macae project in Brazil is consolidated. All others in this
table are reflected as investments in unconsolidated affiliates
in our financial statements.
(2)
See Part II, Item 8, Financial Statements and
Supplementary Data, Note 16 for a further discussion of
these plants.
(3)
See Part II, Item 8, Financial Statements and
Supplementary Data, Note 21 for a further discussion of the
transfer of ownership in 2008 of these facilities.
(4)
We have sold or have received approval from our Board of
Directors to sell these facilities in 2006.
(5)
Our Marketing and Trading segment sells the power that this
facility generates to the wholesale power market.
In addition to the international power plants above, our Power
segment also has investments in the following international
pipelines:
El Paso
Ownership
Miles of
Design
Average 2005
Pipeline
Interest
Pipeline
Capacity(1)
Throughput(1)
(Percent)
(MMcf/d)
(BBtu/d)
Bolivia to Brazil
8
1,957
1,059
841
Argentina to Chile
22
336
138
100
(1)
Volumes represent the pipeline’s total design capacity and
average throughput and are not adjusted for our ownership
interest.
Field Services Segment
As of December 31, 2005, our Field Services segment
conducted our remaining midstream activities, which consisted
principally of two processing plants that support our
Exploration and Production segment activities in the Rocky
Mountain area. These facilities had operational capacity of
49 MMcf/d. In January 2006, these plants were transferred
to our Exploration and Production segment. As a result, our
Field Services segment will cease to be a business segment in
2006.
We currently have a number of other assets and businesses that
are either included as part of our corporate activities or as
discontinued operations. Our corporate operations include our
general and administrative functions as well as a
telecommunications business and various other contracts and
assets, including those related to petroleum ship charters, all
of which were insignificant to our results in 2005. Our
discontinued operations consist of our south Louisiana gathering
and processing assets (previously part of the Field Services
segment), certain of our international power operations in
Central America and Asia, certain of our international natural
gas and oil production operations (primarily in Canada), our
petroleum markets business and our coal mining operations.
Regulatory Environment
Pipelines. Our interstate natural gas transmission
systems and storage operations are regulated by the FERC under
the Natural Gas Act of 1938, the Natural Gas Policy Act of 1978
and the Energy Policy Act of 2005. Each of our pipeline systems
and storage facilities operates under tariffs approved by the
FERC that establish rates, cost recovery mechanisms, and terms
and conditions for service to our customers. Generally, the
FERC’s authority extends to:
•
rates and charges for natural gas transportation, storage, LNG
terminalling and related services;
•
certification and construction of new facilities;
•
extension or abandonment of facilities;
•
maintenance of accounts and records;
•
relationships between pipeline and energy affiliates;
•
terms and conditions of service;
•
depreciation and amortization policies;
•
acquisition and disposition of facilities; and
•
initiation and discontinuation of services.
Our interstate pipeline systems are also subject to federal,
state and local pipeline and LNG plant safety and environmental
statutes and regulations by the U.S. Department of
Transportation, U.S. Department of the Interior, and U.S. Coast
Guard. Our systems have ongoing programs designed to keep our
facilities in compliance with these safety and environmental
requirements.
Exploration and Production. Our natural gas and oil
exploration and production activities are regulated at the
federal, state and local levels, as well as in Brazil. These
regulations include, but are not limited to, the drilling and
spacing of wells, conservation, forced pooling and protection of
correlative rights among interest owners. We are also subject to
governmental safety regulations in the jurisdictions in which we
operate.
Our domestic operations under federal natural gas and oil leases
are regulated by the statutes and regulations of the
U.S. Department of the Interior that currently impose
liability upon lessees for the cost of environmental impacts
resulting from their operations. Royalty obligations on all
federal leases are regulated by the Minerals Management Service,
which has promulgated valuation guidelines for the payment of
royalties by producers. Our Brazilian oil and natural gas
operations are subject to environmental regulations
administered by the Brazilian government, which includes
political subdivisions in that country. These domestic and
international laws and regulations relating to the protection of
the environment affect our natural gas and oil operations
through their effect on the construction and operation of
facilities, water disposal rights, drilling operations,
production or the delay or prevention of future offshore lease
sales. In addition, we maintain insurance to limit exposure to
sudden and accidental spills and oil pollution liability.
International and Domestic Power. Our remaining
international power generation activities are regulated by
governmental agencies in the countries in which these projects
are located. Many of these countries have developed or are
developing new regulatory and legal structures to accommodate
private and foreign-owned businesses. These regulatory and legal
structures are subject to change (including differing
interpretations) over time.
Our remaining domestic power generation activities are regulated
by the FERC under the Federal Power Act with respect to the
rates, terms and conditions of service of these regulated
plants. Power production activities at these plants are
regulated by the FERC under the Public Utility Regulatory
Policies Act of 1978 with respect to rates, procurement and
provision of services and operating standards. Our power
generation activities are also subject to federal, state and
local environmental regulations.
Field Services. Our remaining operations are subject to
the Natural Gas Pipeline Safety Act of 1968, the Hazardous
Liquid Pipeline Safety Act of 1979 and various environmental
statutes and regulations.
Environmental
A description of our environmental activities is included in
Part II, Item 8, Financial Statements and
Supplementary Data, Note 16, and is incorporated herein by
reference.
Employees
As of February 24, 2006, we had approximately
5,700 full-time employees, of which 310 employees are
subject to collective bargaining arrangements.
Executive Vice President and Chief Financial Officer of
El Paso
2005
44
Robert W. Baker
Executive Vice President and General Counsel of El Paso
2002
49
Lisa A. Stewart
Executive Vice President of El Paso and President of
El Paso Exploration & Production Company
2004
48
Susan B. Ortenstone
Senior Vice President (Human Resources and Administration) of
El Paso
2003
49
Stephen C. Beasley
President of Eastern Pipeline Group
2005
54
James J. Cleary
President of Western Pipeline Group
2005
51
James C. Yardley
President of Southern Pipeline Group
2005
54
Daniel B. Martin
Senior Vice President of Pipeline Operations
2005
49
Douglas L. Foshee has been President, Chief Executive
Officer, and a Director of El Paso since September 2003.
Mr. Foshee became Executive Vice President and Chief
Operating Officer of Halliburton Company in 2003, having joined
that company in 2001 as Executive Vice President and Chief
Financial Officer. In December 2003, several subsidiaries of
Halliburton, including DII Industries and Kellogg
Brown & Root, filed for bankruptcy protection, whereby
the subsidiaries jointly resolved their asbestos claims. Prior
to assuming his position at Halliburton, Mr. Foshee was
President, Chief Executive Officer, and Chairman of the
Board at Nuevo Energy Company. From 1993 to 1997, Mr. Foshee
worked at Torch Energy Advisors Inc. in various capacities,
including Chief Operating Officer and Chief Executive Officer.
D. Mark Leland has been Executive Vice President and Chief
Financial Officer of El Paso since August 2005. Mr. Leland
served as Executive Vice President of El Paso Exploration &
Production Company (formerly known as El Paso Production Holding
Company) from January 2004 to August 2005, and also as Chief
Financial Officer and a director from April 2004 to August 2005.
He served in various capacities for GulfTerra Energy Partners,
L.P. and its general partner, including as Senior Vice President
and Chief Operating Officer from January 2003 to December 2003,
as Senior Vice President and Controller from July 2000 to
January 2003, and as Vice President from August 1998 to July
2000. Mr. Leland has also worked in various capacities for
El Paso Field Services from 1997 to August 2005.
Robert W. Baker has been Executive Vice President and
General Counsel of El Paso since January 2004. From
February 2003 to December 2003, he served as Executive Vice
President of El Paso and President of El Paso Merchant
Energy. He was Senior Vice President and Deputy General Counsel
of El Paso from January 2002 to February 2003.
Prior to that time he worked in various capacities in the legal
department of Tenneco Energy and El Paso since 1983.
Lisa A. Stewart has been an Executive Vice President of El
Paso since November 2004, and President of El Paso Exploration
& Production Company since February 2004. Ms. Stewart
was Executive Vice President of Business Development and
Exploration and Production Services for Apache Corporation from
1995 to February 2004. From 1984 to 1995, Ms. Stewart
worked in various capacities for Apache Corporation.
Susan B. Ortenstone has been Senior Vice President of
El Paso since October 2003. Ms. Ortenstone was
Chief Executive Officer for Epic Energy Pty Ltd. from
January 2001 to June 2003. She served as Vice President of
El Paso Gas Services Company and President of El Paso
Energy Communications from December 1997 to December 2000. Prior
to that time Ms. Ortenstone worked in various strategy,
marketing, business development, engineering, and operations
capacities since 1979.
Stephen C. Beasley has been Chairman of the Board and
President of ANR Pipeline Company and Tennessee Pipeline Company
since May 2005. He has been Director of ANR Pipeline Company
since January 2004, Director of Tennessee Gas Pipeline Company
since November 2001 and President of Tennessee Pipeline Company
since June 2001. Prior to that time, Mr. Beasley worked in
various capacities at Tennessee Gas Pipeline since 1987.
James J. Cleary has been Chairman of the Board and
President of El Paso Natural Gas Company and Colorado
Interstate Gas Company since May 2005. He has been Director and
President of El Paso Natural Gas Company and Colorado
Interstate Gas Company since January 2004. From January 2001
through December 2003, he served as President of ANR Pipeline
Company. Prior to that time, Mr. Cleary served as Executive
Vice President of Southern Natural Gas Company from May 1998 to
January 2001. He also worked for Southern Natural Gas Company
and its affiliates in various capacities since 1979.
James C. Yardley has been Chairman of the Board and
President of Southern Natural Gas Company since May 2005,
Director of Southern Natural Gas Company since November 2001 and
President of Southern Natural Gas Company since May 1998. He
served as Vice President, Marketing and Business Development for
Southern Natural Gas Company from April 1994 to April 1998.
Prior to that time, Mr. Yardley worked in various
capacities with Southern Natural Gas and Sonat Inc. since
1978.
Daniel B. Martin has been Director of ANR Pipeline Company,
Colorado Interstate Gas Company, El Paso Natural Gas
Company, Southern Natural Gas Company and Tennessee Gas Pipeline
Company since May 2005. He has been Senior Vice President of El
Paso Natural Gas Company since February 2000, Senior Vice
President of Southern Natural Gas Company and Tennessee Gas
Pipeline Company since June 2000 and Senior Vice President of
ANR Pipeline Company and Colorado Interstate Gas Company since
January 2001. Prior to that time, Mr. Martin worked in various
capacities with Tennessee Gas Pipeline Company since 1978.
Our website is http://www.elpaso.com. We make available, free of
charge on or through our website, our annual, quarterly and
current reports, and any amendments to those reports, as soon as
is reasonably possible after these reports are filed with the
SEC. Information about each of our Board members, as well as
each of our Board’s standing committee charters, our
Corporate Governance Guidelines and our Code of Business Conduct
are also available, free of charge, through our website.
Information contained on our website is not part of this report.
ITEM 1A. RISK FACTORS
CAUTIONARY STATEMENT FOR PURPOSES OF THE “SAFE
HARBOR” PROVISIONS OF THE PRIVATE SECURITIES LITIGATION
REFORM ACT OF 1995
This report contains 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
SEC 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.
Risks Related to Our Business
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,
adverse weather conditions (such as hurricanes and flooding) 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 and assets face possible
risks associated with acts of aggression. If any of these events
were to occur, we could suffer substantial losses.
While we maintain insurance against many of these risks to the
extent and in amounts that we believe are reasonable, this
insurance does not cover all risks. Many of our insurance
coverages have material deductibles and
self-insurance levels,
as well as limits on our maximum recovery. As a result, our
financial condition and operations could be adversely affected
if a significant event occurs that is not fully covered by
insurance.
The success of our pipeline business depends, in part, on
factors beyond our control.
Most of the natural gas and NGL we transport and store are owned
by third parties. As a result, the volume of natural gas and NGL
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 on our pipeline systems:
•
service area competition;
•
expiration and/or turn back of significant contracts;
•
changes in regulation and action of regulatory bodies;
•
future weather conditions;
•
price competition;
•
drilling activity and availability of natural gas supplies;
•
decreased availability of conventional gas supply sources and
the availability and timing of other gas supply sources, such as
LNG;
•
decreased natural gas demand due to various factors, including
increases in prices and the increased availability or popularity
of alternative energy sources such as hydroelectric power;
•
increased costs of capital;
•
opposition to energy infrastructure development, especially in
environmentally sensitive areas;
•
adverse general economic conditions;
•
expiration and/or renewal of existing interests in real
property, including real property on Native American lands; and
•
unfavorable movements in natural gas and NGL prices in certain
supply and demand areas.
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.
In particular, our ability to extend and replace contracts could
be adversely affected by factors we cannot control, including:
•
competition by other pipelines, including the change in rates or
upstream supply of existing pipeline competitors, as well as the
proposed construction by other companies of additional pipeline
capacity or LNG terminals 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 in the areas we serve;
•
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, earnings and cash flows.
Fluctuations in energy commodity prices could adversely
affect our pipeline businesses.
Revenues generated by our transmission, storage and LNG
contracts depend on volumes and rates, both of which can be
affected by the prices of natural gas, LNG and NGL. Increased
prices could result in a reduction of the volumes transported by
our customers, such as power companies who, depending on the
price
of fuel, may not dispatch gas-fired power plants. Increased
prices could also result in industrial plant shutdowns or load
losses to competitive fuels as well as local distribution
companies’ loss of customer base. The success of our
transmission, storage and LNG operations is subject to continued
development of additional oil and natural gas reserves and our
ability to access additional supplies from interconnecting
pipelines or LNG facilities to offset the natural decline from
existing wells connected to our systems. A decline in energy
prices could cause a decrease in these development activities
and could cause a decrease in the volume of reserves available
for transmission, storage and processing through our systems.
Pricing volatility may, in some cases, impact the value of under
or over recoveries of retained gas, imbalances and system
encroachments. If natural gas prices in the supply basins
connected to our pipeline systems are higher than prices in
other natural gas producing regions, our ability to compete with
other transporters may be negatively impacted. Furthermore,
fluctuations in pricing between supply sources and market areas
could negatively impact our transportation revenues.
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 NGL;
•
abundance of supplies of alternative energy sources; and
•
political unrest among oil producing countries.
The expansion of our pipeline systems by constructing new
facilities subjects us to construction and other risks that may
adversely affect the financial results of our pipeline
businesses.
We may expand the capacity of our existing pipeline, storage or
LNG facilities by constructing additional facilities.
Construction of these facilities is subject to various
regulatory, development and operational risks, including:
•
the ability to obtain all necessary approvals and permits by
regulatory agencies on a timely basis on terms that are
acceptable to us;
•
potential changes of federal, state and local statutes and
regulations, including environmental requirements that prevent a
project from proceeding or increase the anticipated cost of the
expansion project;
•
impediments on our ability to acquire rights-of-ways or land
rights on a timely basis or within our anticipated costs;
•
the ability to construct projects within anticipated costs,
including the risk that we may incur cost overruns resulting
from inflation or increased costs of equipment, materials,
labor, or other factors beyond our control, that may be material;
•
anticipated future growth in natural gas supply does not
materialize; and
•
the lack of transportation, storage or throughput commitments
that result in write-offs of development costs.
Any of these risks could prevent a project from proceeding,
delay its completion or increase its anticipated costs. As a
result, new facilities may not achieve our expected investment
return, which could adversely affect our financial position or
results of operations.
Natural gas and oil prices are volatile. A substantial
decrease in natural gas and oil prices could adversely affect
the financial results of our exploration and production
business.
Our future financial condition, revenues, results of operations,
cash flows and future rate of growth depend primarily upon the
prices we receive for our natural gas and oil production.
Natural gas and oil prices historically have been volatile and
are likely to continue to be volatile in the future, especially
given current world geopolitical conditions. The prices for
natural gas and oil are subject to a variety of additional
factors that are beyond our control. These factors include:
•
the level of consumer demand for, and the supply of, natural gas
and oil;
•
commodity processing, gathering and transportation availability;
•
the level of imports of, and the price of, foreign natural gas
and oil;
•
the ability of the members of the Organization of Petroleum
Exporting Countries to agree to and maintain oil price and
production controls;
•
domestic governmental regulations and taxes;
•
the price and availability of alternative fuel sources;
•
the availability of pipeline capacity;
•
weather conditions;
•
market uncertainty;
•
political conditions or hostilities in natural gas and oil
producing regions;
•
worldwide economic conditions; and
•
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.
Further, because the majority of our proved reserves at
December 31, 2005 were natural gas reserves, we are
substantially more sensitive to changes in natural gas prices
than we are to changes in oil prices. Declines in natural gas
and oil prices would not only reduce revenue, but could reduce
the amount of natural gas and oil that we can produce
economically and, as a result, could adversely affect the
financial results of our exploration and production business.
Changes in natural gas and oil prices can have a significant
impact on the calculation of our full cost ceiling test. A
significant decline in natural gas and oil prices could result
in a downward revision of our reserves and a write-down of the
carrying value of our natural gas and oil properties, which
could be substantial, and would negatively impact our net income
and stockholders’ equity.
The success of our exploration and production business is
dependent, in part, on factors that are beyond our
control.
The performance of our exploration and production business is
dependent upon a number of factors that we cannot control,
including:
•
the results of future drilling activity;
•
the availability of rigs, equipment and labor to support
drilling activity and production operations;
•
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
conditions;
•
increased competition in the search for and acquisition of
reserves;
significant increases in future drilling, production and
development costs, including drilling rig rates and oil field
services costs;
•
adverse changes in 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;
•
our lack of control over jointly owned properties and properties
operated by others;
•
the availability of alternative sources of energy;
•
declines in production volumes, including those from the Gulf of
Mexico; and
•
continued access to sufficient capital to fund drilling programs
to develop and replace a reserve base with rapid depletion
characteristics.
Our natural gas and oil drilling and producing operations
involve many risks and may not be profitable.
Our operations are subject to all the risks normally incident to
the operation and development of natural gas and oil properties
and the drilling of natural gas and oil wells, including well
blowouts, cratering and explosions, pipe failure, fires,
formations with abnormal pressures, uncontrollable flows of
natural gas, oil, brine or well fluids, release of contaminants
into the environment and other environmental hazards and risks.
Additionally, our offshore operations may encounter usual marine
perils, including hurricanes and other adverse weather
conditions, damage from collisions with vessels, governmental
regulations and interruption or termination by governmental
authorities based on environmental and other considerations.
Each of these risks could result in damage to property, injuries
to people or the shut in of existing production as damaged
energy infrastructure is repaired or replaced.
We maintain insurance coverage to reduce exposure to potential
losses resulting from these operating hazards. The nature of the
risks is such that some liabilities could exceed our insurance
policy limits, or, as in the case of environmental fines and
penalties, cannot be insured which could adversely affect our
future results of operations, cash flows or financial condition.
Our drilling operations are also subject to the risk that we
will not encounter commercially productive reservoirs. New wells
drilled by us may not be productive, or we may not recover
all or any portion of our investment in those wells. Drilling
for natural gas and oil can be unprofitable, not only because of
dry holes but wells that are productive may not produce
sufficient net reserves to return a profit at then realized
prices after deducting drilling, operating and other costs.
Estimating our reserves, production and future net cash
flow is difficult.
Estimating quantities of proved natural gas and oil reserves is
a complex process that involves significant interpretations and
assumptions. It requires interpretations and judgment of
available technical data, including the evaluation of available
geological, geophysical, and engineering data. It also requires
making estimates based upon economic factors, such as natural
gas and oil prices, production costs, severance and excise
taxes, capital expenditures, workover and remedial costs, and
the assumed effect of governmental regulation. Due to a lack of
substantial, if any, production data, there are greater
uncertainties in estimating proved undeveloped reserves, proved
non-producing reserves and proved developed reserves that are
early in their production life. As a result, our reserve
estimates are inherently imprecise. Also, we use a
10 percent discount factor for estimating the value of our
reserves, as prescribed by the SEC, which may not necessarily
represent the most appropriate discount factor, given actual
interest rates and risks to which our exploration and production
business or the natural gas and oil industry, in general, are
subject. Any significant variations from the interpretations or
assumptions used in our estimates or changes of conditions could
cause the estimated quantities and net present value of our
reserves to differ materially.
Our reserve data represents an estimate. You should not assume
that the present values referred to in this report represent the
current market value of our estimated natural gas and oil
reserves. The timing of the production and the expenses related
to the development and production of natural gas and oil
properties will affect both the timing of actual future net cash
flows from our proved reserves and their present value. Changes
in the present value of these reserves could cause a write-down
in the carrying value of our natural gas and oil properties,
which could be substantial, and would negatively affect our net
income and stockholders’ equity.
A portion of our estimated proved reserves are undeveloped.
Recovery of undeveloped reserves requires significant capital
expenditures and successful drilling operations. The reserve
data assumes that we can and will make these expenditures and
conduct these operations successfully, but future events,
including commodity price changes, may cause these assumptions
to change.
The success of our exploration and production business
depends upon our ability to replace reserves that we
produce.
Unless we successfully replace the reserves that we produce, our
reserves will decline, eventually resulting in a decrease in
natural gas and oil production and lower revenues and cash flows
from operations. We historically have replaced reserves through
both drilling and acquisitions. The business of exploring for,
developing or acquiring reserves requires substantial capital
expenditures. Our operations require continued access to
sufficient capital to fund drilling programs to develop and
replace a reserve base with rapid depletion characteristics. If
we do not continue to make significant capital expenditures, or
if our capital resources become limited, we may not be able to
replace the reserves that we produce, which would negatively
affect our future revenues, cash flows and results of operations.
We face competition from third parties to acquire and
develop natural gas and oil reserves.
The natural gas and oil business is highly competitive in the
search for and acquisition of reserves. We must identify and
precisely locate prospective geologic structures, drill and
successfully complete wells in those structures in a timely
manner. Our ability to expand our leased land positions in
desirable areas is impacted by intensely competitive leasing
conditions. Competition for reserves and producing natural gas
and oil properties is intense and many of our competitors have
financial and other resources that are substantially greater
than those available to us. Our competitors include the major
and independent natural gas and oil companies, individual
producers, gas marketers and major pipeline companies, as well
as participants in other industries supplying energy and fuel to
industrial, commercial and individual consumers. If we are
unable to compete effectively in the acquisition and development
of reserves, our future profitability may be negatively
impacted. Ultimately, our future success in the production
business is dependent on our ability to find or acquire
additional reserves at costs that allow us to remain competitive.
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. To the extent we have
positions that are not designated or qualify as hedges, changes
in commodity prices, interest rates, volatility, correlation
factors and the liquidity of the market could cause our
revenues, net income and cash requirements to be volatile.
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 involves
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 or interest rates were to change favorably. The
use of derivatives could require the posting of collateral with
our counterparties which can impact our working capital (current
assets and liabilities) and liquidity when commodity prices or
interest rates change. For additional information
concerning our derivative financial instruments, see
Part II, Item 7A, Quantitative and Qualitative
Disclosures About Market Risk and Part II, Item 8,
Financial Statements and Supplementary Data, Note 10.
Our businesses are subject to the risk of payment defaults
by our counterparties.
We frequently extend credit to our counterparties following the
performance of credit analysis. Despite performing this
analysis, we are exposed to the risk that we may not be able to
collect amounts owed to us. Although in many cases we have
collateral to secure the counterparty’s performance, it
could be inadequate and we could suffer losses.
Our foreign operations and investments involve special
risks.
Our activities in areas outside the United States, including
material investment exposure in our power, pipeline and
exploration and production projects in Brazil (see Part II,
Item 8, Financial Statements and Supplementary Data,
Note 16), 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.
Retained liabilities associated with businesses that we
have sold could exceed our estimates and we could experience
difficulties in managing these liabilities.
We have sold a significant number of assets over the years,
including the sale of many assets since 2001. Pursuant to
various purchase and sale agreements relating to businesses and
assets sold, we have either retained certain liabilities or
indemnified certain purchasers against liabilities that they
might incur in the future. These liabilities in many cases
relate to breaches of warranties, environmental, asset
maintenance, tax, litigation, personal injury and other
representations that we have provided. Although we believe that
we have established appropriate reserves for these liabilities,
we could be required to accrue additional reserves in the future
and these amounts could be material. In addition, as we exit
businesses, we have experienced substantial reductions and
turnover in our workforce that previously supported the
ownership and operation of such assets. There is the risk that
such reductions and turnover in our workforce prior to closing
could result in difficulties in managing the businesses that we
are exiting or managing the liabilities retained after closing,
including a reduction in historical knowledge of the assets and
businesses in managing the liabilities or defending any
associated litigation.
Risks Related to Legal and Regulatory Matters
The outcome of pending governmental investigations could
be materially adverse to us.
We are subject to numerous governmental investigations including
those involving allegations of round trip trades, price
reporting of transactional data to the energy trade press,
natural gas and oil reserve revisions, accounting treatment of
certain hedges of our anticipated natural gas production, sales
of crude oil of Iraqi origin under the United Nation’s Oil
for Food Program and the rupture of one of our pipelines near
Carlsbad, New Mexico. These investigations involve, among
others, one or more of the following governmental agencies: the
SEC, FERC, a grand jury of the U.S. District Court for the
Southern District of New York, U.S. Senate Permanent
Subcommittee of Investigations, the House of Representatives
International Relations Subcommittee, the U.S. Department of
Transportation Office of Pipeline Safety and the Department of
Justice. We are cooperating with the governmental agency or
agencies in each of these investigations. The outcome of each of
these investigations is uncertain. Because of the uncertainties
associated with the ultimate outcome of each of these
investigations and the costs to the Company of responding and
participating in these
on-going investigations, no assurance can be given that the
ultimate costs and sanctions, if any, that may be imposed upon
us will not have a material adverse effect on our business,
financial condition or results of operation.
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, the U.S. Department
of Interior, and various state, local and tribal 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. In setting authorized
rates of return in recent FERC decisions, the FERC has utilized
a proxy group of companies that includes local distribution
companies that are not faced with as much competition or risks
as interstate pipelines. The inclusion of these lower risk
companies may create downward pressure on tariff rates when
subjected to review by the FERC in future rate proceedings. If
our pipelines’ tariff rates were reduced or
re-designed 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 or because of
regulatory pressure, the profitability of our pipeline
businesses could be reduced.
In addition, increased regulatory requirements relating to the
integrity of our pipelines requires additional spending in order
to maintain compliance with these requirements. Any additional
requirements that are enacted could significantly increase the
amount of these expenditures.
Further, state agencies that regulate our pipelines’ local
distribution company customers could impose requirements that
could impact demand for our pipelines’ services.
Environmental compliance and remediation costs and the
costs of environmental liabilities could exceed our
estimates.
Our operations are subject to various environmental laws and
regulations regarding compliance and remediation obligations.
Compliance obligations can result in significant costs to
install and maintain pollution controls, fines and penalties
resulting from any failure to comply, and potential limitations
on our operations. Remediation obligations can result in
significant costs associated with the investigation and
remediation or clean-up
of contaminated properties (some of which have been designated
as Superfund sites by the Environmental Protection Agency (EPA)
under the Comprehensive Environmental Response, Compensation and
Liability Act (CERCLA)), as well as damage claims arising out of
the contamination of properties or impact on natural resources.
It is not possible for us to estimate exactly the amount and
timing of all future expenditures related to environmental
matters because of:
•
The uncertainties in estimating pollution control and clean up
costs, including for sites for which only preliminary site
investigation or assessments have been completed;
•
The discovery of new sites or additional information at existing
sites;
•
The uncertainty in quantifying liability under environmental
laws that impose joint and several liability on all potentially
responsible parties; and
•
The nature of environmental laws and regulations, including the
interpretation and enforcement thereof.
Currently, various legislative and regulatory measures to
address greenhouse gas (GHG) emissions (including carbon dioxide
and methane) are in various phases of discussion or
implementation. These include the Kyoto Protocol, proposed
federal legislation and state actions to develop statewide or
regional programs, each of which have imposed or would impose
reductions in GHG emissions. These actions could result in
increased costs to (i) operate and maintain our facilities,
(ii) install new emission controls on our facilities and
(iii) administer and manage any GHG emissions program.
These actions could also impact the consumption of natural gas
and oil, thereby affecting our pipeline and exploration and
production operations.
Although we believe we have established appropriate reserves for
our environmental liabilities, we could be required to set aside
additional amounts due to these uncertainties which could
significantly impact our future consolidated results of
operations, cash flows or financial position. For additional
information concerning our environmental matters, see
Part I, Item 3, Legal Proceedings and Part II,
Item 8, Financial Statements and Supplementary Data,
Note 16.
Costs of litigation matters and other contingencies could
exceed our estimates.
We are involved in various lawsuits in which we or our
subsidiaries have been sued. We also have other contingent
liabilities and exposures. Although we believe we have
established appropriate reserves for these liabilities, we could
be required to set aside additional reserves in the future and
these amounts could be material. For additional information
concerning our litigation matters and other contingent
liabilities, see Part II, Item 8, Financial Statements
and Supplementary Data, Note 16.
Our system of internal controls is designed to provide
reasonable assurance regarding the reliability of our financial
reporting and the preparation of our financial statements for
external purposes. A loss of public confidence in the quality of
our internal controls or disclosures could have a negative
impact on us.
Our system of internal controls is designed to provide
reasonable assurance that the objectives of the control system
are met. However, any system of internal controls is subject to
inherent limitations and the design of our controls may not
provide absolute assurances that all of our objectives will be
entirely met. This includes the possibility that controls may be
inappropriately circumvented or overridden, that judgments in
decision-making can be
faulty and that misstatements due to errors or fraud may not be
prevented or detected.
Risks Related to Our Liquidity
We have significant debt and below investment grade credit
ratings, which have impacted and will continue to impact our
financial condition, results of operations and liquidity.
We have significant debt, debt service and debt maturity
obligations. The ratings assigned to our senior unsecured
indebtedness are below investment grade, currently rated Caa1 by
Moody’s Investor Service (Moody’s) and B- by
Standard & Poor’s. These ratings have increased
our cost of capital and our operating costs, particularly in our
trading operations, and could impede our access to capital
markets. Moreover, we must retain greater liquidity levels to
operate our business than if we had investment grade credit
ratings. If our ability to generate or access capital becomes
significantly restrained, our financial condition and future
results of operations could be significantly adversely affected.
See Part II, Item 8, Financial Statements and
Supplementary Data, Note 14, for a further discussion of
our debt.
We
may not achieve our targeted level of debt reduction or complete
our asset sales in a timely manner or at all.
Our ability to achieve our announced targets to reduce our debt
obligations and complete asset sales, as well as the timing of
their achievement, is subject, in part, to factors beyond our
control. These factors include our ability to locate potential
buyers in a timely fashion and obtain a reasonable price, and
our ability to preserve sufficient cash flow to service our debt
and other obligations. If we fail to achieve these targets in a
timely manner, our liquidity or financial position could be
materially adversely affected. In addition, it is possible that
our asset sales could be at prices that are below the current
book value for the assets, which could result in losses that
could be substantial.
A breach of the covenants applicable to our debt and other
financing obligations could affect our ability to borrow funds
and could accelerate our debt and other financing obligations
and those of our subsidiaries.
Our debt and other financing obligations contain restrictive
covenants, which become more restrictive over time, and
cross-acceleration provisions. A breach of any of these
covenants could preclude us or our subsidiaries from issuing
letters of credit and from borrowing under our credit
agreements, and could
accelerate our debt and other financing obligations and those of
our subsidiaries. If this were to occur, we might not be able to
repay such debt and other financing obligations.
Some of our credit agreements are collateralized by our equity
interests in ANR, CIG, EPNG, Southern Gas Storage Company (which
owns an interest in Bear Creek Storage Company), ANR Storage
Company, TGP and certain natural gas and oil reserves. A breach
of the covenants under these agreements could permit the lenders
to exercise their rights to the collateral, and we could be
required to sell these collateral interests.
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. This is
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;
•
our stock price; and
•
market prices for energy.
In addition, although we hedge a portion of our exposure to
interest rate movements, our financial condition and liquidity
could be adversely affected if there is a negative movement in
interest rates.
We believe that we have satisfactory title to the properties
owned and used in our businesses, subject to liens for taxes not
yet payable, liens incident to minor encumbrances, liens for
credit arrangements and easements and restrictions that do not
materially detract from the value of these properties, our
interests in these properties, or the use of these properties in
our businesses. We believe that our properties are adequate and
suitable for the conduct of our business in the future.
ITEM 3. LEGAL PROCEEDINGS
Details of the cases listed below, as well as a description of
our other legal proceedings are included in Part II,
Item 8, Financial Statements and Supplementary Data,
Note 16, and are incorporated herein by reference.
The 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 shareholder class actions relating to our reserve
restatement filed in the U.S. District Court for the Southern
District of Texas, Houston Division, which have now been
consolidated with the above referenced purported shareholder
class actions, are: James Felton v. El Paso Corporation,
Ronald Kuehn, Jr., Douglas Foshee and D. Dwight Scott; Sinclair
Haberman v. El Paso Corporation, Ronald Kuehn, Jr., and William
Wise; Patrick Hinner v. El Paso Corporation, Ronald Kuehn, Jr.,
Douglas Foshee, D. Dwight Scott and William Wise; Stanley Peltz
v. El Paso Corporation, Ronald Kuehn, Jr., Douglas Foshee and D.
Dwight Scott; Yolanda Cifarelli v. El Paso Corporation, Ronald
Kuehn, Jr., Douglas Foshee and D. Dwight Scott; Andrew W.
Albstein v. El Paso Corporation, William Wise; George S. Johnson
v. El Paso Corporation, Ronald Kuehn, Jr., Douglas Foshee, and
D. Dwight Scott; Robert Corwin v. El Paso Corporation, Mark
Leland, Brent Austin, Ronald Kuehn, Jr., D. Dwight Scott and
William Wise; Michael Copland v. El Paso Corporation, Ronald
Kuehn, Jr., Douglas Foshee and D. Dwight Scott; Leslie Turbowitz
v. El Paso Corporation, Mark Leland, Brent Austin, Ronald Kuehn,
Jr., D. Dwight Scott and William Wise; David Sadek v. El Paso
Corporation, Ronald Kuehn, Jr., Douglas Foshee, D. Dwight Scott;
Stanley Sved v. El Paso Corporation, Ronald Kuehn, Jr., and
William Wise; Nancy Gougler v. El Paso Corporation, Ronald
Kuehn, Jr., Douglas Foshee and D. Dwight Scott; William
Sinnreich v. El Paso Corporation, Ronald Kuehn, Jr., Douglas
Foshee, D. Dwight Scott and William Wise; Joseph Fisher v. El
Paso Corporation, Ronald Kuehn, Jr., Douglas Foshee, D. Dwight
Scott and William Wise; Glickenhaus & Co. v. El Paso
Corporation, Rod Erskine, Ronald Kuehn, Jr., Brent Austin,
William Wise, Douglas Foshee and D. Dwight Scott; and Thompson
v. El Paso Corporation, Ronald Kuehn, Douglas Foshee and D.
Dwight Scott.
The stayed shareholder derivative actions filed in the United
States District Court for the Southern District of Texas,
Houston Division 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, and Russo v. William Wise,
Brent Austin, Dwight Scott, Ralph Eads, Ronald Kuehn, Jr.,
Douglas Foshee, Rodney Erskine, PricewaterhouseCoopers and El
Paso Corporation filed in September 2004. The consolidated
shareholder derivative action filed in Houston is John
Gebhart and Marilyn Clark v. El Paso Corporation, Byron
Allumbaugh, John Bissell, Juan Carlos Braniff, James Gibbons,
Anthony Hall Jr., Ronald Kuehn, Jr., J. Carleton MacNeil, Jr.,
Thomas McDade, Malcolm Wallop, William Wise, Joe Wyatt, Ralph
Eads, Brent Austin and John Somerhalder filed in November
2002. Gebhardt Plaintiffs filed a Third Amended Petition in
October 2005 adding additional defendants, James Dunlap, Douglas
Foshee, Robert Goldman, Thomas Hix, William Joyce, Michael
Talbert and John Whitmire. The two derivative actions filed in
Delaware Chancery Court are Stephen Brudno, et al. v. William
A. Wise, et al. filed in October 2002 (which was voluntarily
dismissed in July 2005) and Alan Laties v. William Wise, John
L. Bissell, Juan Carlos Braniff, James L. Dunlap, Douglas L.
Foshee, Robert W. Goldman, Anthony Hall, Thomas R. Hix, William
H. Joyce, Ronald L. Kuehn, Jr., J. Carlton MacNeil, Jr., J.
Michael Talbert, John L. Whitmire, Joe B. Wyatt and El Paso
Corporation. The Laties case was filed in April 2005 in
Delaware Chancery Court nominally on behalf of El Paso against
William Wise and the board of directors. An identical suit was
filed by Laties in Harris County District Court on
August 25, 2005, but has never been served on El Paso.
The Laties case filed in Delaware was dismissed by the court in
December 2005.
Environmental Proceedings
Air Permit Violation. In March 2003, the Louisiana
Department of Environmental Quality (LDEQ) issued a
Consolidated Compliance Order and Notice of Potential Penalty to
our subsidiary, El Paso Production Company, alleging that
it failed to timely obtain air permits for specified oil and
natural gas facilities. El Paso Production Company
requested an adjudicatory hearing on the matter. Pursuant to
discussions with LDEQ, we have reached an agreement to resolve
the allegations for $77,287. We signed the settlement agreement
on November 28, 2005, and will pay the penalty once LDEQ
has completed its approval process for this settlement.
Coastal Eagle Point Air Issues. On April 1, 2004,
the New Jersey Department of Environmental Protection issued an
Administrative Order and Notice of Civil Administrative Penalty
Assessment seeking $183,000 in penalties for excess emission
events that occurred during the fourth quarter of 2003 at our
former
Eagle Point refinery. We filed an administrative appeal
contesting the allegations and penalty. We reached an agreement
to resolve the allegations and appeal for a penalty for
$119,400, have executed the settlement agreement, and paid the
agreed penalty in the fourth quarter of 2005, fully resolving
this matter.
Corpus Christi Refinery Air Violations. On March 18,2004, the Texas Commission on Environmental Quality
(TCEQ) issued an “Executive Director’s
Preliminary Report and Petition” seeking $645,477 in
penalties relating to air violations alleged to have occurred at
El Paso’s former Corpus Christi, Texas refinery from 1996
to 2000. We subsequently filed a hearing request to protect our
procedural rights. In March 2005, the parties reached an
agreement in principle to resolve the allegations for $272,097.
In September 2005, the parties finalized the written terms of
the settlement agreement. The final terms allow for $136,049 to
be paid as a penalty and $136,049 to be spent on a supplemental
environmental project. El Paso and TCEQ have executed the final
agreement and all payments required to resolve this matter have
been made.
EPNG State of Arizona Pipe-Coating. In September 2005,
the Arizona Department of Environmental Quality (ADEQ) issued a
Notice of Violation (NOV) for alleged regulatory violations
related to our handling of asbestos-containing asphaltic pipe
coating. We have been informed by the Attorney General for the
State of Arizona, on behalf of the ADEQ, of its intent to assess
a civil penalty and require preventive actions by us to resolve
the NOV. Although the likely penalty and costs associated with
any preventive actions are unknown at this time, the ADEQ
proposed a fine of less than $1 million. We are in discussions
with the state in an effort to resolve this matter.
Kentucky Polychlorinated Biphenyls (PCB) Project. In
November 1988, the Kentucky Natural Resources and Environmental
Protection Cabinet 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 interim
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 remediation efforts, the agency may raise
additional technical issues or seek additional remediation work
and/or penalties in the future.
Natural Buttes. In May 2003, we met with the EPA to
discuss potential prevention of significant deterioration
violations due to a de-bottlenecking modification at CIG’s
facility. The EPA issued an Administrative Compliance Order and
we were in negotiations with the EPA as to the appropriate
penalty. In September 2005, we were informed that the EPA
referred this matter to the U.S. Department of Justice (DOJ). We
have since entered into a tolling agreement with the DOJ in
order to facilitate continuing settlement discussions.
Shoup Natural Gas Processing Plant. On December 16,2003, El Paso Field Services, L.P. received a Notice of
Enforcement (NOE) from the TCEQ concerning alleged Clean
Air Act violations at its Shoup, Texas plant. The alleged
violations pertained to emission limit, testing, reporting and
recordkeeping issues in 2001. On December 29, 2004, TCEQ
issued an Executive Director’s Preliminary Report and
Petition revising the allegations from the NOE and seeking a
penalty of $419,650. We answered the Petition disputing the
allegations and the penalty. We have reached an agreement to
resolve the matter by agreeing to pay a penalty of $106,439 and
conduct a supplemental environmental project costing $95,961. We
paid the penalty to TCEQ and will perform the supplemental
environmental project upon final execution of the settlement by
TCEQ.
Tucson Waste Management. In September 2004, we received a
NOV from the ADEQ for alleged failure to comply with waste
management regulations at EPNG’s Tucson compressor station.
EPNG fulfilled their request for information and documentation
related to the alleged noncompliance. This matter has been
referred to the Office of the Attorney General for the State of
Arizona, has informed us of its intent to require a civil
penalty to resolve the NOV. The amount of the penalty is unknown
at this time, but we are in discussions with the State in an
effort to resolve this matter.
ITEM 4.
SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED
STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Our common stock is traded on the New York Stock Exchange under
the symbol EP. As of February 24, 2006, we had 44,220
stockholders of record, which does not include beneficial owners
whose shares are held by a clearing agency, such as a broker
or bank.
The following table reflects the quarterly high and low sales
prices for our common stock based on the daily composite listing
of stock transactions for the New York Stock Exchange and the
cash dividends per share we declared in each quarter:
High
Low
Dividends
2005
Fourth Quarter
$
14.07
$
10.78
$
0.04
Third Quarter
14.16
11.13
0.04
Second Quarter
11.87
9.30
0.04
First Quarter
13.15
10.01
0.04
2004
Fourth Quarter
$
11.85
$
8.42
$
0.04
Third Quarter
9.20
7.37
0.04
Second Quarter
7.95
6.58
0.04
First Quarter
9.88
6.57
0.04
On February 14, 2006, we declared a quarterly dividend
of $0.04 per share of our common stock, payable on
April 3, 2006, to shareholders of record as of
March 3, 2006. Future dividends will depend on
business conditions, earnings, our cash requirements and other
relevant factors.
The terms of our 750,000 outstanding shares of 4.99% convertible
preferred stock prohibit the payment of dividends on our common
stock unless we have paid or set apart for payment all
accumulated and unpaid dividends on such preferred stock for all
preceding dividend periods. In addition, although our credit
facilities do not contain any direct restriction on the payment
of dividends, dividends are included as a fixed charge in the
calculation of our fixed charge coverage ratio under our credit
facilities. If our fixed charge ratio were to exceed the
permitted maximum level, our ability to pay additional dividends
would be restricted.
Odd-lot Sales Program
We have an odd-lot stock sales program available to stockholders
who own fewer than 100 shares of our common stock. This
voluntary program offers these stockholders a convenient method
to sell all of their
odd-lot shares at one
time without incurring any brokerage costs. We also have a
dividend reinvestment and common stock purchase plan available
to all of our common stockholders of record. This voluntary plan
provides our stockholders a convenient and economical means of
increasing their holdings in our common stock. Neither the
odd-lot program nor the dividend reinvestment and common stock
purchase plan have a termination date; however, we may suspend
either at any time. You should direct your inquiries to
Computershare Trust Company, N.A., our stock transfer agent at
1-877-453-1503.
The following historical selected financial data excludes our
south Louisiana gathering and processing operations, certain
international power operations, certain of our international
natural gas and oil production operations and our petroleum
markets and coal mining businesses, all of which are presented
as discontinued operations in our financial statements for all
periods. The selected financial data below should be read
together with Part II, Item 7, Management’s Discussion
and Analysis of Financial Condition and Results of Operations
and Part II, Item 8, Financial Statements and
Supplementary Data included in this Report on
Form 10-K. These
selected historical results are not necessarily indicative of
results to be expected in the future.
Decreases were a result of asset sales activities during these
periods. See Part II, Item 8, Financial Statements and
Supplementary Data, Note 3.
(2)
We incurred net losses of $0.4 billion in 2005,
$1.1 billion in 2004, $1.2 billion in 2003 and
$0.9 billion in 2002 related to gains, losses and
impairments of assets and equity investments as well as
restructuring charges related to industry changes and the
realignment of our businesses under our strategic plan. In 2003,
we also entered into an agreement in principle to settle claims
associated with the western energy crisis of 2000 and 2001. This
settlement resulted in charges of $59 million in 2005,
$104 million in 2003 and $899 million in 2002, before
income taxes. In addition, we incurred ceiling test charges of
$5 million, $5 million and $1.9 billion in 2003,
2002 and 2001 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 that totaled
approximately $1.5 billion. For further discussions of
events affecting comparability of our results in 2005, 2004 and
2003, see Part II, Item 8, Financial Statements and
Supplementary Data, Notes 2 through 5.
(3)
The increases in total long-term financing obligations in 2002
and 2003 was a result of the consolidations of our Chaparral and
Gemstone power investments, the restructuring of other financing
transactions, and in 2003, the reclassification of securities of
subsidiaries as a result of our adoption of SFAS No. 150,
Accounting for Certain Financial Instruments with
Characteristics of both Liabilities and Equity.
ITEM 7. 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 24.
During 2005, we discontinued our south Louisiana gathering and
processing operations (previously part of our Field Services
segment) and our international power operations at our Nejapa,
CEBU and East Asia Utilities power plants. Our operating results
for all periods presented reflect these operations as
discontinued.
Overview
Business Purpose and Description. Our business purpose is
to provide natural gas and related energy products in a safe,
efficient and dependable manner. We own North America’s
largest natural gas pipeline system and are a large independent
natural gas and oil producer. We also maintain an energy
marketing and trading business that supports the marketing of
our natural gas and oil production and the management of the
risk associated with commodity prices.
During the past several years we have sold nearly
$12 billion of assets to reduce debt and improve liquidity.
These businesses were either not core to our long-term
objectives or were performing below the expectations we had for
them at the time we made the investment. These divestitures have
resulted in significant financial losses through asset
impairments, realized losses on asset sales and reduction of
income from the businesses sold. We have sold substantially all
of our power and midstream assets and in 2006 we expect to be
substantially complete with the divestiture of our non-core
activities.
Drivers of our Profitability. Our future profitability
will be driven by a number of factors including our
ability to:
Pipelines
—
Expand our existing pipeline systems and gain access to new
supply areas and sources
—
Contract and recontract pipeline capacity with our customers
—
Successfully resolve our pending rate cases
—
Improve operational efficiency
Exploration and Production / Marketing and Trading
—
Increase our natural gas and oil proved reserve base and
production volumes through successful drilling programs or
acquisitions and efficient operations
—
Manage commodity price risk to optimize the amounts we receive
for the commodities we sell
Other
—
Successfully manage and complete the orderly exit of our legacy
assets and trading positions
—
Successfully resolve legacy contingencies
—
Reduce debt levels and interest costs
Summary of Operational/ Financial Performance in 2005.
During 2005, we continued to develop our core pipeline and
exploration and production operations. Our pipelines delivered
strong financial performance and our exploration and production
business stabilized. However, our earnings were negatively
impacted by substantial mark-to-market losses on our natural gas
and power derivative contracts due to commodity price increases,
impairment charges taken in conjunction with the divestiture of
non-core assets and accruals for potential obligations related
to various legacy matters. Additionally, the impact of
Hurricanes Katrina and Rita affected our pipeline and production
operations in the second half of 2005. Listed below and in the
individual segment results that follow is a further discussion
of the events affecting 2005 as well as progress in our key
areas of focus:
Finalized new rates at Southern Natural Gas Company.
Re-contracted or contracted available or expiring capacity.
Proceeded with several pipeline expansion projects in our
pipeline systems and at our Elba Island LNG facility.
Incurred significant damage to sections of our Gulf Coast and
offshore pipeline facilities due to Hurricanes Katrina and Rita.
These hurricanes also resulted in the shut-in of a significant
portion of gas supply on our systems.
E & P and Marketing and Trading
Completed the turnaround of our exploration and production
business by (i) stabilizing production rates, in spite of
incurring a reduction of our annual production of approximately
12 Bcfe as a result of Hurricanes Katrina and Rita and
(ii) growing our reserve base through our capital drilling
program and through four acquisitions of natural gas and oil
properties, including our acquisition of Medicine Bow.
Sold our natural gas and oil production at higher commodity
prices. However, we incurred substantial losses associated with
derivative contracts used to provide price protection on our
production and in settling hedges that had been put in place
during a lower price environment.
Assigned or terminated the majority of our power contracts, our
Cordova tolling agreement and the remaining derivative contracts
associated with our power contract restructuring operations.
Other
Completed or announced the divestiture of substantially all of
our remaining operations in our midstream, power and other
businesses, for total proceeds of approximately
$2.4 billion ($2.0 billion through December 31,2005). The net effect of these sales activities resulted in
substantial losses in 2005.
Furthered legal and contractual disputes, including those
related to our Brazilian power plants and domestic legal matters.
What to Expect Going Forward. For 2006, our pipeline
operations are positioned to provide steady operating results
based on the current levels of contracted capacity, expansion
plans and the status of rate and regulatory actions. Our
exploration and production operating results will be driven by
continued success of our drilling programs, our ability to
restore the remaining production that has been shut-in since
late September 2005 due to Hurricane Rita, our ability to manage
increases in the cost of production services and continued high
commodity prices. Additionally, a substantial portion of our
below-market derivative contracts are scheduled to expire in
2006, which will give us a greater opportunity to participate in
the higher commodity pricing environment.
In 2006, we will also strive to achieve our net debt (debt, less
cash) target of $14 billion by year-end, complete the sale
of our Asian and Central American power assets (substantially
all of which are under contract), pursue the divestiture of our
remaining domestic power assets and complete the resolution of
the issues related to our Brazilian power investments as well as
other remaining legacy issues.
Overview. The year 2005 was a turning point for us in
terms of our liquidity and capital resources. We began the year
focused on reducing liquidity concerns, strengthening our credit
metrics, selling a number of non-core assets and businesses and
reducing cash flow risks associated with a number of derivative
transactions put in place in prior years. During 2005, we
(i) completed asset sales for proceeds of
$2.0 billion, (ii) replaced some of our cash margining
requirements with letters of credit and (iii) entered into
or completed transactions to divest or reduce the risk of a
substantial portion of our power portfolio, including our
Cordova tolling agreement. While we continue to closely monitor
our liquidity, we believe the events of 2005 and those over the
past several years have allowed us to turn our attention in 2006
to expanding our core businesses of natural gas pipelines and
exploration and production.
Available Liquidity. We rely on cash generated from our
operations as a significant source of liquidity. We supplement
this, as needed, through the use of available credit facilities,
project and bank financings, proceeds from asset sales and the
issuance of debt, preferred securities and equity securities.
