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(Exact Name of Registrant as Specified in Its Charter)
Delaware
(State or Other Jurisdiction of
Incorporation or Organization)
76-0568816
(I.R.S. Employer
Identification No.)
El Paso Building
1001 Louisiana Street
Houston, Texas
(Address of Principal Executive Offices)
77002
(Zip Code)
Telephone Number: (713) 420-2600
Internet Website: www.elpaso.com
Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class
Name of Each Exchange
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. o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer,
a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,”“accelerated filer” and “smaller reporting company” in
Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer þ
Accelerated filer o
Non-accelerated filer o
Smaller reporting company o
(Do not check if a smaller reporting company)
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 29, 2007 computed by reference to the closing
sale price of the registrant’s common stock on the New York Stock Exchange on such date:
$12,068,373,398.
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 22, 2008:
700,784,034
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 2008 Annual Meeting of Stockholders are incorporated by
reference into Part III of this report. These will be filed no later than April 30, 2008.
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
GWh
=
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 that primarily operates
in the natural gas transmission and exploration and production sectors of the energy industry. Our
purpose is to provide natural gas and related energy products in a safe, efficient and dependable
manner.
Natural Gas Transmission. We own or have interests in North America’s largest interstate
pipeline system with approximately 42,000 miles of pipe that connect North America’s major natural
gas producing basins to its major consuming markets. We also provide approximately 230 Bcf of
storage capacity and have an LNG receiving terminal and related facilities in Elba Island, Georgia
with 806 MMcf of daily base load sendout capacity. 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. Our focus is to enhance the value of our transmission business by
successfully executing on our backlog of committed
expansion projects in the United States and
Mexico and developing new growth projects in our market and supply areas.
Exploration and Production. Our exploration and production business is currently focused on
the exploration for and the acquisition, development and production of natural gas, oil and NGL in
the United States, Brazil and Egypt. As of December 31, 2007, we held an estimated 2.9 Tcfe of
proved natural gas and oil reserves, not including our equity share in the proved reserves of an
unconsolidated affiliate of 0.2 Tcfe. In this business, we are focused on growing our reserve base
through disciplined capital allocation and portfolio management, cost control and marketing our natural gas and oil production at optimal prices while managing associated price risks.
Our operations are conducted through two core segments, Pipelines and Exploration and
Production. We also have Marketing and Power 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 a further discussion of our business segments, see 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, Note 16.
Pipelines Segment
Our Pipelines segment includes our interstate natural gas transmission systems and related
operations conducted through four separate, wholly owned pipeline systems, three majority-owned
systems and three partially owned systems. These systems connect the nation’s principal natural gas
supply regions to the five largest consuming regions in the United States: the Gulf Coast,
California, the northeast, the southwest and the southeast. We also have access to systems in
Canada and assets in Mexico. Our Pipelines segment also includes our ownership of storage capacity
through our transmission systems, two underground storage facilities and our LNG terminal and
related facilities.
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, and
other 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 strategy is to enhance the value of our transmission and storage business by:
•
Successfully executing on our backlog of committed expansion
projects;
•
Developing new growth projects in our market and supply areas;
•
Recontracting or contracting available or expiring capacity;
•
Focusing on efficiency and synergies across our systems;
•
Ensuring the safety of our pipeline systems and assets; and
•
Providing outstanding customer service.
In November 2007, we formed El Paso Pipeline Partners, L.P., our master limited partnership
(MLP). We contributed our Wyoming Interstate system and 10 percent general
partner interests in each of Southern Natural Gas and Colorado Interstate Gas to the MLP. Our ownership interest in the MLP at December 31, 2007 consists of a two percent
general partner interest and a 64.8 percent limited partner interest.
The tables below provide
more information on our 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.
100
13,700
7,069
92
4,880
4,534
4,443
El Paso Natural Gas
(EPNG)
Extends from San Juan,
Permian, Anadarko
basins and via
interconnects the Rocky
Mountains to
California, its single
largest market, as well
as markets in Arizona,
Nevada, New Mexico,
Oklahoma, Texas and
northern Mexico.
100
10,200
5,650(2)
44
4,189
4,179
4,053
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.
100
400
400(4)
—
458
461
161
Cheyenne Plains Gas
Pipeline(CPG)
(3)
Extends from Cheyenne
hub and Yuma County in
Colorado to various
pipeline
interconnections near
Greensburg, Kansas.
100
400
861
—
735
583
433
(1)
Includes throughput transported on behalf of affiliates.
(2)
Reflects winter-sustainable west-flow capacity of 4,850 MMcf/d and approximately 800 MMcf/d of east-end delivery capacity.
Extends from natural gas
fields in Texas, Louisiana,
Mississippi, Alabama and the
Gulf of Mexico to Louisiana,
Mississippi, Alabama,
Florida, Georgia, South
Carolina and Tennessee,
including, the metropolitan
areas of Atlanta and Birmingham.
97
7,600
3,665
60
2,345
2,167
1,984
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.
97
4,000
3,048
29
2,339
2,008
1,902
Wyoming Interstate (WIC)(2)
Extends from western Wyoming,
eastern Utah, western
Colorado and the Powder River
Basin to various pipeline
interconnections near
Cheyenne, Wyoming.
67
800
2,721
—
2,071
1,914
1,572
Florida Gas
Transmission(3)
(FGT)
Extends from South Texas to
South Florida.
50
4,881
2,100
—
2,056
2,018
1,916
Samalayuca Pipeline and
Gloria a Dios Compression
Station(4)
Extends from U.S.-Mexico
border to the state of
Chihuahua, Mexico.
50
23
460
—
462
442
423
San Fernando Pipeline(4)
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
951
(1)
Includes throughput transported on behalf of affiliates and represents the systems’ totals and are not adjusted for our ownership interest.
(2)
Includes the recently completed Kanda expansion project placed in
service in January 2008.
(3)
We have a 50 percent equity interest in Citrus Corp. (Citrus), which owns this system.
(4)
We have a 50 percent equity interest in Gasoductos de Chihuahua, which owns these systems.
In
December 2007, we placed the LPG Burgos pipeline in
service. This 117 mile pipeline, in which we own 50%, transports
liquified petroleum gas and extends from Pemex’s Burgos complex
to the Monterrey market in the state of Nuevo Leoń, Mexico. The system
has a design capacity of 30 million barrels/day and in 2007 we
transported an average of 30 million barrels/day.
As of December 31, 2007, we had the following FERC approved pipeline expansion projects on our
systems. For a further discussion of other backlog expansion
projects, see Item 7 Management’s Discussion and Analysis
of Financial Condition and Results of Operations.
Existing
Capacity
Anticipated
Project
System
(MMcf/d)
Description
Completion or In-Service Date
Essex Middlesex Project
TGP
80
To construct 7.8 miles of 24-inch
pipeline connecting our Beverly-Salem
line to the DOMAC line in Essex and
Middlesex Counties, Massachusetts
November 2008
Medicine Bow Expansion
WIC
330
To construct a new 24,930 horsepower
compression facility which increases
capacity from the Powder River Basin in
northeast Wyoming to the WIC mainline
near the Cheyenne Hub
July 2008
Cheyenne Plains Expansion
CPG
70
To construct a new compression facility
comprised of 10,310 horsepower at the
Kirk Compressor Station in Yuma County,
Colorado
July 2008
Cypress Phase II
SNG
114
To add 10,350 horsepower of additional
compression on pipeline facilities
extending southward from our Elba Island
facility
May 2008
Cypress Phase III
SNG
161
To add 20,700 horsepower of additional
compression on pipeline facilities
extending southward from our Elba Island
facility
January 2011
Southeast
Supply Header (Phase I)
SNG
140
To construct 115 miles of pipeline to the
western portion of our system and provide
access through pipeline interconnects to
several supply basins
June 2008
Intrastate Transmission Systems
CIG has a 50 percent interest in WYCO Development, L.L.C. (WYCO). WYCO owns a
state regulated intrastate gas pipeline that extends from the Cheyenne Hub in northeast Colorado to
Public Service Company of Colorado’s (PSCo) Fort St. Vrain electric generation plant. WYCO also
owns a compressor station on our WIC system’s Medicine Bow lateral in Wyoming and leases these
pipeline and compression facilities to PSCo and WIC, respectively, under long-term leases. WYCO
currently has two expansion projects underway, the High Plains pipeline and Totem storage expansion
projects, expected to be completed in 2008 and 2009. CIG will lease these facilities and will be the operator of these projects.
Underground Natural Gas Storage Facilities
In
addition to the storage along our pipeline systems, we own or have interests in the following natural gas storage facilities:
Approximately 58 Bcf is contracted to affiliates. Amounts are not adjusted for our ownership interest.
LNG Facility
We own an LNG receiving terminal located on Elba Island, near Savannah, Georgia with a peak
sendout capacity of 1.2 Bcf/d and a base load sendout capacity of 0.8 Bcf/d. The capacity at the
terminal is contracted with subsidiaries of British Gas Group and Royal Dutch Shell PLC.
In September 2007, we received FERC approval to expand the Elba Island LNG receiving terminal
and construct the Elba Express Pipeline. The expansion is anticipated to increase the peak sendout
capacity of the terminal from 1.2 Bcf/d to 2.1 Bcf/d. The Elba Express Pipeline will consist of
approximately 190 miles of pipeline with a total capacity of 1.2 Bcf/d, which will transport
natural gas from the Elba Island LNG terminal to markets in the southeastern and eastern United
States. In February 2008, we completed our acquisition of a 50 percent interest in the Gulf LNG
Clean Energy Project, which is constructing a FERC approved liquefied natural gas terminal in
Pascagoula, Mississippi that is expected to be placed in service in late 2011.
Markets and Competition
Our Pipelines segment provides 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 energy, wind, hydroelectric
power and fuel oil.
Imported LNG is one of the fastest growing supply sectors of the natural gas market. LNG
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 may also
compete with our pipelines for transportation of gas into the 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 potential benefit is offset, in
varying degrees, by increased generation efficiency, the more effective use of surplus electric
capacity, increased natural gas prices and the use and availability of other fuel sources for power
generation. 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 transportation contracts with natural gas 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 our firm transportation contracts as
of December 31, 2007 for our wholly and majority owned systems that expire by year over the next five years and thereafter.
The
following table details information related to our pipeline systems,
including the customers, contracts, markets
served and the competition faced by each as of December 31, 2007. Firm
customers reserve capacity on our pipeline system, storage facilities or LNG terminalling
facilities and 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. Interruptible
customers are customers without reserved capacity that pay usage charges based on the volume of gas
they request to transport, store, inject or withdraw.
Approximately 440 firm and
interruptible customers.
Approximately 500
firm transportation
contracts. Weighted
average remaining
contract term of
approximately four
years.
TGP faces
competition in its
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.
Approximately 140 firm and
interruptible customers
Approximately 190
firm transportation
contracts. Weighted
average remaining
contract term of
approximately four
years.
EPNG faces
competition in the
west and southwest
from other existing
and proposed
pipelines, from
California storage
facilities, and
from alternative
energy sources that
are used to
generate
electricity such as
hydroelectric
power, nuclear
energy, wind,
solar, coal and
fuel oil. In
addition,
construction of
facilities to bring
LNG into California
and northern Mexico
are underway.
Major Customers:
Southern California Gas Company
(187 BBtu/d)
Expires in 2009.
(246 BBtu/d)
Expires in 2010.
(323 BBtu/d)
Expires in 2011.
Southwest Gas Corporation
(11 BBtu/d)
Expires in 2008.
(603 BBtu/d)
Expire in 2011-2015.
MPC
Approximately 20 firm and
interruptible customers
Approximately five
firm transportation
contracts. Weighted
average remaining
contract term of
approximately eight
years.
MPC faces
competition from
other existing and
proposed pipelines,
and alternative
energy sources that
are used to
generate
electricity such as
hydroelectric
power, nuclear
energy, wind,
solar, coal and
fuel oil. In
addition,
construction of
facilities to bring
LNG into California
and northern Mexico
are underway.
Approximately 30
firm transportation
contracts. Weighted
average remaining
contract term of
approximately eight
years.
CPG competes
directly with other
interstate
pipelines serving
the mid-continent
region. Indirectly,
CPG competes with
pipelines that
transport Rocky
Mountain gas to
other markets.
Major Customers:
Oneok Energy Services Company
L.P.
Expires in 2015.
(195 BBtu/d)
Encana Marketing (USA) Inc.
Expires in 2015.
(170 BBtu/d)
Anadarko Petroleum Corporation
Expire in 2015-2016.
(195 BBtu/d)
Coral Energy Resources, L.P.
Expires in 2019.
(125 BBtu/d)
SNG
Approximately 280 firm and
interruptible customers
Approximately 190
firm transportation
contracts. Weighted
average remaining
contract term of
approximately six
years.
SNG faces
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 SNG’s
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 sources.
Approximately 120 firm and
interruptible customers
Approximately 180
firm transportation
contracts. Weighted
average remaining
contract term of
approximately five
years.
CIG serves two
major markets, an
“on- system”
market and an
“off- system”
market. Its
‘on-system’ market
consists of
utilities and other
customers located
along the front
range of the Rocky
Mountains in
Colorado and
Wyoming.
Competitors in this
market consist of
an intrastate
pipeline, an
interstate
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.
CIG’s 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
this off-system
market consists of
interstate
pipelines that are
directly connected
to its supply
sources. CIG faces
competition from
other existing
pipelines and
alternative energy
sources that are
used to generate
electricity such as
hydroelectric
power, wind, solar,
coal and fuel oil.
Major Customers:
PSCo
(187 BBtu/d)
Expires in 2008.
(9 BBtu/d)
Expires in 2009.
(1,106 BBtu/d)
Expire in 2012-2014.
Williams Gas Marketing, Inc.
(53 BBtu/d)
Expires in 2009.
(113 BBtu/d)
Expires in 2010.
(350 BBtu/d)
Expire in 2011-2013.
Anadarko Petroleum Corporation
(70 BBtu/d)
Expires in 2008.
(12 BBtu/d)
Expires in 2009.
(80 BBtu/d)
Expires in 2010.
(128 BBtu/d)
Expire in 2011-2015.
WIC(1)
Approximately 50 firm and
interruptible customers
Approximately 50
firm transportation
contracts. Weighted
average remaining
contract term of
approximately ten
years.
WIC competes with
existing pipelines
to provide
transportation
services from supply basins in northwest Colorado, eastern Utah and
Wyoming to
pipeline
interconnects in
northeast Colorado,
and western Wyoming.
Major Customers:
Williams Gas Marketing, Inc.
(25 BBtu/d)
Expires in 2008.
(84 BBtu/d)
Expires in 2010.
(744 BBtu/d)
Expire in 2013-2021.
Anadarko Petroleum Corporation
(25 BBtu/d)
Expires in 2008.
(810 BBtu/d)
Expire in 2009-2022.
(1)
Information included has been adjusted to reflect the
completion of the Kanda expansion project placed in service in
January 2008.
Regulatory Environment. 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 interstate pipeline systems and storage
facilities operates under tariffs approved by the FERC that establish rates, cost recovery
mechanisms, and terms and conditions for services to our customers. Generally, the FERC’s authority
extends to:
•
rates and charges for natural gas transportation, storage and related services;
•
certification and construction of new facilities;
•
extension or abandonment of services and facilities;
•
maintenance of accounts and records;
•
relationships between pipelines and certain 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 of the U.S. Department of Transportation,
the U.S. Department of Interior and the U.S. Coast Guard. We have ongoing inspection programs
designed to keep our facilities in compliance with pipeline safety and environmental requirements,
and we believe that our systems are in material compliance with the applicable regulations.
Our Exploration and Production segment’s business strategy focuses on the exploration
for and the acquisition, development and production of natural gas, oil and NGL in the United
States, Brazil and Egypt. As of December 31, 2007, we controlled over four million net leasehold
acres and our proved natural gas and oil reserves at December 31, 2007, were approximately 2.9
Tcfe, which does not include 0.2 Tcfe related to our unconsolidated investment in Four Star Oil and Gas Company
(Four Star). During 2007, daily equivalent natural gas production averaged approximately 792
MMcfe/d, not including 70 MMcfe/d from our equity investment in Four Star.
We completed the acquisition of Peoples Energy Production Company (Peoples) in September 2007
for $887 million. This acquisition upgraded our portfolio of assets across a number of our
operating regions, primarily the Onshore and Texas Gulf Coast regions. We are also further
upgrading our portfolio by selling selected non-core properties that no longer meet our strategic
objectives. In January 2008, we entered into agreements to sell $517 million of certain non-core
properties in our Onshore and Texas Gulf Coast regions with estimated proved reserves of 191 Bcfe
at December 31, 2007. While we do not anticipate exiting any region, our divestitures will be
weighted towards the Gulf of Mexico and south Texas areas. We have a balanced portfolio of
development and exploration projects, including long-lived and shorter-lived properties divided
into the following regions discussed below:
United States
Onshore. The Onshore region includes operations that are primarily focused on unconventional
tight gas sands, coal bed methane and lower risk conventional producing areas, which are generally
characterized by lower development costs, higher drilling success rates and longer reserve lives.
We have a large inventory of drilling prospects in this region. During 2007, we invested $543
million on capital projects, not including acquisitions, and production averaged 374 MMcfe/d. The
principal operating areas are listed below:
2007
Average
Net
Capital
Production
Area
Description
Acres
Investment
(MMcfe/d)
(In millions)
East Texas/North
Louisiana
(Arklatex)
Concentrated land positions primarily focused on
tight gas sands production in the Travis
Peak/Hosston, Bossier and Cotton Valley
formations. The Peoples acquisition added to our
existing asset in this area most notably in
Logansport, Bald Prairie, Bethany, Minden and
Bethany Longstreet fields. We also have land
positions in the Mississippi area, primarily in
Hub Field located on the southern edge of the
Mississippi Salt Basin.
113,000
$
260
136
Black Warrior Basin
Established shallow coal bed methane producing
areas of northwestern Alabama. We have high
average working interests in our operated
properties in addition to an average 50 percent
working interest covering approximately 46,000 net
acres operated by Black Warrior Methane which
produces from the Brookwood Field.
171,000
$
51
62
Mid-Continent
Primarily in Oklahoma with a focus on development
projects in the Arkoma Basin where we utilize
horizontal drilling in the Hartshorne Coals area,
West Verdon Field, an oil producing waterflood
project and shallow natural gas production in the
Hugoton field.
456,000
$
40
30
Rocky Mountains
(Rockies)
Primarily in Wyoming and Utah with a focus in the
Powder River and Uinta basins, consisting
predominantly of operated oil fields utilizing
both primary and secondary recovery methods
combined with non-operated coal bed methane
fields. We operate the Altamont and Bluebell
processing plants and related gathering systems in
Utah. We also have a non-operated working
interest primarily in the Stadium Unit in the
Williston Basin of North Dakota, which is
undergoing secondary recovery.
Primarily focused on coal bed methane production
in northern New Mexico and southern Colorado where
we own the minerals and have a 100 percent working
interest in the Vermejo Park Ranch. We also have
working interests in land positions in the San
Juan Basin primarily in the Fruitland Coal and
Dakota formations and the tight gas formations in
Pictured Cliffs and Mesaverde.
605,000
$
113
75
Included
in our Mid-Continent operating area are our interests in 127,000 net acres in West Virginia
and 122,000 net acres in the Illinois Basin, primarily in the New Albany Shale area in southwestern
Indiana. We are the operator of these properties and maintain a 50 percent working interest in this
large emerging area which is still under evaluation. We have drilled
34 gross wells in this basin through the end
of 2007.
Texas Gulf Coast. The Texas Gulf Coast region focuses on developing and exploring for tight
gas sands in south Texas and the upper Gulf Coast of Texas. In this area, we have an inventory of
over 10,000 square miles of three dimensional (3D) seismic data. During 2007, we acquired producing
properties and undeveloped acreage in Zapata County, Texas for $254 million. During 2007, we also
invested $327 million on capital projects and production averaged 213 MMcfe/d. The principal
operating areas are listed below:
2007
Average
Capital
Production
Area
Description
Net Acres
Investment
(MMcfe/d)
(In millions)
Vicksburg/Frio Trends
Includes
concentrated and
contiguous assets,
located in south
Texas, including
the Jeffress and
Monte Christo
fields primarily in
Hidalgo County, in
which we have an
average 90 percent
working interest.
We also have assets
in the Alvarado and
Kelsey fields and
in Starr and Brooks
Counties with an
average working
interest of over 65
percent.
83,000
$
128
132
Upper Gulf Coast Wilcox
Located onshore
Texas Gulf Coast,
including Renger,
Dry Hollow, Brushy
Creek and Speaks
fields in Lavaca
County and
Graceland Field,
located in
Colorado, County.
37,000
$
56
32
South Texas Wilcox
Includes positions
in which we have
working interests
in Bob West,
Jennings Ranch and
Roleta fields in
Zapata County. We
also have working
interests in the
Laredo and Loma
Novia fields in
Webb and Duval
counties.
Gulf of Mexico and south Louisiana. Our Gulf of Mexico and south Louisiana operations are
generally characterized by relatively high initial production rates, resulting in near-term cash
flows, and high decline rates. During 2007, we invested $309 million on drilling, workover and
facilities projects and production averaged 191 MMcfe/d. The principal operating areas are listed
below:
2007
Average
Capital
Production
Area
Description
Net Acres
Investment
(MMcfe/d)
(In millions)
Gulf of Mexico
Primarily drilling
interests in 148
Blocks south of the
Louisiana, Texas
and Alabama
shorelines focused
on deep (greater
than 12,000 feet)
natural gas and oil
reserves in
relatively shallow
water depths (less
than 300 feet).
543,000
$
281
174
South Louisiana
Primarily in
Vermilion Parish
and associated bays
and inland waters
in southwestern
Louisiana covered
by the Catapult 3D
seismic project. We
have internally
processed 2,800
square miles of
contiguous 3D
seismic data in
this project.
21,000
$
28
17
Unconsolidated Investment in Four Star. During the third quarter of 2007, we increased our
ownership interest in Four Star from 43 percent to 49 percent. Four Star operates onshore in the
San Juan, Permian, Hugoton and South Alabama Basins and the Gulf of Mexico. During 2007, our
proportionate share of Four Star’s daily equivalent natural gas production averaged approximately
70 MMcfe/d and at December 31, 2007, proved natural gas and oil reserves, net to our interest, were
0.2 Tcfe.
International
Brazil. Our Brazilian operations cover approximately 361,000 net acres. During 2007, we
invested $220 million on capital projects in Brazil. Our operations include interests in 13
concessions located in the Espirito Santo, Potiguar and Camamu Basins, including our 35 percent
working interest in the Pescada-Arabaiana Fields in the Potiguar Basin. We currently own 100
percent of the BM-CAL-4 concession which includes the Pinauna project. During 2007, we completed
drilling two successful exploratory wells that extended the southern limits of the Pinauna project.
We are currently assessing development options and have a process underway to potentially market up
to a 50 percent non-operating interest in this concession. In addition, we completed drilling and
testing two exploratory wells with Petrobras in the ES-5 Block in the Espirito Basin. These wells
confirmed the extension of an earlier discovery by Petrobras on a block to the south. Our
production in Brazil, primarily attributable to the Pescada-Arabaiana Fields, averaged
approximately 14 MMcfe/d in 2007.
Egypt. Our Egyptian operations include a 20 percent non-operated working interest in
approximately 13,000 net acres in the South Feiran concession located in the Gulf of Suez. We are
currently in the seismic, exploratory drilling and evaluation phases of the project. Our total
funding commitment to the South Feiran concession is $3 million. In 2007, we received formal
government approval and signed the concession agreement for the South Mariut Block. The block is
approximately 1.2 million acres and is located onshore in the western part of the Nile Delta. We
paid $3 million for the concession and agreed to a $22 million firm working commitment over three
years. We are currently performing seismic evaluations on the block and expect to drill our first
exploratory well in late 2008.
Natural Gas, Oil and Condensate and NGL Reserves and Production
The table below presents our estimated proved reserves by region and classification as of
December 31, 2007 based on an internal reserve report as well as our 2007 production by region. 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.
Net Proved Reserves
2007
Natural Gas
Oil/Condensate
NGL
Total
Production
(MMcf)
(MBbls)
(MBbls)
(MMcfe)
(Percent)
(MMcfe)
Reserves and Production by Region
United States
Onshore
1,567,666
36,308
301
1,787,318
63
%
136,701
Texas Gulf Coast
471,448
3,806
9,205
549,513
19
%
77,633
Gulf of Mexico and
south Louisiana
207,546
9,560
608
268,555
9
%
69,671
Total United States
2,246,660
49,674
10,114
2,605,386
91
%
284,005
Brazil
51,206
32,710
—
247,468
9
%
5,237
Total
2,297,866
82,384
10,114
2,852,854
100
%
289,242
Unconsolidated investment in
Four Star
200,109
2,858
6,411
255,722
100
%
25,470
Reserves by Classification
United States
Producing
1,419,621
26,578
6,679
1,619,159
62
%
Non-Producing
318,475
8,492
1,453
378,147
15
%
Undeveloped
508,564
14,604
1,982
608,080
23
%
Total proved
2,246,660
49,674
10,114
2,605,386
100
%
Brazil
Producing
15,229
342
—
17,281
7
%
Non-Producing
3,414
338
—
5,444
2
%
Undeveloped
32,563
32,030
—
224,743
91
%
Total proved
51,206
32,710
—
247,468
100
%
Worldwide
Producing
1,434,850
26,920
6,679
1,636,440
58
%
Non-Producing
321,889
8,830
1,453
383,591
13
%
Undeveloped
541,127
46,634
1,982
832,823
29
%
Total proved
2,297,866
82,384
10,114
2,852,854
100
%
Unconsolidated investment in
Four Star
Producing
167,114
2,804
5,316
215,828
85
%
Non-Producing
3,072
—
29
3,246
1
%
Undeveloped
29,923
54
1,066
36,648
14
%
Total Four Star
200,109
2,858
6,411
255,722
100
%
Our consolidated reserves in the table above are 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 Company, L.P. (Ryder Scott), an independent reservoir engineering firm that
reports to the Audit Committee of our Board of Directors, conducted an audit of the estimates of 84
percent of our consolidated proved natural gas and oil reserves as of December 31, 2007. The scope
of the audit performed by Ryder Scott included the preparation of an independent estimate of proved
natural gas and oil reserves estimates for fields comprising greater than 80 percent of our total
worldwide present value of future cash flows (pretax). The specific fields included in Ryder
Scott’s audit represented the largest fields based on value. Ryder Scott also conducted an audit of the estimates of 75 percent of the proved natural gas and oil reserves
of Four Star, our unconsolidated affiliate. Our estimates of Four Star’s proved natural gas and oil
reserves are prepared by our internal reservoir engineers and do not reflect
those prepared by the engineers of Four Star. Based on the amount of proved reserves determined by Ryder Scott, we
believe our reported reserve amounts are reasonable. Ryder Scott’s reports are included as exhibits
to this Annual Report on Form 10-K.
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 currently prescribed by
the Securities and Exchange Commission (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 declines as reserves
are depleted. Except to the extent we conduct successful exploration and development activities or
acquire additional properties with 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.
Acreage and Wells
The following tables detail (i) our interest in developed and undeveloped acreage at December31, 2007, (ii) our interest in natural gas and oil wells at December 31, 2007 and (iii) our
exploratory and development wells drilled during the years 2005 through 2007. Any acreage in which
our interest is limited to owned royalty, overriding royalty and other similar interests is
excluded.
Developed
Undeveloped
Total
Gross(1)
Net(2)
Gross(1)
Net(2)
Gross(1)
Net(2)
Acreage
United States
Onshore
1,026,566
627,034
1,524,237
1,075,443
2,550,803
1,702,477
Texas Gulf Coast
173,282
119,025
114,842
80,396
288,124
199,421
Gulf of Mexico and south Louisiana
517,597
376,378
220,314
187,506
737,911
563,884
Total United States
1,717,445
1,122,437
1,859,393
1,343,345
3,576,838
2,465,782
Brazil
49,262
17,242
1,158,643
343,563
1,207,905
360,805
Egypt
—
—
1,247,064
1,195,272
1,247,064
1,195,272
Worldwide Total
1,766,707
1,139,679
4,265,100
2,882,180
6,031,807
4,021,859
(1)
Gross interest reflects the total acreage we participated in, regardless of our ownership interest in the acreage.
(2)
Net interest is the aggregate of the fractional working interests that we have in the gross acreage.
In the United States, our net developed acreage is concentrated primarily in the Gulf of
Mexico (33 percent), Texas (13 percent), Utah (11 percent), New Mexico (10 percent), Alabama (8
percent), Oklahoma (8 percent) and Louisiana (7 percent). Our net undeveloped acreage is
concentrated primarily in New Mexico (34 percent), the Gulf of Mexico (14 percent), Wyoming (10
percent), West Virginia (10 percent), Indiana (8 percent), Alabama (6 percent) and Texas (6
percent). Approximately 14 percent, 8 percent and 5 percent of our total United States net
undeveloped acreage is held under leases that have minimum remaining primary terms expiring in
2008, 2009 and 2010. Approximately 17 percent, 14 percent and 17 percent of our total Brazilian net
undeveloped acreage is held under leases that have minimum remaining primary terms expiring in
2008, 2009 and 2010. Approximately 30 percent of our total Egyptian net undeveloped acreage is held
under leases that have minimum remaining primary terms expiring in 2010. We employ various techniques to manage the expiration of leases, including extending lease terms,
drilling the acreage ourselves, or through farm-out agreements with other operators.
Gross interest reflects the total wells we participated in, regardless of our ownership interest.
(2)
Net interest is the aggregate of the fractional working interests that we have in the gross wells or gross wells drilled.
(3)
At December 31, 2007, we operated 4,905 of the 5,450 net productive wells.
(4)
In 2007, there was a reduction in the number of non-operated development wells drilled in the Rockies and an increase in the number of exploration wells drilled in the Raton Basin.
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 and average production costs (including production taxes) associated with the
sale of natural gas and oil for each of the three years ended December 31:
2007
2006
2005
Consolidated Volumes, Prices, and Costs per Unit:
Net Production Volumes
United States
Natural gas (MMcf)
238,021
213,262
206,714
Oil, condensate and NGL (MBbls)
7,664
7,439
7,516
Total (MMcfe)
284,005
257,899
251,807
Brazil(1)
Natural gas (MMcf)
4,295
7,140
15,578
Oil, condensate and NGL (MBbls)
157
247
620
Total (MMcfe)
5,237
8,619
19,300
Worldwide
Natural gas (MMcf)
242,316
220,402
222,292
Oil, condensate and NGL (MBbls)
7,821
7,686
8,136
Total (MMcfe)
289,242
266,518
271,107
Total (MMcfe/d)
792
730
743
Natural Gas Average Realized Sales Price ($/Mcf)
United States
Excluding hedges
$
6.60
$
6.77
$
7.92
Including hedges
$
7.36
$
6.50
$
6.69
Brazil
Excluding hedges
$
2.61
$
2.61
$
2.33
Including hedges
$
2.61
$
2.61
$
2.33
Worldwide
Excluding hedges
$
6.53
$
6.64
$
7.53
Including hedges
$
7.28
$
6.38
$
6.39
Oil, Condensate and NGL Average Realized Sales Price ($/Bbl)
Production volumes in Brazil decreased due to a contractual reduction of our ownership interest in the Pescada-Arabaiana Fields in early 2006.
(2)
Includes our proportionate share of volumes in Four Star which was acquired in 2005. In the third quarter of 2007, we increased our ownership interest in Four Star from 43 percent to 49 percent.
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:
2007
2006
2005
(In millions)
United States
Acquisition Costs:
Proved
$
964
$
2
$
643
Unproved
262
34
143
Development Costs
735
738
503
Exploration Costs:
Delay rentals
6
6
3
Seismic acquisition and reprocessing
19
23
7
Drilling
373
294
133
Asset Retirement Obligations
38
3
1
Total full cost pool expenditures
2,397
1,100
1,433
Non-full cost pool expenditures
13
8
22
Total costs incurred(1)
$
2,410
$
1,108
$
1,455
Acquisition
of unconsolidated investment in Four Star(2)
$
27
$
—
$
769
Brazil and Other International(1)
Acquisition Costs:
Proved
$
—
$
2
$
8
Unproved
5
1
1
Development Costs
26
40
6
Exploration Costs:
Seismic acquisition and reprocessing
6
7
7
Drilling
193
46
8
Asset Retirement Obligations
7
—
—
Total full cost pool expenditures
237
96
30
Non-full cost pool expenditures
1
—
—
Total costs incurred
$
238
$
96
$
30
Worldwide
Acquisition Costs:
Proved
$
964
$
4
$
651
Unproved
267
35
144
Development Costs
761
778
509
Exploration Costs:
Delay rentals
6
6
3
Seismic acquisition and reprocessing
25
30
14
Drilling
566
340
141
Asset Retirement Obligations
45
3
1
Total full cost pool expenditures
2,634
1,196
1,463
Non-full cost pool expenditures
14
8
22
Total costs incurred(1)
$
2,648
$
1,204
$
1,485
Acquisition of unconsolidated investment in Four Star(2)
$
27
$
—
$
769
(1)
Costs incurred for Egypt were $10 million and $4 million for the years ended December 31, 2007 and 2006.
(2)
In 2005, amount includes deferred tax adjustments of $179 million 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 $200 million in 2007, $192 million in 2006 and $247 million in 2005 to
develop proved undeveloped reserves that were included in our reserve report as of January 1 of
each year.
We primarily sell our domestic natural gas and oil to third parties through our Marketing
segment at spot market prices, subject to customary adjustments. 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, Brazil’s state-owned energy company. We also
enter into derivative contracts on our natural gas and oil production to stabilize our cash flows,
reduce the risk and financial impact of downward commodity price movements and to protect the
economic assumptions associated with our capital investment programs. As of December 31, 2007, our
Exploration and Production segment had entered into derivative swap and option contracts on
approximately 141 TBtu of our anticipated 2008 natural gas production, 16 TBtu of our total
anticipated 2009-2012 natural gas production, basis swaps on 97 TBtu of our anticipated 2008
production and 15 TBtu of our total anticipated 2009-2012 natural gas production and fixed price
swaps on 2,498 MBbls of our anticipated 2008 oil production. For a further discussion of these
contracts, see Part II, Item 7, Management’s Discussion and Analysis of Financial Condition and
Results of Operations. Our Marketing segment has also entered into additional production related
derivative contracts as further described below.
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.
Regulatory Environment. Our natural gas and oil exploration and production activities are
regulated at the federal, state and local levels, in the United States, Brazil and Egypt. These
regulations include, but are not limited to, those governing 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 exploration and production operations in
Brazil and Egypt are subject to environmental regulations administered by those governments, which
include political subdivisions in those countries. These domestic and international laws and
regulations affect 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 pollution liability exposures.