Our subsidiaries are a significant source of liquidity to us and
they participate in our cash management program to the extent
they are permitted under their financing agreements and
indentures. Under this program, depending on whether a
participating subsidiary has short-term cash surpluses or
requirements, we either provide cash to them or they provide
cash to us. 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. As of
December 31, 2005, we had available liquidity as follows:
Expected 2006 Cash Flows. In addition to our available
liquidity, we expect to generate significant operating cash flow
in 2006, which we will supplement with $1.2 billion of
expected proceeds from asset sales, including $0.4 billion
of cash upon completing the assignment of a majority of our
power derivative portfolio. We expect to also generate cash from
financing activities as needed, including the anticipated
issuance of common stock during the year.
In 2006, we expect to spend approximately $2.0 billion on
capital investments in our core pipeline and exploration and
production businesses, intended to both maintain and grow these
businesses. Our capital program for 2006 is forecasted as
follows (in billions):
Exploration and
Pipelines
Production
Total
Maintenance
$
0.5
$
0.7
$
1.2
Growth
0.5
0.3
0.8
Total
$
1.0
$
1.0
$
2.0
As of December 31, 2005, we had debt maturities for 2006
and 2007 of approximately $0.6 billion and
$0.9 billion. We also had approximately $0.6 billion
of zero-coupon debentures with a stated maturity of 2021 that
the holders required us to redeem for cash in February 2006. In
2007, we have approximately $0.6 billion of debt that the
holders can require us to redeem which, when combined with our
maturities, could require us to retire up to $1.4 billion
of debt in 2007.
Factors Impacting our Liquidity. Each of our existing and
future sources of cash is impacted by operational and financial
risks that influence the overall amount of cash generated and
the capital available to us. For example, cash generated by our
business operations may be impacted by, among other things,
changes in commodity prices and the extent to which we hedge our
natural gas and oil production, demands for our
commodities or services, success in recontracting existing
pipeline capacity contracts, drilling success and competition
from other providers or alternative energy sources. Collateral
demands or recovery of cash posted as collateral are impacted by
commodity prices, hedging levels and the credit quality of us
and our counterparties. Cash generated by future asset sales may
depend on the condition and location of the assets, the number
of interested buyers and our ability to successfully complete
the transaction. In addition, our future liquidity will be
impacted by our ability to access capital markets which may be
restricted due to our credit ratings and general market
conditions. The following is a further discussion of some of
these factors and their impact on us in 2005 or potential impact
in future periods.
•
Price Risk Management Activities. We enter into
derivative contracts to provide price protection on a portion of
our anticipated natural gas and oil production. Specifically,
our Exploration and Production and Marketing and Trading
segments use swap and option contracts to fix the amount of cash
we will receive on contracted volumes sold or to provide floor
or ceiling prices on these volumes. Floor prices are the minimum
cash prices to be received and ceiling prices are the maximum
cash prices to be received under the option contracts.
As
of December 31, 2005, a number of our swap contracts have
been designated as and are accounted for as accounting hedges.
However, our option contracts and certain other swap contracts
have not been designated as hedges and are therefore
marked-to-market through earnings each period. The accounting
method used for these contracts affects the timing of the income
or loss recognized on any individual contract in periods prior
to its settlement. However, through the settlement date, the
cumulative income or loss and cash flow impacts of a contract
are identical whether or not it is accounted for as a hedge or
is marked-to-market through earnings each period. For a further
discussion of the income impacts of these contracts, see our
Exploration and Production and Marketing and Trading
segments’ discussions of operating results. The following
table shows the contracted volumes and the minimum, maximum and
average cash prices that we will ultimately receive under these
contracts upon settlement or when the underlying production is
sold:
Swaps(1)
Floors(1)
Ceilings(1)
Average
Average
Average
Volumes
Price
Volumes
Price
Volumes
Price
Natural Gas
2006
110
$
4.89
120
$
7.00
60
$
9.50
2007
5
$
3.56
51
$
6.41
21
$
9.00
2008
5
$
3.42
18
$
6.00
18
$
10.00
2009-2012
16
$
3.74
17
$
6.00
17
$
8.75
Oil
2006
1,428
$
52.45
—
—
—
—
2007
192
$
35.15
1,009
$
55.00
1,009
$
60.38
2008
—
—
930
$
55.00
930
$
57.03
(1)
Volumes presented are TBtu for natural gas and MBbl for oil.
Prices presented are per MMBtu of natural gas and per Bbl
of oil.
•
Cash Margining Requirements on Derivative Contracts. A
substantial portion of our natural gas and oil derivative
contracts are at prices significantly below current market
prices, which has resulted in us posting substantial cash margin
deposits with the counterparties for the value of these
instruments. During 2005, we experienced volatility in the level
of margins posted, primarily resulting from the increase in
commodity prices as a result of Hurricanes Katrina and Rita. The
resulting increased commodity prices required us to post
$0.7 billion of additional cash margin deposits with
counterparties to our derivative contracts. In the fourth
quarter of 2005, $0.5 billion of margin deposits had been
returned to us due to a decrease in prices and settlements, but
these cash recoveries were largely offset by cash collateral
requirements relating to an agreement we entered into to assign
a majority of the contracts in our power portfolio to a third
party. In 2006, we expect approximately $1.2 billion of
collateral supported by both cash margin deposits and letters of
credit, to be returned to us, which includes the collateral that
we anticipate to receive upon completion of the assignment of the
positions related to our power portfolio in December 2005. If
commodity prices decrease, we could recover some of this amount
earlier than anticipated.
Any future increases in prices could have a significant impact
on our operating cash flows as additional margin deposits would
be required. Based on our derivative positions at
December 31, 2005, a $0.10/MMBtu increase in the price of
natural gas would result in an increase in our margin
requirements by $19 million for transactions that settle in
2006, $6 million for transactions that settle in 2007,
$5 million for transactions that settle in 2008 and
$13 million for transactions that settle in 2009 and
thereafter.
•
Hurricanes. Hurricanes Katrina and Rita impacted
virtually all producers and transporters doing business in the
Gulf of Mexico region. We incurred significant damage to our
property, including our transmission facilities. To date, we
estimate total repair costs related to these storms to be
approximately $457 million, of which $380 million is
claimed through our property damage insurer, which is a mutual
insurance company that is subject to individual and aggregate
loss limits by event. Based on the level of our claims and the
claims of all insured parties, we will not receive a portion of
the costs we will incur to repair our systems. Based on current
estimates, we anticipate that up to $164 million of capital
and maintenance expenditures claimed through our property damage
insurer will not be recovered due to these limits. Also, the
timing of reimbursements we will receive may occur later than
the capital expenditures on the damaged facilities, which may
increase our net capital expenditures for 2006 and could
negatively impact our estimates of cash flow.
Despite the impact of the factors above, we were able to largely
mitigate the effects of these items in 2005 through the
successful completion of a number of asset sales, the issuance
of $400 million of notes by CIG and by entering into a six
month, $400 million revolving borrowing base credit
agreement (with an initial borrowing capacity of
$300 million). We believe we will have sufficient liquidity
to meet our ongoing liquidity and cash needs through the
combination of available cash and borrowings under our credit
agreements. For a further discussion of risks that may impact
our cash flows, see discussion on page 32.
Capital Resources
Existing Financing Facilities. During 2005, we continued
to reduce our overall debt as part of our strategic plan. We
also issued $750 million of convertible preferred stock
primarily to satisfy our remaining obligations under the Western
Energy Settlement and to redeem the preferred stock of a
consolidated subsidiary. Our debt activity during 2005 was as
follows (in millions):
Related to the sale of Cedar Brakes I and II and Mohawk River
Funding II.
As of December 31, 2005, we have approximately
$0.3 billion of available capacity under several credit
facilities as described below:
•
$3 billion credit agreement. As of December 31,2005, we had borrowed $1.23 billion as a term loan and issued
approximately $1.7 billion of letters of credit under this
credit agreement. The agreement is collateralized by our equity
interests in TGP, EPNG, ANR, CIG, Southern Gas Storage Company
(which owns an interest in Bear Creek Storage Company) and ANR
Storage Company.
•
$500 million revolving credit facility. In August
2005, our subsidiary, EEPC, entered into and borrowed
$500 million under a five-year revolving credit facility
bearing interest at LIBOR plus
1.875%. Amounts borrowed were used to partially fund the
acquisition of Medicine Bow. The facility can be utilized for
funded borrowings or for the issuance of letters of credit and
is collateralized by certain EEPC natural gas and oil production
properties. Our current intent is to issue $500 million to
$800 million of our common stock to repay amounts borrowed
under this facility and for other purposes, the timing of which
is dependent on market conditions.
•
$400 million revolving credit agreement. In November
2005, we entered into a $400 million revolving borrowing
base credit agreement collateralized by certain natural gas and
oil production properties owned by one of our subsidiaries,
which is also a co-borrower. Under the agreement we have initial
borrowing availability of $300 million. The credit
agreement can be used for revolving credit loans or for the
issuance of letters of credit and will mature in May 2006. As of
December 31, 2005, there were no outstanding borrowings or
letters of credit issued under this agreement.
The availability of borrowings under these credit agreements and
our ability to incur additional debt is subject to various
conditions, which we currently meet. These conditions include
compliance with the financial covenants and ratios required by
those agreements, absence of default under the agreements and
continued accuracy of the representations and warranties
contained in the agreements. The financial coverage ratios under
our $3 billion credit agreement change over time. However,
these covenants currently require our Debt to Consolidated
EBITDA (as defined in the credit agreement) not to exceed 6.25
to 1 and our ratio of Consolidated EBITDA to interest expense
and dividends to be equal to or greater than 1.6 to 1, each as
defined in the credit agreement. As of December 31, 2005,
our ratio of Debt to Consolidated EBITDA was 4.79 to 1 and our
ratio of Consolidated EBITDA to interest expense and dividends
was 2.15 to 1.
Overview of Cash Flow Activities for 2005
Compared to 2004
For the years ended December 31, 2005 and 2004, our cash
flows are summarized as follows:
Payments to retire long-term debt and redeem preferred interests
1.7
2.5
Payments of revolving credit facilities
—
0.9
Redemption of preferred stock of a subsidiary
0.3
—
Dividends paid to common stockholders
0.1
0.1
Other
—
0.1
2.1
3.6
Total other cash outflows
4.9
5.4
Net change in cash
$
—
$
0.7
Cash from Continuing Operating Activities
During the year ended December 31, 2005, our net operating
cash flow decreased by $0.8 billion compared to 2004,
primarily due to activities associated with our derivative
contracts. During 2005, we paid approximately $0.4 billion
of settlements on our hedging derivatives and paid approximately
$0.4 billion to assign or terminate our Cordova power
contract and our contracts to supply power to Cedar Brakes I and
II. In addition, we received approximately $0.4 billion to
assign a portion of our power derivative portfolio to Morgan
Stanley, but were required to deposit $0.4 billion of cash
margin with them related to offsetting contracts we entered into
until we complete the assignment. We expect to receive this cash
margin back in the first half of 2006 when the original
contracts are assigned and the offsetting contracts are
terminated. Our cash margining requirements also increased on
our other derivative contracts by an additional
$0.3 billion in 2005 due to the impact of commodity price
increases in 2005.
The net cash outflows of $1.1 billion associated with these
derivatives and their related cash margin deposits were
partially offset by a $0.3 billion increase in cash flows
from our other operating activities, including a
$0.2 billion decrease in the amount of our payments
associated with the Western Energy Settlement in 2005 as
compared to 2004.
Cash From Continuing Investing Activities
For the year ended December 31, 2005, net cash used in our
continuing investing activities was $1.1 billion. Among
other items, during the year we received net proceeds of
approximately $0.6 billion from sales of our power assets
as well as $0.7 billion from the sales of our general
partnership interests in Enterprise and various other assets in
our Field Services segment.
Our 2005 capital expenditures, including acquisitions, were as
follows (in billions):
Production exploration, development and acquisition expenditures
$
1.8
Pipeline expansion, maintenance and integrity projects
Net cash provided by our continuing financing activities was
$0.8 billion for the year ended December 31, 2005. We
generated cash of $2.3 billion primarily from the issuance
of $0.7 billion of convertible preferred stock and
$1.6 billion of long-term debt. We also had
$0.6 billion of cash contributed by our discontinued
operations primarily as a result of proceeds from sales of these
assets. Offsetting our cash inflows were payments of
$1.7 billion to retire long-term third party debt and
$0.3 billion to redeem the cumulative preferred stock of a
subsidiary, El Paso Tennessee Pipeline Co. (EPTP).
Additionally, we paid dividends of $0.1 billion during 2005.
Off-Balance Sheet Arrangements
In the course of our business activities, we enter into a
variety of financing arrangements and contractual obligations.
Certain of these arrangements are often referred to as
off-balance sheet arrangements and include guarantees, letters
of credit and other interests in variable interest entities.
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 purchase services from a third
party and then fails to do so, we would be required to either
purchase these services or make payments to the third party to
compensate them for any losses they incurred because of this
non-performance. We also periodically provide indemnification
arrangements related to assets or businesses we have sold. These
arrangements include, but are not limited to, indemnifications
for income taxes, the resolution of existing disputes,
environmental matters and necessary expenditures to ensure the
safety and integrity of the assets sold.
We record accruals for our guaranty and indemnification
arrangements at their fair value when they are issued and
subsequently adjust those accruals when we believe it is both
probable that we will have to pay amounts under the arrangements
and those amounts can be estimated. As of December 31,2005, we had a liability of $91 million related to our
guarantees and indemnification arrangements. These arrangements
had a total stated exposure of $233 million, for which we
are indemnified by third parties for $29 million. These
amounts exclude guarantees for which we have issued related
letters of credit discussed below.
In addition to the exposures described above, we received a
ruling from a trial court, which was upheld on appeal, that we
are required to indemnify a third party for benefits paid to a
closed group of retirees of one of our former subsidiaries. We
have a liability of approximately $380 million associated
with our estimated exposure under this matter as of
December 31, 2005. For a further discussion of this matter,
see Part II, Item 8, Financial Statements and
Supplementary Data, Note 16.
Letters of Credit
We enter into letters of credit in the ordinary course of our
operations as well as periodically in conjunction with sales of
assets or businesses. As of December 31, 2005, we had
outstanding letters of credit of approximately
$2.0 billion, including $1.2 billion of letters of
credit securing our recorded obligations related to price risk
management activities.
Interests in Variable Interest Entities
We have significant interests in a number of variable interest
entities, primarily investments held in our Power segment. A
variable interest entity is a legal entity whose equity owners
do not have sufficient equity at risk or a controlling financial
interest in the entity. We are required to consolidate such
entities if we are allocated the majority of the variable
interest entity’s losses or return, including fees paid by
the entity. If we
are not the primary beneficiary of the variable interest
entity’s operations, consolidation is not required; as of
December 31, 2005, we do not consolidate approximately 17
variable interest entities for this reason. For additional
information on these entities, including our related interests
in those entities, see Part II, Item 8, Financial
Statements and Supplementary Data, Note 21, Investments in,
Earnings from and Transactions with Unconsolidated Affiliates.
Contractual Obligations
We are party to various contractual obligations, which include
the off-balance sheet arrangements described above. A portion of
these obligations are reflected in our financial statements,
such as short-term and long-term debt and other accrued
liabilities, while other obligations, such as demand charges
under transportation and storage commitments and operating
leases and capital commitments, are not reflected on our balance
sheet. The following table summarizes our contractual cash
obligations as of December 31, 2005, for each of the years
presented (all amounts are undiscounted):
2006
2007
2008
2009
2010
Thereafter
Total
(In millions)
Long-term financing
obligations:(1)
Principal
$
1,211
$
781
$
676
$
2,479
$
2,058
$
11,085
$
18,290
Interest
1,316
1,281
1,212
1,145
945
10,939
16,838
Other contractual
liabilities(2)
101
47
32
15
12
50
257
Operating
leases(3)
81
71
14
11
7
33
217
Other contractual commitments and purchase
obligations:(4)
Transportation and
storage(5)
112
100
94
91
89
368
854
Commodity
purchases(6)
33
32
21
14
14
28
142
Other(7)
377
48
52
22
22
41
562
Total contractual obligations
$
3,231
$
2,360
$
2,101
$
3,777
$
3,147
$
22,544
$
37,160
(1)
See Part II, Item 8, Financial Statements and
Supplementary Data, Note 14.
(2)
Includes contractual, environmental and other obligations
included in other current and noncurrent liabilities in our
balance sheet. Excludes expected contributions to our pension
and other postretirement benefit plans of $61 million in
2006 and $176 million for the four year period ended
December 31, 2010, because these expected contributions are
not contractually required. Also excludes potential amounts due
under an indemnification of a former subsidiary for benefits
being paid to a closed group of retirees. We have a liability of
approximately $380 million related to the litigation
associated with this matter as of December 31, 2005.
(3)
See Part II, Item 8, Financial Statements and
Supplementary Data, Note 16.
(4)
Other contractual commitments and purchase obligations are
defined as legally enforceable agreements to purchase goods or
services that have fixed or minimum quantities and fixed or
minimum variable price provisions, and that detail approximate
timing of the underlying obligations.
(5)
These are commitments for demand charges for firm access to
natural gas transportation and storage capacity.
(6)
Includes purchase commitments for natural gas and power.
(7)
Includes commitments for drilling and seismic activities in our
exploration and production operations and various other
maintenance, engineering, procurement and construction
contracts, as well as service and license agreements used by our
other operations.
We use derivative financial instruments in our Exploration and
Production and Marketing and Trading segments to manage the
price risk of commodities. In the tables below, derivatives
designated as hedges primarily consist of swaps used to hedge
natural gas production. Other commodity-based derivative
contracts relate to derivative contracts not designated as
hedges, such as options, swaps, tolling agreements and other
natural gas and power purchase and supply contracts, our
historical energy trading activities and our power contract
restructuring activities (which were fully disposed of in 2004
and 2005).
The following table details the fair value of our
commodity-based derivative contracts by year of maturity and
valuation methodology as of December 31, 2005:
Maturity
Maturity
Maturity
Maturity
Maturity
Total
Less Than
1 to 3
4 to 5
6 to 10
Beyond
Fair
1 Year
Years
Years
Years
10 Years
Value
(In millions)
Derivatives designated as
hedges(1)
Assets
$
31
$
—
$
—
$
—
$
—
$
31
Liabilities
(570
)
(62
)
(34
)
(18
)
—
(684
)
Total derivatives designated as hedges
(539
)
(62
)
(34
)
(18
)
—
(653
)
Other commodity-based derivatives
Exchange-traded
positions(1)
Assets
191
360
158
—
—
709
Liabilities
(155
)
(1
)
—
—
—
(156
)
Non-exchange traded
positions(2)
Assets
414
467
229
135
16
1,261
Liabilities
(693
)
(979
)
(501
)
(377
)
(27
)
(2,577
)
Total other commodity-based derivatives
(243
)
(153
)
(114
)
(242
)
(11
)
(763
)
Total commodity-based derivatives
$
(782
)
$
(215
)
$
(148
)
$
(260
)
$
(11
)
$
(1,416
)
(1)
These positions are traded on active exchanges such as the New
York Mercantile Exchange, the International Petroleum Exchange
and the London Clearinghouse.
(2)
During the first quarter of 2006, we assigned our contracts to
supply natural gas to the Jacksonville Electric Authority and
The City of Lakeland for no cash consideration. We will record a
gain of approximately $50 million related to this
assignment in 2006.
Represents the fair value of the contracts on the day they were
designated as hedges.
(2)
Amounts are net of premiums received.
(3)
Includes derivative contracts sold in conjunction with the sales
of Cedar Brakes I and II and Mohawk River Funding II
and amounts paid in conjunction with the assignment of our
Cordova tolling agreement. In connection with the sales of Cedar
Brakes I and II and Mohawk River Funding II, we also
assigned or terminated a number of our other commodity-based
derivatives.
(4)
The loss of hedge accounting was a result of a reduction of
anticipated production volumes.
Fair Value of Contract Settlements. The fair value of
contract settlements during the period represents the estimated
amounts of derivative contracts settled through physical
delivery of a commodity or by a claim to cash as accounts
receivable or payable. The fair value of contract settlements
also includes physical or financial contract terminations due to
counterparty bankruptcies and the sale or settlement of
derivative contracts through early termination or through the
sale of the entities that own these contracts.
Changes in Fair Value of Contracts. 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 or acquisition, until their settlement,
early termination or, if not settled or terminated, until the
end of the period.
Assignment of Power Contracts. In December 2005, we
entered into an agreement to assign the majority of our power
derivative assets to Morgan Stanley. The assignment requires the
consent of existing third parties before the contracts can be
transferred to Morgan Stanley. Until the assignment is
finalized, we entered into offsetting liability contracts with
Morgan Stanley to eliminate the commodity price risk associated
with the contracts being assigned. We received total proceeds of
$442 million to enter into these offsetting contracts and
deposited a similar amount of cash margin. The amount we
received approximated the value we would have received if we had
directly sold our power derivative assets. We anticipate that
this assignment will be completed in the first half of 2006.
Results of Operations
Overview
As of December 31, 2005, our operating business segments
were Pipelines, Exploration and Production, Marketing and
Trading, Power and Field Services. These segments provide a
variety of energy products and services. They are managed
separately and each requires different technology and marketing
strategies. Our
corporate activities include our general and administrative
functions, as well as a telecommunications business and various
other contracts and assets.
Our management uses earnings before interest expense 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 cumulative effect of accounting
changes, (ii) income taxes, (iii) interest and debt
expense and (iv) distributions on preferred interests of
consolidated affiliates. Our businesses consist of consolidated
operations as well as investments in unconsolidated affiliates.
We exclude interest and debt expense and distributions on
preferred interests of consolidated subsidiaries from this
measure so that investors may evaluate our operating results
independently from our financing methods or capital structure.
We believe EBIT is useful to our investors because it allows
them to more effectively evaluate the operating performance of
both our consolidated businesses and our unconsolidated
investments using the same performance measure analyzed
internally by our management. EBIT may not be comparable to
measurements used by other companies. Additionally, EBIT should
be considered in conjunction with net income and other
performance measures such as operating income or operating cash
flow.
Below is a reconciliation of our EBIT (by segment) to our
consolidated net loss for each of the three years ended
December 31:
2005
2004
2003
(In millions)
Segment
Pipelines
$
1,226
$
1,331
$
1,234
Exploration and Production
696
734
1,091
Marketing and Trading
(837
)
(539
)
(809
)
Power
(451
)
(576
)
(40
)
Field Services
285
84
129
Segment EBIT
919
1,034
1,605
Corporate and other
(521
)
(217
)
(852
)
Consolidated EBIT
398
817
753
Interest and debt expense
(1,380
)
(1,607
)
(1,790
)
Distributions on preferred interests of consolidated subsidiaries
(9
)
(25
)
(52
)
Income taxes
289
(14
)
484
Loss from continuing operations
(702
)
(829
)
(605
)
Discontinued operations, net of income taxes
100
(118
)
(1,269
)
Cumulative effect of accounting changes, net of income taxes
(4
)
—
(9
)
Net loss
$
(606
)
$
(947
)
$
(1,883
)
The discussions that follow provide additional analysis of the
year over year results of each of our business segments, our
corporate activities and other income statement items.
Our Pipelines segment consists of interstate natural gas
transmission, storage and LNG terminalling related services,
primarily in the United States. We face varying degrees of
competition in this segment from other existing and proposed
pipelines and proposed LNG facilities, as well as from
alternative energy sources used to generate electricity, such as
hydroelectric power, nuclear, coal and fuel oil.
The FERC regulates the rates we can charge our customers. These
rates are a function of the cost of providing services to our
customers, including a reasonable return on our invested
capital. As a result, our revenues and financial results have
historically been relatively stable. However, they can be
subject to volatility due to factors such as changes in natural
gas prices and market conditions, regulatory actions,
competition, the creditworthiness of our customers and weather.
In 2005, 79 percent of our revenues were attributable to
reservation charges paid by firm customers. Reservation charges
are paid regardless of volumes transported or stored. The
remaining 21 percent were variable. We also experience
earnings volatility when the amount of natural gas utilized in
operations differs from the amounts we receive for that purpose.
Historically, much of our business was conducted through
long-term contracts with customers. However over the past
several years 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. This shift, which can increase the
volatility of our revenues, 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 power plant markets.
In addition, our ability to extend existing customer contracts
or remarket 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 renegotiated contracts will be
affected by current prices, competitive conditions and judgments
concerning future market trends and volatility. Subject to
regulatory requirements, we attempt to re-contract or re-market
our capacity at the maximum rates allowed under our tariffs,
although, at times, we discount these rates to remain
competitive. The level of discount varies for each of our
pipeline systems. Our existing contracts mature at various times
and in varying amounts of throughput capacity. We continue to
manage our recontracting process to limit the risk of
significant impacts on our revenues. The weighted average
remaining contract term for active contracts is approximately
five years as of December 31, 2005. Below is the expiration
schedule for firm transportation contracts executed as of
December 31, 2005, including those whose terms begin in
2006 or later.
Below are the operating results and analysis of these results
for our Pipelines segment for each of the three years ended
December 31:
2005
2004
2003
(In millions, except volume
amounts)
Operating revenues
$
2,783
$
2,651
$
2,647
Operating expenses
(1,764
)
(1,522
)
(1,584
)
Operating income
1,019
1,129
1,063
Other income
207
202
171
EBIT
$
1,226
$
1,331
$
1,234
Throughput volumes
(BBtu/d)(1)
TGP
4,493
4,519
4,760
EPNG and MPC
4,214
4,235
4,066
ANR
4,100
4,067
4,232
CIG, WIC and CPG
3,641
2,795
2,743
SNG
1,984
2,163
2,101
Equity investments (our ownership share)
2,833
2,798
2,433
Total throughput
21,265
20,577
20,335
(1)
Volumes exclude intrasegment activities.
The table below and discussion that follows detail the impact on
EBIT of significant events in 2005 compared with 2004 and 2004
as compared with 2003. We have also provided an outlook on
events that may affect our operations in the future.
During the three years ended December 31, 2005, we
completed a number of expansion projects that have generated or
will generate new sources of revenues, the more significant of
which were our CPG pipeline expansion, our ANR Westleg, Eastleg
and Northleg Expansions, our SNG south System Expansions and our
TGP South Texas Expansion. The CPG pipeline increased our
revenues by $60 million and overall EBIT by
$27 million during 2005 compared to 2004. Phase II of
the CPG pipeline, which added 181,000 Mcf/d of capacity,
was placed in service in December 2005. Overall, our expansions
during this time period added approximately 3,253 MMcf/d to
our overall pipeline system.
Currently, we have a number of pipeline expansion projects
underway, which we are in various stages of certification and
approval. The following are those expansion projects that have
been approved by the FERC and that have been recently completed
or are in various stages of completion:
Anticipated Completion
Estimated
Project
or In-Service Date
Cost
Estimated Future Revenues
ANR
Wisconsin 2006
November 2006
$48 million
2006 - $1 million; 2007 - $8 million;
Thereafter - $11 million annually
SNG
Elba Island LNG facility
February 2006
$157 million
$29 million annually
WIC
Piceance Basin
March 2006
$132 million
2006 - $11 million; 2007 - $19 million;
Thereafter - $21 million annually
CIG
Raton Basin
September and
$54 million
2006 - $9 million;
December 2005
Thereafter - $13 million annually
TGP
Northeast ConneXion- NY/NJ
November 2006
$39 million
2006 - $2 million;
Thereafter - $11 annually
Triple T
August 2006
$10 million(1)
(2)
Louisiana Deepwater
October 2006
$11 million
(2)
(1)
An additional $8 million of costs will be funded by ANR.
(2)
Revenues for these projects will be based on throughput levels
as natural gas reserves are developed. We expect these revenues
to commence in 2006 for the Triple T expansion and in 2007
for the Louisiana Deepwater Link expansion.
During 2004, we modified, terminated, or settled several
contracts on several of our pipeline systems, resulting in a
$56 million reduction in EBIT compared with 2003. In 2005,
these transactions improved EBIT by $49 million compared
with 2004. Below is a further discussion of these significant
events:
ANR. In 2005, ANR (i) completed the restructuring of
its transportation contracts with one of its shippers on its
Southwest and Southeast Legs as well as a related gathering
contract, which increased revenues and EBIT by $29 million
in 2005 and (ii) settled two transportation agreements
previously rejected in the bankruptcy of USGen New England,
Inc., which increased EBIT by $15 million but will have no
ongoing impact. In 2004, ANR (i) renegotiated or
restructured several contracts including its contracts with We
Energies, which contributed to the decrease in its revenues by
$36 million in 2004 and (ii) terminated the Dakota
gasification facility contract on its system, which resulted in
lower operating revenues and lower operating expenses during
2004, without a significant overall impact on operating income
and EBIT.
EPNG. In 2005, EPNG benefited from the termination of the
restrictions in 2004 on remarketing expiring capacity contracts,
which increased revenues and EBIT by $5 million during 2005
as compared to 2004. In 2004, EPNG experienced a reduction in
revenues of $24 million due to the expiration at the end of
2003 of its historical risk sharing provisions, which had
provided revenues, net of a sharing obligation.
In December 2004, Southern California Gas Company (SoCal)
acquired approximately 750 MMcf/d of capacity on
EPNG’s system under new contracts with various terms
extending from 2009 to 2011 commencing September 2006. We have
executed the relevant transportation service agreements
with SoCal. Effective September 2006, approximately
500 MMcf/d of capacity formerly held by SoCal to serve its
noncore customers will be available for recontracting. We are
remarketing the remaining expiring capacity to serve
SoCal’s non-core customers or to serve new markets. We are
also pursuing the option of using some or all of this capacity
to provide new services to existing markets. At this time, we
are uncertain how much of this existing capacity will be
recontracted, and if so at what rates.
Gas Not Used in Operations, Revaluations, Processing Revenues
and Other Natural Gas Sales. For some of our regulated
pipelines, the financial impact of operational gas, net of gas
used in operations is based on the amount of natural gas we are
allowed to retain and dispose of according to our tariffs or
FERC orders, relative to the amount of gas we use for operating
purposes and the price of natural gas. The difference between
the amount retained and the amount used in operations results in
revenues or expenses to us, which are driven by volumes and
prices during a given period. In addition, the timing of these
revenues or expenses can vary based on each pipeline’s
ability to sell or otherwise realize the value of gas not used
in operations. The level of retained gas on our systems relative
to amounts we use are based on factors such as system
throughput, facility enhancements and the ability to operate the
pipeline in the most efficient and safe manner. Additionally,
several of our pipelines have encroachments against their system
gas supply and net imbalances to shippers that are impacted by
changing gas prices each period. In 2005, higher gas prices
caused an increase in our obligation to replace system gas and
settle gas imbalances in the future, resulting in an unfavorable
impact on our operating results. Our pipelines also retained
lower volumes of gas not used in operations during 2005. These
unfavorable impacts were partially offset by the sale of higher
volumes of natural gas made available by storage realignment
projects in 2005 versus 2004. During 2003 and 2004, higher
volumes of gas not utilized for operations and a steadily
increasing natural gas price environment resulted in a favorable
impact on our operating results in 2004 versus 2003. We
anticipate that the overall activity in this area will continue
to vary based on factors such as rate actions, some of which
have already been implemented, the efficiency of our pipeline
operations, natural gas prices and other factors.
Hurricanes Katrina and Rita. Hurricanes Katrina and Rita
had substantial impacts on offshore producers in the Gulf of
Mexico Region, resulting in the shut-in of a significant portion
of offshore production in the affected areas. In August 2005,
Hurricane Katrina resulted in the initial shut-in of
approximately 3 Bcf/d of gas supply on our pipeline
systems. Prior to Hurricane Rita in September 2005, we had
approximately of 1.2 Bcf/d of natural gas supply shut-in.
Hurricane Rita resulted in an incremental reduction in supply of
approximately 2.9 Bcf/d on our systems. Currently, we have
approximately 0.6 Bcf/d of natural gas supply shut-in on our
pipeline systems. The timing of these volumes becoming available
is dependent on the completion of pipeline and compressor
station repairs, the ongoing evaluation of producers’
platforms upstream of our pipelines and potential processing
constraints if third-party processing facilities are not
available. Furthermore, these operational constraints have
impacted the efficiency of our pipeline operations. The
hurricanes adversely affected our EBIT in the fourth quarter of
2005 by $42 million because of their impact on certain
usage revenues, estimated unreimbursed repair costs, increased
operating costs and lost revenues associated with reductions in
service. The adverse effect on our results may continue into
early 2006.
General and Administrative Expenses During the year ended
December 31, 2005, our general and administrative costs
were higher than in 2004, primarily due to an increase in direct
payroll related benefits for our employees of $42 million,
higher legal and insurance costs of $14 million, and higher
corporate overhead allocations from El Paso of
$2 million. El Paso’s allocation to us increased
in 2005 based on the estimated level of resources devoted to our
segment’s operations and the relative size of our EBIT,
gross property and payroll as compared to the consolidated
totals.
Operating Costs. Over the past two years, we incurred
higher costs for compressor engine repair and preventative
maintenance, lowering of lines and pipeline integrity testing.
Additionally, in 2005 we recorded higher legal and environmental
reserves. In 2003, El Paso finalized the Western Energy
settlement and EPNG recorded charges of $140 million in
operating expenses related to this settlement.
Beginning in 2006, we will be required under a FERC accounting
release to expense certain costs incurred in connection with our
pipeline integrity programs, instead of our current practice of
capitalizing them as part of our property, plant and equipment.
We currently estimate that we will be required to expense
an additional amount of pipeline integrity costs under this
accounting release in the range of approximately
$26 million to $41 million annually.
Impairments of Pipeline Development Projects. During the
fourth quarter of 2005, we discontinued a portion of our
Seafarer project and the entirety of our Blue Atlantic
development project due to changing market conditions.
Other Regulatory Matters. The following discussion
describes certain regulatory matters that have impacted our
operations or will have an impact on our operations beginning in
2006.
In 2003, we re-applied SFAS No. 71, Accounting for
the Effects of Certain Types of Regulation, on our CIG and
WIC systems, resulting in income from recording the regulatory
assets of these systems. SFAS No. 71 requires a
company to capitalize items that will be considered in future
rate proceedings. Upon re-application, we recorded
$18 million in income resulting from the capitalization of
those items that we believe will be considered in CIG’s and
WIC’s future rate cases. At the same time CIG and WIC
re-applied SFAS No. 71, they adopted the FERC
depreciation rate for their regulated plant and equipment. This
change resulted in an annual increase in depreciation expense of
approximately $9 million. As of December 31, 2004, ANR
Storage Company re-applied SFAS No. 71, which had an
immaterial impact, and also adopted the FERC depreciation rate,
which will result in future depreciation expense increases of
approximately $4 million annually.
Rate Cases. Our pipeline systems periodically file for
changes in their rates, which are subject to the approval of the
FERC. Changes in rates and other tariff provisions resulting
from these regulatory proceedings have the potential to
positively or negatively impact our profitability. Currently,
certain of our pipelines have no requirements to file new rate
cases and expect to continue operating under their existing
rates. However, certain other pipelines listed below are
currently in rate proceedings or have upcoming rate actions.
•
EPNG — Filed a rate case in June 2005 proposing an
increase in revenues of 10.6 percent or $56 million
over current tariff rates and also proposing new services and
revisions to certain terms and conditions of existing services,
including the adoption of a fuel tracking mechanism. On
January 1, 2006, the rates, which are subject to refund,
and the fuel tracking mechanism became effective. Additionally,
settlement discussions with major customers are underway and
implementation of new services is scheduled for April 1,2006.
•
CIG — Will be required to file for new rates to be
effective in the fourth quarter of 2006.
•
MPC — Is expected to file for new rates that would be
effective March 2007.
Our Exploration and Production segment conducts our natural gas
and oil exploration and production activities. Our operating
results in this segment 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 minimize our
total administrative costs.
We manage this business with the goal to create shareholder
value through disciplined capital allocation, cost control and
portfolio management. Our natural gas and oil reserve portfolio
blends slower decline rate, typically longer lived assets in our
Onshore region with steeper decline rate, shorter lived assets
in our Texas Gulf Coast and Gulf of Mexico and south Louisiana
regions. We believe the combination of our assets in these
regions provides significant near-term cash flow while providing
consistent opportunities for high-return investments. During the
past two years, we have dedicated substantial resources and
management effort to stabilizing and improving this business. We
believe this effort has been largely successful. Our efforts
have been focused on the following:
Goal or Strategy
Actions Taken
Results
Improve capital
discipline and
returns
Created a standard economic measure known as PVR (present value
ratio) to evaluate project success. This ratio represents the
present value of future after-tax cash flows discounted at 12%
over total investment. Our target ratio is 1.15, which simply
means that every $1.00 invested returns $1.15 on an after-tax,
discounted basis over the life of the project. A rigorous
post-spending analysis is prepared and a monthly scorecard for
each operating region is evaluated by management.
Our 2005 actual post-drill PVR was 1.19 using a $4.75/MMBtu plan
price compared to our pre-drill PVR target of 1.23. Our PVR was
2.11 using 2005 realized prices with the year-end strip prices
thereafter.
Improve portfolio management
Allocated a greater percentage of capital expenditures to
onshore exploration and development opportunities.
Acquired Medicine Bow to expand our presence in the Rockies and
east Texas and GMT Energy Corporation to expand our presence in
east Texas.
Divested certain high cost onshore and offshore properties with
high abandonment liabilities and only 25 Bcfe of proved
reserves.
Implemented a consistent risk analysis process and reduced
capital exposure to deep drilling. Utilized comprehensive
mapping with life-of-property exploitation plans.
Our onshore reserves increased from 55 percent of our total
reserves at year end 2004 to 60 percent of our total
reserves at year end 2005. Our unconventional coal seam reserves
comprise approximately one third of our total reserve base.
These longer-life reserves form a stable production base and
should make our business more predictable.
The Medicine Bow acquisition accelerated the changes in our
portfolio since over 80 percent of the proved reserves overlap
with our core onshore areas.
Improve our production mix
Increased our onshore production through drilling activities and
our acquisition program, including the acquisition of our equity
investment in Four Star.
From 2004 to 2005, total onshore production grew as a percentage
of total production. A substantial portion of the increase was
organic growth as opposed to acquisitions.
Grow our
reserves base
Created a balanced acquisition and drilling program that focused
on increasing long life reserves while converting proved
undeveloped reserves (PUD) to producing developed reserves.
During 2005, we produced 271 Bcfe (excluding our equity
share of Four Star production of 9 Bcfe) while our drilling
and acquisition programs generated net additions of 505 Bcfe
(excluding our equity share of Four Star of 262 Bcfe). We also
increased our reserves over production ratio from 7.2 years
to 8.9 years. In 2005, we developed 22 percent of our total
2004 year-end PUD reserves.
Build an inventory
of attractive
lower risk
drilling prospects
Improved our ability to grow by creating a regional structure
that leverages a strong acreage position in key producing
basins.
Utilized detailed mapping and reservoir analysis and a
standardized risk measurement system to identify drilling and
workover or recompletion opportunities.
Completed $1.1 billion of acquisitions that complement our
existing core operations.
Identified 629 wells to be drilled in 2006 with 2,620 more in
future years at a $5.50/MMBtu price forecast for natural gas
that generates a PVR of 1.15 or greater.
Created a balanced inventory along the entire risk spectrum with
low risk development prospects coupled with high potential
offshore exploration and international oil opportunities.
Significant Operational Factors Affecting the Year Ended
December 31, 2005
•
Higher realized prices. We benefited from a strong
commodity pricing environment in 2005. Realized natural gas
prices, which include the impact of our hedges, increased
10 percent while oil, condensate and NGL prices increased
32 percent compared to 2004.
•
Average daily production of 743 MMcfe/d (excluding
24 MMcfe/d from our equity investment in Four Star).
Our average daily equivalent production decreased from 2004
primarily due to several hurricanes in the Gulf of Mexico, which
caused us to shut in significant volumes in our Gulf of Mexico
and south Louisiana region. We have continued to increase
production volumes in our Onshore region as a result of our
successful drilling and acquisition programs. However,
production volumes in our Gulf of Mexico and south Louisiana
region, adjusted for the impact of hurricanes, and Texas Gulf
Coast region continued to gradually decrease as drilling
programs and overall lower capital spending in those areas have
not been sufficient to offset the historically steep production
decline rates in these regions.
•
Impact of hurricanes on production volumes. The Gulf
Coast hurricanes negatively impacted our annual production by
approximately 12 Bcfe or 34 MMcfe/d during 2005. Prior
to Hurricane Katrina in late August 2005, our production from
the Gulf of Mexico was about 205 MMcfe/d. A substantial
portion of our shut-in production from Hurricane Katrina was
brought back online during September 2005 to a level of about
170 MMcfe/d just prior to Hurricane Rita. We continue to
experience substantial shut-in volumes from Hurricane Rita;
however, Gulf of Mexico production levels have returned to
approximately 130 MMcfe/d at December 31, 2005 and
currently remain at that level. We expect the majority of the
remaining operated Gulf of Mexico production to come back online
during the first half of 2006. Also impacted were our onshore
Texas Gulf Coast and Arklatex areas, where damage from Hurricane
Rita initially impacted approximately 60 MMcfe/d of
production. However, production was restored within a few days
of the event.
•
Drilling results. In 2005, we participated in drilling a
total of 483 gross wells with a 99 percent success
rate and a PVR of 1.19 based on a plan price of $4.75/MMBtu. Our
drilling results by region were as follows:
Onshore region. We experienced a 99 percent success
rate on 454 gross wells drilled during 2005, resulting in
production growth in the Rockies, Raton, north Louisiana and
Arkoma operating areas.
Texas Gulf Coast region. We experienced significant
improvement in the second half of the year achieving an
89 percent success rate on 18 gross wells drilled
during 2005. New Wilcox production was established from
exploration at the Renger Field in Lavaca County, Texas. In
addition, the shallow Vicksburg development program in Starr and
Hidalgo Counties, Texas provided consistent results adding
production on existing base properties.
Gulf of Mexico and south Louisiana region. Overall, we
experienced a 73 percent success rate on 11 gross
wells drilled during 2005. During the year, we announced our
participation in two deep shelf discovery wells at West Cameron
Blocks 75 and 62 in the Gulf of Mexico. These projects are
expected to come on line during the first quarter of 2006 and
produce 20 MMcfe/d or higher, net
to our interest. We also participated in a third discovery in
2005 through a 25 percent working interest in a well
drilled at Long Point in Vermillion Parish, Louisiana, which
tested at over 40 MMcfe/d, and is expected to come on line
during the second quarter 2006.
Outlook for 2006
For 2006, we also expect:
•
Capital expenditures of approximately $1 billion, excluding
acquisitions;
•
Average daily production volumes for the year of approximately
755 MMcfe/d to 780 MMcfe/d, which excludes approximately 70
MMcfe/d from our equity interest in Four Star. Our daily
production volumes in Brazil averaged approximately
53 MMcfe/d during 2005. Our Brazilian production was
reduced by about 30 MMcfe/d in February 2006 due to a
contractual decrease in our interest from 79 percent to 35
percent in UnoPaso’s production in Brazil as a result of
achieving payout;
•
Average cash operating costs of approximately $1.64/Mcfe to
$1.71/Mcfe for the year;
•
Domestic unit of production depletion rate of $2.22/Mcfe in the
first quarter of 2006. This compares to $2.16/Mcfe in the fourth
quarter of 2005. The increase is expected due to higher finding
and development costs and the costs of acquired reserves;
•
Brazilian unit of production depletion rate of $1.96/ Mcfe in
the first quarter of 2006. This compares to $2.39/ Mcfe in the
fourth quarter of 2005; and
•
Significant industry-wide increases in drilling and oilfield
service costs that will require constant monitoring of capital
spending programs and a mitigation effort designed to manage and
improve field efficiency.
Production Hedge Position
As part of our overall strategy, we hedge our natural gas and
oil production to stabilize cash flows, reduce the risk of
downward commodity price movements on our sales and to protect
the economic assumptions associated with our capital investment
programs. Our Marketing and Trading segment has also entered
into other derivative contracts that are designed to provide
price protection to the overall company, which is discussed
further in that segment’s operating results. Our hedging
positions are regularly monitored by senior management and a
committee of the Board of Directors. Because this strategy only
partially reduces our exposure to downward movements in
commodity prices, our reported results of operations, financial
position and cash flows can be impacted significantly by
movements in commodity prices from period to period. Adjustments
to our hedging strategy and the decision to enter into new
positions or to alter existing positions are made at the
corporate level based on the goals of the overall company.
During 2005, we experienced a significant decrease in the fair
value of our hedging derivatives. These fair value decreases
were generally deferred in our accumulated other comprehensive
income and will be recognized in our income at the time the
production volumes to which they relate are sold. As of
December 31, 2005, the fair value of the positions deferred
in accumulated other comprehensive income was a pretax loss of
$492 million. This deferred amount will be recognized in
income upon the settlement of these derivative commodity
instruments, but will be substantially offset by the impact of
the corresponding change in the price to be received when the
hedged natural gas production is sold. This will result in a
realized price that is approximately equal to the hedged price
if settled as originally anticipated.
Below are the hedging positions on our anticipated natural gas
and oil production as of December 31, 2005:
Natural
Gas
Quarter Ended
March 31
June 30
September 30
December 31
Total
Hedged
Hedged
Hedged
Hedged
Hedged
Price
Price
Price
Price
Price
Volume
(per
Volume
(per
Volume
(per
Volume
(per
Volume
(per
(BBtu)
MMBtu)
(BBtu)
MMBtu)
(BBtu)
MMBtu)
(BBtu)
MMBtu)
(BBtu)
MMBtu)
2006(1)
21,349
$
7.07
21,367
$
6.01
21,385
$
6.01
21,385
$
6.28
85,486
$
6.34
2007
1,579
$
3.79
1,447
$
3.64
1,155
$
3.35
1,155
$
3.35
5,336
$
3.56
2008
1,142
$
3.35
1,142
$
3.35
1,155
$
3.49
1,155
$
3.49
4,594
$
3.42
2009 to 2012
16,026
$
3.74
(1)
The hedged natural gas prices in the table represent the price
on the hedge contract when it was entered into or the price on
the day it was designated as a hedge. The average cash prices to
be received under these hedge contracts when they settle is
approximately $3.95 per MMBtu for each of the quarters
ended March 31, June 30, September 30 and
December 31, 2006 and the year ended December 31, 2006.
Oil. We also have derivative contracts on our Brazilian
oil production that provide us with a fixed price of $35.15 per
Bbl on approximately 96 MBbls per quarter in 2006 and
approximately 48 MBbls per quarter in 2007. Our 2007
derivative positions are accounted for as hedges and will be
recognized in income as the positions settle, while changes in
the fair value of the 2006 positions will be recognized in
income as market prices change.
Operating Results
Below are the operating results and analysis of these results
for each of the three years ended December 31:
Average realized prices including hedges
($/Mcf)(3)
$
6.39
10
%
$
5.83
8
%
$
5.40
Average realized prices excluding hedges
($/Mcf)(3)
$
7.53
28
%
$
5.90
7
%
$
5.51
Average transportation costs ($/Mcf)
$
0.18
6
%
$
0.17
(6
)%
$
0.18
Oil, condensate and NGL
Volumes (MBbls)
8,136
(8
)%
8,818
(25
)%
11,778
Average realized prices including hedges
($/Bbl)(3)
$
45.60
32
%
$
34.61
33
%
$
25.96
Average realized prices excluding hedges
($/Bbl)(3)
$
46.43
34
%
$
34.75
30
%
$
26.64
Average transportation costs ($/Bbl)
$
0.63
(44
)%
$
1.12
7
%
$
1.05
Total equivalent volumes (MMcfe)
271,107
(9
)%
297,766
(27
)%
409,432
Production costs ($/Mcfe)
Average lease operating costs
$
0.72
20
%
$
0.60
43
%
$
0.42
Average production taxes
0.24
118
%
0.11
(21
)%
0.14
Total production
cost(2)
$
0.96
35
%
$
0.71
27
%
$
0.56
Average general and administrative cost ($/Mcfe)
$
0.68
17
%
$
0.58
49
%
$
0.39
Unit of production depletion cost ($/Mcfe)
$
2.10
24
%
$
1.69
29
%
$
1.31
Unconsolidated affiliate volumes (Four
Star)(4)
Natural gas (MMcf)
6,689
Oil, condensate and NGL (MBbls)
359
Total equivalent volumes (MMcfe)
8,844
(1)
Transportation and net product costs are included in operating
expenses on our consolidated statement of income.
(2)
Production costs include lease operating costs and production
related taxes (including ad valorem and severance taxes).
(3)
Prices are stated before transportation costs.
(4)
Includes equity earnings and volumes for our investment in Four
Star. Our equity interest in Four Star was acquired in
connection with our acquisition of Medicine Bow in August 2005.
Our EBIT for 2005 decreased $38 million as compared to
2004. The table below lists the significant variances in our
operating results in 2005 as compared to 2004:
Variance
Operating
Operating
Revenue
Expense
Other
EBIT
Favorable/(Unfavorable)
(In millions)
Natural Gas Revenue
Higher realized prices in 2005
$
362
$
—
$
—
$
362
Lower volumes in 2005
(133
)
—
—
(133
)
Impact of hedges
(237
)
—
—
(237
)
Oil, Condensate and NGL Revenue
Higher realized prices in 2005
95
—
—
95
Lower volumes in 2005
(24
)
—
—
(24
)
Impact of hedges
(5
)
—
—
(5
)
Depreciation, Depletion and Amortization Expense
Higher depletion rate in 2005
—
(110
)
—
(110
)
Lower production volumes in 2005
—
45
—
45
Production Costs
Higher lease operating costs in 2005
—
(17
)
—
(17
)
Higher production taxes in 2005
—
(34
)
—
(34
)
General and Administrative Expenses
—
(12
)
—
(12
)
Other
Earnings from investment in Four Star
—
—
19
19
Other
(6
)
14
5
(1)
13
Total Variances
$
52
$
(114
)
$
24
$
(38
)
(1)
Consists primarily of changes in transportation costs and other
income.
Operating revenues. During 2005, we continued to benefit
from a strong commodity pricing environment for natural gas and
oil, condensate and NGL. However, losses in our hedging program
for the year ended December 31, 2005 were $260 million
compared to $18 million in 2004. Additionally, we
experienced a nine percent decrease in production volumes versus
the same period in 2004. Although our production volumes
benefited from the acquisitions in 2005 and our acquisition and
consolidation of the remaining interest in UnoPaso in Brazil in
July 2004, our Texas Gulf Coast and Gulf of Mexico and south
Louisiana regions experienced declines in year over year
production due to normal declines and a lower capital spending
program in these areas over the last several years. In addition,
the Gulf of Mexico and south Louisiana region was impacted by
the hurricanes discussed previously, while the Texas Gulf Coast
region was impacted by mechanical well failures.
Depreciation, depletion and amortization expense. During
2005, we experienced higher depletion rates compared to 2004 as
a result of higher finding and development costs and the cost of
acquired reserves which resulted in higher depreciation,
depletion and amortization expense. However, during 2005, the
impact of lower production volumes partially offset the impact
of our higher depletion rates.
Production costs. We continued to experience higher costs
in 2005 due to the implementation of programs in the first half
of 2005 to improve production in the Texas Gulf Coast and Gulf
of Mexico and south Louisiana regions, higher salt water
disposal costs, utility expenses, marine transportation costs
and increased operating costs in Brazil due to our July 2004
UnoPaso acquisition and consolidation. Production taxes were
also higher as the result of higher commodity prices in 2005 and
higher tax credits taken in 2004 on high cost natural gas wells.
General and administrative expenses. Our general and
administrative expenses were higher in 2005 than in 2004,
primarily due to an increase in direct payroll related benefits
for our employees, and higher legal and insurance costs.
Our EBIT for 2004 decreased $357 million as compared to
2003. The table below lists the significant variances in our
operating results in 2004 as compared to 2003:
Variance
Operating
Operating
Revenue
Expense
Other(1)
EBIT
Favorable/(Unfavorable)
(In millions)
Natural Gas Revenue
Lower volumes in 2004
$
(518
)
$
—
$
—
$
(518
)
Higher realized prices in 2004
96
—
—
96
Impact of hedges
19
—
—
19
Oil, Condensate and NGL Revenue
Lower volumes in 2004
(79
)
—
—
(79
)
Higher realized prices in 2004
72
—
—
72
Impact of hedges
7
—
—
7
Depreciation, Depletion and Amortization Expense
Lower production volumes in 2004
—
146
—
146
Higher depletion rate in 2004
—
(115
)
—
(115
)
Production Costs
Higher lease operating costs in 2004
—
(8
)
—
(8
)
Lower production taxes in 2004
—
27
—
27
General and Administrative Expenses
—
(13
)
—
(13
)
Other
(3
)
(6
)
18
9
Total Variances
$
(406
)
$
31
$
18
$
(357
)
(1)
Other consists of changes in transportation costs and other
income.
Operating Revenues. During 2004, we experienced a
significant decrease in production volumes. The decline in our
natural gas volumes was due to normal production declines in the
Texas Gulf Coast and Gulf of Mexico and south Louisiana regions,
asset sales, lower capital expenditures and disappointing
drilling results. These declines were partially offset by
increased natural gas production in our coal seam operations in
the Raton, Arkoma and Black Warrior basins. We also had
increased oil production in Brazil in 2004 as a result of our
acquisition of the remaining interest and consolidation of
UnoPaso. In addition, we encountered higher average realized
prices for natural gas and oil, condensate and NGL and a
favorable impact from our hedging program as our hedging losses
were $18 million in 2004 as compared to $44 million in
2003.
Depreciation, depletion and amortization expense. Lower
production volumes in 2004 due to production declines reduced
our depreciation, depletion and amortization expense. Partially
offsetting this decrease were higher depletion rates due to
higher finding and development costs.
Production costs. In 2004, we experienced higher gross
workover costs due to the implementation of programs in the
second half of 2004 to improve production in the Texas Gulf
Coast and Gulf of Mexico and south Louisiana regions. We also
incurred higher utility expenses and higher salt water disposal
costs in the Onshore region. However, more than offsetting these
increases were lower production taxes as a result of higher tax
credits taken in 2004 on high cost natural gas wells.
General and administrative expenses. Higher contract
labor costs and lower capitalized costs were the main factors
leading to the increase in general and administrative expenses
in 2004.
Our Marketing and Trading segment’s primary focus is to
market our Exploration and Production segment’s natural gas
and oil production and to manage the company’s overall
price risks, primarily through the use of natural gas and oil
derivative contracts. Historically this segment has also managed
a portfolio of power derivatives and contracts, as well as other
structured commodity-based transactions. In the fourth quarter
of 2005, we entered into transactions to assign a majority of
our power contracts to third parties, including our Cordova
tolling agreement.
The following is a summary of our remaining contracts and their
sensitivity to changes in commodity prices as of
December 31, 2005:
Production-related natural gas and oil derivatives
Option contracts with various floor and ceiling prices;
fixed-for-float swaps.
Significantly impacted our results in 2005 due to changes in
natural gas and oil prices and may continue to do so if
volatility continues in the future.
High
Power
PJM basis positions.
Impacted by changes in regional power prices in 2005 and may
continue to be impacted if volatility continues.
Terminated or assigned a significant number of contracts in
recent years and anticipate additional assignments in 2006,
which will result in further reduction in exposure.
Experienced significant losses historically due to regional
changes in natural gas prices. Significant expirations in 2006
and 2015 will reduce our exposure.
Low
Long-term gas supply obligations
Supply contracts with delivery obligations up to 1 Bcf/d.
Approximately 90 percent of obligations are index-priced
and remaining fixed price obligations are hedged.
Low
While we continue to evaluate potential opportunities to assign
or otherwise divest of contracts related to our legacy trading
operations, we may not liquidate certain of these remaining
transactions before their expiration if (i) they are either
uneconomical to sell or terminate in the current environment due
to their terms, credit concerns of the counterparty or lack of
liquidity in the market or (ii) a sale would require an
acceleration of cash demands. Any future liquidations may impact
our cash flows and financial results. The
discussion that follows provides additional analysis of the
contracts held by our Marketing and Trading segment.
Production-related Natural Gas and Oil Derivatives
During 2004 and 2005, we entered into option contracts that
provide El Paso with various floor and ceiling prices on a
portion of its anticipated natural gas production in 2006
through 2009 and oil production in 2007 and 2008. We paid a
total premium of $144 million for our floors and received a
$50 million premium for our ceilings. We also maintain
swaps that obligate us to sell natural gas and oil at fixed
prices. As of December 31, 2005, our contracts were as
follows:
Swaps(1)
Floors(1)
Ceilings(1)
Average
Average
Average
Volumes
Price
Volumes
Price
Volumes
Price
Natural Gas
2006
25
$
8.11
120
$
7.00
60
$
9.50
2007
—
—
51
$
6.41
21
$
9.00
2008
—
—
18
$
6.00
18
$
10.00
2009
—
—
17
$
6.00
17
$
8.75
Oil
2006
1,044
$
58.81
—
—
—
—
2007
—
—
1,009
$
55.00
1,009
$
60.38
2008
—
—
930
$
55.00
930
$
57.03
(1)
Volumes presented are TBtu for natural gas and MBbl for oil.
Prices presented are per MMBtu of natural gas and per Bbl
of oil.
For a combined discussion of the cash prices under these
contracts and contracts held by our Exploration and Production
segment, see Liquidity discussion on page 40.
Natural gas contracts. These contracts primarily relate
to our transportation activities. Specifically, these contracts
provide us with approximately 1.5 Bcf of pipeline capacity per
day, on which we will be charged approximately $140 million
in annual demand charges in 2006 and, on average,
$111 million in each of the years 2007 through 2010. The
recovery of these charges, and therefore the profitability of
these contracts, is dependent upon our ability to use the
contracted pipeline capacity, which is impacted by a number of
factors including differences in natural gas prices at
contractual receipt and delivery locations, the working capital
needed to use this capacity and the capacity required to meet
our other long term obligations. These transportation contracts
are accrual-based and impact our gross margin as delivery or
service under the contracts occurs.
In addition to these transportation-related contracts, we have
other contracts with third parties that require us to purchase
or deliver natural gas primarily at market prices. Our remaining
long-term contracts require us to sell natural gas to various
power plants and have expiration dates ranging from 2009 to 2028.
During the first quarter of 2006, we assigned our contracts to
supply natural gas to the Jacksonville Electric Authority and
The City of Lakeland, Florida for no cash consideration. We will
record a gain of approximately $50 million related to this
assignment in 2006.
Power Contracts. As of December 31, 2005, our
primary remaining exposure in our power portfolio is for
locational differences in power prices between eastern PJM and
the west PJM hub through 2016.
We have several contracts that obligate us to deliver power or
manage the risk associated with our obligations to deliver
power, including those related to UCF. In December 2005, we
entered into contracts to substantially offset the price risk
associated with these power supply and power price risk
management contracts. We will assign or terminate a portion of
these contracts in 2006; however, we will retain some
contracts (including those related to UCF) that will present
minimal price risk to us in the future as any exposure is
largely offset by the new contracts we entered into in December
2005.
Operating Results
As a result of substantial changes in the composition of our
portfolio over the past three years, year-to-year comparability
in our operating results was affected. The tables below and the
discussion that follows provide the overall operating results
and analysis for our Marketing and Trading segment and factors
by significant contract type that affected the profitability of
our Marketing and Trading segment during each of the three years
ended December 31:
Changes in fair value of Cordova tolling agreement
(136
)
(36
)
75
Change in fair value of other power derivatives
(250
)
(85
)
(96
)
Other
22
19
(25
)
Gross margin
(360
)
(122
)
(211
)
Total gross margin
$
(796
)
$
(508
)
$
(636
)
(1)
Gross margin for our Marketing and Trading segment consists of
revenues from commodity trading and origination activities less
the costs of commodities sold, including changes in the fair
value of our derivative contracts.
(2)
Includes a $50 million gain in 2004 related to the early
termination of an LNG contract and a $17 million loss in
2003 related to the early termination of a storage contract.
Production-related Natural Gas and Oil Derivative
Contracts
Options and swaps. The fair value of our
production-related option and swap contracts declined in 2005
due to increases in natural gas and oil prices, and as a result,
we experienced significant losses. If natural gas
and oil prices remain above the floor prices of our option
contracts, these contracts will remain unexercised and will
expire without any value. For our ceiling contracts, if natural
gas and oil prices continue to increase, further losses will
occur since we are obligated under these contracts to provide
natural gas and oil at fixed prices that are currently lower
than the market price.
Other production-related derivatives. In 2004 and 2003,
our losses were a result of increases in natural gas prices
relative to fixed priced commodity contracts held at the time.
In the fourth quarter of 2004, we designated those contracts as
accounting hedges and transferred them to our Exploration and
Production segment. As a result, the income impacts of those
contracts are now reflected in our Exploration and Production
segment results.
Transportation-related contracts. During 2005, our
ability to use our transportation-related contracts improved due
to increased price differentials between the receipt and
delivery points for these contracts. The following table is a
summary of our demand charges (in millions) and our percentage
of recovery of these charges for each of the three years ended
December 31:
2005
2004
2003
Alliance:
Demand charges
$
65
$
61
$
56
Recovery
93
%
72
%
74
%
Enterprise Texas:
Demand charges
$
26
$
27
$
23
Recovery
8
%
2
%
—
(1)
Other:
Demand
charges(2)
$
65
$
63
$
98
Recovery
94
%
38
%
8
%
(1)
In 2003, we were unable to recover demand charges and incurred
$13 million in losses in excess of the demand charges
related to managing the capacity under these contracts.
(2)
Includes demand charges related to storage contracts of
$1 million, $2 million, and $21 million in 2005,
2004, and 2003.
Other natural gas derivative contracts. Our exposure to
the volatility of gas prices as it relates to our other natural
gas derivative contracts varies from period to period based on
whether we purchase more or less natural gas than we sell under
these contracts. Because we had the right to purchase more
natural gas at fixed prices than we had the obligation to sell
under these contracts during 2003, 2004 and 2005, the fair value
of these contracts increased as natural gas prices increased
during those years. However, the increase in 2003 was more than
offset by losses associated with the early termination of a
number of these contracts resulting in an overall loss for the
year.
Under certain of these contracts, we supply gas to power plants
that we partially own, including the Midland Cogeneration
Venture(MCV) and Berkshire power projects. Due to their
affiliated nature, we do not recognize mark-to-market gains or
losses on these contracts to the extent of our ownership
interest. However, should we sell our interests in these plants,
we would record the cumulative unrecognized mark-to-market
losses on these contracts, which totaled approximately
$146 million as of December 31, 2005.
During 2005, we divested or entered into transactions to divest
of a substantial portion of our power contracts, including our
(i) Cordova tolling agreement, (ii) substantially all
contracts in our power portfolio and (iii) certain other
contracts related to our Power segment’s historical power
contract restructuring
business. The discussion that follows details significant
factors impacting our power contracts during 2005, 2004 and 2003.
Cordova tolling agreement. In the fourth quarter of 2005,
we completed the assignment of this agreement to Constellation.
Prior to this assignment, we experienced significant volatility
under this agreement, which was sensitive to changes in
forecasted natural gas and power prices. During 2004 and 2005
forecasted natural gas prices increased relative to power
prices, resulting in a decrease in the fair value of the
contract. However, during 2003, forecasted power prices
increased relative to natural gas prices, resulting in a
significant increase in the fair value of this contract.
Other power derivatives. Historically, many of our
contract origination activities related to power contracts.
However, in 2003, we began exiting our power contract
origination activities due to changes in the energy trading
environment and re-aligning the focus of our Marketing and
Trading segment. Our activity in this area was as follows:
•
During 2005, 2004 and 2003, we supplied power to Morgan Stanley
under a power supply agreement related to our formerly-owned UCF
entity. We were also required to purchase power under a number
of other power agreements, which included those used to manage
our risk on the power supply obligation to Morgan Stanley. As a
result of increasing power prices and increases in the
differences in power prices at various locations in PJM, our
Morgan Stanley contract decreased in fair value by
$345 million, $72 million and $77 million in
2005, 2004 and 2003. These decreases were partially offset by
increases in the fair value of our power purchase contacts of
$223 million, $81 million and $48 million in
2005, 2004 and 2003.
In addition to our Cordova assignment, we entered into an
agreement in December 2005 to assign the majority of our
remaining power portfolio to Morgan Stanley. This assignment
includes all of our remaining power derivative assets, except
for certain positions in the PJM power pool that we will retain.
The assignment requires consents by the current counterparties
to the contracts. Until the assignment is finalized, we entered
into new offsetting liability contracts with Morgan Stanley for
the power portfolio being assigned, which eliminated our cash
and earnings exposure to power price movements for these
contracts. We received total proceeds of $442 million to
enter into these offsetting contracts and deposited a similar
amount of cash margin. The amount we received approximated the
value we would have received if we had directly sold our power
derivative assets.
•
Contracts related to our former power contract restructuring
activities. During the first quarter of 2005, we assigned
our contracts to supply power to our Power segment’s Cedar
Brakes I and II entities to Constellation. We recorded a loss of
$30 million in 2004 related to entering into an agreement
to assign these contracts. In 2004 and 2003, these contracts
decreased in fair value by $64 million and
$67 million. In conjunction with the assignment, we also
entered into derivative contracts with Constellation that swap
the locational differences in power prices at several power
plants in eastern PJM and the west PJM hub through 2013. Due to
unfavorable changes in the power prices at each location, the
fair value of these swaps decreased by $105 million during
2005.
During the fourth quarter of 2005, we assigned our contracts to
supply power to our Power segment’s Mohawk River Funding II
subsidiary to Merrill Lynch. We recognized a loss of
$23 million associated with this assignment. As a result of
this assignment, we have no further obligations to provide power
to our Power segment.
Other. During 2005, a bankruptcy court entered an order
allowing Mohawk River Funding III’s (MRF III)
bankruptcy claims with USGen New England. We received payment on
this claim and recognized a gain of $17 million in 2005
related to this settlement. During 2004, we recorded a
$25 million gain related to the termination of a power
contract with our Power segment, which was eliminated in El
Paso’s consolidated results.
During 2005, our Marketing and Trading segment recorded
$18 million of legal settlements and reserves, which
resulted in increased operating expenses. However, this amount
was partially offset by a decline in general and administrative
expenses. Overall operating expenses have decreased
significantly from 2003 due primarily to the following:
•
Recording $26 million of charges in operating expenses in
2003 related to the Western Energy Settlement prior to the
transfer of this obligation to our corporate operations.
•
Recording bad debt expense associated with a fuel supply
agreement we have with the Berkshire power plant of
$2 million, $10 million and $28 million in 2005,
2004 and 2003.
•
Incurring lower corporate overhead allocation and general and
administrative expenses based on overall cost reduction efforts
at the corporate level and our reduced level of operations in
2004 and 2005. These reductions were primarily due to a
reduction of our trading activities coupled with the closing of
our office in London in 2003.
Power Segment
As of December 31, 2005, our Power segment primarily
consisted of an international power business in Brazil.
Substantially all of our other international power assets,
primarily in Asia and Central America, are under sales
agreements and are expected to close in the first half of 2006.
Over the past several years, we also had substantial domestic
power operations, including a portfolio of domestic power plants
and a power contract restructuring business. Substantially all
of these domestic operations have been sold or fully impaired.
As of December 31, 2005, the total financial exposure on
our investments in Brazil was approximately $858 million.
Based on the status of negotiations and disputes in certain of
these projects, it is possible that additional impairments of
these assets may occur in the future. Below is a further
discussion of these matters, which are further described in
Part II, Item 8, Financial Statements and
Supplementary Data, Note 16.
•
Macae. Our Macae power plant sells a majority of its
power to the wholesale Brazilian power market. Macae also has a
contract that requires Petrobras to make minimum revenue
payments until August 2007. Petrobras has not made payments
under the contract since December 2004 and initiated arbitration
proceedings related to that obligation. In early 2006, we signed
a memorandum of understanding to resolve the arbitration
proceedings and sell Macae to Petrobras for approximately
$358 million. The completion of the sale of Macae is
subject to the negotiation of a definitive purchase and sale
agreement, and approvals by Brazilian regulators. As a result of
the dispute and the indication of value we would receive for the
potential sale of the plant, we recorded impairments of
$351 million in 2005. Depending on the terms of the final
agreement, we could be required to record additional losses
related to the disposition and the resolution of disputes
related to Macae.
•
Porto Velho. The Porto Velho plant sells power to
Eletronorte under two power sales agreements that expire in 2010
and 2023. Eletronorte absorbs substantially all of the
plant’s fuel costs and purchases all of the energy and
capacity sold by the plant, provided that the plant operates
within certain operational requirements. As a result, the
profitability of the plant is dependent primarily on meeting the
operational requirements of the contract and through efficient
operations and maintenance practices. In October 2004, our Porto
Velho project experienced an outage with its steam turbine,
which resulted in a partial reduction in the plant’s
capacity. The project expects to have the steam turbine back in
service in the first quarter of 2006. In addition, the project
is also currently negotiating certain provisions of its power
purchase agreement and the outcome of these negotiations may
impact the future financial performance of the project.
•
Manaus and Rio Negro. In January 2005, we signed new
power sales contracts for our Manaus and Rio Negro power plants
with Manaus Energia. Under these new contracts, Manaus Energia
will pay a price for its power that is similar to that in the
previous contracts. In addition, Manaus Energia will assume
ownership of the plants in 2008.
Other. At our Araucaria power plant, the power sales
contract is currently in international arbitration due to
non-payment by the utility that purchases power from the plant.
In early 2006, we signed a letter of intent to resolve the
arbitration proceedings and to sell our investment in Araucaria
to COPEL for $190 million. We also have an interest in two
pipelines which reached full capacity in 2003 and currently
generate income through the transportation of natural gas to
various customers in South America.
Operating Results
The tables below and discussions that follow provide the
operating results and additional analysis of our Power segment
operations for the years ended December 31:
2005
2004
2003
(In millions)
Overall EBIT:
Gross
margin(1)
$
110
$
525
$
753
Operating expenses
(539
)
(921
)
(773
)
Operating loss
(429
)
(396
)
(20
)
Losses from unconsolidated affiliates
(139
)
(249
)
(91
)
Other income
117
69
71
EBIT
$
(451
)
$
(576
)
$
(40
)
EBIT by Area:
Brazil
Impairments
Macae
$
(351
)
$
—
$
—
Manaus and Rio Negro
—
(183
)
—
EBIT from operations
44
235
177
Other International Power
Asia
Impairments related to anticipated sales
(87
)
(182
)
—
Gain on sale of KIECO, PPN and Chinese plants
131
—
—
EBIT from operations
15
64
47
Central and other South America
Impairments related to anticipated sales
(89
)
—
—
Gain on sale of Argentina
—
—
28
EBIT from operations
5
1
8
EBIT from other international plants and investments
Sale of interest in Cedar Brakes I and II and UCF and related
power restructuring contracts
—
(324
)
(15
)
Decline in value of Chaparral investment
—
—
(207
)
Milford receivable write-off due to lender dispute
—
—
(88
)
Other domestic plants and investments
(5
)
(105
)
(208
)
Proceeds from portion of MRF III bankruptcy claim
previously written off
53
—
—
EBIT from operations
—
143
256
Other(3)
(19
)
(53
)
(91
)
EBIT
$
(451
)
$
(576
)
$
(40
)
(1)
Gross margin for our Power segment consists of revenues from our
power plants and the revenues, cost of electricity purchases and
changes in fair value of restructured power contracts. The cost
of fuel used in the power generation process is included in
operating expenses.
(2)
Includes impairment charges and gains (losses) on the sales of
assets and investments.
(3)
Includes impairments and losses on the sales of power turbines
of $27 million, $1 million and $33 million in
2005, 2004 and 2003. Also includes $40 million of gains on
the sales of cost basis investments in 2005.
Brazil
During 2002 and 2003, we completed the construction of several
power plants and pipelines, which allowed them to reach full
operational capacity. However, our financial results during 2004
and 2005 were impacted significantly by regional economic and
political conditions, which affected the renegotiation of
several of the power contracts for our Brazilian power plants
including those related to Macae, Manaus and Rio Negro.
Macae. At our Macae facility, we entered into a
memorandum of understanding in February 2006 to resolve our
disputes with and sell the plant to Petrobras. During 2005, we
recorded significant impairments based on our expected outcome
of the negotiations with Petrobras. EBIT from our Macae
plant’s operations was a loss of $13 million in 2005,
income of $172 million in 2004, and income of
$156 million in 2003. The 2005 decrease was due to the
non-recognition of $206 million of revenues based on
non-payment of minimum revenue amounts by Petrobras.
Porto Velho. EBIT from our Porto Velho plant’s
operations was $23 million, $28 million and
$28 million in 2005, 2004 and 2003. The decrease in 2005
was due to the equipment failure discussed earlier that
temporarily reduced the output of the plant by approximately
30 percent. This equipment failure is expected to be
repaired in the first quarter of 2006.
Manaus and Rio Negro. At our Manaus and Rio Negro
facilities we began negotiating new power contracts in 2003,
which were to expire in 2005 and 2006. These negotiations were
negatively impacted by changes in the Brazilian political
environment, and as a result, we recorded an impairment on these
investments in 2004. As a result of new contracts entered into
during the first quarter of 2005, we deconsolidated these plants
and now account for them as equity investments. The new
contracts also resulted in a decrease in earnings from these
projects. The Manaus and Rio Negro plants had earnings from
plant operations of $19 million in 2005, $30 million
in 2004 and $12 million in 2003.
South American Pipelines. The EBIT for our Brazilian
operations includes EBIT earned by our Bolivia to Brazil and
Argentina to Chile pipelines. EBIT was $26 million in 2005,
$28 million in 2004 and $18 million
in 2003. EBIT increased from 2003 to 2004 due primarily to the
Bolivia to Brazil pipeline reaching full operational capacity in
the third quarter of 2003.
Other International Power
During 2005 and 2004, we recorded substantial gains and losses
in our other international power operations primarily based on
the sale of, or the decision to sell our Asian and Central
American assets. These assets have been written down to the
value expected to be realized upon the close of the sales. As of
December 31, 2005, the total financial exposure on our
investments in Asia and Central America was approximately
$377 million. Until these sales close, which we expect in
the first half of 2006, we have potential risk for negative
impacts of operational, economic or political events that may
occur.
Prior to the decision to sell these assets, our earnings in
these areas were relatively stable as the underlying plants
maintained steady levels of availability and production.
However, our earnings from our Asian power assets decreased in
2005 as we did not recognize approximately $30 million of
earnings in Asia because we did not believe these amounts could
be realized.
Domestic Power
From 2003 to 2005, we sold substantially all of our domestic
power assets, including all of our remaining restructured power
contracts. In conjunction with these sales, we recorded
significant impairments in our domestic power business and had
substantially lower earnings in our domestic power plant
operations during this three year period. The discussion that
follows outlines the significant events that affected our
domestic operating results during the period from 2003 to
2005.
•
MCV. As of December 31, 2005, we maintain an equity
ownership in a natural gas-fired power plant, MCV. Although the
price of electricity sold by MCV is indexed to coal, the plant
is fueled by natural gas, which it purchases under both
long-term contracts and on the spot market. Due to significant
increases in natural gas prices, the economic performance of the
facility was greatly impacted. In 2004, we impaired our
investment in MCV by $161 million based on a decline in the
value of the investment due to the increase in fuel costs. In
2005, we recorded our proportionate share of losses on MCV based
on MCV’s impairment of the plant assets. These impairments
and recorded losses reduced our net investment in the plant to
zero at December 31, 2005. MCV’s owners are pursuing
various commercial alternatives, which could result in the
recovery of some of our previously impaired investment.
•
Other Impairments and EBIT from Operations. Prior to
2003, Chaparral Investors, L.L.C. owned interests in a number of
domestic power facilities and was the principal equity
investment through which we conducted our domestic power
activities. We consolidated Chaparral and its related power
plants in early 2003. In 2003 and 2004, among other impairments
noted in the table above, we recorded substantial impairments,
net of gains and losses based on the anticipated sale of our
merchant and contracted plants, as well as operational and
contractual issues at several of these facilities. Included in
these amounts was a $25 million loss in 2004 on the
termination of a power contract with our Marketing and Trading
segment related to one of the assets sold, which was eliminated
in consolidation. As these facilities were sold through 2004, we
experienced lower EBIT in each year from the operation of these
facilities. See Part II, Item 8, Financial Statements
and Supplementary Data, Notes 2, 3, and 21 for a further
discussion of these matters.
Field Services Segment
As of December 31, 2005, the remaining assets in our Field
Services segment are our Bluebell and Altamont facilities
located in the Rocky Mountain area. Effective January 1,2006, these assets have been transferred to our Exploration and
Production segment, as they primarily support our producing
activities in that segment.
Prior to their sales from 2003 through the third quarter of
2005, our general and limited partner interests in GulfTerra and
Enterprise and gathering and processing assets in south Texas
and south Louisiana were the
primary sources of earnings in our Field Services segment. The
sales of these assets are further described in Part II,
Item 8, Financial Statements and Supplementary Data, Note
21. Our south Louisiana operations are reported as discontinued
operations for the three years ended December 31, 2005. The
tables below and discussion that follows provide the operating
results and additional analysis of significant factors affecting
EBIT for our Field Services segment for each of the three years
ended December 31:
2005
2004
2003
(In millions)
Gathering and processing gross
margins(1)
$
25
$
93
$
96
Operating expenses
Loss on long-lived assets
(10
)
(507
)
(173
)
Other operating expenses
(31
)
(87
)
(120
)
Operating loss
(16
)
(501
)
(197
)
Earnings from unconsolidated affiliates
301
618
329
Other expense
—
(33
)
(3
)
EBIT
$
285
$
84
$
129
(1)
Gross margins consist of operating revenues less cost of
products sold. We believe that this measurement is more
meaningful for understanding and analyzing our Field Services
segment’s operating results because commodity costs
historically were a significant factor in the determination of
profit from our midstream activities.
2005
2004
2003
(In millions)
Gathering and Processing Activities
Gathering and processing margins
$
25
$
93
$
96
Operating expenses
(8
)
(87
)
(120
)
Other income (expense)
7
11
(7
)
EBIT
24
17
(31
)
GulfTerra/Enterprise-related Items
Assets sold to GulfTerra
5
9
(7
)
Assets/interests sold to Enterprise
Sale of GP/LP interests
183
507
266
Sale of south Texas
—
(11
)
(167
)
Goodwill impairment
—
(480
)
—
Other
(1
)
(45
)
—
Equity earnings
—
100
153
EBIT
187
80
245
Other Asset Sales
Sale of Javelina investment
111
—
—
Dauphin Island/ Mobile Bay
—
—
(86
)
Termination of Needle Mountain gas supply contract
(28
)
—
—
Other
(9
)
(13
)
1
74
(13
)
(85
)
EBIT
$
285
$
84
$
129
Gathering and Processing Activities. During the three
years ended December 31, 2005, the decreases in our gross
margins and in operation and maintenance expenses were primarily
a result of asset sales, including
the sales of our south Texas, north and south Louisiana,
mid-continent and Indian Springs gathering and processing plants.
GulfTerra/Enterprise Related Items. During 2002 and 2003,
we sold a number of assets to GulfTerra. While these sales
decreased our gross margin and operating expenses, they
increased the equity earnings from our general and limited
partner interests in GulfTerra. However, over time, our equity
earnings in GulfTerra declined as we sold our interests in that
investment. The effect of significant transactions related to
GulfTerra during 2005, 2004 and 2003 were as follows:
•
Gain of $266 million on the sale of 50 percent of our
interest in GulfTerra to Enterprise in 2003. At the same time,
we recorded an impairment of our south Texas assets of
$167 million based on the planned sale of these assets to
Enterprise;
•
Gain of $507 million upon the sale of our remaining 50
percent interest in the general partner of GulfTerra to
Enterprise in 2004. As a result of this sale, we also impaired
goodwill recorded on the segment; and
•
Gain of $183 million on the sale of our remaining general
partner and limited partner interests in Enterprise in 2005.
Corporate and Other Expenses, Net
Our corporate activities include our general and administrative
functions as well as a number of miscellaneous businesses, which
do not qualify as operating segments and are not material to our
current year results. The following is a summary of significant
items impacting the EBIT in our corporate operations for each of
the three years ended December 31:
2005
2004
2003
(In millions)
Change in litigation, insurance and other reserves
$
(418
)
$
(81
)
$
(10
)
Western Energy Settlement
(72
)
(38
)
(2
)
Impairments, contract terminations and gains (losses) on asset
sales:
Telecommunications business
5
—
(396
)
LNG business
—
—
(108
)
Aircraft
—
8
(8
)
Other operating earnings (losses) from other businesses
21
32
(22
)
Restructuring charges
(27
)
(91
)
(91
)
Debt gains (losses):
Foreign currency fluctuations on Euro-denominated debt
36
(26
)
(112
)
Early extinguishment/exchange of debt
(29
)
(18
)
(49
)
Other
(37
)
(3
)
(54
)
Total EBIT
$
(521
)
$
(217
)
$
(852
)
We have a number of pending litigation matters, including
shareholder and other lawsuits filed against us. In all of our
legal and insurance matters, we evaluate each lawsuit and claim
as to its merits and our defenses. Adverse rulings or
unfavorable settlements against us related to these matters have
impacted and may further impact our future results. In 2005 and
2004, we recorded significant charges in operation and
maintenance expense to increase our litigation, insurance and
other reserves based on ongoing assessments, developments and
evaluations of the possible outcomes of these matters. In 2005,
the most significant item was a charge in connection with a
ruling by an appellate court that we indemnify a former
subsidiary for certain payments being made under a retiree
benefit plan. Additionally, we incurred charges in 2005 with the
final prepayment of the Western Energy Settlement and charges
related to increased premiums from a mutual insurance company in
which we participate, based primarily on the impact of several
hurricanes in 2004 and 2005. In 2004, we also incurred charges
associated with the Western Energy Settlement obligation and
charges related to our decision to withdraw from another mutual
insurance company in which we were a member.
As discussed in Part II, Item 8, Financial Statements
and Supplementary Data, Note 4, we accrued $80 million
in 2004 related to the consolidation of our Houston-based
operations. Our relocation costs were based on a discounted
liability, which included estimates of future sublease rentals.
During 2005, we recorded additional charges of $27 million
related to vacating the remaining leased space and signing a
termination agreement on the lease.
Interest and Debt Expense
The table below and discussion that follows provide an analysis
of our interest and debt expense for each of the three years
ended December 31:
2005
2004
2003
(In millions)
Long-term debt, including current maturities
$
1,348
$
1,533
$
1,696
Other interest
32
74
94
Total interest and debt expense
$
1,380
$
1,607
$
1,790
Our total interest and debt expense decreased between 2003 and
2005 primarily due to the retirements of debt and other
financing obligations, net of issuances. During 2005, our
overall debt level declined by approximately $1.0 billion
through a combination of repayments and asset sales, net of
issuances. In 2004, our overall debt levels declined by
$2.5 billion. See Part II, Item 8. Financial
Statements and Supplementary Data, Note 14, for a further
discussion of our activities related to debt repayments and
issuances.
Distributions on Preferred Interests of Consolidated
Subsidiaries
Our distributions on preferred securities decreased
significantly between 2003 and 2005 due to the redemption, or
reclassification as debt, of substantially all of these
securities during these periods. For a further discussion of our
borrowings and other financing activities related to our
consolidated subsidiaries, see Part II, Item 8,
Financial Statements and Supplementary Data, Notes 14 and
15.
Income Taxes
Income taxes for the years ended December 31, 2005, 2004
and 2003 were ($289) million, $14 million and
($484) million, resulting in effective tax rates of
29 percent, (2) percent and 44 percent.
Differences in our effective tax rates from the statutory tax
rate of 35 percent were primarily a result of the following
factors:
•
earnings from unconsolidated affiliates where we anticipate
receiving dividends;
•
foreign income taxed at different rates;
•
sales and write offs of foreign investments;
•
valuation allowances;
•
audit settlements;
•
non-deductible goodwill impairments; and
•
non-taxable medicare reimbursements.
In 2004, our overall effective tax rate on continuing operations
was significantly different than the statutory rate due
primarily to sales of our GulfTerra investment and impairments
of certain of our foreign investments. The sale of GulfTerra
resulted in a significant net taxable gain (compared to a lower
book gain) and thus significant tax expense due to the
non-deductibility of goodwill written off as a result of the
transaction. The impact of this non-deductible goodwill
increased our tax expense in 2004 by approximately
$139 million. Additionally, we received no U.S. federal
income tax benefit on the impairment of certain of our foreign
investments. The combination of these items resulted in an
overall tax expense in a period for which there was a
pre-tax loss. The
effective tax rate for 2004 absent these items would have been
35 percent.
We have pending IRS and other taxing authority audits and income
tax contingencies that are in various stages of completion. We
have recorded a liability on these matters based on our best
estimate of the ultimate outcome of each matter. As these audits
are finalized and as these contingencies are resolved, we adjust
our estimates, the impact of which could have a material effect
on the recorded amount of income taxes and our effective tax
rates in future periods. We had several such adjustments in 2005
which impacted our effective tax rate.
For a reconciliation of the statutory rate to our effective tax
rate, valuation allowances and additional discussion of other
income tax matters affecting us, see Part II, Item 8,
Financial Statements and Supplementary Data, Note 7.
Discontinued Operations
We present our gathering and processing operations in south
Louisiana, certain international power operations, petroleum
markets operations and international natural gas and oil
production operations outside of Brazil as discontinued
operations in our financial statements. For the year ended
December 31, 2005, income from our discontinued
operations was $100 million compared to losses of
$118 million and $1.3 billion in 2004 and 2003. Our
2005 income was primarily a result of the sale of our south
Louisiana operations in the fourth quarter of 2005, partially
offset by impairments of our discontinued international power
operations in 2005. The gain on the sale of south Louisiana and
the impairments of our international power assets are further
discussed in Part II, Item, 8, Financial Statements and
Supplementary Data, Note 3. Our 2004 losses related
primarily to charges and losses on the sales of discontinued
assets along with other operational and severance costs. The
losses in 2003 related primarily to impairment charges on our
discontinued petroleum refineries and on chemical assets and
ceiling test charges related to our discontinued Canadian
production operations.
Commitments and Contingencies
For a discussion of our commitments and contingencies, see
Part II, Item 8, Financial Statements and
Supplementary Data, Note 16, incorporated herein by
reference.
Critical Accounting Policies
Our critical accounting policies are those that involve the use
of complicated processes, assumptions and/or judgments in the
preparation of our financial statements. We have discussed the
development and selection of our critical accounting policies
and related disclosures with the audit committee of our Board of
Directors.
Price Risk Management Activities. We record the
derivative instruments used in our price risk management
activities at their fair values on our balance sheet. We
estimate the fair value of our derivative instruments 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 assumptions used to estimate the fair value
of derivative instruments is pricing. Our pricing assumptions
are based upon price curves derived from actual prices observed
in the market, pricing information supplied by a third-party
valuation specialist and independent pricing sources and models
that rely on this forward pricing information. The table below
presents the hypothetical sensitivity of our commodity-based
price risk management activities to changes in fair values
arising from immediate selected potential changes in quoted
market prices:
Other significant assumptions that we use in determining the
fair value of our derivative instruments are those related to
time value, anticipated market liquidity and credit risk of our
counterparties. The assumptions and methodologies we use to
determine the fair values of our derivatives may differ from
those used by our derivative counterparties. These differences
can be significant and could impact our future operating results
as we settle these positions.
Accounting for Natural Gas and Oil Producing Activities.
Natural gas and oil reserves estimates underlie a number of the
accounting estimates in our financial statements. The process of
estimating natural gas and oil reserves, particularly proved
undeveloped and proved non-producing reserves, is very complex,
requiring significant judgment in the evaluation of all
available geological, geophysical, engineering and economic
data. Accordingly, our reserve estimates are developed
internally by a reserve reporting group separate from our
operations group and reviewed by internal committees and
internal auditors. In addition, a third-party engineering firm,
which is appointed by and reports to the Audit Committee of our
Board of Directors, prepares an independent estimate of a
significant portion of our proved reserves. As of
December 31, 2005, of our total proved reserves,
31 percent were undeveloped and 12 percent were
developed, but non-producing. In addition, 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. In addition, the subjective decisions and
variances in available data for various fields increases the
likelihood of significant changes in these estimates.
The estimates of proved natural gas and oil reserves primarily
impact our property, plant and equipment amounts in our balance
sheets and the depreciation, depletion and amortization amounts
in our income statements, among other items. 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
acquisition, exploration and development of natural gas and oil
reserves in full cost pools maintained by geographic areas,
regardless of whether reserves are actually discovered. We
record depletion expense of these capitalized amounts over the
life of our proved reserves based on the unit of production
method and, if all other factors are held constant, a
10 percent increase in estimated proved reserves would
decrease our unit of production depletion rate by 9 percent
and a 10 percent decrease in estimated proved reserves
would increase our unit of depletion rate by 11 percent.
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 from proved reserves using
end of period spot prices and, 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 greater than or equal to the total
capitalized costs, we are required to write-down our capitalized
costs to this level. Our ceiling test calculations include the
effect of derivative instruments we have designated as, and that
qualify as hedges of our anticipated natural gas and oil
production. As a result, higher proved reserves can reduce the
likelihood of ceiling test impairments. We recorded ceiling test
charges in our continuing and discontinued operations of less
than $1 million, $35 million and $76 million
during 2005, 2004 and 2003.
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, even though actual prices of natural gas and oil
are volatile and change from period to period. A decline in
commodity prices can impact the results of our ceiling test and
may result in writedowns. A decrease in commodity prices of
10 percent from the price levels at December 31, 2005
would not have resulted in a ceiling test charge in 2005.
Asset and Investment Impairments. The accounting rules on
asset and investment impairments require us to continually
monitor our businesses and the business environment to determine
if an event has occurred indicating that a long-lived asset or
investment may be impaired. If an event occurs, which is a
determination that involves judgment, we then assess the
expected future cash flows against which to compare the carrying
value of the asset group being evaluated, a process which also
involves judgment. We ultimately arrive at the fair value of the
asset, which is 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). The assessment of project level cash
flows requires us to make projections and assumptions for many
years into the future for pricing, demand, competition,
operating costs, legal and regulatory issues and other factors.
Actual results can, and often do, differ from our estimates.
These changes can have either a positive or negative impact on
our impairment estimates. We recorded impairments of our
long-lived assets of $406 million, $1.1 billion and
$791 million and impairments on our investments in
unconsolidated affiliates of $347 million,
$397 million, and $449 million during the years ended
December 31, 2005, 2004 and 2003. We also recorded asset
and investment impairments of our discontinued operations of
$169 million, $40 million and $1.5 billion, net
of minority interest during the years ended December 31,2005, 2004 and 2003. Future changes in the economic and business
environment can impact our assessments of potential impairments.
Accounting for Legal and Environmental Reserves. We
accrue legal and 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
our evaluation of potential outcomes, currently available facts,
and in the case of environmental reserves, existing technology
and presently enacted laws and regulations taking into
consideration the likely effects of societal and economic
factors, estimates of associated onsite, offsite and groundwater
technical studies and legal costs. 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 matter.
As of December 31, 2005, we had accrued approximately
$574 million for legal matters and $379 million for
environmental matters. Our environmental estimates range from
approximately $379 million to approximately
$546 million, and the amounts we have accrued represent a
combination of two estimation methodologies. First, where the
most likely outcome can be reasonably estimated, that cost has
been accrued ($75 million). Second, where the most likely
outcome cannot be estimated, a range of costs is established
($304 million to $471 million) and the lower end of
the expected range has been accrued.
Accounting for Pension and Other Postretirement Benefits.
As of December 31, 2005, we had a $918 million pension
asset and a $250 million liability for other postretirement
benefits reflected in other assets and liabilities on our
balance sheet related to our pension and other postretirement
benefit plans. These amounts are primarily based on actuarial
calculations. We use various assumptions in performing these
calculations, including those related to the return that we
expect to earn on our plan assets, the rate at which we expect
the compensation of our employees to increase over the plan
term, the estimated cost of health care when benefits are
provided under our plans and other factors. A significant
assumption we utilize is the discount rates used in calculating
our benefit obligations. We select our discount rates by
comparing the average expected timing of our pension and other
postretirement obligations to the maturity profiles of the
Moody’s Corporate Bond Indices and the Citigroup Pension
Discount Curve. Based on these comparisons, we select discount
rates that appropriately reflect the yields included in these
market sources adjusted for the estimated timing of our
obligations.
Actual results may differ from the assumptions included in these
calculations, and as a result, our estimates associated with our
pension and other postretirement benefits can be, and often are,
revised in the future. The income statement impact of the
changes in the assumptions on our related benefit obligations
are generally deferred and amortized into income over either the
period of expected future service of active participants, or
over the lives of the plan participants. The cumulative amount
deferred as of December 31, 2005 is recorded as an
$814 million increase in our pension asset and a
$20 million reduction of our other postretirement
liability. The following table shows the impact of a one percent
change in the primary
assumptions used in our actuarial calculations associated with
our pension and other postretirement benefits for the year ended
December 31, 2005 (in millions):
Pension Benefits
Other Postretirement Benefits
Projected
Accumulated
Net Benefit
Benefit
Net Benefit
Postretirement
Expense (Income)
Obligation
Expense (Income)
Benefit Obligation
One percent increase in:
Discount rates
$
(14
)
$
(205
)
$
—
$
(41
)
Expected return on plan assets
(21
)
—
(2
)
—
Rate of compensation increase
1
6
—
—
Health care cost trends
—
—
1
20
One percent decrease in:
Discount rates
$
15
$
245
$
—
$
44
Expected return on plan assets
(1)
21
—
2
—
Rate of compensation increase
(1
)
(5
)
—
—
Health care cost trends
—
—
(1
)
(18
)
(1)
If the actual return on plan assets was one percent lower than
the expected return on plan assets, our expected cash
contributions to our pension and other postretirement benefit
plans would not significantly change.
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. 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 expense would have been $19 million
lower for the year ended December 31, 2005.
We have not recorded an additional pension liability for our
primary pension plan because the fair value of assets of that
plan exceeded the accumulated benefit obligation of that plan by
approximately $212 million and $226 million as of
September 30, 2005 and December 31, 2005. If the
accumulated benefit obligation exceeded plan assets under this
primary pension plan as of September 30, 2005, we would
have recorded a pre-tax
additional pension liability of approximately $918 million,
plus an amount equal to the excess of the accumulated benefit
obligation over the assets of that plan. We would have also
recorded an amount equal to this additional pension liability in
accumulated other comprehensive loss, net of taxes, on our
balance sheet.
As stated in Part II, Item 8, Financial Statements and
Supplementary Data, Note 16, we were ordered to indemnify a
third party for certain benefit payments being made to a closed
group of retirees pending the outcome of litigation related to
these payments. We estimated the liability associated with this
indemnification obligation using actuarial methods similar to
those used in estimating our obligations on our other
postretirement benefit plans, which involves using various
assumptions, including those related to discount rates and
health care trends. A one percent change in the discount rate
assumption used in the calculation would have changed the
liability (and the related expense) by approximately
$45 million and a one percent change in the health care
cost trend assumption would have changed the liability (and the
related expense) by approximately $50 million as of and for
the year ended December 31, 2005.
New Accounting Pronouncements Issued But Not Yet Adopted
See Part II, Item 8, Financial Statements and
Supplementary Data, Note 1 under New Accounting
Pronouncements Issued But Not Yet Adopted, which is
incorporated herein by reference.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES
ABOUT MARKET RISK
We are exposed to market risks in our normal business
activities. Market risk is the potential loss that may result
from market changes associated with an existing or forecasted
financial or commodity transaction. The types of market risks we
are exposed to and examples of each are:
•
Commodity Price Risk
–
Natural gas and oil price changes, impacting the forecasted sale
of natural gas and oil in our Exploration and Production segment;
–
Locational price differences in natural gas changes, affecting
our ability to optimize pipeline transportation capacity
contracts held in our Marketing and Trading segment; and
–
Electricity and natural gas price changes and locational pricing
changes, affecting the value of our natural gas contracts and
remaining power contracts held in our Marketing and Trading and
Power segments. During 2005, we assigned or entered into
agreements to assign to third parties the majority of our power
contract portfolio, including our Cordova tolling agreement. As
a result, our sensitivity to change in power prices will be
significantly reduced in future periods.
•
Interest Rate Risk
–
Changes in interest rates affect the interest expense we incur
on our variable-rate
debt and the fair value of our fixed-rate debt;
–
Changes in interest rates used in the estimation of the fair
value of our derivative positions can result in increases or
decreases in the unrealized value of those positions; and
–
Changes in interest rates used to discount liabilities which can
result in higher or lower accretion expense over time.
•
Foreign Currency Exchange Rate Risk
–
Weakening or strengthening of the U.S. dollar relative to the
Euro can result in an increase or decrease in the value of our
Euro-denominated debt obligations and the related interest costs
associated with that debt; and
–
Changes in foreign currencies exchange rates where we have
international investments may impact the value of those
investments and the earnings and cash flows from those
investments.
We manage these risks by entering into contractual commitments
involving physical or financial settlement that attempt to limit
exposure related to future market movements. Our risk management
activities typically involve the use of the following types of
contracts:
•
Forward contracts, which commit us to purchase or sell energy
commodities in the future;
•
Futures contracts, which are exchange-traded standardized
commitments to purchase or sell a commodity or financial
instrument, or to make a cash settlement at a specific price and
future date;
•
Options, which convey the right to buy or sell a commodity,
financial instrument or index at a predetermined price;
•
Swaps, which require payments to or from counterparties based
upon the differential between two prices for a predetermined
contractual (notional) quantity; and
•
Structured contracts, which may involve a variety of the above
characteristics.
Many of the contracts we use in our risk management activities
are derivative financial instruments. A discussion of our
accounting policies for derivative instruments are included in
Part II, Item 8, Financial Statements and
Supplementary Data, Notes 1 and 10.
Our Marketing and Trading segment attempts to mitigate its
exposure to commodity price risk through the use of various
financial instruments, including forwards, swaps, options and
futures. We measure risks from our Marketing and Trading
segment’s commodity and energy-related contracts on a daily
basis using a Value-at-Risk simulation. This simulation allows
us to determine the maximum expected
one-day unfavorable
impact on the fair values of those contracts due to adverse
market movements over a defined period of time within a
specified confidence level and allows us to monitor our risk in
comparison to established thresholds. We use what is known as
the historical simulation technique for measuring
Value-at-Risk. This
technique simulates potential outcomes in the value of our
portfolio based on market-based price changes. Our exposure to
changes in fundamental prices over the long-term can vary from
the exposure using the one-day assumption in our Value-at-Risk
simulations. We supplement our Value-at-Risk simulations with
additional fundamental and market-based price analyses,
including scenario analysis and stress testing to determine our
portfolio’s sensitivity to its underlying risks. These
analyses and our
Value-at-Risk
simulations do not include the commodity exposures of our
Exploration and Production segment’s sales of natural gas
and oil production.
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
was $60 million and $16 million as of
December 31, 2005 and 2004. Our highest, lowest and average
of the month-end values for
Value-at-Risk during
2005 was $60 million, $12 million and
$36 million. Our
Value-at-Risk increased
significantly during 2005 due to several financial swaps and
option contracts that we entered into during 2004 and 2005 to
provide price protection on a portion of the Company’s
anticipated natural gas and oil production. These contracts
increased our exposure to market changes in natural gas and oil
prices, which were volatile during 2005. This volatility may
continue into the future and actual losses in fair value may
exceed those measured by
Value-at-Risk.
Exploration and
Production
Our Exploration and Production segment attempts to mitigate
commodity price risk and to stabilize cash flows associated with
its forecasted sales of natural gas and oil production through
the use of derivative natural gas and oil swap contracts. The
table below presents the hypothetical sensitivity to changes in
fair values arising from immediate selected potential changes in
the quoted market prices of the derivative commodity instruments
used to mitigate these market risks. Any gain or loss on these
derivative commodity instruments would be substantially offset
by a corresponding gain or loss on the hedged commodity
positions, which are not included in the table. These
derivatives do not hedge all of our commodity price risk related
to our forecasted sales of our natural gas and oil production
and, as a result, we are subject to commodity price risks on our
remaining forecasted natural gas and oil production.
10 Percent Increase
10 Percent Decrease
Fair Value
Fair Value
(Decrease)
Fair Value
Increase
(In millions)
Impact of changes in commodity prices on derivative commodity
instruments
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 long-term
interest-bearing
securities by expected maturity dates as well as the total fair
value of those securities. The fair value of the securities has
been estimated based on quoted market prices for the same or
similar issues.
Expected Fiscal Year of Maturity of Carrying Amounts
Fair
Carrying
Fair
2006
2007
2008
2009
2010
Thereafter
Total
Value
Amounts
Value
(In millions)
Long-term debt and other obligations, including current
portion — fixed rate
$
1,062
$
747
$
643
$
1,300
$
1,536
$
10,841
$
16,129
$
16,573
$
17,747
$
18,387
Average interest rate
4.9
%
6.7
%
6.9
%
6.5
%
8.5
%
7.6
%
Long-term debt and other obligations, including current
portion — variable rate
$
149
$
33
$
33
$
1,179
$
515
$
196
$
2,105
$
2,105
$
1,442
$
1,442
Average interest rate
9.5
%
6.1
%
6.1
%
6.2
%
6.1
%
5.9
%
Foreign Currency Exchange Rate Risk
Debt
Our exposure to foreign currency exchange rates relates
primarily to changes in foreign currency rates on our
Euro-denominated debt obligations. As of December 31, 2005,
we have Euro-denominated debt with a principal amount of
€522 million
of which
€22 million
matures in 2006 and
€500 million
matures in 2009. As of December 31, 2005 and 2004, we had
swaps that effectively converted
€367 million
and
€725 million
of debt into $418 million and $766 million. The
remaining principal at December 31, 2005 and 2004 of
€155 million
and
€325 million
was subject to foreign currency exchange risk.