Our Marketing 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 risk, primarily through
the use of natural gas and oil derivative contracts. In addition, we continue to manage and
liquidate various natural gas supply, transportation, power and other natural gas related contracts
remaining from our legacy trading activities, which were primarily entered into prior to the
deterioration of the energy trading environment in 2002. As of December 31, 2007, we managed the
following types of contracts:
•
Production-Related Natural Gas and Oil Derivative Contracts. Includes options that
provide price protection on our Exploration and Production segment’s natural gas and oil
production.
•
Natural Gas Transportation-Related Contracts. Includes contracts that provide
transportation capacity primarily with our affiliates.
•
Legacy Natural Gas and Power Contracts. Includes a variety of natural gas derivative
contracts and long-term supply obligations, including our Midland Cogeneration Venture
(MCV) supply agreement and power contracts in the
Pennsylvania-New Jersey-Maryland (PJM) region.
Production-Related Natural Gas and Oil Derivative Contracts
Our natural gas and oil contracts include options designed to provide price protection to El
Paso from fluctuations in natural gas and oil prices. These contracts are in addition to contracts
entered into by our Exploration and Production segment described in
that segment. For a further
discussion of the entirety of El Paso’s production-related price risk management activities, refer
to Item 7, Management’s Discussion and Analysis of
Financial Condition, Results of Operations and Liquidity and Capital Resources. As of December 31, 2007, our Marketing segment’s
contracts provided El Paso with price protection on the following quantities 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. 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, 2007:
Affiliated Pipelines(1)
Other Pipelines
Daily capacity (MMBtu/d)
521,000
63,000
Expiration
2009 to 2028
2012 to 2026
Receipt points
Various
Various
Delivery points
Various
Various
(1)
Primarily consists of contracts with TGP and EPNG.
Other natural gas contracts. As of December 31, 2007, we had eight significant physical
natural gas contracts with power plants associated with our legacy trading activities, including
MCV. We sold our equity investment in the MCV power facility in 2006. These contracts obligate us
to sell gas to these plants and have various expiration dates ranging from 2008 to 2028, with
expected obligations under individual contracts with third parties ranging from 12,550 MMBtu/d to
130,000 MMBtu/d.
Power contracts. As of December 31, 2007, we had four derivative contracts that require us to
swap locational differences in power prices between four power plants in the PJM eastern region with the PJM west hub. In total, these contracts require us
annually to swap locational differences in power prices on approximately 4,000 GWh of power through
2008; 3,700 GWh from 2009 to 2012; 2,400 GWh for 2013 and 1,700 GWh from 2014 to 2016.
Additionally, these contracts require us to provide installed capacity of approximately 71 GWh per
year in the PJM power pool through 2016. While we have basis and capacity risk associated with the
contracts, we do not have commodity risk associated with these contracts due to positions we put in
place prior to 2007.
Markets, Competition and Regulatory Environment
Our Marketing 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 major oil and natural gas producers and their affiliates, large
domestic and foreign utility companies, large local distribution companies and their affiliates,
other interstate and intrastate pipelines and their affiliates, and independent energy marketers
and financial institutions. Our marketing activities are subject to the regulations of among
others, the FERC and the Commodity Futures Trading Commission.
Power Segment
As of December 31, 2007, our Power segment primarily included the ownership and operation of
our remaining investments in international power generation facilities listed below. These
facilities primarily sell power under long-term power purchase agreements with power transmission
and distribution companies owned by local governments. As a result, we are subject to certain
political risks related to these facilities. We continue to pursue the sale of our remaining power
investments.
Ownership of these plants transferred to the power purchaser in January 2008.
(2)
In the third quarter of 2007, we received an offer from our partners to purchase this investment. For further discussion, see Item 8, Financial Statements, Note 17.
(3)
In December 2007, we signed an agreement to sell this facility which is expected to close in the first half of 2008.
In addition to the international power plants above, we also have investments in two operating
pipelines in South America with a total design capacity and average 2007 throughput of 1,197 MMcf/d
and 1,162 BBtu/d, unadjusted for our ownership interest.
Regulatory Environment. 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 for private and
foreign-owned businesses. These regulatory and legal structures are subject to change over time.
Executive Vice President and Chief Financial Officer of El Paso
2005
46
Robert W. Baker
Executive Vice President and General Counsel of El Paso
2002
51
Brent Smolik
Executive Vice President of El Paso and President of El Paso
Exploration & Production Company
2006
46
Susan B. Ortenstone
Senior Vice President (Human Resources and Administration) of El Paso
2003
51
James C. Yardley
Executive Vice President, Pipeline
Group
2005
56
James J. Cleary
President of Western Pipeline Group
2005
53
Daniel B. Martin
Senior Vice President of Pipeline Operations
2005
51
Douglas L. Foshee has been President, Chief Executive Officer and a director of El Paso since
September 2003. He 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. Several subsidiaries of Halliburton, including DII Industries and Kellogg Brown & Root,
commenced prepackaged Chapter 11 proceedings to discharge current and future asbestos and silica
personal injury claims in December 2003 and an order confirming a plan of reorganization became
final effective December 31, 2004. Under the plan of reorganization, all current and future
asbestos and silica personal injury claims were channeled into trusts established for the benefit
of asbestos and silica claimants. Prior to assuming his position at Halliburton, Mr. Foshee was
President, Chief Executive Officer and Chairman of the Board of Nuevo Energy Company from 1997 to
2001. From 1993 to 1997, Mr. Foshee served Torch Energy Advisors Inc. in various capacities,
including Chief Executive Officer and Chief Operating Officer. Mr. Foshee serves on the Federal
Reserve Bank of Dallas, Houston Branch as a director. Mr. Foshee serves on the Board of Trustees of
Rice University, where he chairs the Building and Grounds Committee in addition to serving as a
member of the Council of Overseers for the Jesse H. Jones Graduate School of Management at Rice
University. He is a member of the Greater Houston Partnership Board and Executive Committee and
serves as Chair of the Environment Advisory Committee. In addition, Mr. Foshee serves on the Boards
of Central Houston, Inc., Children’s Museum of Houston, Goodwill Industries, Small Steps Nurturing
Center and the Texas Business Hall of Fame Foundation. Mr. Foshee serves on the board of directors
of El Paso Pipeline GP Company, L.L.C., the general partner of El Paso Pipeline Partners, L.P.
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 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 and El Paso Natural Gas
Company since 1986. Mr. Leland serves on the board of directors of El Paso Pipeline GP Company,
L.L.C.
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. Mr. Baker serves as Executive Vice
President and General Counsel of El Paso Pipeline GP Company, L.L.C.
Brent J. Smolik has been Executive Vice President of El Paso and President of El Paso
Exploration & Production Company since November 2006. Mr. Smolik was President of ConocoPhillips
Canada from April 2006 to October 2006. Prior to the Burlington Resources merger with
ConocoPhillips, he was President of Burlington Resources Canada from September 2004 to March 2006.
From 1990 to 2004, Mr. Smolik worked in various engineering management
and executive capacities for Burlington Resources Inc.
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. Ms. Ortenstone serves as Senior Vice President of El Paso Pipeline GP Company, L.L.C.
James C. Yardley has been Executive Vice President of El Paso with responsibility for the
regulated pipeline business unit since August 2006. He has also served as President of Southern
Natural Gas Company since May 1998 and President and Chairman of the Board of Tennessee Gas
Pipeline Company since August 2006. Mr. Yardley has also been Chairman of the Board of El Paso
Natural Gas Company since August 2006. He has been a member of the Management Committees of both
Colorado Interstate Gas Company and Southern Natural Gas Company since their conversion to general
partnerships in November 2007. Mr. Yardley served as Vice President, Marketing and Business
Development for Southern Natural Gas Company from April 1994 to April 1998. Prior to that time, he
worked in various capacities with Southern Natural Gas and Sonat Inc. beginning in 1978. Mr.
Yardley serves as Director, President and Chief Executive Officer of El Paso Pipeline GP Company,
L.L.C.
James J. Cleary has been President of El Paso Natural Gas Company and Colorado
Interstate Gas Company since January 2004. He also served as Chairman of the Board of El Paso
Natural Gas Company and Colorado Interstate Gas Company from May 2005 to August 2006. From January
2001 to 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
beginning in 1979. Mr. Cleary serves as Senior Vice President of El Paso Pipeline GP Company,
L.L.C
Daniel B. Martin has been Director of Colorado Interstate Gas Company, El Paso Natural Gas
Company, Southern Natural Gas Company and Tennessee Gas Pipeline Company since May 2005. He was
Director of ANR prior to its sale in February 2007. 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 Colorado Interstate Gas
Company since January 2001. He was Senior Vice President of ANR Pipeline prior to its sale in
February 2007. Prior to 2001, Mr. Martin worked in various capacities with Tennessee Gas Pipeline
Company since 1978. Mr. Martin serves as Senior Vice President of El Paso Pipeline GP Company,
L.L.C.
Available Information
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.
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. These forward-looking statements are based on assumptions or beliefs
that we believe to be reasonable; however assumed facts almost always vary from the actual results,
and differences between assumed facts and actual results can be material, depending upon the
circumstances. Where, based on assumptions, 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 stated expectation or belief will
occur, 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), terrorist activity or acts of aggression, and
other hazards. Each of these risks could result in damage to or destruction of our facilities or
damages or injuries to persons and property causing us to suffer substantial losses.
While we maintain insurance against many of these risks to the extent and in amounts that we
believe are reasonable, our insurance coverages have material deductibles and self-insurance
levels, as well as limits on our maximum recovery, and do not cover all risks. As a result, our
results of operations, cash flows or financial condition 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 we transport and store is owned by third parties.
The results of our
transportation and storage operations are impacted by the volumes of natural gas
we transport or store and the prices we are able to charge for doing so. The volume of natural gas
we are able to transport and store 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,
or to remarket unsubscribed capacity on our pipeline systems:
changes in regulation and action of regulatory bodies;
•
weather conditions that impact throughput and storage levels;
•
price competition;
•
drilling activity and decreased availability of conventional gas supply sources and the
availability and timing of other natural gas supply sources, such as LNG;
continued development of additional sources of gas supply
that can be accessed;
•
decreased natural gas demand due to various factors,
including increases in prices and the availability or increased demand of alternative energy sources
such as hydroelectric power, nuclear energy, wind, solar, coal and fuel oil;
•
availability and cost of capital to fund ongoing maintenance and growth projects;
•
opposition to energy infrastructure development, especially in environmentally sensitive
areas;
•
adverse general economic conditions including prolonged recessionary periods that might
negatively impact natural gas demand and the capital markets;
•
expiration and/or renewal of existing interests in real property, including real property
on Native American lands; and
•
unfavorable movements in natural gas prices in certain supply and demand areas.
Certain of our systems’ transportation services are subject to long-term, fixed-price “negotiated
rate”contracts that are not subject to adjustment, even if our cost to perform such services
exceeds the revenues received from such contracts, and, as a result, our costs could exceed our
revenues received under such contracts.
It is possible that costs to perform services under “negotiated rate”contracts will exceed
the negotiated rates. Under FERC policy, a regulated service provider and a customer may mutually
agree to sign a contract for service at a “negotiated rate” which may be above or below the FERC
regulated “recourse rate” for that service, and that contract must be filed and accepted by FERC.
These “negotiated rate”contracts are not generally subject to adjustment for increased costs which
could be produced by inflation or other factors relating to the specific facilities being used to
perform the services. Any shortfall of revenue, representing the difference between “recourse
rates” (if higher) and negotiated rates, under current FERC policy is generally not recoverable
from other shippers.
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, extended or replaced. If we are unable to extend or
replace these contracts when they expire or renegotiate contract terms as favorable as the existing
contracts, we could suffer a material reduction in our revenues, earnings and cash flows. 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 natural gas supply points; and
•
regulatory actions.
Fluctuations in energy commodity prices could adversely affect our pipeline businesses.
Revenues generated by our transportation, storage and LNG contracts depend on volumes and
rates, both of which can be affected by the prices of natural gas and LNG. Increased prices could
result in a reduction of the volumes transported by our customers, including power companies that
may not dispatch natural gas-fired power plants if natural gas prices increase. 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 gas supplies to offset the natural
decline from existing wells connected to our systems, which requires the development of additional
oil and natural gas reserves, obtaining additional supplies from interconnecting pipelines, and the
development of LNG facilities on or near 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 impact the value of under or over recoveries of retained natural 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 on a short-term basis, as well as with respect to our
long-term recontracting activities. 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;
•
abundance of supplies of alternative energy sources; and
•
political unrest among countries producing oil and LNG.
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:
•
our ability to obtain necessary approvals and permits by the FERC and other regulatory
agencies on a timely basis and on terms that are acceptable to us;
•
the ability to obtain continued access to sufficient capital to fund expansion projects;
•
the availability of skilled labor, equipment, and materials to complete expansion
projects;
•
potential changes in federal, state and local statutes,
regulations, and orders, including
environmental requirements that prevent a project from proceeding or increase the
anticipated cost of the project;
•
impediments on our ability to acquire rights-of-way or land rights on a timely basis or
on terms that are acceptable to us;
•
our 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, contractor productivity or other factors beyond our control, that we may not be able
to recover from our
customers which may be material;
•
the lack of future growth in natural gas supply; and
•
the lack of transportation, storage or throughput commitments.
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 results of operations, cash flows or financial position.
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;
•
the availability and reliability of commodity processing, gathering and pipeline
capacity;
•
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;
•
weather conditions, such as unusually warm or cold weather, and hurricanes in the Gulf of
Mexico;
•
market uncertainty;
•
political conditions or hostilities in natural gas and oil producing regions;
•
worldwide economic conditions; and
•
changes in 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, 2007 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. A decline
in natural gas and oil prices could result in a downward revision of our reserves and a full cost
ceiling test 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 the following factors.
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 and increases in future costs 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 from other companies;
•
our ability to successfully integrate acquisitions;
•
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;
•
governmental action affecting the profitability of our exploration and production
activities, such as increased royalty rates payable on oil and gas leases, the imposition of
additional taxes on such activities or the modification or withdrawal of tax incentives in
favor of exploration and development activity;
•
our lack of control over jointly owned properties and
properties operated by others;
•
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 of drilling
rights 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 inherently imprecise.
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 developed non-producing reserves and proved developed reserves that
are early in their production life. As a result, our reserve estimates are inherently imprecise. We
also use a ten percent discount factor for estimating the value of our future net cash flows from
reserves and a one-day spot price (typically the last day of the year), each as prescribed by the
SEC. This discount factor 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. Additionally, this one day
spot price will not generally represent the market prices for natural gas and oil over time. 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 which
will eventually result 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, if our capital resources become limited,
or if our exploration, development and acquisition activities are unsuccessful, 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. Our competitors include the major and independent natural gas and oil companies,
individual producers, gas marketers and major pipeline companies some of which have financial and
other resources that are substantially greater than those available to us, as well as participants
in other industries supplying energy and fuel to industrial, commercial and individual consumers.
In order to expand our leased land positions in intensively competitive and desirable areas, we
must identify and precisely locate prospective geologic structures, identify and review any
potential risks and uncertainties in these areas, and drill and successfully complete wells in a
timely manner. Our future success and profitability in the production business may be negatively
impacted if we are unable to identify these risks or uncertainties and 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, 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 as hedges or do not qualify as hedges, changes in commodity prices, interest rates,
volatility, correlation factors and the liquidity of the market could cause our revenues and net
income 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 could otherwise experience if commodity prices or
interest rates were to change favorably. The use of derivatives, to
the extent they require collateral posting with our counterparties,
could impact our
working capital (current assets less current 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 7.
Our foreign operations and investments involve special risks.
Our activities in areas outside the United States, including power, pipeline and exploration
and production projects in Brazil, exploration and production
projects in Egypt and pipeline projects in Mexico, are subject to
the risks inherent in foreign operations. As a general rule, we have elected not to carry political
risk insurance against these sorts of risks including:
•
loss of revenue, property and equipment as a result of hazards such as wars or
insurrection;
•
the effects of currency fluctuations and exchange controls, such as devaluation of
foreign currencies and other economic problems;
•
changes in laws, regulations and policies of foreign governments, including those
associated with changes in the governing parties, nationalization, and expropriation; and
•
protracted delays in securing government consents, permits, licenses, customer
authorizations or other regulatory approvals necessary to conduct our operations.
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 and either retained certain liabilities or
indemnified certain purchasers against future liabilities relating to businesses and assets sold,
including breaches of warranties, environmental expenditures, asset maintenance, tax, litigation,
personal injury claims 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 amounts in the future and these amounts could be material. We have experienced
substantial reductions and turnover in the workforce that previously supported the ownership and
operation of such assets which could result in difficulties in managing these businesses, including
a reduction in historical knowledge of the assets and businesses and in managing the liabilities
retained after closing or defending any associated litigation.
Our business requires the retention and recruitment of a skilled workforce and the loss of
employees could result in the failure to implement our business plans.
Our pipeline and exploration and production businesses require the retention and recruitment
of a skilled workforce. If we are unable to retain and recruit employees such as engineers and
other technical personnel, our business could be negatively impacted.
Risks Related to Legal and Regulatory Matters
The outcome of pending governmental investigations could be materially adverse to us.
We are subject to various governmental investigations by one or more of the following
governmental agencies: the SEC, FERC and the U.S. Department of Transportation Office of Pipeline
Safety. Although we are cooperating with the governmental agency or
agencies in these investigations, the outcome of each of these investigations and the costs to the
Company of responding and participating in these investigations is uncertain. The ultimate costs
and sanctions, if any, that may be imposed upon us could have a material adverse effect on our
business, financial condition or results of operation.
The agencies that regulate our pipeline businesses and their customers could 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 and local regulatory agencies whose actions 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 and sets authorized rates of
return. The FERC uses a discounted cash flow model that incorporates the use of proxy groups to
develop a range of reasonable returns earned on equity interests in companies with corresponding
risks. The FERC then assigns a rate of return on equity within that range to reflect specific
risks of that pipeline when compared to the proxy group companies. The FERC had been using a proxy
group of companies that included local distribution companies that are not faced with as much
competition or risk as interstate pipelines. The inclusion of these lower risk companies could
have created downward pressure on tariff rates when subjected to review by the FERC in future rate
proceedings. Recently, the U.S. Court of Appeals for the DC Circuit issued a decision
that would require the FERC, if it utilizes lower risk companies in the proxy group, to make upward
adjustments to the return on equity to compensate for their lower level of risk. Pursuant to the
FERC’s jurisdiction over rates, existing rates may be challenged by complaint and proposed
rate increases may be challenged by protest. A successful complaint or protest against our
pipelines rates could have an adverse impact on our revenues. In addition, in July 2007, the FERC
issued a proposed policy statement addressing the issue of the proxy groups it will use to decide
the return on equity of natural gas pipelines. The proposed policy statement describes the FERC’s
intention to allow the use of master limited partnerships in proxy groups, which we and other
pipelines have advocated. However, the FERC also proposed certain restrictions that would reduce
the overall benefit that pipelines would receive by use of master limited partnerships in the proxy
group. Through our trade association, we have filed comments on the policy and participated in a
public conference on this subject.
Additionally,
we formed El Paso Pipeline Partners, L.P., a master limited
partnership, in 2007.
The FERC currently allows publicly traded partnerships to include in their cost-of-service an
income tax allowance. Any changes to FERC’s treatment of income tax allowances in cost of service
and to potential adjustment in a future rate case of our pipelines’ respective equity rates of
return that underlie their recourse rates may cause their recourse rates to be set at a level that
is different, and in some instances lower than the level otherwise in effect, could negatively
impact our investment in El Paso Pipeline Partners, L.P.
Also, 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 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. Although we believe we have
established appropriate reserves for our environmental liabilities, it is not possible for us to
estimate the exact amount and timing of all future expenditures related to environmental matters
and we could be required to set aside additional amounts which could significantly impact our
future consolidated results of operations, cash flows or financial position. See Part I, Item 3,
Legal Proceedings and Part II, Item 8, Financial Statements and Supplementary Data, Note 12.
In estimating our environmental liabilities, we face uncertainties that include:
•
estimating pollution control and clean up costs, including sites where preliminary site
investigation or assessments have been completed;
•
discovering new sites or additional information at existing sites;
•
quantifying liability under environmental laws that impose joint and several liability on
all potentially responsible parties;
•
evaluating and understanding environmental laws and regulations, including their
interpretation and enforcement; and
•
changing environmental laws and regulations that may increase our costs.
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 which has been ratified by some of the
international countries in which we have operations such as Mexico, Brazil, and Egypt. In the
United States, various federal legislative proposals have been made over the last several years. It
is difficult to predict the timing of enactment of any federal legislation, as well as the ultimate
legislation that will be enacted. However, components of the legislation that have been proposed
in the past could negatively impact our operations and financial results, including whether any of
our facilities are designated as the point of regulation for GHG emissions, whether the federal
legislation will expressly preempt the potentially conflicting state GHG legislation and how
inter-fuel issues will be handled, including how allowances are granted and whether caps will be
imposed on GHG charges.
Legislation and regulation are also in various stages of proposal, enactment, and
implementation in many of the states in which we operate. This includes various initiatives of
individual states and coalition of states in the northeastern portion of the United States that are
members of the Regional Greenhouse Gas Initiative and seven western states that are members of the
Western Climate Initiative.
Additionally, various governmental entities and environmental groups have filed lawsuits
seeking to force the federal government to regulate GHG emissions and individual companies to
reduce the GHG emissions from their operations. These and other suits may also result in decisions
by federal agencies and state courts and other agencies that impact our operations and ability to
obtain certifications and permits to construct future projects.
These legislative, regulatory, and judicial actions could result in changes to our operations
and to the consumption and demand for natural gas and oil. Changes to our operations could include
increased costs to (i) operate and maintain our facilities, (ii) install new emission controls on
our facilities, (iii) construct new facilities, (iv) acquire allowances to authorize our GHG
emissions, (v) pay any taxes related to our GHG emissions and (vi) administer and manage a GHG
emissions program.
While we may be able to include some or all of any costs in our rates charged by our pipelines
and in the prices at which we sell natural gas and oil, such recovery of costs is uncertain and may
depend on events beyond our control including the outcome of future rate proceedings before the
FERC and the provisions of any final legislation.
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 (see Part
II, Item 8, Financial Statements and Supplementary Data, Note 12). 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 amounts in the future and these amounts
could be material.
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
El Paso’s senior unsecured indebtedness are below investment grade, currently rated Ba3 with a
positive outlook by Moody’s Investor Service (Moody’s) and BB- with a positive outlook by Standard
& Poor’s. These ratings have increased our cost of capital and our operating costs, particularly in
our marketing operations, and could impede our access to capital markets. Although we must retain
greater liquidity levels to operate our business than if we had investment grade credit ratings,
the simplification of our capital structure and business has reduced the amount of liquidity we
maintain in the ordinary course of business. If there is significant volatility in energy commodity
prices or interest rates, then these lower liquidity levels might not be adequate. In such an
event, if our ability to generate or access capital becomes significantly restrained, then our
financial condition and future results of operations could be significantly adversely affected. See
Part II, Item 8, Financial Statements and Supplementary Data, Note 11, for a further discussion of
our debt.
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 contain cross default provisions. A breach of any of these covenants
could preclude us or our subsidiaries from issuing letters of credit, 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.
Additionally, some of our credit agreements are collateralized by our equity interests in EPNG
and TGP as well as certain natural gas and oil reserves. A breach of the covenants under these
agreements could permit the lenders to exercise their rights to foreclose on these collateral
interests.
Adverse changes in general domestic economic conditions could adversely affect our operating
results, financial condition, or liquidity.
We are subject to the risks arising from adverse changes in general domestic economic
conditions including recession or economic slowdown. Recently, the direction and relative strength
of the U.S. economy has been increasingly uncertain due to softness in the housing markets, rising
oil prices, and difficulties in the financial services sector. If economic growth in the United
States is slowed, demand growth from consumers for natural gas and oil produced and transported by
us on our natural gas transportation systems may decrease which could impact our planned growth
capital. Additionally, our access to capital could be impeded. Any of
these events, which are beyond our control, could negatively impact our business, results of operations, financial condition, and liquidity.
We are subject to financing and interest rate risks.
Our future success, financial condition and liquidity could be adversely affected based 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;
•
the unhedged portion of our exposure to interest rates;
•
the structured and commercial financial markets;
•
market perceptions of us or the natural gas and energy industry;
A description of our properties is included in Part I, Item 1, Business, and is incorporated
herein by reference.
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 12, and are
incorporated herein by reference.
Fort Morgan Storage Field. CIG owns and operates an underground natural gas storage field in
the vicinity of Fort Morgan, Colorado. In October 2006, the production casing in one of the field’s
injection and withdrawal wells failed resulting in the emergence of natural gas from the storage reservoir
at the ground surface. In June 2007, CIG received a proposed Administrative Order of Consent (AOC)
from the Colorado Oil and Gas Conservation Commission (Commission). In January 2008, the
Commission approved the AOC with a settlement of all alleged violations with a penalty of $374,000.
Rawlins Plant Notice of Probable Violation. CIG owns and operates the Rawlins Gas Plant and
Compressor Station which produces butane, propane, and natural gas liquids. Recently, CIG
discovered that emissions from the loading process were emitted into the atmosphere and reported
the discovery to the Wyoming Department of Environmental Quality (Department) which issued a Notice
of Violation. CIG has reached an agreement with the Department to pay a total of $83,000 and to
conduct a supplemental environmental program to install additional equipment which will reduce
future emissions.
Natural Buttes. On May 19, 2004, the Federal Environmental
Protection Agency (“EPA”) issued a
Compliance Order (“Order”) to
CIG related to alleged violations of a Title V air permit in effect at
CIG’s Natural Buttes Compressor Station. On July 7, 2004,
the EPA issued a confidential “Pre-filing Settlement Offer”
which contained a proposed fine of $350,000. In September
2005 the matter was referred to the U.S Department of Justice
(“DOJ”). We have entered into a tolling agreement with the
United States and have concluded settlement discussions in principle
with the DOJ and the EPA, setting a penalty of $470,000, which includes
$50,000 in incremental costs for a Supplemental Environmental Project.
We have established a reserve for this penalty amount, and we anticipate
a documented settlement in the first half of 2008.
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 February22, 2008, we had 33,757 stockholders of record, which does not include beneficial owners whose
shares are held by a clearing agency, such as a broker or bank.
Quarterly Stock Prices. 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
2007
Fourth Quarter
$
18.37
$
15.29
$
0.04
Third Quarter
18.56
15.00
0.04
Second Quarter
17.43
14.41
0.04
First Quarter
15.66
13.71
0.04
2006
Fourth Quarter
$
15.84
$
12.92
$
0.04
Third Quarter
16.39
12.82
0.04
Second Quarter
16.00
11.85
0.04
First Quarter
13.95
11.80
0.04
Stock Performance Graph. This graph reflects the comparative changes in the value of $100
invested since December 31, 2002 as invested in (i) El Paso’s common stock, (ii) the Standard &
Poor’s 500 Stock Index, (iii) the Standard & Poor’s 500 Oil & Gas Storage & Transportation Index
and (iv) our peer group identified below. The Peer Group we used for this comparison is the same
group we use to compare total shareholder return relative to our performance for compensation
purposes. Our peer group for 2007 included the following companies: Anadarko Petroleum Corp.,
Apache Corp., CenterPoint Energy Inc., Devon Energy Corp., Dominion Resources, Inc., Enbridge,
Inc., Equitable Resources, Inc., NiSource, Inc., ONEOK, Inc., PG&E Corp., PPL Corp., Questar Corp.,
Sempra Energy, Southern Union Co., Spectra Energy Corp., Transcanada Corp. and Williams Companies,
Inc. Our peer group for 2006 included the companies listed above as
well as Western Gas Resources, Inc. and Kinder Morgan, Inc., but did
not include Spectra Energy Corp.
S&P 500 Oil & Gas Storage & Transportation Index(1)
$
100
$
163.09
$
228.19
$
301.43
$
358.54
$
409.59
New Peer Group
$
100
$
137.32
$
172.32
$
225.16
$
254.39
$
319.86
Old Peer Group
$
100
$
137.51
$
172.76
$
226.38
$
256.51
$
328.44
(1)
The S&P 500 Oil & Gas Storage & Transportation Index
was created as of May 1, 2005 and thus, historical values
for this index were not available. Accordingly, we
provided this comparison against a custom index which
includes the companies in the Standard & Poor’s 500 Oil &
Gas Storage & Transportation Index, including El Paso.
(2)
The annual values of each investment are based on the
share price appreciation and assume cash dividend
reinvestment. The calculations exclude any applicable
brokerage commissions and taxes. Cumulative total
stockholder returns from each investment can be calculated
from the annual values given above.
Dividends Declared. On February 7, 2008, we declared a quarterly dividend of $0.04 per share
of our common stock, payable on April 1, 2008, to shareholders of record as of March 7, 2008.
Future dividends will depend on business conditions, earnings, our cash requirements and other
relevant factors.
Other. 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 restrictions 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 selected historical financial data as of and for the years ended
December 31, 2004 to 2007 is derived from our audited consolidated
financial statements for El Paso and its subsidiaries and is not necessarily indicative of results
to be expected in the future. The
amounts as of and for the year ended December 31, 2003, are
derived from unaudited consolidated financial statements. Such amounts were
adjusted to reflect the reclassification of ANR, our Michigan storage
assets and our 50% interest in Great Lakes Gas Transmission as
discontinued operations. The selected financial data 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.
Net income (loss) available to common stockholders
$
1,073
$
438
$
(633
)
$
(947
)
$
(1,883
)
Basic earnings (loss) per common share from continuing operations
$
0.57
$
0.73
$
(0.82
)
$
(1.61
)
$
(1.33
)
Diluted earnings (loss) per common share from continuing operations
$
0.57
$
0.72
$
(0.82
)
$
(1.61
)
$
(1.33
)
Cash dividends declared per common share
$
0.16
$
0.16
$
0.16
$
0.16
$
0.16
Basic average common shares outstanding
696
678
646
639
597
Diluted average common shares outstanding
699
739
646
639
597
Financial Position Data:
Total assets
$
24,579
$
27,261
$
31,840
$
31,398
$
36,968
Long-term financing obligations, less current maturities
12,483
13,329
16,282
17,506
19,193
Minority Interest
565
31
31
367
447
Stockholders’ equity
5,280
4,186
3,389
3,438
4,346
Factors Affecting Trends.
Prior to 2006, our financial position and operating results were substantially affected by the restructuring and
realignment of our business around our core pipeline and exploration and production operations.
Accordingly, we sold a substantial amount of non-core assets to reduce our long-term financing
obligations resulting in a significant reduction of our revenues and net income during the years
ended December 31, 2003, 2004, and 2005. We recorded net pretax charges of approximately $0.1
billion in 2005, $1.1 billion in 2004 and $1.3 billion in 2003, primarily as a result of losses and
impairments of assets and equity investments, restructuring charges, and settling litigation. In 2007, we sold our ANR pipeline
system and related assets and also completed the offering of common units in El Paso
Pipeline Partners, L.P., our master
limited partnership.
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Overview
Our Management’s Discussion and Analysis (MD&A) should be read in conjunction with our
consolidated financial statements and the accompanying footnotes. MD&A includes forward-looking
statements that are subject to risks and uncertainties that may result in actual results differing
from the statements we make. These risks and uncertainties are discussed further beginning on page
27. Listed below is a general outline of our MD&A:
Our
Business — includes a summary of our business purpose and description, factors influencing
profitability, a summary of our 2007 performance, an outlook for 2008 and an update of our credit
profile;
Results
of Operations — includes a year-over-year analysis beginning
on page 44 of the results of
our business segments, our corporate activities and other income statement items, including trends
that may impact our business in the future;
Liquidity
and Capital Resources — includes a general discussion
beginning on page 65 of our debt
obligations, available liquidity, expected 2008 cash flows, and significant factors that could
impact our liquidity, as well as an overview of cash flow activity during 2007;
Off Balance Sheet Arrangements, Contractual Obligations, and Commodity-Based Derivative
Contracts— includes a discussion beginning on page 68 of our (i) off balance sheet arrangements,
including guarantees and letters of credit, (ii) other contractual obligations, and (iii)
derivative contracts used to manage the price risks associated with our natural gas and oil
production and;
Critical
Accounting Estimates — includes a discussion beginning on
page 71 of accounting estimates
that involve the use of significant assumptions and/or judgments in the preparation of our
financial statements.
Our Business
Our business purpose is to provide natural gas and related energy products in a safe,
efficient and dependable manner. We own or have interests in North America’s largest interstate
natural gas pipeline systems and are a large independent natural gas and oil producer focused on
growing our reserve base through disciplined capital investment and portfolio management, cost
control and marketing and selling our natural gas and oil production at optimal prices while
managing associated price risks.
Factors Influencing Our Profitability. Our pipeline operations are rate-regulated and
accordingly we generate profit based on our ability to earn a return in excess of our costs through
the rates we charge our customers. Our exploration and production operations generate profits
dependent on the prices for natural gas and oil and the volumes we are able to produce, among other
factors. Our future profitability in each of our operating segments will be primarily influenced by
the following factors:
Pipelines
•
Successfully executing on our backlog of committed expansion projects and developing new
growth projects in our market and supply areas;
•
Contracting and recontracting pipeline capacity with our customers;
•
Maintaining or obtaining approval by FERC of acceptable rates and terms of
service; and
•
Improving operating efficiency.
Exploration and Production
•
Increasing our natural gas and oil proved reserve base and production volumes
through successful drilling programs and/or acquisitions;
•
Finding and producing natural gas and oil at a reasonable cost; and
•
Managing price risks to optimize realized prices on our natural gas and oil production.
In addition to these factors, our future profitability will also continue to be impacted by
our debt level and related interest costs, the successful resolution of our historical
contingencies and completing the orderly exit of our remaining power assets, historical derivative
contracts and other remaining non-core assets.
Summary of Overall Performance in 2007. The year ended December 31, 2007 marked our fifth
consecutive year of improved profitability, driven primarily by a strong base of earnings and cash flow in our
pipeline and exploration and production businesses as well as an interest expense reduction of
approximately 20 percent. Across our pipeline system, we made
progress on our backlog
of committed expansion projects and created El Paso Pipeline Partners, L.P., our master limited partnership.
In our exploration and production business, we experienced continued
success in our worldwide exploration and
drilling programs. These
successes allowed us to replace our worldwide natural gas and oil reserves and move forward in high
grading our portfolio to improve our cost structure. The following
provides additional details of these
items and other significant highlights in our core businesses in 2007:
Area of Operations
Significant Highlights
Pipelines
Completed and
entered into new expansion projects resulting in a
current backlog of almost $4 billion.