Several of our international power plants in Asia, Central
America and South America have long-term power sales contracts
that are denominated in the local country’s currencies.
Because we expect to sell substantially all of our Asian and
Central American power plants during the first half of 2006, our
exposure to foreign currency exchange risk related to these
power sales contracts will end when the related power plants are
sold. We do not believe that the remaining exposure is material
to our operations and have not chosen to mitigate this exposure.
MANAGEMENT’S ANNUAL REPORT ON INTERNAL CONTROL OVER
FINANCIAL REPORTING
Our management is responsible for establishing and maintaining
adequate internal control over financial reporting, as defined
by the Securities Exchange Act of 1934, as amended. Our internal
control over financial reporting is designed to provide
reasonable assurance regarding the reliability of financial
reporting and the preparation of financial statements for
external purposes in accordance with generally accepted
accounting principles. It consists of policies and procedures
that:
•
Pertain to the maintenance of records that, in reasonable
detail, accurately and fairly reflect the transactions and
dispositions of our assets;
•
Provide reasonable assurance that transactions are recorded as
necessary to permit preparation of the financial statements in
accordance with generally accepted accounting principles, and
that our receipts and expenditures are being made only in
accordance with authorizations of our management and directors;
and
•
Provide reasonable assurance regarding prevention or timely
detection of unauthorized acquisition, use or disposition of our
assets that could have a material effect on the financial
statements.
Under the supervision and with the participation of management,
including the Chief Executive Officer(CEO) and Chief Financial
Officer(CFO), we made an assessment of the effectiveness of our
internal control over financial reporting as of
December 31, 2005. In making this assessment, we used the
criteria established in Internal Control —
Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission (COSO). Based on our
evaluation, we concluded that our internal control over
financial reporting was effective as of December 31, 2005.
Our assessment of the effectiveness of our internal control over
financial reporting as of December 31, 2005 has been
audited by PricewaterhouseCoopers LLP, an independent registered
public accounting firm, as stated in their report included
herein.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of
El Paso Corporation:
We have completed integrated audits of El Paso
Corporation’s 2005 and 2004 consolidated financial
statements and of its internal control over financial reporting
as of December 31, 2005, and an audit of its 2003
consolidated financial statements in accordance with the
standards of the Public Company Accounting Oversight Board
(United States). Our opinions, based on our audits, are
presented below.
Consolidated Financial Statements and Financial Statement
Schedule
In our opinion, the consolidated financial statements listed in
the accompanying index present fairly, in all material respects,
the financial position of El Paso Corporation and its
subsidiaries (the “Company”) at December 31, 2005
and 2004, and the results of their operations and their cash
flows for each of the three years in the period ended
December 31, 2005 in conformity with accounting principles
generally accepted in the United States of America. In addition,
in our opinion, the financial statement schedule listed in the
accompanying index presents fairly, in all material respects,
the information set forth therein when read in conjunction with
the related consolidated financial statements. These financial
statements and the financial statement schedule are the
responsibility of the Company’s management. Our
responsibility is to express an opinion on these financial
statements and the financial statement schedule based on our
audits. We conducted our audits of these statements in
accordance with the standards of the Public Company Accounting
Oversight Board (United States). 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 of financial statements includes
examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements, assessing the
accounting principles used and significant estimates made by
management, and evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable
basis for our opinion.
As discussed in the notes to the consolidated financial
statements, the Company adopted FASB Interpretation No. 47,
Accounting for Conditional Asset Retirement Obligations,
on December 31, 2005, FASB Staff Position No. 106-2,
Accounting and Disclosure Requirements Related to the
Medicare Prescription Drug Improvement and Modernization Act of
2003, on July 1, 2004, FASB Interpretation No. 46,
Consolidation of Variable Interest Entities, an
Interpretation of ARB No. 51, on January 1, 2004,
Statement of Financial Accounting Standards
(SFAS) No. 150, Accounting for Certain Financial
Instruments with Characteristics of Both Liabilities and
Equity, on July 1, 2003 and SFAS No. 143,
Accounting for Asset Retirement Obligations.
Internal Control Over Financial Reporting
Also, in our opinion, management’s assessment, included in
Management’s Annual Report on Internal Control Over
Financial Reporting appearing under Item 8, that the
Company maintained effective internal control over financial
reporting as of December 31, 2005 based on criteria
established in Internal Control — Integrated
Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission (COSO), is fairly
stated, in all material respects, based on those criteria.
Furthermore, in our opinion, the Company maintained, in all
material respects, effective internal control over financial
reporting as of December 31, 2005, based on criteria
established in Internal Control — Integrated
Framework issued by the COSO. The Company’s management
is responsible for maintaining effective internal control over
financial reporting and for its assessment of the effectiveness
of internal control over financial reporting. Our responsibility
is to express opinions on management’s assessment and on
the effectiveness of the Company’s internal control over
financial reporting based on our audit. We conducted our audit
of internal control over financial reporting in accordance with
the standards of the Public Company Accounting Oversight Board
(United States). Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether
effective internal control over financial reporting was
maintained in all material respects. An audit of internal
control over financial reporting includes obtaining an
understanding of internal control over
financial reporting, evaluating management’s assessment,
testing and evaluating the design and operating effectiveness of
internal control, and performing such other procedures as we
consider necessary in the circumstances. We believe that our
audit provides a reasonable basis for our opinions.
A company’s internal control over financial reporting is a
process designed to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of
financial statements for external purposes in accordance with
generally accepted accounting principles. A company’s
internal control over financial reporting includes those
policies and procedures that (i) pertain to the maintenance
of records that, in reasonable detail, accurately and fairly
reflect the transactions and dispositions of the assets of the
company; (ii) provide reasonable assurance that
transactions are recorded as necessary to permit preparation of
financial statements in accordance with generally accepted
accounting principles, and that receipts and expenditures of the
company are being made only in accordance with authorizations of
management and directors of the company; and (iii) provide
reasonable assurance regarding prevention or timely detection of
unauthorized acquisition, use, or disposition of the
company’s assets that could have a material effect on the
financial statements.
Because of its inherent limitations, internal control over
financial reporting may not prevent or detect misstatements.
Also, projections of any evaluation of effectiveness to future
periods are subject to the risk that controls may become
inadequate because of changes in conditions, or that the degree
of compliance with the policies or procedures may deteriorate.
Preferred stock, par value $0.01 per share; authorized
50,000,000 shares; issued 750,000, 4.99% convertible
perpetual shares in 2005; stated at liquidation value
750
—
Common stock, par value $3 per share; authorized
1,500,000,000 shares; issued 667,082,043 shares in 2005 and
651,064,508 shares in 2004
2,001
1,953
Additional paid-in capital
4,592
4,538
Accumulated deficit
(3,415
)
(2,809
)
Accumulated other comprehensive income (loss)
(332
)
1
Treasury stock (at cost); 7,620,272 shares in 2005 and 7,767,088
shares in 2004
1. Basis of Presentation and Significant Accounting
Policies
Basis of Presentation
Our consolidated financial statements include the accounts of
all majority owned and controlled subsidiaries after the
elimination of all significant intercompany accounts and
transactions. Our results for all periods presented reflect our
south Louisiana gathering and processing assets, which were part
of our Field Services segment, certain of our international
power operations, our Canadian and certain other international
natural gas and oil production operations, our petroleum markets
operations and our coal mining operations 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 loss or stockholders’ equity.
Principles of
Consolidation
We consolidate entities when we either (i) have the ability
to control the operating and financial decisions and policies of
that entity or (ii) are allocated a majority of the
entity’s losses and/or returns through our variable
interests in that entity. The determination of our ability to
control or exert significant influence over an entity and if we
are allocated a majority of the entity’s losses and/or
returns involves the use of judgment. We apply the equity method
of accounting where we can exert significant influence over, but
do not control, the policies and decisions of an entity and
where we are not allocated a majority of the entity’s
losses and/or returns. We use the cost method of accounting
where we are unable to exert significant influence over the
entity. On January 1, 2004, we adopted the provisions of
FASB Financial Interpretation (FIN) No. 46,
Consolidation of Variable Interest Entities, an
Interpretation of ARB No. 51. The adoption of this
standard did not have a material impact to our financial
statements. For a further discussion of our variable interests,
see Note 21.
Use of Estimates
The preparation of financial statements in conformity with
accounting principles generally accepted in the U.S. 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.
Regulated Operations
Our interstate natural gas pipelines and storage operations are
subject to the jurisdiction of the FERC in accordance with the
Natural Gas Act of 1938, the Natural Gas Policy Act of 1978 and
the Energy Policy Act of 2005. Of our regulated pipelines, all
but ANR follow the regulatory accounting principles prescribed
under Statement of Financial Accounting Standards (SFAS)
No. 71, Accounting for the Effects of Certain Types of
Regulation. ANR discontinued the application of SFAS
No. 71 in 1996, primarily due to the level of competition
and discounting in ANR’s market areas, uncertainties
related to expired contracts and the construction of competing
facilities. The accounting required by SFAS No. 71 differs
from the accounting required for businesses that do not apply
its provisions. Items that are generally recorded differently as
a result of applying regulatory accounting requirements include
postretirement employee benefit plan costs, an equity return
component on regulated capital projects and certain costs
included in, or expected to be included in, future rates.
We perform an annual review to assess the applicability of the
provisions of SFAS No. 71 to our financial statements, the
outcome of which could result in the re-application of this
accounting in some of our regulated systems or the
discontinuance of this accounting in others.
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 restricted
cash in other current or
non-current assets on
our balance sheet based on when we expect this cash to be used.
As of December 31, 2005, we had $281 million of
restricted cash in current assets and $168 million in other
non-current assets. As
of December 31, 2004, we had $180 million of
restricted cash in current assets and $180 million in other
non-current assets.
Allowance for Doubtful
Accounts
We establish provisions for losses on accounts and notes
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.
Property, Plant and Equipment
Our property, plant and equipment is recorded at its original
cost of construction or, upon acquisition, at the fair value of
the assets acquired. For assets we construct, 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’ property, plant and equipment. 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 and depreciable lives:
Under the composite (group) method, assets with similar useful
lives and other characteristics are grouped and depreciated as
one asset. We apply the depreciation rate approved in our rate
settlements 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.
When we retire regulated property, plant and equipment, 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 operating income.
We capitalize a carrying cost on funds related to our
construction of long-lived assets. This carrying cost consists
of (i) an interest cost on our debt that could be
attributed to the assets, which applies to all of our regulated
transmission businesses and unevaluated costs related to our
natural gas and oil properties, and (ii) a return on our
equity, that could be attributed to the assets, which only
applies to regulated transmission businesses that apply
SFAS No. 71. The debt portion is calculated based on
the average cost of debt. Interest cost on debt amounts
capitalized during the years ended December 31, 2005, 2004
and 2003, were $45 million,
$39 million and $31 million. 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, 2005, 2004
and 2003 were $31 million, $22 million and
$19 million. These amounts are included as other
non-operating income on our income statement. Capitalized
carrying costs for debt and equity-financed construction are
reflected as an increase in the cost of the asset on our balance
sheet.
Asset and Investment
Impairments
We evaluate our assets and investments for impairment when
events or circumstances indicate that their carrying values may
not be recovered. These events include market declines that are
believed to be other than temporary, changes in the manner in
which we intend to use a long-lived asset, decisions to sell an
asset or investment and adverse changes in the legal or business
environment such as adverse actions by regulators. When an event
occurs, we evaluate the recoverability of our carrying value
based on either (i) our long-lived assets’ ability to
generate future cash flows on an undiscounted basis or
(ii) the fair value of our investments in unconsolidated
affiliates. If an impairment is indicated or if we decide to
sell a long-lived asset or group of assets, we adjust the
carrying values of these assets downward, if necessary, to their
estimated fair value, less costs to sell. Our fair value
estimates are generally based on market data obtained through
the sales process or an analysis of expected discounted cash
flows. The magnitude of any impairments are impacted by a number
of factors, including the nature of the assets being sold and
our established time frame for completing the sales, among other
factors. We also reclassify the asset or assets as either
held-for-sale or as discontinued operations, depending on, among
other criteria, whether we will have significant continuing
involvement in the cash flows of those assets after they are
sold.
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
costs incurred in connection with the acquisition, development
and exploration of natural gas and oil reserves are capitalized.
These capitalized amounts include the costs of unproved
properties, internal costs directly related to acquisition,
development and exploration activities, asset retirement costs
and capitalized interest. Under the full cost method, both dry
hole costs and geological and geophysical costs are capitalized
into the full cost pool, which is subject to amortization and
periodically assessed in our ceiling test calculations as
discussed below.
Capitalized costs associated with proved reserves are amortized
over the life of the reserves using the unit of production
method. Conversely, capitalized costs associated with unproved
properties are excluded from the amortizable base until these
properties are evaluated, which occurs on a quarterly basis.
Specifically, we transfer costs to the amortizable base when
properties are determined to have proved reserves. In addition,
we transfer unproved property costs to the amortizable base when
unproved properties are evaluated as being impaired and as
exploratory dry holes are determined to be unsuccessful.
Additionally, the amortizable base includes future development
costs and dismantlement, restoration and abandonment costs, net
of estimated salvage values; and geological and geophysical
costs incurred that cannot be associated with specific
unevaluated properties or prospects in which we own a direct
interest.
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 the
ceiling is not greater than or equal to the total capitalized
costs, we are required to write-down our capitalized costs to
the ceiling. 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, and that qualify as, cash flow hedges of our
anticipated future natural gas and oil production. Our ceiling
test calculations exclude the estimated future cash outflows
associated with asset retirement liabilities related to proved
developed reserves.
When we sell or convey interests in our natural gas and oil
properties, we reduce our natural gas and oil reserves for the
amount attributable to the sold or conveyed interest. 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.
Goodwill and Other
Intangible Assets
Our intangible assets consist of goodwill resulting from
acquisitions and other intangible assets. Goodwill is not
amortized, but instead is periodically tested for impairment, at
least annually, and whenever an event occurs that indicates that
an impairment may have occurred. We amortize all other
intangible assets on a straight-line basis over their estimated
useful lives.
The net carrying amounts of our goodwill as of December 31,2005 and 2004 and the changes in the net carrying amounts of
goodwill for the years ended December 31, 2005 and 2004 by
segment are as follows:
The goodwill impairment in our Field Services segment resulted
from the sales of our GulfTerra investment and certain segment
assets. As a result of these sales, we determined that the
remaining segment assets could not support the segment’s
goodwill.
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 related to these plans 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 function of the employee’s salary, the level of
benefits provided under the plan, actuarial assumptions, and the
passage of time), expected returns on plan assets and
amortization of certain deferred gains and losses. For a further
discussion of our policies with respect to our pension and
postretirement plans, See Note 17.
In our balance sheet, changes in the recorded assets and
liabilities associated with our primary pension plan and other
postretirement benefit plans are based on the amounts of our
contributions, benefit expense and changes in deferred gains and
losses during a given period. Changes in the liabilities on our
other pension plans are reported as changes in other
comprehensive income, net of income taxes, on our financial
statements. For a further discussion of the contributions,
benefits and deferred gains and losses related to our pension
and other postretirement obligations see Note 17.
In 2004, we adopted FASB Staff Position (FSP)
No. 106-2,
Accounting and Disclosure Requirements Related to the
Medicare Prescription Drug, Improvement and Modernization Act of
2003. This pronouncement required us to record the impact of
the Medicare Prescription Drug, Improvement and Modernization
Act of 2003 on our postretirement benefit plans that provide
drug benefits that are covered by that legislation. The adoption
of FSP No. 106-2
decreased our accumulated postretirement benefit obligation by
$49 million, which is accounted for as an actuarial gain in
our postretirement benefit liabilities as of December 31,2005 and 2004. The adoption of this guidance reduced our
postretirement benefit expense by approximately $6 million
in 2005.
Our business segments provide a number of services and sell a
variety of products. The revenue recognition policies of our
most significant operating segments are as follows:
Pipelines revenues. Our Pipelines segment derives
revenues primarily from transportation and storage services. For
our transportation and storage services, we recognize
reservation revenues on firm contracted capacity ratably over
the contract period regardless of the amount of natural gas that
is transported or stored. For interruptible or volumetric based
services, we record revenues when physical deliveries of natural
gas are made at the agreed upon delivery point or when gas is
injected or withdrawn from the storage facility. Gas not needed
for operations is based on the volumes we are allowed to retain
relative to the amounts of gas we use for operating purposes. We
recognize revenue from gas not used in operations when we retain
the volumes under our tariffs. Revenues for all services are
generally based on the thermal quantity of gas delivered or
subscribed at a price specified in the contract. We are subject
to FERC regulations and, as a result, revenues we collect in
rate proceedings may be subject to refund. We establish reserves
for these potential refunds.
Exploration and Production revenues. Our Exploration and
Production segment derives revenues primarily through the
physical sale of natural gas, oil, condensate and NGL. 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.
Power and Marketing and Trading revenues. Our Power and
Marketing and Trading segments derive revenues from physical
sales of natural gas and power and the management of their
derivative contracts. Our derivative transactions are recorded
at their fair value and changes in their fair value are
reflected in operating revenues. See a discussion of our income
recognition policies on derivatives below under Price Risk
Management Activities. Revenues on physical sales are
recognized at the time the commodity is delivered and are based
on the volumes delivered and the contractual or market price.
Environmental Costs and Other Contingencies
Environmental Costs. We record liabilities at their
undiscounted amounts on our balance sheet in other current and
long-term liabilities when our environmental assessments
indicate that remediation efforts are probable and the costs 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 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. Our estimates are subject to
revision in future periods based on actual costs or new
circumstances. We capitalize costs that benefit future periods
and we recognize a current period charge in operation and
maintenance expense when clean-up efforts do not benefit future
periods.
We evaluate separately from our liability any amounts paid
directly or reimbursed by government sponsored programs and
potential recoveries or reimbursements of remediation costs from
third parties including insurance coverage. When recovery is
assured after an evaluation of their creditworthiness or
solvency, we record and report an asset separately from the
associated liability on our balance sheet.
Other Contingencies. 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 the associated
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.
Our price risk management activities consist of the following
activities:
•
derivatives entered into to hedge or otherwise reduce the
commodity, interest rate and foreign currency exposure on our
natural gas and oil production and our long-term debt;
•
derivatives related to our historical power contract
restructuring business; and
•
derivatives related to trading activities that we historically
entered into with the objective of generating profits from
exposure to shifts or changes in market prices.
Our derivatives are reflected on our balance sheet at their fair
value as assets and liabilities from price risk management
activities. We classify our derivatives as either current or
non-current assets or
liabilities based on their anticipated settlement date. We net
derivative assets and liabilities for counterparties where we
have a legal right of offset. See Note 10 for a further
discussion of our price risk management activities.
Derivatives that we have designated as accounting hedges impact
our revenues or expenses based on the nature and timing of the
transactions that they hedge. Derivatives related to our power
contract restructuring activities are marked-to-market and
reflected as either revenues (for changes in the fair values of
the power sales contracts) or expenses (for changes in the fair
values of the power supply agreements). We report the changes in
the fair value of our other derivative contracts in revenue.
In our cash flow statement, cash inflows and outflows associated
with the settlement of our derivative instruments are recognized
in operating cash flows (other than those derivatives intended
to hedge the principal amounts of our foreign currency
denominated debt). In our balance sheet, receivables and
payables resulting from the settlement of our derivative
instruments are reported as trade receivables and payables.
Income Taxes
We record current income taxes based on our current 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.
Foreign Currency Translation
For foreign operations whose functional currency is the local
currency, assets and liabilities are translated at year-end
exchange rates and revenues and expenses are translated at
average exchange rates prevailing during the year. The
cumulative translation effects are included as a separate
component of accumulated other comprehensive income (loss) in
stockholders’ equity.
Accounting for Asset Retirement Obligations
On January 1, 2003, we adopted SFAS No. 143,
Accounting for Asset Retirement Obligations, which
requires that we record a liability for retirement and removal
costs of long-lived assets used in our business when the timing
and/or amount of the settlement of those costs are relatively
certain. On December 31, 2005, we adopted the provisions of
FIN No. 47, Accounting for Conditional Asset
Retirement Obligations, which requires that we record a
liability for those retirement and removal costs in which the
timing and/or amount of the settlement of the costs are
uncertain.
We have legal obligations associated with our natural gas and
oil wells and related infrastructure, our natural gas pipelines
and related transmission facilities and storage wells, as well
as in our corporate headquarters building. We have obligations
to plug wells when production on those wells is exhausted or we
no
longer plan to use them, and when we abandon them. Our legal
obligations associated with our natural gas transmission
facilities relate primarily to purging and sealing the pipelines
if they are abandoned. We also have obligations to remove
hazardous materials associated with our natural gas transmission
facilities and in our corporate headquarters if these facilities
are replaced or renovated. We accrue a liability on those legal
obligations when we can estimate the timing and amount of their
settlement. These obligations include those where we have plans
to or otherwise will be legally required to replace, remove or
retire the associated assets. Substantially all of our natural
gas pipelines can be maintained indefinitely and, as a result,
we have not accrued a liability associated with purging and
sealing them.
Our asset retirement liabilities are recorded at their estimated
fair value with a corresponding increase to property, plant and
equipment. This increase in property, plant and equipment is
then depreciated over the remaining useful life of the
long-lived asset to which that liability relates. An ongoing
expense is also recognized for changes in the value of the
liability as a result of the passage of time, which we record in
depreciation, depletion and amortization expense in our income
statement. Many of our regulated pipelines have the ability to
file for recovery of certain of these costs from their customers
and have recorded an asset (rather than expense) associated with
the depreciation of the property, plant and equipment and
accretion of the liabilities described above. We recorded a
charge as a cumulative effect of accounting change, net of
income taxes of $4 million in 2003 and $2 million in 2005, of
approximately $9 million in the first quarter of 2003 and
$4 million in the fourth quarter of 2005 related to our
adoption of SFAS No. 143 (primarily related to our
Exploration and Production segment), and FIN No. 47
(primarily related to our Pipelines segment and our corporate
activities), respectively.
In estimating the liability associated with our asset retirement
obligations, we utilize several assumptions, including
credit-adjusted discount rates ranging from six to eight
percent, a projected inflation rate of 2.5 percent and the
estimated timing and amount of settling our obligations, which
are based on internal models and external quotes. The net asset
retirement liability as of December 31 reported on our
balance sheet in other current and non-current liabilities, and
the changes in the net liability for the years ended
December 31, were as follows:
2005
2004
(In millions)
Net asset retirement liability at January 1
$
322
$
269
Liabilities
settled(1)
(93
)
(38
)
Accretion expense
28
25
Liabilities incurred
19
36
Changes in estimate
(16
)
30
Adoption of FIN No. 47
15
—
Net asset retirement liability at December 31
$
275
$
322
(1)
Increase is due primarily to the sale of certain domestic
natural gas and oil properties in our Exploration and Production
segment. For a further discussion of these divestitures see Note
3.
Our changes in estimate represent changes to the expected amount
and timing of payments to settle our asset retirement
obligations. These changes primarily result from obtaining new
information about the timing of our obligations to plug our
natural gas and oil wells and the costs to do so. If we had
adopted the provisions of FIN No. 47 as of
January 1, 2004, our asset retirement liability would have
been higher by approximately $13 million and
$14 million as of January 1, 2004 and
December 31, 2004, and our net income for the years ended
December 31, 2004 and 2005 would not have been materially
affected.
Accounting for Certain Financial Instruments with
Characteristics of both Liabilities and Equity
On July 1, 2003, we adopted the provisions of
SFAS No. 150, Accounting for Certain Financial
Instruments with Characteristics of both Liabilities and
Equity and reclassified $625 million of our Capital
Trust I and Coastal Finance I preferred interests from
preferred interests of consolidated subsidiaries to
long-term financing
obligations on our balance sheet as required by that standard.
We also began classifying dividends accrued on these preferred
interests as interest and debt expense in our income statement.
Stock-Based Compensation
We account for our stock-based compensation plans using the
intrinsic value method under the provisions of Accounting
Principles Board Opinion (APB) No. 25, Accounting for
Stock Issued to Employees, and its related interpretations.
We grant stock awards under stock option plans, restricted stock
plans, and employee stock purchase programs. Our stock options
are granted under a fixed plan at the market value on the date
of grant. Accordingly, no compensation expense is recognized.
Had we accounted for our stock-based compensation using the fair
value recognition provisions of SFAS No. 123,
Accounting for
Stock-Based
Compensation, rather than APB No. 25, the net loss
available to common stockholders and per share impacts on our
financial statements would have been different. The following
table shows the impact on net loss available to common
stockholders and loss per share had we applied
SFAS No. 123 (See Note 19 for the weighted
average assumptions of our options granted in 2005, 2004 and
2003):
Net loss available to common stockholders, as reported
$
(633
)
$
(947
)
$
(1,883
)
Add: Stock-based employee compensation expense included in
reported net loss, net of taxes
12
14
38
Deduct: Total stock-based compensation expense determined under
fair-value based method for all awards, net of
taxes(1)
(19
)
(25
)
(38
)
Net loss available to common stockholders, pro forma
$
(640
)
$
(958
)
$
(1,883
)
Loss per share:
Basic and diluted, as reported
$
(0.98
)
$
(1.48
)
$
(3.15
)
Basic and diluted, pro forma
$
(0.99
)
$
(1.50
)
$
(3.15
)
(1)
Amounts have been adjusted from those previously reported to
reflect the impact of actual forfeitures of unvested stock
option awards on proforma compensation expense.
New Accounting Pronouncements Issued But Not Yet Adopted
As of December 31, 2005, there were several accounting
standards and interpretations that had not yet been adopted by
us. Below is a discussion of significant standards that may
impact us.
Accounting for Stock-Based Compensation. In December
2004, the FASB issued SFAS No. 123(R), Share-Based
Payment. This standard and related interpretations amend
previous stock-based compensation guidance and require companies
to measure all employee stock-based compensation awards at fair
value on the date they are granted to employees and recognize
compensation cost in its financial statements over the requisite
service period. The fair value of options is determined by a
model (e.g. Black-Scholes or binomial) using a variety of
assumptions, the most significant of which are expected price
volatility and expected term of the option. We also make
assumptions about expected forfeiture rates. Our assumptions for
new awards upon adoption of this standard could differ from
those we have historically utilized. We will adopt
SFAS No. 123(R) and related interpretations on
January 1, 2006 prospectively for awards of stock-based
compensation granted after that date and for the unvested
portion of outstanding awards at that date. Based on the
stock-based compensation awards outstanding as of
December 31, 2005 and our anticipated level of stock-based
compensation awards in 2006, we expect to record incremental
compensation expense of approximately $15 million to
$20 million as a result of adopting this standard.
Accounting for Pipeline Integrity Costs. In June 2005,
the FERC issued an accounting release that will impact certain
costs our interstate pipelines incur related to their pipeline
integrity programs requiring us to
prospectively expense certain costs incurred after
January 1, 2006, instead of our current practice of
capitalizing them as part of our property, plant and equipment.
In December 2005, FERC approved a request to allow one of
our regulated pipeline subsidiaries, EPNG, to adopt the
provisions of this release in December 2005, which did not
have a material impact on our financial statements for the year
ended December 31, 2005. We currently estimate that we will
be required to expense an additional amount of pipeline
integrity costs under this accounting release in the range of
approximately $26 million to $41 million annually.
2. Acquisitions
Medicine Bow. In August 2005, we acquired Medicine Bow, a
privately held energy company for total cash consideration of
$853 million. Medicine Bow owns a 43.1 percent
interest in Four Star, an unconsolidated affiliate. Our
proportionate share of the future operating results associated
with Four Star will be reflected as earnings from unconsolidated
affiliates in our financial statements.
The Medicine Bow acquisition was accounted for using the
purchase method of accounting. No goodwill was recorded
associated with the acquisition. As part of our purchase price
allocation, we allocated approximately $0.4 billion to
property, plant, and equipment (of which $0.3 billion
related to properties in our natural gas and oil full cost
pool), $0.8 billion to our unconsolidated investment in
Four Star, and $0.4 billion related to deferred tax
liabilities. We reflected Medicine Bow’s results of
operations in our income statement beginning
September 1, 2005. The following summary unaudited pro
forma consolidated results of operations for the years ended
December 31, 2005 and 2004 reflect the combination of
our historical income statements with Medicine Bow, adjusted for
certain effects of the acquisition and related funding. These
pro forma results are prepared as if the acquisition had
occurred as of the beginning of the periods presented and are
not necessarily indicative of the operating results that would
have occurred had the acquisition been consummated at that date,
nor are they necessarily indicative of future operating results.
Chaparral and Gemstone. During 2003, we acquired the
remaining third party interests in our Chaparral and Gemstone
power generation investments for approximately $1 billion
and began consolidating them in the first and second quarters of
2003, respectively. We have reflected the results of operations
in our income statement for Chaparral as though we acquired it
on January 1, 2003 and the results of operations for
Gemstone in our income statement since April 1, 2003. Had
we acquired Gemstone on January 1, 2003, our net income and
loss per share would have been unaffected.
3.
Divestitures
Sales of Assets and Investments
During 2005, 2004 and 2003, we completed the sale of a number of
assets and investments in each of our business segments and
corporate operations. The following table summarizes the
proceeds from these sales:
2005
2004
2003
(In millions)
Pipelines
$
49
$
59
$
145
Exploration and Production
7
24
673
Power
625
884
768
Field Services
657
1,029
753
Corporate
121
16
149
Total
continuing(1)
1,459
2,012
2,488
Discontinued
577
1,295
808
Total
$
2,036
$
3,307
$
3,296
(1)
Proceeds exclude returns of invested capital and cash
transferred with the assets sold and include costs incurred in
preparing assets for disposal. These items decreased our sales
proceeds by $35 million, $85 million and
$30 million for the years ended December 31, 2005,
2004 and 2003.
The following table summarizes the significant assets sold. See
Notes 5 and 21 for a discussion of gains, losses and impairments
related to the sales below:
2005
2004
2003
Pipelines
• Facilities located in the southeastern U.S.
• Interest in a gathering system in the western U.S.
• Australian pipelines
• Interest in gathering systems
• 2.1% interest in Alliance pipeline
• Equity interest in Portland Natural Gas Transmission
System
• Horsham pipeline in Australia
Exploration and Production
• Miscellaneous domestic natural gas and oil properties
• Brazilian exploration and production acreage
• Natural gas and oil properties in NM, TX, LA, OK and
the Gulf of Mexico
Power
• Cedar Brakes I and II
• Interest in power plants in Korea, India, England
and China
• Four domestic power plants
• Portion of investment in Intercontinental
Exchange
• Mohawk River Funding II
• Power turbines
• Utility Contract Funding
• 31 domestic power plants and several turbines
• Interest in CE Generation L.L.C.
• Mt. Carmel power plant
• CAPSA/CAPEX investments
• East Coast Power
Field Services
• General partner and
common unit interests in Enterprise
• Interest in Indian Springs natural gas gathering
system and processing facility
• Interest in Javelina natural gas processing and
pipeline assets
• Remaining general partnership interest, common units
and Series C units in GulfTerra
• South TX processing plants
• Dauphin Island and Mobile Bay investments
• Gathering systems located in WY
• Midstream assets in the north LA and Mid-Continent
regions
• Common, Series B preference units and
50 percent general partnership interests in GulfTerra
Corporate
• Lakeside Technology Center
• Aircraft
• Aircraft
• Enerplus Global Energy Management Company and
its financial operations
• EnCap funds management business and its investments
Discontinued
• Interest in Paraxylene facility
• MTBE processing facility
• International natural gas and oil properties
• South Louisiana gathering and processing assets
• Ammonia manufacturing facility
• Natural gas and oil properties in Canada and other
international production assets
• Aruba and Eagle Point refineries and other
petroleum assets
• Corpus Christi refinery
• Florida petroleum terminals
• Louisiana lease crude
• Coal reserves
• Canadian natural gas and oil properties
• Asphalt facilities
We have also completed or entered into agreements to sell
(i) our interests in our remaining Asian power assets
(which includes our CEBU and East Asia Utilities power plants in
discontinued operations) for $174 million;
(ii) substantially all of our interests in our Central and
other South American power assets (which includes our Nejapa
power plant in discontinued operations) for $164 million;
(iii) our interest in a power facility in Hungary for
$28 million; and (iv) a power turbine for
$9 million. In February 2006, we entered into a memorandum
of understanding to settle our ongoing contractual disputes with
Petrobras relating to the Macae power facility and to sell our
interest in the facility to Petrobras for $358 million. We
also signed a letter of intent in February 2006 to resolve the
arbitration proceedings with COPEL relating to the Araucaria
power facility and to sell our interest in the facility to COPEL
for $190 million. See Note 16 for a further discussion
of these matters.
Discontinued Operations
South Louisiana Gathering and Processing Operations.
During the second quarter of 2005, our Board of Directors
approved the sale of our south Louisiana gathering and
processing assets, which were part of our Field Services
segment. In the fourth quarter of 2005, we completed the sale of
these assets for net proceeds of approximately $486 million
and recorded a pre-tax
gain of approximately $394 million.
International Power Operations. During 2005, our Board of
Directors approved the sale of our Asian and Central American
power asset portfolio, which included our consolidated interests
in the Nejapa, CEBU and East Asia Utilities power plants. During
2005, we recognized approximately $166 million of impairment
losses, net of minority interest, based on our decision to sell
these assets. We expect to complete the sale of our Nejapa, CEBU
and East Asia Utilities power plants during 2006.
International Natural Gas and Oil Production Operations.
During 2004, our Canadian and certain other international
natural gas and oil production operations were approved for
sale. As of December 31, 2005, we have completed the sale
of substantially all of these properties for total proceeds of
approximately $395 million. During 2005 and 2004, we
recognized approximately $5 million and $22 million in
losses based on our decision to sell these assets.
Petroleum Markets. During 2003, the sales of our
petroleum markets businesses and operations were approved. These
businesses and operations consisted of our Eagle Point and Aruba
refineries, our asphalt business, our Florida terminal, tug and
barge business, our lease crude operations, our Unilube blending
operations, our domestic and international terminalling
facilities and our petrochemical and chemical plants. Based on
our intent to dispose of these operations, we were required to
adjust these assets to their estimated fair value. As a result,
we recognized pre-tax impairment charges during 2003 of
approximately $1.5 billion related to certain of these
assets. These impairments were based on a comparison of the
carrying value of these assets to their estimated fair value,
less selling costs. We also recorded realized gains of
approximately $59 million in 2003 from the sale of our
Corpus Christi refinery, our asphalt assets and our Florida
terminalling and marine assets.
In 2004, we completed the sales of our Aruba and Eagle Point
refineries for $880 million and used a portion of the
proceeds to repay $370 million of debt associated with the
Aruba refinery. We recorded realized losses of approximately
$32 million in 2004, primarily from the sale of our Aruba
and Eagle Point refineries.
Coal Mining. In 2003, we sold our coal mining operations,
which consisted of fifteen active underground and two surface
mines located in Kentucky, Virginia and West Virginia. We
received sales proceeds of $92 million in cash and
$24 million in notes receivable, which were settled in the
second quarter of 2004. We did not record a significant gain or
loss on these sales.
As of December 31, 2005 and 2004, our assets held for sale
(which primarily relate to a natural gas gathering system and
processing facility we sold in 2005) and the assets of our
discontinued operations were $36 million and
$587 million and our total liabilities were $8 million
and $170 million primarily related to property, plant and
equipment and working capital balances related to these
facilities. The summarized operating results of our discontinued
operations were as follows:
Loss from discontinued operations, net of income taxes
$
(1,269
)
4.
Restructuring and Other Charges
The discussion below provides additional details of certain
costs incurred in connection with our ongoing liquidity
enhancement and cost reduction efforts in 2003, 2004, and 2005
and in conjunction with our Western Energy Settlement. These
charges were recorded as part of operations and maintenance
expense.
Employee severance, retention and transition costs.
Employee severance costs were not significant in 2005.
During 2004, we eliminated approximately 1,900 full-time
positions from our continuing businesses and approximately 1,200
positions related to businesses we discontinued. As a result, we
incurred approximately $38 million of employee severance
costs primarily related to our Exploration and Production
segment and corporate operations. Additionally, during 2003, we
eliminated approximately 900 full-time positions from our
continuing businesses and approximately 1,800 positions
related to businesses we discontinued and incurred approximately
$76 million of employee severance costs, primarily related
to our Marketing and Trading segment and corporate operations.
As of December 31, 2005, substantially all of the total employee
severance, retention and transition costs had been paid.
Office relocation and consolidation. During 2004, we
announced that we would consolidate our Houston-based operations
into one location and incurred $80 million of charges to
record the discounted liability, net of estimated sub-lease
rentals, for our obligations under leases for space we no longer
use. In 2005, we vacated our remaining leased space, signed a
termination agreement on the lease and recorded additional
charges of $27 million related to these actions. The costs
associated with this office relocation and consolidation have
been charged to corporate operations. Actual moving expenses
related to the relocation were insignificant and were expensed
in the periods that they were incurred. As of December 31,2005, our remaining liability associated with this consolidation
and relocation was $97 million.
Western Energy Settlement. During 2003 and 2005, we
incurred charges in operations and maintenance expense related
to the final resolution of our Western Energy Settlement of
$104 million and $59 million. Final payments under
this settlement were made in early 2005.
Other. In 2003, our contract termination and other costs
included charges of approximately $44 million related to
amounts paid for canceling or restructuring our obligations to
transport LNG from supply areas to domestic and international
market centers and were charged to corporate operations.
5. (Gain) Loss on Long-Lived Assets
Our (gain) loss on long-lived assets from continuing operations
consists of realized gains and losses on sales of long-lived
assets and impairments of long-lived assets, including goodwill
and other intangibles. During each of the three years ended
December 31, our (gain) loss on long-lived assets was as
follows:
2005
2004
2003
(In millions)
Net realized (gain) loss
$
1
$
(16
)
$
69
Asset impairments
Power
Brazilian
assets(1)
333
183
—
Domestic assets and restructured power contract entities
(2)
—
397
147
Turbines(2)
18
1
33
Pipelines
Pipeline development
projects(3)
46
—
—
Field Services
Goodwill
impairment(4)
—
480
—
Indian Springs processing
assets(2)
—
13
—
South Texas processing
assets(2)
—
—
167
Other
9
10
4
Exploration and Production
Other
—
8
10
Corporate
Telecommunications
assets(2)
—
—
396
Other
—
1
34
Total asset impairments
406
1,093
791
Loss on long-lived assets
407
1,077
860
(Gain) loss on sale of investments in unconsolidated affiliates,
net of
impairments(5)
(91
)
(124
)
176
Loss on assets and investments
$
316
$
953
$
1,036
(1)
These assets were impaired as a result of negotiations
associated with the power contracts of these plants. See
Note 16 for a further discussion of these matters.
(2)
We adjusted the carrying value of these assets to their
estimated fair value, less cost to sell.
(3)
This impairment resulted from our decision to discontinue
development of several pipeline expansion projects.
(4)
This impairment resulted from the sale of substantially all of
our interests in GulfTerra, as well as the sale of our
processing assets in south Texas to affiliates of Enterprise in
2004 (see Note 21).
(5)
See Note 21 for a further description of these gains and
losses.
For additional asset impairments on our discontinued operations
and investments in unconsolidated affiliates, see Notes 3
and 21. For additional discussion on goodwill and other
intangibles, see Note 1.
Pretax Income (Loss) and Income Tax Expense (Benefit).
The tables below show our pretax income (loss) from continuing
operations and the components of income tax expense (benefit)
for each of the years ended December 31:
Effective Tax Rate Reconciliation. Our income taxes,
included in loss from continuing operations, 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:
2005
2004
2003
(In millions, except rates)
Income taxes at the statutory federal rate of 35%
$
(347
)
$
(285
)
$
(381
)
Increase (decrease)
Sales and write-offs of foreign investments
(7
)
14
(53
)
Valuation allowances
91
18
(57
)
Foreign income taxed at different rates
115
144
(20
)
Earnings from unconsolidated affiliates where we anticipate
receiving dividends
(37
)
(18
)
(13
)
Audit
settlements(1)
(58
)
—
—
Non-deductible goodwill impairments
—
139
29
Non-taxable medicare reimbursements
(25
)
—
—
Other
(21
)
2
11
Income taxes
$
(289
)
$
14
$
(484
)
Effective tax rate
29
%
(2
)%
44
%
(1)
We finalized The Coastal Corporation’s IRS tax audits for
years prior to 1997, and as a result, recorded a tax benefit of
approximately $58 million in 2005.
Deferred Tax Assets and Liabilities. The following are
the components of our net deferred tax liability related to
continuing operations as of December 31:
2005
2004
(In millions)
Deferred tax liabilities
Property, plant and equipment
$
3,299
$
2,565
Investments in unconsolidated affiliates
192
410
Regulatory and other assets
321
327
Total deferred tax liability
3,812
3,302
Deferred tax assets
Net operating loss and tax credit carryovers
Federal
1,101
1,194
State
204
174
Foreign
76
35
Environmental liability
159
174
Price risk management activities
573
—
(1)
Legal and other reserves
280
124
Other
601
783
Valuation allowance
(164
)
(51
)
Total deferred tax asset
2,830
2,433
Net deferred tax liability
$
982
$
869
(1)
As of December 31, 2004, we had a net deferred tax
liability associated with our price risk management activities
which was included as part of Regulatory and other assets above.
Prior to 2004, we had not recorded U.S. deferred tax assets or
liabilities on book versus tax basis differences for a
substantial portion of our international investments based on
our intent to indefinitely reinvest earnings from these
investments outside the U.S. However, based on sales
negotiations on certain of our Asian and Central American power
assets, we have received or expect to receive these sales
proceeds within the U.S. During the years ended
December 31, 2005 and 2004, our effective tax rate was
impacted upon recording U.S. deferred tax assets and liabilities
on book versus tax basis differences in these investments based
on the status
of these negotiations. We also recorded U.S. deferred tax
benefits on the sale of a power asset in India. As of
December 31, 2005 and 2004, we have U.S. deferred tax
assets of $103 million and $6 million and U.S.
deferred tax liabilities of $23 million and
$39 million related to these investments.
Cumulative undistributed earnings from the remainder of our
foreign subsidiaries and foreign corporate joint ventures
(excluding our Asian and Central American power assets discussed
above) have been or are intended to be indefinitely reinvested
in foreign operations. Therefore, no provision has been made for
any U.S. taxes or foreign withholding taxes that may be
applicable upon actual or deemed repatriation, and an estimate
of the taxes if earnings were to be repatriated is not
practical. At December 31, 2005, the portion of the
cumulative undistributed earnings from these investments on
which we have not recorded U.S. income taxes was approximately
$121 million. For these same reasons, we have not recorded
a provision for U.S. income taxes on the foreign currency
translation adjustments recorded in accumulated other
comprehensive income.
Tax Credit and NOL Carryovers. As of December 31,2005, we have U.S. federal alternative minimum tax credits
of $303 million that carryover indefinitely and capital
loss carryovers of $11 million for which the carryover
period ends in 2008. The table below presents the details of our
federal and state net operating loss carryover periods as of
December 31, 2005:
Carryover Period
2006
2007-2010
2011-2015
2016-2025
Total
(In millions)
U.S. federal net operating loss
$
—
$
10
$
15
$
2,745
$
2,770
State net operating loss
126
699
553
1,236
2,614
We also had $225 million of foreign net operating loss
carryovers of which $192 million carryover indefinitely,
$30 million carryover through 2007, and the remainder
carryover through 2008 and 2009. Usage of our U.S. federal
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.
Valuation Allowances. Deferred tax assets are recorded on
net operating losses and temporary differences in the book and
tax basis of assets and liabilities expected to produce tax
deductions in future periods. The realization of these assets
depends on recognition of sufficient future taxable income in
specific tax jurisdictions during periods in which those
temporary differences or net operating losses are deductible. In
assessing the need for a valuation allowance on our deferred tax
assets, we consider whether it is more likely than not that some
portion or all of them will not be realized. We believe it is
more likely than not that we will realize the benefit of our
deferred tax assets, net of existing valuation allowances, due
to the effect of future reversals of existing taxable temporary
differences primarily related to depreciation.
During 2005, we recorded foreign deferred tax assets on our
Macae project (which is anticipated to be sold in 2006) from the
generation of tax loss carryforwards and differences in the book
and tax basis of fixed assets due to the impairment of the
project. At this time, we recorded a full valuation allowance of
$51 million on these assets as we do not expect to generate
sufficient future taxable income to realize them. We recorded a
state valuation allowance on deferred state tax assets generated
in 2005, and recorded additional valuation allowances on
existing deferred state tax assets due to changes in expected
revenue allocations for future periods.
Other Tax Matters. The IRS has audited The Coastal
Corporation’s 1998-2000 tax years and El Paso
Corporation’s 2001 and 2002 tax years, and these audits are
pending finalization with the IRS Appeals Office. We anticipate
that these audits will be finalized in either 2006 or 2007. In
addition, the IRS is currently auditing El Paso’s 2003 and
2004 tax years. We have recorded a liability for tax
contingencies associated with these audits, as well as for
proceedings and examinations with other taxing authorities,
which management believes is adequate. As these matters are
finalized, we may be required to adjust our liability which
could significantly increase or decrease our income tax expense
in future periods.
We incurred losses from continuing operations during the three
years ended December 31, 2005. Accordingly, we excluded a
number of securities for the years ended December 2005, 2004,
and 2003 from the determination of diluted earnings per share
due to their antidilutive effect on loss per common share. These
included stock options, restricted stock, trust preferred
securities, equity security units, and convertible debentures.
Additionally, in 2005 we excluded our convertible preferred
stock, which has conversion features discussed in Note 18,
and in 2003, we excluded shares related to our remaining stock
obligation under the Western Energy Settlement. For a further
discussion of these instruments, see Notes 14 and 19.
9. Fair Value of Financial Instruments
The following table presents the carrying amounts and estimated
fair values of our financial instruments as of December 31,2005 and 2004.
2005
2004
Carrying
Carrying
Amount
Fair Value
Amount
Fair Value
(In millions)
Long-term financing obligations, including current maturities
$
18,234
$
18,678
$
19,189
$
19,829
Commodity-based price risk management derivatives
(1,416
)
(1,416
)
68
68
Interest rate and foreign currency derivatives
2
2
239
239
Investments
61
61
47
47
As of December 31, 2005 and 2004, our carrying amounts of
cash and cash equivalents, short-term borrowings, and trade
receivables and payables represented fair value because of the
short-term 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 interest rate. We estimated
the fair value of debt with fixed interest rates based on quoted
market prices for the same or similar issues. See Note 10
for a discussion of our methodology of determining the fair
value of the derivative instruments used in our price risk
management activities. Our investments primarily relate to
available for sale securities and cost basis investments.
10. Price Risk Management Activities
The following table summarizes the carrying value of the
derivatives used in our price risk management activities as of
December 31, 2005 and 2004. In the table, derivatives
designated as hedges consist of instruments used to hedge our
natural gas and oil production. Other commodity-based derivative
contracts relate to derivative contracts not designated as
hedges, such as options, swaps, tolling agreements (assigned to
a third party in 2005) and other natural gas and power purchase
and supply contracts, our historical energy trading activities
and our power contract restructuring activities (which were
fully disposed of in 2004 and 2005). Finally, interest rate and
foreign currency derivatives consist of swaps that are primarily
designated as hedges of our interest rate and foreign currency
risk on long-term debt.
Net assets (liabilities) from price risk management
activities(3)
$
(1,414
)
$
307
(1)
Decrease is due primarily to the sale or assignment of a number
of derivative contracts and significant changes in natural gas
and oil prices during 2005.
(2)
Decrease is due to settlement of hedge contracts upon repurchase
of related debt as discussed below.
(3)
Included in both current and
non-current assets and
liabilities on the balance sheet.
Our derivative contracts are recorded in our financial
statements at fair value. The best indication of fair value is
quoted market prices. However, when quoted market prices are not
available, we estimate the fair value of those derivatives.
Historically, we used commodity prices from market-based sources
such as the New York Mercantile Exchange for forward pricing
data within two years. For forecasted settlement prices beyond
two years, we used a combination of commodity prices from
market-based sources and other independent pricing sources to
develop price curves. The curves were then used to estimate the
value of settlements in future periods based on the contractual
settlement quantities and dates. Finally, we discounted these
estimated settlement values using a LIBOR curve for the majority
of our derivative contracts or by using an adjusted risk-free
rate for our restructured power contracts. Additionally,
contracts denominated in foreign currencies were converted to
U.S. dollars using market-based, foreign exchange spot
rates.
Effective April 1, 2005, we began using new forward
pricing data provided by Platts Research and Consulting, our
independent pricing source, due to their decision to discontinue
the publication of the pricing data they had provided to us in
prior periods. In addition, due to the nature of the new forward
pricing data, we extended the use of that data over the entire
contractual term of our derivative contracts. Prior to
April 1, 2005, we only used Platts’ pricing data
to value our derivative contracts beyond two years. Based on our
analysis, the overall impact of this change in estimate was not
material to our financial statements.
We record valuation adjustments to reflect uncertainties
associated with the estimates we use in determining fair value.
Common valuation adjustments include those for market liquidity
and those for the credit-worthiness of our contractual
counterparties. To the extent possible, we use market-based data
together with quantitative methods to measure the risks for
which we record valuation adjustments and to determine the level
of these valuation adjustments.
Derivatives
Designated as Hedges
We engage in two types of hedging activities: hedges of cash
flow exposure and hedges of fair value exposure. Hedges of cash
flow exposure, which primarily relate to our natural gas and oil
production hedges and interest rate risks on our long-term debt,
are designed to hedge forecasted sales transactions or limit 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 protect the fair value of a recognized asset,
liability or firm commitment. When we enter into the derivative
contract, we may designate the derivative as either a cash flow
hedge or a fair value hedge. Our hedges of our interest rate and
foreign currency exposure are designated as either cash flow
hedges or fair value hedges based on whether the interest on the
underlying debt is converted to either a fixed or floating
interest rate. Changes in derivative fair values that are
designated as cash flow hedges are deferred in accumulated other
comprehensive income (loss) to the extent that they are
effective and then recognized in earnings when the hedged
transactions occur. The ineffective portion of a cash flow
hedge’s change in value, if any, is recognized immediately
in earnings as a component of operating revenues or interest and
debt expense in our income statement. Changes in the fair value
of derivatives that are designated as fair value hedges are
recognized in earnings as offsets to the changes in fair values
of the related hedged assets, liabilities or firm commitments.
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 regularly assess whether these
derivatives 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 discontinue the
hedging relationship.
A discussion of each of our hedging activities is as follows:
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 as well as fluctuations in
foreign currency and interest rates with the objective of
realizing a fixed cash flow stream from these activities. A
summary of the impacts of our cash flow hedges included in
accumulated other comprehensive income (loss), net of income
taxes, as of December 31, 2005 and 2004 follows.
Accumulated
Other
Comprehensive
Estimated
Income (Loss)
Income (Loss)
Final
Reclassification
Termination
2005
2004
in 2006(1)
Year
(In millions)
Commodity cash flow hedges
Held by consolidated
entities(2)
$
(285
)
$
54
$
(220
)
2012
Held by unconsolidated affiliates
(7
)
(8
)
2
2013
Total commodity cash flow hedges
(292
)
46
(218
)
Interest rate and foreign currency cash flow hedges
Fixed
rate(3)
2
4
—
2015
Undesignated
(4
)
(8
)
—
2009
Total foreign currency cash flow hedges
(2
)
(4
)
—
Total(4)
$
(294
)
$
42
$
(218
)
(1)
Reclassifications occur upon the physical delivery of the hedged
commodity and the corresponding expiration of the hedge or if
the forecasted transaction is no longer probable.
(2)
We have a derivative that hedges a portion of the production
owned by UnoPaso, a wholly-owned subsidiary that owns natural
gas and oil properties in Brazil. As a result of the earlier
than expected payout of certain of UnoPaso’s natural gas
and oil properties, which will reduce our interest in the
properties and related anticipated production volumes, we
recorded an $11 million loss in the third quarter of 2005
related to the elimination of the accumulated other
comprehensive loss associated with this hedge and reclassified
the hedge as an other commodity-based derivative contract.
(3)
In March 2005, we repurchased approximately
€528 million
of debt, of which
€375 million
was hedged with interest rate and foreign currency derivatives.
As a result of the repurchase, we removed the hedging
designation on these derivatives and settled substantially all
of the contracts. We recorded a gain of approximately
$2 million during the first quarter of 2005 upon the
reversal of the related accumulated other comprehensive income
associated with these derivatives.
(4)
Accumulated other comprehensive income (loss) also includes:
a) $(4) million and $5 million of net cumulative
foreign currency translation adjustments as of December 31,2005 and 2004; b) $(49) million and $(46) million
of additional minimum pension liability as of December 31,2005 and 2004; and c) $15 million of unrealized gains
related to an available for sale security as of
December 31, 2005. All amounts are net of taxes.
In December 2004, we designated a number of our other
commodity-based derivative contracts with a fair value loss of
$592 million as hedges of our 2005 and 2006 natural gas
production. As a result, we reclassified this amount to
derivatives designated as cash flow hedges, beginning in the
fourth quarter of 2004.
For the years ended December 31, 2005, 2004 and 2003, we
recognized net losses of $5 million, $1 million and
$2 million, net of income taxes, in our loss from
continuing operations related to the ineffective portion of our
commodity cash flow hedges. We did not record any
ineffectiveness related to our interest rate or foreign currency
cash flow hedges in 2003, 2004 and 2005.
Fair Value Hedges. We have fixed rate U.S. dollar
and foreign currency denominated debt that exposes us to paying
higher than market rates should interest rates decline. We use
interest rate swaps to effectively convert the fixed amounts of
interest due under the debt agreements to variable interest
payments based on LIBOR plus a spread. As of December 31,2005 and 2004, these derivatives had a net fair value loss of
$7 million and gain of $117 million. Specifically, we
had derivatives with fair value losses of $30 million and
$20 million as of December 31, 2005 and 2004, that
converted the interest rate on $440 million of our U.S.
dollar denominated debt to a floating weighted average interest
rate of LIBOR plus 4.2%. Additionally, we had derivatives with
fair values of $23 million and $137 million as of
December 31, 2005 and 2004, that converted
approximately
€350 million
and
€450 million
of our debt to $402 million and $511 million. These
derivatives also converted the interest rate on this debt to a
floating weighted average interest rate of LIBOR plus 4.2% as of
December 31, 2005, and LIBOR plus 3.9% as of
December 31, 2004. We have recorded the fair value of those
derivatives as a component of long-term debt and the related
accrued interest.
In March 2005, we repurchased approximately
€528 million
of debt, of which approximately
€100 million
were hedged with fair value hedges. As a result of the
repurchase, we removed the hedging designation on, and
subsequently settled, these derivative contracts.
Our other commodity-based derivatives primarily relate to our
historical trading activities, which include the services we
provide in the energy sector that we entered 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. Additionally, they include derivatives
related to our historical power contract restructuring
activities and other derivative contracts not designated as
hedges, including our production-related option and swap
contracts held by our Marketing and Trading segment.
During 2001 and 2002, we conducted power contract restructuring
activities that involved amending or terminating power purchase
contracts at existing power facilities. As a result of our
credit downgrade and economic changes in the power market, we
are no longer pursuing additional power contract restructuring
activities and during 2005, we disposed of our remaining
historical restructured power contracts. Specifically, during
2005, we sold or assigned derivative contracts with a net fair
value of $376 million in conjunction with the sales of
Cedar Brakes I and II and Mohawk River Funding II entities.
See Note 3 for a discussion of these sales, which include
the sales of UCF, Cedar Brakes I and II and our other power
restructuring entities that owned derivative contracts.
Additionally, during 2005, we entered into agreements to assign
a number of our other derivative contracts not designated as
hedges. Specifically, we (i) completed the assignment of
our liability under the Cordova tolling agreement for which we
paid $177 million and (ii) entered into an agreement
to assign the majority of our power derivative assets to Morgan
Stanley. This assignment requires the consent of existing third
parties before the contracts can be transferred to Morgan
Stanley. Until the assignment is finalized, we entered into
offsetting liability contracts with Morgan Stanley to eliminate
the commodity price risk associated with the contracts being
assigned. We received total proceeds of $442 million to
enter into these offsetting contracts and deposited a similar
amount of cash margin. The amount received approximated the
value we would have received if we had directly sold our power
derivative assets. We expect to complete this assignment to
Morgan Stanley in the first half of 2006.
During the first quarter of 2006, we assigned our contracts to
supply natural gas to the Jacksonville Electric Authority and
The City of Lakeland, Florida for no cash consideration. We will
record a gain of approximately $50 million related to this
assignment in 2006.
Credit Risk
We are subject to credit risk related to our financial
instrument assets. 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
measure credit risk as the estimated replacement costs for
commodities we would have to purchase or sell in the future,
plus amounts owed from counterparties for delivered and unpaid
commodities. These exposures are netted where we have a legally
enforceable right of setoff. We maintain credit policies with
regard to our counterparties in our price risk management
activities to minimize overall credit risk. These policies
require (i) the evaluation of potential
counterparties’ financial condition (including credit
rating), (ii) collateral under certain circumstances
(including cash in advance, letters of credit, and guarantees),
(iii) the use of margining provisions in standard
contracts, and (iv) the use of master netting agreements
that allow for the netting of positive and negative exposures of
various contracts associated with a single counterparty.
We use daily margining provisions in our financial contracts,
most of our physical power agreements and our master netting
agreements, which require a counterparty to post cash or letters
of credit when the fair value of the contract exceeds the daily
contractual threshold. The threshold amount is typically tied to
the published credit rating of the counterparty. Our margining
collateral provisions also allow us to terminate a contract and
liquidate all positions if the counterparty is unable to provide
the required collateral. Under our margining provisions, we are
required to return collateral if the amount of posted collateral
exceeds the amount of collateral required. Collateral received
or returned can vary significantly from day to day based on the
changes in the market values and our counterparty’s credit
ratings. Furthermore, the amount of collateral
“Investment Grade” and “Below Investment
Grade” are determined using publicly available credit
ratings. “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 public credit rating that do not
meet the criteria of “Investment Grade”. “Not
Rated” includes counterparties that are not rated by any
public rating service.
(2)
Net asset exposure from financial instrument assets primarily
relates to our assets and liabilities from price risk management
activities. These exposures 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 and do not include amounts
already billed or delivered under the derivative contracts,
which would be netted against these exposures.
We have approximately 95 counterparties as of
December 31, 2005, most of which are energy marketers.
Although most of our counterparties are not currently rated as
below investment grade, if one of our counterparties fails to
perform, we may recognize an immediate loss in our earnings, as
well as additional financial impacts in the future delivery
periods to the extent a replacement contract at the same prices
and quantities cannot be established.
As of December 31, 2005, two energy marketers,
Constellation Energy Commodities Group, Inc. and Duke Energy
Trading and Marketing LLC, comprised 28 percent and
18 percent of our net financial instrument asset exposure.
As of December 31, 2004, one electric utility customer, Public
Service Electric and Gas Company (PSEG), comprised
42 percent of our net financial instrument asset exposure;
however, this exposure to PSEG was eliminated with the sale of
our interests in Cedar Brakes I and II in 2005. 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.
11. Regulatory Assets and Liabilities
Our regulatory assets and liabilities relate to our interstate
pipeline subsidiaries that apply the provisions of
SFAS No. 71 and are included in other current and
non-current assets and liabilities on our balance sheets. These
balances are presented on our balance sheets on a gross basis
and are recoverable over various periods. Below are the details
of our regulatory assets and liabilities as of December 31:
Description
2005
2004
(In millions)
Current regulatory assets
$
4
$
3
Non-current regulatory assets
Grossed-up deferred taxes on capitalized funds used during
construction
96
85
Postretirement benefits
25
30
Unamortized net loss on reacquired debt
20
23
Under-collected state income tax
7
7
Other
16
10
Total non-current regulatory assets
164
155
Total regulatory assets
$
168
$
158
Current regulatory liabilities
$
9
$
9
Non-current regulatory liabilities
Environmental liability
110
97
Cost of removal of offshore assets
48
50
Property and plant depreciation
41
35
Postretirement benefits
16
13
Plant regulatory liability
11
11
Excess deferred income taxes
8
11
Other
8
11
Total non-current regulatory liabilities
242
228
Total regulatory liabilities
$
251
$
237
12. 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:
Other postretirement and employment benefits (Note 17)
224
249
Regulatory liabilities (Note 11)
242
228
Asset retirement obligations (Note 1)
194
244
Other deferred credits
186
126
Accrued lease obligations
77
126
Insurance reserves
132
125
Liabilities related to discontinued operations (Note 3)
—
55
Other
188
185
Total
$
2,271
$
2,452
13. Property, Plant and Equipment
At December 31, 2005 and 2004, we had approximately
$1.1 billion and $0.8 billion of construction
work-in-progress
included in our property, plant and equipment.
As of December 31, 2005 and 2004, 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
$1.4 billion and $1.3 billion at December 31,2005 and 2004. These excess costs are being depreciated over the
life of the pipeline assets we assigned the costs to, and our
related depreciation expense for the years ended
December 31, 2005, 2004, and 2003 was approximately
$76 million, $76 million and $74 million. We do
not currently earn a return on these excess purchase costs from
our rate payers.
In addition to the borrowing, we have an associated letter of
credit facility for $12 million, under which we issued
$6 million of letters of credit in May 2005. We also
concurrently entered into swaps to convert the variable interest
rate on approximately $213 million of this debt to a
current fixed rate of 5.94%.
(2)
In July 2005, we remarketed $272 million of notes which
originally formed a portion of our 9.0% equity security units.
Existing note holders utilized proceeds from the remarketing to
satisfy their obligation under the equity security units to
purchase common stock which had the effect of exchanging debt
for equity. We have reflected this transaction as a non-cash
financing transaction and the issuance of the new remarketed
notes as a financing cash inflow.
(3)
This security has a yield-to-maturity of approximately 4%.
(4)
Prior to the sale of Cedar Brakes I and II, and Mohawk
River Funding II, we made $37 million of scheduled
principal repayments. Upon the sale of these entities, the
remaining balance of $575 million was eliminated.
(5)
We recorded a $26 million loss on the early extinguishment
of this debt.
We recorded accretion expense on our zero coupon bonds of
$25 million and $36 million during the years ended
December 31, 2005 and 2004. These amounts are added to
the principal balance each period and are included in our
long-term debt. We
account for redemption of zero coupon debentures as a financing
activity in our statement of cash flows, which included this
accretion. During 2005, we redeemed $236 million of our
zero coupon debentures of which $34 million represented
increased principal due to the accretion of interest on the
debentures.
Debt Maturities
Aggregate maturities of the principal amounts of long-term
financing obligations for the next 5 years and in total
thereafter are as follows (in millions):
2006
$
1,211
2007
781
2008
676
2009
2,479
2010
2,058
Thereafter
11,085
Total long-term financing obligations, including current
maturities
$
18,290
Included above in 2006 is $225 million of debt associated
with our Macae project in Brazil, which we have classified as
current as a result of an event of default on Macae’s
non-recourse debt. (See Note 16 for additional details on
the event of default.) Also included in 2006 maturities are
approximately $0.6 billion of zero coupon debentures, which
the holders required us to redeem in February 2006 for
cash. Additionally, we have debt of approximately
$600 million that is redeemable by holders in 2007, prior
to its stated maturity, which is included in the
“Thereafter” amount.
In addition to the debt we may be required to redeem prior to
its maturity, we also have a number of our debt obligations that
are callable by us prior to their stated maturity date. At this
time, we have $12.3 billion of debt obligations callable in
2006 and an additional $0.6 billion callable in 2007 and
thereafter. To the extent we decide to redeem any of this debt,
certain obligations will require us to pay a make whole premium.
Credit Facilities
In November 2004, we entered into a $3 billion credit
agreement consisting of a $1.25 billion five-year term
loan; a $1 billion three-year revolving credit facility;
and a $750 million, five-year letter of credit facility.
Our subsidiaries, ANR, CIG, EPNG and TGP are eligible borrowers
under this credit agreement. Additionally, El Paso and certain
of its subsidiaries have guaranteed borrowings under this credit
agreement, which is collateralized by our stock ownership in
ANR, CIG, ANR Storage Company, EPNG, Southern Gas Storage
Company and TGP.
As of December 31, 2005, we had $1.23 billion
outstanding under the term loan and had utilized approximately
all of the $750 million letter of credit facility and
approximately all of the $1 billion revolving credit
facility to issue letters of credit. The term loan accrues
interest at LIBOR plus 2.75 percent, matures in
November 2009 and will be repaid in increments of
$5 million per quarter with the unpaid balance due at
maturity. Under the revolving credit facility, which matures in
November 2007, we can borrow funds at LIBOR plus
2.75 percent or issue letters of credit at
2.75 percent plus a fee of 0.25 percent of the amount
issued. We pay an annual commitment fee of 0.75 percent on
any unused capacity under the revolving credit facility. The
terms of the $750 million letter of credit facility
provides us the ability to issue letters of credit or borrow any
unused capacity under the letter of credit facility as revolving
loans with a maturity in November 2009. We pay LIBOR plus
2.75 percent on any amounts borrowed under the letter of
credit facility, and 2.85 percent on letters of credit and
unborrowed funds.
In August 2005, our subsidiary EEPC entered into a
$500 million five-year revolving credit facility bearing
interest at LIBOR plus 1.875%. Under the facility, we borrowed
$500 million, which was used to partially fund the
acquisition of Medicine Bow. The facility can be utilized for
funded borrowings or for the issuance of letters of credit and
is collateralized by certain EEPC natural gas and oil production
properties.
In November 2005, we entered into a $400 million revolving
borrowing base credit agreement collateralized by natural gas
and oil production properties owned by one of our subsidiaries,
which is also a co-borrower. Under the agreement we have initial
borrowing availability of $300 million. While we have not
drawn any amounts under this credit facility it can be used for
revolving credit loans or for the issuance of letters of credit
and will mature in May 2006. If fully drawn, the interest rate
on this facility would be LIBOR plus 2.50%.
Restrictive Covenants
$3 billion revolving credit facility. Our
restrictive covenants under the $3 billion revolving credit
facility include restrictions on debt levels, restrictions on
liens securing debt and guarantees, restrictions on mergers and
on the sales of assets, dividend restrictions, cross default,
cross-acceleration and prepayment of debt 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 credit agreement the significant debt
covenants and cross defaults are:
(a)
El Paso’s ratio of Debt to Consolidated EBITDA, (each
as defined in the credit agreement), shall not exceed 6.25 to
1.0 at any time on or after September 30, 2005, and prior
to June 30, 2006, and 6.0 to 1.0 at any time on or after
June 30, 2006, until maturity;
(b)
El Paso’s ratio of Consolidated EBITDA, (as defined in
the credit agreement), to interest expense plus dividends paid
shall not be less than 1.6 to 1.0 prior to
March 31, 2006, 1.75 to 1.0 on or after March 31,2006, and prior to March 31, 2007, and 1.8 to 1.0 on
or after March 31, 2007, until maturity;
EPNG, TGP, ANR and CIG cannot incur incremental Debt if the
incurrence of this incremental Debt would cause their Debt to
Consolidated EBITDA ratio, (each as defined in the credit
agreement), for that particular company to exceed 5.0 to 1.0;
(d)
the proceeds from the issuance of Debt by our pipeline company
borrowers can only be used for maintenance and expansion capital
expenditures or investments in other
FERC-regulated assets,
to fund working capital requirements, or to refinance existing
debt; and
(e)
the occurrence of an event of default and after the expiration
of any applicable grace period, with respect to Debt in an
aggregate principal amount of $200 million or more.
$500 million credit facility. The availability of
borrowings under this facility is subject to various conditions.
The financial coverage ratio under the facility requires that
EEPC’s EBITDA (as defined in the facility) to interest
expense not be less than 2.0 to 1.0, EEPC’s debt to EBITDA
must not be greater than 4.5 to 1.0 until
September 30, 2006, and 4.0 to 1.0 thereafter, and
EEPC’s Collateral Coverage Ratio (as defined in the
facility) must be greater than 1.5 to 1.0.
$400 million credit agreement. The availability of
borrowings under this facility is subject to various conditions.
One of the more restrictive new covenants of this facility is
the requirement to maintain a Collateral Coverage Ratio (as
defined in the facility) of at least 1.5 to 1.0.
Other Restrictions and Provisions. In addition to the
above restrictions and default provisions, we and/or our
subsidiaries are subject to a number of additional restrictions
and covenants. These restrictions and covenants include
limitations of additional debt at some of our subsidiaries;
limitations on the use of proceeds from borrowing at some of our
subsidiaries; limitations, in some cases, on transactions with
our affiliates; limitations on the occurrence of liens;
potential limitations on the abilities of some of our
subsidiaries to declare and pay dividends and potential
limitations on some of our subsidiaries to participate in our
cash management program, and limitations on our ability to
prepay debt.
We also issued various guarantees securing financial obligations
of our subsidiaries and affiliates with similar covenants as the
above facilities.
Our most restrictive acceleration provision is $5 million
and is associated with the indenture of one of our subsidiaries.
This indenture states that should an event of default occur
resulting in the acceleration of other debt obligations in
excess of $5 million, the long-term debt obligation
containing that provision could be accelerated. The acceleration
of our debt would adversely affect our liquidity position and in
turn, our financial condition.
Other Financing
Arrangements
Capital Trusts. El Paso Energy Capital Trust I
(Trust I), is a wholly owned business trust formed in March
1998. Trust I issued 6.5 million of 4.75 percent
trust convertible preferred securities in a public offering for
$325 million. Trust I exists for the sole purpose of
issuing preferred securities and investing the proceeds in
4.75 percent convertible subordinated debentures we issued
due 2028. Trust I’s sole source of income is interest
earned on these debentures. This interest income is used to pay
distributions on the preferred securities. We also have two
wholly owned business trusts, El Paso Energy Capital
Trust II and III (Trust II and III), under which
we have not issued securities. We provide a full and
unconditional guarantee of Trust I’s preferred
securities, and would provide the same guarantee if securities
were issued under Trust II and III.
Trust I’s preferred securities are non-voting (except in
limited circumstances), pay quarterly distributions at an annual
rate of 4.75 percent, 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). We have classified these securities as
long-term debt and we have the right to redeem these securities
at any time.
Coastal Finance I. Coastal Finance I is an indirect
wholly owned business trust formed in May 1998. Coastal
Finance I issued in a public offering 12 million
mandatory redemption preferred securities for $300 million.
Coastal Finance I held subordinated debt securities issued
by our wholly owned subsidiary, El Paso CGP, L.L.C., that it
purchased with the proceeds of the preferred securities
offering. Cumulative quarterly distributions were being paid on
the preferred securities at an annual rate of 8.375 percent
of the liquidation amount of $25 per preferred security. On
February 8, 2006, the $300 million of outstanding
preferred securities were redeemed.
Non-Recourse Project Financings. Many of our subsidiaries
and investments have debt obligations related to their costs of
construction or acquisition. Several of our projects have
experienced events that have either constituted or could
constitute an event of default under the loan agreements. Among
other projects, our consolidated Macae project in Brazil and our
Berkshire project have been either issued a notice of default or
experienced an event of default. Our outstanding debt at our
consolidated Macae project is $225 million at
December 31, 2005. This debt (as well as other project
financing debt) is recourse only to the project company and
assets (i.e. without recourse to El Paso). We do not
believe any of these defaults, or other events that have led to
or could lead to events of default at other projects, will have
a material effect on us or our subsidiaries’ financial
statements based on the amounts we have recorded on our balance
sheet for these projects and/or the current status of
negotiations relating to these projects (for a further
discussion, see Notes 16 and 21).
Letters of Credit
We enter into letters of credit in the ordinary course of our
operating activities as well as periodically in conjunction with
the sales of assets or businesses. As of December 31, 2005,
we had outstanding letters of credit of approximately
$2.0 billion, of which $1.7 billion were issued under
our credit agreement. Included in this amount is
$1.2 billion of letters of credit securing our recorded
obligations related to price risk management activities.
15. Preferred Interests of Consolidated Subsidiaries
In the past, we entered into transactions accomplished through
the sale of preferred interests in consolidated subsidiaries.
During 2003, approximately $3 billion of these preferred
interests were redeemed, reclassified to long-term debt or
eliminated through various actions. In May 2005, we redeemed
$300 million of 8.25% Series A cumulative preferred
stock of our subsidiary, El Paso Tennessee Pipeline Co.
16.
Commitments and Contingencies
Legal Proceedings
Shareholder/ Derivative/ ERISA
Litigation
Shareholder Litigation. Twenty-eight purported
shareholder class action lawsuits have been pending since 2002
and are consolidated in federal court in Houston, Texas. This
consolidated lawsuit, which alleges violations of federal
securities laws against us and several of our current and former
officers and directors, includes allegations regarding the
accuracy or completeness of press releases and other public
statements made during the class period from 2000 through early
2004 related to alleged wash trades, mark-to-market accounting,
off-balance sheet debt, the overstatement of natural gas and oil
reserves and manipulation of the California energy market.
Formal discovery in the consolidated lawsuit is currently
stayed. The Court has ordered the parties to mediate this case
in April 2006.
Derivative Litigation. Since 2002, six shareholder
derivative actions have also been filed. Two of these actions
were filed in federal court in Houston, two were filed in state
court in Houston, and two were filed in Delaware Chancery Court.
Only three of these actions remain following consolidation and
dismissal of the other cases.
•
The Houston federal court cases: The first federal court
case was filed in 2002 and the second was filed in 2004. The
2002 federal court case generally alleges the same claims pled
in the
consolidated shareholder class action described above, with the
exception that there are no allegations related to the
overstatement of natural gas and oil reserves. The 2004 federal
court case includes allegations related to the overstatement of
natural gas and oil reserves, in addition to the allegations
alleged in the 2002 federal court case. The two federal court
actions in Houston are both currently stayed.
•
The Houston state court cases: The two state court
actions in Houston have been consolidated. The plaintiffs in
those cases originally alleged that the manipulation of
California gas prices exposed us to claims of antitrust
conspiracy, FERC penalties and erosion of share value. The
plaintiffs in the consolidated state court case recently amended
their petition to add claims of unjust enrichment of certain
former executives allegedly attributable to round trip trading
and restructuring of energy contracts and breach of fiduciary
duty claims for failure to recover 2001 compensation paid to
certain officers and related to the overstatement of natural gas
and oil reserves. Discovery is ongoing in this case.
•
The Delaware Chancery Court cases: The first of these two
cases was filed in 2002, and generally alleges the same claims
pled in the consolidated shareholder class action described
above, with the exception that there were no allegations related
to the overstatement of natural gas and oil reserves. This
lawsuit was voluntarily dismissed by plaintiffs in July 2005.
The second Delaware derivative case was filed in April 2005 and
seeks to recover the compensation paid to a former executive in
2001 alleging unjust enrichment allegedly attributable to round
trip trading and restructuring of energy contracts and breach of
fiduciary duty claims for failure to seek recovery of the 2001
compensation. In December 2005, the court dismissed this lawsuit
because of the plaintiffs’ failure to make demand on the
Board of Directors before filing suit.
ERISA Class Action Suits. In December 2002, a
purported class action lawsuit entitled William H. Lewis, III
v. El Paso Corporation, et al. was filed in the U.S.
District Court for the Southern District of Texas 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). That lawsuit was subsequently amended to include
allegations relating to our reporting of natural gas and oil
reserves. Formal discovery in this lawsuit is currently stayed.
We and our representatives have insurance coverages that are
applicable to each of these shareholder, derivative and ERISA
lawsuits subject to certain deductibles and co-pay obligations.
We have established certain accruals for these matters, which we
believe are adequate.
Cash Balance Plan Lawsuit. In December 2004, a lawsuit
entitled Tomlinson, et al. v. El Paso Corporation and El Paso
Corporation Pension Plan was filed in U.S. District Court
for Denver, Colorado. The lawsuit seeks class action status and
alleges that the change from a final average earnings formula
pension plan to a cash balance pension plan, the accrual of
benefits under the plan, and the communications about the change
violate the ERISA and/or the Age Discrimination in
Employment Act. Our costs and legal exposure related to this
lawsuit are not currently determinable.
Retiree Medical Benefits Matters. We currently serve as
the plan administrator for a medical benefits plan that covers a
closed group of retirees of the Case Corporation who retired on
or before June 30, 1994. Case was formerly a subsidiary of
Tenneco, Inc. that was spun off prior to our acquisition of
Tenneco in 1996. In connection with the Tenneco-Case
Reorganization Agreement of 1994, Tenneco assumed the obligation
to provide certain medical and prescription drug benefits to
eligible retirees and their spouses. We assumed this obligation
as a result of our merger with Tenneco. However, we believe that
our liability for these benefits is limited to certain maximums,
or caps, and costs in excess of these maximums are assumed by
plan participants. In 2002, we and Case were sued by individual
retirees in federal court in Detroit, Michigan in an action
entitled Yolton et al. v. El Paso Tennessee Pipeline Co. and
Case Corporation. The suit alleges, among other things, that
El Paso and Case violated ERISA and that they should be required
to pay all amounts above the cap. Case further filed claims
against El Paso asserting that El Paso is obligated to
indemnify, defend and hold Case harmless for the amounts it
would be required to pay. In separate rulings in 2004, the court
ruled
that pending a trial on the merits Case must pay the amounts
incurred above the cap and that El Paso must reimburse Case for
those payments. In January 2006, these rulings were upheld on
appeal before a 3-member panel of the U.S. Court of Appeals for
the 6th Circuit. In February 2006, we filed for a review of this
decision by the full panel of the U.S. Court of Appeals for the
6th Circuit as a result of conflicting precedent. The appellate
court has requested that the plaintiff file a reply brief in
March 2006. If such a review is not granted, we will proceed
with a trial on the merits with regard to the issue of whether
the cap is enforceable. Until this is resolved, El Paso will
indemnify Case for any payments Case makes above the cap, which
are currently about $1.7 million per month. While we will
continue to defend the action, based upon the ruling of the 6th
Circuit and the lessening avenues of appellate reviews, we
recorded a pre-tax charge of approximately $350 million for
this matter during the fourth quarter of 2005. We have also
filed for approval by the trial court various amendments to the
medical benefit plans which would allow us to deliver the
benefits to plan participants in a more cost effective manner.
We will seek expeditious approval of such plan amendments.
Although it is uncertain what plan amendments will ultimately be
approved, the approval of plan amendments could reduce our
overall costs and, as a result, could reduce our recorded
liability.
Natural Gas Commodities Litigation. Beginning in August
2003, several lawsuits have been filed against El Paso and
El Paso Marketing L.P. (EPM), formerly El Paso Merchant Energy
L.P., our affiliate, in which plaintiffs alleged, in part, that
El Paso, EPM and other energy companies conspired to manipulate
the price of natural gas by providing false price information to
industry trade publications that published gas indices. The
first set of cases were filed in the United States District
Court for the Southern District of New York which included:
Cornerstone Propane Partners, L.P. v. Reliant Energy Services
Inc., et al.;Roberto E. Calle Gracey v. American Electric
Power Company, Inc., et al.; and Dominick Viola v.
Reliant Energy Services Inc., et al. In December 2003, those
cases were consolidated with others into a single master file in
federal court in New York for all pre-trial purposes. The
consolidated cases are styled, in re: Gas Commodity
Litigation. In September 2004, El Paso Corporation was
dismissed from the master case. In September 2005, the court
certified the class to include all persons who purchased or sold
NYMEX natural gas futures between January 1, 2000 and
December 31, 2002. EPM and the remaining defendants
have petitioned the United States Court of Appeals for the
Second Circuit for permission to appeal the class certification
order. The second set of cases involve similar allegations on
behalf of commercial and residential customers. These cases were
filed in the U.S. District Court for the Eastern District of
California, which include Texas Ohio Energy, Inc. v.
CenterPoint Energy, Inc. et al. (filed in November 2003),
Fairhaven Power v. El Paso Corporation et al. (filed in
September 2004), Utility Savings and Refund Services, et al.
v. Reliant Energy, et al. (filed in December 2004) and
Abelman Art Glass, et al. v. Encana Corporation, et al.
(filed in December 2004). Each of these cases was
transferred to a multi-district litigation proceeding (MDL),
In re Western States Wholesale Natural Gas Antitrust
Litigation, pending in the U.S. District Court for Nevada.
These cases have been dismissed and have been appealed. The
third set of cases also involve similar allegations on behalf of
certain purchasers of natural gas. These include a purported
class action lawsuit styled Leggett et al. v. Duke Energy
Corporation et al. (filed in Chancery Court of Tennessee in
January 2005), Ever-Bloom Inc. v. AEP Energy Services Inc. et
al. (filed in June 2005), Farmland Industries, Inc. v.
Oneok Inc. (filed in state court in Wyandotte County, Kansas
in July 2005) and the purported class action Learjet, Inc. v.
Oneok Inc. (filed in state court in Wyandotte County, Kansas
in September 2005). All four actions have been transferred to
the MDL proceeding in federal district court in Nevada. Similar
motions to dismiss have either been filed or are anticipated to
be filed in these cases as well. Our costs and legal exposure
related to these lawsuits and claims are not currently
determinable.
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 due to the
alleged mismeasurement. The plaintiff seeks royalties along with
interest, expenses, and punitive damages. The plaintiff also
seeks injunctive relief with regard to future 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). Motions to dismiss were argued before a
representative appointed by the court. In May 2005, the
representative issued its
recommendation, which if adopted by the district court judge,
will result in the dismissal on jurisdictional grounds of six of
the seven Qui Tam actions filed by Grynberg against El
Paso subsidiaries. The seventh case involves only a few
midstream entities owned by El Paso, which have meritorious
defenses to the underlying claims. If the district court judge
adopts the representative’s recommendations, an appeal by
the plaintiff of the district court’s order is likely. Our
costs and legal exposure related to these lawsuits and claims
are not currently determinable.
Will Price (formerly Quinque). A number of our
subsidiaries are named as defendants in Will Price,
et al. v. Gas Pipelines and Their Predecessors, et al.,
filed in 1999 in the District Court of Stevens County,
Kansas. Plaintiffs allege that the defendants mismeasured
natural gas volumes and heating content of natural gas on
non-federal and non-Native American lands and seek to recover
royalties that they contend they 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, attorneys’ 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 of a nationwide
class of natural gas working interest owners and natural gas
royalty owners was denied in April 2003. Plaintiffs were granted
leave to file a Fourth Amended Petition, which narrows the
proposed class to royalty owners in wells in Kansas, Wyoming and
Colorado and removes claims as to heating content. A second
class action petition has since been filed as to the heating
content claims. Motions for class certification have been
briefed and argued in both proceedings, and the parties are
awaiting the court’s ruling. Our costs and legal exposure
related to these lawsuits and claims are not currently
determinable.
Hurricane Litigation. One of our affiliates has been
named in two class action petitions (subsequently consolidated
by the court into one action) for damages filed in the United
States District Court for the Eastern District of Louisiana
against all natural gas and oil pipeline and exploration and
production companies that dredged pipeline canals, installed
transmission lines or drilled for natural gas and oil in the
marshes of coastal Louisiana. The lawsuits, George Barasich,
et al. v. Columbia Gulf Transmission Company, et al.
and Charles Villa Jr., et al. v. Columbia Gulf
Transmission Company, et al. assert that the defendants
caused erosion and land loss which destroyed critical protection
against hurricane surges and winds and was a substantial cause
of the loss of life and destruction of property. The first
lawsuit alleges damages associated with Hurricane Katrina. The
second lawsuit alleges damages associated with Hurricanes
Katrina and Rita. Our costs and legal exposures related to these
lawsuits and claims are not currently determinable.
Bank of America. We are a named defendant, along with
Burlington Resources, Inc. (Burlington), in two class action
lawsuits styled as Bank of America, et al. v. El Paso Natural
Gas Company, et al., and Deane W. Moore, et al. v.
Burlington Northern, Inc., et al., each filed in 1997 in the
District Court of Washita County, State of Oklahoma and
subsequently consolidated by the court. The consolidated class
action has been settled pursuant to a settlement agreement
executed in January 2006. A third action, styled Bank of
America, et al. v. El Paso Natural Gas and Burlington Resources
Oil and Gas Company, was filed in October 2003 in the
District Court of Kiowa County, Oklahoma asserting similar
claims as to specified shallow wells in Oklahoma, Texas and New
Mexico. All the claims in this action have also been settled as
part of the January 2006 settlement. The settlement of all these
claims is subject to court approval, after a fairness hearing
anticipated in the spring of 2006. We filed an action styled
El Paso Natural Gas Company v. Burlington Resources, Inc. and
Burlington Resources Oil and Gas Company, L.P. against
Burlington in state court in Harris County, Texas relating to
indemnity issues between Burlington and us. That action was
stayed by agreement of the parties and settled in November 2005,
subject to the underlying class settlements being finalized and
approved by the court. Upon final court approval of these
settlements, our contribution will be approximately
$30 million, which has been accrued as of December 31,2005.
Araucaria. We own a 60 percent interest in a 484 MW
gas-fired power project known as the Araucaria project located
near Curitiba, Brazil. The Araucaria project has a 20-year power
purchase agreement (PPA) with a government-controlled
regional utility, COPEL. In December 2002, the utility ceased
making payments to the project and, as a result, the Araucaria
project and the utility are currently involved in international
arbitration over the PPA. The final arbitration hearing was held
in January 2006. A Curitiba
court has ruled that the arbitration clause in the PPA is
invalid. The project company is appealing this ruling. In
February 2006, El Paso signed a letter of intent to settle this
matter and to sell its interest in Araucaria to COPEL for
$190 million. The sale is subject to negotiations of
definitive purchase and sale agreements and requisite corporate
approvals and its consummation would be subject to customary
conditions to closing, including receipt of any necessary
government approvals. The letter of intent provides that the
parties will complete and sign definitive purchase and sale
agreements by mid-April and that in the interim, the Araucaria
arbitration will be suspended.
Our investment in the Araucaria project was $187 million at
December 31, 2005. We have political risk insurance that
covers a substantial portion of our investment in the project.
Based on the future outcome of our dispute under the PPA and the
letter of intent and depending on our ability to collect amounts
from the utility or under our political risk insurance policies,
we could be required to write down the value of our investment.
Macae. We own a 928 MW gas-fired power plant known as the
Macae project located near the city of Macae, Brazil. The Macae
project revenues are derived, in part, from minimum capacity and
revenue payments made by Petrobras under a participation
agreement that extends through August 2007. Petrobras filed a
notice of arbitration that seeks rescission of the participation
agreement and reimbursement of some or all of the capacity
payments that it has made. An arbitration hearing took place in
October 2005 and the arbitrators issued a partial final award on
certain issues raised in the arbitration in November 2005. A
final hearing is scheduled for late April 2006 on the remaining
issues in the arbitration. We believe we have substantial
defenses to the claims of Petrobras and continue to defend our
legal rights vigorously. If, however, Petrobras’ claims
were successful, they could result in a termination of the
minimum revenue payments as well as Petrobras’ obligation
to provide firm natural gas supply to the project through 2012.
On February 1, 2006, El Paso and Petrobras signed a
memorandum of understanding that provides for the settlement of
this matter and the sale of the entities that own
El Paso’s interest in the Macae power plant.
El Paso would sell these entities for a purchase price of
approximately $358 million, adjusted for working capital,
and approximately $225 million of project financing would
be repaid from those sales proceeds. The sale is subject to
negotiations of definitive purchase and sale agreements and
requisite corporate approvals and its consummation would be
subject to customary conditions to closing, including receipt of
any necessary government approvals. We and Petrobras will
attempt to complete the definitive agreements in March 2006 and
in the interim, the arbitration proceedings will be suspended.
Based on the status of the arbitration proceedings and the
indication of value we may ultimately receive for the settlement
of this matter described in the memorandum of understanding, we
recorded $333 million of impairment charges in 2005 on our
investment in the Macae facility. In addition, we did not
recognize approximately $206 million of revenues under our
participation agreement during 2005 and reserved
$18 million of related receivables because of the
uncertainty about their collectibility. Depending on the terms
of the final agreement, we could be required to record
additional losses related to the disposition and the resolution
of disputes related to Macae.
Pending the issuance of the final arbitration award or the sale
of Macae under the memorandum of understanding, Petrobras has
been depositing the amounts owed directly into a restricted cash
account, subject to Macae’s obligation to post a bank
guarantee as security for any repayment obligation if Petrobras
prevails in the dispute. We have recorded a liability of
$186 million and the same amount in restricted cash related
to these payments in addition to $1 million of debt service
reserves held by Macae in their restricted cash accounts. We
have reflected payments by Petrobras into this account as a
non-cash investing transaction for purposes of our cash flow
statement.
Petrobras’ non-payment has created an event of default
under the applicable loan agreements. As a result, we have
classified the debt as current. In light of the default of
Petrobras under the participation agreement and the inability of
Macae to continue to make ongoing payments under its loan
agreements, one or more of the lenders could exercise remedies
under the loan agreements in the future, one of which could be
an acceleration of the amounts owed under the loan agreements
which could ultimately result in the lenders foreclosing on the
Macae project. In February 2006, Macae’s lenders issued
notices of default due to the
project’s non-payment of scheduled principal and interest
payments and the lenders are reserving all of their rights under
the loan agreements. In the event that the lenders foreclose on
the project, we may incur additional losses of up to
approximately $141 million. As new information becomes
available or future material developments occur, we will
reassess the carrying value of our interests in this project.
In late 2005, Macae also received an assessment from the
Brazilian tax authorities totaling approximately
$73 million, including $18 million for various import
taxes and $55 million for interest and penalties related to
the importation of equipment for the Macae plant during its
construction. We believe we have valid defenses against the
amounts assessed and have filed an appeal of the assessment to
the administrative level of the Brazilian tax authorities and,
accordingly, we have not accrued a liability related to this
claim. In addition, we are pursuing a refund of tax payments
that have been made related to interest income that the supreme
court in Brazil, in a similar case, has recently determined to
be unconstitutional. We have not accrued a receivable related to
this potential tax receivable as collectibility is not assured.
This tax claim, including interest that has accrued on these tax
payments, totals approximately $21 million.
MTBE. In compliance with the 1990 amendments to the Clean
Air Act, certain of our subsidiaries used the gasoline additive
methyl tertiary-butyl ether (MTBE) in some of their
gasoline. Certain subsidiaries have also produced, bought, sold
and distributed MTBE. A number of lawsuits have been filed
throughout the U.S. regarding MTBE’s potential impact on
water supplies. Some of our subsidiaries are among the
defendants in over 60 such lawsuits. As a result of a ruling
issued in March 2004, these suits have been consolidated for
pre-trial purposes in multi-district litigation in the U.S.
District Court for the Southern District of New York. The
plaintiffs, certain state attorneys general and various water
districts, seek remediation of their groundwater, prevention of
future contamination, a variety of compensatory damages,
punitive damages, attorney’s fees, and court costs. Among
other allegations, plaintiffs assert that gasoline containing
MTBE is a defective product and that defendant refiners are
liable in proportion to their market share. The plaintiff states
of California and New Hampshire have filed an appeal to the 2nd
Circuit Court of Appeals challenging the removal of the cases
from state to federal court. That appeal is pending. In April
2005, the judge denied a motion by defendants to dismiss the
lawsuits. In that opinion the Court recognized, for certain
states, a potential commingled product market share basis for
collective liability. Our costs and legal exposure related to
these lawsuits are not currently determinable.
Government Investigations
Round Trip Trades. In June 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 in July 2002. On May 24, 2005, we
received a subpoena from the SEC requesting the production of
documents related to certain hedges on our natural gas
production. We are cooperating with the SEC investigation.
Price Reporting. We have provided information to the
Commodity Futures Trading Commission (CFTC) and the U.S.
Attorney in response to their requests for information regarding
price reporting of transactional data to the energy trade press.
In the first quarter of 2003, we announced a settlement with the
CFTC of the price reporting matter providing for the payment of
a civil monetary penalty by EPM of $20 million,
$10 million of which is payable in 2006, without admitting
or denying the CFTC holdings in the order. We are continuing to
cooperate with the U.S. Attorney’s investigation of this
matter.
Reserve Revisions. In March 2004, we received a subpoena
from the SEC requesting documents relating to our
December 31, 2003 natural gas and oil reserve revisions. We
will continue to cooperate with the SEC in its investigation
related to such reserve revisions. Although we had also received
federal grand jury subpoenas for documents with regard to these
reserve revisions, in June 2005, we were informed that the U.S.
Attorney’s office closed this investigation and will not
pursue prosecution at this time.
Iraq Oil Sales. In September 2004, Coastal (which we
acquired in January 2001) received a subpoena from the grand
jury of the U.S. District Court for the Southern District of New
York to produce records regarding the United Nations’ Oil
for Food Program governing sales of Iraqi oil. The subpoena
seeks various records related to transactions in oil of Iraqi
origin during the period from 1995 to 2003. In November 2004, we
received an order from the SEC to provide a written statement
and to produce certain documents in
connection with The Coastal Corporation’s and
El Paso’s participation in the Oil for Food Program.
In June and December 2005, we received additional requests for
documents and information from the SEC. We have also received
informal requests for information and documents from several
congressional committees related to Coastal’s purchases of
Iraqi crude under the Oil for Food Program. In October 2005, a
grand jury sitting in the Southern District of New York handed
down an indictment against Oscar S. Wyatt, Jr., a former CEO and
Chairman of Coastal. Also in October 2005, the Independent
Inquiry Committee into the United Nations’ Oil for Food
Program issued its final report. The report states that $201,877
in surcharges were paid with respect to a single contract
entered into by our subsidiary, Coastal Petroleum NV (CPNV). The
report lists Oscar Wyatt as the non-contractual beneficiary of
the contract. The report indicates that the payments were made
by two other individuals or entities and does not contend that
CPNV paid that surcharge. We continue to cooperate with all
government investigations into this matter.
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. There are also other regulatory rules and orders
in various stages of adoption, review and/or implementation. We
do not believe that these matters will have a material impact on
us.
Rates and Regulatory Matters
EPNG Rate Case. In June 2005, EPNG filed a rate case with
the FERC proposing an increase in revenues of 10.6 percent
or $56 million over current tariff rates, new services and
revisions to certain terms and conditions of existing services,
including the adoption of a fuel tracking mechanism. Subject to
refund, the rates became effective January 1, 2006. In
addition, the reduced tariff rates provided to EPNG’s
former full requirements customers under the terms of our FERC
approved systemwide capacity allocation proceeding terminated.
The FERC accepted a delay in the effective date of the proposed
new services and certain other provisions until April 1,2006. EPNG is continuing settlement discussions with its
customers. The outcome of this rate case cannot be predicted
with certainty at this time.
Other Contingencies
Iraq Imports. In December 2005, the Ministry of Oil for
the State Oil Marketing Organization of Iraq (SOMO) sent an
invoice to one of Coastal’s subsidiaries with regard to
shipments of crude oil that SOMO alleged were purchased and paid
for by Coastal in 1990. The invoices request an additional
$144 million of payments for such shipments, along with an
allegation of an undefined amount of interest. The invoice
appears to be associated with cargoes that Coastal had purchased
just before the 1990 invasion of Kuwait by Iraq. We are
evaluating the invoice and the underlying facts. In addition, we
are evaluating our legal defenses, including applicable statute
of limitation periods.
Navajo Nation. Nearly 900 looped pipeline miles of the
north mainline of our EPNG pipeline system are located on lands
held in trust by the United States for the benefit of the Navajo
Nation. Our rights-of-way, on lands crossing the Navajo Nation
expired in October 2005. Under an interim agreement reached
in January 2006, the Navajo Nation consented to EPNG’s
continued use and enjoyment of their existing rights-of-way
through the end of 2006. Under the interim agreement, EPNG will
make quarterly payments to the Navajo Nation, subject to a
two-way adjustment if the parties reach final agreement on a
long term right of way agreement prior to the end of 2006.
Negotiations on the terms of the long-term agreement are
continuing. Although the Navajo Nation has at times demanded
more than ten times the $2 million annual fee that existed
prior to the execution of the interim agreement, EPNG continues
to offer a combination of cash and non-cash consideration,
including collaborative projects to benefit the Navajo Nation.
In addition, EPNG continues to preserve other legal and
regulatory alternatives, which include continuing to pursue our
application with the Department of the Interior for renewal of
our rights-of-way on Navajo Nation lands. EPNG also continues to
press for public policy intervention by Congress in this area.
The Energy Policy Act of 2005 commissioned a comprehensive study
of energy infrastructure rights-of-way on tribal lands. The
study, to be conducted jointly by the Departments of Energy and
the Department of Interior must be submitted to Congress by
August 2006. It is uncertain whether our negotiation, public
policy or litigation efforts will be
successful, or if successful, what will be the ultimate cost of
obtaining the rights-of-way or whether EPNG will be able to
recover these costs in its rate case.
Brazilian Matters. We own a number of interests in
various production properties, power and pipeline assets in
Brazil, including our Macae project discussed previously. Our
total investment in Brazil was approximately $1.3 billion
as of December 31, 2005 (of which $0.9 billion relates to
our Power segment and $0.4 billion relates to our
Exploration and Production segment). In addition, we also have
$225 million of project financing related to Macae which is
non-recourse to us. For a further discussion, see Note 14.
In a number of our assets and investments, Petrobras either
serves as a joint owner, a customer or a shipper to the asset or
project. Although we have no material current disputes with
Petrobras with regard to the ownership or operation of our
production and pipeline assets, the outcome of current disputes
on the Macae power plant between us and Petrobras may negatively
impact these investments and the impact could be material.
We also own an investment in the Porto Velho power plant. The
Porto Velho project is in the process of negotiating certain
provisions of its power purchase agreements (PPA) with
Eletronorte, including the amount of installed capacity, energy
prices, take or pay levels, the term of the first PPA and other
issues. In addition, in October 2004, the project experienced an
outage with a steam turbine which resulted in a partial
reduction in the plant’s capacity. The project expects to
repair the steam turbine by the first quarter of 2006. We are
uncertain what impact this outage will have on the PPAs.
Although the current terms of the PPAs and the ongoing contract
negotiations do not indicate an impairment of our investment, we
may be required to write down the value of our investment if
these negotiations are resolved unfavorably. Our investment in
Porto Velho was approximately $302 million at
December 31, 2005.
For each of our outstanding legal and other contingent 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. While the outcome of these matters, discussed above,
cannot be predicted with certainty and there are still
uncertainties related to the costs we may incur, based upon our
evaluation and experience to date, we believe we have
established appropriate reserves for these matters. However, it
is possible that new information or future developments could
require us to reassess our potential exposure related to these
matters and adjust our accruals accordingly, and these
adjustments could be material. As of December 31, 2005, we
had approximately $574 million accrued, net of related
insurance receivables, for outstanding legal and other
contingent matters.
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, 2005, we had accrued approximately
$379 million, which has not been reduced by
$27 million for amounts paid directly under government
sponsored programs. Our accrual includes approximately
$368 million for expected remediation costs and associated
onsite, offsite and groundwater technical studies, and
approximately $11 million for related environmental legal
costs. Of the $379 million accrual, $75 million was
reserved for facilities we currently operate, and
$304 million was reserved for non-operating sites
(facilities that are shut down or have been sold) and Superfund
sites.
Our reserve estimates range from approximately $379 million
to approximately $546 million. Our accrual represents a
combination of two estimation methodologies. First, where the
most likely outcome can be reasonably estimated, that cost has
been accrued ($75 million). Second, where the most likely
outcome cannot be estimated, a range of costs is established
($304 million to $471 million) and if no one amount in
that range is more likely than any other, the lower end of the
expected range has been accrued. Our environmental remediation
projects are in various stages of completion. The liabilities we
have recorded reflect our current estimates of amounts we will
expend to remediate these sites. However, depending on the stage
of completion or assessment, the ultimate extent of
contamination or remediation required may not be known. As
additional assessments occur or remediation efforts continue, we
may incur additional liabilities. By type of site, our reserves
are based on the following estimates of reasonably possible
outcomes:
For 2006, we estimate that our total remediation expenditures
will be approximately $76 million, most of which will be
expended under government directed clean-up plans. In addition,
we expect to make capital expenditures for environmental matters
of approximately $91 million in the aggregate for the years
2006 through 2010. These expenditures primarily relate to
compliance with clean air regulations.
Polychlorinated Biphenyls (PCB) Cost Recoveries.