Completed the sale of ANR, our Michigan storage assets and our 50 percent interest
in Great Lakes Gas Transmission for net cash proceeds of approximately $3.7
billion
Implemented FERC approved rate case settlements for El Paso Natural Gas Company
and Mojave Pipeline Company
Completed a $575 million initial public offering of common units for El Paso
Pipeline Partners, L.P., a newly formed master limited partnership to enhance the
value and financial flexibility of our pipeline assets and provide a lower-cost
source of capital for new pipeline growth projects
Reached an agreement (completed
February 2008) to acquire a 50 percent interest in the Gulf LNG Clean
Energy project, which is constructing an LNG
regasification terminal in Mississippi
Exploration and
Production
Met production and cost targets established for 2007 with increased production
volumes in each quarter of 2007
High-graded our portfolio
through the acquisition of Peoples for $887 million,
adding proved reserves of 298 Bcfe, and progressed on our announced divestiture
program
Replaced 129% of our worldwide
natural gas and oil reserves, excluding acquisitions, and 252%
including acquisitions
Achieved success in our exploration programs in Brazil
Managed price risk through
derivative contracts which, when combined with our other
positions, provided higher realized commodity prices in 2007 and gives
us price protection on approximately two-thirds of our planned 2008
equivalent production.
In
addition, our 2007 performance was impacted by our Marketing
and Power segments where we continued to reduce the size and volatility of these operations
and by corporate costs incurred in conjunction with simplifying and strengthening our balance
sheet. Specifically, we incurred (i) mark-to-market losses in our Marketing segment on
production-related option contracts and legacy positions, including
our Pennsylvania-New Jersey-Maryland (PJM) power contracts and
(ii) incremental losses in our Power segment on Brazilian power
investments. Additionally, in 2007, we (i) incurred debt
extinguishment costs of approximately $291 million in
conjunction with repurchasing or refinancing more than
$5 billion of debt to strengthen our
balance sheet and
(ii) resolved certain legal and contractual disputes (see,
Item 8, Financial Statements and Supplementary Data, Note 12).
Outlook. For 2008, we expect the current operating trends in our core pipeline and
exploration and production businesses to continue with a focus on growing these businesses. For
each business, we expect the following:
Pipelines — We anticipate that our pipeline operations will continue to provide strong
operating results based on its expansion plans, the current levels of contracted capacity, and
the status of its rate and regulatory actions. In the pipeline industry, a favorable
macroeconomic environment supports continued industry growth. We expect to spend significant pipeline growth capital in 2008.
These expenditures should lay the foundation for future growth and
the advancement of our significant
backlog of committed expansion projects in our market and supply
areas and in the development of significant new infrastructure opportunities. Additionally, we will continue to pursue proposed joint venture
development projects that would use our incumbent pipeline infrastructure to
connect supply areas to areas of high demand in the West, Northeast and Southeast. Finally,
we expect to grow our MLP through organic growth opportunities, potential
acquisitions, or through future asset contributions.
Currently we have in excess of $2
billion in net operating losses available to us to offset any
potential tax gains on future asset
contributions to the MLP.
Exploration and Production — We expect to continue with the momentum established in 2007 and
seek to create value through a disciplined and balanced capital investment program. Our
drilling programs will focus on growing reserves at reasonable finding and development costs,
and growing production efficiently through active cost management. In 2008, our domestic
programs will constitute approximately 80 percent of our planned capital and substantially all of
our expected production. Performance of these programs will require successful integration
and execution of our 2007 acquisitions and our 2008 planned divestitures. In 2008, our
International capital is expected to increase approximately 50 percent over our 2007 program.
Successful execution of these programs, primarily in Brazil, will require effective project
management, partner relations and successful negotiations with regulatory agencies. Our
future financial results will be primarily dependent on the continued successful execution of
these drilling programs and favorable commodity prices to the extent our anticipated natural
gas and oil production is unhedged. Based on our current derivative positions, we anticipate
our 2008 hedging program will provide protection from price exposure on a substantial portion
of our anticipated natural gas and oil production as previously described.
Credit
Profile. Our outstanding debt was $12.8 billion at December 31, 2007. In
2007, we strengthened our credit profile as a result of several actions taken during the year
including:
•
Reducing debt by approximately $2.6 billion (including debt of our discontinued ANR
operations) primarily with proceeds from the sale of ANR;
•
Refinancing approximately $2.0 billion of the debt of our subsidiaries SNG, EPNG, and
EPEP;
•
Receiving upgraded senior unsecured debt ratings for El Paso of Ba3 with a positive outlook from
Moody’s, BB- with a positive outlook from Standard and Poor’s and BB+ from Fitch Ratings
and receiving investment grade senior unsecured debt ratings on our pipeline
subsidiaries of Baa3 with a positive outlook from Moody’s, BB with a positive outlook
from Standard and Poor’s and an investment grade rating of BBB- from Fitch Ratings.
This improvement should provide us a lower cost of capital on
planned expansions in our pipeline business;
•
Restructuring the El Paso and EPEP revolving
credit facilities with improved terms and total capacities of $1.5 billion and $1.0
billion, respectively; and
•
Completing our pipeline MLP initial public offering in November 2007 providing us a
lower cost of capital for further pipeline growth projects and
entering into a $750 million
revolving credit facility available to the MLP and non-recourse to El Paso.
As of December 31, 2007, our core operating business segments were Pipelines and Exploration
and Production. We also have a Marketing segment that markets our natural gas and oil production
and manages our legacy trading activities and a Power segment that
has interests in several international power plants. Our segments are managed
separately, provide a variety of energy products and services, and require different technology and
marketing strategies. Our corporate activities include our general and administrative functions, as
well as other miscellaneous businesses, contracts and assets all of which are immaterial.
Our management uses earnings before interest expense and income taxes (EBIT) to assess the
operating results and effectiveness of our business segments, which
consist of both consolidated businesses and investments in
unconsolidated affiliates. We believe EBIT is useful to our
investors because it allows them to evaluate our operating performance using the same performance
measure analyzed internally by our management. We define EBIT as net income (loss) adjusted for (i)
items that do not impact our income or loss from continuing operations, such as discontinued
operations and the impact of accounting changes, (ii) income taxes and (iii) interest and debt
expense. We exclude interest and debt expense from this measure so that investors may evaluate our
operating results without regard to our financing methods or capital structure. 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 flows.
Below is a reconciliation of our EBIT (by segment) to our consolidated net income (loss) for
each of the three years ended December 31:
2007
2006
2005
(In millions)
Segment
Pipelines
$
1,265
$
1,187
$
924
Exploration and Production
909
640
696
Marketing
(202
)
(71
)
(837
)
Power
(37
)
82
(89
)
Field Services
—
—
285
Segment EBIT
1,935
1,838
979
Corporate and other
(283
)
(88
)
(521
)
Consolidated EBIT
1,652
1,750
458
Interest and debt expense
(994
)
(1,228
)
(1,295
)
Income taxes
(222
)
9
331
Income (loss) from continuing operations
436
531
(506
)
Discontinued operations, net of income taxes
674
(56
)
(96
)
Cumulative effect of accounting changes, net of income taxes
—
—
(4
)
Net income (loss)
$
1,110
$
475
$
(606
)
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 operates primarily in the United States and consists of interstate
natural gas transmission, storage and LNG terminalling related services. 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 energy, wind, solar, coal and fuel oil. Our revenues from transportation, storage, LNG
terminalling and related services consist of two types:
Percent of Total
Type
Description
Revenues
Reservation
Reservation revenues are
from customers (referred
to as firm customers)
that reserve capacity on
our pipeline systems,
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.
77
Usage and Other
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. We
also earn revenues from
the processing and sale
of natural gas liquids
and other miscellaneous
sources.
23
The FERC regulates the rates we can charge our customers. These rates are generally a function
of the cost of providing services to our customers, including a reasonable return on our invested
capital. 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, market
conditions, regulatory actions, competition, weather and declines in the creditworthiness of
our customers. We also experience earnings volatility at certain pipelines when the amount of
natural gas used 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, many of our customers have shifted from a traditional dependence 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.
We continue to manage our recontracting process to limit the risk of significant impacts on
our revenues from expiring contracts. Our ability to extend existing customer contracts or remarket expiring contracted
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 we discount these rates at various levels for each of our
pipeline systems to remain competitive. Our existing contracts mature at various times and in
varying amounts of throughput capacity. The weighted average remaining contract term for active
contracts is approximately five years as of December 31, 2007. Below are the contract expiration
portfolio and the associated revenue expirations for our firm
transportation contracts on our wholly and majority owned systems as of
December 31, 2007, including those with terms beginning in 2008 or later:
In
November 2007, we completed an offering of common units in an
MLP. We contributed 100 percent of WIC (our wholly owned
interstate pipeline transportation business located primarily in Wyoming and Colorado) and 10
percent equity interests in CIG and SNG to the MLP. We have both a 2 percent general partner
interest and a 64.8 percent limited partner interest in the MLP.
Summary of Operational and Financial Performance
In 2007, we continued to deliver strong financial performance across all pipelines. We
placed several expansion projects in service including Phase I of the SNG
Cypress project, TGP Louisiana Deepwater Link project, TGP Triple-T Extension project, TGP
Northeast Connexion-New England project and Mexico LPG Burgos project and continued to make
significant progress on our backlog of expansion projects. We also
successfully resolved our EPNG and Mojave rate cases and restructured and renewed certain customer
contracts. During 2007, we benefited from (i) higher
realized rates on certain of our systems, (ii) increased throughput, and (iii) increased activity
under other various interruptible services.
The level of throughput on our systems can provide evidence of the underlying long-term value
of our system capacity. In 2007, increased throughput across our system was a result of broad based
increases in power demand from Mexico, California, the Northeast and the Southeast based on
underlying growth in electricity demand, colder weather and lower availability of hydroelectric
power in the Northwest. We have also experienced higher supply related throughput as a result of
our Rockies—related expansions.
During 2008, we currently plan on spending $1.6 billion in capital, of which $1.2 billion will be
targeted towards our backlog of expansion projects. We intend to
build on the growth achieved in 2007 and currently have almost $4 billion in committed expansion projects
that comprise our backlog as follows:
Project
Anticipated In-Service Dates
Estimated Cost
FERC Approved
(in millions)
Cheyenne Plains Expansion
July 2008
$
23
Yes
Cypress II/III
May 2008/January 2011
102
Yes
Essex-Middlesex
November 2008
76
Yes
Southeast
Supply Header — Phase I
June 2008
137
Yes
WIC Medicine Bow Expansion
July 2008
32
Yes
High Plains Pipeline (50%)
November 2008
98
No
Carthage Expansion
May 2009
39
No
Concord Lateral Expansion
November 2009
21
No
WIC Piceance Lateral Expansion
4th Quarter 2009
62
No
Totem Storage (50%)
July 2009
60
No
Elba Expansion III and Elba Express
2010-2013
1,093
Yes
South System
III and Southeast Supply Header — Phase II
2010-2012
319
No
FGT Phase VIII Expansion (50%)
2011
1,050
No
Gulf LNG Clean Energy (50%)(1)
2011
787
Yes
Total Committed Expansion
Backlog
$
3,899
(1)
Includes approximately $294 million that we paid to acquire a 50 percent interest in this project.
Other
Large Projects in Development. We also have two development
projects underway,
the recently announced Ruby Pipeline project and the Northeast
Passage project. Combined, these projects are estimated to cost over $4 billion (over
$2 billion net to our interests) with estimated in-service dates in 2011. These
projects are in various phases of development, including obtaining necessary
customer commitments and holding ownership discussions.
The table below and discussion that follows detail the impact on EBIT of significant events in
2007 compared with 2006 and 2006 as compared with 2005. We have also provided an outlook on events
that may affect our operations in the future.
2007 to 2006
2006 to 2005
Variance
Variance
Revenue
Expense
Other
EBIT
Revenue
Expense
Other
EBIT
Impact
Impact
Impact
Impact
Impact
Impact
Impact
Impact
Favorable/(Unfavorable)
(In millions)
Reservation and usage revenues
$
31
$
—
$
—
$
31
$
128
$
—
$
—
$
128
Expansions
50
(7
)
9
52
75
(9
)
(10
)
56
Gas not used in operations, revaluations,
processing revenues and other natural gas
sales
3
(16
)
—
(13
)
20
38
—
58
Hurricanes Katrina and Rita
—
12
—
12
—
(1
)
—
(1
)
Asset impairments
—
4
(2
)
2
—
30
—
30
General and administrative expense
—
(10
)
—
(10
)
—
52
—
52
Depreciation expense
—
2
—
2
—
(19
)
—
(19
)
Operating costs (including pipeline integrity)
—
(25
)
—
(25
)
—
(32
)
—
(32
)
Bankruptcy settlements
—
(3
)
—
(3
)
15
3
—
18
Equity earnings from Citrus
—
—
19
19
—
—
(4
)
(4
)
Other(1)
8
(1
)
4
11
(7
)
(9
)
(7
)
(23
)
Total impact on EBIT
$
92
$
(44
)
$
30
$
78
$
231
$
53
$
(21
)
$
263
(1)
Consists of individually insignificant items on several of our pipeline systems.
Reservation and Usage Revenues. During the year ended December 31, 2007, our EBIT was
favorably impacted by:
•
an increase in throughput on our pipeline systems, primarily in the Rocky Mountains
and southern regions which increased due to new supply, colder weather and increased
transportation services to power plants;
•
additional firm capacity sold in the south central region on
our TGP system; and
•
increased rates on our CIG system effective October 2006 as a result of CIG’s rate
settlement
Partially offsetting these favorable impacts in 2007 was the expiration of certain firm transportation contracts on our EPNG, MPC and SNG systems.
The increase in our reservation and usage revenues in 2006 compared with 2005 was primarily due
to:
•
the expiration of reduced EPNG tariff rates effective December 31, 2005, to certain
customers under the terms of EPNG’s FERC-approved system wide capacity allocation
proceeding;
•
an increase in EPNG’s tariff rates effective
January 1, 2006 as a result of its rate filing;
•
the sales of additional firm capacity and higher realized rates on several of our pipeline
systems in 2006; and
•
increased activity on our pipeline systems under various interruptible services
provided under their tariffs as a result of favorable market
conditions.
Expansions. During 2007 and 2006, our reservation revenues and throughput volumes increased
due to projects placed in service. Below is a discussion of our expansion projects placed in
service.
Projects Placed in Service in 2007 and 2006. During 2007, we placed several expansion projects
in service including Phase I of the Cypress project, the Louisiana Deepwater Link project, the
Triple-T Extension project, the Northeast Connexion-New England project and the Mexico LPG
Burgos project. In 2006, we placed several expansion projects in service including the
Cheyenne Plains Yuma Lateral project, the Elba Island LNG expansion and the Piceance Basin
project on our WIC system.
Projects Placed in Service in 2008. In January 2008, we completed the WIC
Kanda Lateral project which should increase annual revenues by approximately
$25 million.
Gas Not Used in Operations, Revaluations, Processing Revenues and Other Natural Gas Sales.
During the year ended December 31, 2007, our EBIT was unfavorably impacted by the (i) revaluation
of net gas imbalances and other gas owed to our customers in our CIG and WIC systems as a result
of increasing natural gas prices in 2007 versus decreasing natural gas prices in 2006 (ii) lower
processing revenues and operational gas costs on our CIG system due to a decrease in processing
volumes and natural gas liquids. Partially offsetting these unfavorable impacts in 2007 were
higher volumes of gas not used in TGP’s operations.
During 2006, higher realized prices on sales of gas not used in operations resulted in
favorable impacts to our operating revenues, partially offset by lower sales volumes of natural gas
not used in operations during 2006 compared to 2005. We also experienced favorable impacts to our operating expenses in
2006 due to decreases in the index prices used to value the net imbalance position on several of
our pipeline systems. 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 2005
operating results. In addition, our pipelines also retained lower volumes of gas not used in
operations during 2005. We anticipate that the overall activity in this area will continue to vary
based on factors such as volatility in natural gas prices, the efficiency of our pipeline
operations, regulatory actions and other factors.
Hurricanes Katrina and Rita. During 2007, we incurred lower operation and maintenance expenses
to repair damage caused by Hurricanes Katrina and Rita as compared to 2006. In 2006, we recorded
higher operation and maintenance expenses compared with 2005 as a result of unreimbursed amounts
expended to repair hurricane damage. We do not anticipate that expenditures related to these
hurricanes, net of related reimbursements, will materially impact our future financial results.
Asset Impairments. During 2007, we recorded a $10 million impairment of certain pipeline
assets originally purchased to repair certain offshore hurricane damage following a decision
not to use these assets. In addition,
we recorded a loss of approximately $9 million pursuant to a
FERC determination on the accounting treatment for the pending sale of certain transmission
facilities. During 2006 and 2005, we impaired various pipeline development projects based on
changing market conditions. In 2006, these impairments included $13 million and $3 million due to
discontinuing our Continental Connector Pipeline
project and the remainder of our Seafarer Project. In 2005, we recorded impairments of $18
million and $28 million due to discontinuing a portion of our Seafarer project and the entirety of
our Blue Atlantic development project.
General and Administrative Expenses. During the year ended December 31, 2007, our general and
administrative expenses were higher than in 2006 primarily due to increased insurance costs for
wind damage on our pipeline assets located primarily in the Gulf of Mexico region. Our general and
administrative costs were lower in 2006 than 2005, primarily due to a decrease in accrued benefit
costs and lower allocated costs from El Paso based on the estimated level of resources devoted to
the pipeline segment and the relative size of its EBIT, gross property and payroll
as compared to the consolidated totals.
Depreciation Expense. Depreciation expense was higher for 2006 compared to 2005 primarily due
to higher depreciation rates applied to EPNG’s property, plant and equipment following its 2006
rate case.
Operating Costs (Including Pipeline Integrity). During 2007, we incurred higher operating
costs than in 2006 primarily due to increased repair and maintenance costs, allowances for
non-trade accounts receivable and environmental reserves. During 2006, we incurred higher costs
than in 2005 primarily for repairs and maintenance and $19 million of pipeline integrity costs
which we began expensing in 2006 as a result of the adoption of an accounting release issued by
the FERC.
Bankruptcy Settlements. In 2007, we received $10 million to settle our bankruptcy claim
against USGen New England, Inc. During 2007 and 2006, we recorded income of approximately $5
million and $18 million, net of amounts potentially owed to
certain customers, related to amounts recovered from the Enron bankruptcy settlement. In February 2008,
we received a portion of the bankruptcy settlement under Calpine Corporation’s approved plan of reorganization. In
connection with this plan, we received Calpine common stock with a market value of approximately $29 million, on which we will recognize a gain in the first quarter of 2008.
Equity Earnings from Citrus. During the year ended December 31, 2007, equity earnings on our
Citrus investment increased primarily due to (i) a favorable settlement of approximately $8 million
for litigation brought against Spectra LNG Sales (formerly Duke Energy LNG Sales, Inc.) for the
wrongful termination of a gas supply contract; (ii) Citrus’ sale of a receivable for approximately
$3 million related to the bankruptcy of Enron North America and (iii) favorable operating results
of approximately $8 million from Florida Gas Transmission Company, a pipeline owned 100 percent by
Citrus, due to higher system usage and lower operating costs.
Regulatory Matters/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
in 2008 and expect to continue operating under their existing rates. Certain other pipelines
have recently completed, or are in rate proceedings or have upcoming
rate actions including the following:
•
EPNG — In August 2007, EPNG received approval of the settlement of its rate case
from the FERC. The settlement provides benefits for both EPNG and its customers for a
three year period ending December 31, 2008. Under the terms of the settlement, EPNG is
required to file a new rate case to be effective January 1, 2009. EPNG received approval
of its settlement from the FERC and refunded $115
million, with interest, in the fourth quarter of 2007. A final refund of $10
million was paid in January 2008.
•
MPC — MPC’s primary customer is EPNG. In February 2007, MPC filed with the FERC a general rate case proposing a 33
percent decrease in its base tariff rates. No
new services were proposed. The new base rates were effective March 1, 2007. In December
2007, FERC approved an offer of settlement to resolve all issues in
the rate case. Under the settlement, MPC has a $4 million, third
party refund obligation for a previously accrued regulatory obligation.
CIG/WIC — In August 2007, CIG filed a tariff change with the FERC to modify its
fuel recovery mechanism to recover all cost impacts, or flow through to shippers any
revenue impacts, of fuel imbalance revaluations and related gas balance items. CIG
currently experiences variability in cash flow and earnings under its fuel recovery
mechanism, but its earnings variability from price fluctuations will be
substantially reduced if the FERC approves the fuel tracker. This tariff filing was
protested by certain shippers and the FERC suspended the effective date to March 1, 2008
subject to the similar outcome of a technical conference on the proposed tariff change which was
held in November 2007. In September 2007, WIC filed a tariff change with the FERC.
This tariff filing was protested by certain shippers and the FERC suspended
the effective date to April 1, 2008, subject to the outcome of a technical conference on
the proposed tariff change, which was held in November 2007. Comments on these
proposals have been filed by various parties to the proceedings, but no further action
has yet been taken by the FERC relative to these proceedings.
Our Exploration and Production segment conducts our natural gas and oil exploration and
production activities. The profitability and performance of this segment are driven by the ability
to locate and develop economic natural gas and oil reserves and extract those reserves with the
lowest possible production and administrative costs. Accordingly, we manage this business with the
goal of creating value through disciplined capital allocation, cost control and portfolio
management.
Our domestic natural gas and oil reserve portfolio blends slower decline rate, typically
longer lived assets in our Onshore region with steeper decline rate and shorter lived assets in our
Texas Gulf Coast, Gulf of Mexico and south Louisiana regions. We believe the combination of our
assets in these domestic regions provides significant near-term cash flow while providing
consistent opportunities for competitive investment returns. In addition, our international
activities in Brazil and Egypt provide opportunity for additional future reserve additions and
longer term cash flows.
As part of our business strategy, we attempt to create value through a balance of drilling
activities, exploration, and through acquisitions of assets and companies. For 2008, we expect our
growth to occur principally through drilling activities and we will continue to evaluate
acquisition and growth opportunities that are tightly focused around our core competencies and
areas of competitive advantage. We believe strategic acquisitions can support our corporate
objectives by:
•
Re-shaping our portfolio to provide greater opportunities to achieve our long term
performance goals;
•
Leveraging operational expertise we already possess in key operating areas, geologies or
techniques;
•
Balancing our exposure to regions, basins and commodities;
•
Achieving risk-adjusted returns competitive with those available within our existing
inventory; and
•
Increasing our reserves more rapidly by supplementing our current drilling inventory.
In
September 2007, we acquired Peoples, which provided an upgrade to our portfolio of assets.
We are also further upgrading our portfolio by selling selected properties. In January 2008, we
entered into agreements to sell $517 million of certain non-core properties in our Onshore and
Texas Gulf Coast regions with estimated proved reserves of 191 Bcfe at December 31, 2007. These sales are expected
to close in the first quarter of 2008. We expect upgrading our portfolio will extend the reserve life of our
assets, reduce unit operation and maintenance costs, increase predictability, improve capital
efficiency and expand the depth of our inventory.
In addition to executing on our strategy, the profitability and performance of our exploration
and production operations can be substantially impacted by (i) changes in commodity prices, (ii)
industry-wide increases in drilling and oilfield service costs, and (iii) the effect of hurricanes
and other weather impacts on our daily production, operating and capital costs. To the extent
possible, we attempt to mitigate these factors. As part of our risk management activities, we have
entered into derivative contracts on a significant portion of our anticipated 2008 natural gas and
oil production to reduce the financial impact of downward commodity price movements.
Significant Operational Factors Affecting the Year Ended December 31, 2007
Production. Our average daily production for the year was 792 MMcfe/d (not including 70 MMcfe/d
from our share of production from our equity investment in Four Star). Our production levels grew in every quarter of 2007.
Below is a further analysis of our 2007 production by region (MMcfe/d):
2007
2006
2005
United States
Onshore
374
345
300
Texas Gulf Coast
213
187
211
Gulf of Mexico and south Louisiana
191
174
179
International
Brazil
14
24
53
Total Consolidated
792
730
743
Four Star
70
68
24
Onshore region — Our 2007 production continued to increase through capital projects where we
maintained or increased production in most of our major operating areas, with the majority of
growth coming from the Rockies and Arklatex areas. Our Peoples acquisition in September 2007
also contributed to production volume increases during the year.
Texas Gulf Coast region — The acquisition of properties in Zapata County during the first
quarter of 2007 and the success of our drilling program more than offset natural production
declines and the sale of certain non-strategic south Texas properties in 2006. Our Peoples
acquisition in September 2007 also contributed to production volume increases during the year.
Gulf of Mexico and south Louisiana region — We began producing from development wells in the
western Gulf and south Louisiana and several exploratory discoveries occurring prior to 2007.
We also recovered volumes previously shut-in by hurricane damage which, when coupled with these
new production sources, helped to offset natural production declines.
Brazil — Production volumes decreased in 2007 due to natural production declines and a
contractual reduction of our ownership interest in the Pescada-Arabaiana Fields in early 2006.
Four
Star — Our original ownership interest in Four Star was obtained in the Medicine Bow acquisition in August 2005.
In January 2007, Four Star acquired properties that added production of approximately 5
MMcfe/d, net of our interest on the acquisition date. In the third quarter of 2007, we spent
$27 million to increase our ownership interest in Four Star from 43 percent to 49 percent.
2007 Drilling Results
Onshore. We realized a 99 percent success rate on 502 gross wells drilled.
Texas Gulf Coast. We experienced a 92 percent success rate on 84 gross wells drilled.
Gulf of Mexico and south Louisiana. We drilled six successful wells and seven unsuccessful
wells.
Brazil. We currently own 100 percent of the BM-CAL-4 concession in the Camamu Basin. In
2007, we completed drilling two successful exploratory wells south of the Pinauna Field in this
concession that extends the southern limits of the Pinauna project. We are currently assessing
development options and have a process underway to potentially market up to a 50 percent
non-operating interest in this concession. In addition, we completed drilling and testing two
exploratory wells with Petrobras in the ES-5 Block in the Espirito Basin. These wells confirmed the
extension of an earlier discovery by Petrobras on a block to the south. We are currently in
negotiations with Petrobras on a unitization agreement for the development of this discovery.
Egypt. In 2007, we received formal government approval and signed the concession agreement
for the South Mariut Block. The block is approximately 1.2 million acres and is located onshore in
the western part of the Nile Delta. We paid $3 million for the concession and agreed to a $22
million firm working commitment over three years. We are currently performing seismic evaluations
on the block and expect to drill our first exploratory well in late 2008.
Cash Operating Costs. We monitor cash operating costs required to produce our natural gas and
oil volumes. These costs are calculated on a per Mcfe basis and include total operating expenses
less depreciation, depletion and amortization expense, other non-cash expense items and the cost of
products and services on our income statement. In 2007, cash operating costs per unit increased to
$1.88/Mcfe as compared to $1.86/Mcfe in 2006. Our operating costs increased primarily as a result
of higher production taxes which increased due to higher natural gas and oil reserves, lower
severance tax credits, higher marketing and other costs and higher corporate overhead allocations.
Reserve Replacement Costs/Reserve Replacement Ratio. We calculate two primary metrics, (i) a
reserve replacement ratio and (ii) reserve replacement costs, to measure our ability to establish
a long-term trend of adding reserves at a reasonable cost in our core asset areas. The reserve
replacement ratio is an indicator of our ability to replenish annual production volumes and grow
our reserves. It is important for us to economically find and develop new reserves that will more
than offset produced volumes and provide for future production given the inherent decline of
hydrocarbon reserves. In addition, we calculate reserve replacement costs to assess the cost of
adding reserves which is ultimately included in depreciation, depletion and amortization expense.
We believe the ability to develop a competitive advantage over other natural gas and oil companies
is dependent on adding reserves in our core asset areas at a lower cost than our competition. We
calculate these metrics as follows:
Reserve replacement ratio
Sum of reserve additions(1)
Actual production for the corresponding period
Reserve replacement costs/Mcfe
Total oil and gas capital costs(2)
Sum of reserve additions (1)
(1)
Reserve additions include proved reserves and reflect
reserve revisions, extensions, discoveries and other
additions and acquisitions and do not include unproved
reserve quantities or proved reserve additions
attributable to investments accounted for using the equity
method. Amounts are derived directly from the table
presented in Item 8, Financial Statements and
Supplementary Data, Supplemental Natural Gas and Oil
Operations.
(2)
Total oil and gas capital costs include the costs of
development, exploration and property acquisition
activities conducted to add reserves and exclude asset
retirement obligations. Amounts are derived directly from
the table presented in Item 8, Financial Statements and
Supplementary Data, Supplemental Natural Gas and Oil
Operations.
Both the reserve replacement ratio and reserve replacement costs per unit are statistical
indicators that have limitations, including their predictive and comparative value. As an annual
measure, the reserve replacement ratio is limited because it typically varies widely based on the
extent and timing of new discoveries, project sanctioning and property acquisitions. In addition,
since the reserve replacement ratio does not consider the cost or timing of future production of
new reserves, it cannot be used as a measure of value creation.
The exploration for and the acquisition and development of natural gas and oil reserves is
inherently uncertain as further discussed in Part I, Item 1A, Risk Factors, Risks Related to our
Business. One of these risks and uncertainties is our ability to spend sufficient capital to
increase our reserves. While we currently expect to spend such amounts in the future, there are no
assurances as to the timing and magnitude of these expenditures or the classification of the proved
reserves as developed or undeveloped. At December 31, 2007, proved developed reserves represent
approximately 71 percent of total proved reserves. Proved developed reserves will generally begin
producing within the year they are added whereas proved undeveloped reserves generally require a
major future expenditure.
The table below shows our reserve replacement costs and reserve replacement ratio for our
domestic and worldwide operations for each of the years ended December 31:
2007
2006
2005
($/Mcfe)
Domestic
Reserve replacement costs, including acquisitions
$
3.26
$
3.92
$
3.02
Reserve replacement costs, excluding acquisitions
3.22
3.94
3.98
Worldwide
Reserve replacement costs, including acquisitions
$
3.55
$
4.17
$
2.75
Reserve replacement costs, excluding acquisitions
3.79
4.19
3.19
(% of Production)
Domestic
Reserve replacement ratio, including acquisitions
255
%
109
%
188
%
Reserve replacement ratio, excluding acquisitions
129
%
108
%
79
%
Worldwide
Reserve replacement ratio, including acquisitions
252
%
108
%
195
%
Reserve replacement ratio, excluding acquisitions
129
%
107
%
93
%
In 2007, our domestic reserve replacement costs decreased primarily due to favorable
acquisitions and finding and development costs and upward revisions in previous estimates of
reserves due to higher commodity prices at December 31, 2007. We typically cite reserve
replacement costs in the context of a multi-year trend, in recognition of its limitation as a
single year measure, but also to demonstrate consistency and stability, which are essential to our
business model. For the three year period ending December 31, 2007, our average reserve replacement
costs for our domestic and worldwide operations were $3.31/Mcfe and
$3.40/Mcfe, including
acquisitions, and $3.64/Mcfe and $3.75/Mcfe excluding acquisitions.
Capital Expenditures. Our capital expenditures were as follows for the three years ended
December 31:
2007
2006
2005
(in millions)
Total oil and gas capital costs(1)
$
2,589
$
1,193
$
1,462
Less: acquisition capital
(1,178
)
(4
)
(651
)
Capital expenditures, excluding acquisitions
$
1,411
$
1,189
$
811
(1)
Total oil and gas capital costs include the costs of
development, exploration and property acquisition
activities conducted to add reserves and exclude asset
retirement obligations. Amounts are derived directly from
the table presented in Item 8, Financial Statements and
Supplementary Data, Supplemental Natural Gas and Oil
Operations.
Outlook for 2008
For 2008, we anticipate the following on a worldwide basis:
•
Average daily production volumes for the year of approximately 805 MMcfe/d to 860
MMcfe/d, which excludes approximately 65 MMcfe/d to 70 MMcfe/d from our equity investment in
Four Star.
•
Capital expenditures, excluding acquisitions, of approximately $1.7 billion. While
approximately 80% of the Company’s planned 2008 capital program is allocated to its domestic
program, we plan to spend approximately $350 million in international capital in 2008,
primarily in our Brazil exploration and development program. As part of our domestic
capital program, we will allocate a greater percentage of our capital to our Onshore and
Texas Gulf Coast regions in light of our announced divestiture plans.
•
Average cash operating costs which include production costs, general and administrative
expenses and other expenses of approximately $1.75/Mcfe to $1.90/Mcfe for the year; and
•
Depreciation, depletion and amortization rate of between $2.80/Mcfe and $3.20/Mcfe.
As part of our strategy, we enter into derivative contracts on our natural gas and oil
production to stabilize cash flows, to reduce the risk and financial impact of downward commodity
price movements on commodity sales and to protect the economic assumptions associated with our
capital investment programs. 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.
The following table and discussion that follows shows, as of December 31, 2007, the contracted
volumes and the minimum, maximum and average prices we will receive under these contracts when
combined with the sale of the underlying hedged production:
Fixed Price
Basis
Swaps(1)
Floors(1)
Ceilings(1)
Swaps(1)(2)
Average
Average
Average
Texas Gulf Coast
Onshore-Raton
Rockies
Volumes
Price
Volumes
Price
Volumes
Price
Volumes
Avg. Price
Volumes
Avg. Price
Volumes
Avg. Price
Natural Gas
2008
33
$
7.65
108
$
8.00
108
$
10.80
58
$
(0.33
)
26
$
(1.13
)
13
$
(1.37
)
2009
5
$
3.56
—
—
—
—
—
—
15
$
(1.00
)
—
—
2010
5
$
3.70
—
—
—
—
—
—
—
—
—
—
2011-2012
6
$
3.88
—
—
—
—
—
—
—
—
—
—
Oil
2008
2,498
$
88.48
—
—
—
—
—
—
—
—
—
—
(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.
(2)
Our basis swaps effectively limit our exposure to differences between the NYMEX gas price and the price at the location where we
sell our gas. The average prices listed above are the amounts we will pay per MMBtu relative to the NYMEX price to “lock-in” these
locational differences.
All of our oil fixed price swaps and 86 percent of our natural gas fixed price swaps and
option contracts are designated as accounting hedges. Gains and losses associated with these
natural gas contracts are deferred in accumulated other comprehensive income and will be recognized
in earnings upon the sale of the related production at market prices, resulting in a realized price
that is approximately equal to the hedged price. With regard to our natural gas positions,
approximately 7 TBtu of our fixed price swaps, 15 TBtu of our option contracts and all of our basis
swaps are not designated as accounting hedges. Accordingly, changes in the fair value of these
derivatives are recognized in earnings each period.
During
January and February 2008, we entered into (i) 47 TBtu of
options on our anticipated 2008 natural gas production with a floor
price of $8.00 per MMBtu and an average ceiling price of
$10.64 per MMBtu; (ii) 7 TBtu of options on our
anticipated 2009 natural gas production with a floor price of
$8.00 per MMBtu and a ceiling price of $11.05 per MMBtu; and
(iii) 292 MBbls of fixed price swaps on our anticipated 2008 oil
production at a price of $99.00 per barrel. All of these contracts were designated as accounting hedges, except for
19 TBtu of the 2008 natural gas option contracts. The total of all
our positions provides price protection on approximately two-thirds
of our planned 2008 equivalent production.
Additionally, the table above does not include contracts entered into by our Marketing segment
as further described in that segment. For the consolidated impact of the entirety of El Paso’s
production-related price risk management activities on our overall liquidity, see the discussion of
factors that could impact our liquidity in Liquidity and Capital Resources.
The tables below and the discussion that follows provide the operating results and analysis of
significant variances in these results during the periods ended December 31:
2007
2006
2005
(In millions, except for
Volumes and prices)
Operating Revenues:
Natural gas
$
1,764
$
1,406
$
1,420
Oil, condensate and NGL
494
430
371
Other
42
18
(4
)
Total operating revenues
2,300
1,854
1,787
Operating Expenses:
Depreciation, depletion and amortization
(780
)
(645
)
(612
)
Production costs
(344
)
(331
)
(261
)
Cost of products and services
(92
)
(87
)
(47
)
General and administrative expenses
(185
)
(156
)
(185
)
Other
(13
)
(10
)
(11
)
Total operating expenses
(1,414
)
(1,229
)
(1,116
)
Operating income
886
625
671
Other income (1)
23
15
25
EBIT
$
909
$
640
$
696
(1)
Includes equity earnings from our investment in Four Star.
Percent
Percent
2007
Variance
2006
Variance
2005
Consolidated volumes, prices and costs per unit:
Natural gas
Volumes (MMcf)
242,316
10
%
220,402
(1
)%
222,292
Average realized prices including hedges ($/Mcf)
$
7.28
14
%
$
6.38
—
%
$
6.39
Average realized prices excluding hedges ($/Mcf)
$
6.53
(2
)%
$
6.64
(12
)%
$
7.53
Average transportation costs ($/Mcf)
$
0.27
17
%
$
0.23
28
%
$
0.18
Oil, condensate and NGL
Volumes (MBbls)
7,821
2
%
7,686
(6
)%
8,136
Average
realized prices including hedges ($/Bbl)
$
63.11
13
%
$
55.90
23
%
$
45.60
Average
realized prices excluding hedges ($/Bbl)
$
63.71
13
%
$
56.21
21
%
$
46.43
Average transportation costs ($/Bbl)
$
0.81
(1
)%
$
0.82
30
%
$
0.63
Total equivalent volumes
MMcfe
289,242
9
%
266,518
(2
)%
271,107
MMcfe/d
792
8
%
730
(2
)%
743
Production costs and other cash operating costs ($/Mcfe)
Average lease operating costs
$
0.88
(7
)%
$
0.95
32
%
$
0.72
Average production taxes(1)
0.31
7
%
0.29
21
%
0.24
Total production costs
$
1.19
(4
)%
$
1.24
29
%
$
0.96
Average general and administrative expenses
$
0.64
8
%
$
0.59
(13
)%
$
0.68
Average taxes, other than production and income taxes
$
0.05
67
%
$
0.03
—
%
$
0.03
Total cash operating costs
$
1.88
1
%
$
1.86
11
%
$
1.67
Depreciation, depletion and amortization ($/Mcfe)
$
2.70
12
%
$
2.42
7
%
$
2.26
Unconsolidated affiliate volumes (Four Star)
Natural gas (MMcf)
19,380
18,140
6,689
Oil, condensate and NGL (MBbls)
1,015
1,087
359
Total equivalent volumes
MMcfe
25,470
24,663
8,844
MMcfe/d
70
68
24
(1)
Production taxes include ad valorem and severance taxes.
Our EBIT for 2007 increased $269 million as compared to 2006. The table below lists the
significant variances in our operating results in 2007 as compared to 2006:
Variance
Operating
Operating
Revenue
Expense
Other
EBIT
Favorable/(Unfavorable)
(In millions)
Natural Gas Revenue
Lower natural gas prices in 2007
$
(26
)
$
—
$
—
$
(26
)
Impact of hedges
239
—
—
239
Higher volumes in 2007
145
—
—
145
Oil, Condensate and NGL Revenue
Higher oil, condensate, and NGL prices in 2007
59
—
—
59
Impact of hedges
(4
)
—
—
(4
)
Higher volumes in 2007
7
—
—
7
Other Revenue
Change in fair value of derivatives not designated as accounting hedges
47
—
—
47
Other
(21
)
—
—
(21
)
Depreciation, Depletion and Amortization Expense
Higher depletion rate in 2007
—
(82
)
—
(82
)
Higher production volumes in 2007
—
(52
)
—
(52
)
Production Costs
Higher lease operating costs in 2007
—
(1
)
—
(1
)
Higher production taxes in 2007
—
(12
)
—
(12
)
General and Administrative Expenses
—
(29
)
—
(29
)
Other
Earnings from investment in Four Star
—
—
2
2
Other
—
(9
)
6
(3
)
Total Variances
$
446
$
(185
)
$
8
$
269
Operating revenues. During 2007, revenues increased compared with 2006 due to higher realized
natural gas and oil prices, including the effects of our hedging program. Realized gains on hedging
transactions were $177 million during 2007, as compared to losses of $58 million in 2006. During
2007, we also benefited from an increase in production volumes in all domestic regions over 2006.
Other revenue. During 2007, we recognized mark-to-market gains of $7 million compared to
losses of $40 million in 2006 related to the change in fair value of derivatives not designated as
hedges, including a portion of our oil and natural gas fixed price swaps, option contracts and
basis swaps.
Depreciation, depletion and amortization expense. During 2007, our depletion rate increased
as compared to the same periods in 2006 as a result of the Peoples and Zapata County, Texas
property acquisitions and higher finding and development costs.
Production costs. Our production taxes increased during 2007 as compared to 2006 primarily
due to higher natural gas and oil revenues and lower severance tax credits in 2007.
General and administrative expenses. Our general and administrative expenses increased during
2007 as compared to 2006 primarily due to higher marketing and other costs previously included in
our Marketing segment and higher corporate overhead allocations.
Our EBIT for 2006 decreased $56 million as compared to 2005. The table below lists the
significant variances in our operating results in 2006 as compared to 2005:
Variance
Operating
Operating
Revenue
Expense
Other
EBIT
Favorable/(Unfavorable)
(In millions)
Natural Gas Revenue
Lower natural gas prices in 2006
$
(197
)
$
—
$
—
$
(197
)
Impact of hedges
197
—
—
197
Lower production volumes in 2006
(14
)
—
—
(14
)
Oil, Condensate and NGL Revenue
Higher oil, condensate, and NGL prices in 2006
75
—
—
75
Impact of hedges
5
—
—
5
Lower volumes in 2006
(21
)
—
—
(21
)
Depreciation, Depletion and Amortization Expense
Higher depletion rate in 2006
—
(51
)
—
(51
)
Lower production volumes in 2006
—
10
—
10
Production Costs
Higher lease operating costs in 2006
—
(58
)
—
(58
)
Higher production taxes in 2006
—
(12
)
—
(12
)
General and Administrative Expenses
—
29
—
29
Other
Change in fair value of oil and basis swaps
(31
)
—
—
(31
)
Earnings from investment in Four Star
—
—
(9
)
(9
)
Processing plants
41
(29
)
—
12
Other
12
(2
)
(1
)
9
Total Variances
$
67
$
(113
)
$
(10
)
$
(56
)
Operating revenues. Natural gas revenues decreased by approximately $197 million as natural
gas prices were not as strong in 2006 as compared to 2005. However, we experienced lower hedging
program losses for 2006 of $58 million compared to losses of $260 million for 2005. Realized oil,
condensate and NGL prices increased in 2006 when compared to 2005.
Our
production volumes benefited in 2006 from our acquisitions in 2005. However, overall
production volumes decreased in our Texas Gulf Coast and Gulf of Mexico and south Louisiana
regions due to natural declines, and the sale of certain non-strategic south Texas properties with
average production of 5 MMcfe/d in 2006. Also, our Gulf of Mexico and south Louisiana region
production continued to be impacted in 2006 by Hurricanes Katrina and Rita, which occurred in late
2005. Our production volumes in Brazil decreased due to the contractual reduction of our ownership
interest in the Pescada-Arabaiana Fields in 2006.
Depreciation, depletion and amortization expense. During 2006, we experienced higher
depletion rates as compared to 2005 primarily as a result of higher finding and development costs
and the cost of acquired reserves. However, lower production volumes in 2006 partially offset the
impact of these higher depletion rates.
Production costs. In 2006, our lease operating costs increased as compared to 2005 in all
regions as a result of inflation in fuel costs, power and other services. In our Onshore region,
additional increases were due to increased subsurface maintenance and our acquisition of Medicine
Bow. In the Gulf of Mexico region, additional increases were due to hurricane repairs not
recoverable through insurance. Additionally, production taxes increased as a result of lower tax
credits in Texas taken in 2006 compared to 2005.
General and administrative expenses. Our general and administrative expenses decreased during
2006 as compared to the same period in 2005, primarily due to lower corporate overhead allocations.
Other. During 2006, we recorded a loss of approximately $40 million of the fair value of our
derivatives not designated as hedges as compared to a $9 million loss in 2005. In 2006, our EBIT
was also unfavorably impacted by earnings from Four Star due to lower natural gas prices. Our EBIT
was favorably impacted by operations at our processing plants and insurance recoveries resulting
from Hurricane Ivan, among other items.
Our Marketing 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. In addition, we continue to manage and
liquidate remaining legacy natural gas supply, transportation, power and other natural gas
contracts entered into prior to the deterioration of the energy trading environment in 2002. Any
future liquidations may impact our cash flows and financial results. However, we may not liquidate
certain of these remaining legacy contracts before their expiration if (i) they are 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. The table that follows provides a description of our remaining contracts and our
remaining exposure on these contracts. All mark-to-market contracts are subject to interest rate
exposure as the interest rates used in determining the fair market values are subject to change
from period to period.
Locational differences in natural gas
prices which could affect our ability
to use the capacity to recover demand
charges. Exposure to future losses
reduced significantly due to
releasing or assigning capacity
related to Alliance and other
pipelines in 2006 and 2007.
Long-term gas supply
obligations
Primarily four contracts with
delivery obligations up to 0.3
Bcf/d with expiration dates
ranging from 2011 to 2028.
Index-priced contracts are exposed to
locational changes in natural gas
prices.
Overview. Over the past three years, our operating results and year-to-year comparability
have been impacted by significant commodity and other market fluctuations, changes in the
composition of our portfolio (and related effort to manage our portfolio) based on actions taken to
reduce exposure and exit our legacy trading activities. The tables below and discussions that
follow provide further information about these events, our overall operating results and analysis
by significant contract type for our Marketing segment during each of the three years ended
December 31:
Our 2007 results were primarily driven by mark-to-market losses on our production-related
option contracts and legacy natural gas and power positions (including our PJM contracts). These
losses were partially offset by $23 million of other income recognized upon the sale of our
investment in the NYMEX and $28 million of EBIT ($23 million of revenues and $5 million of
other income) related to the settlement of outstanding California power price disputes.
Our 2006 and 2005 financial results were significantly impacted by:
•
mark-to-market gains and losses on our production-related natural gas and oil derivative contracts
•
the divestiture in 2006 of a significant portion of our natural gas portfolio
•
a termination payment in 2006 of $188 million to a third party to assume our
Alliance transportation capacity obligations effective November 1, 2007
•
losses in 2006 based on changes in the fair value of our other natural gas
derivative contracts including approximately $133 million of previously unrecorded losses
on our Midland Cogeneration Venture (MCV) supply agreement in conjunction with the sale
of our interest in that facility
•
the divestitures in 2005 of our Cordova tolling agreement and a majority of the
contracts in our power portfolio
Production-related Natural Gas and Oil Derivative Contracts
Options contracts. Our production-related natural gas and oil derivative contracts are
designed to provide protection to El Paso against changes in natural gas and oil prices. These are
in addition to those derivative contracts entered into by our Exploration and Production segment
which are further described in the discussion of that segment above. For the consolidated impact of
all of El Paso’s production-related price risk management activities, refer to our Liquidity and
Capital Resources discussion. The fair value of our derivative contracts is impacted by changes in
commodity prices from period-to-period and is marked-to-market in our results. Listed below are the
volumes and average prices associated with our production-related derivative contracts as of
December 31, 2007:
Floors(1)
Ceilings(1)
Average
Average
Volumes
Price
Volumes
Price
Natural Gas — 2009
17
$
6.00
17
$
8.75
Oil — 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.
We experience volatility in our financial results based on changes in the fair value of our
option contracts which generally move in the opposite direction from changes in forward commodity
prices. During 2007 and 2005, increases in forward commodity prices reduced the fair value of our
option contracts resulting in a loss. During 2006, decreases in forward commodity prices increased
the fair value of our option contracts resulting in a gain. We
received approximately $45 million
and $59 million in 2007 and 2006 and paid $40 million in 2005 on contracts that settled during
those periods.
Natural gas transportation-related contracts. As of December 31, 2007, our transportation
contracts provide us with approximately 0.6 Bcf/d of pipeline capacity. The recovery of demand
charges related to our transportation contracts and therefore the profitability of these contracts,
is dependent upon our ability to use or remarket 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. In November, 2007, our future earnings exposure relating
to our transportation contracts was reduced with the transfer of our Alliance capacity to a third
party. As of December 31, 2007, our contracts require us to pay demand charges of approximately $41
million in 2008 and an average of $24 million between 2009 and 2012. Our transportation contracts
are accounted for on an accrual basis and impact our revenues as delivery or service under the
contracts occurs. The following table is a summary of demand charges (in millions) and percentage
of recovery of these charges for each of the three years ended December 31:
2007
2006
2005
Alliance:
Demand charges
$
56
$
64
$
65
Recovery(1)
48
%
59
%
93
%
Other:
Demand charges
$
42
$
61
$
91
Recovery
100
%
68
%
69
%
(1)
Excluded from this amount is the $188 million we paid in 2006 in conjunction with the sale of this contract.
Other natural gas derivative contracts. In 2006 we divested or entered into transactions to
divest of a substantial portion of these natural gas contracts, which substantially reduced our
exposure to price movements on these contracts. However, we maintain contracts with third parties
that require us to purchase or deliver natural gas primarily at market prices including a gas
supply contract with the MCV power facility. Additionally, we recognized a $49 million gain in 2006
associated with the assignment of certain natural gas derivative contracts to supply natural gas in
the southeastern U.S. In 2006 in conjunction with sale of the MCV facility in our Power segment, we
recorded a cumulative mark to market loss of approximately $133 million which had not been
previously recognized due to our affiliated ownership interest.
Power Contracts. By the end of 2005, we had substantially eliminated exposure to power price
movements on our legacy power contracts. Prior to eliminating this price risk, we experienced
significant net decreases in the fair value of these contracts based primarily on changes in
natural gas and power prices as well as differences in locational power prices.
The
remaining exposure in our power portfolio is related to several contracts that require us to
swap locational differences in power prices between power plants in the Pennsylvania-New
Jersey-Maryland (PJM) eastern region with the PJM west hub, and provide installed capacity in the
PJM power pool through 2016. The fair value of these contracts decreased by approximately $100
million in 2007 and increased by approximately $70 million in 2006. The losses in 2007 were
primarily the result of increasing installed capacity prices in the PJM region, while the gains in
2006 primarily related to locational price differences in these
regions. By the end of 2006, we had eliminated the
commodity price risk associated with these contracts. In 2007, the PJM
Independent System Operator began conducting periodic auctions to set prices for providing
installed capacity to customers in the PJM power pool. The fair value of our power contracts is
impacted by changes in installed capacity prices, which are based in part on the result of these
auctions. The results of future auctions, and other potential developments with our contracts and
the PJM marketplace may result in future volatility in our operating results. We estimate that a
ten percent change in auction prices from the most recent capacity price of $174/MW-day would
change the fair value of our contracts by approximately $5 million.
Other. During 2005, a bankruptcy court entered an order allowing Mohawk River Funding III’s,
our subsidiary’s, bankruptcy claims with USGen New England. We received payment on these claims and
recognized a gain of $17 million in 2005 in other income related to this settlement.
Overview. Our Power segment consists of assets in Brazil, Asia and Central America. We
continue to pursue the sales of these remaining power investments. As of December 31, 2007, our
remaining investment, guarantees and letters of credit related to projects in this segment totaled
approximately $548 million, which consisted of approximately $514 million in equity investments and
notes receivable and approximately $34 million in financial guarantees and letters of credit as
follows:
Amount
Area
(In millions)
Brazil
Porto Velho
$
275
Manaus & Rio Negro
57
Pipeline projects
138
Asia & Central America
78
Total investment, guarantees and letters of credit
$
548
Operating Results. In 2007, our results were primarily negatively impacted by impairment
losses in Brazil related to the Porto Velho, Manaus and Rio Negro projects. Prior to 2006, our
financial results in this segment were significantly impacted by impairments, net of gains and
losses on sale, on both domestic and other international power facilities. A further discussion of
these events and other factors impacting our results in this segment for the three years ended
December 31 are listed below:
2007
2006
2005
(In millions)
EBIT by Area:
Brazil
Impairments
$
(72
)
$
—
$
—
Other EBIT from operations
51
64
55
Other International Power
Impairments, net of gains (losses) on sales
(1
)
(12
)
(45
)
Other EBIT from operations
(1
)
(1
)
34
Domestic Power
Impairments, net of gains (losses) on sales
—
10
(167
)
Favorable resolution of bankruptcy claim
—
—
53
Gain on sale of available-for-sale investment (1)
—
47
40
Other(2)
(14
)
(26
)
(59
)
EBIT
$
(37
)
$
82
$
(89
)
(1)
Related to the disposition of our shares of International Commodity Exchange in 2005 and 2006.
(2)
Consists of indirect expenses and general and administrative costs and includes $27 million of impairments and losses in 2005.
Brazil. In 2007, our Porto Velho project, Manaus and Rio Negro projects and our other
Brazilian operations (including our interests in the Bolivia-to-Brazil and Argentina-to-Chile
pipelines) generated EBIT losses of $27 million, EBIT losses of $6 million and EBIT of $12
million, respectively. Our 2007 results included charges of $57 million for Porto Velho and
$15 million for Manaus and Rio Negro based on adverse developments at these projects. In 2006 and
2005, EBIT was $41 million and $23 million for Porto Velho, $17 million and $19 million for Manaus
and Rio Negro and $6 million and $13 million for our other Brazilian operations. For a further
discussion of matters that have impacted or could impact our Brazilian investments, see Item 8,
Financial Statements, Note 17.
Other International Power. During 2005, we recorded impairments of $176 million which were
significantly offset by gains on sales of assets of $131 million based on the value received or
expected to be received upon closing the sales of our assets in Asia and Central America. Our
results were also impacted by our decision to not recognize earnings from assets we planned to
sell based on our inability to realize those earnings through their expected selling price. We did
not recognize earnings of approximately $10 million, $26 million and $30 million for the years
ended 2007, 2006 and 2005. We continue to pursue the sale of our remaining
investments in Asia and Central America and until these sales are completed, any changes in
regional political and economic conditions could negatively impact the anticipated proceeds we may
receive, which could result in additional impairments of our investments.
Domestic Power. In 2006, we completed the disposition of our domestic power business. We
recorded a gain in this segment of approximately $10 million, primarily related to the sale of our
investment in MCV. The disposition of our investment in MCV in 2006 also impacted certain
contracts and the financial results in our Marketing segment. Prior to 2006 we sold our interests
in several domestic power facilities and restructured power contracts, resulting in significant
impairments and substantially lower earnings from these operations. In addition, we recorded our
proportionate share of MCV’s losses based on their impairment of the plant assets in 2005.
Field Services
Prior to January 1, 2006, we had a Field Services segment. During 2005, we generated EBIT of
$285 million which, among other items, was primarily due to a gain of $183 million on the sale of
our general partner and limited partner interests in Enterprise
Products Partners, L.P. and a gain of $111 million on the sale of our Javelina processing
operations.
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 activities for each of the three years ended December 31:
2007
2006
2005
(In millions)
Early extinguishment/exchange of debt
$
(291
)
$
(26
)
$
(29
)
Foreign currency fluctuations on Euro-denominated debt
(8
)
(20
)
36
Change in litigation, insurance and other reserves
23
(71
)
(490
)
Lease termination
—
—
(27
)
Other
(7
)
29
(11
)
Total EBIT
$
(283
)
$
(88
)
$
(521
)
Extinguishment of Debt. During 2007,
we incurred losses of $291 million in conjunction with repurchasing or
refinancing more than $5 billion of debt. This amount included $86 million related to repurchasing EPEP’s $1.2 billion notes.
For further information on our debt, see Item 8, Financial Statements, Note 11.
Litigation, Insurance, and Other Reserves. During 2007, we recorded a gain of approximately
$77 million on the reversal of a liability related to The Coastal Corporation’s legacy crude oil
marketing and trading business. For a further discussion of this matter, see Item 8, Financial
Statements, Note 12. We also have a number of pending litigation matters against us. In all of
these matters, we evaluate each lawsuit and claim as to its merits and our defenses. Adverse
rulings and unfavorable settlements against us related to these matters impacted our results in
2007 and 2006 and may further impact our future results. In 2005, 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, in 2005 we incurred charges of $72 million primarily related to the final prepayment
of the Western Energy Settlement and additional charges related to increased premiums from a mutual
insurance company in which we participate, based primarily on the impact of several hurricanes in
2005.
Interest and Debt Expense
Our
interest and debt expense was approximately $1.0 billion, $1.2
billion and $1.3 billion during the years ended December 31, 2007,
2006 and 2005.
Our total interest and debt expense has decreased over the past three years primarily due to
the retirements of debt and other financing obligations, net of issuances. See Part II, Item 8,
Financial Statements and Supplementary Data, Note 11, for a further discussion.
In 2007, our overall effective tax rate on continuing operations for each period differed from
the statutory rate due primarily to earnings from unconsolidated affiliates where we anticipate
receiving dividends that qualify for the dividend received deduction. In 2006 and 2005, we recorded
$159 million and $58 million of tax benefits based primarily on the conclusion of IRS audits. In
2006, the audits of The Coastal Corporation’s 1998-2000 tax years and El Paso’s 2001 and 2002 tax
years were concluded which resulted in the reduction of tax contingencies and the reinstatement of
certain tax credits. In 2005, we finalized The Coastal Corporation’s IRS tax audits for years prior
to 1998.
For a discussion of our effective tax rates and other tax matters, see Part II, Item 8,
Financial Statements and Supplementary Data, Note 4.
Discontinued Operations
Our discontinued operations in the years presented primarily include our ANR pipeline and
related assets, our gathering and processing operations in south Louisiana and certain
international power operations. For the year ended December 31, 2007, income from discontinued
operations was $674 million primarily a result of the gain on the sale of ANR and related
operations of $648 million, net of income taxes of $354 million. For the years ended December 31,2006 and 2005, we had losses from our discontinued operations of $56 million and $96 million. Our
2006 loss of $56 million was primarily a result of recording approximately $188 million of deferred
taxes upon agreeing to sell the stock of ANR, our Michigan storage assets and our 50 percent
interest in Great Lakes Gas Transmission. Prior to our decision to sell, we were only required to
record deferred taxes on individual assets and liabilities and a portion of our investment in the
stock of one of these companies. Our 2005 loss of $96 million was primarily a result of impairments
of our discontinued international power operations partially offset by income from ANR and related
assets and a gain on the sale of our south Louisiana operations. All of these items are further
discussed in Part II, Item 8, Financial Statements and Supplementary Data, Note 2.
Commitments and Contingencies
For a further discussion of our commitments and contingencies, see Part II, Item 8, Financial
Statements and Supplementary Data, Note 12.
Sources and Uses of Cash. Our primary sources of cash are cash flow from operations and
amounts available to us under revolving credit facilities. On occasion and as conditions warrant,
we may also generate funds through capital market activities and proceeds from asset sales. Our
primary uses of cash are funding the capital expenditure programs of our pipeline and exploration
and production operations, meeting operating needs, and repaying debt when due or repurchasing
certain debt obligations when conditions warrant.
Overview of Cash Flow Activities. During 2007, we generated positive operating cash flow of
approximately $1.8 billion, primarily as a result of cash provided by our pipeline and exploration
and production operations. We also sold our ANR pipeline and related assets which generated $3.7
billion of net proceeds. We utilized our operating cash flow and cash from the sale of ANR to fund
maintenance and growth projects in our pipeline and exploration and production operations and to
reduce our debt obligations (see Item 8, Financial Statements, Note 11). In November 2007, we
issued units in a master limited partnership generating gross proceeds
of $575 million from the initial public offering.
For the year ended December 31, 2007 and 2006, our cash flows from continuing operations are
summarized as follows:
2007
2006
(In billions)
Cash Flow from Operations
Continuing operating activities
Income from continuing operations
$
0.4
$
0.5
Loss on debt extinguishment
0.3
—
Other income adjustments
1.4
1.1
Change in other assets and liabilities
(0.3
)
0.2
Total cash flow from operations
$
1.8
$
1.8
Other Cash Inflows
Continuing investing activities
Net proceeds from the sale of assets and investments
$
0.1
$
0.7
Net change in restricted cash and other
—
0.2
0.1
0.9
Continuing financing activities
Net proceeds from the issuance of long-term debt
6.6
0.4
Contribution from discontinued operations
3.4
0.2
Net proceeds from the issuance of common stock
—
0.5
Net proceeds from the issuance of minority interest in consolidated subsidiary
0.5
—
10.5
1.1
Total other cash inflows
$
10.6
$
2.0
Cash Outflows
Continuing investing activities
Capital expenditures
$
2.5
$
2.2
Cash paid for acquisitions, net of cash acquired
1.2
—
3.7
2.2
Continuing financing activities
Payments to retire long-term debt and other financing obligations
8.9
3.0
Dividends and other
0.1
0.2
9.0
3.2
Total cash outflows
$
12.7
$
5.4
Net change in cash
$
(0.3
)
$
(1.6
)
The contribution of cash generated from our discontinued operations reflected above consists
of the following for the year ended December 31, 2007:
Credit Profile. The substantial repayment of debt obligations during 2007 improved our credit
profile and our credit ratings. In March 2007, Moody’s Investor Services upgraded our pipeline
subsidiaries’ senior unsecured debt rating to an investment grade rating of Baa3 and upgraded El
Paso’s senior unsecured debt rating to Ba3 while maintaining a positive outlook. Additionally, in
March 2007, (i) Standard and Poor’s upgraded our pipeline subsidiaries’ senior unsecured debt
rating to BB and upgraded El Paso’s senior unsecured debt rating to BB- maintaining a positive
outlook and (ii) Fitch Ratings initiated coverage on El Paso assigning a rating of BB+ on our
senior unsecured debt and an investment grade rating of BBB- to our pipeline subsidiaries’ senior
unsecured debt. This improvement should provide us a lower cost of
capital on our planned expansion projects in our pipeline business.
In addition, during 2007 we restructured our El Paso and El Paso Exploration & Production
revolving credit agreements with improved terms and pricing and refinanced approximately $2.0
billion of EPEP, SNG and EPNG debt providing us with a lower cost of debt with less restrictive
covenants. We also established a pipeline MLP which provides us a
lower cost of capital and allows us to better compete for expansion
projects of our pipeline business. We
expect to grow our MLP through organic growth and
accretive acquisitions from third parties, El Paso or both.
Liquidity/Cash Flow Outlook. For 2008, we expect to continue to generate positive operating
cash flows. We also anticipate generating over $1 billion upon the completion of asset divestitures
in conjunction with high grading our exploration and production asset portfolio and completing
remaining international power asset sales. We anticipate using cash
proceeds from our exploration and production divestitures to repay
debt in the first quarter of 2008. We expect to use our cash from operations and remaining sales
proceeds primarily for working capital requirements and for expected capital
expenditures. We have approximately $0.3 billion of debt that matures through December 31, 2008
that we currently intend on refinancing. Additionally, we previously announced our intention to
repurchase debt of approximately $0.5 billion of CIG and SNG. In December 2007, we repurchased
approximately $0.2 billion and anticipate completing the remaining $0.3 billion of repurchases in
the first half of 2008.
Our planned cash capital expenditures for 2008 are as follows:
Total
(In billions)
Pipelines
Maintenance
$
0.4
Growth
1.2
Exploration and Production
1.7
Corporate
and other(1)
0.1
$
3.4
(1)
Relates primarily to building renovations at our corporate facilities.
Factors That Could Impact Our Future Liquidity. Based on the simplification of our capital
structure and our businesses, we have reduced the amount of liquidity needed in the normal course
of business. However, our liquidity needs could increase or decrease based on certain factors
described below and others listed in Part 1, Item 1A, Risk Factors. These factors include, but
are not limited to, the completion of planned asset sales, the effect
that our debt level, and
below investment grade credit ratings could have on our cost of
capital, our ability to access capital markets,
and operating costs (primarily margining requirements related to our derivative positions) and
adverse changes in domestic economic conditions, including recession or economic slowdown, which
could also impact the demand for our natural gas transportation services and ultimately impact our
planned growth capital.
Price Risk Management Activities and Cash Margining Requirements. Our Exploration and
Production and Marketing segments have derivative contracts that provide price protection on a
portion of our anticipated natural gas and oil production. The following table shows the contracted
volumes and the minimum, maximum and average cash prices that we will receive under our derivative
contracts when combined with the sale of the underlying production as of December 31, 2007. These
cash prices may differ from the income impacts of our derivative contracts, depending on whether
the contracts are designated as hedges for accounting purposes or not. The individual segment
discussions provide additional information on the income impacts of our derivative contracts.
Fixed Price
Basis
Swaps(1)
Floors(1)
Ceilings(1)
Swaps(1)(2)
Average
Average
Average
Texas Gulf Coast
Onshore-Raton
Rockies
Volumes
Price
Volumes
Price
Volumes
Price
Volumes
Avg. Price
Volumes
Avg. Price
Volumes
Avg. Price
Natural Gas
2008
33
$
7.65
108
$
8.00
108
$
10.80
58
$
(0.33
)
26
$
(1.13
)
13
$
(1.37
)
2009
5
$
3.56
17
$
6.00
17
$
8.75
—
—
15
$
(1.00
)
—
—
2010
5
$
3.70
—
—
—
—
—
—
—
—
—
—
2011-2012
6
$
3.88
—
—
—
—
—
—
—
—
—
—
Oil
2008
2,498
$
88.48
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.
(2)
Our basis swaps effectively limit our exposure to differences between the NYMEX
gas price and the price at the location where we sell our gas. The average prices listed above
are the amounts we will pay per MMBtu relative to the NYMEX price to “lock-in” these
locational price differences.
During
January and February 2008, we entered into (i) 47 TBtu of
options on our anticipated 2008 natural gas production with a floor
price of $8.00 per MMBtu and an average ceiling price of $10.64 per
MMBtu; (ii) 7 TBtu of options on anticipated 2009 natural gas
production with a floor price of $8.00 per MMBtu and a ceiling price
of $11.05 per MMBtu; and (iii) 292 MBbls of fixed price swaps on our
anticipated 2008 oil production at a price of $99.00 per barrel.
We currently post letters of credit for
the required margin on most of our derivative contracts. Historically, we were required to post cash margin deposits for these
amounts. During 2007, approximately $90 million of posted cash margin deposits were returned to us
resulting from settlement of the related contracts and changes in commodity prices. In 2008, based
on current prices, we expect approximately $0.2 billion of the total of $1.0 billion in collateral
outstanding at December 31, 2007 to be returned to us, primarily in the form of letters of credit.
Depending on changes in commodity prices, we could be required to post additional margin or
may recover margin earlier than anticipated. Based on our derivative positions at December 31,2007, a $0.10/MMBtu increase in the price of natural gas would result in an increase in our margin
requirements of approximately $14 million which consists of $5 million for transactions that settle
in 2008, $3 million for transactions that settle in 2009 and $6 million for transactions that
settle in 2010 and thereafter. We have a $250 million unsecured contingent letter of credit
facility available to us if the average NYMEX gas price strip for the remaining calendar months
through March 2008 reaches $11.75 per MMBtu, which is further described in Item 8, Financial
Statements, Note 11.
We enter into a variety of financing arrangements and contractual obligations, some of which
are referred to as off-balance sheet arrangements. These include guarantees, letters of credit and
other interests in variable interest entities.
Guarantees
We are involved in joint ventures and other ownership arrangements that sometimes require
additional financial support in the form 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.
Our potential exposure under guarantee and indemnification agreements can range from a
specified amount to an unlimited dollar amount, depending on the nature of the claim and the
particular transaction. For those arrangements with a specified dollar amount, we have a maximum
stated value of approximately $785 million, for which we are indemnified by third parties for $15
million. These amounts exclude guarantees for which we have issued related letters of credit
discussed in Note 11. Included in the above maximum stated value is approximately $438 million
related to indemnification arrangements associated with the sale of ANR and related operations and
approximately $119 million related to tax matters, related interest and other indemnifications and
guarantees arising out of the sale of our Macae power facility. As of December 31, 2007, we have
recorded obligations of $51 million related to our guarantees and indemnification arrangements, of
which $8 million is related to ANR and related assets and Macae. We are unable to estimate a
maximum exposure for our guarantee and indemnification agreements that do not limit the amount of
future payments due to the uncertainty of these exposures.
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 paid to a closed group of
retirees of one of our former subsidiaries. We have a liability of
approximately $379 million
associated with our estimated exposure under this matter as of December 31, 2007. For a further
discussion of this matter, see Part II, Item 8 Financial Statements and Supplementary Data, Notes
12 and 13.
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, 2007, we had
outstanding letters of credit of approximately $1.3 billion,
including $1.0 billion of letters of
credit securing our recorded obligations related to price risk management activities.
Interests in Variable Interest Entities
We have interests in several 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. As of December 31, 2007, we do not consolidate six
variable interest entities since we are not the primary beneficiary of the variable interest
entity’s operations. For additional information regarding our interests in those entities, see Part
II, Item 8 Financial Statements and Supplementary Data, Note 17, Investments in, Earnings from and
Transactions with Unconsolidated Affiliates.
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 long-term debt, liabilities from commodity-based derivative contracts and other
accrued liabilities, while other obligations, such as demand charges under transportation and
storage commitments, operating leases and capital commitments, are not reflected on our balance
sheet. The following table and discussion that follows summarizes our contractual cash obligations
as of December 31, 2007, for each of the periods presented (all amounts are undiscounted except
liabilities from commodity-based derivative contracts):
Due in Less
Due in 1 to
Due in 4 to
than 1 Year
3 Years
5 Years
Thereafter
Total
(In millions)
Long-term financing obligations:
Principal
$
331
$
1,346
$
2,718
$
8,452
$
12,847
Interest
914
1,677
1,490
8,051
12,132
Liabilities from commodity-based derivative contracts
267
431
319
178
1,195
Other contractual liabilities
56
68
26
54
204
Operating leases
14
23
14
29
80
Other contractual commitments and purchase obligations:
Transportation and storage
26
43
26
100
195
Other
561
91
31
26
709
Total contractual obligations
$
2,169
$
3,679
$
4,624
$
16,890
$
27,362
Long Term Financing Obligations (Principal and Interest). Debt obligations included represent
stated maturities unless otherwise puttable to us prior to their stated maturity date. Contractual
interest payments are shown through the stated maturity date of the related debt. For a further
discussion of our debt obligations see Item 8, Financial Statements and Supplementary Data, Note
11.