Pursuant to a consent order executed by TGP, our subsidiary,
in May 1994, with the EPA, TGP has been conducting various
remediation activities at certain of its compressor stations
associated with the presence of PCBs, and certain other
hazardous materials. 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 PCB 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
remediation costs, with these surcharges to be collected over a
defined collection period. TGP has received approval from the
FERC to extend the collection period, which is currently set to
expire in June 2006. The agreement also provided for bi-annual
audits of eligible costs. As of December 31, 2005, TGP had
pre-collected PCB costs of approximately $132 million. The
pre-collected amount will be reduced by future eligible costs
incurred for the remainder of the remediation project. To the
extent actual eligible expenditures are less than the amounts
pre-collected, TGP will refund to its customers the difference,
plus carrying charges incurred up to the date of the refunds. As
of December 31, 2005, TGP recorded a regulatory
liability of $110 million for the estimated future refund
obligations.
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 47 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, 2005, we have estimated our share of the
remediation costs at these sites to be between $39 million
and $69 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 estimating our liabilities.
Accruals for these issues are included in the previously
indicated estimates for Superfund sites.
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, regulations, and
orders of regulatory agencies, as well as claims for damages to
property and the environment or injuries to employees and other
persons 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 related to the
ultimate costs we may incur, based upon our evaluation and
experience to date, we believe our reserves are adequate.
Commitments, Purchase Obligations and Other Matters
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
2006 until 2053. As of December 31, 2005, our total
commitments under non-cancellable operating leases were
approximately $217 million which have not been reduced by
minimum sublease rentals of approximately $15 million due
in the future under noncancelable subleases. Minimum annual
rental commitments under our operating leases at
December 31, 2005, were as follows:
Year Ending December 31,
Operating Leases
(In millions)
2006
$
81
2007
71
2008
14
2009
11
2010
7
Thereafter
33
Total
$
217
During 2004, we announced that we would consolidate our
Houston-based operations into one location. We recorded a charge
of $80 million in 2004 as a result of this decision and an
additional charge of $27 million in 2005 upon vacating this
remaining leased space and signing a termination agreement on
the lease. Our remaining obligation under this terminated
agreement is included in the table above. Rental expense on our
non-terminated lease obligations for the years ended
December 31, 2005, 2004, and 2003 was $55 million,
$92 million, and $105 million.
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. We also periodically provide indemnification
arrangements related to assets or businesses we have sold. These
arrangements include, but are not limited to, indemnification
for income taxes, the resolution of existing disputes,
environmental matters, and necessary expenditures to ensure the
safety and integrity of the assets sold.
We record accruals for our guaranty and indemnification
arrangements at their fair value when they are issued and
subsequently adjust those accruals when we believe it is both
probable that we will have to pay amounts under the arrangements
and those amounts can be estimated. As of December 31,2005, we had a liability of $91 million related to our
guarantees and indemnification arrangements. These arrangements
had a total stated value of $233 million, for which we are
indemnified by third parties for $29 million. These amounts
exclude guarantees for which we have issued related letters of
credit discussed in Note 14.
In addition to the exposures described above, a trial court has
ruled, which was upheld on appeal, that we are required to
indemnify a third party for benefits being paid to a closed
group of retirees of one of our former subsidiaries. We have a
liability of approximately $380 million associated with our
estimated exposure under this matter as of December 31,2005. For a further discussion of this matter, see Retiree
Medical Benefits Matters above.
Other Commercial Commitments. We have various other
commercial commitments and purchase obligations that are not
recorded on our balance sheet. At December 31, 2005, we had
firm commitments under transportation and storage capacity
contracts of $854 million, commodity purchase commitments
of $142 million and other purchase and capital commitments
(including maintenance, engineering, procurement and
construction contracts) of $562 million.
We also hold cancelable easements or right-of-way arrangements
from landowners permitting the use of land for the construction
and operation of our pipeline systems. Currently, our obligation
under these easements is not material to the results of our
operations. However, we are currently negotiating a long-term
right-of-way agreement with the Navajo Nation which could result
in a significant commitment to us (see Other Contingencies).
17. Retirement Benefits
Overview of Retirement Benefits
Pension Benefits. Our primary pension plan is a defined
benefit plan that covers substantially all of our
U.S. employees and provides benefits under a cash balance
formula. Certain employees who participated in the prior pension
plans of El Paso, Sonat or Coastal receive the greater of cash
balance benefits or transition benefits under the prior plan
formulas. We do not anticipate making any contributions to this
pension plan in 2006.
In addition to our primary pension plan, we maintain a
Supplemental Executive Retirement Plan (SERP) that provides
additional benefits to selected officers and key management. The
SERP provides benefits in excess of certain IRS limits that
essentially mirror those in the primary pension plan. We also
maintain two other pension plans that are closed to new
participants which provide benefits to former employees of our
previously discontinued coal and convenience store operations.
The SERP and the frozen plans together are referred to below as
other pension plans. We also participate in several
multi-employer pension plans for the benefit of our former
employees who were union members. Our contributions to these
plans during 2005, 2004 and 2003 were not material. We expect to
contribute $5 million to the SERP and $11 million to
the frozen plans in 2006.
During 2004, we recognized a $4 million curtailment benefit
in our pension plans primarily related to a reduction in the
number of employees that participate in our pension plan, which
resulted from our various asset sales and employee severance.
Retirement Savings Plan. We maintain a defined
contribution plan covering all of our U.S. employees. We
match 75 percent of participant basic contributions up to 6
percent of eligible compensation and can make additional
discretionary matching contributions. Amounts expensed under
this plan were approximately $30 million, $16 million
and $14 million for the years ended December 31, 2005,
2004 and 2003.
Other Postretirement Benefits. We provide postretirement
medical benefits for closed groups of retired employees and
limited postretirement life insurance benefits for current and
retired employees. Other postretirement employee benefits (OPEB)
for our regulated pipeline companies are prefunded to the extent
such costs are recoverable through rates. To the extent actual
OPEB costs for our regulated pipeline companies differ from the
amounts recovered in rates, a regulatory asset or liability is
recorded. We expect to contribute $45 million to our
postretirement plans in 2006. 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, and we reserve the right to change these benefits.
Pension and Other Postretirement Benefits. Below is our
projected benefit obligation, accumulated benefit obligation,
fair value of plan assets as of September 30, our plan
measurement date, and related balance sheet accounts for our
pension plans as of December 31:
Primary
Other
Pension Plan
Pension Plans
2005
2004
2005
2004
(In millions)
Projected benefit obligation
$
2,059
$
1,948
$
176
$
170
Accumulated benefit obligation
2,041
1,934
176
169
Fair value of plan assets
2,253
2,196
97
93
Accrued benefit liability
—
—
77
74
Prepaid benefit cost
918
960
—
—
Accumulated other comprehensive loss
—
—
75
70
We are required to recognize an additional minimum liability for
pension plans with an accumulated benefit obligation in excess
of plan assets. We recorded pre-tax other comprehensive income
(loss) of $(5) million in 2005, $(33) million in 2004
and $18 million in 2003 related to the change in this
additional minimum liability.
Change in Projected Benefit Obligation, Plan Assets and
Funded Status. Our benefits are presented and computed as of
and for the twelve months ended September 30.
Other
Postretirement
Pension Benefits
Benefits
2005
2004
2005
2004
(In millions)
Change in benefit obligation:
Projected benefit obligation at beginning of period
$
2,118
$
2,091
$
541
$
575
Service cost
22
31
1
1
Interest cost
121
121
29
34
Participant contributions
—
—
34
27
Settlements, curtailments and special termination benefits
Less: Projected benefit obligation at end of period
2,235
2,118
527
541
Funded status at September 30
115
171
(276
)
(321
)
Fourth quarter contributions and income
2
2
11
13
Unrecognized net actuarial
loss(2)
814
800
20
32
Unrecognized net transition obligation
—
—
—
8
Unrecognized prior service cost
(13
)
(17
)
(5
)
(6
)
Prepaid (accrued) benefit cost at December 31
$
918
$
956
$
(250
)
$
(274
)
(1)
Increase is due primarily to changes in our discount rate and
mortality assumptions in 2005 and 2004.
(2)
We recognize the difference between our actual return on plan
assets and our expected return over a three year period.
Our deferred actuarial gains and losses are recognized only to
the extent that all of our remaining unrecognized actual gains
and loses exceed the greater of 10 percent of our projected
benefit obligations or market related value of plan assets.
The portion of our other postretirement benefit obligation
included in current liabilities was $35 million and
$38 million as of December 31, 2005 and 2004.
Expected Payment of Future Benefits. As of
December 31, 2005, we expect the following payments under
our plans:
Year Ending
Other Postretirement
December 31,
Pension Benefits
Benefits(1)
(In millions)
2006
$
167
$
49
2007
168
47
2008
167
46
2009
167
45
2010
166
44
2011-2015
815
197
Total
$
1,650
$
428
(1)
Includes a reduction of $3 million for the years 2006
through 2008 and $4 million for each year thereafter for an
expected subsidy related to the Medicare Prescription Drug,
Improvement and Modernization Act of 2003.
Components of Net Benefit Cost (Income). For each of the
years ended December 31, the components of net benefit cost
(income) are as follows:
Other Postretirement
Pension Benefits
Benefits
2005
2004
2003
2005
2004
2003
(In millions)
Service cost
$
22
$
31
$
36
$
1
$
1
$
1
Interest cost
121
121
134
29
34
35
Expected return on plan assets
(168
)
(187
)
(227
)
(12
)
(11
)
(9
)
Amortization of net actuarial loss
69
47
7
—
4
1
Amortization of transition obligation
—
—
(1
)
8
8
8
Amortization of prior service
cost(1)
(2
)
(3
)
(3
)
(1
)
(1
)
(1
)
Settlements, curtailment, and special termination benefits
—
(4
)
11
—
—
(6
)
Other
7
—
—
—
—
—
Net benefit cost (income)
$
49
$
5
$
(43
)
$
25
$
35
$
29
(1)
As permitted, the amortization of any prior service cost is
determined using a straight-line amortization of the cost over
the average remaining service period of employees expected to
receive benefits under the plan.
Actuarial Assumptions and Sensitivity Analysis. Projected
benefit obligations and net benefit cost are based on actuarial
estimates and assumptions. The following table details the
weighted-average actuarial assumptions used in determining the
projected benefit obligation and net benefit costs of our
pension and other postretirement plans for 2005, 2004 and 2003:
Other
Pension Benefits
Postretirement Benefits
2005
2004
2003
2005
2004
2003
(Percent)
(Percent)
Assumptions related to benefit obligations at September 30:
Discount rate
5.50
5.75
5.25
5.75
Rate of compensation increase
4.00
4.00
Assumptions related to benefit costs for the year ended
December 31:
Discount rate
5.75
6.00
6.75
5.75
6.00
6.75
Expected return on plan
assets(1)
8.00
8.50
8.80
7.50
7.50
7.50
Rate of compensation increase
4.00
4.00
4.00
(1)
The expected return on plan assets is a pre-tax rate (before a
tax rate ranging from 26 percent to 27 percent on other
postretirement benefits) that is primarily based on an expected
risk-free investment return, adjusted for historical risk
premiums and specific risk adjustments associated with our debt
and equity securities. These expected returns were then weighted
based on our target asset allocations of our investment
portfolio.
Actuarial estimates for our other postretirement benefit plans
assumed a weighted-average annual rate of increase in the per
capita costs of covered health care benefits of
10.9 percent, gradually decreasing to 5.0 percent by
the year 2015. 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 as of September 30:
2005
2004
(In millions)
One percentage point increase:
Aggregate of service cost and interest cost
$
1
$
1
Accumulated postretirement benefit obligation
20
19
One percentage point decrease:
Aggregate of service cost and interest cost
$
(1
)
$
(1
)
Accumulated postretirement benefit obligation
(18
)
(18
)
Plan Assets. The following table provides the target and
actual asset allocations in our pension and other postretirement
benefit plans as of September 30:
Pension Plans
Other Postretirement Plans
Asset Category
Target
Actual 2005
Actual 2004
Target
Actual 2005
Actual 2004
(Percent)
(Percent)
Equity
securities(1)
60
65
62
65
61
60
Debt securities
40
34
37
35
32
33
Other
—
1
1
—
7
7
Total
100
100
100
100
100
100
(1)
During the third quarter of 2005, we liquidated all of the
El Paso common stock included in plan assets. At
September 30, 2004, actuals for our pension plans include
$42 million (1.8 percent of total assets) of our
common stock.
The primary investment objective of our plans is to ensure, that
over the long-term life of the plans, an adequate pool of
sufficiently liquid assets to support the benefit obligations to
participants, retirees and beneficiaries exists. In meeting this
objective, the plans seek to achieve a high level of investment
return consistent with a prudent level of portfolio risk.
Investment objectives are long-term in nature covering typical
market cycles of three to five years. Any shortfall of
investment performance compared to investment objectives is the
result of general economic and capital market conditions.
Other Matters. During the fourth quarter of 2005, we
recorded an increase to our legal reserves of approximately
$350 million associated with a closed group of retirees of
the Case Corporation increasing our total liability to
$380 million at December 31, 2005. A trial court
ruled, which was upheld on appeal, that we are required to
indemnify Case for benefits paid to these retirees. We estimated
our liability under this ruling utilizing actuarial methods
similar to those used in estimating our obligations associated
with our other postretirement benefit plans; however, these
legal reserves are not included in the disclosures related to
our pension and other postretirement benefits above. For a
further discussion of this matter, see Note 16.
18. Capital Stock
Common Stock
In 2003 and 2004, we issued 26.4 million shares to satisfy
our obligations under the Western Energy Settlement. In December
2003, we completed a tender offer to exchange approximately
53 percent of our total 9.0% equity security units
outstanding for $59 million in cash, and issued
approximately 15.2 million shares of our common stock with
a total market value of $119 million. In August 2005,
we issued approximately 13.6 million shares of common stock
to the remaining holders of $272 million of notes which
originally formed a portion of our equity security units in
settlement of their commitment to purchase the shares.
Convertible Perpetual Preferred
Stock
In April 2005, we issued $750 million of convertible
perpetual preferred stock. Cash dividends on the preferred stock
are paid quarterly at the rate of 4.99% per annum if declared by
our Board of Directors. Unpaid dividends accumulate at 4.99%
until paid. Each share of the preferred stock is convertible at
the holder’s option, at any time, subject to adjustment,
into 76.7754 shares of our common stock under certain
conditions. This conversion rate represents an equivalent
conversion price of approximately $13.03 per share. The
conversion rate is subject to adjustment based on certain events
which include, but are not limited to, fundamental changes in
our business such as mergers or business combinations as well as
distributions of our common stock or adjustments to the current
rate of dividends on our common stock. We will be able to cause
the preferred stock to be converted into common stock after five
years if our common stock is trading at a premium of
130 percent to the conversion price.
The net proceeds of $723 million from the issuance of the
preferred stock, together with cash on hand, was used to prepay
our Western Energy Settlement of approximately $442 million
in April 2005, and to pay the redemption price (an
aggregate of $300 million plus accrued dividends of
$3 million) of the 6 million outstanding shares of
8.25% Series A cumulative preferred stock of our
subsidiary, EPTP, in May 2005.
Dividends
The table below shows the amount of dividends paid and declared
(in millions, except per share amounts).
Dividends on our common stock are treated as reduction of
additional paid-in-capital since we currently have an
accumulated deficit. We expect dividends paid on our common and
preferred stock in 2005 will be
taxable to our stockholders because we anticipate that these
dividends will be paid out of current or accumulated earnings
and profits for tax purposes.
The terms of our 750,000 outstanding shares of 4.99% convertible
preferred stock prohibit the payment of dividends on our common
stock unless we have paid or set aside for payment all
accumulated and unpaid dividends on such preferred stock for all
preceding dividend periods. In addition, although our credit
facilities do not contain any direct restriction on the payment
of dividends, dividends are included as a fixed charge in the
calculation of our fixed charge coverage ratio under our credit
facilities. If our fixed charge ratio were to exceed the
permitted maximum level, our ability to pay additional dividends
would be restricted.
19. Stock-Based Compensation
We grant stock awards under various stock option plans. We
account for our stock option plans using APB No. 25
and its related interpretations. Under our stock-based
compensation plans, we may issue to our employees incentive
stock options on our common stock (intended to qualify under
Section 422 of the Internal Revenue Code), non-qualified
stock options, restricted stock, restricted stock units, stock
appreciation rights, performance shares, performance units and
other stock-based awards. In addition, we may also issue shares
under our employee stock purchase plan or issue deferred shares
of common stock to our non-employee directors.
We are authorized to grant awards of approximately 42.5 million
shares of our common stock under our current plans, which
includes 35 million shares under our employee plan,
2.5 million shares under our non-employee director plan and
5 million shares under our employee stock purchase plan. At
December 31, 2005, approximately 40 million shares
remain available for grant under our current plans. In addition,
we have approximately 28 million shares of stock option
awards outstanding which were granted under terminated plans
that obligate us to issue additional shares of common stock if
they are exercised.
Non-qualified Stock
Options
We granted non-qualified stock options to our employees in 2005,
2004 and 2003. 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. Prior to
2004, we also granted options to non-employee members of the
Board of Directors at fair market value on the grant date that
were exercisable immediately. A summary of our stock option
transactions, stock options outstanding and stock options
exercisable as of December 31 is presented below:
Stock Options
2005
2004
2003
Weighted
Weighted
Weighted
# Shares of
Average
# Shares of
Average
# Shares of
Average
Underlying
Exercise
Underlying
Exercise
Underlying
Exercise
Options
Price
Options
Price
Options
Price
Outstanding at beginning of year
33,923,578
$
42.73
36,245,014
$
47.90
43,208,374
$
49.16
Granted
4,254,270
$
10.74
4,842,453
$
7.16
1,180,041
$
7.29
Exercised
(219,244
)
$
7.31
(3,193
)
$
7.64
—
—
Converted(1)
—
—
(11,333
)
$
42.99
(871,250
)
$
42.00
Forfeited or canceled
(9,875,119
)
$
45.78
(7,149,363
)
$
44.75
(7,272,151
)
$
49.53
Outstanding at end of year
28,083,485
$
37.12
33,923,578
$
42.73
36,245,014
$
47.90
Exercisable at end of year
20,792,538
$
46.96
28,455,056
$
49.45
28,703,151
$
46.04
(1)
Includes the conversion of stock options into common stock and
cash at no cost to employees based upon achievement of certain
performance targets and lapse of time. These options had an
original stated exercise price of approximately $43 per
share and $42 per share in 2004 and 2003.
The following table summarizes the range of exercise prices and
the weighted-average remaining contractual life of options
outstanding and the range of exercise prices for the options
exercisable at December 31, 2005.
Options Outstanding
Options Exercisable
Weighted Average
Weighted
Weighted
Range of
Number
Remaining Years of
Average
Number
Average
Exercise Prices
Outstanding
Contractual Life
Exercise Price
Exercisable
Exercise Price
$ 0.00 - $14.29
8,866,680
8.4
$
8.74
1,575,733
$
7.24
$14.30 - $28.59
2,292,259
1.3
$
21.76
2,292,259
$
21.76
$28.60 - $42.88
4,740,576
2.9
$
39.79
4,740,576
$
39.79
$42.89 - $57.18
4,405,272
3.6
$
46.91
4,405,272
$
46.91
$57.19 - $70.63
7,778,698
4.1
$
66.82
7,778,698
$
66.82
28,083,485
5.0
$
37.12
20,792,538
$
46.96
SFAS No. 123 Assumptions
The fair value of each stock option granted was estimated on the
date of grant using a separate
Black-Scholes
option-pricing
calculation for each grant and was used to estimate the pro
forma compensation expense in Note 1. Listed below is the
weighted average of each assumption based on grants in each
fiscal year:
Assumption:
2005
2004
2003
Expected Term in Years
4.82
5.35
6.19
Expected Volatility
42%
45%
52%
Expected Dividends
1.5%
2.1%
2.2%
Risk-Free Interest Rate
3.7%
3.7%
3.4%
These assumptions yielded a weighted average grant date fair
value of options granted of $3.88 per share in 2005,
$2.69 per share in 2004 and $3.21 per share in 2003.
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, which typically vest over three years from the
date of grant. These shares carry voting and dividend rights,
however, sale or transfer of the shares is restricted until they
vest. We currently have outstanding and grant only time-based
restricted share awards. Historically, we also granted
performance-based restricted share awards; however, these shares
have been fully vested or were forfeited prior to the end of
2005. The fair value of our time-based restricted shares is
determined on the grant date, recorded as unamortized
compensation as a component of stockholders’ equity on our
balance sheet and amortized to compensation expense over the
vesting period.
During 2005, 2004 and 2003 we granted 2.1 million,
3.1 million and 0.4 million shares of restricted stock
awards with a weighted average grant date fair value of $10.78,
$8.63 and $7.46 per share, respectively. We recognized
compensation expense of $18 million, $23 million and
$60 million during 2005, 2004 and 2003 related to the
vesting of our restricted stock grants. At December 31,2005, we had 4 million shares of time-based restricted
stock outstanding and $17 million of unamortized
compensation on our balance sheet that will be charged to
compensation expense over the remaining vesting period.
Employee Stock Purchase
Program
In July 2005, we reinstated our employee stock purchase plan
under Section 423 of the Internal Revenue Code. The amended
and restated plan allows participating employees the right to
purchase our common stock on a quarterly basis at
95 percent of the market price on the last trading day of
each month. At December 31, 2005, approximately
3 million shares remain available for issuance under this
plan.
Our business consists of our Pipelines, Exploration and
Production, Marketing and Trading, Power and Field Services
segments. Our segments are strategic business units that provide
a variety of energy products and services. They are managed
separately as each segment requires different technology and
marketing strategies. Our corporate operations include our
general and administrative functions, a telecommunications
business, and various other contracts and assets, all of which
are immaterial. These other assets and contracts relate to
assets or businesses sold including financial services, LNG and
other items.
During 2005, we reclassified our south Louisiana gathering and
processing assets, which were part of our Field Services
segment, and the international power operations at our Nejapa,
CEBU and East Asia Utilities power plants as discontinued
operations. Our operating results for all periods reflect these
operations as discontinued.
Our Pipelines segment provides natural gas transmission,
storage, and related services, primarily in the United States.
We conduct our activities primarily through eight wholly owned
and four partially owned interstate transmission systems along
with five underground natural gas storage entities and an LNG
terminalling facility.
Our Exploration and Production segment is engaged in the
exploration for and the acquisition, development and production
of natural gas, oil and NGL, primarily in the United States and
Brazil.
Our Marketing and Trading segment’s operations focus on
marketing and managing the price risk associated with our
natural gas and oil production as well as the management of our
remaining trading portfolio.
Our Power segment primarily consists of an international power
business. Historically, this segment also had domestic power
plant operations and a domestic power contract restructuring
business. We have sold or announced the sale of substantially
all of these domestic businesses. Our ongoing focus within the
Power segment will be to manage the risks associated with our
remaining assets in Brazil.
Our Field Services segment conducts midstream activities related
to our remaining gathering and processing assets. We have
disposed of substantially all of the assets in this segment. Our
remaining assets were transferred to our Exploration and
Production segment during the first quarter of 2006.
We had no customers whose revenues exceeded 10 percent of
our total revenues in 2005, 2004 and 2003.
We use earnings before interest expense 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. Our business operations consist of both
consolidated businesses as well as substantial investments in
unconsolidated affiliates. We believe EBIT is useful to our
investors because it allows them to more effectively evaluate
the performance of all of our businesses and investments. Also,
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. EBIT may not be
comparable to measures used by other companies. Additionally,
EBIT should be considered in conjunction with net income and
other performance measures
such as operating income or operating cash flow. Below is a
reconciliation of our EBIT to our income (loss) from continuing
operations for the three years ended December 31:
2005
2004
2003
(In millions)
Segment EBIT
$
919
$
1,034
$
1,605
Corporate and other
(521
)
(217
)
(852
)
Interest and debt expense
(1,380
)
(1,607
)
(1,790
)
Distributions on preferred interests of consolidated subsidiaries
(9
)
(25
)
(52
)
Income taxes
289
(14
)
484
Loss from continuing operations
$
(702
)
$
(829
)
$
(605
)
The following tables reflect our segment results as of and for
each of the three years ended December 31:
Capital expenditures, capital investments and advances to
unconsolidated affiliates, net
(6)
908
1,851
—
6
8
14
2,787
Total investments in unconsolidated affiliates
1,042
761
—
670
—
—
2,473
(1)
Includes eliminations of intercompany transactions. Our
intersegment revenues, along with our intersegment operating
expenses, were incurred in the normal course of business between
our operating segments. We recorded an intersegment revenue
elimination of $91 million and an operation and maintenance
expense elimination of $2 million, which is included in the
“Corporate” column, to remove intersegment
transactions.
(2)
Revenues from external customers include gains and losses
related to our hedging of price risk associated with our natural
gas and oil production. Intersegment revenues represent sales to
our Marketing and Trading segment, which is responsible for
marketing our production.
(3)
Relates to intercompany activities between our continuing
operations and our discontinued operations.
(4)
Excludes assets of discontinued operations of $36 million
(see Note 3).
(5)
Of total foreign assets, approximately $672 million relates
to property, plant and equipment and approximately
$1.0 billion relates to investments in and advances to
unconsolidated affiliates.
(6)
Amounts are net of third party reimbursements of our capital
expenditures and returns of invested capital.
Capital expenditures, capital investments and advances to
unconsolidated affiliates,
net(6)
1,047
728
—
27
(15
)
10
1,797
Total investments in unconsolidated affiliates
1,032
6
—
1,225
305
6
2,574
(1)
Includes eliminations of intercompany transactions. Our
intersegment revenues, along with our intersegment operating
expenses, were incurred in the normal course of business between
our operating segments. We recorded an intersegment revenue
elimination of $236 million and an operation and
maintenance expense elimination of $25 million, which is
included in the “Corporate” column, to remove
intersegment transactions.
(2)
Revenues from external customers include gains and losses
related to our hedging of price risk associated with our natural
gas and oil production. Intersegment revenues represent sales to
our Marketing and Trading segment, which is responsible for
marketing our production.
(3)
Relates to intercompany activities between our continuing
operations and our discontinued operations.
(4)
Excludes assets of discontinued operations of $511 million
(see Note 3).
(5)
Of total foreign assets, approximately $1.1 billion relates
to property, plant and equipment and approximately
$1.5 billion relates to investments in and advances to
unconsolidated affiliates.
(6)
Amounts are net of third party reimbursements of our capital
expenditures and returns of invested capital.
Capital expenditures and investments in and advances to
unconsolidated affiliates,
net(6)
837
1,300
(1
)
1,081
(25
)
89
3,281
Total investments in unconsolidated affiliates
1,018
79
—
1,626
655
5
3,383
(1)
Includes eliminations of intercompany transactions. Our
intersegment revenues, along with our intersegment operating
expenses, were incurred in the normal course of business between
our operating segments. We recorded an intersegment revenue
elimination of $338 million and an operation and
maintenance expense elimination of $59 million, which is
included in the “Corporate” column, to remove
intersegment transactions.
(2)
Revenues from external customers include gains and losses
related to our hedging of price risk associated with our natural
gas and oil production. Intersegment revenues represent sales to
our Marketing and Trading segment, which is responsible for
marketing our production.
(3)
Relates to intercompany activities between our continuing
operations and our discontinued operations.
(4)
Excludes assets of discontinued operations of $2.2 billion.
(5)
Of total foreign assets, approximately $1.2 billion relates
to property, plant and equipment, and approximately
$1.7 billion relates to investments in and advances to
unconsolidated affiliates.
(6)
Amounts are net of third party reimbursements of our capital
expenditures and returns of invested capital. Our Power segment
includes approximately $1 billion to acquire remaining
interest in Chaparral and Gemstone (see Note 2).
21. Investments in, Earnings from and Transactions with
Unconsolidated Affiliates
We hold investments in unconsolidated affiliates which are
accounted for using the equity method of accounting. Our income
statement typically reflects (i) our share of net earnings
directly attributable to these unconsolidated affiliates, and
(ii) impairments and other adjustments recorded by us.
Our investment balance differs from the underlying net equity in
our investments due primarily to purchase price adjustments or
impairment charges recorded by us. As of December 31, 2005,
our investment balance exceeded the net equity in the underlying
net assets of these investments by $443 million due to
these items. The largest of our purchase price adjustments is
related to our investment in Four Star which we amortize over
the life of its proved reserves. Our investment balance at
December 31, 2004 was lower than the
underlying net assets of our investments by $305 million.
Our net ownership interest, investments in and earnings (losses)
from our consolidated affiliates are as follows as of and for
the years ended December 31:
Net Ownership
Earnings (Losses) from
Interest
Investment
Unconsolidated Affiliates
2005
2004
2005
2004
2005
2004
2003
(Percent)
(In millions)
(In millions)
Domestic:
Four
Star(1)
43
—
$
754
$
—
$
19
$
—
$
—
Citrus
50
50
596
589
66
65
43
Enterprise Products
Partners(2)
—
—
—
257
183
6
—
GulfTerra Energy
Partners(2)
—
—
—
—
—
601
419
Midland Cogeneration Venture
44
44
—
191
(162
)
(171
)
29
Great Lakes Gas Transmission
50
50
300
316
59
65
57
Javelina(2)
—
40
—
45
121
15
(2
)
Milford(2)
—
—
—
—
—
(1
)
(88
)
Chaparral
Investors(2)
—
—
—
—
—
—
(207
)
Other Domestic Investments
various
various
55
47
19
25
(36
)
Total domestic
1,705
1,445
305
605
215
Foreign:
Korea Independent Energy
Corporation(2)
—
50
—
176
127
22
29
Araucaria
Power(3)
60
60
187
186
—
—
—
EGE
Itabo(4)
25
25
24
88
(58
)
1
1
Bolivia to Brazil Pipeline
8
8
96
86
20
24
17
EGE
Fortuna(4)
25
25
68
65
2
6
3
Aguaytia
Energy(4)
24
24
23
39
(11
)
(5
)
4
San Fernando Pipeline
50
50
53
46
14
13
5
Habibullah
Power(4)(5)
50
50
16
20
(13
)
(46
)
(3
)
Manaus(6)
100
—
65
—
10
—
—
Rio
Negro(6)
100
—
49
—
9
—
—
Saba Power
Company(4)
94
94
—
7
(7
)
(51
)
4
Other Foreign
Investments(5)
various
various
187
416
(56
)
(23
)
88
Total foreign
768
1,129
37
(59
)
148
Total investments in unconsolidated affiliates
$
2,473
$
2,574
Total earnings from unconsolidated affiliates
$
342
$
546
$
363
(1)
We acquired our interest in Four Star in 2005 in connection with
our acquisition of Medicine Bow.
(2)
We sold our interest in Enterprise, Javelina and Korea
Independent Energy Corporation in 2005 and GulfTerra in 2004. We
also transferred our interest in Milford and consolidated
Chaparral Investors during 2003.
(3)
We signed a letter of intent in February 2006 to sell our
interest in this power facility.
(4)
We sold our interest in Aguaytia Energy in the first quarter of
2006. We have received approval from our Board of Directors to
sell our interest in the other investments, which are targeted
to close in the first half of 2006.
(5)
As of December 31, 2005 and 2004, we also had outstanding
advances and receivables of $37 million and
$64 million related to our investment in Habibullah Power.
We also had other outstanding advances and receivables of
$348 million and $320 million related to our other
foreign investments as of December 31, 2005 and 2004, of
which $331 million and $307 million are related to our
investment in Porto Velho.
(6)
While we continue to have 100 percent ownership, we
deconsolidated these investments in January 2005, upon entering
into an agreement that will transfer ownership of these plants
to the power purchaser in January 2008.
Impairment charges and gains and losses on sales of equity
investments are included in earnings from unconsolidated
affiliates. During 2005, 2004 and 2003, our impairments, gains
and losses were primarily a result of our decision to sell a
number of these investments, but we also had several investments
that experienced declines in their fair value due to changes in
economics of the investments’ underlying contracts, or the
markets they serve. These gains and losses consisted of the
following:
Investment or Group
2005
2004
2003
(In millions)
Midland Cogeneration
Venture(1)
$
(162
)
$
(161
)
$
—
Asia power investments
(64
)
(182
)
(1
)
Central and South American power investments
(89
)
—
24
Chaparral Investors
—
—
(207
)
Domestic power plants held for sale, sold or transferred
—
(44
)
(163
)
Dauphin Island Gathering/Mobile Bay Processing
—
—
(86
)
Enterprise/GulfTerra(2)
183
507
266
Javelina
111
—
—
KIECO
108
—
—
Other
4
4
(9
)
$
91
$
124
$
(176
)
(1)
Represents an impairment of our investment in 2004 and our
proportionate share of losses from our investment in MCV in
2005, primarily based on MCV’s impairment of the plant
assets.
(2)
See further discussion of these sales below.
Below is summarized financial information of our proportionate
share of the operating results and financial position of our
unconsolidated affiliates, including those in which we hold
greater than a 50 percent interest.
Includes net income of $15 million, $7 million and
$119 million in 2005, 2004 and 2003, related to our
proportionate share of affiliates in which we hold greater than
a 50 percent interest.
(2)
Includes total assets of $485 million and $593 million
as of December 31, 2005 and 2004 related to our
proportionate share of affiliates in which we hold greater than
a 50 percent interest.
We received distributions and dividends of $279 million and
$358 million in 2005 and 2004, which includes less than
$1 million and $23 million of returns of capital, from
our investments.
The following table shows revenues and charges resulting from
transactions with our unconsolidated affiliates:
2005
2004
2003
(In millions)
Operating
revenue(1)
$
117
$
199
$
216
Other revenue — management fees
—
3
13
Cost of sales
15
101
105
Reimbursement for operating
expenses(1)
5
95
139
Other income
9
8
10
Interest income
47
44
36
Interest expense
—
—
2
(1)
Decrease in 2005 is due primarily to the sale of GulfTerra
during 2004. See further discussion below.
GulfTerra and Enterprise
During 2003 and 2004, we owned a general partnership interest
and common and preference units in GulfTerra Energy Partners, a
limited partnership that held a variety of natural gas
gathering, treating and processing assets. During 2004,
GulfTerra merged with Enterprise Products Partners. Through a
series of transactions in 2003, 2004 and 2005, we disposed of
our interests in GulfTerra and Enterprise.
During 2003 and 2004, our Field Services segment managed
GulfTerra’s daily operations and performed all of their
administrative and operational activities through a series of
agreements. We also had a number of other transactions with
GulfTerra and Enterprise, including sales under natural gas
transportation contracts and the sale of several of our natural
gas gathering, treating and processing assets to GulfTerra in
previous years. The following table summarizes the income
statement impacts of our transactions with GulfTerra and
Enterprise and the sale of our interests in those entities for
the years ended December 31:
2005
2004
2003
(In millions)
Operating revenue
$
—
$
28
$
33
Operating expenses
—
113
114
Reimbursements
—
(71
)
(91
)
Earnings from unconsolidated affiliates
Proportionate share of earnings and other income
—
100
153
Gains on sales of investments
183
507
266
Matters that Could Impact Our
Investments
Investments in Power Facilities. We have interests in a
number of equity and cost basis investments that are considered
variable interests under FIN No. 46(R). As of December 31,2005, these entities consisted primarily of 17 equity and cost
investments held in our Power segment that had interests in
power generation and transmission facilities with a total
generating capacity of approximately 4,240 gross MW. We
operate many of these facilities but do not supply a significant
portion of the fuel consumed or purchase a significant portion
of the power generated by these facilities. The long-term debt
issued by these entities is recourse only to the power project.
As a result, our exposure to these entities is limited to our
investment in and advances to the entities ($564 million as
of December 31, 2005) and our guarantees and other
agreements associated with these entities (a maximum of
$87 million as of December 31, 2005).
We own a 56 percent direct equity interest in a
261 MW power plant, Berkshire Power, located in
Massachusetts. Berkshire’s lenders have asserted that
Berkshire is in default on its loan agreement and on
February 9, 2006, the lenders declared all obligations
outstanding under the loan agreement to be immediately due and
payable in full. This obligation is non-recourse to El Paso. We
have previously fully impaired the value of this investment.
However, we supply natural gas to Berkshire under a fuel
management agreement. Berkshire had the ability to delay payment
of 33 percent of the amounts due to us under the fuel
supply agreement, up to a maximum of $49 million which
Berkshire reached in March 2005. We reserved the cumulative
amount of the delayed payments based on Berkshire’s
inability to generate adequate cash flows
related to this agreement. We continue to supply fuel to the
plant under the fuel supply agreement and we may incur losses if
amounts owed on future fuel deliveries are not paid under this
agreement because of Berkshire’s inability to generate
adequate cash flow and the uncertainty surrounding their
negotiations with their lenders. We are in discussions with the
lenders and other owners of the project to transfer or terminate
our interest in this project.
We supply gas to power plants that we partially own, including
the Midland Cogeneration Venture (MCV) and Berkshire power
projects. Due to their affiliated nature, we do not recognize
mark-to-market gains or losses on these contracts to the extent
of our ownership interest. However, should we sell our interests
in these plants, we would record the cumulative unrecognized
mark-to-market losses on these contracts, which totaled
approximately $146 million as of December 31, 2005. We
also have issued letters of credit and margin deposits to MCV
for approximately $386 million and $44 million as of
December 31, 2005, securing our obligation under the gas
supply contracts.
Investment in Bolivia. We own an eight percent interest
in the Bolivia to Brazil pipeline in which we have approximately
$108 million of exposure, including guarantees, as of
December 31, 2005. During 2005, political disputes in
Bolivia related to pressure to nationalize the energy industry
led to the resignation of the country’s president and the
election of a new president. Recent changes in Bolivian law have
also increased the combined rate of production taxes and
royalties to 50 percent and required that existing
exploration contracts be renegotiated. Actions by the new
government in Bolivia could potentially lead to a disruption or
cessation of the supply of gas from that country and impact the
payments that our investment receives from Petrobras. We
continue to monitor the political situation in Bolivia and as
new information becomes available or future material
developments arise, it is possible that a future impairment of
our investment may occur.
Citrus Corporation. Citrus Trading Corporation (CTC), a
subsidiary of Citrus Corp. (Citrus), in which we own a
50 percent equity interest, has filed suit against Duke
Energy LNG Sales, Inc. (Duke) and PanEnergy Corp., the holding
company of Duke, seeking damages of $185 million for breach
of a gas supply contract and wrongful termination of that
contract. Duke sent CTC notice of termination of the gas supply
contract alleging failure of CTC to increase the amount of an
outstanding letter of credit as collateral for its purchase
obligations. CTC filed a motion for partial summary judgment,
requesting that the court find that Duke failed to give proper
notice of default to CTC regarding its alleged failure to
maintain the letter of credit. Duke has filed an amended counter
claim in federal court joining Citrus and a cross motion for
partial summary judgment, requesting that the court find that
Duke had a right to terminate its gas sales contract with CTC
due to the failure of CTC to adjust the amount of the letter of
credit supporting its purchase obligations. CTC has filed an
answer to Duke’s motion. In August 2005, the federal
district court issued an order denying both motions for summary
judgment, asserting that the ambiguity in the contract and the
performance of the parties created issues of fact that precluded
summary judgment on either side. CTC has filed additional
motions for partial summary judgment, requesting that the court
find that Duke improperly asserted force majeure due to its
alleged loss of gas supply and that Duke is in error in
asserting that CTC breached contractual provisions that imposed
resale restrictions and credit maintenance obligations. An
unfavorable outcome on this matter could impact the value of our
investment in Citrus. However, we do not expect the ultimate
resolution of this matter to have a material adverse effect on
us.
Supplemental Selected Quarterly Financial Information
(Unaudited)
Financial information by quarter is summarized below.
Quarters Ended
March 31
June 30
September 30
December 31
Total
(In millions, except per common share amounts)
2005
Operating revenues
$
1,108
$
1,184
$
768
$
957
$
4,017
Loss on long-lived assets
7
276
3
121
407
Operating income (loss)
243
89
(158
)
(361
)
(187
)
Earnings (losses) from unconsolidated affiliates
190
(19
)
14
157
342
Income (loss) from continuing operations
115
(212
)
(322
)
(283
)
(702
)
Discontinued operations, net of income
taxes(1)
(9
)
(26
)
10
125
100
Net income (loss)
106
(238
)
(312
)
(162
)
(606
)
Net income (loss) available to common stockholders
106
(246
)
(321
)
(172
)
(633
)
Basic and diluted earnings per common share
Income (loss) from continuing operations
0.18
(0.34
)
(0.51
)
(0.45
)
(1.13
)
Net income (loss)
0.17
(0.38
)
(0.50
)
(0.26
)
(0.98
)
Quarters Ended
March 31
June 30
September 30
December 31
Total
(In millions, except per common share amounts)
2004
Operating revenues
$
1,472
$
1,443
$
1,349
$
1,275
$
5,539
Loss on long-lived assets
238
17
582
240
1,077
Operating income (loss)
180
361
(368
)
9
182
Earnings (losses) from unconsolidated affiliates
87
98
617
(256
)
546
Income (loss) from continuing operations
(126
)
28
(205
)
(526
)
(829
)
Discontinued operations, net of income
taxes(1)
(70
)
(23
)
(9
)
(16
)
(118
)
Net income (loss)
(196
)
5
(214
)
(542
)
(947
)
Basic and diluted earnings per common share
Income (loss) from continuing operations
(0.20
)
0.04
(0.32
)
(0.82
)
(1.30
)
Net income (loss)
(0.31
)
0.01
(0.33
)
(0.85
)
(1.48
)
(1)
Our petroleum markets operations, our Canadian and certain other
international natural gas and oil production operations, our
south Louisiana gathering and processing operations, and our
consolidated international power operations in Central America
and Asia are classified as discontinued operations (See
Note 3 for further discussion).
Supplemental Natural Gas and Oil Operations (Unaudited)
Our Exploration and Production segment is engaged in the
exploration for, and the acquisition, development and production
of natural gas, oil and NGL, primarily in the United States and
Brazil.
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
States
Brazil
Worldwide
2005
Natural gas and oil properties:
Costs subject to amortization
$
14,874
$
371
$
15,245
Costs not subject to amortization
384
107
491
15,258
478
15,736
Less accumulated depreciation, depletion and amortization
11,021
183
11,204
Net capitalized costs
$
4,237
$
295
$
4,532
FAS 143 abandonment liability
$
186
$
4
$
190
2004
Natural gas and oil properties:
Costs subject to amortization
$
14,211
$
337
$
14,548
Costs not subject to amortization
308
112
420
14,519
449
14,968
Less accumulated depreciation, depletion and amortization
11,130
138
11,268
Net capitalized costs
$
3,389
$
311
$
3,700
FAS143 abandonment liability
$
252
$
4
$
256
Costs incurred in natural gas and oil producing activities,
whether capitalized or expensed, were as follows at December 31
(in millions):
Includes $179 million of deferred income tax adjustments
related to the acquisition of full-cost pool properties and
$217 million related to the acquisition of our
unconsolidated investment in Four Star.
(2)
Includes an increase to our property, plant and equipment of
approximately $114 million in 2003 associated with our
adoption of Statement of Financial Accounting Standard
No. 143.
The table above includes capitalized internal costs incurred in
connection with the acquisition, development and exploration of
natural gas and oil reserves of $47 million,
$44 million, and $58 million and capitalized interest
of $30 million, $22 million and $19 million for
the years ended December 31, 2005, 2004 and 2003.
In our January 1, 2006 reserve report, the amounts
estimated to be spent in 2006, 2007 and 2008 to develop our
worldwide proved undeveloped reserves are $318 million,
$459 million and $221 million.
Presented below is an analysis of the capitalized costs of
natural gas and oil properties by year of expenditures that are
not being amortized as of December 31, 2005, pending
determination of proved reserves (in millions):
Includes operations in the United States and Brazil.
(2)
Includes capitalized interest of $19 million,
$7 million, and less than $1 million for the years
ended December 31, 2005, 2004, and 2003.
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 2006
through 2008. Our total amortization expense per Mcfe for the
United States was $2.25, $1.84, and $1.40 in 2005, 2004, and
2003 and $2.33 and $2.02 for Brazil in 2005 and 2004. We had no
production in Brazil during 2003. Included in our worldwide
depreciation, depletion and amortization expense is accretion
expense of $0.10/Mcfe, $0.08/Mcfe and $0.06/Mcfe for 2005, 2004
and 2003 for the United States and $0.01/Mcfe for Brazil in 2005
and 2004, attributable to SFAS No. 143, which we adopted in
January 2003.
Net quantities of proved developed and undeveloped reserves of
natural gas and NGL, oil, and condensate, and changes in these
reserves at December 31, 2005 are presented below.
Information in these tables is based on our internal reserve
report. Ryder Scott Company, an independent petroleum
engineering firm, prepared an estimate of our natural gas and
oil reserves for 92 percent of our properties. Based on the
amount of proved reserves determined by Ryder Scott, we believe
these reported reserve amounts are
reasonable. 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. Ryder
Scott was retained by, and reports to the Audit Committee of our
Board of Directors. The tables below exclude our Power
segment’s equity interest in in proved reserves in
Indonesia and Peru. Our Power segment has completed or expects
to complete these sales in 2006. Combined proved reserve
balances for these interests were 162,254 MMcf of natural
gas and 2,058 MBbls of oil, condensate and NGL for total
natural gas equivalents of 174,600 MMcfe, all net to our
ownership interests.
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)
Our unconsolidated share of Four Star’s proved reserves has
been estimated based on an evaluation of those reserves by El
Paso’s internal reservoir engineers, and not by engineers
of Four Star. An independent reservoir engineering firm, Ryder
Scott, which was engaged by us, prepared an estimate on
86 percent of Four Star’s proved reserves. Based on
the amount of Four Star’s proved reserves determined by
Ryder Scott, we believe our reported reserve amounts are
reasonable.
(3)
All of our NGL reserves are in the United States.
There are numerous uncertainties inherent in estimating
quantities of proved reserves, projecting future rates of
production and projecting the 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 accuracy of any reserve
estimate is a function of the quality of available data and of
engineering and geological interpretations and judgment. All
estimates of proved reserves are determined according to the
rules prescribed by the SEC. These rules indicate that the
standard of “reasonable certainty” be applied to
proved reserve estimates. This concept of reasonable certainty
implies that as more technical data becomes available, a
positive, or upward, revision is more likely than a negative, or
downward, revision. Estimates are subject to revision based upon
a number of factors, including reservoir performance, prices,
economic conditions and government restrictions. In addition,
results of drilling, testing and production subsequent to the
date of an estimate may justify revision of that estimate.
Reserve estimates are often different from the quantities of
natural gas and oil that are ultimately recovered. The
meaningfulness of reserve estimates is highly dependent on the
accuracy of the assumptions on which they were based. In
general, the volume of production from natural gas and oil
properties we own declines as reserves are depleted. Except to
the extent we conduct successful exploration and development
activities or acquire additional properties containing proved
reserves, or both, our proved reserves will decline as reserves
are produced. 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, 2005.
We maintain an agreement with a subsidiary of Nabors Industries
in which we sold interests in 23 wells. As the wells were
developed, Nabors paid 20 percent of the drilling and
development costs in exchange for 20 percent of the net
profits of the wells sold. As each well commenced, Nabors
received an overriding royalty interest in the form of a net
profits interest in the well, under which they are entitled to
receive 20 percent of the aggregate net profits of all
wells until they recover 117.5 percent of their aggregate
investment. Upon recovery, the net profits interest converts to
a proportionately reduced 2 percent overriding royalty
interest in the wells for the remainder of the well’s
productive life. We do not guarantee a return or the recovery of
Nabors’ costs.
Results of operations from producing activities by fiscal year
were as follows at December 31 (in millions):
United
States
Brazil
Worldwide
2005
Net Revenues
Sales to external customers
$
431
$
62
$
493
Affiliated sales
1,256
(9
)
1,247
Total
1,687
53
1,740
Production
costs(1)
(253
)
(8
)
(261
)
Depreciation, depletion and amortization
(567
)
(45
)
(612
)
867
—
867
Income tax expense
(309
)
—
(309
)
Results of operations from producing activities
$
558
$
—
$
558
Equity earnings from unconsolidated investment in Four Star
Production cost includes lease operating costs and production
related taxes, including ad valorem and severance taxes.
The standardized measure of discounted future net cash flows
relating to our consolidated proved natural gas and oil reserves
at December 31 is as follows (in millions):
United
States
Brazil
Worldwide
2005
Future cash
inflows(1)
$
18,175
$
1,992
$
20,167
Future production costs
(3,968
)
(453
)
(4,421
)
Future development costs
(1,335
)
(309
)
(1,644
)
Future income tax expenses
(3,160
)
(286
)
(3,446
)
Future net cash flows
9,712
944
10,656
10% annual discount for estimated timing of cash flows
(3,660
)
(381
)
(4,041
)
Standardized measure of discounted future net cash flows
$
6,052
$
563
$
6,615
Standardized measure of discounted future net cash flows,
including effects of hedging activities
$
5,748
$
560
$
6,308
Unconsolidated investment in Four Star
Standardized measure of discounted future net cash flows
$
617
$
—
$
617
2004
Future cash
inflows(1)
$
11,895
$
1,077
$
12,972
Future production costs
(3,585
)
(135
)
(3,720
)
Future development costs
(1,234
)
(274
)
(1,508
)
Future income tax expenses
(1,184
)
(141
)
(1,325
)
Future net cash flows
5,892
527
6,419
10% annual discount for estimated timing of cash flows
(2,004
)
(219
)
(2,223
)
Standardized measure of discounted future net cash flows
$
3,888
$
308
$
4,196
Standardized measure of discounted future net cash flows,
including effects of hedging activities
$
3,907
$
305
$
4,212
2003
Future cash
inflows(1)
$
13,302
$
588
$
13,890
Future production costs
(3,025
)
(65
)
(3,090
)
Future development costs
(1,325
)
(236
)
(1,561
)
Future income tax expenses
(1,695
)
(75
)
(1,770
)
Future net cash flows
7,257
212
7,469
10% annual discount for estimated timing of cash flows
(2,449
)
(128
)
(2,577
)
Standardized measure of discounted future net cash flows
$
4,808
$
84
$
4,892
Standardized measure of discounted future net cash flows,
including effects of hedging activities
United States excludes $502 million, $1 million and
$104 million of future net cash outflows attributable to
hedging activities in the years 2005, 2004 and 2003. Brazil
excludes $4 million and $5 million of future net cash
outflows attributable to hedging activities in 2005 and 2004.
For the calculations in the preceding table, estimated future
cash inflows from estimated future production of proved reserves
were computed using year-end prices of $10.08 per MMBtu for
natural gas and $61.04 per barrel of oil at
December 31, 2005. In the United States, after adjustments
for transportation and other charges, net prices were $8.33 per
Mcf of gas, $57.42 per barrel of oil and $36.61 per barrel of
NGL at December 31, 2005. 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.