Liabilities from Commodity-Based Derivative Contracts. These amounts only include the fair
value of our price risk management liabilities. The fair value of our commodity-based price risk
management assets of $303 million as of December 31, 2007 is not reflected in these amounts. We
have also excluded margin and other deposits held associated with these contracts from these
amounts. For a further discussion of our commodity-based derivative contracts, see the discussion
of commodity-based derivative contracts below.
Other Contractual Liabilities. Included in this amount are contractual, environmental and
other obligations included in other current and non-current liabilities in our balance sheet. We
have excluded from these amounts expected contributions to our pension and other postretirement
benefit plans, because these expected contributions are not contractually required. For further
information on our expected contributions to our pension and post retirement benefit plans, see
Part II, Item 8, Financial Statements and Supplementary Data, Note 13. Also excluded are potential
amounts due under an indemnification of a former subsidiary for benefits being paid to a closed
group of retirees, for which we have a liability of approximately $379 million related to the
litigation associated with this matter as of December 31, 2007. We have also excluded from these
amounts liabilities for unrecognized tax benefits of $157 million as of December 31, 2007,
since we cannot reasonably estimate the time frame over which those amounts may be resolved.
Operating Leases. For a further discussion of these obligations, see Part II, Item 8
Financial Statements and Supplementary Data, Note 12.
Other Contractual Commitments and Purchase Obligations. 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. Included are the following:
•
Transportation and Storage Commitments. Included in these amounts are commitments for
demand charges for firm access to natural gas transportation and storage capacity.
•
Other Commitments. Included in these amounts are 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 have excluded asset retirement obligations and
reserves for litigation, environmental remediation and self-insurance claims as these
liabilities are not contractually fixed as to timing and amount.
Commodity-Based Derivative Contracts. We use derivative financial instruments in our
Exploration and Production and Marketing segments to manage the price risk of commodities. In the
tables below, derivatives designated as hedges primarily consist of options and swaps used to hedge
natural gas production. Other commodity-based derivative contracts relate to derivative contracts
not designated as hedges, such as options, swaps and other natural gas and power purchase and
supply contracts. The following table details the fair value of our commodity-based derivative
contracts by year of maturity and valuation methodology as of December 31, 2007:
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
Non-exchange traded positions
Assets
$
65
$
—
$
—
$
—
$
—
$
65
Liabilities
(19
)
(42
)
(27
)
—
—
(88
)
Total derivatives designated as hedges
46
(42
)
(27
)
—
—
(23
)
Other commodity-based derivatives
Exchange-traded positions(1)
Liabilities
—
(15
)
—
—
—
(15
)
Non-exchange traded positions
Assets
48
72
82
29
7
238
Liabilities
(248
)
(374
)
(292
)
(174
)
(4
)
(1,092
)
Total other commodity-based derivatives
(200
)
(317
)
(210
)
(145
)
3
(869
)
Total commodity-based derivatives
$
(154
)
$
(359
)
$
(237
)
$
(145
)
$
3
$
(892
)
(1)
These positions are traded on active exchanges such as the New York Mercantile Exchange, the International Petroleum Exchange and the London Clearinghouse.
The following is a reconciliation of our commodity-based derivatives for the years ended
December 31, 2007 and 2006:
In 2006 includes derivative contracts
sold/terminated. In 2007, we settled derivative assets
of approximately $381 million by applying the related cash
margin we held against amounts due to us under those
contracts.
(2)
Amounts are net of premiums received.
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, including amounts received from the sale
of option 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. In 2006, the change in fair value also includes a loss on
natural gas supply agreements related to MCV upon the sale of our interest in this facility.
Assignment of Contracts. In 2006, we sold or entered into offsetting derivative transactions
to eliminate the price risk associated with a substantial portion of our remaining historical
natural gas derivatives. We paid proceeds of approximately $32 million related to this transaction.
Designation and Reclassifications of Hedges. During 2006, we removed the hedging designation
on certain derivative contracts where we experienced decreases in the related anticipated hedged
production volumes in Brazil. Also, during 2006 we designated certain existing other
commodity-based derivatives as hedges of our anticipated 2007 natural gas production.
Critical Accounting Estimates
Our significant accounting policies are described in Note 1 to the Consolidated Financial
Statements included in Item 8 of this Annual Report on Form 10-K. The preparation of financial
statements in conformity with generally accepted accounting principles requires management to
select appropriate accounting estimates and to make estimates and assumptions that affect the
reported amount of assets, liabilities, revenue and expenses and the disclosures of contingent
assets and liabilities. We consider our critical accounting estimates to be those that require
difficult, complex, or subjective judgment necessary in accounting for inherently uncertain matters
and those that could significantly influence our financial results based on changes in those
judgments. Changes in facts and circumstances may result in revised estimates and actual results
may differ materially from those estimates. We have discussed the development and selection of the
following critical accounting estimates and related disclosures with the Audit Committee of our
Board of Directors.
Accounting for Natural Gas and Oil Producing Activities. Our estimates of proved reserves
reflect quantities of natural gas, oil and NGL which geological and engineering data demonstrate,
with reasonable certainty, will be recoverable in future years from known reservoirs under existing
economic conditions. 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 complex, requiring
significant judgment in the evaluation of all available geological, geophysical, engineering and
economic data. Our reserve estimates are developed internally by a reserve reporting group which is
separate from our operations group and reviewed by internal committees and internal auditors. In
addition, a third-party reservoir engineering firm, which is appointed by and reports to the Audit
Committee of our Board of Directors, conducted an audit of the estimates of a
significant portion of our proved reserves. The scope of the audit performed by Ryder Scott
included the preparation of an independent estimate of proved natural gas and oil reserves
estimates for fields comprising greater than 80 percent of our total worldwide present value of
future cash flows (pretax). The specific fields included in Ryder Scott’s audit represented the
largest fields based on value.
As of December 31, 2007, of our total proved reserves, 29 percent were undeveloped and 13
percent were developed, but non-producing. The data for a given field may 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
increase 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, including salaries, benefits and other internal costs directly related to these
finding activities. Capitalized costs are maintained in full cost pools 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. 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.
Natural gas and oil properties include unproved property costs that are excluded from costs
being depleted. These unproved property costs include non-producing leasehold, geological and
geophysical costs associated with leasehold or drilling interests and
exploration drilling costs in investments in unproved properties and major development
projects in which we own a direct interest. We exclude these costs on a country-by-country basis
until proved reserves are found or until it is determined that the costs are impaired. All costs
excluded are reviewed at least quarterly to determine if exclusion from the full-cost pool
continues to be appropriate. If costs are determined to be impaired, the amount of any impairment
is transferred to the full cost pool if a reserve base exists or is expensed if a reserve base has
not yet been created. Impairments transferred to the full cost pool increase the depletion rate for
that country.
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, discounted at 10 percent, net of related income tax effects, plus the lower of cost or fair market value of unproved
properties. We utilize end of period spot prices when calculating future net revenues unless those
prices result in a ceiling test charge in which case we evaluate price recoveries subsequent to the
end of the period. If the 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. Higher proved reserves can
reduce the likelihood of ceiling test impairments. We had no ceiling test charges in 2007, 2006 and
2005.
The
price used in the ceiling test calculation 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 a
write-down. A decrease in commodity prices of 10 percent from the price levels at December 31, 2007
would not have resulted in a ceiling test charge in 2007.
Accounting for Legal and Environmental Reserves, Guarantees and Indemnifications. 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 an 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, 2007, we had accrued approximately $460 million for legal matters, net of
related insurance receivables, which includes approximately $379 million associated with an
indemnity for certain retiree benefit payments, which is further discussed below. We have accrued
$260 million for environmental matters. Our environmental estimates range from approximately $260
million to approximately $470 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 ($18 million). Second, where the most likely outcome cannot be
estimated, a range of costs is established ($242 million to $452 million) and the lower end of the
expected range has been accrued.
We also have guarantee and indemnification agreements related to various joint ventures and
other ownership arrangements that require us to assess our potential exposure. This exposure can
range from a specified amount to an unlimited dollar amount, depending on the nature of the claim
and the particular transaction. For those arrangements with a specified dollar amount, we have a
maximum stated value of approximately $785 million, for which we are indemnified by third parties
for $15 million. As of December 31, 2007, we have recorded obligations of $51 million related to
our guarantees and indemnification arrangements. We are unable to estimate a maximum exposure for
our guarantee and indemnification agreements that do not provide for limits on the amount of future
payments under the agreement due to the uncertainty of these exposures. For further information,
see Off Balance Sheet Arrangements above.
Accounting for Pension and Other Postretirement Benefits. We reflect an asset or liability
for our pension and other postretirement benefit plans based on their over funded or under funded
status. As of December 31, 2007, our combined pension plans were over funded by $513 million and
our combined other postretirement benefit plans were under funded by $110 million. Our pension and
other postretirement benefit assets and liabilities 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 matching the
timing and amount of our expected future benefit payments for our pension and other postretirement
benefit obligations to the average yields of various high-quality bonds with corresponding
maturities. We also
compare our discount rates to the Citigroup Pension Discount Curve and to the yields of
several high-quality bond indices with maturity profiles similar to the average duration of our
benefit obligations, including the Moody’s Aa Average Corporate Bond Rate.
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, along with changes to the plans and other items, are deferred and
amortized into income over either the period of expected future service of active participants, or
over the lives of the plan participants. We record these deferred amounts as accumulated other
comprehensive income for our non-regulated operations and as either a regulatory asset or
liability for our regulated operations. As of December 31, 2007
we had deferred losses of approximately $237 million, net of income taxes in accumulated other
comprehensive income. 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, 2007 (in millions):
Pension Benefits
Other Postretirement Benefits
Change in Net
Change in Net
Asset and Pretax
Asset and Pretax
Accumulated Other
Accumulated Other
Net Benefit
Comprehensive
Net Benefit
Comprehensive
Expense (Income)
Income
Expense (Income)
Income
One percent increase in:
Discount rates
$
(11
)
$
170
$
—
$
36
Expected return on plan assets
(23
)
—
(3
)
—
Rate of compensation increase
2
(4
)
—
—
Health care cost trends
—
—
1
(13
)
One percent decrease in:
Discount rates
$
13
$
(201
)
$
—
$
(40
)
Expected return on plan assets(1)
23
—
3
—
Rate of compensation increase
(2
)
3
—
—
Health care cost trends
—
—
(1
)
12
(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.
The estimates for our net benefit expense or 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 over three years, after which they are
considered for inclusion in net benefit expense or income. 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 $6 million lower for the year ended
December 31, 2007.
As stated in Financial Statements and Supplementary Data, Note 12, 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 initial 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. The following table
shows the impact of a one percent change in the primary assumptions used in our calculation of this
liability for the year ended December 31, 2007 (in millions):
Price Risk Management Activities. We record the derivative instruments used in our price risk
management activities at their fair values. 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 at December 31, 2007:
10 Percent Increase
10 Percent Decrease
Fair Value
Fair Value
Change
Fair Value
Change
(In millions)
Derivatives designated as hedges
$
(23
)
$
(117
)
$
(94
)
$
76
$
99
Other commodity-based derivatives
(869
)
(910
)
(41
)
(828
)
41
Total
$
(892
)
$
(1,027
)
$
(135
)
$
(752
)
$
140
Another significant assumption are the discount rates we use in determining the fair value of
our derivative instruments. The table below presents the hypothetical sensitivity of our
commodity- based price risk management activities to changes in fair values arising from changes in
the discount rates we used to determine the fair value of our derivatives at December 31, 2007:
Change in Discount Rate
1 Percent Increase
1 Percent Decrease
Fair Value
Fair Value
Change
Fair Value
Change
(In millions)
Derivatives designated as hedges
$
(23
)
$
(21
)
$
2
$
(25
)
$
(2
)
Other commodity-based derivatives
(869
)
(846
)
23
(894
)
(25
)
Total
$
(892
)
$
(867
)
$
25
$
(919
)
$
(27
)
Other significant assumptions that we use in determining the fair value of our derivative
instruments are those related to anticipated market liquidity and the credit risk of our
counterparties. We believe the application of these assumptions derive a fair value that is
representative of the proceeds we would receive if we disposed of our derivative instruments. We currently do not consider the impact of our credit risk in
determining the fair value of our derivative liabilities, which we will begin considering upon our
adoption of SFAS No. 157, Fair Value Measurements, on January 1, 2008. The assumptions and
methodologies we use to determine the fair values of our derivatives may differ from those used by
our derivative counterparties, and these differences can be significant. As a result, the actual
settlement of our price risk management activities could differ materially from the fair value
recorded and could impact our future operating results.
Deferred Taxes and Uncertain Income Tax Positions. We record deferred income tax assets and
liabilities reflecting tax consequences deferred to future periods based on differences between the
financial statement carrying value of assets and liabilities and the
tax basis of assets and
liabilities. Additionally, our deferred tax assets and liabilities also reflect our assessment
that tax positions taken, and the resulting tax basis, are more likely than not to be sustained if
they are audited by taxing authorities. Our most significant judgments on tax related matters
include, but are not limited to, the items noted below. All of these matters involve the exercise
of significant judgment which could change and materially impact our financial condition or results
of operations. For a further discussion of these items and other income tax matters, see Item 8,
Financial Statements and Supplementary Data, Note 4.
Valuation Allowance. The realization of our deferred tax assets depends on recognition of
sufficient future taxable income in specific tax jurisdictions during periods in which those
temporary differences are deductible. Valuation allowances are established when necessary to
reduce deferred income tax assets to the amounts we believe are more likely than not to be
recovered. In evaluating our valuation allowance, we consider the reversal of existing temporary
differences, the existence of taxable income in prior carryback years, tax planning strategies and
future taxable income for each of our taxable jurisdictions, the latter two of which involve the
exercise of significant judgment. Changes to our valuation allowance
could materially impact our results of operations.
Uncertain Tax Positions. We have liabilities for unrecognized tax benefits related to
uncertain tax positions connected with ongoing examinations and open tax years. Changes in our
assessment of these liabilities may require us to increase the liability and record additional tax
expense or reverse the liability and recognize a tax benefit which would positively or negatively
impact our effective tax rate.
Undistributed
Earnings of Foreign Investees and Certain Unconsolidated Affiliates. We record
deferred tax liabilities on the undistributed earnings of our foreign investments if we anticipate
these earnings to be repatriated. If we do not plan to repatriate these foreign undistributed
earnings, no provision has been made for any U.S. taxes or foreign withholding taxes.
Additionally, we have not recorded a provision for U.S. income taxes on the foreign currency
translation adjustments recorded in accumulated other comprehensive income. Any changes to our
repatriation assumptions, including the repatriation of proceeds from sales of these investments,
could require us to record additional deferred taxes.
Additionally,
we believe certain of our unconsolidated affiliates’ undistributed earnings will ultimately be
distributed to us through dividends which would be eligible for a dividends received deduction. We
and our joint venture partners have the intent and ability to recover these cumulative
undistributed earnings over time through dividends; however, should we subsequently determine that
our unconsolidated affiliates would be unable to pay such dividends, we would be required to record
additional deferred income tax liabilities.
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 that indicates that a long-lived asset or investment may be impaired. If an
event occurs, which is a determination that involves judgment, we then estimate the fair value of
the asset, which considers a number of factors, including the potential value we would receive if
we sold the asset and the projected cash flows of the asset based on current and anticipated future
market conditions. The assessment of project level cash flows requires judgment 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. Utilizing these cash flow projections, we assess our ability to recover the carrying
value of our assets and investments 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, we record an impairment charge for the
excess of carrying value of the asset over its fair value. We recorded impairments of our
long-lived assets of $20 million, $16 million and $73 million and impairments and losses on our
investments in and advances to unconsolidated affiliates of $75 million, $13 million and $347
million during the years ended December 31, 2007, 2006 and 2005. We also recorded asset and
investment impairments of our discontinued operations of $13 million and $502 million, net of
minority interest during the years ended December 31, 2006 and 2005. Future changes in the economic
and business environment can impact our assessments of potential impairments.
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.
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 sale of natural gas and oil in
our Exploration and Production segment, affecting gas not used in the operations of our
Pipelines segment and affecting the fair value of our natural gas and oil derivative
contracts held in our Marketing segment;
•
Natural gas locational price differences change, affecting our ability to optimize
pipeline transportation capacity contracts held in our Marketing segment; and
•
Electricity price changes and locational pricing changes, affecting the value of
our remaining power contracts held in our Marketing segment.
•
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/or the
related interest costs associated with that debt; and
•
Weakening or strengthening of the U.S. dollar relative to the Brazilian real and
the Mexican peso can affect the revenues and expenses generated by our foreign pipeline,
exploration and production, and power operations.
We manage our risks by entering into contractual commitments involving physical or financial
settlement that attempt to limit exposure related to future market movements. The timing and extent
of our risk management activities is based on a number of factors, including our market outlook,
risk tolerance and liquidity. 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 or rates 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 qualify as 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 7.
We attempt to mitigate commodity price risk and stabilize cash flows associated with our
forecasted sales of natural gas and oil production through the use of derivative natural gas and
oil swaps, basis swaps and option contracts. These derivative contracts are entered into by both
our Exploration and Production and Marketing segments. 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.
We have designated certain of these derivatives as accounting hedges. Contracts that are designated
as accounting hedges will impact our earnings when the related hedged production sales occur, and,
as a result, any gain or loss on these hedging derivatives would be offset by a gain or loss on the
sale of the underlying hedged commodity, which is not included in the table. Contracts that are not
designated as accounting hedges impact our earnings as the fair value of these derivatives changes.
Our production-related derivatives do not mitigate all of the commodity price risks of our
forecasted sales of 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
Impact of changes
in commodity prices
on
production-related
derivative
instruments
In our Marketing segment, we have other derivative contracts that are not used to mitigate the
commodity price risk associated with our natural gas and oil production. Many of these contracts,
which include forwards, swaps, options and futures, are long-term historical contracts that we
either intend to assign to third parties or manage until their expiration. We measure risks from
these 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 of
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. To measure Value-at-Risk, we
use what is known as the historical simulation technique. 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 underlying risks. These analyses and our Value-at-Risk
simulations do not include commodity exposures related to our production-related derivatives
(described above), our Marketing segment’s natural gas transportation related contracts that are
accounted for under the accrual basis of accounting, or 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 other
commodity-based derivatives as measured by Value-at-Risk based on a confidence level of 95 percent
and a one-day holding period was $1 million and $6 million as of December 31, 2007 and 2006. Our
highest, lowest and average of the month-end values for Value-at-Risk during 2007 was $6 million,
$1 million and $2 million. We may experience changes in our Value-at-Risk in the future if
commodity prices are volatile.
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 date 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. We
estimate that the fair value of our long-term debt with variable rates approximates its carrying value
because of the market based nature of its interest rate.
Expected Fiscal Year of Maturity of Carrying Amounts
Fair
Carrying
Fair
2008
2009
2010
2011
2012
Thereafter
Total
Value
Amounts
Value
(In millions)
Long-term debt and
other obligations,
including current
portion — fixed rate.
$
318
$
1,097
$
236
$
621
$
425
$
8,248
$
10,945
$
11,244
$
14,093
$
14,891
Average interest rate
6.2
%
6.7
%
6.1
%
6.4
%
7.3
%
7.2
%
Long-term debt and
other obligations,
including current
portion — variable
rate
$
13
$
14
$
15
$
16
$
1,648
$
163
$
1,869
$
1,869
$
596
$
596
Average interest rate
6.3
%
6.3
%
6.3
%
6.3
%
5.0
%
6.3
%
Foreign Currency Exchange Rate Risk
Our exposure to foreign currency exchange rates relates primarily to changes in foreign
currency rates on our Euro-denominated debt obligations. As of
December 31, 2007 and 2006, we have
Euro-denominated debt with a principal amount of
€380 million
and €500
million which matures in 2009. As of December31, 2007 and 2006, we have swaps that effectively convert €330 million and €350 million of
debt into $379 million and $402 million. The remaining principal at December 31, 2007 and 2006 of
€50 million
and
€150 million
is subject to foreign currency exchange risk. A $0.10 change in the
Euro to U.S. dollar exchange rate would result in a $5 million gain or loss on our unhedged
Euro-denominated debt as of December 31, 2007.
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 SEC rules adopted under 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, 2007. 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, 2007.
The effectiveness of our internal control over financial reporting as of December 31, 2007 has been
audited by Ernst & Young LLP, an independent registered public accounting firm, as stated in
their report included herein.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Stockholders of
El Paso Corporation:
We have audited the accompanying
consolidated balance sheets of El Paso Corporation as of December 31, 2007 and 2006, and the related consolidated statements
of income, comprehensive income, stockholders’ equity, and cash flows for the years then ended. Our audits also included the
financial statement schedule listed in the Index at Item 15(a) for the years ended December 31, 2007 and 2006. These
financial statements and schedule are the responsibility of the Company’s management. Our responsibility is to express an
opinion on these financial statements and schedule based on our audits. The financial statements of Citrus Corp. and
Subsidiaries (a corporation in which the Company had a 50% interest as of December 31, 2007 and 2006) and Four Star Oil
& Gas Company (a corporation in which the Company had
approximately a 49% and 43% interest, as of December 31, 2007 and 2006,
respectively) have been audited by other auditors whose reports have been furnished to us, and our opinion on the
consolidated financial statements, insofar as it relates to the amounts included from Citrus Corp. and Subsidiaries
and Four Star Oil & Gas Company, is based solely on the reports of the other auditors. In the consolidated financial
statements, the Company’s combined investments in these companies represent approximately 3% of total assets
as of December 31, 2007 and 2006, and earnings from these investments
represent approximately 23% and
24% of income before income taxes from continuing operations for the years then ended, based on the amounts audited
by other auditors.
We conducted
our audits 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 includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the
accounting principles used and significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits and the reports of other auditors provide a reasonable
basis for our opinion.
In our opinion, based on
our audits and the reports of other auditors, the financial statements referred to above
present fairly, in all material respects, the consolidated financial position of El Paso Corporation at December 31,2007 and 2006, and the consolidated results of its operations and its cash flows for the years then ended, in
conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial
statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly
in all material respects the information set forth therein.
As discussed in Note 1
to the consolidated financial statements, effective January 1, 2007, the Company adopted
the provisions of Financial Accounting Standards Board
Interpretation No. 48, Accounting for Uncertainty in
Income Taxes, an interpretation of FASB Statement No. 109, effective December 31, 2006the Company adopted
the recognition provisions of Statement of Financial Accounting
Standards No. 158, Employers’ Accounting for
Defined Benefit Pension and Other Postretirement Plans - An Amendment of FASB Statements No. 87, 88, 106,
and 132(R), and effective January 1, 2006, the Company adopted the provisions of Statement of Financial
Accounting Standards No. 123(revised 2004), Share-Based Payment and the Federal Energy Regulatory
Commission’s accounting release related to pipeline assessment costs.
We also have audited,
in accordance with the standards of the Public Company Accounting Oversight Board
(United States), El Paso Corporation’s internal control over financial reporting as of December 31, 2007, based
on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission and our report dated February 25, 2008 expressed an unqualified
opinion thereon.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM ON INTERNAL CONTROL OVER
FINANCIAL REPORTING
The Board of Directors and Stockholders of
El Paso Corporation:
We have audited El Paso
Corporation’s internal control over financial reporting as of December 31, 2007, based
on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission (the COSO criteria). El Paso Corporation’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 included in the accompanying Management’s Annual
Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the
Company’s internal control over financial reporting based on our audit.
We conducted our audit 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. Our audit
included obtaining an understanding of internal control over financial reporting, assessing the risk that a material
weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the
assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe
that our audit provides a reasonable basis for our opinion.
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 (1) pertain to the maintenance of records that, in reasonable detail,
accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) 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 (3) 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.
In our opinion, El Paso Corporation
maintained, in all material respects, effective internal control over financial
reporting as of December 31, 2007, based on the COSO criteria.
We also have audited, in accordance
with the standards of the Public Company Accounting Oversight Board
(United States), the 2007 consolidated financial statements of El Paso Corporation and our report dated February 25, 2008 expressed an unqualified opinion thereon.
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Stockholders of
El Paso Corporation:
In our opinion, the consolidated statements of income, comprehensive income, stockholders’
equity and cash flows for the year ended December 31, 2005 present fairly, in all material
respects, the results of operations and cash flows of El Paso Corporation and its
subsidiaries (the “Company”) for the year then ended in conformity with accounting principles
generally accepted in the United States of America. In addition, in our opinion, the
financial statement schedule for the year ended December 31, 2005 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 audit. We conducted our audit 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 audit provides 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 December31, 2005.
Houston, Texas March 2, 2006, except for the eleventh paragraph
of Note 2, as to which the date is May 10, 2006
and the tenth paragraph of Note 2, as to which
the date is February 26, 2007
Report of Independent Registered Public Accounting Firm
To the Stockholders of Four Star Oil & Gas Company:
In our opinion, the consolidated balance sheets and the related consolidated statements of
income, of stockholders’ equity and of cash flows (not presented
separately herein) present fairly,
in all material respects, the financial position of Four Star Oil & Gas Company (the “Company”) and
its subsidiary at December 31, 2007 and 2006, and the results of their operations and their cash
flows for each of the three years in the period ended December 31, 2007, in conformity with
accounting principles generally accepted in the United States of America. These financial
statements are the responsibility of the Company’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
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 described in Notes 3 and 4 to the financial statements, the Company has significant
transactions with affiliated companies. Because of these relationships, it is possible that the
terms of these transactions are not the same as those that would result from transactions among
wholly unrelated parties.
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Stockholders of Citrus Corp.:
In our opinion, the consolidated balance sheets and the related consolidated
statements of income, of stockholders’ equity, of comprehensive
income and of cash flows (not presented separately herein) present
fairly, in all material respects, the financial position of Citrus Corp. and subsidiaries (the
“Company”) at December 31, 2007 and 2006, and the results of their operations and their cash flows
for each of the three years in the period ended December 31, 2007 in conformity with the accounting
principles generally accepted in the United States of America. These consolidated financial
statements are the responsibility of the Company’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
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 Notes 2 and 6 to the consolidated financial statements, the Company adopted the
recognition and disclosure provisions of FASB Statement No. 158 “Employers’ Accounting for Defined
Pension and Other Postretirement Plans — an amendment of FASB Statements No. 87, 88, 106 and
132(R),” as of December 31, 2006.
Short-term financing obligations, including current maturities
331
1,360
Liabilities from price risk management activities
267
278
Liabilities of discontinued operations
—
1,817
Margin deposits held by us
20
344
Accrued interest
195
269
Other
633
1,033
Total current liabilities
2,413
6,151
Long-term financing obligations, less current maturities
12,483
13,329
Other
Liabilities from price risk management activities
931
924
Deferred income taxes
1,157
950
Other
1,750
1,690
3,838
3,564
Commitments and contingencies (Note 12)
Minority interests
565
31
Stockholders’ equity
Preferred stock, par value $0.01 per share; authorized 50,000,000 shares;
issued 750,000 shares of 4.99% convertible perpetual stock; stated at liquidation value
750
750
Common stock, par value $3 per share; authorized 1,500,000,000 shares;
issued 709,192,605 shares in 2007 and 705,833,206 shares in 2006
2,128
2,118
Additional paid-in capital
4,699
4,804
Accumulated deficit
(1,834
)
(2,940
)
Accumulated other comprehensive loss
(272
)
(343
)
Treasury stock (at cost); 8,656,095 shares in 2007 and 8,715,288 shares in 2006
1. Basis of Presentation and Significant Accounting Policies
Basis of Presentation and Principles of Consolidation
Our consolidated financial statements are prepared in accordance with U.S. generally accepted
accounting principles (GAAP) and include the accounts of all majority owned and controlled
subsidiaries after the elimination of all significant intercompany accounts and transactions. Our
financial statements for prior periods include reclassifications that were made to conform to the
current year presentation. These reclassifications did not impact our reported net income (loss) or
stockholders’ equity.
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 (see Note 17) in that entity. The
determination of our ability to control or exert significant influence over an entity and whether
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.
Use of Estimates
The preparation of our financial statements 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 under the Natural Gas Act of 1938, the Natural Gas Policy Act of 1978 and the Energy
Policy Act of 2005. Our pipelines follow the regulatory accounting principles prescribed under
Statement of Financial Accounting Standards (SFAS) No. 71, Accounting for the Effects of Certain
Types of Regulation. Under SFAS No. 71, we record regulatory assets and liabilities that would not
be recorded under GAAP for non-regulated entities. Regulatory assets and liabilities represent
probable future revenues or expenses associated with certain charges or credits that will be
recovered from or refunded to customers through the rate making process. Items to which we apply
regulatory accounting requirements include certain 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.
Cash and Cash Equivalents
We consider short-term investments with an original maturity of less than three months to be
cash equivalents.
We maintain cash on deposit with banks and insurance companies that is pledged for a
particular use or restricted to support a potential liability. We classify these balances as
restricted cash in other current or non-current assets on our balance sheet based on when we expect
the restrictions on this cash to be removed. As of December 31, 2007, we had $7 million of
restricted cash in current assets and $91 million in other non-current assets. As of December 31,2006, we had $8 million of restricted cash in other current assets and $123 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.
Our
inventory consists primarily of supplies and materials and is
classified as current on our balance sheet. We use the average cost
method to account for our inventories. We value all inventory at the
lower of its cost or market value.
Property, Plant and Equipment
Pipelines and Other (Excluding Natural Gas and Oil Properties). 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, an equity return component in our
regulated businesses. We capitalize major units of property replacements or improvements and
expense minor items. Prior to January 1, 2006, we capitalized certain costs our interstate
pipelines incurred related to their pipeline integrity programs as part of our property, plant and
equipment. Beginning January 1, 2006, we began expensing these costs based on FERC guidance. During
the years ended December 31, 2007 and 2006, we expensed
approximately $18 million and $19 million as
a result of the adoption of this accounting release, which was
approximately $0.03 per basic and fully diluted share in 2007 and $0.02 per
basic and fully diluted share in 2006.
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.
When we retire property, plant and equipment in our regulated operations, we charge
accumulated depreciation and amortization for the original cost of the assets in addition to the
cost to remove, sell or dispose of the assets, less their 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.
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 on a
country-by-country basis. 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 for impairment through a ceiling test calculation 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 quarterly. We transfer unproved property costs into the amortizable base when properties are
determined to have proved reserves. In addition, in areas where a natural gas or oil reserve base
exists, 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; 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 discounted at 10 percent plus the lower of cost or fair
market value of unproved properties, net of related income tax effects. We utilize end-of-period
spot prices when calculating future net revenues unless those prices result in a ceiling test
charge in which case we evaluate price recoveries subsequent to the end of the period. If total
capitalized costs exceed the ceiling, we are required to write-down our capitalized costs to the
ceiling. We perform this ceiling test calculation each quarter. Any required write-down is 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.
Asset and Investment Divestitures/Impairments
We evaluate 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) the long-lived asset’s ability to generate future cash flows on
an undiscounted basis or (ii) the fair value of the investment in an unconsolidated affiliate. 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 the asset downward, if necessary, to their estimated fair value. 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 impairment is impacted by a number
of factors, including the nature of the assets being sold and our established time frame for
completing the sale, among other factors.
We reclassify the asset or assets to be sold as either held-for-sale or as discontinued
operations, depending on, among other criteria, whether we will have significant long-term
continuing involvement with those assets after they are sold. We cease depreciating assets in the
period that they are reclassified as either held for sale or discontinued operations.
Pension and Other Postretirement Benefits
We
maintain several pension and other postretirement benefit plans. These plans require us to
make contributions to fund the benefits to be paid out under the plans. These contributions are
invested until the benefits are paid out to plan participants. We record benefit expense 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
13.
Our pension and other postretirement benefit plans use the recognition provisions of SFAS No.
158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans — an
Amendment of FASB Statements No. 87, 88, 106 and 132(R). Under SFAS No. 158, we record an asset or
liability for our pension and other postretirement benefit plans based on their overfunded or
underfunded status. Any deferred amounts related to unrealized gains and losses or changes in
actuarial assumptions are recorded either as a regulatory asset or liability for our regulated
operations or in accumulated other comprehensive income (loss), a component of stockholders’
equity, for our nonregulated operations until those gains and losses are recognized in the income
statement. For a further discussion of our application of SFAS No. 158, see Note 13.
Revenue Recognition
Our business segments provide a number of services and sell a variety of products. We record
revenues for these products and services which include estimates of amounts earned but unbilled. We
estimate these unbilled revenues related to services provided or products delivered based on
contract data, regulatory information, commodity prices, and preliminary throughput and allocation
measurements, among other items. 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. Revenues for all services are generally based on the thermal quantity of gas
delivered or subscribed at a price specified in the contract. 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. 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 delivery and 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 products and services.
Marketing revenues. Our Marketing segment derives revenues from physical natural gas and
power transactions and the management of derivative contracts. Our derivative transactions are
recorded at their fair value and changes in their fair value are reflected net in operating
revenues. For a further discussion of our income recognition policies on derivatives see Price Risk
Management Activities below. The impact of non-derivative transactions, including our
transportation contracts, are recognized net in operating revenues based on the contractual or
market price and related volumes at the time the commodity is delivered or the contracts are
terminated.
Environmental Costs and Other Contingencies
Environmental Costs. We record liabilities at their undiscounted amounts on our balance sheet
as other current and long-term liabilities when 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 recognize a current period
charge in operation and maintenance expense when clean-up efforts do not benefit future periods.
We evaluate any amounts paid directly or reimbursed by government sponsored programs and
potential recoveries or reimbursements of remediation costs from third parties, including insurance
coverage, separately from our liability. Recovery is evaluated based on the creditworthiness or
solvency of the third party, among other factors. When recovery is assured, 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 a liability has been
incurred and the amount of loss can be reasonably estimated. Where the most likely outcome of a
contingency can be reasonably estimated, we accrue a liability for that amount. Where the most
likely outcome cannot be estimated, a range of potential losses is established and if no one amount
in that range is more likely than any other, the low end of the range is accrued.
Price Risk Management Activities
Our price risk management activities consist of the following activities:
•
derivatives entered into to hedge or otherwise reduce the commodity exposure on our
natural gas and oil production and interest rate and foreign currency exposure on our
long-term debt; and
•
derivatives not intended to hedge these exposures, including those related to our legacy
trading activities that we 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 7 for a
further discussion of our price risk management activities. During
2007, we adopted the provisions of FASB Staff Position (FSP) FIN
No. 39-1, Offsetting of Amounts Related to Certain
Contracts, which allowed companies the option to offset amounts
recorded for their derivative contracts with cash collateral posted
or held if the contracts are executed with the same counterparty and
under the same master netting arrangement. We elected to continue to
report separately amounts recorded for derivative contracts from cash
collateral posted or held on our balance sheet and, as a result, our
adoption of this standard had no impact on our financial statements.
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 that we have not
designated as hedges are marked-to-market each period and changes in their fair value are reflected
as revenues.
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.
We record current income taxes based on our current taxable income and 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.
Effective January 1, 2007, we adopted the provisions of FIN No. 48, Accounting for Uncertainty
in Income Taxes. FIN No. 48 clarifies SFAS No. 109, Accounting for Income Taxes, and requires us
to evaluate our tax positions for all jurisdictions and for all years where the statute of
limitations has not expired. FIN No. 48 requires companies to meet a “more-likely-than-not”
threshold (i.e. greater than a 50 percent likelihood of a tax position being sustained under
examination) prior to recording a benefit for their tax positions. Additionally, for tax positions
meeting this “more-likely-than-not” threshold, the amount of benefit is limited to the largest
benefit that has a greater than 50 percent probability of being realized upon effective settlement.
We recognize interest and penalties related to unrecognized tax benefits in income tax
expenses on our income statement.
For a further discussion of the impact of the adoption of FIN No. 48, see Note 4.
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 effects of translating the local currency
to the U.S. dollar are included as a separate component of accumulated other comprehensive income
(loss) in stockholders’ equity on our balance sheet.
Accounting for Asset Retirement Obligations
We account for our asset retirement obligations in accordance with SFAS No. 143, Accounting
for Asset Retirement Obligations and Financial Accounting Standards Board (FASB) Interpretation
(FIN) No. 47, Accounting for Conditional Asset Retirement Obligations. We record a liability for
legal obligations associated with the replacement, removal, or retirement of our long-lived assets.
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 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 as depreciation, depletion and
amortization expense in our income statement. Our regulated pipelines have the ability to recover
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.
Accounting for Stock-Based Compensation.
On January 1, 2006, we adopted SFAS No. 123(R), Share-Based Payment, prospectively for awards
of stock-based compensation granted after that date and for the unvested portion of outstanding
awards at that date. We measure all employee stock-based compensation awards at fair value on the
date they are granted to employees and recognize compensation cost in our financial statements over
the requisite service period. Prior to January 1, 2006, we accounted for stock-based compensation
awards using the intrinsic value method under the provisions of Accounting Principles Board (APB)
Opinion No. 25, Accounting for Stock Issued to Employees, and its related interpretations, and did
not record compensation expense on stock options that were granted at the market value of the stock
on the date of grant. For additional information on our stock-based compensation awards, see
Note 15.
The following table shows the impact on the net loss available to common stockholders and loss
per share had we applied the provisions of SFAS No. 123 in 2005 (in millions, except
for per share amounts):
Net loss available to common stockholders, as reported
$
(633
)
Add: Stock-based employee compensation expense included in reported net loss, net of taxes
12
Deduct: Total stock-based compensation expense determined under fair-value based method
for all awards, net of taxes
(19
)
Net loss available to common stockholders, pro forma
$
(640
)
Loss per common share:
Basic and diluted, as reported
$
(0.98
)
Basic and diluted, pro forma
$
(0.99
)
New Accounting Pronouncements Issued But Not Yet Adopted
As of December 31, 2007, the following accounting standards and interpretations had not yet
been adopted by us.
Fair Value Measurements. In September 2006, the FASB issued SFAS No. 157, Fair Value
Measurements, which provides guidance on measuring the fair value of assets and liabilities in the
financial statements. We will adopt the provisions of this standard for our financial assets and
liabilities effective January 1, 2008, at which time we will be required to consider our own credit
standing in the determination of the fair value of our liabilities. Adoption of the standard is not expected to have a material
impact on our financial statements. The FASB provided a one year deferral of the adoption of SFAS
No. 157 for certain non-financial assets and liabilities. We have elected to defer the adoption for
certain of our non-financial assets and liabilities and are currently evaluating the impact, if
any, that the deferred provisions of this standard will have on our financial statements.
Measurement Date of Pension and Other Postretirement Benefits. In December 2006, we adopted
the recognition provisions of SFAS No. 158. Beginning in 2008, this standard will also require us
to change the measurement date of our pension and other postretirement benefit plans from September
30, the date we currently use, to December 31. Adoption of the measurement date
provisions of this standard is not expected to have a material impact on our financial statements.
Fair Value Option. In February 2007, the FASB issued SFAS No. 159, Fair Value Option for
Financial Assets and Financial Liabilities — including an Amendment to FASB Statement No. 115,
Accounting for Certain Investments in Debt and Equity Securities, which permits entities to choose
to measure many financial instruments and certain other items at fair value. We will adopt the
provisions of this standard effective January 1, 2008, and do
not anticipate that it will have
a material impact on our financial statements.
Business Combinations. In December 2007, the FASB issued SFAS No. 141(R), Business
Combinations, which provides revised guidance on the accounting for acquisitions of businesses.
This standard changes the
current guidance to require that all acquired assets, liabilities,
minority interest and certain contingencies be measured at fair
value, and certain other acquisition-related costs be expensed rather than capitalized. SFAS No.
141(R) will apply to acquisitions that are effective after December 31, 2008, and application of
the standard to acquisitions prior to that date is not permitted.
Noncontrolling Interests. In December 2007, the FASB issued SFAS No. 160, Noncontrolling
Interests in Consolidated Financial Statements, which provides guidance on the presentation of
minority interest in the financial statements. This standard requires that minority interest be
presented as a separate component of equity rather than as a “mezzanine” item between liabilities
and equity, and also requires that minority interest be presented as a separate caption in the
income statement. This standard also requires all transactions with minority interest holders,
including the issuance and repurchase of minority interests, be accounted for as equity
transactions unless a change in control of the subsidiary occurs. SFAS No. 160 is effective for
fiscal years beginning after December 15, 2008, and we are currently evaluating the impact that
this standard will have on our financial statements.
Peoples
Energy Production Company (Peoples). In September 2007, we acquired Peoples for $887
million using cash on hand and borrowings under our revolving credit facilities. Peoples is an
exploration and production company with natural gas and oil properties located primarily in the
Arklatex, Texas Gulf Coast and Mississippi areas and in the San Juan and Arkoma Basins.
We accounted for this acquisition under the purchase method of accounting and allocated the
purchase price primarily to natural gas and oil properties on our balance sheet, which is subject
to change based on the finalization of this allocation. We did not record any goodwill
associated with this transaction.
South Texas properties. In January 2007, we acquired operated natural gas and oil producing
properties and undeveloped acreage in south Texas, for approximately $254 million.
Medicine Bow. In August 2005, we completed the acquisition of Medicine Bow, a privately
held energy company, for total cash consideration of approximately $853 million. As part of the
transaction, we also acquired Four Star, an unconsolidated affiliate of Medicine Bow, and we
reflect our proportionate share of their operating results as earnings from unconsolidated
affiliates in our financial statements (see Note 17). In 2007, we increased our ownership in
Four Star from 43 percent to 49 percent.
Gulf LNG. In February 2008, we closed on the previously announced acquisition of a 50
percent interest in the Gulf LNG Clean Energy Project, a liquefied natural gas (LNG) terminal
which is currently under construction in Pascagoula, Mississippi, and
paid $294 million.
Divestitures
During 2007, 2006 and 2005, we sold a number of assets and investments in each of our business
segments and corporate activities. The table and discussions below summarize the assets sold and
proceeds from these sales:
2007
2006
2005
(In millions)
Power
$
1
$
531
$
625
Field Services
—
—
657
Exploration and Production
2
122
7
Marketing
24
—
—
Pipelines
36
3
49
Corporate
3
2
121
Total continuing(1)
66
658
1,459
Discontinued
3,660
368
577
Total
$
3,726
$
1,026
$
2,036
(1)
Proceeds exclude any returns of capital on our
investments in unconsolidated affiliates and cash
transferred with the assets sold and include costs
incurred in preparing assets for disposal. These items
increased our sales proceeds by $40 million for the year
ended December 31, 2007, increased our sales proceeds by
$15 million for the year ended December 31, 2006, and
decreased our sales proceeds by $35 million for the years
ended December 31, 2005.
Power. Assets sold in 2006 consisted primarily of our interests in MCV and power plants in
Brazil, Asia, and Central America. Assets sold in 2005 consisted primarily of interests in our
power contract restructuring entities and power plants in India and Korea.
Field Services. Assets sold in 2005 consisted primarily of our investment in Enterprise and
the Javelina natural gas processing and pipeline assets.
Exploration and Production, Marketing, Pipelines and Corporate. Assets sold consisted
primarily of our investment in NYMEX and our Stagecoach Pipeline lateral in 2007, natural gas and
oil properties in south Texas in 2006 and pipeline facilities and gathering systems located in the
southeastern and western U.S. and Lakeside Technology Center in 2005.
Discontinued Operations and Assets Held for Sale
Under SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, we
classify assets to be disposed of as held for sale or, if appropriate, discontinued operations when
they have received appropriate approvals to be disposed of by our management or Board of Directors
and when they meet other criteria. Cash flows from our discontinued businesses are reflected as
discontinued operating, investing, and financing activities in our statement of cash flows. To the
extent these operations do not maintain separate cash balances, we reflect the net cash flows
generated from these businesses as a contribution to our continuing operations in cash from
continuing financing activities. The following is a description of our discontinued operations and
summarized results of these operations for the periods ended December 31, 2007, 2006 and 2005. We
also had $28 million of assets held for sale as of December 31, 2006. As of December 31, 2007, all
of our assets and liabilities related to our discontinued operations and assets held for sale had
been sold.
ANR and Related Operations. In February 2007, we sold ANR, our Michigan storage assets and
our 50 percent interest in Great Lakes Gas Transmission for approximately $3.7 billion. We recorded
a gain on the sale of $648 million, net of taxes of $354 million. Included in the net assets of
these discontinued operations as of the date of sale were net deferred tax liabilities assumed by
the purchaser. We also recorded approximately $188 million of deferred taxes in 2006 in
conjunction with the sale.
International Power Operations. During 2006, we completed the sale of all of our discontinued
international power operations including Macae, a wholly owned power plant facility in Brazil, and
Asian and Central American power assets for total net proceeds of approximately $368 million.
Previously in 2005, we recognized approximately $499 million of impairments, net of minority
interest, based upon indications of the value we would receive upon the sale of the assets.
South Louisiana Gathering and Processing Operations. During 2005, we completed the sale of
our south Louisiana gathering and processing assets for net proceeds of approximately $486 million
and recorded a pre-tax gain of approximately $394 million. These assets were part of our
historical Field Services segment.
Other.
Prior to 2005, our Canadian and certain other international natural gas and oil
production operations and our petroleum markets businesses and
operations were approved for sale. We completed the sale of substantially all of these
properties in 2004 and 2005.
Income Taxes on Discontinued Operations. For the years ended December 31, 2007, 2006 and
2005, we incurred income tax expense associated with our discontinued operations of $369 million,
$274 million and $179 million resulting in an effective tax rate of approximately 35%, 126% and
216% for these years. The effective tax rates in 2006 and 2005 are significantly higher than the
statutory rate of 35% primarily due to the following items:
•
In 2006, we recorded approximately $188 million of deferred taxes upon agreeing to sell
the stock of ANR, our Michigan storage assets and our 50 percent interest in Great Lakes Gas
Transmission. Prior to our decision to sell, we only recorded deferred taxes on individual
assets/liabilities and a portion of our investment in the stock of one of these companies;
•
In 2005, (i) impairments and operating losses of certain foreign investments for
which no tax benefit was available, (ii) receipt of dividends from foreign subsidiaries taxable
in the U.S. and (iii) state income taxes.
The following are the components of other income and other expenses from continuing operations
for each of the three years ended December 31:
2007
2006
2005
(In millions)
Other Income
Interest income
$
49
$
138
$
125
Allowance for funds used during construction
32
20
23
Deferred taxes on capitalized funds used during construction
18
11
14
Development, management and administrative services fees on power projects from affiliates
3
7
11
Reversal of liability for legacy crude oil purchases (see Note 12)
77
—
—
Foreign currency gain, net
—
—
36
Gain on sale of non-equity method investments
24
47
40
Dividend income
—
14
19
Other
11
8
17
Total
$
214
$
245
$
285
Other Expenses
Foreign currency losses, net
$
1
$
20
$
—
Loss on sale of non-equity method investments
—
12
—
Other
10
8
17
Total
$
11
$
40
$
17
4. Income Taxes
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 income (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:
2007
2006
2005
(In millions, except rates)
Income taxes at the statutory federal rate of 35%
$
230
$
183
$
(293
)
Increase (decrease)
Audit settlements
—
(159
)
(58
)
Earnings from unconsolidated affiliates where we anticipate receiving dividends
(40
)
(35
)
(36
)
Texas margins tax credit on accumulated net operating loss
(16
)
—
—
State income taxes, net of federal income tax effect
14
20
(16
)
Sales and write-offs of foreign investments
1
(17
)
(7
)
Foreign income taxed at different rates
24
(13
)
75
IRS interest refund
—
(11
)
—
Valuation allowances
10
23
34
Non-taxable Medicare reimbursements
(3
)
(6
)
(25
)
Other
2
6
(5
)
Income taxes
$
222
$
(9
)
$
(331
)
Effective tax rate
34
%
(2
)%
40
%
In 2006 and 2005, our overall effective tax rate on continuing operations was significantly
different than the statutory rate due primarily to the conclusion of IRS audits. In 2006, our audit
settlements primarily relate to the conclusion of the audits of The Coastal Corporation’s 1998-2000
tax years and El Paso’s 2001 and 2002 tax years which resulted in the reduction of tax
contingencies and the reinstatement of certain tax credits. In 2005, audit settlements primarily
relate to the conclusion of The Coastal Corporation’s IRS tax audits for years prior to 1998.
Deferred Tax Assets and Liabilities. The following are the components of our net deferred tax
liability related to continuing operations as of December 31:
2007
2006
(In millions)
Deferred tax liabilities
Property, plant and equipment
$
3,106
$
2,736
Investments in affiliates
227
555
Regulatory and other assets
107
53
Total deferred tax liability
3,440
3,344
Deferred tax assets
Net operating loss and tax credit carryovers
Federal
1,135
1,560
State
188
214
Foreign
105
81
Price risk management activities
439
284
Legal and other reserves
321
332
Other
464
568
Valuation allowance
(137
)
(127
)
Total deferred tax asset
2,515
2,912
Net deferred tax liability
$
925
$
432
We expect to receive sales proceeds within the U.S. on Asia and Central America power assets and
have recorded U.S. deferred tax assets and liabilities on book versus tax basis differences in
these assets. As of December 31, 2007 and 2006, we have U.S. deferred tax assets of $12 million and
$45 million and U.S. deferred tax liabilities of $1 million and $2 million related to these
investments. Cumulative undistributed earnings from substantially all of the remainder of our
foreign subsidiaries and foreign corporate joint ventures (excluding the 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, 2007, the portion of the cumulative undistributed earnings from
these investments on which we have not recorded U.S. income taxes was approximately $117 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.
Unrecognized Tax Benefits (Liabilities) for Uncertain Tax Matters (FIN No. 48). We file
income tax returns in the U.S. federal jurisdiction, and various states and foreign jurisdictions.
With few exceptions, we are no longer subject to U.S. federal, state and local, or non-U.S. income
tax examinations by tax authorities for years before 1999. Additionally, the Internal Revenue
Service has completed an examination of El Paso’s U. S. income tax returns for 2003 and 2004, with
a tentative settlement at the appellate level for all issues. While the settlement of these
matters is expected to change our unrecognized tax benefits in the next twelve months, we do not
anticipate the impact to be significant to our results of operations, financial condition or
liquidity. For our remaining open tax years, our unrecognized tax benefits (liabilities for
uncertain tax matters) could increase or decrease our income tax expense and effective income tax
rates as these matters are finalized, although we are currently unable to estimate the range of
potential impacts these matters could have on our financial statements.
Upon the adoption of FIN No. 48, we recorded additional liabilities for unrecognized tax
benefits of $2 million, including interest and penalties, which we accounted for as an increase of
$4 million to our January 1, 2007 accumulated deficit and an increase of $2 million to additional
paid—in capital. The following table below shows the change in unrecognized tax benefits from
January 1, 2007 to December 31, 2007:
Balance at January 1, 2007 including $39 million of interest and
penalties was $178 million.
(2)
There were no lapses in statutes of limitations during 2007 that impacted
our unrecognized tax benefits.
As
of December 31, 2007, approximately $132 million (net of federal tax benefits) of unrecognized tax
benefits would affect our income tax expense and our effective income tax rate if recognized in
future periods. While the amount of our unrecognized tax benefits could change in the next twelve
months, we do not expect this change to have a significant impact on our results of operations or
financial position.
During the year ended December 31, 2007, we recognized $6
million in interest and penalties. We had $45 million accrued for the payment of interest and
penalties as of December 31, 2007.
Tax Credit and NOL Carryovers. As of December 31, 2007, we have U.S. federal alternative
minimum tax credits of $344 million that carryover indefinitely. The
table below presents the details of our federal and state net operating loss carryover periods as
of December 31, 2007:
Carryover Period
2008
2009-2012
2013-2017
2018-2027
Total
(In millions)
U.S. federal net operating loss
$
—
$
19
$
17
$
2,335
$
2,371
State net operating loss
197
752
553
1,224
2,726
We also had $240 million of foreign net operating loss carryovers and $68 million of foreign
capital loss carryovers which carryover indefinitely. 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. As part of our assessment, we consider future reversals of existing
taxable temporary differences, primarily related to depreciation. We believe it is more likely than
not that we will realize the benefit of our deferred tax assets, net of existing valuation
allowances.
5. Earnings Per Share
We calculated basic and diluted earnings per common share as follows for the three years ended
December 31:
2007
2006
2005
Basic
Diluted
Basic
Diluted
Basic
Diluted
(In millions, except per share amounts)
Income (loss) from continuing operations
$
436
$
436
$
531
$
531
$
(506
)
$
(506
)
Convertible preferred stock dividends
(37
)
(37
)
(37
)
—
(27
)
(27
)
Income (loss) from continuing operations available to
common stockholders
399
399
494
531
(533
)
(533
)
Discontinued operations
674
674
(56
)
(56
)
(96
)
(96
)
Cumulative effect of accounting changes, net of income taxes
—
—
—
—
(4
)
(4
)
Net income (loss) available to common stockholders
$
1,073
$
1,073
$
438
$
475
$
(633
)
$
(633
)
Weighted average common shares outstanding
696
696
678
678
646
646
Effect of dilutive securities:
Options and restricted stock
—
3
—
4
—
—
Convertible preferred stock
—
—
—
57
—
—
Weighted average common shares outstanding and dilutive
potential common shares
696
699
678
739
646
646
Earnings per common share:
Income (loss) from continuing operations
$
0.57
$
0.57
$
0.73
$
0.72
$
(0.82
)
$
(0.82
)
Discontinued operations, net of income taxes
0.97
0.96
(0.08
)
(0.08
)
(0.15
)
(0.15
)
Cumulative effect of accounting changes, net of income taxes
—
—
—
—
(0.01
)
(0.01
)
Net income (loss)
$
1.54
$
1.53
$
0.65
$
0.64
$
(0.98
)
$
(0.98
)
We exclude potentially dilutive securities from the determination of diluted earnings per
share (as well as their related income statement impacts) when their impact on income from
continuing operations per common share is antidilutive. These potentially dilutive securities
consist of our employee stock options, restricted stock, convertible preferred stock, trust
preferred securities, and zero coupon convertible debentures (which were paid off in April 2006).
For the year ended December 31, 2007 and 2006, certain employee stock options and our trust
preferred securities were antidilutive. Additionally, in 2006, our zero coupon convertible
debentures (redeemed in April 2006) were antidilutive and in 2007 our convertible preferred stock
was antidilutive. For the year ended December 31, 2005, we incurred losses from continuing
operations and accordingly excluded all potentially dilutive securities from the determination of
diluted earnings per share as their impact on loss per common share was antidilutive. For a
discussion of our capital stock activity, our stock-based compensation arrangements, and other
instruments noted above, see Notes 14 and 15.
As of December 31, 2007 and 2006, the 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 7
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.
7. 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, 2007 and 2006. 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 and swaps, other natural gas and power purchase and supply contracts, and derivatives
from our historical energy trading activities. 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 liabilities from price risk management activities(1)
$
(783
)
$
(352
)
(1)
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. We use commodity pricing data either
obtained or derived from an independent pricing source and other assumptions about certain power
and natural gas markets to develop price curves. The curves are then used to estimate the value of
settlements in future periods based on the contractual settlement quantities and dates. Finally, we
discount these estimated settlement values using a LIBOR curve. 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. We believe this methodology results in a fair value that is representative
of the proceeds we would receive if we disposed of our derivative
instruments. The estimates utilized in determining the fair value of derivatives are subject to
revisions, either up or down, in future periods based on changes in market conditions. During
2006, we changed the independent pricing source that provided the pricing data we used in valuing
certain of our commodity-based derivative contracts. These changes did not have a material impact
on the fair value of our positions.
Derivatives Designated as Hedges
We engage in two types of hedging activities: hedges of cash flow exposure and hedges of fair
value exposure. When we enter into a derivative contract, we may designate the derivative as either
a cash flow hedge or a fair value hedge, at which time we prepare the documentation required under
SFAS No. 133. 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. 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 or loss to the extent that they are effective and then
recognized in earnings when the hedged transactions occur. 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. The ineffective portion
of a hedge’s change in fair value, if any, is recognized immediately in earnings as a component of
operating revenues or interest and debt expense in our income statement. 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 fixed price swaps and floor and ceiling option contracts to limit our
exposure to decreases in commodity prices as well as fluctuations in foreign currency and
interest rates with the objective of limiting the variability of the cash flows 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, 2007 and 2006 follows:
Accumulated
Other
Estimated
Comprehensive
Income (Loss)
Final
Income (Loss)
Reclassification
Termination
2007
2006
in 2008(1)
Year
(In millions)
Commodity cash flow hedges
Held by consolidated entities
$
(25
)
$
84
$
46
2012
Held by unconsolidated affiliates
(4
)
(4
)
(1
)
2013
Total commodity cash flow hedges
(29
)
80
45
Interest rate and foreign currency cash flow hedges
Fixed rate
(2
)
3
—
2015
De-designated
(4
)
(3
)
—
2009
Total foreign currency cash flow hedges
(6
)
—
—
Total interest rate and cash flow hedges
$
(35
)
$
80
$
45
(1)
Reclassifications occur upon the physical delivery of the hedged commodity or if the forecasted transaction is no longer probable.
For the years ended December 31, 2007, 2006 and 2005, we recognized a net loss of $3 million,
a net gain of $10 million and a net loss of $5 million, net of income taxes, respectively, in our
income (loss) from continuing operations related to the ineffective portion of our cash flow
hedges.
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 protect the value of these debt instruments by converting the fixed amounts of interest
due under the debt agreements to variable interest payments and have recorded the fair value of
these derivatives as a component of long-term debt and the related accrued interest. As of December31, 2007 and 2006, these derivatives were as follows (amounts in millions):
Hedged
Price Risk Management
Weighted
Debt
Asset (Liability)(1)
Derivative
Average Rate
2007
2006
2007
2006
Fixed-to-floating swaps
LIBOR + 4.18%
$
218
$
440
$
(5
)
$
(31
)
Fixed-to-floating cross
currency swaps(2)
LIBOR + 4.23%
379
402
118
67
$
113
$
36
(1)
We did not record any ineffectiveness related to our fair value hedges in 2006 or 2007.
(2)
As of December 31, 2007 and 2006, these derivatives, when combined with our Euro denominated
debt, converted 330 million Euro and 350 million Euro of our debt to $379 million and $402
million.
Other Commodity-Based Derivatives.
Our other commodity-based derivatives primarily relate to derivative contracts not designated
as hedges and other contracts associated with our legacy trading activities.
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 we hold may be more or less than the fair value of our derivative contracts with that
counterparty at any given period. The following table presents a summary of the fair value of our
derivative contracts, net of collateral and liabilities where a right of offset exists. It is
presented by type of derivative counterparty in which we had net asset exposure as of December 31,2007 and 2006:
“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.
We have approximately 48 counterparties as of December 31, 2007. 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, 2007, four counterparties, (Merrill Lynch Commodities, Morgan Stanley
Group, Central Lomas de Real and Constellation Energy Commodities
Group, Inc.) comprise 20 percent, 16 percent,
15 percent and 12 percent, respectively of our net financial asset exposure. As of December 31,2006, three counterparties (Deutsche Bank AG, J. Aron & Company and Constellation Energy
Commodities Group, Inc.) comprised 39 percent, 18 percent and 16 percent of our net financial
instrument asset exposure. The 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.
Our regulatory assets and liabilities relate to our interstate pipeline operations and are
included in other current and non-current assets and liabilities on our balance sheets. These
balances are recoverable or reimbursable over various periods. Below are the details of our
regulatory assets and liabilities as of December 31:
2007
2006
(In millions)
Current regulatory assets
$
—
$
6
Non-current regulatory assets
Taxes on capitalized funds used during construction
122
106
Postretirement benefits
18
22
Unamortized net loss on reacquired debt
59
19
Under-collected income taxes
8
3
Other
14
21
Total non-current regulatory assets
221
171
Total regulatory assets
$
221
$
177
Current regulatory liabilities
$
41
$
16
Non-current regulatory liabilities
Environmental liability
143
130
Cost of removal of offshore assets
7
12
Property and plant depreciation
67
70
Postretirement benefits
90
19
Plant regulatory liability
11
11
Excess deferred income taxes
3
6
Other
7
4
Total non-current regulatory liabilities
328
252
Total regulatory liabilities
$
369
$
268
9. 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:
2007
2006
(In millions)
Other current assets
Prepaid expenses
$
66
$
72
Margin and other deposits held by others
27
60
Deposits
—
60
Other
34
45
Total
$
127
$
237
Other non-current assets
Pension, other postretirement and postemployment benefits (Note 13)
Pension and other postretirement benefits (Note 13)
28
30
Accrued lease obligations
—
56
Asset retirement obligations (Note 10)
41
89
Dividends payable
37
37
Regulatory liabilities (Note 8)
41
16
Other
114
103
Total
$
633
$
1,033
Other non-current liabilities
Environmental and legal reserves (Note 12)
$
590
$
616
Pension, other postretirement and postemployment benefits (Note 13)
236
294
Regulatory liabilities (Note 8)
328
252
Asset retirement obligations (Note 10)
212
154
Other deferred credits
62
159
Insurance reserves
111
118
Other
211
97
Total
$
1,750
$
1,690
10. Property, Plant and Equipment
Depreciable lives. The table below presents the depreciation method and depreciable lives of
our property, plant and equipment:
Method
Depreciable
Lives
(In years)
Regulated interstate systems
Composite
(1)
Non-regulated assets
Natural gas and oil properties
(2)
(2)
Transmission and storage facilities
Straight-line
15-26
Gathering and processing systems
Straight-line
15-40
Transportation equipment
Straight-line
5
Buildings and improvements
Straight-line
4-49
Office and miscellaneous equipment
Straight-line
1-10
(1)
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.
(2)
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. See
Note 1 for additional information.
Excess purchase costs. As of December 31, 2007 and 2006, TGP and EPNG have excess purchase
costs associated with their historical acquisition. Total excess costs on these pipelines were
approximately $2.5 billion and accumulated depreciation was approximately $0.4 billion at December31, 2007 and 2006. These excess costs are being depreciated over the life of the pipeline assets to
which the costs were assigned, and our related depreciation expense for each year ended December31, 2007, 2006, and 2005 was approximately $42 million. We do not currently earn a return on these
excess purchase costs from our rate payers.
Capitalized costs during construction. We capitalize a carrying cost on funds related to our
construction of long-lived assets and reflect these as increases in the cost of the asset on our
balance sheet. This carrying cost consists of (i) an interest cost on our debt that could be
attributed to the assets being constructed, and (ii) in our regulated transmission business, a
return on our equity, that could be attributed to the assets being constructed. The debt portion is
calculated based on the average cost of debt. Interest costs capitalized are included as a
reduction of interest expense in our income statements and were $50 million, $41 million and $41
million during the years ended December 31, 2007, 2006 and 2005. The equity portion is calculated
using the most recent FERC approved equity rate of return. Equity amounts capitalized are included
as other non-operating income on our income statement and were $32 million, $20 million and $23
million during the years ended December 31, 2007, 2006 and 2005.
Construction
work-in progress. At December 31, 2007 and 2006, we had
approximately $1.6
billion and $1 billion of construction work-in-progress included in our property, plant and
equipment.
Asset retirement obligations. We have legal obligations associated with the retirement of our
natural gas and oil wells and related infrastructure, natural gas pipelines, transmission
facilities and storage wells, and obligations related to our corporate headquarters building. In
our production operations, we have obligations to plug wells when abandoned because production is
exhausted or we no longer plan to use the wells. In our pipeline operations, our legal obligations
primarily involve 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 ever demolished, replaced or renovated. We continue
to evaluate our asset retirement obligations and future developments could impact the amounts we
record.
Where we can reasonably estimate the asset retirement obligation liability, we accrue a
liability based on an estimate of the timing and amount of their settlement In estimating the fair
value of the liabilities associated with our asset retirement obligations, we utilize several
assumptions, including a projected inflation rate of 2.5 percent, and credit-adjusted discount
rates that currently range from six to eight percent. We record changes in these estimates based on
the expected amount and timing of payments to settle our asset retirement obligations. Typically,
these changes result from obtaining new information in our Exploration and Production segment about
the timing of our obligations to plug our natural gas and oil wells and the costs to do so. In
2006, we also revised our estimates due primarily to the impacts of hurricanes Katrina and Rita. In
our pipelines operations, we intend on operating and maintaining our natural gas pipeline and
storage systems as long as supply and demand for natural gas exists, which we expect for the
foreseeable future. Therefore, we believe that we cannot reasonably estimate the asset retirement
obligation liability for the substantial majority of our natural gas pipeline and storage system
assets because these assets have indeterminate lives.
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:
2007
2006
(In millions)
Net asset retirement liability at January 1
$
243
$
252
Liabilities settled
(62
)
(48
)
Accretion expense
23
19
Liabilities incurred
16
5
Changes in estimate
33
15
Net asset retirement liability at December 31
$
253
$
243
11. Debt, Other Financing Obligations and Other Credit Facilities
During 2007, we recorded $291 million of pre-tax losses on the extinguishment of certain debt
obligations repurchased and debt refinanced above.
Prior to their redemption in 2006, we recorded accretion expense on our zero coupon
debentures, which increased the principal balance of long-term debt each period. During 2006 and
2005, the accretion recorded in interest expense was $4 million and $25 million. During 2006 and
2005, we redeemed $615 million and $236 million of our zero coupon convertible debentures, of which
$110 million and $34 million represented increased principal due to the accretion of interest on
the debentures. We account for these redemptions as financing activities in our statement of cash
flows.
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):
2008
$
331
2009
1,095
2010
251
2011
643
2012
2,075
Thereafter
8,452
Total long-term financing obligations, including current maturities
$
12,847
Credit Facilities/Letters of Credit
As of December 31, 2007, subject to the terms of various agreements, we had available capacity
under such credit agreements of approximately $1.0 billion,
exclusive of capacity on the El Paso Pipeline Partners, L.P. (EPPP) facility further discussed below. Below is a description of our existing credit facilities as of
December 31, 2007:
$1.5 Billion Revolving Credit Agreement. In November 2007, we restructured our $1.75 billion
credit agreement to eliminate the $0.5 billion deposit letter of credit facility and to increase
the revolving credit facility from $1.25 billion to $1.5 billion. El Paso and certain of its
subsidiaries have guaranteed the $1.5 billion revolving credit agreement, which is collateralized
by our stock ownership in EPNG and TGP who are also eligible borrowers under the $1.5 billion
revolving credit agreement.
Under the $1.5 billion revolving credit facility which matures in November 2012, we can borrow
funds at LIBOR plus 1.25% based on a current applicable margin or issue letters of credit at 1.375%
of the amount issued. We pay an annual commitment fee of 0.25% (based on a current applicable
margin) on any unused capacity under the revolving credit facility. Under the credit agreement, the
applicable margin used to calculate interest on borrowings, letters of credit and commitment fees
is determined by a variable pricing grid tied to the credit ratings of our senior secured debt. As
of December 31, 2007, we had approximately $0.3 billion of
letters of credit issued and $0.4
billion of debt outstanding under this facility.
Unsecured Revolving Credit Facility. We have a $500 million unsecured revolving credit
facility that matures in July 2011 with a third party and a third party trust that provides for
both borrowings and issuing letters of credit. We are required to pay fixed facility fees at a rate
of 2.34% on the total committed amount of the facility. In addition, we will pay interest on any
borrowings at a rate comprised of either LIBOR or a base rate. Substantially all of the capacity under this facility
was used to issue letters of credit.
Unsecured Credit Facility. In June 2007, we entered into a $150 million unsecured facility
that provides for both borrowings and issuing letters of credit. As of December 31, 2007, we had
increased the capacity under this facility to $500 million. The facility matures in various
tranches during 2009. Based on this facility size, we are required to pay a fixed facility fee at a
weighted average rate of 1.58% per annum on the full facility amount. Borrowings carry an interest
rate of LIBOR in addition to the facility fee. Substantially all of
the capacity under the facility has been used to issue
letters of credit.
EPEP $1.0 Billion Revolving Credit Agreement. In September 2007, we amended and restated
EPEP’s revolving credit facility, increasing the capacity by $0.5 billion to $1.0 billion. The
other material terms and conditions of this facility remain the same. As of December 31, 2007, we
had $0.8 billion outstanding under this facility. Based on current borrowing levels, we pay
interest at LIBOR plus 1.25% on borrowings, and a commitment fee of 0.30% on any unused capacity.
This facility is
collateralized by certain of our natural gas and oil properties, which are subject to revaluation
on a semi-annual basis. As of December 31, 2007, the most recent determination was sufficient to
fully support this facility.
Contingent Letter of Credit Facility. We have a $250 million unsecured contingent letter of
credit facility that matures in March 2008. Letters of credit are available to us under the
facility if the average NYMEX gas price strip for the remaining calendar months through March 2008
is equal to or exceeds $11.75 per MMBtu. The facility fee, if triggered, is 1.66% per annum.