The following are the principal sources of change in our
consolidated worldwide standardized measure of discounted future
net cash flows (in millions):
Years Ended December 31,(1)
2005
2004
2003
(In millions)
Sales and transfers of natural gas and oil produced net of
production costs
$
(1,477
)
$
(1,470
)
$
(1,829
)
Net changes in prices and production costs
2,884
29
1,586
Extensions, discoveries and improved recovery, less related costs
793
268
1,105
Changes in estimated future development costs
2
4
(16
)
Previously estimated development costs incurred during the period
247
156
220
Revision of previous quantity estimates
47
(453
)
(94
)
Accretion of discount
476
568
526
Net change in income taxes
(1,093
)
257
159
Purchases of reserves in place
956
114
5
Sale of reserves in place
(83
)
(75
)
(1,229
)
Change in production rates, timing and other
(333
)
(94
)
150
Net change
$
2,419
$
(696
)
$
583
(1) This
disclosure reflects changes in the standardized measure
calculation excluding the effects of hedging activities.
Relates primarily to valuation allowances for deferred tax
assets related to the Western Energy Settlement, foreign ceiling
test charges, foreign asset impairments and state and foreign
net operating loss carryovers.
(3)
Relates to our Western Energy Settlement of $104 million in
2003. In 2005 and 2004, we paid approximately $442 million
and $602 million to the settling parties.
(4)
Relates primarily to payments for various litigation reserves,
including the Western Energy Settlement, environmental
remediation reserves or revenue crediting and rate settlement
reserves.
(5)
Relates primarily to receivables from trading counterparties,
reclassified due to bankruptcy or declining credit that have
been accounted for within our price risk management activities.
(6)
Relates primarily to liabilities previously classified in our
petroleum discontinued operations, but reclassified as
continuing operations due to our retention of these obligations.
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
AND FINANCIAL DISCLOSURE
None.
ITEM 9A. CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
As of December 31, 2005, we carried out an evaluation under
the supervision and with the participation of our management,
including our CEO and our CFO, as to the effectiveness, design
and operation of our disclosure controls and procedures, as
defined by the Securities Exchange Act of 1934, as amended. This
evaluation considered the various processes carried out under
the direction of our disclosure committee in an effort to ensure
that information required to be disclosed in the SEC reports we
file or submit under the Exchange Act is accurate, complete and
timely.
Based on the results of this evaluation, our CEO and CFO
concluded that our disclosure controls and procedures were
effective as of December 31, 2005.
See Part II, Item 8 Financial Statements and Supplementary Data
under Management’s Annual Report on Internal Control Over
Financial Reporting.
Changes in Internal Control over Financial Reporting
There were no changes in our internal control over financial
reporting that have materially affected or are reasonably likely
to materially affect our internal control over financial
reporting during the fourth quarter 2005.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE
REGISTRANT
The information included under the captions “Corporate
Governance”, “Proposal No. 1 — Election
of Directors” and “Section 16(a) Beneficial
Ownership Reporting Compliance” in our Proxy Statement for
the 2006 Annual Meeting of Stockholders is incorporated herein
by reference. Information regarding our executive officers is
presented in Part I, Item 1, Business, of this
Form 10-K under
the caption “Executive Officers of the Registrant.”
As a result of the promulgation of
Rule 10b5-1, we
allow certain officers and directors to establish
pre-established trading plans.
Rule 10b5-1 allows
certain officers and directors to establish written programs
that permit an independent person who is not aware of inside
information at the time of the trade to execute pre-established
trades of our securities for the officer or director according
to fixed parameters. Effective November 9, 2005, Mr. Kuehn
entered into a trading plan in compliance with Rule 10b5-1
for 125,000 of his stock options that expire on
September 2, 2006. The sale period under the trading plan
is effective November 16, 2005 to September 1, 2006
and will effectuate an exercise and sale of the shares at
certain minimum limit prices provided by the trading plan.
ITEM 11. EXECUTIVE COMPENSATION
Information appearing under the captions “Information about
the Board of Directors and Committees”, “Executive
Compensation”, “Performance Graph”,
“Compensation Committee Report on Executive
Compensation” and “Employment Contracts, Termination
of Employment, Change in Control Agreements and Director and
Officer Indemnification Agreements” in our proxy statement
for the 2006 Annual Meeting of Stockholders is incorporated
herein by reference.
ITEM 12.
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT AND RELATED STOCKHOLDER MATTERS
Information appearing under the caption “Security Ownership
of Certain Beneficial Owners and Management” and
“Equity Compensation Plan Information Table” in our
proxy statement for the 2006 Annual Meeting of Stockholders is
incorporated herein by reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED
TRANSACTIONS
Information appearing under the caption “Certain
Relationships and Related Transactions” in our proxy
statement for the 2006 Annual Meeting of Stockholders is
incorporated herein by reference.
The Audit fees for the years ended December 31, 2005
and 2004, respectively, were for professional services rendered
for the audits of the consolidated financial statements of El
Paso, statutory subsidiary and equity investee audits; the audit
of our internal controls in compliance with Section 404 of
the Sarbanes-Oxley Act of 2002; the review of documents filed
with the Securities and Exchange Commission; and consents and
the issuance of comfort letters.
The Audit Related fees for the years ended
December 31, 2005 and December 31, 2004, respectively,
were for professional services rendered for employee benefit
plans; the carve-out audits of businesses disposed of by El
Paso; responding to inquiries of certain federal agencies
related to audit work performed; and accounting consultations.
Tax fees for the years ended December 31, 2005 and
2004, respectively, were for professional services related to
tax compliance and tax planning.
El Paso’s Audit Committee has adopted a pre-approval policy
for audit and non-audit services. The Audit Committee has
considered whether the provision of non-audit services by
PricewaterhouseCoopers LLP is compatible with maintaining
auditor independence and has determined that auditor
independence has not been compromised.
PART IV
ITEM 15.
EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a) The following documents are filed as a part of this
report:
1. Financial statements.
The following consolidated financial statements are included in
Part II, Item 8 of this report:
Page
Consolidated Statements of Income
86
Consolidated Balance Sheets
87
Consolidated Statements of Cash Flows
89
Consolidated Statements of Stockholders’ Equity
91
Consolidated Statements of Comprehensive Income
92
Notes to Consolidated Financial Statements
93
Report of Independent Registered Public Accounting Firm
84
2. Financial statement schedules and supplementary
information required to be submitted.
Schedule II — Valuation and Qualifying Accounts
154
Midland Cogeneration Venture Limited Partnership
Report of Independent Registered Public Accounting Firm
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Partners and the Management Committee of
Midland Cogeneration Venture Limited Partnership:
We have completed integrated audits of Midland Cogeneration
Venture Limited Partnership’s 2005 and 2004 consolidated
financial statements and of its internal control over financial
reporting as of December 31, 2005 and an audit of its 2003
consolidated financial statements in accordance with the
standards of the Public Company Accounting Oversight Board
(United States). Our opinions, based on our audits, are
presented below.
Consolidated financial statements
In our opinion, the consolidated financial statements listed in
the index appearing under Item 15(a)(1) present fairly, in
all material respects, the financial position of Midland
Cogeneration Venture Limited Partnership (a Michigan Limited
Partnership) and its subsidiaries at December 31, 2005 and
2004, and the results of their operations and their cash flows
for each of the three years in the period ended
December 31, 2005 in conformity with accounting principles
generally accepted in the United States of America. These
financial statements are the responsibility of the
Partnership’s management. Our responsibility is to express
an opinion on these financial statements based on our audits. We
conducted our audits of these statements in accordance with the
standards of the Public Company Accounting Oversight Board
(United States). 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 of financial statements includes examining, on a test
basis, evidence supporting the amounts and disclosures in the
financial statements, assessing the accounting principles used
and significant estimates made by management, and evaluating the
overall financial statement presentation. We believe that our
audits provide a reasonable basis for our opinion.
Internal control over financial reporting
Also, in our opinion, management’s assessment, included in
Management’s Report on Internal Control Over Financial
Reporting appearing under Item 9(A), that the Partnership
maintained effective internal control over financial reporting
as of December 31, 2005 based on criteria established in
Internal Control — Integrated Framework issued by the
Committee of Sponsoring Organizations of the Treadway Commission
(COSO), is fairly stated, in all material respects, based on
those criteria. Furthermore, in our opinion, the Partnership
maintained, in all material respects, effective internal control
over financial reporting as of December 31, 2005, based on
criteria established in Internal Control — Integrated
Framework issued by the COSO. The Partnership’s management
is responsible for maintaining effective internal control over
financial reporting and for its assessment of the effectiveness
of internal control over financial reporting. Our responsibility
is to express opinions on management’s assessment and on
the effectiveness of the Partnership’s internal control
over financial reporting based on our audit. We conducted our
audit of internal control over financial reporting in accordance
with the standards of the Public Company Accounting Oversight
Board (United States). Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether
effective internal control over financial reporting was
maintained in all material respects. An audit of internal
control over financial reporting includes obtaining an
understanding of internal control over financial reporting,
evaluating management’s assessment, testing and evaluating
the design and operating effectiveness of internal control, and
performing such other procedures as we consider necessary in the
circumstances. We believe that our audit provides a reasonable
basis for our opinions.
A company’s internal control over financial reporting is a
process designed to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of
financial statements for external purposes in accordance with
generally accepted accounting principles. A company’s
internal control over financial reporting includes those
policies and procedures that (i) pertain to the maintenance
of records that, in reasonable detail, accurately and fairly
reflect the transactions and dispositions of the assets of the
company; (ii) provide reasonable assurance that
transactions are recorded as necessary to permit preparation
of financial statements in accordance with generally accepted
accounting principles, and that receipts and expenditures of the
company are being made only in accordance with authorizations of
management and directors of the company; and (iii) provide
reasonable assurance regarding prevention or timely detection of
unauthorized acquisition, use, or disposition of the
company’s assets that could have a material effect on the
financial statements.
Because of its inherent limitations, internal control over
financial reporting may not prevent or detect misstatements.
Also, projections of any evaluation of effectiveness to future
periods are subject to the risk that controls may become
inadequate because of changes in conditions, or that the degree
of compliance with the policies or procedures may deteriorate.
MCV was organized to construct, own and operate a
combined-cycle, gas-fired cogeneration facility (the
“Facility”) located in Midland, Michigan. MCV was
formed on January 27, 1987, and the Facility began
commercial operation in 1990.
In 1992, MCV had acquired the outstanding common stock of PVCO
Corp., a previously inactive company. MCV and PVCO Corp. then
entered into a partnership agreement to form MCV Gas
Acquisition General Partnership (“MCV GAGP”) for the
purpose of buying and selling natural gas on the spot market and
other transactions involving natural gas activities. PVCO Corp.
and MCV GAGP were dissolved on January 30, 2004 and
July 2, 2004, respectively, due to inactivity.
The Facility has a net electrical generating capacity of
approximately 1500 MW (including approximately 100 MW
of duct burner generation from five of six duct burners, which
are currently unavailable for operational use) and approximately
1.5 million pounds of process steam capacity per hour. MCV
has entered into three principal energy sales agreements. MCV
has contracted to (i) supply up to 1240 MW of electric
capacity (“Contract Capacity”) to Consumers Energy
Company (“Consumers”) under the Power Purchase
Agreement (“PPA”), for resale to its customers through
2025, (ii) supply electricity and steam to The Dow Chemical
Company (“Dow”) through 2008 and 2015, respectively,
under the Steam and Electric Power Agreement (“SEPA”)
and (iii) supply steam to Dow Corning Corporation
(“DCC”) under the Steam Purchase Agreement
(“SPA”) through 2011 (see Note 8,
“Commitments and Other Agreements — Steam
Purchase Agreement”). From time to time, MCV enters into
other sales agreements for the sale of excess capacity and/or
energy available above MCV’s internal use and obligations
under the PPA, SEPA and SPA. Results of operations are primarily
dependent on successfully operating the Facility at or near
contractual capacity levels and on Consumers’ ability to
perform its obligations under the PPA. Sales pursuant to the PPA
have historically accounted for over 90% of MCV’s revenues.
The PPA permits Consumers, under certain conditions, to reduce
the capacity and energy charges payable to MCV and/or to receive
refunds of capacity and energy charges paid to MCV if the
Michigan Public Service Commission (“MPSC”) does not
permit Consumers to recover from its customers the capacity and
energy charges specified in the PPA (the
“regulatory-out” provision). Until September 15,2007, however, the capacity charge may not be reduced below an
average capacity rate of 3.77 cents per kilowatt-hour for the
available Contract Capacity notwithstanding the
“regulatory-out” provision. Consumers and MCV are
required to support and defend the terms of the PPA.
The Facility is a qualifying cogeneration facility
(“QF”) originally certified by the Federal Energy
Regulatory Commission (“FERC”) under the Public
Utility Regulatory Policies Act of 1978, as amended
(“PURPA”). In order to maintain QF status, certain
operating and efficiency standards must be maintained on a
calendar-year basis and certain ownership limitations must be
met. In the case of a topping-cycle generating plant such as the
Facility, the applicable operating standard requires that the
portion of total energy output that is put to some useful
purpose other than facilitating the production of power (the
“Thermal Percentage”) be at least 5%. In addition, the
Facility must achieve a PURPA efficiency standard (the sum of
the useful power output plus one-half of the useful thermal
energy output, divided by the energy input (the “Efficiency
Percentage”)) of at least 45%. If the Facility maintains a
Thermal Percentage of 15% or higher, the required Efficiency
Percentage is reduced to 42.5%. Since 1990, the Facility has
achieved the applicable Thermal and Efficiency Percentages. For
the twelve months ended December 31, 2005, the Facility
achieved a Thermal Percentage of 23.7% and an Efficiency
Percentage of 47.2%. The loss of QF status could, among other
things, cause MCV to lose its rights under PURPA to sell power
from the Facility to Consumers at Consumers’ “avoided
cost” and subject MCV to additional federal and state
regulatory requirements.
At both the state and federal level, efforts continue to
restructure the electric industry. A significant issue to MCV is
the potential for future regulatory denial of recovery by
Consumers from its customers of above market PPA costs Consumers
pays MCV. At the state level, the MPSC entered a series of
orders from
June 1997 through February 1998 (collectively the
“Restructuring Orders”), mandating that utilities
“wheel” third-party power to the utilities’
customers, thus permitting customers to choose their power
provider. MCV, as well as others, filed an appeal in the
Michigan Court of Appeals to protect against denial of recovery
by Consumers of PPA charges. The Michigan Court of Appeals found
that the Restructuring Orders do not unequivocally disallow such
recovery by Consumers and, therefore, MCV’s issues were not
ripe for appellate review and no actual controversy regarding
recovery of costs could occur until 2008, at the earliest. In
June 2000, the State of Michigan enacted legislation which,
among other things, states that the Restructuring Orders (being
voluntarily implemented by Consumers) are in compliance with the
legislation and enforceable by the MPSC. The legislation
provides that the rights of parties to existing contracts
between utilities (like Consumers) and QFs (like MCV), including
the rights to have the PPA charges recovered from customers of
the utilities, are not abrogated or diminished, and permits
utilities to securitize certain stranded costs, including PPA
charges.
In 1999, the U.S. District Court granted summary judgment
to MCV declaring that the Restructuring Orders are preempted by
federal law to the extent they prohibit Consumers from
recovering from its customers any charge for avoided costs (or
“stranded costs”) to be paid to MCV under PURPA
pursuant to the PPA. In 2001, the United States Court of Appeals
(“Appellate Court”) vacated the U.S. District
Court’s 1999 summary judgment and ordered the case
dismissed based upon a finding that no actual case or
controversy existed for adjudication between the parties. The
Appellate Court determined that the parties’ dispute is
hypothetical at this time and the QFs’ (including MCV)
claims are premised on speculation about how an order might be
interpreted by the MPSC, in the future.
Two significant issues that could affect MCV’s future
financial performance are the price of natural gas and
Consumers’ ability/obligation to pay PPA charges. First,
the Facility is wholly dependent upon natural gas for its fuel
supply and a substantial portion of the Facility’s
operating expenses consist of the costs of natural gas. MCV
recognizes that its existing gas contracts are not sufficient to
satisfy the anticipated gas needs over the term of the PPA and,
as such, no assurance can be given as to the availability or
price of natural gas after the expiration of the existing gas
contracts, since natural gas prices have historically been
volatile and extremely difficult to forecast. In addition, there
is no consensus among forecasters of natural gas prices as to
whether the price or range will increase, decrease or remain at
current levels over any period of time. Since December 2004, the
spot price of natural gas has risen by approximately
$6.50 per million British thermal units
(“MMBtu”), and natural gas futures contract prices (as
of the last trading day of each month) for the period 2006 to
2010 are an average of approximately $3.80 per MMBtu
higher. To the extent that the costs associated with production
of electricity rise faster than the energy charge payments,
MCV’s financial performance will be negatively affected.
The extent of such impact will depend upon the amount of the
average energy charge payable under the PPA, which is based upon
costs incurred at Consumers’ coal-fired plants and upon the
amount of energy scheduled by Consumers for delivery under the
PPA. Even with the RCA and RDA, if gas prices stay at present
levels or increase, the results of operating the Facility would
be adversely affected and could result in MCV failing to meet
its financing obligations. Second, Consumers’
ability/obligation to pay PPA charges may be affected by an MPSC
order denying Consumers’ recovery from ratepayers. This
issue is likely to be addressed in the timeframe of 2007 or
beyond. MCV continues to monitor the current and long-term
trends in natural gas prices, and to participate in MPSC
matters, as appropriate. However, given the unpredictability of
these factors, the overall economic impact upon MCV of changes
in energy charges payable under the PPA and in future fuel costs
under new or existing contracts, cannot accurately be predicted.
MCV management cannot, at this time, predict the future impact
or outcome of these matters. (See Note 3 — Asset
Impairment).
(2)
Summary of Significant Accounting Policies
The preparation of financial statements in conformity with
accounting principles generally accepted in the United States of
America requires management to make estimates and assumptions
that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of
the financial statements and the reported amounts of revenues
and expenses during the reporting period. Actual results could
differ from those estimates. Following is a discussion of
MCV’s significant accounting policies.
Principles of Consolidation and Operating Segments
The consolidated financial statements included the accounts of
MCV and its wholly-owned subsidiaries, PVCO Corp. and MCV GAGP.
Previously, all material transactions and balances among
entities, which comprise MCV, had been eliminated in the
consolidated financial statements. The 2004 dissolution of these
wholly-owned subsidiaries had no impact on the financial
position and results of operations. In addition, under
SFAS No. 131, “Disclosures about Segments of an
Enterprise and Related Information,” MCV has determined
that it has one reportable segment.
Revenue Recognition
MCV recognizes revenue for the sale of variable energy and fixed
energy when delivered. Capacity and other installment revenues
are recognized based on plant availability or other contractual
arrangements.
Fuel Costs
MCV’s fuel costs are those costs associated with securing
natural gas, transportation and storage services necessary to
generate electricity and steam from the Facility. These costs
are recognized in the income statement based upon actual volumes
burned to produce the delivered energy, as well as gains and
losses resulting from
mark-to-market and
natural gas hedging activity. For further disclosure, see
sections,
“Mark-to-Market
Activity” and “Natural Gas Supply Futures and Options
which Qualify for Hedge Accounting,” within this
Note 2. In addition, MCV engages in certain cost mitigation
activities to offset the fixed charges MCV incurs for these
activities. The gains or losses resulting from these activities
have resulted in net gains of approximately $15.8 million,
$6.7 million and $7.7 million for the years ended
2005, 2004 and 2003, respectively. These net gains are reflected
as a component of fuel costs.
In 2004, MCV and Consumers entered into a Resource Conservation
Agreement (“RCA”) and a Reduced Dispatch Agreement
(“RDA”) which, among other things, provides that
Consumers will economically dispatch MCV, based upon the market
price of natural gas, if certain conditions are met. Such
dispatch is expected to reduce electric production from historic
levels, as well as decrease gas consumption by MCV. The RCA
provides that Consumers has a right of first refusal to
purchase, at market prices, the gas conserved under the RCA. The
RCA and RDA provide for the sharing of savings realized by not
having to generate electricity. The RCA and RDA were approved by
the MPSC on January 25, 2005 and MCV and Consumers accepted
the terms of the MPSC order. The RCA and RDA became effective
January 27, 2005. This MPSC order has been appealed by
certain parties. MCV management cannot predict the final outcome
of this appeal. Effective October 23, 2004, MCV and
Consumers entered into an interim dispatch mitigation program
for energy dispatch above 1100 MW up to 1240 MW of
Contract Capacity under the PPA. This program, which was
structured very similarly to the RCA and RDA, was terminated on
January 27, 2005 with the effective date of the RCA/ RDA
which superceded this interim program.
Accounts Receivable
Accounts receivable and accounts receivable-related parties are
recorded at the billed amount and do not bear interest. MCV
evaluates the need for an allowance for doubtful accounts using
MCV’s best estimate of the amount of probable credit
losses. At December 31, 2005 and 2004, no allowance was
provided since typically all receivables are collected within
30 days of each month end.
Inventory
MCV’s inventory of natural gas is stated at the lower of
cost or market, and valued using the
last-in, first-out
(“LIFO”) method. Inventory includes the costs of
purchased gas, variable transportation and storage. The amount
of reserve to reduce inventories from
first-in, first-out
(“FIFO”) basis to the LIFO basis at December 31,2005 and 2004, was $14.7 million and $10.3 million,
respectively. Inventory cost, determined on a FIFO basis,
approximates current replacement cost.
Materials and supplies are stated at the lower of cost or market
using the weighted average cost method. The majority of
MCV’s materials and supplies are considered replacement
parts for MCV’s Facility.
Depreciation
Original plant, equipment and pipeline were valued at cost for
the constructed assets and at the asset transfer price for
purchased and contributed assets, and are depreciated using the
straight-line method over an estimated useful life of
35 years, which is the term of the PPA, except for the hot
gas path components of the GTGs which are primarily being
depreciated over a
25-year life. Plant
construction and additions, since commercial operations in 1990,
are depreciated using the straight-line method over the
remaining life of the plant which currently is 20 years.
Major renewals and replacements, which extend the useful life of
plant and equipment are capitalized, while maintenance and
repairs are expensed when incurred. Major equipment overhauls
are capitalized and amortized to the next equipment overhaul.
Personal property is depreciated using the straight-line method
over an estimated useful life of 5 to 15 years. The cost of
assets and related accumulated depreciation are removed from the
accounts when sold or retired, and any resulting gain or loss
reflected in operating income. (See Note 3 —
Asset Impairment.)
Federal Income Tax
MCV is not subject to Federal or State income taxes. Partnership
earnings are taxed directly to each individual partner.
Statement of Cash Flows
All liquid investments purchased with a maturity of three months
or less at time of purchase are considered to be current cash
equivalents.
Fair Value of Financial Instruments
The carrying amounts of cash and cash equivalents and short-term
investments approximate fair value because of the short maturity
of these instruments. MCV’s short-term investments, which
are made up of investment securities
held-to-maturity, as of
December 31, 2005 and December 31, 2004 have original
maturity dates of approximately one year or less. The unique
nature of the negotiated financing obligation discussed in
Note 7 makes it unnecessary to estimate the fair value of
the Owner Participants’ underlying debt and equity
instruments supporting such financing obligation, since
SFAS No. 107 “Disclosures about Fair Value of
Financial Instruments” does not require fair value
disclosure for the lease obligation.
Accounting for Derivative Instruments and Hedging
Activities
MCV records every derivative instrument on the balance sheet as
either an asset or liability measured at its fair value, except
for those which qualify for the normal purchases and normal
sales exception. SFAS No. 133 requires that changes in
a derivative’s fair value be recognized currently in
earnings unless specific hedge accounting criteria are met.
Special accounting for qualifying hedges in some cases allows a
derivative’s gains and losses to offset related results on
the hedged item in the income statement or permits recognition
of the hedge results in other comprehensive income, and requires
that a company formally document, designate and assess the
effectiveness of transactions that receive hedge accounting.
Electric Sales Agreements
Prior to April 1, 2005, MCV had concluded that its electric
sales agreements did not qualify as derivatives under
SFAS No. 133, due to the lack of an active energy
market in the State of Michigan. With the launch of the Midwest
Independent System Operator (MISO) market effective
April 1, 2005, MCV concluded that an active energy market
may exist and as such, the agreements may qualify as
derivatives. MCV currently
believes that these electric sales agreements qualify under
SFAS No. 133 for the normal purchase and normal sale
exception. Therefore, these contracts continue to not be
recognized at fair value on the balance sheet.
MCV management believes that its long-term natural gas
contracts, except for those which contain volume optionality and
the long-term gas contracts under the RCA/ RDA, qualify under
SFAS No. 133 for the normal purchases and normal sales
exception. Therefore, these contracts are currently not
recognized at fair value on the balance sheet.
Natural Gas Credit Risk
MCV is exposed to the risk of loss from failure of its
counterparties, under its natural gas supply and derivative
contracts, to comply with the terms of the respective contracts,
which includes non-delivery under the natural gas supply
contracts. To protect against this loss, many of MCV’s gas
supply contracts have credit support requirements that can be
triggered by changes in the financial condition of MCV or the
gas supplier, price changes in the forward gas market or the
quantity of gas purchases (see Note 6 — Gas
Supplier Funds on Deposit). MCV management monitors this risk
through the periodic review of the credit and financial
condition of these counterparties and as of December 31,2005, believes the risk of noncompliance to be remote. If any of
these counterparties fails to deliver on their requirements, MCV
does not expect this would have a material impact on its
financial condition or cash flows.
Mark-to-Market
Activity
MCV holds certain long-term gas contracts that do not qualify
for the normal purchases and sales exception, under
SFAS No. 133, because (1) these gas contracts contain
volume optionality and/or (2) are gas contracts associated
with the implementation of the RCA/ RDA in January 2005. With
the implementation of the RCA/ RDA, MCV determined that
additional gas contracts no longer qualified under the normal
purchases and sales exception, because the contracted gas will
not be consumed for electric production. Therefore, both the
contracts with volume optionality and the contracts affected by
the RCA/ RDA are being accounted for as derivatives, which do
not qualify for hedge accounting treatment. In addition, the
financial derivatives associated with the long-term gas
contracts now under the RCA/ RDA that were previously recognized
as cash flow hedges in other comprehensive income were
designated as hedges in the first quarter of 2005 and
marked-to-market
through earnings since the previously hedged long-term gas
contracts no longer qualify for the normal purchase and sales
exception. MCV expects future earnings volatility on all of
these contracts as changes in the
mark-to-market
recognition are recorded in earnings on a quarterly basis.
The cumulative
mark-to-market gain
through December 31, 2005 of $255.9 million is
recorded as a current and non-current derivative asset on the
balance sheet, as described below. These assets will reverse
over the remaining life of these contracts as the unrealized
gains and losses are realized at contract settlement. For the
twelve months ended December 31, 2005 and December 31,2004, MCV recorded in “Fuel costs” a gain of
$200.4 million and a loss of $19.4 million,
respectively, for the net
mark-to-market
adjustment associated with these contracts. In addition, as of
December 31, 2005 and December 31, 2004, MCV recorded
“Derivative assets” in Current Assets in the amount of
$198.5 million and $31.4 million, respectively, and
for the same periods recorded “Derivative assets,
non-current” in Other Assets in the amount of
$57.4 million and $24.3 million, respectively,
representing the
mark-to-market value on
these long-term natural gas contracts and associated financial
positions. MCV has also recorded a net $93.8 million gain
in earnings from recognized gains on the financial positions
associated with the long-term gas contracts.
Natural Gas Supply Futures and Options Which Qualify for
Hedge Accounting
To manage market risks associated with the volatility of natural
gas prices, MCV maintains a gas hedging program. MCV enters into
natural gas futures contracts, option contracts, and over the
counter swap transactions (“OTC swaps”) in order to
hedge against unfavorable changes in the market price of natural
gas
in future months when gas is expected to be needed. These
financial instruments are being utilized principally to secure
anticipated natural gas requirements necessary for projected
electric and steam sales, and to lock in sales prices of natural
gas previously obtained in order to optimize MCV’s existing
gas supply, storage and transportation arrangements.
These financial instruments are derivatives under
SFAS No. 133 and the contracts that are utilized to
secure the anticipated natural gas requirements necessary for
projected electric and steam sales qualify as cash flow hedges
under SFAS No. 133, since they hedge the price risk
associated with the cost of natural gas. MCV also engages in
cost mitigation activities to offset the fixed charges MCV
incurs in operating the Facility. These cost mitigation
activities include the use of futures and options contracts to
purchase and/or sell natural gas to maximize the use of the
transportation and storage contracts when it is determined that
they will not be needed for Facility operation. Although these
cost mitigation activities do serve to offset the fixed monthly
charges, these cost mitigation activities are not considered a
normal course of business for MCV and do not qualify as hedges
under SFAS No. 133. Therefore, the resulting
mark-to-market gains
and losses from cost mitigation activities are flowed through
MCV’s earnings.
For the twelve months ended December 31, 2005, MCV has
recognized in other comprehensive income, an unrealized gain of
$109.1 million on the gas futures contracts and OTC swaps
(including a $29.3 million loss of dedesignated cash flow
hedges), which are hedges of forecasted purchases for plant use
of market priced gas. This resulted in a net $174.8 million
gain in other comprehensive income (loss) as of
December 31, 2005. This balance represents natural gas
futures, options and OTC swaps with maturities ranging from
January 2006 to December 2009, of which $45.9 million of
this gain is expected to be reclassified into earnings within
the next twelve months. MCV also has recorded, as of
December 31, 2005, a $42.6 million “Derivative
assets,” in Current Assets and for the same period a
$128.9 million “Derivative asset —
non-current” in Other Assets, representing the
mark-to-market gain on
natural gas futures for anticipated projected electric and steam
sales accounted for as hedges. In addition, for the twelve
months ended December 31, 2005, MCV has recorded a net
$24.7 million gain in earnings from hedging activities
related to MCV natural gas requirements for Facility operations
and a net $2.7 million loss in earnings from hedges related
to cost mitigation activities.
For the twelve months ended December 31, 2004, MCV
recognized an unrealized $34.5 million increase in other
comprehensive income on the futures contracts, which are hedges
of forecasted purchases for plant use of market priced gas,
which resulted in a $65.8 million gain balance in other
comprehensive income as of December 31, 2004. As of
December 31, 2004, MCV had recorded a $63.6 million
current derivative asset in “Derivative assets.” For
the twelve months ended December 31, 2004, MCV had recorded
a net $36.5 million gain in earnings from hedging
activities related to MCV natural gas requirements for Facility
operations and a net $1.8 million gain in earnings from
cost mitigation activities.
Accumulated Other Comprehensive Income
Accumulated other comprehensive income reflects the following
balances at December 31 (thousands):
2005
2004
2003
Beginning Accumulated Other Comprehensive Income
$
65,774
$
31,255
$
26,280
Unrealized gain on hedging activities
163,060
71,548
39,609
Reclassification adjustments recognized in net income
(24,690
)
(37,029
)
(34,634
)
Dedesignated cash flow hedges
(29,300
)
—
—
Ending Accumulated Other Comprehensive Income
$
174,844
$
65,774
$
31,255
New Accounting Standard
In March 2005, the FASB issued FAS Interpretation No. 47,
“Accounting for Conditional Asset Retirement
Obligations.” This interpretation clarified the term
“conditional asset retirement obligation” as used in
SFAS No. 143. The term refers to a legal obligation to
perform an asset retirement activity in which the timing and
(or) method of settlement are conditional on a future
event. This interpretation is effective for
MCV on December 31, 2005. MCV has reviewed its current
commitments and key contracts to operate the MCV Facility. Based
on this review, MCV finds no material conditional asset
retirement obligations that need to be accrued upon the adoption
of this interpretation.
(3)
Asset Impairment
SFAS No. 144 “Accounting for the Impairment or
Disposal of Long-Lived Assets” requires that MCV review, on
a forward-looking basis, the recoverability of its long-lived
assets (such as property, plant and equipment) whenever events
or circumstances indicate that the carrying amount of the
long-lived assets may not be recoverable. Recoverability of
“assets to be held and used” is measured by a
comparison of the carrying amount of the assets to the estimated
undiscounted future cash flows expected to be generated by the
assets, over their remaining useful life. If the carrying amount
of the assets exceeds the estimated undiscounted future cash
flows expected to be generated, an impairment charge is
recognized in the amount by which the carrying amount of the
long-lived assets exceed their fair value.
The single largest cost to MCV of producing electricity is the
cost of natural gas. Natural gas prices have increased
substantially in recent months. As a result, MCV has
continuously monitored trends in and forecasts of natural gas
prices and their estimated effect on the economics of operating
the Facility. In April 2005, MCV performed its usual semi-annual
economic analysis using then current market prices and apparent
trends in and forecasts of natural gas prices; the results of
this update of its economic analysis did not indicate an
impairment of MCV’s long-lived assets.
After the April 2005 economic analysis was performed, natural
gas prices rose dramatically as a result of events and
circumstances, which created tight supply and higher market
demand for natural gas. For example, hurricane disruptions in
the supply of gas in the third quarter of 2005 drastically
reduced Gulf Coast natural gas production and distribution,
causing a further upward spike in NYMEX forward natural gas
prices, as well as third-parties’ forecasts for natural gas
prices. As a result, the MCV Partnership determined that
updating its impairment analysis, considering revised forward
natural gas price assumptions and third parties’ forecasts
of natural gas prices, among others circumstances was
appropriate to evaluate the recoverability of the asset group.
The asset group under SFAS No. 144 represents all
assets and liabilities that impact the lowest level of
identifiable cash flows to be generated to recover the
MCV’s long-lived assets. For the MCV, the asset group
included net property, plant and equipment and the fair value of
derivative assets, as discussed in Note 2 —
“Summary of Significant Accounting Policies”, both of
which impact management’s estimate of the net cash flows to
be generated by the MCV to recover these long-lived assets.
Based on MCV’s 2005 third quarter updated impairment
analysis, MCV concluded that the carrying value of the
MCV’s asset group exceeded cash flows that would be
generated by the Facility on an undiscounted basis and
therefore, under SFAS No. 144, an impairment
adjustment was required to reduce the carrying value to the
estimated fair value. The fair value of the asset group was
determined by discounting a set of probability-weighted streams
of future cash flows at a 4.3% risk free interest rate. This
impairment adjustment was recorded in the third quarter of 2005
for $1,159.0 million under “Asset impairment
loss” in MCV’s Statement of Operations. MCV will
continue to monitor the current and long-term trends in natural
gas prices and other factors, as appropriate. Since the 2005
third quarter impairment analysis, gas prices have decreased,
however, should natural gas prices remain at present levels or
increase, the results of operating the Facility would be
adversely affected in the long term and could result in MCV
failing to meet its financial obligations under the sale and
leaseback transactions and other contracts.
Non-current restricted investment securities
held-to-maturity have
carrying amounts that approximate fair value because of the
short maturity of these instruments and consist of the following
at December 31 (in thousands):
2005
2004
Funds restricted for rental payments pursuant to the Overall
Lease Transaction
$
90,111
$
138,150
Funds restricted for management non-qualified plans
804
1,260
Total
$
90,915
$
139,410
(5)
Accounts Payable and Accrued Liabilities
Accounts payable and accrued liabilities consist of the
following at December 31 (in thousands):
2005
2004
Accounts payable — related parties
$
16,651
$
12,772
Accounts payable — non-related
Trade creditors
$
100,956
$
53,476
Property and single business taxes
11,088
11,833
Other
6,619
4,612
Total accounts payable — non-related
$
118,663
$
69,921
(6)
Gas Supplier Funds on Deposit
Pursuant to individual gas contract terms with counterparties,
including margin accounts with futures and option brokers,
deposit amounts or letters of credit may be required by one
party to the other based upon the net amount of exposure. The
net amount of exposure will vary with changes in market prices,
credit provisions and various other factors. Collateral paid or
received will be posted by one party to the other based on the
net amount of the exposure. Interest is earned on funds on
deposit. MCV has paid or received the following as of
December 31 (in thousands):
2005
2004
Cash or letters of credit supplied by MCV to others:
Cash paid, recorded in “Broker margin accounts and prepaid
expenses”
$
16,520
$
8,670
Letters of credit provided to others
2,430
2,430
Cash or letters of credit supplied to MCV by others:
Cash received, recorded in “Gas supplier funds on
deposit”
148,650
19,613
Cash received by El Paso (a related party), recorded in
“Gas supplier funds on deposit — related
parties”
44,353
—
Letters of credit provided to MCV from non-related parties
21,700
24,600
Letters of credit provided to MCV by El Paso (a related
party)
385,700
184,000
(7)
Long-Term Debt
Long-term debt consists of the following at December 31 (in
thousands):
2005
2004
Financing obligation, maturing through 2015, payable in
semi-annual installments of principal and interest,
collateralized by property, plant and equipment
In June 1990, MCV obtained permanent financing for the Facility
by entering into sale and leaseback agreements (“Overall
Lease Transaction”) with a lessor group, related to
substantially all of MCV’s fixed assets. Proceeds of the
financing were used to retire borrowings outstanding under
existing loan commitments, make a capital distribution to the
Partners and retire a portion of notes issued by MCV to MEC
Development Corporation (“MDC”) in connection with the
transfer of certain assets by MDC to MCV. In accordance with
SFAS No. 98, “Accounting For Leases,” the
sale and leaseback transaction has been accounted for as a
financing arrangement.
The financing obligation utilizes the effective interest rate
method, which is based on the minimum lease payments required
through the end of the basic lease term of 2015 and
management’s estimate of additional anticipated obligations
after the end of the basic lease term. The effective interest
rate during the remainder of the basic lease term is
approximately 9.4%.
Under the terms of the Overall Lease Transaction, MCV sold
undivided interests in all of the fixed assets of the Facility
for approximately $2.3 billion, to five separate owner
trusts (“Owner Trusts”) established for the benefit of
certain institutional investors (“Owner
Participants”). U.S. Bank National Association serves
as owner trustee (“Owner Trustee”) under each of the
Owner Trusts, and leases undivided interests in the Facility on
behalf of the Owner Trusts to MCV for an initial term of
25 years. CMS Midland Holdings Company (“CMS
Holdings”), currently a wholly owned subsidiary of
Consumers, acquired a 35% indirect equity interest in the
Facility through its purchase of an interest in one of the Owner
Trusts.
The Overall Lease Transaction requires MCV to achieve certain
rent coverage ratios and other financial tests prior to a
distribution to the Partners. Generally, these financial tests
become more restrictive with the passage of time. Further, MCV
is restricted to making permitted investments and incurring
permitted indebtedness as specified in the Overall Lease
Transaction. The Overall Lease Transaction also requires filing
of certain periodic operating and financial reports,
notification to the lessors of events constituting a material
adverse change, significant litigation or governmental
investigation, and change in status as a qualifying facility
under FERC proceedings or court decisions, among others.
Notification and approval is required for plant modification,
new business activities, and other significant changes, as
defined. In addition, MCV has agreed to indemnify various
parties to the sale and leaseback transaction against any
expenses or environmental claims asserted, or certain federal
and state taxes imposed on the Facility, as defined in the
Overall Lease Transaction.
Under the terms of the Overall Lease Transaction and refinancing
of the tax-exempt bonds, approximately $25.0 million of
transaction costs were a liability of MCV and have been recorded
as a deferred cost. Financing costs incurred with the issuance
of debt are deferred and amortized using the interest method
over the remaining portion of the
25-year lease term.
Deferred financing costs of approximately $1.1 million,
$1.2 million and $1.4 million were amortized in the
years 2005, 2004 and 2003, respectively.
Interest and fees incurred related to long-term debt
arrangements during 2005, 2004 and 2003 were $95.5 million,
$103.4 million and $111.9 million, respectively.
Interest and fees paid during 2005, 2004 and 2003 were
$98.2 million, $108.6 million and $115.4 million,
respectively.
Minimum payments due under these long-term debt arrangements
over the next five years are (in thousands):
MCV has also entered into a working capital line (“Working
Capital Facility”), which expires August 26, 2006.
Under the terms of the existing agreement, MCV can borrow up to
the $50.0 million commitment, in the form of short-term
borrowings or letters of credit collateralized by MCV’s
natural gas inventory and earned receivables. At any given time,
borrowings and letters of credit are limited by the amount of
the borrowing base, defined as 90% of earned receivables and 50%
of natural gas inventory, capped at $15 million. MCV did
not utilize the Working Capital Facility during the year 2005,
except for letters of credit associated with normal business
practices. At December 31, 2005, MCV had $47.6 million
available under its Working Capital Facility. As of
December 31, 2005, MCV’s borrowing base was capped at
the maximum amount available of $50.0 million and MCV had
outstanding letters of credit in the amount of
$2.4 million. MCV believes that amounts available to it
under the Working Capital Facility along with available cash
reserves will be sufficient to meet any working capital
shortfalls that might occur in the near term.
Intercreditor Agreement
MCV has also entered into an Intercreditor Agreement with the
Owner Trustee, Working Capital Lender, U.S. Bank National
Association as Collateral Agent (“Collateral Agent”)
and the Senior and Subordinated Indenture Trustees. Under the
terms of this agreement, MCV is required to deposit all revenues
derived from the operation of the Facility with the Collateral
Agent for purposes of paying operating expenses and rent. In
addition, these funds are required to pay construction
modification costs and to secure future rent payments. As of
December 31, 2005, MCV has deposited $90.1 million
into the reserve account. The reserve account is to be
maintained at not less than $40 million nor more than
$137 million (or debt portion of next succeeding basic rent
payment, whichever is greater). Excess funds in the reserve
account are periodically transferred to MCV. This agreement also
contains provisions governing the distribution of revenues and
rents due under the Overall Lease Transaction, and establishes
the priority of payment among the Owner Trusts, creditors of the
Owner Trusts, creditors of MCV and the Partnership.
(8)
COMMITMENTS AND OTHER AGREEMENTS
MCV has entered into numerous commitments and other agreements
related to the Facility. Principal agreements are summarized as
follows:
Power Purchase Agreement
MCV and Consumers have executed the PPA for the sale to
Consumers of a minimum amount of electricity, subject to the
capacity requirements of Dow and any other permissible
electricity purchasers. Consumers has the right to terminate
and/or withhold payment under the PPA if the Facility fails to
achieve certain operating levels or if MCV fails to provide
adequate fuel assurances. In the event of early termination of
the PPA, MCV would have a maximum liability of approximately
$270 million if the PPA were terminated in the
12th through 24th years. The term of this agreement is
35 years from the commercial operation date and
year-to-year thereafter.
Steam and Electric Power Agreement
MCV and Dow executed the SEPA for the sale to Dow of certain
minimum amounts of steam and electricity for Dow’s
facilities.
If the SEPA is terminated, and Consumers does not fulfill
MCV’s commitments as provided in the Backup Steam and
Electric Power Agreement, MCV will be required to pay Dow a
termination fee, calculated at that time, ranging from a minimum
of $60 million to a maximum of $85 million. This
agreement provides for the sale to Dow of steam and electricity
produced by the Facility for terms of 25 years and
15 years, respectively, commencing on the commercial
operation date and
year-to-year thereafter.
MCV and DCC executed the SPA for the sale to DCC of certain
minimum amounts of steam for use at the DCC Midland site. Steam
sales under the SPA commenced in July 1996. Termination of this
agreement, prior to expiration, requires the terminating party
to pay to the other party a percentage of future revenues, which
would have been realized had the initial term of 15 years
been fulfilled. The percentage of future revenues payable is 50%
if termination occurs prior to the fifth anniversary of the
commercial operation date and
331/3%
if termination occurs after the fifth anniversary of this
agreement. The term of this agreement is 15 years from the
commercial operation date of steam deliveries under the contract
and year-to-year
thereafter.
In September 2005, MCV gave notice to DCC of its intent to
terminate the SPA effective September 19, 2006, as provided
for in the SPA. MCV informed DCC that it was willing to consider
entering into another agreement with DCC at market-based pricing
of steam. MCV has not been able to reach a new agreement with
DCC at market-based pricing. The termination of the SPA is
conditioned upon MCV making a payment to DCC 30 days prior
to the effective date of the termination. The termination
payment is for a certain portion of future revenues. The
termination payment, which was accrued in December 2005 to
“Administrative, Selling and General,” is estimated to
be $5.1 million. The contract termination is not expected
to have any negative impact on MCV’s PURPA QF certification
(i.e., MCV’s operating and efficiency requirements under
PURPA will be met without steam sales to DCC).
Gas Supply Agreements
MCV has entered into gas purchase agreements with various
producers for the supply of natural gas. The current contracted
volume totals 238,665 MMBtu per day annual average for
2006. As of January 1, 2006, gas contracts with
U.S. suppliers provide for the purchase of
176,010 MMBtu per day while gas contracts with Canadian
suppliers provide for the purchase of 62,655 MMBtu per day.
Some of these contracts require MCV to pay for a minimum amount
of natural gas per year, whether or not taken. The estimated
minimum commitments under these contracts based on current
long-term prices for gas for the years 2006 through 2010 are
$569.7 million, $683.8 million, $548.0 million,
$478.5 million and $380.4 million, respectively. A
portion of these payments may be utilized in future years to
offset the cost of quantities of natural gas taken above the
minimum amounts.
Gas Transportation Agreements
MCV has entered into firm natural gas transportation agreements
with various pipeline companies. These agreements require MCV to
pay certain reservation charges in order to reserve the
transportation capacity. MCV incurred reservation charges in
2005, 2004 and 2003 of $34.5 million, $35.5 million
and $34.8 million, respectively. The estimated minimum
reservation charges required under these agreements for each of
the years 2006 through 2010 are $30.5 million,
$22.4 million, $22.4 million, $22.3 million and
$21.7 million, respectively. These projections are based on
current commitments.
Gas Turbine Service Agreements
MCV has a maintenance service and parts agreement with General
Electric International, Inc. (“GEII”), which commenced
July 1, 2004 (“GEII Agreement”). GEII is
providing maintenance services and hot gas path parts for
MCV’s twelve GTGs, including an initial inventory of spare
parts for the GTGs, providing qualified service personnel and
supporting staff to assist MCV to perform scheduled inspections
on the GTGs and to repair the GTGs at MCV’s request. The
GEII Agreement will cover four rounds of major GTG inspections,
which are expected to be completed by the year 2015. MCV is to
make monthly payments over the life of the contract totaling
approximately $207 million (subject to escalations based on
defined indices). The GEII Agreement can be terminated by either
party for cause or convenience. Should termination for
convenience occur, a buy out amount will be paid by the
terminating party with payments ranging from approximately
$19.0 million to $.9 million, based upon the number of
operating hours utilized since commencement of the GEII
Agreement.
MCV entered into a nine year Steam Turbine Maintenance Agreement
with General Electric Company effective January 1, 1995,
which is designed to improve unit reliability, increase
availability and minimize unanticipated maintenance costs. In
addition, this contract includes performance incentives and
penalties, which are based on the length of each scheduled
outage and the number of forced outages during a calendar year.
Effective February 1, 2004, MCV and GE amended this
contract to extend its term through August 31, 2007. MCV
will continue making monthly payments over the life of the
contract, which will total $22.3 million (subject to
escalation based on defined indices). The parties have certain
termination rights without incurring penalties or damages for
such termination. Upon termination, MCV is only liable for
payment of services rendered or parts provided prior to
termination.
Site Lease
In December 1987, MCV leased the land on which the Facility is
located from Consumers (“Site Lease”). MCV and
Consumers amended and restated the Site Lease to reflect the
creation of five separate undivided interests in the Site Lease
as of June 1, 1990. Pursuant to the Overall Lease
Transaction, MCV assigned these undivided interests in the Site
Lease to the Owner Trustees, which in turn subleased the
undivided interests back to MCV under five separate site
subleases.
The Site Lease is for a term which commenced on
December 29, 1987, and ends on December 31, 2035,
including two renewal options of five years each. The rental
under the Site Lease is $.6 million per annum, including
the two five-year renewal terms.
(9)
Contingencies
Property Taxes
In 1997, MCV filed a property tax appeal against the City of
Midland at the Michigan Tax Tribunal (“MTT”)
contesting MCV’s 1997 property taxes. Subsequently, MCV
filed appeals contesting its property taxes for tax years
1998 — 2005 at the Michigan Tax Tribunal. A trial was
held for tax years 1997 — 2000. The appeals for tax
years 2001-2005 are being held in abeyance. In 2004, the
Michigan Tax Tribunal issued its decision in MCV’s tax
appeal against the City of Midland for tax years 1997-2000 (the
“MTT Decision”). MCV management has estimated that the
MTT Decision and the impact of Michigan law (Proposal A,
which caps taxable value increases) would result in a refund to
MCV for the tax years 1997 — 2005 of at least
$83.3 million, inclusive of interest as of
December 31, 2005. The MTT Decision has been appealed to
the Michigan Appellate Court by the City of Midland. MCV has
filed a cross-appeal at the Michigan Appellate Court. On
February 21, 2006, the Michigan Appellate Court primarily
upheld the MTT Decision but remanded the case to the MTT for the
limited purpose of clarification of whether the MTT erroneously
included tax-exempt pollution-control equipment or property
located outside the City of Midland in its concluded true cash
value. If the MTT determines there was such double taxation, MCV
will be entitled to a greater refund. The case is subject to
further appeal. MCV management cannot predict the outcome of
these legal proceedings. MCV has not recognized any of the above
stated estimated refunds in earnings at this time.
NOx
Allowances
The United States Environmental Protection Agency (“US
EPA”) has approved the State of Michigan’s —
State Implementation Plan (“SIP”), which includes an
interstate NOx budget and allowance trading program administered
by the US EPA beginning in 2004. Each NOx allowance permits a
source to emit one ton of NOx during the seasonal control
period, which is from May 1 through September 30. NOx
allowances may be bought or sold and unused allowances may be
“banked” for future use, with certain limitations. MCV
has excess NOx allowances to sell under this program. Consumers
has given notice to MCV that it believes the ownership of the
NOx allowances under this program, which have not been
incorporated into the RCA/ RDA program, belong, at least in
part, to Consumers. MCV has initiated the dispute resolution
process pursuant to the PPA to resolve this issue and the
parties have entered into a standstill agreement deferring the
resolution of this dispute. However, either party may terminate
the standstill agreement at any
time and reinstate the PPA’s dispute resolution provisions.
MCV management cannot predict the outcome of this issue. As of
December 31, 2005, MCV has recorded in “Accounts
payable and accrued liabilities”, approximately
$4.7 million for NOx allowances sold in 2005 and 2004,
which are not part of the RCA/ RDA and are pending resolution of
ownership rights.
Environmental Issues
On July 12, 2004, the Michigan Department of
Environmental Quality (“DEQ”), Air Control Division,
issued MCV a “Letter of Violation” asserting that MCV
violated its Air Use Permit to Install
No. 209-02
(“PTI”) by exceeding the carbon monoxide emission
limit on the Unit 14 GTG duct burner and failing to
maintain certain records in the required format. MCV declared
five of the six duct burners as unavailable for operational use
(which reduces the generation capability of the Facility by
approximately 100 MW) and took other corrective action to
address the DEQ’s assertions. The one available duct burner
was tested in April 2005 and its emissions met permitted levels
due to the configuration of that particular unit. MCV disagrees
with certain of the DEQ’s assertions. MCV filed a response
in July 2004 to address the Letter of Violation. On
December 13, 2004, the DEQ informed MCV that it was
pursuing an escalated enforcement action against MCV regarding
the alleged violations of MCV’s PTI. The DEQ also stated
that the alleged violations are deemed federally significant
and, as such, placed MCV on the US EPA’s High Priority
Violators List (“HPVL”). The DEQ and MCV are pursuing
voluntary settlement of this matter, which will satisfy state
and federal requirements and remove MCV from the HPVL. Any such
settlement may involve a fine, but the DEQ has not, at this
time, stated what, if any, fine they will seek to impose. MCV
has accrued $50,000 for this issue. At this time, MCV management
cannot predict the financial impact or outcome of this issue.
On July 13, 2004, the DEQ, Water Division, issued MCV a
“Notice Letter” asserting MCV violated its National
Pollutant Discharge Elimination System Permit by discharging
heated process waste water into the storm water system, failing
to document inspections, and other minor infractions
(“alleged NPDES violations”). In August 2004, MCV
filed a response to the DEQ letter covering the remediation for
each of the DEQ’s alleged violations. On
October 17, 2005, the DEQ, Water Bureau, issued to MCV
a “Compliance Inspection” report, which listed several
minor violations and concerns that needed to be addressed by
MCV. This report was issued in connection with an inspection of
the Facility in September 2005, which was conducted for
compliance and review of the Storm Water Pollution Prevention
Plans (“SWPPP”). MCV submitted its updated SWPPP on
December 1, 2005. MCV management believes it has
resolved all issues associated with the Notice Letter and
Compliance Inspection and does not expect any further DEQ
actions on these matters.
(10)
Retirement Benefits
Postretirement Health Care Plans
In 1992, MCV established defined cost postretirement health care
plans (“Plans”) that cover all full-time employees,
excluding key management. The Plans provide health care credits,
which can be utilized to purchase medical plan coverage and pay
qualified health care expenses. Participants become eligible for
the benefits if they retire on or after the attainment of
age 65 or upon a qualified disability retirement, or if
they have 10 or more years of service and retire at age 55
or older. The Plans granted retroactive benefits for all
employees hired prior to January 1, 1992. This prior
service cost has been amortized to expense over a five-year
period. MCV annually funds the current year service and interest
cost as well as amortization of prior service cost to both
qualified and non-qualified trusts. The MCV accounts for retiree
medical benefits in accordance with SFAS 106,
“Employers Accounting for Postretirement Benefits Other
Than Pensions.” This standard required the full accrual of
such costs during the years that the employee renders service to
the MCV until the date of full eligibility. The accumulated
benefit obligation of the Plans were $5.4 million at
December 31, 2005 and $4.9 million at
December 31, 2004. The measurement date of these Plans
was December 31, 2005.
The Medicare Prescription Drug, Improvement and Modernization
Act of 2003 (the “Act”) was signed into law in
December 2003. The Act expanded Medicare to include, for the
first time, coverage for
prescription drugs. The final
SFAS No. 106-2
was issued in second quarter 2004 and supersedes
SFAS No. 106-1,
which MCV adopted during this same period. The adoption of this
standard had no impact to MCV’s financial position because
MCV does not consider its Plans to be actuarially equivalent.
The Plans benefits provided to eligible participants are not
annual or on-going in nature, but are a readily exhaustible,
lump-sum amount available for use at the discretion of the
participant.
The following table reconciles the change in the Plans’
benefit obligation and change in Plan assets as reflected on the
balance sheet as of December 31 (in thousands):
2005
2004
Change in benefit obligation:
Benefit obligation at beginning of year
$
4,972.6
$
3,276.0
Service cost
311.5
232.1
Interest cost
230.1
174.8
Actuarial gain
9.2
1,298.0
Benefits paid during year
(108.0
)
(8.3
)
Benefit obligation at end of year
5,415.4
4,972.6
Change in Plan assets:
Fair value of Plan assets at beginning of year
3,317.7
2,826.8
Actual return on Plan assets
246.2
292.7
Employer contribution
426.3
206.5
Benefits paid during year
(108.0
)
(8.3
)
Fair value of Plan assets at end of year
3,882.2
3,317.7
Unfunded status
1,533.2
1,654.9
Unrecognized prior service cost
(141.6
)
(155.9
)
Unrecognized net loss
(1,378.4
)
(1,499.0
)
Accrued benefit cost
$
13.2
$
—
Net periodic postretirement health care cost for years ending
December 31, included the following components (in
thousands):
2005
2004
2003
Components of net periodic benefit cost:
Service cost
$
311.5
$
232.1
$
212.5
Interest cost
230.1
174.8
178.2
Expected return on Plan assets
(187.7
)
(216.1
)
(163.7
)
Amortization of unrecognized net loss
85.6
15.7
30.5
Net periodic benefit cost
$
439.5
$
206.5
$
257.5
Assumed health care cost trend rates have a significant effect
on the amounts reported for the health care plans. A
one-percentage-point change in assumed health care cost trend
rates would have the following effects (in thousands):
1-Percentage-
1-Percentage
Point Increase
Point Decrease
Effect on total of service and interest cost components
Assumptions used in accounting for the Post-Retirement Health
Care Plan were as follows:
2005
2004
2003
Discount rate
5.50%
5.75%
6.00%
Long-term rate of return on Plan assets
8.00%
8.00%
8.00%
Inflation benefit amount
1999 through 2005
0.00%
0.00%
0.00%
2006 and later years
5.00%
5.00%
4.00%
The long-term rate of return on Plan assets is established based
on MCV’s expectations of asset returns for the investment
mix in its Plan (with some reliance on historical asset returns
for the Plans). The expected returns for various asset
categories are blended to derive one long-term assumption.
Plan Assets. Citizens Bank has been appointed as trustee
(“Trustee”) of the Plan. The Trustee serves as
investment consultant, with the responsibility of providing
financial information and general guidance to the MCV Benefits
Committee. The Trustee shall invest the assets of the Plan in
the separate investment options in accordance with instructions
communicated to the Trustee from time to time by the MCV Benefit
Committee. The MCV Benefits Committee has the fiduciary and
investment selection responsibility for the Plan. The MCV
Benefits Committee consists of MCV Officers (excluding the
President and Chief Executive Officer).
The MCV has a target allocation of 80% equities and 20% debt
instruments. These investments emphasis total growth return,
with a moderate risk level. The MCV Benefits Committee reviews
the performance of the Plan investments quarterly, based on a
long-term investment horizon and applicable benchmarks, with
rebalancing of the investment portfolio, at the discretion of
the MCV Benefits Committee.
MCV’s Plan’s weighted-average asset allocations, by
asset category are as follows as of December 31:
Asset Category:
2005
2004
Cash and cash equivalents
8
%
1
%
Fixed income
16
%
19
%
Equity securities
76
%
80
%
Total
100
%
100
%
Contributions. MCV expects to contribute approximately
$.4 million to the Plan in 2006.
Retirement and Savings Plans
MCV sponsors a defined contribution retirement plan covering all
employees. Under the terms of the plan, MCV makes contributions
to the plan of either five or ten percent of an employee’s
eligible annual compensation dependent upon the employee’s
age. MCV also sponsors a 401(k) savings plan for employees.
Contributions and costs for this plan are based on matching an
employee’s savings up to a maximum level. In 2005, 2004 and
2003, MCV contributed $1.2 million, $1.4 million and
$1.3 million, respectively under these plans.
MCV has also maintained an Employee Excess Benefit Plan for
contributions to the defined contribution and 401(k) plans,
which exceed the annual federal limits. Due to a change in law,
the Internal Revenue Service established a special election
period for employees to elect distribution of funds from
accounts such as this. During the fourth quarter of 2005, all
MCV participants in the Employee Excess Benefit Plan elected to
take distribution of their funds, which totaled
$.2 million. Upon the withdrawal of all funds from the
plan, MCV terminated the Employee Excess Benefit Plan.
Supplemental Retirement Benefits
MCV provides supplemental retirement, postretirement health care
and excess benefit plans for key management. These plans are not
qualified plans under the Internal Revenue Code; therefore,
earnings of the trusts maintained by MCV to fund these plans are
taxable to the Partners and trust assets are included in the
assets of MCV. During the fourth quarter of 2005, some MCV
officers, to the extent they were vested in such plans, elected
distributions totaling $.6 million from these supplemental
retirement plans.
(11) PARTNERS’ EQUITY AND RELATED PARTY
TRANSACTIONS
The following table summarizes the nature and amount of each of
MCV’s Partner’s equity interest, interest in profits
and losses of MCV at December 31, 2005, and the nature and
amount of related party transactions or agreements that existed
with the Partners or affiliates as of December 31, 2005,
2004 and 2003, and for each of the twelve month periods ended
December 31 (in thousands).
Each exhibit identified below is filed as part of this report.
Exhibits filed with this Report are designated by “*”.
All exhibits not so designated are incorporated herein by
reference to a prior filing as indicated. Exhibits designated
with a “+” constitute a management contract or
compensatory plan or arrangement.
2
.A
Merger Agreement, dated as of December 15, 2003, by and among
Enterprise Products Partners L.P., Enterprise Products GP, LLC,
Enterprise Products Management LLC, GulfTerra Energy Partners,
L.P. and GulfTerra Energy Company, L.L.C. (including the form of
Assumption Agreement to be entered into in connection with the
merger, attached as an exhibit thereto) (Exhibit 2.1 to our Form
8-K filed December 15, 2003)
2
.B
Parent Company Agreement, dated as of December 15, 2003, by
and among Enterprise Products Partners L.P., Enterprise Products
GP, LLC, Enterprise Products GTM, LLC, El Paso Corporation,
Sabine River Investors I, L.L.C., Sabine River Investors II,
L.L.C., El Paso EPN Investments, L.L.C. and GulfTerra GP
Holding Company (including the form of Second Amended and
Restated Limited Liability Company Agreement of Enterprise
Products GP, LLC, to be entered into in connection with the
merger, attached as an exhibit thereto) (Exhibit 2.2 to our
Form 8-K filed December 15, 2003);
Amendment No. 1 to Parent Company Agreement, dated as
of December 15, 2003, by and among Enterprise Products
Partners L.P., Enterprise Products GP, LLC, Enterprise Products
GTM, LLC, El Paso Corporation, Sabine River Investors I,
L.L.C., Sabine River Investors II, L.L.C., El Paso EPN
Investments, L.L.C. and GulfTerra GP Holding Company, dated as
of April 19, 2004 (including the forms of Second
Amended and Restated Limited Liability Company Agreement of
Enterprise Products GP, LLC, Exchange and Registration Rights
Agreement and Performance Guaranty, to be entered into by the
parties named therein in connection with the merger of
Enterprise and GulfTerra, attached as Exhibits 1, 2
and 3, respectively, thereto) (Exhibit 2.1 to our Form
8-K filed April 21, 2004); Second Amended and Restated
Limited Liability Company Agreement of GulfTerra Energy Company,
L.L.C., adopted by GulfTerra GP Holding Company, a Delaware
corporation, and Enterprise Products GTM, LLC, a Delaware
limited liability company, as of December 15, 2003
(Exhibit 2.3 to our Form 8-K filed December 15, 2003);
Purchase and Sale Agreement (Gas Plants), dated as of
December 15, 2003, by and between El Paso Corporation, El
Paso Field Services Management, Inc., El Paso Transmission,
L.L.C., El Paso Field Services Holding Company and Enterprise
Products Operating L.P. (Exhibit 2.4 to our Form 8-K filed
December 15, 2003); Purchase and Sale Agreement, dated as
of January 14, 2005, by and among Enterprise GP Holdings,
L.P., Sabine River Investors I, L.L.C., Sabine River Investors
II, L.L.C., El Paso Corporation and GulfTerra GP Holding Company
(Exhibit 2.B.1 to our 2004 Form 10-K)
Indenture dated as of May 10, 1999, by and between El Paso
and HSBC Bank USA, National Association (as
successor-in-interest to JPMorgan Chase Bank (formerly The Chase
Manhattan Bank)), as Trustee (Exhibit 4.A to our 2004 Form
10-K)
4
.B
Certificate of Designations of 4.99% Convertible Perpetual
Preferred Stock (included in Exhibit 3.A to our Current
Report on Form 8-K filed May 31, 2005)
Registration Rights Agreement, dated April 15, 2005, by and
among El Paso Corporation and the Initial Purchasers party
thereto (Exhibit 4.A to our Current Report on Form 8-K
filed April 15, 2005)
4
.D
Registration Rights Agreement dated as of December 28, 2005
among El Paso Corporation, Goldman Sachs & Co. and
Citigroup Global Markets Inc. (Exhibit 10.A to our Current
Report on Form 8-K filed January 4, 2006)
4
.E
Tenth Supplemental Indenture dated as of December 28, 2005
between El Paso Corporation and HSBC Bank USA, National
Association, as trustee. (Exhibit 4.A to our Current Report
on Form 8-K filed January 4, 2006)
10
.A
Amended and Restated Credit Agreement dated as of
November 23, 2004, among El Paso Corporation, ANR Pipeline
Company, Colorado Interstate Gas Company, El Paso Natural Gas
Company, Tennessee Gas Pipeline Company, the several banks and
other financial institutions from time to time parties thereto
and JPMorgan Chase Bank, N.A., as administrative agent and as
collateral agent (Exhibit 10.A to our Form 8-K filed
November 29, 2004); Amended and Restated Subsidiary
Guarantee Agreement dated as of November 23, 2004, made by
each of the Subsidiary Guarantors, as defined therein, in favor
of JPMorgan Chase Bank, N.A., as collateral agent
(Exhibit 10.C to our Form 8-K filed November 29,2004); Amended and Restated Parent Guarantee Agreement dated as
of November 23, 2004, made by El Paso Corporation, in favor
of JPMorgan Chase Bank, N.A., as Collateral Agent
(Exhibit 10.D to our Form 8-K filed November 29, 2004)
10
.B
Amended and Restated Security Agreement dated as of
November 23, 2004, among El Paso Corporation, ANR Pipeline
Company, Colorado Interstate Gas Company, El Paso Natural Gas
Company, Tennessee Gas Pipeline Company, the Subsidiary
Guarantors and certain other credit parties thereto and JPMorgan
Chase Bank, N.A., not in its individual capacity, but solely as
collateral agent for the Secured Parties and as the depository
bank (Exhibit 10.B to our Form 8-K filed November 29,2004)
+10
.C
1995 Compensation Plan for Non-Employee Directors Amended and
Restated effective as of December 4, 2003
(Exhibit 10.F to our 2003 Form 10-K)
+10
.D
Stock Option Plan for Non-Employee Directors Amended and
Restated effective as of January 20, 1999
(Exhibit 10.G to our 2004 Form 10-K);
Amendment No. 1 effective as of July 16, 1999 to
the Stock Option Plan for Non-Employee Directors
(Exhibit 10.G.1 to our 2004 Form 10-K);
Amendment No. 2 effective as of February 7, 2001
to the Stock Option Plan for Non-Employee Directors
(Exhibit 10.F.1 to our 2001 First Quarter Form 10-Q)
+10
.E
2001 Stock Option Plan for Non-Employee Directors effective as
of January 29, 2001 (Exhibit 10.1 to our Form S-8
filed June 29, 2001); Amendment No. 1 effective as of
February 7, 2001 to the 2001 Stock Option Plan for
Non-Employee Directors (Exhibit 10.G.1 to our 2001
Form 10-K); Amendment No. 2 effective as of
December 4, 2003 to the 2001 Stock Option Plan for
Non-Employee Directors (Exhibit 10.H.1 to our 2003
Form 10-K)
+10
.F
1995 Omnibus Compensation Plan Amended and Restated effective as
of August 1, 1998 (Exhibit 10.I to our 2004
Form 10-K); Amendment No. 1 effective as of
December 3, 1998 to the 1995 Omnibus Compensation Plan
(Exhibit 10.I.1 to our 2004 Form 10-K);
Amendment No. 2 effective as of January 20, 1999
to the 1995 Omnibus Compensation Plan (Exhibit 10.I.2 to
our 2004 Form 10-K)
+10
.G
1999 Omnibus Incentive Compensation Plan dated January 20,1999 (Exhibit 10.1 to our Form S-8 filed May 20,1999); Amendment No. 1 effective as of
February 7, 2001 to the 1999 Omnibus Incentive Compensation
Plan (Exhibit 10.V.1 to our 2001 First Quarter
Form 10-Q); Amendment No. 2 effective as of
May 1, 2003 to the 1999 Omnibus Incentive Compensation Plan
(Exhibit 10.I.1 to our 2003 Second Quarter Form 10-Q)
2001 Omnibus Incentive Compensation Plan effective as of
January 29, 2001 (Exhibit 10.1 to our Form S-8
filed June 29, 2001); Amendment No. 1 effective
as of February 7, 2001 to the 2001 Omnibus Incentive
Compensation Plan (Exhibit 10.J.1 to our 2001
Form 10-K); Amendment No. 2 effective as of
April 1, 2001 to the 2001 Omnibus Incentive Compensation
Plan (Exhibit 10.J.1 to our 2002 Form 10-K);
Amendment No. 3 effective as of July 17, 2002 to
the 2001 Omnibus Incentive Compensation Plan
(Exhibit 10.J.1 to our 2002 Second Quarter Form 10-Q);
Amendment No. 4 effective as of May 1, 2003 to
the 2001 Omnibus Incentive Compensation Plan
(Exhibit 10.J.1 to our 2003 Second Quarter Form 10-Q);
Amendment No. 5 effective as of March 8, 2004 to
the 2001 Omnibus Incentive Compensation Plan
(Exhibit 10.K.1 to our 2003 Form 10-K)
+10
.I
Supplemental Benefits Plan Amended and Restated effective
December 7, 2001 (Exhibit 10.K to our 2001
Form 10-K); Amendment No. 1 effective as of
November 7, 2002 to the Supplemental Benefits Plan
(Exhibit 10.K.1 to our 2002 Form 10-K);
Amendment No. 3 effective December 17, 2004 to
the Supplemental Benefits Plan (Exhibit 10.UU to our 2004
Third Quarter Form 10-Q); Amendment No. 2
effective as of June 1, 2004 to the Supplemental Benefits
Plan (Exhibit 10.L.1 to our 2004 Form 10-K)
*+10
.I.1
Amendment No. 4 to the Supplemental Benefits Plan effective
as of December 31, 2004
+10
.J
Senior Executive Survivor Benefit Plan Amended and Restated
effective as of August 1, 1998 (Exhibit 10.M to our
2004 Form 10-K); Amendment No. 1 effective as of
February 7, 2001 to the Senior Executive Survivor Benefit
Plan (Exhibit 10.I.1 to our 2001 First Quarter
Form 10-Q); Amendment No. 2 effective as of
October 1, 2002 to the Senior Executive Survivor Benefit
Plan (Exhibit 10.L.1 to our 2002 Form 10-K)
+10
.K
Key Executive Severance Protection Plan Amended and Restated
effective as of August 1, 1998 (Exhibit 10.N to
our 2004 Form 10-K); Amendment No. 1 effective as
of February 7, 2001 to the Key Executive Severance
Protection Plan (Exhibit 10.K.1 to our 2001 First Quarter
Form 10-Q); Amendment No. 2 effective as of
November 7, 2002 to the Key Executive Severance Protection
Plan (Exhibit 10.N.1 to our 2002 Form 10-K);
Amendment No. 3 effective as of December 6, 2002
to the Key Executive Severance Protection Plan
(Exhibit 10.N.1 to our 2002 Form 10-K);
Amendment No. 4 effective as of September 2, 2003
to the Key Executive Severance Protection Plan
(Exhibit 10.N.1 to our 2003 Third Quarter Form 10-Q)
+10
.L
2004 Key Executive Severance Protection Plan effective as of
March 9, 2004 (Exhibit 10.P to our 2003 Form 10-K)
+10
.M
Director Charitable Award Plan Amended and Restated effective as
of August 1, 1998 (Exhibit 10.P to our 2004
Form 10-K); Amendment No. 1 effective as of
February 7, 2001 to the Director Charitable Award Plan
(Exhibit 10.L.1 to our 2001 First Quarter Form 10-Q);
Amendment No. 2 effective as of December 4, 2003
to the Director Charitable Award Plan (Exhibit 10.Q.1 to
our 2003 Form 10-K)
+10
.N
Strategic Stock Plan Amended and Restated effective as of
December 3, 1999 (Exhibit 10.1 to our Form S-8
filed January 14, 2000); Amendment No. 1
effective as of February 7, 2001 to the Strategic Stock
Plan (Exhibit 10.M.1 to our 2001 First Quarter
Form 10-Q); Amendment No. 2 effective as of
November 7, 2002 to the Strategic Stock Plan;
Amendment No. 3 effective as of December 6, 2002 to the
Strategic Stock Plan and Amendment No. 4 effective as
of January 29, 2003 to the Strategic Stock Plan
(Exhibit 10.P.1 to our 2002 Form 10-K)
+10
.O
Domestic Relocation Policy effective November 1, 1996
(Exhibit 10.R to our 2004 Form 10-K)
+10
.P
Executive Award Plan of Sonat Inc. Amended and Restated
effective as of July 23, 1998, as amended May 27, 1999
(Exhibit 10.S to our 2004 Form 10-K); Termination of
the Executive Award Plan of Sonat Inc. (Exhibit 10.K.1 to
our 2000 Second Quarter Form 10-Q)
Omnibus Plan for Management Employees Amended and Restated
effective as of December 3, 1999 (Exhibit 10.1 to
our Form S-8 filed December 18, 2000);
Amendment No. 1 effective as of December 1, 2000
to the Omnibus Plan for Management Employees (Exhibit 10.1
to our Form S-8 filed December 18, 2000);
Amendment No. 2 effective as of February 7, 2001
to the Omnibus Plan for Management Employees
(Exhibit 10.U.1 to our 2001 First Quarter Form 10-Q);
Amendment No. 3 effective as of December 7, 2001
to the Omnibus Plan for Management Employees (Exhibit 10.1
to our Form S-8 filed February 11, 2002);
Amendment No. 4 effective as of December 6, 2002 to
the Omnibus Plan for Management Employees (Exhibit 10.T.1
to our 2002 Form 10-K)
+10
.R
El Paso Production Companies Long-Term Incentive Plan effective
as of January 1, 2003 (Exhibit 10.AA to our 2003 First
Quarter Form 10-Q); Amendment No. 1 effective as
of June 6, 2003 to the El Paso Production Companies
Long-Term Incentive Plan (Exhibit 10.AA.1 to our 2003
Second Quarter Form 10-Q); Amendment No. 2
effective as of December 31, 2003 to the El Paso Production
Companies Long-Term Incentive Plan (Exhibit 10.V.1 to our
2003 Form 10-K)
+10
.S
Severance Pay Plan Amended and Restated effective as of
October 1, 2002; Supplement No. 1 to the
Severance Pay Plan effective as of January 1, 2003; and
Amendment No. 1 to Supplement No. 1
effective as of March 21, 2003 (Exhibit 10.Z to our 2003 First
Quarter Form 10-Q); Amendment No. 2 to
Supplement No. 1 effective as of
June 1, 2003 (Exhibit 10.Z.1 to our 2003 Second
Quarter Form 10-Q); Amendment No. 3 to
Supplement No. 1 effective as of September 2,2003 (Exhibit 10.Z.1 to our 2003 Third Quarter
Form 10-Q); Amendment No. 4 to
Supplement No. 1 effective as of October 1, 2003
(Exhibit 10.W.1 to our 2003 Form 10-K); Amendment
No. 5 to Supplement No. 1 effective as of
February 2, 2004 (Exhibit 10.W.1 to our 2003
Form 10-K)
*+10
.S.1
Supplement No. 2 dated April 1, 2005 to the Severance
Pay Plan Amended and Restated effective as of October 1,2002
+10
.T
Letter Agreement dated July 16, 2004 between El Paso
Corporation and D. Dwight Scott. (Exhibit 10.VV to our 2003
Third Quarter Form 10-Q)
+10
.U
Letter Agreement dated July 15, 2003 between El Paso and
Douglas L. Foshee (Exhibit 10.U to our 2003 Third Quarter
Form 10-Q)
Letter Agreement dated January 6, 2004 between El Paso and
Lisa A. Stewart (Exhibit 10.CC to our 2003 Form 10-K)
+10
.X
Form of Indemnification Agreement of each member of the Board of
Directors effective November 7, 2002 or the effective date
such director was elected to the Board of Directors, whichever
is later (Exhibit 10.FF to our 2002 Form 10-K)
*+10
.Y
Form of Indemnification Agreement executed by El Paso for the
benefit of each officer and effective the date listed in
Schedule A thereto.
+10
.Z
Indemnification Agreement executed by El Paso for the benefit of
Douglas L. Foshee, effective December 17, 2004
(Exhibit 10.XX to our 2003 Third Quarter Form 10-Q)
Master Settlement Agreement dated as of June 24, 2003, by
and between, on the one hand, El Paso Corporation, El Paso
Natural Gas Company, and El Paso Merchant Energy, L.P.; and, on
the other hand, the Attorney General of the State of California,
the Governor of the State of California, the California Public
Utilities Commission, the California Department of Water
Resources, the California Energy Oversight Board, the Attorney
General of the State of Washington, the Attorney General of the
State of Oregon, the Attorney General of the State of Nevada,
Pacific Gas & Electric Company, Southern California Edison
Company, the City of Los Angeles, the City of Long Beach, and
classes consisting of all individuals and entities in California
that purchased natural gas and/or electricity for use and not
for resale or generation of electricity for the purpose of
resale, between September 1, 1996 and
March 20, 2003, inclusive, represented by class
representatives Continental Forge Company, Andrew Berg, Andrea
Berg, Gerald J. Marcil, United Church Retirement Homes of Long
Beach, Inc., doing business as Plymouth West, Long Beach
Brethren Manor, Robert Lamond, Douglas Welch, Valerie Welch,
William Patrick Bower, Thomas L. French, Frank Stella, Kathleen
Stella, John Clement Molony, SierraPine, Ltd., John Frazee and
Jennifer Frazee, John W.H.K. Phillip, and Cruz Bustamante
(Exhibit 10.HH to our 2003 Second Quarter Form 10-Q)
10
.BB
Agreement With Respect to Collateral dated as of June 11,2004, by and among El Paso Production Oil & Gas USA,
L.P., a Delaware limited partnership, Bank of America, N.A.,
acting solely in its capacity as Collateral Agent under the
Collateral Agency Agreement, and The Office of the Attorney
General of the State of California, acting solely in its
capacity as the Designated Representative under the Designated
Representative Agreement (Exhibit 10.HH to our 2003
Form 10-K)
10
.CC
Joint Settlement Agreement submitted and entered into by El Paso
Natural Gas Company, El Paso Merchant Energy Company, El Paso
Merchant Energy-Gas, L.P., the Public Utilities Commission of
the State of California, Pacific Gas & Electric Company,
Southern California Edison Company and the City of Los Angeles
(Exhibit 10.II to our 2003 Second Quarter Form 10-Q)
10
.DD
Swap Settlement Agreement dated effective as of August 16,2004, among the Company, El Paso Merchant Energy, L.P.,
East Coast Power Holding Company L.L.C. and ECTMI Trutta
Holdings LP (Exhibit 10.A to our Form 8-K filed
October 15, 2004, and terminated as described in our
Form 8-K filed December 3, 2004)
10
.EE
Purchase Agreement dated April 11, 2005, by and among El
Paso Corporation and the Initial Purchasers party thereto
(Exhibit 10.A to our Form 8-K filed April 15,2005)
+10
.FF
Agreement and General Release dated May 4, 2005, by and
between El Paso Corporation and John W. Somerhalder II
(Exhibit 10.A to our Form 8-K filed May 4, 2005)
+10
.GG
El Paso Corporation 2005 Compensation Plan for Non-Employee
Directors (Exhibit 10.A to our Form 8-K filed on
May 31, 2005).
+10
.HH
El Paso Corporation 2005 Omnibus Incentive Compensation Plan
(Exhibit 10.B to our Form 8-K filed on May 31,2005).
*+10
.HH.1
Amendment No. 1 to the 2005 Omnibus Incentive Compensation
Plan effective as of December 2, 2005
+10
.II
El Paso Corporation Employee Stock Purchase Plan, Amended and
Restated Effective as of July 1, 2005. (Exhibit 10.E
to our 2005 Second Quarter Form 10-Q)
Credit Agreement among El Paso Corporation and El Paso
Production Oil & Gas USA, L.P., as Borrowers, Fortis
Capital Corp., as Administrative Agent, Arranger and Bookrunner,
dated as of November 3, 2005 (Exhibit 10.A to our
Form 8-K filed on November 4, 2005); First Amendment,
Consent and Waiver Agreement, dated as of December 20, 2005,
among El Paso Corporation and El Paso Production Oil &
Gas USA, L.P., as Borrowers, Fortis Capital Corp., as
Administrative Agent for the Lenders, and the several Lenders
party from time to time thereto (Exhibit 10.B to our
Form 8-K filed on January 4, 2006)
*+10
.KK
2005 Supplemental Benefits Plan effective as of January 1,2005
12
Ratio of Earnings to Combined Fixed Charges and Preferred Stock
Dividends
Certification of Chief Executive Officer pursuant to Section 302
of the Sarbanes-Oxley Act of 2002
*31
.B
Certification of Chief Financial Officer pursuant to Section 302
of the Sarbanes-Oxley Act of 2002
*32
.A
Certification of Chief Executive Officer pursuant to Section 906
of the Sarbanes-Oxley Act of 2002
*32
.B
Certification of Chief Financial Officer pursuant to Section 906
of the Sarbanes-Oxley Act of 2002
Undertaking
We hereby undertake, pursuant to Regulation S-K,
Item 601(b), paragraph (4) (iii), to furnish to the
Securities and Exchange Commission upon request all constituent
instruments defining the rights of holders of our long-term debt
and consolidated subsidiaries not filed herewith for the reason
that the total amount of securities authorized under any of such
instruments does not exceed 10 percent of our total
consolidated assets.
Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, El Paso Corporation has
duly caused this report to be signed on its behalf by the
undersigned, thereunto duly authorized on the 3rd day of
March, 2006.
Pursuant to the requirements of the Securities Exchange Act of
1934, this report has been signed below by the following persons
on behalf of El Paso Corporation and in the capacities and
on the dates indicated:
Each exhibit identified below is filed as part of this report.
Exhibits filed with this Report are designated by “*”.
All exhibits not so designated are incorporated herein by
reference to a prior filing as indicated. Exhibits designated
with a “+” constitute a management contract or
compensatory plan or arrangement.
2
.A
Merger Agreement, dated as of December 15, 2003, by and among
Enterprise Products Partners L.P., Enterprise Products GP, LLC,
Enterprise Products Management LLC, GulfTerra Energy Partners,
L.P. and GulfTerra Energy Company, L.L.C. (including the form of
Assumption Agreement to be entered into in connection with the
merger, attached as an exhibit thereto) (Exhibit 2.1 to our Form
8-K filed December 15, 2003)
2
.B
Parent Company Agreement, dated as of December 15, 2003, by
and among Enterprise Products Partners L.P., Enterprise Products
GP, LLC, Enterprise Products GTM, LLC, El Paso Corporation,
Sabine River Investors I, L.L.C., Sabine River Investors II,
L.L.C., El Paso EPN Investments, L.L.C. and GulfTerra GP
Holding Company (including the form of Second Amended and
Restated Limited Liability Company Agreement of Enterprise
Products GP, LLC, to be entered into in connection with the
merger, attached as an exhibit thereto) (Exhibit 2.2 to our
Form 8-K filed December 15, 2003);
Amendment No. 1 to Parent Company Agreement, dated as
of December 15, 2003, by and among Enterprise Products
Partners L.P., Enterprise Products GP, LLC, Enterprise Products
GTM, LLC, El Paso Corporation, Sabine River Investors I,
L.L.C., Sabine River Investors II, L.L.C., El Paso EPN
Investments, L.L.C. and GulfTerra GP Holding Company, dated as
of April 19, 2004 (including the forms of Second
Amended and Restated Limited Liability Company Agreement of
Enterprise Products GP, LLC, Exchange and Registration Rights
Agreement and Performance Guaranty, to be entered into by the
parties named therein in connection with the merger of
Enterprise and GulfTerra, attached as Exhibits 1, 2
and 3, respectively, thereto) (Exhibit 2.1 to our Form
8-K filed April 21, 2004); Second Amended and Restated
Limited Liability Company Agreement of GulfTerra Energy Company,
L.L.C., adopted by GulfTerra GP Holding Company, a Delaware
corporation, and Enterprise Products GTM, LLC, a Delaware
limited liability company, as of December 15, 2003
(Exhibit 2.3 to our Form 8-K filed December 15, 2003);
Purchase and Sale Agreement (Gas Plants), dated as of
December 15, 2003, by and between El Paso Corporation, El
Paso Field Services Management, Inc., El Paso Transmission,
L.L.C., El Paso Field Services Holding Company and Enterprise
Products Operating L.P. (Exhibit 2.4 to our Form 8-K filed
December 15, 2003); Purchase and Sale Agreement, dated
as of January 14, 2005, by and among Enterprise GP
Holdings, L.P., Sabine River Investors I, L.L.C., Sabine River
Investors II, L.L.C., El Paso Corporation and GulfTerra GP
Holding Company (Exhibit 2.B.1 to our 2004 Form 10-K)
Indenture dated as of May 10, 1999, by and between El Paso
and HSBC Bank USA, National Association (as
successor-in-interest to JPMorgan Chase Bank (formerly The Chase
Manhattan Bank)), as Trustee (Exhibit 4.A to our 2004 Form
10-K)
4
.B
Certificate of Designations of 4.99% Convertible Perpetual
Preferred Stock (included in Exhibit 3.A to our Current
Report on Form 8-K filed May 31, 2005)
Registration Rights Agreement, dated April 15, 2005, by and
among El Paso Corporation and the Initial Purchasers party
thereto (Exhibit 4.A to our Current Report on Form 8-K
filed April 15, 2005)
4
.D
Registration Rights Agreement dated as of December 28, 2005
among El Paso Corporation, Goldman Sachs & Co. and
Citigroup Global Markets Inc. (Exhibit 10.A to our Current
Report on Form 8-K filed January 4, 2006)
4
.E
Tenth Supplemental Indenture dated as of December 28, 2005
between El Paso Corporation and HSBC Bank USA, National
Association, as trustee. (Exhibit 4.A to our Current Report
on Form 8-K filed January 4, 2006)
10
.A
Amended and Restated Credit Agreement dated as of
November 23, 2004, among El Paso Corporation, ANR Pipeline
Company, Colorado Interstate Gas Company, El Paso Natural Gas
Company, Tennessee Gas Pipeline Company, the several banks and
other financial institutions from time to time parties thereto
and JPMorgan Chase Bank, N.A., as administrative agent and as
collateral agent (Exhibit 10.A to our Form 8-K filed
November 29, 2004); Amended and Restated Subsidiary
Guarantee Agreement dated as of November 23, 2004, made by
each of the Subsidiary Guarantors, as defined therein, in favor
of JPMorgan Chase Bank, N.A., as collateral agent
(Exhibit 10.C to our Form 8-K filed November 29,2004); Amended and Restated Parent Guarantee Agreement dated as
of November 23, 2004, made by El Paso Corporation, in favor
of JPMorgan Chase Bank, N.A., as Collateral Agent
(Exhibit 10.D to our Form 8-K filed November 29, 2004)
10
.B
Amended and Restated Security Agreement dated as of
November 23, 2004, among El Paso Corporation, ANR Pipeline
Company, Colorado Interstate Gas Company, El Paso Natural Gas
Company, Tennessee Gas Pipeline Company, the Subsidiary
Guarantors and certain other credit parties thereto and JPMorgan
Chase Bank, N.A., not in its individual capacity, but solely as
collateral agent for the Secured Parties and as the depository
bank (Exhibit 10.B to our Form 8-K filed November 29,2004)
+10
.C
1995 Compensation Plan for Non-Employee Directors Amended and
Restated effective as of December 4, 2003
(Exhibit 10.F to our 2003 Form 10-K)
+10
.D
Stock Option Plan for Non-Employee Directors Amended and
Restated effective as of January 20, 1999
(Exhibit 10.G to our 2004 Form 10-K);
Amendment No. 1 effective as of July 16, 1999 to
the Stock Option Plan for Non-Employee Directors
(Exhibit 10.G.1 to our 2004 Form 10-K);
Amendment No. 2 effective as of February 7, 2001
to the Stock Option Plan for Non-Employee Directors
(Exhibit 10.F.1 to our 2001 First Quarter Form 10-Q)
+10
.E
2001 Stock Option Plan for Non-Employee Directors effective as
of January 29, 2001 (Exhibit 10.1 to our Form S-8
filed June 29, 2001); Amendment No. 1 effective as of
February 7, 2001 to the 2001 Stock Option Plan for
Non-Employee Directors (Exhibit 10.G.1 to our 2001
Form 10-K); Amendment No. 2 effective as of
December 4, 2003 to the 2001 Stock Option Plan for
Non-Employee Directors (Exhibit 10.H.1 to our 2003
Form 10-K)
+10
.F
1995 Omnibus Compensation Plan Amended and Restated effective as
of August 1, 1998 (Exhibit 10.I to our 2004
Form 10-K); Amendment No. 1 effective as of
December 3, 1998 to the 1995 Omnibus Compensation Plan
(Exhibit 10.I.1 to our 2004 Form 10-K);
Amendment No. 2 effective as of January 20, 1999
to the 1995 Omnibus Compensation Plan (Exhibit 10.I.2 to
our 2004 Form 10-K)
+10
.G
1999 Omnibus Incentive Compensation Plan dated January 20,1999 (Exhibit 10.1 to our Form S-8 filed May 20,1999); Amendment No. 1 effective as of
February 7, 2001 to the 1999 Omnibus Incentive Compensation
Plan (Exhibit 10.V.1 to our 2001 First Quarter
Form 10-Q); Amendment No. 2 effective as of
May 1, 2003 to the 1999 Omnibus Incentive Compensation Plan
(Exhibit 10.I.1 to our 2003 Second Quarter Form 10-Q)
2001 Omnibus Incentive Compensation Plan effective as of
January 29, 2001 (Exhibit 10.1 to our Form S-8
filed June 29, 2001); Amendment No. 1 effective
as of February 7, 2001 to the 2001 Omnibus Incentive
Compensation Plan (Exhibit 10.J.1 to our 2001
Form 10-K); Amendment No. 2 effective as of
April 1, 2001 to the 2001 Omnibus Incentive Compensation
Plan (Exhibit 10.J.1 to our 2002 Form 10-K);
Amendment No. 3 effective as of July 17, 2002 to
the 2001 Omnibus Incentive Compensation Plan
(Exhibit 10.J.1 to our 2002 Second Quarter Form 10-Q);
Amendment No. 4 effective as of May 1, 2003 to
the 2001 Omnibus Incentive Compensation Plan
(Exhibit 10.J.1 to our 2003 Second Quarter Form 10-Q);
Amendment No. 5 effective as of March 8, 2004 to
the 2001 Omnibus Incentive Compensation Plan
(Exhibit 10.K.1 to our 2003 Form 10-K)
+10
.I
Supplemental Benefits Plan Amended and Restated effective
December 7, 2001 (Exhibit 10.K to our 2001
Form 10-K); Amendment No. 1 effective as of
November 7, 2002 to the Supplemental Benefits Plan
(Exhibit 10.K.1 to our 2002 Form 10-K);
Amendment No. 3 effective December 17, 2004 to
the Supplemental Benefits Plan (Exhibit 10.UU to our 2004
Third Quarter Form 10-Q); Amendment No. 2
effective as of June 1, 2004 to the Supplemental Benefits
Plan (Exhibit 10.L.1 to our 2004 Form 10-K)
*+10
.I.1
Amendment No. 4 to the Supplemental Benefits Plan effective
as of December 31, 2004
+10
.J
Senior Executive Survivor Benefit Plan Amended and Restated
effective as of August 1, 1998 (Exhibit 10.M to our
2004 Form 10-K); Amendment No. 1 effective as of
February 7, 2001 to the Senior Executive Survivor Benefit
Plan (Exhibit 10.I.1 to our 2001 First Quarter
Form 10-Q); Amendment No. 2 effective as of
October 1, 2002 to the Senior Executive Survivor Benefit
Plan (Exhibit 10.L.1 to our 2002 Form 10-K)
+10
.K
Key Executive Severance Protection Plan Amended and Restated
effective as of August 1, 1998 (Exhibit 10.N to
our 2004 Form 10-K); Amendment No. 1 effective as
of February 7, 2001 to the Key Executive Severance
Protection Plan (Exhibit 10.K.1 to our 2001 First Quarter
Form 10-Q); Amendment No. 2 effective as of
November 7, 2002 to the Key Executive Severance Protection
Plan (Exhibit 10.N.1 to our 2002 Form 10-K);
Amendment No. 3 effective as of December 6, 2002
to the Key Executive Severance Protection Plan
(Exhibit 10.N.1 to our 2002 Form 10-K);
Amendment No. 4 effective as of September 2, 2003
to the Key Executive Severance Protection Plan
(Exhibit 10.N.1 to our 2003 Third Quarter Form 10-Q)
+10
.L
2004 Key Executive Severance Protection Plan effective as of
March 9, 2004 (Exhibit 10.P to our 2003 Form 10-K)
+10
.M
Director Charitable Award Plan Amended and Restated effective as
of August 1, 1998 (Exhibit 10.P to our 2004
Form 10-K); Amendment No. 1 effective as of
February 7, 2001 to the Director Charitable Award Plan
(Exhibit 10.L.1 to our 2001 First Quarter Form 10-Q);
Amendment No. 2 effective as of December 4, 2003
to the Director Charitable Award Plan (Exhibit 10.Q.1 to
our 2003 Form 10-K)
+10
.N
Strategic Stock Plan Amended and Restated effective as of
December 3, 1999 (Exhibit 10.1 to our Form S-8
filed January 14, 2000); Amendment No. 1
effective as of February 7, 2001 to the Strategic Stock
Plan (Exhibit 10.M.1 to our 2001 First Quarter
Form 10-Q); Amendment No. 2 effective as of
November 7, 2002 to the Strategic Stock Plan;
Amendment No. 3 effective as of December 6, 2002 to the
Strategic Stock Plan and Amendment No. 4 effective as
of January 29, 2003 to the Strategic Stock Plan
(Exhibit 10.P.1 to our 2002 Form 10-K)
+10
.O
Domestic Relocation Policy effective November 1, 1996
(Exhibit 10.R to our 2004 Form 10-K)
+10
.P
Executive Award Plan of Sonat Inc. Amended and Restated
effective as of July 23, 1998, as amended May 27, 1999
(Exhibit 10.S to our 2004 Form 10-K); Termination of
the Executive Award Plan of Sonat Inc. (Exhibit 10.K.1 to
our 2000 Second Quarter Form 10-Q)
Omnibus Plan for Management Employees Amended and Restated
effective as of December 3, 1999 (Exhibit 10.1 to
our Form S-8 filed December 18, 2000);
Amendment No. 1 effective as of December 1, 2000
to the Omnibus Plan for Management Employees (Exhibit 10.1
to our Form S-8 filed December 18, 2000);
Amendment No. 2 effective as of February 7, 2001
to the Omnibus Plan for Management Employees
(Exhibit 10.U.1 to our 2001 First Quarter Form 10-Q);
Amendment No. 3 effective as of December 7, 2001
to the Omnibus Plan for Management Employees (Exhibit 10.1
to our Form S-8 filed February 11, 2002);
Amendment No. 4 effective as of December 6, 2002 to
the Omnibus Plan for Management Employees (Exhibit 10.T.1
to our 2002 Form 10-K)
+10
.R
El Paso Production Companies Long-Term Incentive Plan effective
as of January 1, 2003 (Exhibit 10.AA to our 2003 First
Quarter Form 10-Q); Amendment No. 1 effective as
of June 6, 2003 to the El Paso Production Companies
Long-Term Incentive Plan (Exhibit 10.AA.1 to our 2003
Second Quarter Form 10-Q); Amendment No. 2
effective as of December 31, 2003 to the El Paso Production
Companies Long-Term Incentive Plan (Exhibit 10.V.1 to our
2003 Form 10-K)
+10
.S
Severance Pay Plan Amended and Restated effective as of
October 1, 2002; Supplement No. 1 to the
Severance Pay Plan effective as of January 1, 2003; and
Amendment No. 1 to Supplement No. 1
effective as of March 21, 2003 (Exhibit 10.Z to our 2003 First
Quarter Form 10-Q); Amendment No. 2 to
Supplement No. 1 effective as of
June 1, 2003 (Exhibit 10.Z.1 to our 2003 Second
Quarter Form 10-Q); Amendment No. 3 to
Supplement No. 1 effective as of September 2,2003 (Exhibit 10.Z.1 to our 2003 Third Quarter
Form 10-Q); Amendment No. 4 to
Supplement No. 1 effective as of October 1, 2003
(Exhibit 10.W.1 to our 2003 Form 10-K); Amendment
No. 5 to Supplement No. 1 effective as of
February 2, 2004 (Exhibit 10.W.1 to our 2003
Form 10-K)
*+10
.S.1
Supplement No. 2 dated April 1, 2005 to the Severance
Pay Plan Amended and Restated effective as of October 1,2002
+10
.T
Letter Agreement dated July 16, 2004 between El Paso
Corporation and D. Dwight Scott. (Exhibit 10.VV to our 2003
Third Quarter Form 10-Q)
+10
.U
Letter Agreement dated July 15, 2003 between El Paso and
Douglas L. Foshee (Exhibit 10.U to our 2003 Third Quarter
Form 10-Q)
Letter Agreement dated January 6, 2004 between El Paso and
Lisa A. Stewart (Exhibit 10.CC to our 2003 Form 10-K)
+10
.X
Form of Indemnification Agreement of each member of the Board of
Directors effective November 7, 2002 or the effective date
such director was elected to the Board of Directors, whichever
is later (Exhibit 10.FF to our 2002 Form 10-K)
*+10
.Y
Form of Indemnification Agreement executed by El Paso for the
benefit of each officer and effective the date listed in
Schedule A thereto.
+10
.Z
Indemnification Agreement executed by El Paso for the benefit of
Douglas L. Foshee, effective December 17, 2004
(Exhibit 10.XX to our 2003 Third Quarter Form 10-Q)
Master Settlement Agreement dated as of June 24, 2003, by
and between, on the one hand, El Paso Corporation, El Paso
Natural Gas Company, and El Paso Merchant Energy, L.P.; and, on
the other hand, the Attorney General of the State of California,
the Governor of the State of California, the California Public
Utilities Commission, the California Department of Water
Resources, the California Energy Oversight Board, the Attorney
General of the State of Washington, the Attorney General of the
State of Oregon, the Attorney General of the State of Nevada,
Pacific Gas & Electric Company, Southern California Edison
Company, the City of Los Angeles, the City of Long Beach, and
classes consisting of all individuals and entities in California
that purchased natural gas and/or electricity for use and not
for resale or generation of electricity for the purpose of
resale, between September 1, 1996 and
March 20, 2003, inclusive, represented by class
representatives Continental Forge Company, Andrew Berg, Andrea
Berg, Gerald J. Marcil, United Church Retirement Homes of Long
Beach, Inc., doing business as Plymouth West, Long Beach
Brethren Manor, Robert Lamond, Douglas Welch, Valerie Welch,
William Patrick Bower, Thomas L. French, Frank Stella, Kathleen
Stella, John Clement Molony, SierraPine, Ltd., John Frazee and
Jennifer Frazee, John W.H.K. Phillip, and Cruz Bustamante
(Exhibit 10.HH to our 2003 Second Quarter Form 10-Q)
10
.BB
Agreement With Respect to Collateral dated as of June 11,2004, by and among El Paso Production Oil & Gas USA,
L.P., a Delaware limited partnership, Bank of America, N.A.,
acting solely in its capacity as Collateral Agent under the
Collateral Agency Agreement, and The Office of the Attorney
General of the State of California, acting solely in its
capacity as the Designated Representative under the Designated
Representative Agreement (Exhibit 10.HH to our 2003
Form 10-K)
10
.CC
Joint Settlement Agreement submitted and entered into by El Paso
Natural Gas Company, El Paso Merchant Energy Company, El Paso
Merchant Energy-Gas, L.P., the Public Utilities Commission of
the State of California, Pacific Gas & Electric Company,
Southern California Edison Company and the City of Los Angeles
(Exhibit 10.II to our 2003 Second Quarter Form 10-Q)
10
.DD
Swap Settlement Agreement dated effective as of August 16,2004, among the Company, El Paso Merchant Energy, L.P.,
East Coast Power Holding Company L.L.C. and ECTMI Trutta
Holdings LP (Exhibit 10.A to our Form 8-K filed
October 15, 2004, and terminated as described in our
Form 8-K filed December 3, 2004)
10
.EE
Purchase Agreement dated April 11, 2005, by and among El
Paso Corporation and the Initial Purchasers party thereto
(Exhibit 10.A to our Form 8-K filed April 15,2005)
+10
.FF
Agreement and General Release dated May 4, 2005, by and
between El Paso Corporation and John W. Somerhalder II
(Exhibit 10.A to our Form 8-K filed May 4, 2005)
+10
.GG
El Paso Corporation 2005 Compensation Plan for Non-Employee
Directors (Exhibit 10.A to our Form 8-K filed on
May 31, 2005).
+10
.HH
El Paso Corporation 2005 Omnibus Incentive Compensation Plan
(Exhibit 10.B to our Form 8-K filed on May 31,2005).
*+10
.HH.1
Amendment No. 1 to the 2005 Omnibus Incentive Compensation
Plan effective as of December 2, 2005
+10
.II
El Paso Corporation Employee Stock Purchase Plan, Amended and
Restated Effective as of July 1, 2005. (Exhibit 10.E
to our 2005 Second Quarter Form 10-Q)
Credit Agreement among El Paso Corporation and El Paso
Production Oil & Gas USA, L.P., as Borrowers, Fortis
Capital Corp., as Administrative Agent, Arranger and Bookrunner,
dated as of November 3, 2005 (Exhibit 10.A to our
Form 8-K filed on November 4, 2005); First Amendment,
Consent and Waiver Agreement, dated as of December 20, 2005,
among El Paso Corporation and El Paso Production Oil &
Gas USA, L.P., as Borrowers, Fortis Capital Corp., as
Administrative Agent for the Lenders, and the several Lenders
party from time to time thereto (Exhibit 10.B to our
Form 8-K filed on January 4, 2006)
*+10
.KK
2005 Supplemental Benefits Plan effective as of January 1,2005
*12
Ratio of Earnings to Combined Fixed Charges and Preferred Stock
Dividends