El Paso Pipeline
Partners, L.P. Revolving Credit Facility. In November 2007, EPPP and WIC, their subsidiary, entered into an unsecured 5-year revolving credit
facility with an initial aggregate borrowing capacity of up to
$750 million expandable to $1.25 billion for certain
expansion projects and acquisitions. This facility is only
available to EPPP and its subsidiaries and borrowings are guaranteed
by EPPP or its
subsidiaries. Amounts borrowed are non-recourse to El Paso. Approximately $455 million was
outstanding under the credit facility as of December 31, 2007.
The credit facility has two pricing grids, one based on credit
ratings and the other based on leverage. Currently, the leverage
pricing grid is in effect and EPPP’s cost of borrowings is LIBOR
plus 0.525% based on EPPP’s current leverage. EPPP also pays a
0.125% annual commitment fee for this facility.
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, 2007, we had outstanding letters of credit of approximately $1.3 billion. Included in
this amount is $1.0 billion of letters of credit securing our recorded obligations related to price
risk management activities.
Restrictive Covenants
$1.5 billion Revolving Credit Agreement. Our covenants under the $1.5 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 and cross-acceleration. 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 most restrictive debt covenants and cross default provisions are:
(a)
Our ratio of Debt to Consolidated EBITDA, each as defined in the credit agreement, shall
not exceed 5.5 to 1 at anytime prior to June 30, 2008. Thereafter it shall not exceed 5.25
to 1 until maturity;
(b)
Our ratio of Consolidated EBITDA, as defined in the credit agreement, to interest expense
plus dividends paid shall not be less than 1.75 to 1 at anytime prior to June 30, 2008.
Thereafter it shall not be less than 2.00 to 1 until maturity;
(c)
EPNG and TGP 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; and
(d)
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.
EPEP $1.0 Billion Revolving Credit Agreement. EPEP’s borrowings under this facility are
subject to various conditions. The financial coverage ratio under the facility requires that EPEP’s
EBITDA, as defined in the facility, to interest expense not be less than 2.0 to 1 and EPEP’s debt
to EBITDA, each as defined in the credit agreement, must not exceed 4.0 to 1.
EPPP Revolving Credit Facility. EPPP’s borrowings under the credit facility contains
covenants and provisions, the most restrictive of which requires EPPP to maintain, as of the end of each fiscal quarter, a
consolidated leverage ratio (consolidated indebtedness to consolidated EBITDA (as defined in the
credit facility)) of less than 5.0 to 1.0 for any four consecutive quarters; and 5.5 to 1.0 for any
three consecutive quarters subsequent to the consummation of specified permitted acquisitions
having a value greater than $25 million. EPPP has also added additional flexibility to their
covenants for growth projects. In case of a capital construction or expansion project in excess of
$20 million, adjustments to consolidated EBITDA, approved by the lenders, may be made
based on the percentage of capital costs expended and projected cash flows for the project. Such
adjustments shall be limited to 25% of actual EBITDA.
Other Restrictions and Provisions. In addition to the above restrictions and 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 ability 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. Our most
restrictive acceleration provision is $10 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 $10 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.
We have also issued various guarantees securing financial obligations of our subsidiaries and
affiliates with similar covenants as the above facilities.
Other Financing Arrangements
Capital Trusts. El Paso Energy Capital Trust I (Trust I), is a wholly owned business trust
formed in March 1998 that issued 6.5 million of 4.75 percent trust convertible preferred securities
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, which are 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.
Non-Recourse Project Financings. Several of our subsidiaries and investments have debt
obligations related to their costs of construction or acquisition. This project financing
debt is recourse only to the project company and assets (i.e. without recourse to El Paso).
As of December 31, 2007, two international power projects accounted for as equity
investments are in default under their debt agreements; however, we
have no material exposure as a result of these defaults.
ERISA Class Action Suit. 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 that our communication with participants in our Retirement Savings Plan
included various 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). Various motions have been filed and we are awaiting the court’s ruling. We have insurance
coverage for this lawsuit, subject to certain deductibles and co-pay obligations. We have
established accruals for this matter which we believe are adequate.
Cash Balance Plan Lawsuit. In December 2004, a purported class action 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 alleges various violations of ERISA and the Age
Discrimination in Employment Act as a result of our change from a final average earnings formula
pension plan to a cash balance pension plan. Certain of the claims that our cash balance plan
violated ERISA were recently dismissed by the trial court. Our costs and legal exposure related to
this lawsuit are not currently determinable.
Shareholder
Litigation. In 2007, we settled twenty-eight shareholder class action
lawsuits that had alleged violations of federal securities laws by us and several of our current and former officers and
directors. Under the settlement, we contributed approximately
$48 million, our insurers
contributed approximately $225 million, and a third party contributed $12 million.
Retiree Medical Benefits Matters. We 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 July1, 1994. Case was formerly a subsidiary of Tenneco, Inc. that was spun off in 1994. Tenneco
retained an obligation to provide certain medical benefits at the time of the spin-off and we
assumed this obligation as a result of our merger with Tenneco. Pursuant to an agreement with the
applicable union for Case employees, our liability for these benefits was subject to a cap, such
that costs in excess of the cap were to be assumed by plan participants. In 2002, we and Case were
sued by individual retirees in a 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 was obligated to indemnify
Case 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
by the U.S. Court of Appeals for the 6th Circuit. In October 2007, pending a trial on the merits,
the court expanded the number of retirees covered by its prior preliminary rulings. We will proceed
with a trial on the merits with regard to the issues of whether the cap is enforceable and to what
degree benefits have actually vested. Until this is resolved, El Paso will indemnify Case for
payments Case makes above the cap, which are currently about $2 million per month. We continue to
defend the action and have 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. 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 obligation. We have established an accrual for this matter which we believe is adequate
and further discussed in guarantees and indemnifications below.
Natural Gas Commodities Litigation. Beginning in August 2003, several lawsuits were filed
against El Paso Marketing L.P. (EPM) alleging 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 cases were consolidated in federal court
in New York for all pre-trial purposes and were styled In re: Gas Commodity Litigation. 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. A settlement was finalized and
has been paid. The second set of cases, involving similar allegations on behalf of commercial and
residential customers, was transferred to a multi-district litigation proceeding (MDL) in the U.S.
District Court for Nevada and styled In re: Western States Wholesale Natural Gas Antitrust
Litigation. These cases were dismissed. The U.S. Court of Appeals for the Ninth Circuit, however,
reversed the dismissal and ordered that these cases be remanded to the trial court. A petition for
certiorari has been filed with the U.S. Supreme Court. The third set of cases also involve similar
allegations on behalf of certain purchasers of natural gas. These include Farmland Industries v.
Oneok Inc., et al. (filed in state court in Wyandotte County, Kansas in July 2005) and Missouri
Public Service Commission v. El Paso Corporation, et al. (filed in the circuit court of Jackson
County, Missouri at Kansas City in October 2006), and the purported class action lawsuits styled:
Leggett, et al. v. Duke Energy Corporation, et al. (filed in Chancery Court of Tennessee in January
2005); Ever-Bloom Inc., et al. v. AEP Energy Services Inc., et al. (filed in federal court for
the Eastern District of California in September 2005); Learjet, Inc., et al. v. Oneok Inc., et al.
(filed in state court in Wyandotte County, Kansas in September 2005); Breckenridge, et al. v. Oneok
Inc., et al. (filed in state court in Denver County, Colorado in May 2006); Arandell, et al. v.
Xcel Energy, et al. (filed in the circuit court of Dane County, Wisconsin in December 2006); and
Heartland, et al. v. Oneok Inc., et al. (filed in the circuit court of Buchanan County, Missouri in
March 2007). The Leggett case was dismissed by the Tennessee state court and has been appealed.
The remaining cases have all been transferred to the MDL proceeding. The Missouri Public Service
case has been remanded to state court. Dispositive motions have been filed or are anticipated to
be filed in these cases. Our costs and legal exposure related to these lawsuits and claims are not
currently determinable.
Gas Measurement Cases. A number of our subsidiaries were named defendants in actions that
generally allege mismeasurement of natural gas volumes and/or heating content resulting in the
underpayment of royalties. The first set of cases was filed in 1997 by an individual under the
False Claims Act, which have been consolidated for pretrial purposes (In re: Natural Gas Royalties
Qui Tam Litigation, U.S. District Court for the District of Wyoming). 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. In October 2006, the U.S. District Judge issued an
order dismissing all claims against all defendants. An appeal has been filed.
Similar allegations were filed in a set of actions initiated in 1999 in Will Price, et al. v.
Gas Pipelines and Their Predecessors, et al., in the District Court of Stevens County, Kansas. The
plaintiffs currently seek certification of a class of royalty owners in wells on non-federal and
non-Native American lands in Kansas, Wyoming and Colorado. Motions for class certification have
been briefed and argued in the proceedings and the parties are awaiting the court’s ruling. The
plaintiff seeks an unspecified amount of monetary damages in the form of additional royalty
payments (along with interest, expenses and punitive damages) and injunctive relief with regard to
future gas measurement practices. Our costs and legal exposure related to these lawsuits and claim
are not currently determinable.
MTBE. 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 the potential
impact of MTBE on water supplies. Some of our subsidiaries are among the defendants in
approximately 80 such lawsuits. The plaintiffs, certain state attorneys general, various water
districts and a limited number of individual water customers, generally seek remediation of their
groundwater, prevention of future contamination, damages (including natural resource 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. Although these suits had been consolidated for pre-trial
purposes in multi-district litigation in the U.S. District Court for the Southern District of New
York, a recent appellate court decision directed two of the cases to be remanded back to state
court. A limited number of cases have since been remanded to separate state court proceedings. It
is possible many of the other cases will also be remanded. We have
reached an agreement in
principle with the plaintiffs to settle approximately 60 of the lawsuits. We have also reached an
agreement in principle with our insurers, whereby our insurers would fund substantially all of the
consideration to be provided by our subsidiaries under the terms of the settlement with the
plaintiffs. Approximately 20 of the remaining lawsuits are not covered by the terms of this
settlement. While the damages claimed in these remaining actions are substantial there remains
significant legal uncertainty regarding the validity of the causes of action asserted and the
availability of the relief sought by the plaintiffs. We have tendered these remaining cases to our
insurers. Our costs and legal exposure related to these remaining lawsuits are not currently
determinable.
Government Investigations and Inquiries
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 continue to cooperate
with the SEC in its investigation related to such reserve revisions. We originally self-reported
this matter to the SEC and have been cooperating fully with the investigation, which has included
producing a large volume of documents and making our employees available for interviews or
testimony upon request. On July 13, 2007, we received a notice indicating the SEC staff has made a
preliminary decision to recommend to the SEC that it institute an enforcement action against us and
two of our subsidiaries related to the reserve revisions. We understand that the staff of the SEC
may have also issued similar notices to several of our former employees related to the reserves
revisions. We were given the opportunity to respond to the staff before it makes its formal
recommendation on whether any action should be brought by the SEC, and on September 25, 2007 we
submitted our response.
Legacy
Crude Oil Trading. In 2007, we recorded $77 million of other income in our income statement
related to the reversal of amounts accrued prior to 2001 relating to shipments of crude oil
allegedly purchased by Coastal in 1990. We reversed these amounts following the expiration of the related statute of limitation
periods and the completion of a review of
the matter and related defenses.
In addition to the above proceedings, 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. For each of these 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, including those 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. It is possible, however, 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, 2007,
we had approximately $460 million accrued, net of related insurance receivables, for our
outstanding legal and governmental proceedings.
Rates and Regulatory Matters
Notice of Inquiry on Pipeline Fuel Retention Policies. In September 2007, the FERC issued a
Notice of Inquiry regarding its policy about the in-kind recovery of fuel and lost and unaccounted
for gas by natural gas pipeline companies. Under current policy, pipelines have options for
recovering these costs. For some pipelines, the tariff states a fixed percentage as a
non-negotiable fee-in-kind retained from the volumes tendered for shipment by each shipper. There
is also a tracker approach, where the pipeline’s tariff provides for prospective adjustments to the
fuel retention rates from time-to-time, but does not include a mechanism to allow the pipeline to
reconcile past over or under-recoveries of fuel. Finally, some pipelines’ tariffs provide for a
tracker with a true-up approach, where provisions in a pipeline’s tariff allow for periodic
adjustments to the fuel retention rates, and also provide for a true-up of past over and
under-recoveries of fuel and lost and unaccounted for gas. In this proceeding, the FERC is seeking
comments on whether it should change its current policy and prescribe a uniform method for all
pipelines to use in recovering these costs. Our pipeline subsidiaries currently utilize a variety
of these methodologies. At this time, we do not know what impact this proceeding may
ultimately have on any of us.
Notice
of Proposed Rulemaking. On October 3, 2007, the Minerals Management Service (MMS)
issued a Notice of Proposed Rulemaking for “Oil and Gas and Sulphur Operations in the Outer
Continental Shelf — Pipelines and Pipeline Rights-of-Way”. If adopted, the proposed rules would
substantially revise MMS Outer Continental Shelf (OCS) pipeline and rights-of-way (ROW)
regulations. The proposed rules would have the effect of: (1) increasing the financial obligations
of entities, like us, which have pipelines and pipeline rights-of-way in the OCS; (2) increasing
the regulatory requirements imposed on the operation and maintenance of existing pipelines in the
OCS; and (3) increasing the requirements and preconditions for
obtaining new rights-of-way in the
OCS. .
EPNG. In August 2007, EPNG received approval of the settlement of its rate case from the FERC.
The settlement provides benefits for both EPNG and its customers for a three year period ending
December 31, 2008. Under the terms of the settlement, EPNG is required to file a new rate case to
be effective January 1, 2009. EPNG received approval from the FERC to begin billing the settlement
rates on October 1, 2007. Our financial statements reflect EPNG’s settled rates. Additionally, in
2007 and 2006, we recorded rate refund provisions of approximately $60 million and $65 million
inclusive of interest, which we reflected as accrued liabilities on our balance sheet. In the
fourth quarter of 2007, EPNG refunded $115 million including interest in rate refunds to its
customers and refunded the remaining $10 million in January 2008.
Other Contingencies
Navajo Nation. Approximately 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 are the subject of a pending
renewal application filed in 2005 with the Department of the Interior’s Bureau of Indian Affairs.
An interim agreement with the Navajo Nation expired at the end of December 2006. Negotiations on
the terms of the long-term agreement are continuing. In addition, we continue to preserve other
legal, regulatory and legislative 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. It is
uncertain whether our negotiation, or other alternatives, will be successful, or if successful,
what the ultimate cost will be of obtaining the rights-of-way and whether we will be able to
recover these costs in EPNG’s rates.
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. At December 31, 2007, we accrued approximately $260 million, which has not been
reduced by $27 million for amounts to be paid directly under government sponsored programs. Our
accrual includes approximately $251 million for expected remediation costs and associated onsite,
offsite and groundwater technical studies and approximately $9 million for related environmental
legal costs. Of the $260 million accrual, $22 million was reserved for facilities we currently
operate and $238 million was reserved for non-operating sites (facilities that are shut down or
have been sold) and Superfund sites.
Our estimates of potential liability range from approximately $260 million to approximately
$470 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 ($18 million).
Second, where the most likely outcome cannot be estimated, a range of costs is established ($242
million to $452 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. Our recorded liabilities 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 2008, we estimate that our total remediation expenditures will be approximately $65 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 $7 million in the aggregate
for the years 2008 through 2011. These expenditures primarily relate to compliance with clean air
regulations.
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 44 active sites under the Comprehensive 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, 2007, we have estimated our share of the
remediation costs at these sites to be between $27 million and $49 million. Because the clean-up
costs are estimates and are subject to revision as more information becomes available about the
extent of remediation required, and 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, operating facilities and equipment. The
terms of the agreements vary from 2008 until 2053. Minimum annual rental commitments under our
operating leases at December 31, 2007, were as follows:
Year Ending December 31,
Operating
Leases(1)
(In millions)
2008
$
14
2009
13
2010
10
2011
7
2012
7
Thereafter
29
Total
$
80
(1)
Amounts have not been reduced by minimum sublease rentals of approximately $1 million due
in the future under noncancelable subleases.
Rental expense on our lease obligations for the years ended December 31, 2007, 2006, and 2005
was $40 million, $43 million and $53 million, which includes $27 million in 2005 related to
consolidating our Houston-based operations.
Guarantees. We are involved in various joint ventures and other ownership arrangements that
sometimes require 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 and environmental matters.
Our potential exposure under guarantee and indemnification agreements can range from a
specified amount to an unlimited dollar amount, depending on the nature of the claim and the
particular transaction. For those arrangements with a specified dollar amount, we have a maximum
stated value of approximately $785 million, for which we are indemnified by third parties for $15
million. These amounts exclude guarantees for which we have issued related letters of credit
discussed in Note 11. Included in the above maximum stated value is approximately $438 million
related to indemnification arrangements associated with the sale of ANR and related operations and
approximately $119 million related to tax matters, related interest and other indemnifications and
guarantees arising out of the sale of our Macae power facility. As of December 31, 2007, we have
recorded obligations of $51 million related to our guarantees and indemnification arrangements, of
which $8 million is related to ANR and related assets and Macae. We are unable to estimate a
maximum exposure for our guarantee and indemnification agreements that do not provide for limits on
the amount of future payments due to the uncertainty of these exposures.
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 $379 million
associated with our estimated exposure under this matter as of December 31, 2007. 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, 2007, we had firm
commitments under transportation and storage capacity contracts of
$195 million due at various times and other purchase
and capital commitments (including maintenance, engineering, procurement and construction
contracts) of $709 million, the substantial majority of which is
due in less than one year.
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 by us (see Navajo Nation above).
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, Inc. or The Coastal
Corporation 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 2008.
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 expect to contribute $4 million to the SERP in 2008. We also maintain two other frozen pension
plans that are closed to new participants which provide benefits to former employees of our
previously discontinued coal and convenience store operations. We do not anticipate making any
contributions to our frozen pension plans in 2008. 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 2007, 2006 and 2005 were not material.
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 depending on our
performance relative to our peers. Amounts expensed under this plan were approximately $16 million,
$30 million and $25 million for the years ended December 31, 2007, 2006 and 2005.
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 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 $27 million to our postretirement plans in 2008.
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. On December 31, 2006, we adopted the recognition
provisions of SFAS No. 158, and upon adoption we reflected the assets and liabilities related to
our pension and other postretirement benefit plans based on their funded or unfunded status and all
actuarial deferrals were reclassified as a component of accumulated other comprehensive income. The
adoption of this standard decreased our other non-current assets by $601 million, our other
non-current deferred tax liabilities by $210 million, and our accumulated other comprehensive
income by $391 million. In March 2007, the FERC issued guidance requiring regulated pipeline
companies to recognize a regulatory asset or liability for the funded status asset or liability
that would otherwise be recorded in accumulated other comprehensive income under SFAS No. 158, if
it is probable that amounts calculated on the same basis as SFAS No. 106, Employers’ Accounting for
Postretirement Benefits Other Than Pensions, would be included in our rates in future periods. Upon
adoption of this FERC guidance, we reclassified approximately $9 million from the beginning balance
of accumulated other comprehensive income to regulatory liabilities, which is included in other
non-current liabilities on our balance sheet.
The table below provides additional information related to our pension and other
postretirement plans as of September 30, our measurement date, for our benefit obligations and plan
assets and as of December 31 for the balance sheet amounts:
Our accumulated benefit obligation for our defined benefit pension plans was $2.0 billion and
$2.1 billion as of December 31, 2007 and 2006. Our projected benefit obligation and accumulated
benefit obligation for our pension plans whose accumulated benefit obligations exceeded the fair
value of plan assets, was $37 million as of December 31, 2007 and $167 million as of December 31,2006.
Our accumulated postretirement benefit obligation for our other postretirement benefit plans
whose accumulated postretirement benefit obligations exceeded the fair value of plan assets was
$222 million and $320 million as of December 31, 2007 and 2006.
Our accumulated other comprehensive income includes approximately $8 million of unamortized
prior service costs, net of tax. We anticipate that approximately $16 million of our accumulated
other comprehensive loss, net of tax, will be recognized as a part of our net periodic benefit cost
in 2008.
Change in 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
2007
2006
2007
2006
(In millions)
Change in benefit obligation(1):
Benefit obligation — beginning of period
$
2,157
$
2,235
$
494
$
527
Service cost
17
17
1
11
Interest cost
119
118
26
26
Participant contributions
—
—
32
34
Actuarial gain
(86
)
(37
)
(66
)
(35
)
Benefits paid
(186
)
(176
)
(69
)
(69
)
Other
6
—
—
—
Benefit obligation — end of period
$
2,027
$
2,157
$
418
$
494
Change in plan assets:
Fair value of plan assets at beginning of period
$
2,382
$
2,350
$
276
$
251
Actual return on plan assets(2)
333
192
39
19
Employer contributions
8
16
25
41
Participant contributions
—
—
32
34
Benefits paid
(186
)
(176
)
(69
)
(69
)
Fair value of plan assets at end of period
$
2,537
$
2,382
$
303
$
276
Reconciliation of funded status:
Fair value of plan assets at September 30
$
2,537
$
2,382
$
303
$
276
Less: Benefit obligation — end of period
2,027
2,157
418
494
Funded status at September 30
510
225
(115
)
(218
)
Fourth quarter contributions and income
3
3
5
9
Net asset (liability) at December 31
$
513
$
228
$
(110
)
$
(209
)
(1)
Benefit obligation in the table above refers to the projected benefit obligation for our pension plans and accumulated postretirement benefit obligation for our postretirement plans.
(2)
We defer the difference between our actual return on plan assets and our expected return over a three year period, after which they are considered for inclusion in net benefit expense or
income. Our deferred actuarial gains and losses are amortized only to
the extent that our remaining unrecognized actual gains and losses exceed the greater of 10 percent of our projected
benefit obligations or market related value of plan assets.
Expected Payment of Future Benefits. As of December 31, 2007, we expect the following
payments under our plans, net of participant contributions:
Year Ending
Other Postretirement
December 31
Pension Benefits
Benefits(1)
(In millions)
2008
$
167
$
44
2009
167
43
2010
166
42
2011
164
41
2012
163
39
2013-2017
793
173
(1)
Includes a reduction in each of the years presented 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:
Pension Benefits
Other Postretirement Benefits
2007
2006
2005
2007
2006
2005
(In millions)
Service cost
$
17
$
17
$
22
$
1
$
11
$
1
Interest cost
119
118
121
26
26
29
Expected return on plan assets
(181
)
(175
)
(168
)
(16
)
(14
)
(12
)
Amortization of net actuarial loss
43
55
69
(1
)
—
—
Amortization of prior service cost(1)
(2
)
(2
)
(2
)
(1
)
(1
)
(1
)
Other
—
(2
)
1
—
(1
)
8
Net benefit cost (income)
$
(4
)
$
11
$
43
$
9
$
21
$
25
(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 2007, 2006 and 2005:
Other
Pension Benefits
Postretirement Benefits
2007
2006
2005
2007
2006
2005
(Percent)
(Percent)
Assumptions related to benefit obligations at September 30:
Discount rate
6.25
5.75
6.05
5.50
Rate of compensation increase
4.27
4.00
Assumptions related to benefit costs for the year ended December 31:
Discount rate
5.75
5.50
5.75
5.50
5.25
5.75
Expected return on plan assets(1)
8.00
8.00
8.00
8.00
8.00
7.50
Rate of compensation increase
4.00
4.00
4.00
(1)
The expected return on plan assets is a pre-tax rate
of return based on our targeted portfolio of investments.
Some of our postretirement benefit plans’ investment
earnings are subject to unrelated business income tax at a
rate of 35%. The expected return on plan assets for our
postretirement benefit plans is calculated using the
after-tax rate of return.
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 9.4 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:
Plan Assets. 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 meet the benefit
obligations to participants, retirees and beneficiaries exists. 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. 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 2007
Actual 2006
Target
Actual 2007
Actual 2006
(Percent)
(Percent)
Equity securities
60
67
66
65
63
63
Debt securities
40
32
33
35
33
33
Other
—
1
1
—
4
4
Total
100
100
100
100
100
100
Other Matters. A trial court has ruled, which was upheld on appeal, that we are required to
indemnify a third party for benefits paid to a closed group of 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 12.
14. Stockholders’ Equity and Minority Interest
Stockholders’ Equity
Common Stock. In 2006, we issued 35.7 million shares of common stock for net proceeds of
approximately $500 million. In 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 2005, we issued $750 million of convertible
perpetual preferred stock. Dividends on the preferred stock are declared quarterly at the rate of
4.99% per annum if approved by our Board of Directors and dividends accumulate if not 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 five years after issuance if our
common stock is trading at a premium of 130 percent to the conversion price.
The net proceeds from the issuance of the preferred stock, along with cash
on hand, was used to settle litigation of approximately $442 million and to
redeem all of the 6 million outstanding shares of 8.25% Series A cumulative preferred stock of our
subsidiary, El Paso Tennessee Pipeline Company for approximately $300 million.
Dividends. The table below shows the amount of dividends paid and declared (in millions,
except per share amounts):
Dividends on our common stock and preferred 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 2007 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.
Accumulated Other Comprehensive Income. The following table provides the components of our
accumulated other comprehensive income (loss) as of December 31:
2007
2006
Cash flow hedges (see Note 7)
$
(35
)
$
80
Pension and other postretirement benefits (see Note 13)
(237
)
(435
)
Investments available for sale
—
12
Total accumulated other comprehensive loss, net of income taxes
$
(272
)
$
(343
)
Minority Interest
In November 2007, we issued common units in our subsidiary El Paso Pipeline Partners, L.P., a master
limited partnership and accordingly recorded minority interest on our
balance sheet of $537 million. Under its partnership agreement,
the MLP is obligated to distribute available cash as defined in the
agreement. Currently, the MLP’s minimum quarterly distribution on its
common units is $0.2875/unit
per quarter.
15. Stock-Based Compensation
Overview. 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. 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, 2007,
approximately 29 million shares remain available for grant under our current plans. In addition, we
have approximately 18 million shares of stock option awards outstanding that were granted under
terminated plans that obligate us to issue additional shares of common stock if they are exercised.
Stock option exercises and restricted stock are funded primarily through the issuance of new common
shares.
We record stock-based compensation expense, excluding amounts capitalized, as operation and
maintenance expense over the requisite service period for each separately vesting portion of the award, net of estimates of
forfeitures. If actual forfeitures differ from our estimates, additional adjustments to
compensation expense will be required in future periods.
Non-Qualified Stock Options. We grant non-qualified stock options to our employees with an
exercise price equal to the market value of our stock on the grant date. Our stock option awards
have contractual terms of 10 years and generally vest in equal amounts over three years from the
grant date. We do not pay dividends on unexercised options. A summary of our stock option
transactions for the year ended December 31, 2007 is presented below:
In
2007 and 2006, we recognized $16 million and $11 million of pre-tax compensation expense on
stock options, capitalized approximately $4 million and $2 million of this expense in each respective year as
part of fixed assets and recorded $6 million and $4 million of income tax benefits. Total
compensation cost related to non-vested option awards not yet recognized at December 31, 2007 was
approximately $16 million, which is expected to be recognized over a weighted average period of 10
months. Options exercised during the year ended December 31, 2007 and 2006 had a total intrinsic
value of approximately $6 million and $5 million, generated $7 million and $6 million of cash
proceeds and did not generate any significant associated income tax benefit. The total intrinsic
value, cash received and income tax benefit generated from option exercises was not material during
the year ended December 31, 2005.
Fair Value Assumptions. The fair value of each stock option granted is estimated on the date
of grant using a Black-Scholes option-pricing model based on several assumptions. These assumptions
are based on management’s best estimate at the time of grant. For the years ended December 31,2007, 2006 and 2005 the weighted average grant date fair value per share of options granted was
$5.53, $4.89, and $3.88.
Listed below is the weighted average of each assumption based on grants in each fiscal year:
2007
2006
2005
Expected Term in Years
6.0
6.0
4.8
Expected Volatility
34
%
38
%
42
%
Expected Dividends
1
%
1.3
%
1.5
%
Risk-Free Interest Rate
4.6
%
4.9
%
3.7
%
We estimate expected volatility based on an analysis of implied volatilities from traded
options on our common stock and our historical stock price volatility over the expected term,
adjusted for certain time periods that we believe are not representative of future stock
performance. Prior to January 1, 2006, we estimated expected volatility based primarily on adjusted
historical stock price volatility. Effective January 1, 2006, we adopted the provisions of SEC
Staff Accounting Bulletin (SAB) No. 107 and estimate the expected term of our option awards based
on the vesting period and average remaining contractual term. We expect to continue to use this
approach for all stock option contracts consistent with SEC SAB No. 110, Share Based Payment, which allows us to continue the use
of the “simplified method” in estimating our expected term consistent with the manner in which we
determined expected term under SAB 107. We use this method due to a lack of sufficient
historical data to provide a reasonable basis for estimating our expected term based on significant
changes in the composition of our employees receiving stock-based compensation awards over the last
several years.
Restricted Stock. We may grant shares of restricted common stock, which carry voting and
dividend rights, to our officers and employees. Sale or transfer of these shares is restricted
until they vest. We currently have outstanding and grant time-based restricted stock. The fair
value of our time-based restricted shares is determined on the grant date and these shares
generally vest in equal amounts over three years from the date of grant. A summary of the changes
in our non-vested restricted shares for each fiscal years are presented below:
The weighted average grant date fair value per share for restricted stock granted during 2007,
2006 and 2005 was $14.73, $13.09 and $10.78. The total fair value of shares vested during 2007,
2006 and 2005 was $31 million, $24 million, and $14 million.
During 2007, 2006 and 2005, we recognized approximately $25 million, $17 million and $18
million of pre-tax compensation expense on our restricted share
awards, capitalized approximately $7
million in 2007 and $2 million in 2006 and 2005 as part of fixed assets and recorded $9 million,
$6 million and $6 million of income tax benefits related to restricted stock arrangements. The
total unrecognized compensation cost related to these arrangements at December 31, 2007 was
approximately $24 million, which is expected to be recognized over a weighted average period of 10
months.
Employee Stock Purchase Plan. Our employee stock purchase plan allows participating employees
the right to purchase our common stock at 95 percent of the market price on the last trading day of
each month. This plan is non-compensatory under the provisions of SFAS No. 123(R). Shares issued
under this plan were insignificant during 2007, 2006 and 2005.
16. Business Segment Information
As of December 31, 2007, our business consists of two core segments, Pipelines and
Exploration and Production. We also have Marketing and Power segments. Prior to 2006, we also had
a Field Services segment. 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 activities include our general and
administrative functions, as well as other miscellaneous businesses and various other contracts and
assets, all of which are immaterial. A further discussion of each segment follows.
Pipelines. Provides natural gas transmission, storage, and related services, primarily in
the United States. As of December 31, 2007, we conducted our activities primarily through
seven wholly or majority owned interstate pipeline systems and equity interests in three interstate transmission systems, along with two underground natural gas
storage entities and an LNG terminalling facility.
Exploration and Production. Engaged in the exploration for and the acquisition, development
and production of natural gas, oil and NGL, primarily in the United States, Brazil and Egypt.
Marketing. Markets and manages the price risks associated with our natural gas and oil
production as well as our remaining legacy trading portfolio.
Power. Manages the risks associated with our remaining international power assets, primarily
in Brazil, Asia and Central America. We continue to pursue the sale of these assets.
Prior
to January 1, 2006, we had a Field Services segment which conducted midstream activities.
We have disposed of substantially all of the assets in this segment.
We had no customers whose revenues exceeded 10 percent of our total revenues in 2007, 2006 and
2005.
Our management uses earnings before interest expense and income taxes (EBIT) to assess the
operating results and effectiveness of our business segments which
consist of both consolidated businesses and investments in unconsolidated affiliates. We believe EBIT is useful to our
investors because it allows them to more effectively evaluate the operating performance using the
same performance measure analyzed internally by our management. We define EBIT as net income or
loss adjusted for (i) items that do not impact our income or loss from continuing operations, such
as discontinued operations and the impact of accounting changes, (ii) income taxes and (iii)
interest and debt expense. We exclude interest and debt expense 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 from continuing operations for the
periods ended December 31:
Capital expenditures and investments in and
advances to unconsolidated affiliates,
net(4)
1,059
2,613
—
(34
)
7
3,645
Total investments in unconsolidated affiliates
759
704
—
151
—
1,614
(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 $19 million and an operation and maintenance expense elimination of $1 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 segment, which is responsible for marketing our production to third parties.
(3)
Of total foreign assets, approximately $0.6 billion relates to property, plant and equipment, and approximately $0.6 billion relates to investments in and advances to unconsolidated affiliates.
(4)
Amounts are net of third party reimbursements of our capital expenditures and returns of invested capital.
(5)
Includes debt extinguishment costs of $86 million related to refinancing EPEP’s $1.2 billion notes.
Capital expenditures, and investments in and
advances to unconsolidated affiliates,
net(5)
1,023
1,113
—
(44
)
14
2,106
Total investments in unconsolidated
affiliates
757
729
—
221
—
1,707
(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 $37 million and an operation and maintenance expense elimination of $13 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 segment, which is responsible for marketing our production to third parties.
(3)
Excludes assets of discontinued operations of $4,133 million (see Note 2).
(4)
Approximately $0.4 billion of total foreign assets relates to property, plant and equipment and approximately $0.7 billion relates to investments in and advances to unconsolidated affiliates.
(5)
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)
780
1,851
—
5
8
14
2,658
Total investments in unconsolidated
affiliates
734
761
—
670
—
—
2,165
(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 segment, which is responsible for marketing our production to third parties.
(3)
Relates to intercompany activities between our continuing operations and our discontinued operations.
(4)
Excludes assets of discontinued operations of $4,649 million.
(5)
Of total foreign assets, approximately $0.3 billion 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.
17. 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 and impairment charges recorded by us. As of December 31, 2007 and
2006, our investment balance exceeded the net equity in the underlying net assets of these
investments by $377 million and $409 million due to these items. The majority of our purchase price
adjustments is related to our investment in Four Star which we acquired in 2005. We generally
amortize and assess the recoverability of this amount based on the development and production of
the underlying estimated proved natural gas and oil reserves of Four Star. Our net ownership
interest, investments in and earnings (losses) from our unconsolidated affiliates are as follows as
of and for the years ended December 31:
Net Ownership
Earnings (Losses) from
Interest
Investment
Unconsolidated Affiliates
2007
2006
2007
2006
2007
2006
2005
(Percent)
(In millions)
(In millions)
Domestic:
Four Star(1)
49
43
$
698
$
723
$
12
$
10
$
19
Citrus
50
50
576
597
81
62
66
Enterprise Products Partners(2)
—
—
—
—
—
—
183
Midland Cogeneration Venture(2)
—
—
—
—
—
13
(162
)
Javelina(2)
—
—
—
—
—
—
121
Other Domestic Investments
various
various
38
36
3
3
17
Total domestic
1,312
1,356
96
88
244
Foreign:
Bolivia to Brazil Pipeline
8
8
105
105
11
11
20
Gasoductos de Chihuahua
50
50
146
126
21
25
19
Habibullah Power(3)
50
50
17
17
—
1
(13
)
Manaus/Rio Negro(4)
100
100
56
96
(6
)
17
19
Porto Velho(3)
50
50
(60
)
(34
)
(23
)
2
(16
)
Korea Independent Energy Corporation(2)
—
—
—
—
—
—
127
EGE Itabo(2)
—
—
—
—
—
1
(58
)
Other Foreign Investments
various
various
38
41
2
—
(61
)
Total foreign
302
351
5
57
37
Total investments in unconsolidated affiliates
$
1,614
$
1,707
Total earnings from unconsolidated affiliates
$
101
$
145
$
281
(1)
Amortization of our purchase cost in excess of the underlying net assets of Four Star was $53 million, $54 million and $20 million during 2007, 2006 and 2005.
During the third quarter of 2007, we paid $27 million to
increase our ownership interest in Four Star from 43 percent to 49 percent.
(2)
We sold our interests in these investments.
(3)
As of December 31, 2007 and 2006, we had outstanding advances and receivables not included in these balances of $350 million and $413 million related to our foreign
investments of which $12 million and $25 million related to our investment in Habibullah Power, $335 million and $350 million relate to our investment in Porto Velho, and
the remainder in our other foreign investments. We recognized interest income on these outstanding advances and receivables of approximately $1 million, $46 million, and
$47 million in 2007, 2006 and 2005. For a further discussion of these receivables, see Matters that Could Impact Our Investments below.
(4)
We transferred ownership of these plants to the power purchaser in January 2008. For a further discussion, see Matters that Could Impact Our Investments below.
Impairment charges and gains and losses on sales of equity investments are included in
earnings from unconsolidated affiliates. During 2007, 2006 and 2005, our impairments and gains and
losses were primarily a result of our decision to sell a number of these investments or were based
on declines in their fair value of the investments due to changes in economics of the investments’
underlying contracts, or the markets they serve. These gains (losses) consisted of the
following:
Investment or Group
2007
2006
2005
(In millions)
Midland Cogeneration Venture(1)
$
—
$
13
$
(162
)
Asia power investments
(1
)
(8
)
(64
)
Porto Velho(2)
(32
)
—
—
Manaus and Rio Negro
(15
)
—
—
Central and other South American power investments
(2
)
1
(89
)
Enterprise
—
—
183
Javelina
—
—
111
KIECO
—
—
108
Other
—
—
4
$
(50
)
$
6
$
91
(1)
Amounts represent our proportionate share of losses from our investment in MCV in 2005 primarily based on MCV’s impairment of the plant assets, and a gain on the sale in 2006.
(2)
Amount does not include a $25 million impairment of our note receivable in 2007 as further described in Matters that Could Impact Our Investments, 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 (loss) of $(1) million, $20 million and $15 million in 2007, 2006 and 2005, related to our proportionate share of affiliates in which we hold greater than a 50 percent interest.
(2)
Includes total assets of $190 million and $417 million as of December 31, 2007 and 2006 related to our proportionate share of affiliates in which we hold greater than a 50 percent interest.
We received distributions and dividends of $223 million and $177 million in 2007 and 2006,
which includes $34 million and $38 million of returns of capital from our investments.
The following table shows revenues and charges resulting from transactions with our
unconsolidated affiliates:
2007
2006
2005
(In millions)
Operating revenue(1)
$
7
$
64
$
114
Cost of sales
5
3
7
Other income
4
6
9
Interest income(2)
1
46
47
(1)
Decrease primarily due to the sale of investments in our Power segment.
(2)
Decrease primarily due to the impairment of our Porto Velho note receivable in 2007 as further described below.
Accounts Receivable Sales Program. Several of our pipeline subsidiaries have agreements to
sell certain accounts receivable to qualifying special purpose entities (QSPEs) under SFAS No. 140,
Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities. As
of December 31, 2007 and 2006, we sold approximately
$189 million and $202 million, of receivables, received cash of
approximately $79 million and $108 million, received subordinated beneficial interests of approximately $107
million and $91 million, and recognized a loss of approximately $3 million in both years. In conjunction with the sale, the QSPEs
also issued senior beneficial interests on the receivables sold to a third party financial
institution, which totaled $80 million and $111 million as of December 31, 2007 and 2006. We reflect the subordinated beneficial
interest in receivables sold as accounts receivable from affiliates in our balance sheet. We
reflect accounts receivable sold under this program and changes in the subordinated beneficial
interests as operating cash flows in our statement of cash flows. Under the agreements, we earn a
fee for servicing the accounts receivable and performing all administrative duties for the QSPEs
which is reflected as a reduction of operation and maintenance expense in our income statement. The
fair value of these servicing and administrative agreements as well as the fees earned were not
material to our financial statements for the years ended December 31, 2007 and 2006.
Matters that Could Impact Our Investments
International Power. During 2006, we completed the sales of our in
domestic power facilities and, accordingly, our remaining power investments are in international
power facilities. As of December 31, 2007, we had equity investments in six power generation and
transmission facilities in Asia, Central America, and Brazil that are considered variable interests
under FIN No. 46(R). We operate 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.
Additionally, the long-term debt issued by these entities is recourse only to the project. We have
investments in and advances to these entities as well as guarantees and other agreements which are
as follows at December 31, 2007:
Porto Velho. We have an equity investment in and a note receivable from the Porto Velho
project in Brazil. The power generated by the Porto Velho project is committed to a state-owned
utility under power purchase agreements, the largest of which extends through 2023. In July 2007,
we received an offer from our partner to purchase our investment in the project for less than its
overall carrying value. Our discussions with our partner about this offer have been temporarily suspended pending the
resolution of certain claims with the state-owned utility, which are further described below, and a decision to
sell our investment has not been made at this time. The power markets in Brazil continue to evolve
and mature, and during the third quarter of 2007, the Brazilian national power grid operator
communicated to Porto Velho’s management that its power plant (and the region that the plant
serves) will be interconnected to an integrated power grid in Brazil as soon as late 2008. When
the interconnection is completed, the state-owned utility will have access to sources of power at
rates that may be less than the price under Porto Velho’s existing power purchase agreements.
Furthermore, there are plans to construct new hydroelectric plants in northern Brazil that could
reportedly be completed as early as 2012 which, once connected to the grid, could further reduce
regional power prices and the amount of power Porto Velho will be able to sell under its power
purchase agreements. Based on our assessment of the impact these ongoing developments may have on
northern Brazil’s electricity markets and Porto Velho’s power purchase agreements, we recorded
incremental losses on our investment during 2007 of approximately $32 million. We also recorded a
$25 million impairment of our note receivable from the project, and have discontinued accruing
interest on the note. After these adjustments, our total investment in the Porto Velho project was
approximately $275 million as of December 31, 2007, comprised primarily of the note receivable from
the project. In February 2008, we received a dividend from the project of approximately $29
million, and we and our partner extended the date upon which we will be required to convert
approximately $80 million of the amounts due under this note into an equity investment in the
project until July 2008. In addition, we may be required to convert up to an additional $80
million of the note in July 2008, depending on the level of equity that our partner contributes to
the project, which would increase our percentage ownership in Porto Velho.
In December 2006, the Brazilian tax authorities assessed a $30 million fine against the Porto
Velho power project for allegedly not filing the proper tax forms related to the delivery of fuel
to the power facility under its power purchase agreements. We believe the claim by the tax
authorities is without merit. In addition, beginning in the fourth quarter of 2007, the
state-owned utility made claims against the Porto Velho project for the period of 2003 through
2007 totaling approximately $60 million related to alleged excess fuel consumption. We believe
that we have valid defenses to these fuel claims. The state-owned utility has made additional net claims of $30 million for retroactive currency indexation adjustments, which are
partially offset by retroactive revenue surcharges for periods when
the plant uses oil for fuel.
We are currently evaluating this claim. Further adverse developments in the Brazilian power markets or
at the project could impact our ability to recover our remaining investment in the future.
Manaus /Rio Negro. On January 15, 2008, we transferred our ownership in the Manaus and Rio
Negro facilities to the plants’ power purchaser as required by their power purchase agreements. On
the transfer date, we have approximately $69 million of accounts receivable owed to us under the projects terminated power purchase
agreements, which are guaranteed by the purchaser’s parent. The purchaser has withheld payment of
these receivables in light of a dispute over approximately $54 million of maintenance and other
items that the purchaser claims should have been performed at the plants prior to the transfer. We
intend to recover our receivable through our legal rights to enforce the parental guarantee,
independent of the resolution of the disputed claim. The ultimate resolution of each of these
matters is unknown at this time. During 2007, we recorded an impairment of our investments in
these projects of approximately $15 million as a result of our assessment of these matters and
other unrelated mechanical failures at the plants. Adverse developments related to either our
ability to collect amounts due to us or related to the dispute could require us to record
additional losses in the future.
Asian and Central American power investments. As of December 31, 2007, our total investment
(including advances to the projects) and guarantees related to these projects was approximately $78
million. We are in the process of selling these assets. Any changes in political and economic
conditions could negatively impact the amount of net proceeds we expect to receive upon their sale,
which may result in additional impairments.
Investment in Bolivia. We own an 8 percent interest in the Bolivia to Brazil pipeline. As of
December 31, 2007, our total investment and guarantees related to this pipeline project was
approximately $117 million, of which the Bolivian portion was $3 million. In 2006, the Bolivian
government announced a decree significantly increasing its interest in and control over Bolivia’s
oil and gas assets. We continue to monitor and evaluate, together with our partners, the potential
commercial impact that these political events in Bolivia could have on our investment. As new
information becomes available or future material developments arise, we may be required to record
an impairment of our investment.
Investment in Argentina. We own an approximate 22 percent interest in the Argentina to Chile
pipeline. As of December 31, 2007, our total investment in this pipeline project was approximately
$21 million. We are currently evaluating opportunities to sell our interest in this pipeline. In
addition, in July 2006, the Ministry of Economy and Production in Argentina issued a decree that
significantly increases the export taxes on natural gas. We continue to evaluate, together with our
partners, the potential commercial impact that this and other decrees could have on the Argentina
to Chile pipeline and the potential value we expect to receive upon the sale of our investment. As
new information becomes available or future material developments arise, we may be required to
record an impairment of our investment.
Supplemental Selected Quarterly Financial Information (Unaudited)
Financial information by quarter, adjusted to reflect our discontinued operations, is
summarized below.
Quarters Ended
March 31
June 30
September 30
December 31
Total
(In millions, except per common share amounts)
2007
Operating revenues
$
1,022
$
1,198
$
1,166
$
1,262
$
4,648
Operating income
335
451
417
442
1,645
Earnings (losses) from unconsolidated affiliates
37
44
(6
)
26
101
Income (loss) from continuing operations
(48
)
169
155
160
436
Discontinued operations, net of income taxes
677
(3
)
—
—
674
Net income
629
166
155
160
1,110
Net income available to common stockholders
620
156
146
151
1,073
Basic earnings per common share
Income (loss) from continuing operations
(0.08
)
0.23
0.21
0.22
0.57
Net income
0.89
0.23
0.21
0.22
1.54
Diluted earnings per common share
Income (loss) from continuing operations
(0.08
)
0.22
0.20
0.21
0.57
Net income
0.89
0.22
0.20
0.21
1.53
2006
Operating revenues
$
1,337
$
1,089
$
942
$
913
$
4,281
Operating income
683
363
218
163
1,427
Earnings from unconsolidated affiliates
29
37
55
24
145
Income (loss) from continuing operations
301
134
111
(15
)
531
Discontinued operations, net of income taxes
55
16
24
(151
)
(56
)
Net income (loss)
356
150
135
(166
)
475
Net income (loss) available to common stockholders
346
141
126
(175
)
438
Basic earnings per common share
Income (loss) from continuing operations
0.44
0.19
0.15
(0.03
)
0.73
Net income (loss)
0.53
0.21
0.18
(0.25
)
0.65
Diluted earnings per common share
Income (loss) from continuing operations
0.42
0.19
0.15
(0.03
)
0.72
Net income (loss)
0.49
0.21
0.18
(0.25
)
0.64
Below are unusual or infrequently occurring items, if any, in each of the respective quarters
of 2007 and 2006:
September 30, 2007. Items include (i) $77 million gain in other income related to the
reversal of a liability related to a legacy crude oil marketing and trading
business matter and (ii) losses of $64 million ($72 million for the year ended December 31, 2007) related
to our Porto Velho and Manaus and Rio Negro projects.
June 30, 2007. Items include (i) $86 million loss on debt extinguishment relating to
repurchasing notes of El Paso Exploration and Production Company and (ii) a $35 million loss ($100
million for the year ended December 31, 2007) on our PJM power contracts, primarily resulting from increases in installed capacity
prices.
March 31, 2007. Items include (i) gain of $651 million, net of taxes of $356 million on the
sale of ANR and related assets recorded in discontinued operations and (ii) a loss on
extinguishment of debt of $201 million in conjunction with the repurchase of $3.5 billion of debt
obligations.
December 31, 2006. Items include (i) $188 million charge associated with the release of
capacity under our Alliance contract and (ii) approximately $188 million in deferred taxes related
to ANR discontinued operations (Note 2).
September 30, 2006. Items include (i) Mark-to-market losses of $133 million on our MCV
supply agreement recorded in conjunction with the sale of our interest in the related power
facility and (ii) a $105 million income tax benefit associated with the reduction of tax
contingencies and reinstatement of certain tax credits as a result of IRS audit settlements and
net tax amounts recognized on certain foreign investments (Note 4).
June 30, 2006. Items include income tax benefit of $34 million associated with IRS audit
settlements (Note 4).
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, in the United States, Brazil and Egypt.
Capitalized Costs. 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):
Brazil
United
and
States
Egypt(1)
Worldwide
2007
Natural gas and oil properties:
Costs subject to amortization
$
17,631
$
546
$
18,177
Costs not subject to amortization
474
265
739
18,105
811
18,916
Less accumulated depreciation, depletion and amortization
11,847
255
12,102
Net capitalized costs
$
6,258
$
556
$
6,814
2006
Natural gas and oil properties:
Costs subject to amortization
$
15,582
$
460
$
16,042
Costs not subject to amortization
333
77
410
15,915
537
16,452
Less accumulated depreciation, depletion and amortization
11,322
202
11,524
Net capitalized costs
$
4,593
$
335
$
4,928
(1)
Capitalized costs for Egypt were $14 million and $4 million as of December 31, 2007 and 2006.
Total Costs Incurred. Costs incurred in natural gas and oil producing activities, whether
capitalized or expensed, were as follows for the year ended December 31 (in millions):
Costs incurred for Egypt were $10 million and $4 million for the years ended December 31, 2007 and 2006.
(2)
Amount includes deferred income tax adjustments of $179 million related to the acquisition of full-cost pool
properties and $217 million related to the acquisition of our unconsolidated investment in Four Star.
Pursuant to the full cost method of accounting, we capitalize certain general and
administrative expenses related to property acquisition, exploration and development activities and
interest costs incurred and attributable to unproved oil and gas properties and major development
projects of oil and gas properties. The table above includes capitalized internal general and
administrative costs incurred in connection with the acquisition, development and exploration of
natural gas and oil reserves of $69 million, $50 million and $47 million for the years ended
December 31, 2007, 2006 and 2005. We also capitalized interest of $35 million, $30 million and $30
million for the years ended December 31, 2007, 2006 and 2005.
In our January 1, 2008 reserve report, the amounts estimated to be spent in 2008, 2009 and
2010 to develop our consolidated worldwide proved undeveloped reserves are $743 million, $515
million and $170 million.
Unevaluated Capitalized Costs. We exclude capitalized costs of natural gas and oil properties
from amortization that are in various stages of evaluation. We expect a majority of these costs to
be included in the amortization calculation in 2008 and 2009.
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, 2007, pending determination of
proved reserves (in millions):
Includes capitalized interest of $33 million, $24 million and $9 million for the years ended December 31, 2007, 2006 and 2005.
Natural Gas and Oil Reserves. Net quantities of proved developed and undeveloped reserves of
natural gas and NGL, oil and condensate, and changes in these reserves at December 31, 2007
presented in the tables below are based on our internal reserve report. 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. Our consolidated reserves are 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, an independent reservoir engineering firm that reports to the Audit Committee of
our Board of Directors, conducted an audit of the estimates of 84 percent of our consolidated
natural gas and oil reserves. The scope of the audit performed by Ryder Scott included the
preparation of an independent estimate of proved natural gas and oil reserves estimates for fields
comprising greater than 80 percent of our total worldwide present value of future cash flows
(pretax). The specific fields included in Ryder Scott’s audit represented the largest fields based
on value. Ryder Scott also conducted an audit of the estimates of 75 percent of the proved
reserves of Four Star, our unconsolidated affiliate. Our estimates of Four Star’s proved natural
gas and oil reserves are prepared by our internal reservoir engineers and do not reflect those
prepared by the engineers of Four Star. Based on the amount of proved reserves determined by Ryder
Scott, we believe our reported reserve amounts are reasonable. Ryder Scott’s reports are included
as exhibits to this Annual Report on Form 10-K.
In 2007, of the 341 Bcfe of extensions and discoveries, 80 Bcfe related to the Raton area in
northern New Mexico, 43 Bcfe related to the McCook area in south Texas, 34 Bcfe related to the
Zapata area in south Texas, 26 Bcfe related to the success in the Niobrara and Johnson counties in
Wyoming, 22 Bcfe related to the Mustang Island 739/740 block in the Gulf of Mexico and 20 Bcfe
related to the Victoria area in south Texas.
In 2006, of the 299 Bcfe of extensions and discoveries, 45 Bcfe related to the coal bed
methane projects in central Alabama, 37 Bcfe related to the House Creek Parkman and County Line
areas in northeast Wyoming, 35 Bcfe related to the McCook area in South Texas, 27 Bcfe related to
the Raton area in northern New Mexico, 18 Bcfe related to the Victoria area in south Texas, 18 Bcfe
related to the Bear Creek area in northern Louisiana, and 16 Bcfe related to the Minden area in
east Texas.
In 2005, of the 242 Bcfe of extensions and discoveries, 46 Bcfe related to the Holly and
Minden fields in northwest Louisiana and east Texas, 39 Bcfe related to the West Cameron 62/75
offshore block in the Gulf of Mexico, 25 Bcfe related to the Raton area in northern New Mexico, 22
Bcfe related to the coal bed methane projects in central Alabama, 22 Bcfe related to the House
Creek Parkman area in northeast Wyoming, and 14 Bcfe related to the Altamont/Bluebell area in
northeast Utah.
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, 2007.
Standardized Measure of Discounted Future Net Cash Flows. 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
2007
Future cash inflows(1)
$
19,329
$
3,226
$
22,555
Future production costs
(4,822
)
(560
)
(5,382
)
Future development costs
(1,805
)
(444
)
(2,249
)
Future income tax expenses
(3,144
)
(625
)
(3,769
)
Future net cash flows
9,558
1,597
11,155
10% annual discount for estimated timing of cash flows
(3,704
)
(617
)
(4,321
)
Standardized measure of discounted future net cash flows
$
5,854
$
980
$
6,834
Standardized measure of discounted future net cash flows, including effects of hedging activities
$
5,902
$
980
$
6,882
2006
Future cash inflows(1)
$
12,349
$
1,977
$
14,326
Future production costs
(3,623
)
(431
)
(4,054
)
Future development costs
(1,280
)
(506
)
(1,786
)
Future income tax expenses
(1,089
)
(239
)
(1,328
)
Future net cash flows
6,357
801
7,158
10% annual discount for estimated timing of cash flows
(2,302
)
(377
)
(2,679
)
Standardized measure of discounted future net cash flows
$
4,055
$
424
$
4,479
Standardized measure of discounted future net cash flows, including effects of hedging activities
$
4,225
$
424
$
4,649
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
2007
$
444
$
—
$
444
2006
$
323
$
—
$
323
2005
$
617
$
—
$
617
(1)
United States excludes $61 million, $219 million and
$(502) million of future net cash inflows (outflows)
attributable to hedging activities in the years 2007, 2006
and 2005. Brazil excludes $4 million of future net cash
outflows attributable to hedging activities in 2005.
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 $6.80, $5.64, and
$10.08 per MMBtu for natural gas and $95.98, $61.05 and $61.04 per barrel of oil at December 31,2007, 2006 and 2005. In the United States, after adjustments for transportation and other charges,
net prices were $6.40 per Mcf of gas, $87.88 per barrel of oil and $58.63 per barrel of NGL at
December 31, 2007. 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.
Changes in Standardized Measure of Discounted Future Net Cash Flows. 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)
2007
2006
2005
(In millions)
Sales and transfers of natural gas and oil produced net of production costs
$
(1,657
)
$
(1,516
)
$
(1,477
)
Net changes in prices and production costs
2,723
(2,891
)
2,884
Extensions, discoveries and improved recovery, less related costs
910
549
793
Changes in estimated future development costs
(4
)
(55
)
2
Previously estimated development costs incurred during the period
200
192
247
Revision of previous quantity estimates
117
(38
)
47
Accretion of discount
501
827
476
Net change in income taxes
(1,333
)
1,123
(1,093
)
Purchases of reserves in place
810
4
956
Sale of reserves in place
(7
)
(42
)
(83
)
Change in production rates, timing and other
95
(289
)
(333
)
Net change
$
2,355
$
(2,136
)
$
2,419
(1)
This disclosure reflects changes in the standardized measure calculation excluding the effects of hedging activities.
Amounts reflect the reclassification of discontinued operations.
(2)
Included is the settlement of our shareholder litigation lawsuits.
(3)
In 2006 and 2007, we recorded reserves for rate refunds under EPNG’s rate case which was settled in 2007 and refunds paid to customers.
(4)
In 2006, relates primarily to the sale of our accounts receivable under an accounts receivable sales program. In 2005, relates primarily to accounts written off.
(5)
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.
(6)
Relates primarily to payments for various litigation reserves (including $442 million related to the Western Energy Settlement), environmental remediation reserves or
revenue crediting and rate settlement reserves.
ITEM 9. 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, 2007, 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
U.S. Securities and Exchange Commission (SEC) reports we file or submit under the Exchange Act is
accurate, complete and timely. Our management, including our CEO and CFO, does not expect that our
disclosure controls and procedures or our internal controls will prevent and/or detect all error
and all fraud. A control system, no matter how well conceived and operated, can provide only
reasonable, not absolute, assurance that the objectives of the control system are met. Further, the
design of a control system must reflect the fact that there are resource constraints, and the
benefits of controls must be considered relative to their costs. Because of the inherent
limitations in all control systems, no evaluation of controls can provide absolute assurance that
all control issues and instances of fraud, if any, within our company have been detected. Based on
the results of this evaluation, our CEO and CFO concluded that our disclosure controls and
procedures are effective at a reasonable level of assurance at December 31, 2007. 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 of 2007.
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
The information included under the captions “Corporate Governance”, “Proposal No. 1 —
Election of Directors”, “Section 16(a), Beneficial Ownership Reporting Compliance” and “Information
about the Board of Directors and Committees” in our Proxy Statement for the 2008 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 required by the New York Stock Exchange corporate governance listing standards, in June
2007, Douglas L. Foshee, our president and chief executive officer, submitted an unqualified
certification to the New York Stock Exchange that as of the date of the certification, he was not
aware of any violation by El Paso of the exchange’s corporate governance standards. The
certifications of our chief executive officer and chief financial officer pursuant to Section 302
of the Sarbanes-Oxley Act of 2002 are attached as Exhibits 31.A and 31.B to this report.
ITEM 11. EXECUTIVE COMPENSATION
Information appearing under the captions “Information about the Board of Directors and
Committees — Compensation Committee Interlocks and Insider Participation”, “Executive
Compensation”, “Director Compensation” and “Compensation Committee Report” in our Proxy Statement
for the 2008 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 captions “Security Ownership of Certain Beneficial Owners and
Management” and “Equity Compensation Plan Information Table” in our Proxy Statement for the 2008
Annual Meeting of Stockholders is incorporated herein by reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
Information appearing under the captions “Corporate Governance — Independence of Board
Members” and “Corporate Governance — Transactions with Related Persons” in our Proxy Statement for
the 2008 Annual Meeting of Stockholders is incorporated herein by reference.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
Information appearing under the caption “Proposal No. 2 — Ratification of Appointment of
Ernst & Young, LLP as our Independent Registered Public Accountant — Principal Accountant Fees and
Services” and “Information about the Board of Directors — Policy for Approval of Audit and
Non-Audit Fees,” in our Proxy Statement for the 2008 Annual Meeting of Stockholders is incorporated
herein by reference.
The Exhibit Index, which index follows the signature page to this report and is hereby
incorporated herein by reference, sets forth a list of those exhibits filed herewith, and includes
and identifies management contracts or compensatory plans or arrangements required to be filed as
exhibits to this Form 10-K by Item 601 (b)(10)(iii) of Regulation S-K.
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 28th day of February, 2008.
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.
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).
4.C
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).
Eleventh Supplemental Indenture dated as of August 31, 2006, between El Paso Corporation and HSBC Bank USA,
National Association, as trustee, to Indenture dated as of May 10, 1999 (Exhibit 4.A to our 2006 Third Quarter
Form 10-Q).
4.F
Twelfth Supplemental Indenture dated as of June 18, 2007 between El Paso Corporation and HSBC Bank USA,
National Association, as trustee, to Indenture dated as of May 10, 1999 (Exhibit 4.A to our 2007 Second Quarter
Form 10-Q).
+10.A
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.A.1
Amendment No. 1 effective as of January 1, 2007 to the 1995 Compensation Plan for Non-Employee Directors
Amended and Restated effective as of December 4, 2003.
+10.B
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).
+10.B.1
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).
*+10.B.2
Amendment No. 2 effective as of February 7, 2001 to the Stock Option Plan for Non-Employee Directors.
+10.B.3
Amendment No. 3 effective as of October 26, 2006 to the Stock Option Plan for Non-Employee Directors (Exhibit
10.N to our 2006 Third Quarter Form 10-Q).
+10.C
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);
*+10.C.1
Amendment No. 1 effective as of February 7, 2001 to the 2001 Stock Option Plan for Non-Employee Directors.
*+10.C.2
Amendment No. 2 effective as of December 4, 2003 to the 2001 Stock Option Plan for Non-Employee Directors.
+10.C.3
Amendment No. 3 effective as of October 26, 2006 to the 2001 Stock Option Plan for Non-Employee Directors
(Exhibit 10.O to our 2006 Third Quarter Form 10-Q).
+10.D
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); Amendment No. 3 effective as of October 26, 2006 to
the 1995 Omnibus Compensation Plan (Exhibit 10.L to our 2006 Third Quarter Form 10-Q).
*+10.E
1999 Omnibus Incentive Compensation Plan dated January 20, 1999.
*+10.E.1
Amendment No. 1 effective as of February 7, 2001 to the 1999 Omnibus Incentive Compensation Plan.
+10.E.2
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).
+10.E.3
Amendment No. 3 effective as of October 26, 2006 to the 1999 Omnibus Incentive Compensation Plan (Exhibit 10.K
to our 2006 Third Quarter Form 10-Q).
*+10.F
2001 Omnibus Incentive Compensation Plan effective as of January 29, 2001.
*+10.F.1
Amendment No. 1 effective as of February 7, 2001 to the 2001 Omnibus Incentive Compensation Plan.
*+10.F.2
Amendment No. 2 effective as of April 1, 2001 to the 2001 Omnibus Incentive Compensation Plan.
*+10.F.3
Amendment No. 3 effective as of July 17, 2002 to the 2001 Omnibus Incentive Compensation Plan.
+10.F.4
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).
+10.F.5
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.F.6
Amendment No. 6 effective as of October 26, 2006 to the 2001 Omnibus Incentive Compensation Plan (Exhibit 10.M
to our 2006 Third Quarter Form 10-Q).
*+10.G
Supplemental Benefits Plan Amended and Restated effective December 7, 2001.
*+10.G.1
Amendment No. 1 effective as of November 7, 2002 to the Supplemental Benefits Plan.
+10.G.2
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.G.3
Amendment No. 3 effective December 17, 2004 to the Supplemental Benefits Plan (Exhibit 10.UU to our 2004 Third
Quarter Form 10-Q).
Director Charitable Award Plan Amended and Restated effective as of August 1, 1998 (Exhibit 10.P to our 2004
Form 10-K).
*+10.K.1
Amendment No. 1 effective as of February 7, 2001 to the Director Charitable Award Plan.
+10.K.2
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.L
Strategic Stock Plan Amended and Restated effective as of December 3, 1999.
*+10.L.1
Amendment No. 1 effective as of February 7, 2001 to the Strategic Stock Plan.
*+10.L.2
Amendment No. 2 effective as of November 7, 2002 to the Strategic Stock Plan.
*+10.L.3
Amendment No. 3 effective as of December 6, 2002 to the Strategic Stock Plan.
*+10.L.4
Amendment No. 4 effective as of January 29, 2003 to the Strategic Stock Plan.
+10.L.5
Amendment No. 5 effective as of October 26, 2006 to the Strategic Stock Plan (Exhibit 10.J to our 2006 Third
Quarter Form 10-Q).
+10.M
Domestic Relocation Policy effective November 1, 1996 (Exhibit 10.R to our 2004 Form 10-K).
+10.N
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).
*+10.N.1
Termination of the Executive Award Plan of Sonat Inc.
+10.N.2
Amendment to the Executive Award Plan of Sonat Inc. effective as of October 26, 2006 (Exhibit 10.H to our 2006
Third Quarter Form 10-Q).
*+10.O
Omnibus Plan for Management Employees Amended and Restated effective as of December 3, 1999.
*+10.O.1
Amendment No. 1 effective as of December 1, 2000 to the Omnibus Plan for Management Employees.
*+10.O.2
Amendment No. 2 effective as of February 7, 2001 to the Omnibus Plan for Management Employees.
*+10.O.3
Amendment No. 3 effective as of December 7, 2001 to the Omnibus Plan for Management.
*+10.O.4
Amendment No. 4 effective as of December 6, 2002 to the Omnibus Plan for Management Employees.
+10.O.5
Amendment No. 5 effective as of October 26, 2006 to the Corporation Omnibus Plan for Management Employees
(Exhibit 10.I to our 2006 Third Quarter Form 10-Q).
+10.P
Severance Pay Plan Amended and Restated effective as of October 1, 2002 (Exhibit 10.Z to our 2003 First Quarter
Form 10-Q); Supplement No. 1 to the Severance Pay Plan effective as of January 1, 2003 (Exhibit 10.Z to our
2003 First Quarter Form 10-Q); 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); Supplement No. 2 dated April 1, 2005
to the Severance Pay Plan Amended and Restated effective as of October 1, 2002 (Exhibit 10.S.1 to our 2005 Form
10-K).
*+10.P.1
Amendment No. 1 effective January 1, 2007 to the Severance Pay Plan Amended and Restated effective as of
October 1, 2002.
+10.Q
Letter Agreement dated September 20, 2006 between El Paso Corporation and Brent J. Smolik (Exhibit 10.A to our
Form 8-K filed October 16, 2006).
+10.R
Letter Agreement dated July 15, 2003 between El Paso and Douglas L. Foshee (Exhibit 10.U to our 2003 Third
Quarter Form 10-Q).
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).
Form of Indemnification Agreement executed by El Paso for the benefit of each officer and effective the date
listed in Schedule A thereto (Exhibit 10.F to our 2006 Third Quarter Form 10-Q).
+10.V
Indemnification Agreement executed by El Paso for the benefit of Douglas L. Foshee, effective December 17, 2004
(Exhibit 10.XX to our 2004 Third Quarter Form 10-Q).
10.W
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.X
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.Y
El Paso Corporation 2005 Compensation Plan for Non-Employee Directors effective as of May 26, 2005 (Exhibit
10.A to our Form 8-K filed May 31, 2005); Amendment No. 1 to the El Paso Corporation 2005 Compensation Plan for
Non-Employee Directors effective as of October 26, 2006 (Exhibit 10.P to our 2006 Third Quarter Form 10-Q).
*+10.Y.1
Amendment No. 2 effective as of January 1, 2007 to the El Paso Corporation 2005 Compensation Plan for
Non-Employee Directors effective as of May 26, 2005.
+10.Z
El Paso Corporation 2005 Omnibus Incentive Compensation Plan effective as of May 26, 2005 (Exhibit 10.B to our
Form 8-K filed May 31, 2005); Amendment No. 1 to the 2005 Omnibus Incentive Compensation Plan effective as of
December 2, 2005 (Exhibit 10.HH.1 to our 2005 Form 10-K); Amendment No. 2 to the El Paso Corporation 2005
Omnibus Incentive Compensation Plan effective as of October 26, 2006 (Exhibit 10.Q to our 2006 Third Quarter
Form 10-Q).
*+10.Z.1
Amendment No. 3 to the El Paso Corporation 2005 Omnibus Incentive Compensation Plan effective as of May 26,2005.
+10.AA
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); Amendment No. 1 to the El Paso Corporation Employee Stock Purchase
Plan effective as of October 26, 2006 (Exhibit 10.G to our 2006 Third Quarter Form 10-Q).
+10.BB
2005 Supplemental Benefits Plan effective as of January 1, 2005 (Exhibit 10.KK to our 2005 Form 10-K).
*+10.BB.1
Amendment No. 1 effective as of January 1, 2007 to the 2005 Supplemental Benefits Plan effective as of January1, 2005.
10.CC
Credit Agreement dated as of July 19, 2006 among El Paso Corporation, as Borrower, Deutsche Bank AG New York
Branch, as Initial Lender, Issuing Bank, Administrative Agent and Collateral Agent (Exhibit 10.A to our Form
8-K filed July 20, 2006).
10.DD
Third Amended and Restated Credit Agreement dated as of November 16, 2007, among El Paso Corporation, 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 21, 2007).
10.EE
Third Amended and Restated Security Agreement dated as of November 16, 2007, made by among El Paso Corporation,
El Paso Natural Gas Company, Tennessee Gas Pipeline Company, the Subsidiary Grantors 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 21, 2007).
10.FF
Third Amended and Restated Subsidiary Guarantee Agreement dated as of November 16, 2007, made by each of the
Subsidiary Guarantors in favor of JPMorgan Chase Bank, N.A., as Collateral Agent (Exhibit 10.C to our Form 8-K
filed November 21, 2007).
10.GG
Purchase and Sale Agreement dated December 22, 2006, among El Paso Corporation, El Paso CNG Company, L.L.C.,
and TransCanada American Investments Ltd. (Exhibit 10.A to our Form 8-K filed December 29, 2006).
10.HH
Purchase and Sale Agreement dated December 22, 2006, among El Paso Great Lakes Company, L.L.C., TC GL
Intermediate Limited Partnership and TransCanada PipeLine USA Ltd. (Exhibit 10. B to our Form 8-K filed
December 29, 2006).
*12
Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends.