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3: EX-12 Ratio of Earnings to Combined Fixed Charges and HTML 30K
Preferred Stock Dividends
4: EX-21 Subsidiaries HTML 333K
5: EX-23.A Consent of Independent Registered Public HTML 16K
Accounting Firm
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Company
Securities registered pursuant
to Section 12(b) of the Act:
Name of Each Exchange
Title of Each Class
on which Registered
Common Stock, par value
$3 per share
New York Stock Exchange
Securities registered pursuant to Section 12(g) of the
Act: None
Indicate by check mark if the registrant is a well-known
seasoned issuer, as defined in Rule 405 of the Securities
Act. Yes þ No o.
Indicate by check mark if the registrant is not required to file
reports pursuant to Section 13 or Section 15(d) of the
Act. Yes o No þ.
Indicate by check mark whether the registrant (1) has filed
all reports required to be filed by Section 13 or 15(d) of
the Securities Exchange Act of 1934 during the preceding
12 months (or for such shorter period that the registrant
was required to file such reports), and (2) has been
subject to such filing requirements for the past
90 days. Yes þ No o.
Indicate by check mark if disclosure of delinquent filers
pursuant to Item 405 of
Regulation S-K
is not contained herein, and will not be contained, to the best
of registrant’s knowledge, in definitive proxy or
information statements incorporated by reference in
Part III of this
Form 10-K
or any amendment to this
Form 10-K. þ
Indicate by check mark whether the registrant is a large
accelerated filer, an accelerated filer, or a non-accelerated
filer. See definition of “accelerated filer and large
accelerated filer” in
Rule 12b-2
of the Exchange Act. (Check one):
Large
accelerated filer þ
Accelerated
filer o
Non-accelerated
filer o
Indicate by check mark whether the registrant is a shell company
(as defined in
Rule 12b-2
of the Exchange
Act). Yes o No þ.
State the aggregate market value of the voting and non-voting
common equity held by non-affiliates of the registrant.
Aggregate market value of the voting stock (which consists
solely of shares of common stock) held by non-affiliates of the
registrant as of June 30, 2006 computed by reference to the
closing sale price of the registrant’s common stock on the
New York Stock Exchange on such date: $10,437,735,495.
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 21, 2007: 698,334,034
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 2007 Annual Meeting of Stockholders are incorporated by
reference into Part III of this report. These will be filed
no later than April 30, 2007.
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 regulated
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.
Regulated Natural Gas Transmission. We own or
have interests in North America’s largest interstate
pipeline system with approximately 55,000 miles of pipe
that connect North America’s major producing basins to its
major consuming markets. We also provide approximately
470 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. In February
2007, we sold ANR Pipeline Company (ANR), our Michigan storage
assets and our 50 percent interest in Great Lakes Gas
Transmission, which comprised approximately 12,600 miles of
pipeline and 236 Bcf of storage capacity. The size,
connectivity and diversity of our remaining U.S. pipeline
system provides growth opportunities through infrastructure
development or large scale expansion projects and gives us the
capability to adapt to the dynamics of shifting supply and
demand. We are focused on enhancing the value of our
transmission business through successful recontracting,
continual efficiency improvements through reliable and safe
operations, cost management, developing growth projects and
prudent capital spending in the United States and Mexico.
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, 2006, we held an estimated 2.4 Tcfe of
proved natural gas and oil reserves, exclusive of our equity
share in the proved reserves of an unconsolidated affiliate of
222 Bcfe. In this business, we are focused on growing our
reserve base through disciplined capital allocation and
portfolio management, cost control and marketing and selling our
natural gas and oil production at optimal prices while managing
associated price risks.
Our operations are conducted through three primary segments:
Pipelines, Exploration and Production and Marketing. We also
have a Power segment which holds our remaining interests in
international power plants in Brazil, Asia and Central America.
Our business segments provide a variety of energy products and
services and are managed separately as each segment requires
different technology and marketing strategies. For further
discussion of our business segments, see 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 17.
Pipelines
Segment
Our Pipelines segment includes our interstate natural gas
transmission systems and related operations. These operations
are conducted through eight separate, wholly owned pipeline
systems and five 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 (i) our
ownership of storage capacity through our wholly owned
transmission systems, two wholly owned storage facilities, and
three partially owned storage systems as well as (ii) 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:
•
Expanding our systems by attracting new customers, markets or
supply sources;
•
Identifying and developing growth opportunities;
•
Recontracting or contracting available or expiring capacity;
Extends from Louisiana, the Gulf
of Mexico and south Texas to the northeast section of the U.S.,
including the metropolitan areas of New York City and Boston.
14,100
6,961
90
4,534
4,443
4,469
ANR
Pipeline(2) (ANR)
Extends from Louisiana, Oklahoma,
Texas and the Gulf of Mexico to the midwestern and northeastern
regions of the U.S., including the metropolitan areas of
Detroit, Chicago and Milwaukee.
10,500
7,311
197
3,954
4,100
4,067
El Paso Natural Gas (EPNG)
Extends from San Juan,
Permian and Anadarko basins to California, its single largest
market, as well as markets in Arizona, Nevada, New Mexico,
Oklahoma, Texas and northern Mexico.
10,300
5,650(3
)
44
4,179
4,053
4,074
Southern Natural
Gas (SNG)
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.
7,500
3,450
60
2,211
1,984
2,163
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.
4,000
3,000
29
2,008
1,902
1,744
Wyoming
Interstate
(WIC)
Extends from western Wyoming,
western Colorado and the Powder River Basin to various pipeline
interconnections near Cheyenne, Wyoming.
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 to customers in the vicinity of Bakersfield,
California.
400
407
—
461
161
161
Cheyenne Plains Gas
Pipeline(4) (CPG)
Extends from Cheyenne hub in
Colorado to various pipeline interconnections near Greensburg,
Kansas.
400
838
—
583
433
89
(1)
Includes throughput transported on
behalf of affiliates.
(2)
Sold in February 2007.
(3)
This capacity reflects
winter-sustainable west-flow capacity of 4,850 MMcf/d and
approximately 800 MMcf/d of east-end delivery capacity.
(4)
This system was completed in 2005.
As of December 31, 2006, we had the following pipeline and
storage expansion projects on our existing systems that have
been approved by the FERC:
Capacity
Anticipated
Project
(MMcf/d)
Description
Completion Date
Louisiana Deepwater Link
850
To construct a 300 foot extension
of our
20-inch
Grand Isle supply lateral, construct 2,100 feet of
24-inch West
Delta supply lateral, abandon 3,100 feet of the
20-inch line
connected to the Grand Isle platform, and install appurtenant
facilities on Enterprise Product Partners Independence Hub
platform located in Mississippi Canyon Block 920.
July 2007
Triple-T Extension
200
To construct 6.2 miles of
24-inch
pipeline to extend our existing
30-inch
Triple-T Line, beginning in Eugene Island Block 349, to
interconnect with Enterprise Products Partners L.P.’s
Anaconda System on the El 371 platform, as well as associated
piping and other appurtenant facilities.
September 2007
Essex Middlesex Project
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 2007
Northeast ConneXion —
New England
108
To construct a compression station
and modify compression at six existing facilities on our
interstate pipeline system in Pennsylvania, New York, and
Massachusetts.
November 2007
Cypress Expansion
500
To construct approximately
177 miles of pipeline to connect our Elba Island facility
with markets in Georgia and Florida.
May
2007(1)
(1)
Project will consist of three
phases. The anticipated completion date is related to
phase 1.
Extends from Manitoba-Minnesota
border to the Michigan-Ontario border at St. Clair, Michigan.
50
2,115
2,600
2,244
2,376
2,200
Samalayuca Pipeline and Gloria a
Dios Compression Station
Extends from
U.S.-Mexico
border to the state of Chihuahua, Mexico.
50
23
460
442
423
433
San Fernando Pipeline
Extends from Pemex Compression
Station 19 to the Pemex metering station in San Fernando,
Mexico in the State of Tamaulipas.
50
71
1,000
951
951
951
(1)
These systems are accounted for as
equity investments.
(2)
Miles, volumes and average
throughput represent the systems’ totals and are not
adjusted for our ownership interest.
(3)
We have a 50 percent equity
interest in Citrus Corp. (Citrus), which owns this system.
(4)
Sold in February 2007.
Partially
Owned Intrastate Transmission Systems
We also have a 50 percent interest in WYCO Development,
L.L.C. (WYCO). WYCO owns a state regulated intrastate gas
pipeline extending 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.
Underground
Natural Gas Storage Entities
In addition to the storage capacity on our transmission systems,
we own or have interests in the following natural gas storage
entities:
Approximately 135 Bcf is
contracted to affiliates. Amounts are not adjusted for our
ownership interest.
(2)
Sold in February 2007.
(3)
This system is accounted for as an
equity investment.
LNG
Facility
We own an LNG receiving terminal located on Elba Island, near
Savannah, Georgia with a peak sendout capacity of
1,215 MMcf/d and a base load sendout capacity of
806 MMcf/d. The capacity at the terminal is contracted with
subsidiaries of British Gas Group and Royal Dutch Shell PLC.
We provide natural gas services to a variety of customers,
including natural gas producers, marketers, end-users and other
natural gas transmission, distribution and electric generation
companies. In performing these services, we compete with other
pipeline service providers as well as alternative energy sources
such as coal, nuclear, wind, hydroelectric and fuel oil.
Imported LNG is one of the fastest growing supply sectors of the
natural gas market. Terminals and other regasification
facilities can serve as important sources of supply for
pipelines, enhancing their delivery capabilities and operational
flexibility and complementing traditional supply transported
into market areas. These LNG delivery systems, however, 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 contracts with pipelines.
Our existing contracts mature at various times and in varying
amounts of throughput capacity. Our ability to extend our
existing contracts or remarket expiring capacity is dependent on
competitive alternatives, the regulatory environment at the
federal, state and local levels and market supply and demand
factors at the relevant dates these contracts are extended or
expire. The duration of new or renegotiated contracts will be
affected by current prices, competitive conditions and judgments
concerning future market trends and volatility. Subject to
regulatory requirements, we attempt to recontract or remarket
our capacity at the rates allowed under our tariffs although, at
times, we discount these rates to remain competitive. The level
of discount varies for each of our pipeline systems. The table
below shows the contracted capacity that expires by year over
the next five years and thereafter.
The following table details information related to our
customers, contracts, the markets we serve, and the competition
faced by each of our wholly owned pipeline transmission systems
as of December 31, 2006. Our 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 actually transported, stored,
injected or withdrawn.
Approximately 460 firm and
interruptible customers, none of which individually represents
more than 10 percent of revenues
Approximately 470 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.
In the offshore areas of the Gulf of Mexico, factors such as the distance of the supply fields from the pipeline, relative basis pricing of the pipeline receipt points, and costs of intermediate gathering or required processing of the natural gas to be transported may influence determinations of whether natural gas is ultimately attached to the TGP system.
Approximately 290 firm and
interruptible customers
Major Customer:
We Energies
(799 BBtu/d)
Approximately 670 firm
transportation contracts. Weighted average remaining contract
term of approximately five years.
Expire in 2007-2016.
In its market areas, ANR competes directly with Guardian Pipeline, for markets in Wisconsin. ANR also competes directly with other interstate pipelines in the northeast markets to serve electric generation and local distribution companies.
In its supply areas, ANR competes directly with numerous pipelines and gathering systems for access to new supply sources.
ANR’s principal supply sources are the Rockies and mid-continent production accessed in Kansas and Oklahoma, western Canadian production delivered to Wisconsin and the Chicago area and Gulf of Mexico sources, including deepwater production and LNG imports.
Approximately 160 firm and
interruptible customers
Major Customers:
Southern California Gas Company
(101 BBtu/d)
(187 BBtu/d)
(561 BBtu/d)
Approximately 190 firm
transportation contracts. Weighted average remaining contract
term of approximately four years.
Expires in 2007.
Expires in 2009.
Expire in 2010 - 2011.
Expires in 2008.
Expire in 2011 - 2015.
EPNG faces competition in the west
and southwest from other existing and proposed pipelines, from
California storage facilities, and alternative energy sources
that are used to generate electricity such as hydroelectric,
nuclear, wind, coal and fuel oil. In addition, construction of
facilities to bring LNG into California and northern Mexico are
underway.
Approximately 274 firm and
interruptible customers
Major Customers:
Atlanta Gas Light Company
(959 BBtu/d)
Southern Company Services
(418 BBtu/d)
Approximately 200 firm
transportation contracts. Weighted average remaining contract
term of approximately six years.
Expire in 2009-2015.
Expire in 2010-2018.
Expire in 2010-2013.
Expire in 2007-2019.
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, nuclear power, coal and fuel oil.
SNG’s four largest customers are able to obtain a
significant portion of their natural gas requirements through
transportation from other pipelines. Also, SNG competes with
several pipelines for the transportation business of their other
customers. In addition, SNG competes with pipelines and
gathering systems for connection to new supply services.
Approximately 110 firm and
interruptible customers
Major Customers:
Public Service Company of Colorado
(187 BBtu/d)
(9 BBtu/d)
(1,106 BBtu/d)
Williams Power Company
(30 BBtu/d)
(53 BBtu/d)
(348 BBtu/d)
Approximately 170 firm
transportation contracts. Weighted average remaining contract
term of approximately six years.
Expires in 2008.
Expires in 2009.
Expire in 2012-2014.
Expires in 2007.
Expires in 2009.
Expire in 2010 - 2013.
Expires in 2007.
Expires in 2008.
Expires in 2009.
Expire in 2010 - 2015.
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, a new 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 a
new interstate pipeline and other existing interstate pipelines
that are directly connected to its supply sources.
Major Customers:
Williams Power Company
(25 BBtu/d)
Approximately 50 firm
transportation contracts. Weighted average remaining contract
term of approximately six years.
Expires in 2008.
Expire in 2010-2021.
Expires in 2008.
Expire in 2011-2017.
WIC competes with existing
pipelines and a new interstate pipeline to provide
transportation services to pipeline interconnects in northeast
Colorado and western Wyoming.
Major Customers:
Los Angeles Department of Water
and Power
(50 BBtu/d)
Approximately six firm
transportation contracts. Weighted average remaining contract
term of approximately seven years.
Expires in 2015.
Expires in 2007.
MPC faces competition from other
existing and proposed pipelines, and alternative energy sources
that are used to generate electricity such as hydroelectric,
nuclear, wind, coal and fuel oil. In addition, construction of
facilities to bring LNG into California and northern Mexico are
underway.
Major Customers:
Oneok Energy Services
Company L.P.
(195 BBtu/d)
Approximately 30 firm
transportation contracts. Weighted average remaining contract
term of approximately eight years.
Expire in 2015.
Expire in 2015.
Expire in 2015-2016.
CPG competes directly with other
interstate pipelines serving the mid- continent region.
Indirectly, CPG competes with pipelines that are existing and
currently under construction to transport Rocky Mountain gas to
other markets.
Our Exploration and Production segment’s current 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, 2006,
we controlled over 2.9 million net leasehold acres. During
2006, daily equivalent natural gas production averaged
approximately 730 MMcfe/d and our proved natural gas and
oil reserves at December 31, 2006, were approximately
2.4 Tcfe, excluding 0.2 Tcfe related to our
unconsolidated investment in Four Star Oil & Gas
Company. 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 and coal bed methane 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 2006, we
invested $500 million on capital projects and production
averaged 345 MMcfe/d. The principal operating areas are
listed below:
2006
Average
Net
Capital
Production
Region
Description
Acres
Investment
(MMcfe/d)
East Texas/north Louisiana
(Arklatex)
Concentrated land position
primarily focused on tight gas sands production in the Travis
Peak/Hosston and Cotton Valley formations.
104,000
$203 million
122
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.
172,000
$49 million
64
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.
319,000
$56 million
28
Rocky Mountain (Rockies)
Primarily in Wyoming and Utah with
a focus in the Powder River and Uintah basins, consisting
predominantly of operated oil fields utilizing both primary and
secondary recovery methods combined with non-operated coal bed
methane fields. We also operate the Altamont and Bluebell
processing plants and related gathering systems in Utah.
364,000
$120 million
55
Raton Basin
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.
605,000
$72 million
76
Included in our Mid-Continent region is our interest in
127,000 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 22 wells through the end
of 2006.
Texas Gulf Coast. The Texas Gulf Coast region
focuses on developing and exploring for tight gas sands in south
Texas. In this area, we have an inventory of over
10,000 square miles of three dimensional (3D) seismic data.
During 2006, we invested $217 million on capital projects
and production averaged 187 MMcfe/d. The principal
operating areas are listed below:
2006
Average
Capital
Production
Region
Description
Net Acres
Investment
(MMcfe/d)
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.
81,000
$111 million
123
Upper Gulf Coast Wilcox
Located onshore Texas Gulf Coast,
including Renger, Dry Hollow and Speaks fields in Lavaca County.
In this area, average well depth is between 13,000 to
18,000 feet.
31,000
$60 million
32
South Texas Wilcox
Includes the Bob West and Roleta
fields in Zapata County where in January 2007 we completed the
acquisition described below.
25,000
$29 million
27
In January 2007, we acquired operated producing properties and
undeveloped acreage in Zapata County, Texas with an average
working interest of 85 percent. These properties complement
our existing south Texas Wilcox operations providing a re-entry
into the Lobo trend and a multi-year drilling inventory with
significant additional exploration and development drilling
opportunities. The 23,000 net acres acquired had production
of approximately 12 MMcfe/d on the acquisition date.
Estimated proved reserves at the acquisition date were
approximately 84 Bcfe, of which approximately
73 percent was undeveloped.
Gulf of Mexico Shelf and south Louisiana. Our
Gulf of Mexico shelf and south Louisiana operations are
generally characterized by relatively high initial production
rates, resulting in near-term cash flows, and high decline
rates. During 2006, we invested $310 million on drilling,
workover and facilities projects and production averaged
174 MMcfe/d. The principal operating areas are listed below:
2006
Average
Capital
Production
Region
Description
Net Acres
Investment
(MMcfe/d)
Gulf of Mexico Shelf
Primarily deep shelf drilling
interests in 173 Blocks (generally nine square miles) south of
the Louisiana, Texas and Alabama shorelines focused on deep
(greater than 12,000 feet) gas reserves in relatively
shallow waters depths (less than 400 feet).
688,000
$246 million
163
South Louisiana
Primarily in Vermillion Parish and
associated bays and waters in southwestern Louisiana covered by
the Catapult 3D seismic project. We have internally processed
2,600 square miles of contiguous 3D seismic data in this
project.
Unconsolidated Investment in Four Star. We own
a 43.1 percent investment in Four Star. Four Star operates
onshore in the San Juan, Permian, Hugoton and South Alabama
Basins and the Gulf of Mexico. During 2006, our proportionate
share of Four Star’s daily equivalent natural gas
production averaged approximately 68 MMcfe/d and at
December 31, 2006, proved natural gas and oil reserves, net
to our interest, were 222 Bcfe. In January 2007, Four Star
acquired 79 wells in the San Juan basin that had daily
production of approximately 5 MMcfe/d and proved reserves
of 16 Bcfe, net to our interest, on the acquisition date.
International
Brazil. Our Brazil operations cover
approximately 361,000 net acres. These 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. In 2006, we invested $80 million in capital projects
in Brazil and production averaged approximately 24 MMcfe/d
from the Pescada Arabaiana Fields.
Egypt. Our Egypt 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, which is in the seismic, exploratory drilling
and evaluation phases of the project. Our total funding
commitment to the South Feiran concession is $3 million. In
addition, we were the winning bidder of the South Mariut Block
in the second quarter of 2006 with a $3 million payment due
on final receipt of the concession and an agreement for a
$22 million firm working commitment over three years. The
block is approximately 1.2 million acres and is located
onshore in the western part of the Nile Delta. We expect to
receive formal governmental approvals and sign the concession
agreement during the first quarter of 2007.
Natural
Gas, Oil and Condensate and NGL Reserves and
Production
The table below presents our estimated proved reserves based on
our internal reserve report as of December 31, 2006 by
region and classification as well as our 2006 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.:
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, prepared an estimate on
84 percent of our consolidated natural gas and oil
reserves. Additionally, Ryder Scott prepared an estimate of
80 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.
There are numerous uncertainties inherent in estimating
quantities of proved reserves, projecting future rates of
production costs, and projecting the timing of development
expenditures, including many factors beyond our control.
Reservoir engineering is a subjective process of estimating
underground accumulations of natural gas and oil that cannot be
measured in an exact manner. The reserve data represents only
estimates which are often different from the quantities of
natural gas and oil that are ultimately recovered. The accuracy
of any reserve estimate is highly dependent on the quality of
available data, the accuracy of the assumptions on which they
are based, and on engineering and geological interpretations and
judgment.
All estimates of proved reserves are determined according to the
rules prescribed by the SEC. These rules indicate that the
standard of “reasonable certainty” be applied to
proved reserve estimates. This concept of reasonable certainty
implies that as more technical data becomes available, a
positive, or upward, revision is more likely than a negative, or
downward, revision. Estimates are subject to revision based upon
a number of factors, including reservoir performance, prices,
economic conditions and government restrictions. In addition,
results of drilling, testing and production subsequent to the
date of an estimate may justify revision of that estimate.
In general, the volume of production from natural gas and oil
properties we own declines as reserves are depleted. Except to
the extent we conduct successful exploration and development
activities or acquire additional properties containing proved
reserves, or both, our proved reserves will decline as reserves
are produced. Recovery of proved undeveloped reserves requires
significant capital expenditures and successful drilling
operations. The reserve data assumes that we can and will make
these expenditures and conduct these operations successfully,
but future events, including commodity price changes, may cause
these assumptions to change. In addition, estimates of proved
undeveloped reserves and proved non-producing reserves are
subject to greater uncertainties than estimates of proved
producing reserves. For further discussion of our reserves, see
Part II, Item 8, Financial Statements and
Supplementary Data, under the heading Supplemental Natural Gas
and Oil Operations.
Acreage
and Wells
The following tables detail (i) our interest in developed
and undeveloped acreage at December 31, 2006, (ii) our
interest in natural gas and oil wells at December 31, 2006
and (iii) our exploratory and development wells drilled
during the years 2004 through 2006. Any acreage in which our
interest is limited to owned royalty, overriding royalty and
other similar interests is excluded.
In the United States, our net developed acreage is concentrated
primarily in the Gulf of Mexico (36 percent), Utah
(13 percent), Texas (9 percent), Alabama
(9 percent), New Mexico (9 percent), Oklahoma
(8 percent) and Louisiana (7 percent). Our net
undeveloped acreage is concentrated primarily in New Mexico
(31 percent), the Gulf of Mexico (22 percent),
Wyoming (10 percent), West Virginia (8 percent),
Indiana (7 percent), Alabama (5 percent), Texas
(4 percent) and Louisiana (3 percent). Approximately
23 percent, 20 percent and 8 percent of our total
United States net undeveloped acreage is held under leases that
have minimum remaining primary terms expiring in 2007, 2008 and
2009. Approximately 16 percent, 25 percent and
12 percent of our total Brazilian net undeveloped acreage
is held under leases that have minimum remaining primary terms
expiring in 2007, 2008 and 2009. Approximately 33 percent
of our total Egyptian net undeveloped acreage is held under
leases that have minimum remaining primary terms expiring in
2008. 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.
Wells Being Drilled at December 31,
Natural Gas
Oil
Total
2006
Productive Wells
Gross(1)
Net(2)
Gross(1)
Net(2)
Gross(1)
Net(2)(3)
Gross(1)
Net(2)
United States
Onshore
3,880
2,954
801
548
4,681
3,502
52
38
Texas Gulf Coast
843
703
—
—
843
703
6
5
Gulf of Mexico Shelf and south
Louisiana
187
122
58
40
245
162
6
4
Total
4,910
3,779
859
588
5,769
4,367
64
47
Brazil
4
1
6
2
10
3
—
—
Worldwide Total
4,914
3,780
865
590
5,779
4,370
64
47
Net
Exploratory(2)
Net
Development(2)
Wells Drilled
2006
2005
2004
2006
2005
2004
United States
Productive
106
86
13
319
279
298
Dry
6
2
10
2
4
3
Total
112
88
23
321
283
301
Brazil
Productive
—
—
—
—
—
—
Dry
—
—
1
—
—
—
Total
—
—
1
—
—
—
Worldwide
Productive
106
86
13
319
279
298
Dry
6
2
11
2
4
3
Total
112
88
24
321
283
301
(1)
Gross interest reflects the total
acreage or wells we participated in, regardless of our ownership
interest in the acreage or wells.
(2)
Net interest is the aggregate of
the fractional working interests that we have in the gross
acreage, gross wells or gross wells drilled.
(3)
At December 31, 2006, we
operated 3,957 of the 4,370 net productive wells.
The drilling performance above should not be considered
indicative of future drilling performance, nor should it be
assumed that there is any correlation between the number of
productive wells drilled and the amount of natural gas and oil
that may ultimately be recovered.
Net
Production, Sales Prices, Transportation and Production
Costs
The following table details our net production volumes, average
sales prices received, average transportation costs 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:
2006
2005
2004
Consolidated Volumes, Prices,
and Costs per Unit:
Net Production Volumes
United States
Natural gas (MMcf)
213,262
206,714
238,009
Oil, condensate and NGL (MBbls)
7,439
7,516
8,498
Total (MMcfe)
257,899
251,807
288,994
Brazil(1)
Natural gas (MMcf)
7,140
15,578
6,848
Oil, condensate and NGL (MBbls)
247
620
320
Total (MMcfe)
8,619
19,300
8,772
Worldwide
Natural gas (MMcf)
220,402
222,292
244,857
Oil, condensate and NGL (MBbls)
7,686
8,136
8,818
Total (MMcfe)
266,518
271,107
297,766
Total (MMcfe/d)
730
743
814
Natural Gas Average Realized Sales
Price ($/Mcf)
United States
Excluding hedges
$
6.77
$
7.92
$
6.02
Including hedges
$
6.50
$
6.69
$
5.94
Brazil
Excluding hedges
$
2.61
$
2.33
$
2.01
Including hedges
$
2.61
$
2.33
$
2.01
Worldwide
Excluding hedges
$
6.64
$
7.53
$
5.90
Including hedges
$
6.38
$
6.39
$
5.83
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 Field in 2006.
(2)
Production cost includes lease
operating costs and production related taxes (including ad
valorem and severance taxes).
(3)
Includes our proportionate share of
volumes in Four Star which was acquired in the third quarter of
2005.
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:
2006
2005
2004
(In millions)
United States
Acquisition Costs:
Proved
$
2
$
643
$
33
Unproved
34
143
32
Development Costs
738
503
395
Exploration Costs:
Delay rentals
6
3
7
Seismic acquisition and
reprocessing
23
7
29
Drilling
294
133
149
Asset Retirement Obligations
3
1
30
Total full cost pool expenditures
1,100
1,433
675
Non-full cost pool expenditures
8
22
11
Total cost
incurred(1)
$
1,108
$
1,455
$
686
Acquisition of unconsolidated
investment in Four
Star(1)
Acquisition of unconsolidated
investment in Four
Star(1)
$
—
$
769
$
—
(1)
In 2005, amount includes
$179 million of deferred income tax adjustments related to
the acquisition of full-cost pool properties and
$217 million related to the acquisition of our
unconsolidated investment in Four Star.
We spent approximately $192 million in 2006,
$247 million in 2005 and $156 million in 2004 to
develop proved undeveloped reserves that were included in our
reserve report as of January 1 of each year.
Markets
and Competition
We primarily sell our domestic natural gas and oil to third
parties through our Marketing 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 31,2006, we had entered into derivative contracts on approximately
133,000 BBtu of our anticipated natural gas production in 2007
and approximately 21,000 BBtu of our total anticipated natural
gas production from 2008 through 2012. We also have derivative
contracts on our Brazilian oil production that provides us with
a fixed price on approximately 192 MBbls in 2007. 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.
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 historical
trading activities, which were primarily entered into prior to
the deterioration of the energy trading environment in 2002. As
of December 31, 2006, we managed the following types of
contacts:
•
Production-Related Natural Gas and Oil
Derivatives. 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.
•
Historical Natural Gas and Power
Contracts. Includes supply agreements with
Midland Cogeneration Venture and power contracts in the
Pennsylvania-New Jersey-Maryland region.
Production-Related
Natural Gas and Oil Derivatives
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 on page 12. For a further discussion of the
entirety of El Paso’s production-related price risk
management activities, refer to our liquidity discussion
beginning on page 62. As of December 31, 2006,
Marketing’s contracts provided El Paso with price
protection on the following quantities of future natural gas and
oil production:
2007
2008
2009
Natural Gas (TBtu)
Volumes with floor price
89
18
17
Volumes with ceiling price
—
18
17
Oil (MBbls)
Volumes with floor and ceiling
prices
1,009
930
—
Contracts
Related to Historical Trading Operations
Natural gas transportation-related
contracts. Our transportation contracts give us
the right to transport natural gas using pipeline capacity for a
fixed reservation charge plus variable transportation costs. We
typically refer to the fixed reservation cost as a demand
charge. Our ability to utilize our transportation capacity under
these contracts is dependent on several factors, including the
difference in natural gas prices at receipt and delivery
locations along the pipeline system, the amount of working
capital needed to use this capacity and the capacity required to
meet our other long-term obligations. The following table
details our transportation contracts as of December 31,2006:
Primarily consists of contracts
with TGP and EPNG.
(2)
In December 2006, we paid a third
party to assume our capacity obligations under this contract
beginning November 1, 2007 through the contractual term of
the contract which ends in 2015.
Other natural gas contracts. As of
December 31, 2006, we had a variety of natural gas
derivative contracts and long-term gas supply obligations,
including ten significant physical natural gas contracts with
power plants associated with our historical trading activities.
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 21,500 to 130,000 MMBtu/d.
Power contracts. As of December 31, 2006,
we had four derivative contracts that require us to swap
locational differences in power prices between four power plants
in the Pennsylvania-New Jersey-Maryland (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 2013 and 1,700 GWh from 2014 to 2016. Additionally,
these contracts require us to provide installed capacity of
approximately 71 GWh 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 in 2005 and 2006.
Markets
and Competition
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 power producers with varying
scopes of operations and financial resources.
Power
Segment
As of December 31, 2006, our Power segment primarily
included the ownership and operation of investments in
international power generation facilities listed in the table
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 currently expect to complete the sale of
substantially all of the Asian and Central American facilities
in the first half of 2007.
Ownership of these plants will
transfer to the power purchaser no later than January 2008.
(2)
The power purchaser has approached
us with the opportunity to sell them our interest in the
facility.
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 2006 throughput of
1,197 MMcf/d and 1,037 BBtu/d, unadjusted for our ownership
interest. We also have an interest in a pipeline project in
Brazil that is in the development stage.
Regulatory
Environment
Pipelines. Our interstate natural gas
transmission systems and storage operations are regulated by the
FERC under the Natural Gas Act of 1938, the Natural Gas Policy
Act of 1978 and the Energy Policy Act of 2005. Each of
our interstate pipeline systems and storage facilities operates
under tariffs approved by the FERC that establish rates, cost
recovery mechanisms, and terms and conditions for service to our
customers. Generally, the FERC’s authority extends to:
•
rates and charges for natural gas transportation, storage, LNG
terminalling and related services;
•
certification and construction of new facilities;
•
extension or abandonment of 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 the 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.
Exploration and Production. 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, 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 spills and oil pollution
liability.
Power. Our remaining international power
generation activities are regulated by governmental agencies in
the countries in which these projects are located. Many of these
countries have developed or are developing new regulatory and
legal structures for private and foreign-owned businesses. These
regulatory and legal structures are subject to change (including
differing interpretations) over time.
Environmental
A description of our environmental activities is included in
Part II, Item 8 Financial Statements and Supplementary
Data, Note 13.
Employees
As of February 23, 2007, we had approximately
5,050 full-time employees, of which 224 employees are
subject to collective bargaining arrangements.
Executive Vice President and Chief
Financial Officer of El Paso
2005
45
Robert W. Baker
Executive Vice President and
General Counsel of El Paso
2002
50
Brent Smolik
Executive Vice President of
El Paso and President of El Paso
Exploration & Production Company
2006
45
Susan B. Ortenstone
Senior Vice President (Human
Resources and Administration) of El Paso
2003
50
James C. Yardley
Executive Vice President of
El Paso, Chairman of the Board of El Paso’s
Pipeline Group and Chairman of the Board and President of
Southern Pipeline Group
2005
55
James J. Cleary
President of Western Pipeline Group
2005
52
Daniel B. Martin
Senior Vice President of Pipeline
Operations
2005
50
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.
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.
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.
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 supervisory
and asset management 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.
James C. Yardley has been Executive Vice President of
El Paso and Chairman of the Board of El Paso’s
Pipeline Group since August 2006. He has been Chairman of the
Board and President of Southern Natural Gas Company since May
2005, Director of Southern Natural Gas Company since November
2001 and President of Southern Natural Gas Company since May
1998. He served as Vice President, Marketing and Business
Development for Southern Natural Gas Company from April 1994 to
April 1998. Prior to that time, Mr. Yardley worked in
various capacities with Southern Natural Gas and Sonat Inc.
since 1978.
James J. Cleary has been President and Director 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 through
December 2003, he served as President of ANR Pipeline
Company. Prior to that time, Mr. Cleary served as Executive
Vice President of Southern Natural Gas Company from May 1998 to
January 2001. He also worked for Southern Natural Gas Company
and its affiliates in various capacities since 1979.
Daniel B. Martin has been Director of ANR Pipeline Company,
Colorado Interstate Gas Company, El Paso Natural Gas
Company, Southern Natural Gas Company and Tennessee Gas Pipeline
Company since May 2005. He has been Senior Vice President of
El Paso Natural Gas Company since February 2000, Senior
Vice President of Southern Natural Gas Company and Tennessee Gas
Pipeline Company since June 2000 and Senior Vice President of
ANR Pipeline Company and Colorado Interstate Gas Company since
January 2001. Prior to that time, Mr. Martin worked in
various capacities with Tennessee Gas Pipeline Company since
1978.
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.
ITEM 1A.
RISK
FACTORS
CAUTIONARY
STATEMENT FOR PURPOSES OF THE “SAFE HARBOR” PROVISIONS
OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF
1995
This report contains forward-looking statements within the
meaning of the Private Securities Litigation Reform Act of 1995.
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 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 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, to renegotiate
existing contracts as they expire 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 gas
supply sources, such as LNG;
•
decreased natural gas demand due to various factors, including
increases in prices and the availability or popularity of other
energy sources such as hydroelectric, nuclear, wind, and coal
power 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;
•
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.
The
revenues of our pipeline businesses are generated under
contracts that must be renegotiated periodically.
Substantially all of our pipeline subsidiaries’ revenues
are generated under contracts which expire periodically and must
be renegotiated and extended or replaced. 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 transmission, 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 oil producing countries.
The
expansion of our pipeline systems by constructing new facilities
subjects us to construction and other risks that may adversely
affect the financial results of our pipeline
businesses.
We may expand the capacity of our existing pipeline, storage or
LNG facilities by constructing additional facilities.
Construction of these facilities is subject to various
regulatory, development and operational risks, including:
•
our ability to obtain necessary approvals and permits by
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 and
regulations, 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, or other factors beyond our control, that may be material;
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, 2006 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 factors that are beyond our control.
The performance of our exploration and production business is
dependent upon a number of factors that we cannot control,
including:
•
the results of future drilling activity;
•
the availability and significant 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
•
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
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, as prescribed by the SEC, which may not
necessarily represent the most appropriate discount factor,
given actual interest rates and risks to which our exploration
and production business or the natural gas and oil industry, in
general, are subject. Any significant variations from the
interpretations or assumptions used in our estimates or changes
of conditions could cause the estimated quantities and net
present value of our reserves to differ materially.
Our reserve data represents an estimate. You should not assume
that the present values referred to in this report represent the
current market value of our estimated natural gas and oil
reserves. The timing of the production and the expenses related
to the development and production of natural gas and oil
properties will affect both the timing of actual future net cash
flows from our proved reserves and their present value. Changes
in the present value of these reserves could cause a write-down
in the carrying value of our natural gas and oil properties,
which could be substantial, and would negatively affect our net
income and stockholders’ equity.
A portion of our estimated proved reserves are undeveloped.
Recovery of undeveloped reserves requires significant capital
expenditures and successful drilling operations. The reserve
data assumes that we can and will make these expenditures and
conduct these operations successfully, but future events,
including commodity price changes, may cause these assumptions
to change.
The
success of our exploration and production business depends upon
our ability to replace reserves that we produce.
Unless we successfully replace the reserves that we produce, our
reserves will decline 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, swaps and option contracts
traded on the New York Mercantile Exchange,
over-the-counter
options and price and basis swaps with other natural gas
merchants and financial institutions. To the extent we have
positions that are not designated or qualify as hedges, changes
in commodity prices, interest rates, volatility, correlation
factors and the liquidity of the market could cause our
revenues, net income and cash requirements to be volatile.
We could incur financial losses in the future as a result of
volatility in the market values of the energy commodities we
trade, or if one of our counterparties fails to perform under a
contract. The valuation of these financial instruments involves
estimates. Changes in the assumptions underlying these estimates
can occur, changing our valuation of these instruments and
potentially resulting in financial losses. To the extent we
hedge our commodity price exposure and interest rate exposure,
we forego the benefits we would otherwise experience if
commodity prices or interest rates were to change favorably. The
use of derivatives could require the posting of collateral with
our counterparties which can impact our working capital (current
assets 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 8.
Our
businesses are subject to the risk of payment defaults by our
counterparties.
We frequently extend credit to our counterparties following the
performance of credit analysis. Despite performing this
analysis, we are exposed to the risk that we may not be able to
collect amounts owed to us. Although in many cases we have
collateral to secure the counterparty’s performance, it
could be inadequate and we could suffer losses.
Our
foreign operations and investments involve special
risks.
Our activities in areas outside the United States, including
power, pipeline and exploration and production projects in
Brazil and exploration and production projects in Egypt, 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, 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. In addition,
as we exit businesses, we have experienced substantial
reductions and turnover in our workforce that previously
supported the ownership and operation of such assets 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 including
those involving allegations associated with our legacy trading
business, our oil and gas reserves, and the accounting treatment
of certain hedges of our anticipated natural gas production.
These investigations involve, among others, one or more of the
following governmental agencies: the SEC, FERC, the
U.S. Department of Transportation Office of Pipeline Safety
and the Department of Justice. We are cooperating with the
governmental agency or agencies in each of these investigations.
The outcome of each of these investigations and the costs to the
Company of responding and participating in these on-going
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 affect our profitability.
Our pipeline businesses are regulated by the FERC, the
U.S. Department of Transportation, the U.S. Department
of Interior, and various state, local and tribal regulatory
agencies. Regulatory actions taken by those agencies have the
potential to adversely affect our profitability. In particular,
the FERC regulates the rates our pipelines are permitted to
charge their customers for their services. In setting authorized
rates of return in recent FERC decisions, the FERC has utilized
a proxy group of companies that includes local distribution
companies that are not faced with as much competition or risk as
interstate pipelines. The inclusion of these lower risk
companies may create downward pressure on tariff rates when
subjected to review by the FERC in future rate proceedings.
Shippers on other pipelines have sought reductions from the FERC
for the rates charged by pipelines to their customers. If our
pipelines’ tariff rates were reduced or re-designed in a
future proceeding, if our pipelines’ volume of business
under their currently permitted rates was decreased
significantly, or if our pipelines were required to
substantially discount the rates for their services because of
competition or because of regulatory pressure, the profitability
of our pipeline businesses could be reduced.
In addition, increased regulatory requirements relating to the
integrity of our pipelines requires additional spending in order
to maintain compliance with these requirements. Any additional
requirements that are enacted could significantly increase the
amount of these expenditures. Further, state agencies that
regulate our pipelines’ local distribution company
customers could impose requirements that could impact demand for
our pipelines’ services.
Environmental
compliance and remediation costs and the costs of environmental
liabilities could exceed our estimates.
Our operations are subject to various environmental laws and
regulations regarding compliance and remediation obligations.
Compliance obligations can result in significant costs to
install and maintain pollution controls, fines and penalties
resulting from any failure to comply, and potential limitations
on our operations. Remediation obligations can result in
significant costs associated with the investigation 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 exactly the 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 13. These
uncertainties include:
•
estimating pollution control and clean up costs, including for
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; and
•
evaluating and understanding environmental laws and regulations,
including their interpretation and enforcement.
Currently, various legislative and regulatory measures to
address greenhouse gas (GHG) emissions (including carbon dioxide
and methane) are in various phases of discussion or
implementation. These include the Kyoto Protocol, proposed
federal legislation and state actions to develop statewide or
regional programs, each of which have imposed or would impose
reductions in GHG emissions. These actions could result in
increased costs to (i) operate and maintain our facilities,
(ii) install new emission controls on our facilities and
(iii) administer and manage any GHG emissions program.
These actions could also impact the consumption of natural gas
and oil, thereby affecting our pipeline and exploration and
production operations.
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 13). 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 our senior unsecured
indebtedness are below investment grade, currently rated B2 with
a positive outlook by Moody’s Investor Service
(Moody’s) and B 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 12, 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 CIG, EPNG, TGP and certain natural
gas and oil reserves. A breach of the covenants under these
agreements could permit the lenders to exercise their rights to
foreclose on these collateral interests.
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;
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 13, and are incorporated herein by reference.
Various shareholder class actions were filed in the
U.S. District Court for the Southern District of Texas,
Houston Division commencing on July 18, 2002. They have now
been consolidated into the action styled as follows: Oscar S.
Wyatt, Jr et al v. El Paso Corporation, William
Wise, H. Brent Austin, Ralph Eads, Rodney D. Erskine, Ronald
Kuehn, Jr., D. Dwight Scott, Credit Suisse First Boston LLC
and PricewaterhouseCoopers LLP.
Environmental
Proceedings
Natural Buttes. In May 2003, we met with the
EPA to discuss potential prevention of significant deterioration
violations due to a possible de-bottlenecking modification at
our facility in Utah. The EPA issued an Administrative
Compliance Order as to this and other matters and we entered
into settlement negotiations with the EPA. In September 2005, we
were informed that the EPA referred this matter to the
U.S. Department of Justice. We have since entered into
tolling agreements to facilitate continuing settlement
discussions. In October 2006, the EPA indicated that it would
settle this matter for a penalty of $420,000, largely related to
alleged excess emissions from an improperly installed flare. We
have reserved our anticipated settlement amount and are
formulating a proposal for a supplemental environmental project,
which would be conducted in lieu of a substantial portion of any
eventual penalty. We believe the resolution of this matter will
not have a material adverse effect on our operating results or
financial condition.
ITEM 4.
SUBMISSION
OF MATTERS TO A VOTE OF SECURITY HOLDERS
MARKET
FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS
AND ISSUER PURCHASES OF EQUITY SECURITIES
Our common stock is traded on the New York Stock Exchange under
the symbol EP. As of February 26, 2007, we had 30,164
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
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
2005
Fourth Quarter
$
14.07
$
10.78
$
0.04
Third Quarter
14.16
11.13
0.04
Second Quarter
11.87
9.30
0.04
First Quarter
13.15
10.01
0.04
Stock Performance Graph. This graph reflects
the comparative changes in the value of $100 invested since
December 31, 2001 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 2006 included the following companies:
Anadarko Petroleum Corp., Apache Corp., CenterPoint Energy Inc.,
Devon Energy Corp., Dominion Resources, Inc., Enbridge, Inc.,
Equitable Resources, Inc., Kinder Morgan, Inc., NiSource, Inc.,
ONEOK, Inc., PG&E Corp., PPL Corp., Questar Corp., Sempra
Energy, Southern Union Co., Transcanada Corp., Western Gas
Resources, Inc. and Williams Companies, Inc.
S&P 500 Oil & Gas
Storage & Transportation
Index(1)
$
100
$
23.68
$
38.62
$
54.04
$
71.38
$
85.07
Peer Group
$
100
$
82.63
$
113.63
$
142.76
$
187.06
$
211.96
(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 14, 2007,
we declared a quarterly dividend of $0.04 per share of our
common stock, payable on April 2, 2007, to shareholders of
record as of March 2, 2007. 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 presents selected historical financial data
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. This
information has been adjusted in all periods to reflect the
reclassification of ANR, our Michigan storage assets and our
50% interest in Great Lakes Gas Transmission as well as our
Macae power facility 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.
Over the past five years, our financial position and operating
results have been substantially affected by the restructuring
and realignment of our business around our core pipeline and
exploration and production operations. As part of this
realignment, since 2003 we have sold a substantial amount of
non-core assets to reduce our long-term financing obligations
resulting in a substantial reduction of our revenues and net
income during this period. During this period, we recorded net
pretax charges of approximately $0.1 billion in 2005,
$1.1 billion in 2004, $1.3 billion in 2003, and
$1.8 billion in 2002, primarily as a result of losses and
impairments of assets and equity investments, restructuring
charges, and settling litigation associated with the western
energy crisis in 2000 to 2001.
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. This information has
been adjusted in all periods to reflect the reclassification of
ANR, our Michigan storage assets and our 50% interest in Great
Lakes Gas Transmission as well as our Macae power facility as
discontinued operations. 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 22. Listed below is a general outline of our MD&A
to help understand our operations and the business environment
in which we operate.
Our Business — a summary of our business
purpose and description, profitability drivers, a summary of our
2006 performance, what to expect in our business in 2007 and an
update of our credit metrics;
Results of Operations — a
year-over-year
analysis beginning on page 37 of the results of our
business segments, our corporate activities and other income
statement items;
Capital Resources and Liquidity — a general
discussion beginning on page 62 of our debt obligations,
available liquidity, expected 2007 cash flows, and significant
factors that could impact our liquidity, as well as an overview
of cash flow activity during 2006;
Off Balance Sheet Arrangements, Contractual Obligations, and
Commodity-Based Derivative Contracts — a
discussion beginning on page 67 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 — a discussion
beginning on page 70 of accounting estimates that involve
the use of significant assumptions
and/or
judgments in the preparation of our financial statements.
Our
Business
Primary Business Purpose and Description. Our
business purpose is to provide natural gas and related energy
products in a safe, efficient and dependable manner. We own 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 allocation and portfolio management,
cost control and marketing and selling our natural gas and oil
production at optimal prices while managing associated price
risks.
Drivers of 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. The profitability of
our exploration and production operations is 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 these operations will be primarily driven by the following
factors:
Pipelines
—
Expanding our existing pipeline systems to meet demand growth
and gain access to new supply areas and sources;
—
Contracting and recontracting pipeline capacity with our
customers;
—
Maintaining approval by FERC of acceptable rates and terms of
service, including successfully resolving rate cases; and
Increasing our natural gas and oil proved reserve base and
production volumes through successful drilling programs or
acquisitions; and
—
Finding and producing natural gas and oil at a reasonable cost.
In addition to these factors, our future profitability will also
be impacted by our debt level and related interest costs,
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 2006. During
2006, our financial performance was relatively stable. Our
pipeline business experienced substantial earnings growth and
continued to provide a strong base of earnings and cash flow.
Our exploration and production business experienced continued
success in its drilling programs resulting in higher production
levels during each quarter of the year. However, lower than
planned production volumes in 2006 and lower than expected
commodity prices impacted our ability to attain the operational
and financial targets for the year we previously established.
The table that follows and our individual segment discussions
provide further analysis of our operating results.
Area of Operations
Significant Highlights
Pipelines
Announced the sale of ANR, our
Michigan storage assets and our 50 percent interest in
Great Lakes Gas Transmission
Implemented a FERC approved rate
case settlement for Colorado Interstate Gas Company and filed a
rate case settlement for approval with the FERC for El Paso
Natural Gas Company
Re-contracted or contracted
available or expiring capacity
Completed several expansion
projects and proceeded with other expansion projects in our
pipeline systems and at our Elba Island LNG facility
Repaired significant damage to
sections of our Gulf Coast and offshore pipeline facilities
caused by Hurricanes Katrina and Rita
E & P
Increased production volumes in
each quarter of the year despite lower than planned annual
production as a result of delays in bringing certain production
online, delays in recovering lost volumes due to Hurricanes
Katrina and Rita and higher than planned maintenance in certain
onshore fields
Entered into additional derivative
contracts in 2006 to manage price risk on a substantial portion
of our 2007 natural gas production
Replaced our production primarily
through our capital drilling program, achieving an overall
drilling success rate of 98 percent
Marketing
Entered into agreements to assign,
terminate or divest of a significant transportation contract and
certain of our historical natural gas and power contracts
Other
Resolved various legal and
contractual disputes, including a settlement of the pending
shareholder and derivative actions, those related to our
Brazilian power plants and other domestic legal matters
Divested of a majority of our
remaining power operations for total proceeds of approximately
$0.9 billion, including our Macae power facility
What to Expect Going Forward. For 2007, we
expect our current operating trends to continue. In our pipeline
business, in February 2007, we sold ANR, our Michigan storage
assets and our 50 percent interest in Great Lakes Gas
Transmission. We continue to lay the foundation for future
growth by establishing an inventory of expansion projects in our
primary growth areas and developing significant infrastructure
opportunities. We anticipate that our remaining pipeline
operations will continue to provide strong operating results
based on the current levels of contracted capacity, continued
success in re-contracting, expansion plans in our market and
supply areas and the
status of rate and regulatory actions. We recently announced
that we will pursue the formation of a master limited
partnership in 2007 to enhance the value and financial
flexibility of our pipeline assets and provide a lower-cost
source of capital for new projects.
In our exploration and production business, we will continue to
seek to create value through a disciplined and balanced capital
investment program, through active management of the increasing
cost of production services, and efficiency improvements. In our
drilling programs, we will focus on delivering reserves and
volumes at reasonable finding and operating costs. Our future
financial results will be primarily dependent on the continued
successful execution of these drilling programs and commodity
prices to the extent our anticipated natural gas and oil
production is unhedged. We have hedged a substantial portion of
our anticipated 2007 natural gas and oil production.
Update of Credit Metrics. In 2006, we
strengthened our credit metrics as a result of several actions
taken during the year including:
•
Reducing debt by $2.8 billion, primarily through asset
sales and issuing common stock;
•
Restructuring our revolving credit facilities with improved
terms;
•
Receiving upgraded senior unsecured debt ratings to B2 with a
positive outlook from Moody’s and B with a positive outlook
from Standard and Poor’s; and
•
Entering into contracts to eliminate the price risk on a portion
of our historical Marketing natural gas book.
Our net debt (debt less cash) was $14.9 billion at
December 31, 2006 (including $0.7 billion of ANR debt
reported in discontinued operations). The closing of the ANR
sale provides us with approximately $3.3 billion for
additional debt reduction, and in February 2007, we launched an
offer to tender for certain of our outstanding debt issues.
Additional debt reductions will be based on the capital
requirements of our pipeline and exploration and production
businesses, our ability to generate strong cash flow from these
businesses, completion of the sale of our remaining power assets
and resolution of remaining historical issues. Our liquidity and
capital resources discussions that follow provide further
information on these events.
Results
of Operations
Overview
As of December 31, 2006, our core operating business
segments were Pipelines, Exploration and Production and
Marketing. We also have a Power segment with interests in
international power plants in Brazil, Asia and Central America.
These 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 consolidated
operations as well as investments in unconsolidated affiliates.
We believe EBIT is useful to our investors because it allows
them to more effectively 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 (loss) from
continuing operations, such as extraordinary items, discontinued
operations and the cumulative effect of accounting changes,
(ii) income taxes, (iii) interest and debt expense
(iv) distributions on preferred interests of consolidated
subsidiaries and (v) preferred stock dividends. We exclude
interest and debt expense and distributions on preferred
interests of consolidated subsidiaries from this measure so that
investors may evaluate our operating results independently from
our financing methods or capital structure. EBIT may not be
comparable to measurements used by other companies.
Additionally, EBIT should be considered in conjunction with net
income and other performance measures such as operating income
or operating cash flow.
Below is a reconciliation of our EBIT (by segment) to our
consolidated net income (loss) for each of the three years ended
December 31:
2006
2005
2004
(In millions)
Segment
Pipelines
$
1,187
$
924
$
1,059
Exploration and Production
640
696
734
Marketing
(71
)
(837
)
(539
)
Power
82
(89
)
(747
)
Field Services
—
285
84
Segment EBIT
1,838
979
591
Corporate and other
(88
)
(521
)
(217
)
Consolidated EBIT
1,750
458
374
Interest and debt expense
(1,228
)
(1,286
)
(1,497
)
Distributions on preferred
interests of consolidated subsidiaries
—
(9
)
(25
)
Income taxes
9
331
116
Income (loss) from continuing
operations
531
(506
)
(1,032
)
Discontinued operations, net of
income taxes
(56
)
(96
)
85
Cumulative effect of accounting
changes, net of income taxes
—
(4
)
—
Net income (loss)
$
475
$
(606
)
$
(947
)
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.
Pipelines
Segment
Overview
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 power, coal and fuel oil. Our
revenues from transportation, storage, LNG terminalling and
related services consist of two types:
% of Total
Type
Description
Revenues
Reservation
Reservation revenues are from
customers (referred to as firm customers) that reserve capacity
on our pipeline system, storage facilities or LNG terminalling
facilities. These firm customers are obligated to pay a monthly
reservation or demand charge, regardless of the amount of
natural gas they transport or store, for the term of their
contracts.
79
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.
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 and market conditions,
regulatory actions, competition, weather and the
creditworthiness of our customers. We also experience earnings
volatility when the amount of natural gas utilized in operations
differs from the amounts we receive for that purpose.
Historically, much of our business was conducted through
long-term contracts with customers. However, many of our
customers have shifted from a traditional dependence solely on
long-term contracts to a portfolio approach, which balances
short-term opportunities with long-term commitments. This shift,
which can increase the volatility of our revenues, is due to
changes in market conditions and competition driven by state
utility deregulation, local distribution company mergers, new
supply sources, volatility in natural gas prices, demand for
short-term capacity and new power plant markets.
We continue to manage our recontracting process to limit the
risk of significant impacts on our revenues. Our ability to
extend existing customer contracts or remarket expiring
contracted capacity is dependent on the competitive
alternatives, the regulatory environment at the federal, state
and local levels and market supply and demand factors at the
relevant dates these contracts are extended or expire. The
duration of new or renegotiated contracts will be affected by
current prices, competitive conditions and judgments concerning
future market trends and volatility. Subject to regulatory
requirements, we attempt to re-contract or re-market our
capacity at the maximum rates allowed under our tariffs,
although, at times, we discount these rates 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. We continue to manage our
recontracting process to limit the risk of significant impacts
on our revenues. The weighted average remaining contract term
for active contracts is approximately five years as of
December 31, 2006. Below is the expiration schedule for
firm transportation contracts executed as of December 31,2006:
Percent of Total
BBtu/d
Available Capacity
2007
3,450
15
2008
2,628
11
2009
1,764
8
2010
3,339
14
2011
2,171
9
2012 and beyond
10,056
43
Summary
of Operational and Financial Performance
In 2006, we continued to deliver excellent results with strong
performance across all pipelines. We successfully resolved our
EPNG rate case, restructured and renewed certain customer
contracts, continued to place several expansion projects in
service, including the Elba Island II terminal expansion
and pipeline expansions in the Rockies, such as Cheyenne Plains,
Piceance Basin, and Raton Basin, and made significant progress
on several other growth projects. We have also benefited from
(i) higher realized rates on certain of our systems,
(ii) increased throughput in 2006, (iii) other various
interruptible services, (iv) sales of gas not used in
operations and (v) favorable impacts upon revaluation of
gas imbalances. However, we continue to experience
non-reimbursable hurricane related costs.
While actual throughput levels have a relatively minor impact on
us since we generally sell capacity on our pipeline, the level
of throughput can provide evidence of the underlying value of
the capacity. In 2006, increased throughput across our system
was a result of broad based increases in power demand from
Mexico, California, the Northeast, and southeast based on
underlying growth in electricity demand, a warmer summer, 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.
In 2007, we intend to build on the growth achieved in 2006.
Among other projects currently underway, we are in the process
of filing with the FERC several growth projects that will
transport LNG from Georgia to Florida and the remainder of the
southeastern United States. See a further discussion below.
Operating
Results
2006
2005
2004
(In millions, except volume
amounts)
Operating revenues
$
2,402
$
2,171
$
2,145
Operating expenses
(1,339
)
(1,392
)
(1,218
)
Operating income
1,063
779
927
Other income
124
145
132
EBIT
$
1,187
$
924
$
1,059
Throughput volumes
(BBtu/d)(1)
TGP
4,584
4,493
4,519
EPNG and MPC
4,255
4,214
4,235
CIG, WIC and CPG
4,301
3,734
2,808
SNG
2,167
1,984
2,163
Equity investments
1,705
1,645
1,698
Total throughput
17,012
16,070
15,423
(1)
Volumes exclude intrasegment
activities.
The table below and discussion that follows detail the impact on
EBIT of significant events in 2006 compared with 2005 and 2005
as compared with 2004. We have also provided an outlook on
events that may affect our operations in the future.
2006 to 2005
2005 to 2004
Variance
Variance
Revenue
Expense
Other
EBIT
Revenue
Expense
Other
EBIT
Impact
Impact
Impact
Impact
Impact
Impact
Impact
Impact
Favorable/(Unfavorable)
(In millions)
Higher reservation and services
revenues
$
128
$
—
$
—
$
128
$
24
$
—
$
—
$
24
Gas not used in operations,
revaluations, processing revenues and other natural gas sales
20
38
—
58
(45
)
8
—
(37
)
Expansions
75
(9
)
(10
)
56
75
(28
)
(2
)
45
Hurricanes Katrina and Rita
—
(1
)
—
(1
)
(13
)
(28
)
—
(41
)
Impairment of pipeline development
projects
—
30
—
30
—
(46
)
—
(46
)
General and administrative expense
—
52
—
52
—
(42
)
—
(42
)
Higher depreciation expense
—
(19
)
—
(19
)
—
(2
)
—
(2
)
Higher pipeline integrity expense
—
(19
)
—
(19
)
—
—
—
—
Operating costs
—
(13
)
—
(13
)
—
(34
)
—
(34
)
Enron bankruptcy settlement
15
3
—
18
—
—
—
—
Sale of interest in gathering
system
—
—
(11
)
(11
)
—
—
—
—
Other(1)
(7
)
(9
)
—
(16
)
(15
)
(2
)
15
(2
)
Total impact on EBIT
$
231
$
53
$
(21
)
$
263
$
26
$
(174
)
$
13
$
(135
)
(1)
Consists of individually
insignificant items on several of our pipeline systems.
Higher Reservation and Other Services
Revenues. During the year ended December 31,2006, our reservation revenues increased primarily due to the
termination, effective December 31, 2005, of reduced tariff
rates to certain customers under the terms of EPNG’s
FERC-approved systemwide capacity allocation proceeding, an
increase in EPNG’s tariff rates which are subject to refund
and which became effective on January 1, 2006, sales of
additional firm capacity and higher realized rates on several of
our pipeline systems compared to 2005. In addition, our usage
revenues increased due to increased activity on our pipeline
systems under various interruptible services provided under
their tariffs as a result of favorable market conditions.
Gas Not Used in Operations, Revaluations, Processing Revenues
and Other Natural Gas Sales. 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 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 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 regulatory actions, some of which have already
been implemented, the efficiency of our pipeline operations,
natural gas prices and other factors.
Expansions. Below is a discussion of
(i) our FERC approved expansion projects placed in service
and (ii) other FERC approved expansion projects not yet
completed which we are in various stages of certification and
approval.
Projects Placed in Service. During 2005 and
2006, we placed several significant expansion projects in
service including Cheyenne Plains, the Elba Island LNG
expansion, the Raton Basin project and the Piceance Basin
project and related compression on our WIC system.
Projects
Not Yet Completed.
Anticipated Completion
Estimated
Project
or In-Service Date
Cost
Estimated Future Revenues
Louisiana Deepwater Link
July 2007
$
55 million
(1)
(2)
Triple-T Extension
September 2007
$
33 million
(3)
(2)
Essex Middlesex Project
November 2007
$
47 million
$1 million in 2007
$8 million annually thereafter
Northeast
ConneXion — New England
November 2007
$
103 million
$6 million in 2007
$37 million annually thereafter
Cypress
Expansion(4)
May 2007
$
321 million
$62 million annually
(1)
Estimate reflects anticipated
payment of approximately $15 million in contributions to a
third party.
(2)
Revenues for these projects will be
based on throughput levels as natural gas reserves are developed.
(3)
Amount shown is net of anticipated
the receipt of approximately $12 million in
contributions-in-aid-of
construction.
(4)
Project will consist of three
phases. The anticipated completion date is related to
phase 1.
Hurricanes Katrina and Rita. During 2006 and
2005, we recorded higher operation and maintenance expenses as a
result of unreimbursed amounts expended to repair damage caused
by Hurricanes Katrina and Rita in 2005. For a further discussion
of the impact of these hurricanes on our capital expenditures,
see Capital Resources and Liquidity below.
Impairment of Pipeline Development
Projects. During 2006 and 2005, we impaired
various pipeline development projects based on changing market
conditions. In 2006, we recorded impairments of $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, 2006, our general and
administrative costs were lower than 2005, primarily due to a
decrease in accrued benefit costs and lower allocated costs from
El Paso. During the year ended December 31, 2005, our
general and administrative costs were higher
than in 2004, primarily due to an increase in direct payroll
related benefits for our employees, higher legal and insurance
costs of, and higher corporate overhead allocations from
El Paso. El Paso’s allocation to us increased in
2005 based on the estimated level of resources devoted to our
segment’s operations and the relative size of our EBIT,
gross property and payroll as compared to the consolidated
totals.
Higher 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 the effective date of its rate case.
Pipeline Integrity Costs. As of
January 1, 2006, we adopted an accounting release issued by
the FERC that requires us to expense certain costs our
interstate pipelines incur related to their pipeline integrity
programs. Prior to adoption, we capitalized these costs as part
of our property, plant and equipment.
Operating Costs. During 2006, we incurred
higher costs primarily for repairs and maintenance. During 2005
and 2004, we incurred higher costs for compressor engine repair
and preventive maintenance, lowering of lines and pipeline
integrity testing as well as higher legal and environmental
reserves.
Enron Bankruptcy Settlement. During 2006, we
recorded income of approximately $18 million, net of
amounts potentially owed to certain customers, associated with
the receipt of settlement proceeds related to the Enron
bankruptcy. We may receive additional amounts in the future as
settlement proceeds are released by the bankruptcy court.
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 and expect to continue
operating under their existing rates. However, certain other
pipelines listed below are currently in rate proceedings or have
upcoming rate actions.
•
EPNG — EPNG negotiated a settlement of its rate case
that was filed with the FERC in December 2006. The settlement
provides benefits for both EPNG and its customers for a
three-year period ending December 31, 2008. For a further
discussion of this settlement, see Item 8, Financial
Statements and Supplementary Data, Note 13.
•
CIG — In August 2006, the FERC approved a settlement
reached with CIG’s customers effective October 1,2006. The settlement establishes system-wide base rates through
at least September 2010, but no later than September 2011, and
establishes a sharing mechanism to encourage additional fuel
savings. We anticipate an increase in revenues of approximately
$6 million annually from the effective date of the
settlement.
•
MPC — MPC is required by its previous rate case
settlement to file for new rates to be effective in
March 2007. We anticipate a rate decrease resulting from a
variety of factors, including a decline in the rate base and
various changes in rate design since the last rate case although
the amount of the impact is not yet determinable.
Our Exploration and Production segment conducts our natural gas
and oil exploration and production activities. Our operating
results in 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, shorter lived assets in our Texas Gulf Coast and Gulf of
Mexico Shelf and south Louisiana regions. We believe the
combination of our assets in these regions provides significant
near-term cash flow while providing consistent opportunities for
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 our drilling activities and through acquisitions of
assets and companies. For 2007, we expect our growth to occur
principally through drilling activities. However, we believe
strategic acquisitions can support our corporate objectives by:
•
Re-shaping our portfolio to provide greater optionality for
achieving 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 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 natural gas and oil production in 2007 to reduce
the financial impact of downward commodity price movements. We
are also actively managing increases in operating and capital
costs.
Significant
Operational Factors Affecting the Year Ended December 31,2006
Production. Our average daily production for
the year was 730 MMcfe/d (excluding 68 MMcfe/d from
our equity investment in Four Star). Our production levels grew
in every quarter of 2006. However, our average daily production
was lower than originally expected primarily due to unexpected
delays in our Gulf of Mexico Shelf and Onshore regions. Below is
a further analysis of our 2006 production by region (MMcfe/d):
2006
2005
2004
United States
Onshore
345
300
231
Texas Gulf
Coast(1)
187
211
283
Gulf of Mexico Shelf / south
Louisiana
174
179
276
International
Brazil(2)
24
53
24
Total Consolidated
730
743
814
Four Star
(3)
68
24
—
(1)
During 2006, we completed the sale
of certain non-strategic south Texas properties with production
of approximately 5 MMcfe/d. In January 2007, we acquired
certain properties with net production on the acquisition date
of approximately 12 MMcfe/d.
(2)
Production volumes decreased due to
a contractual reduction of our ownership interest in the
Pescada-Arabaiana Field in 2006.
(3)
Amounts represent our proportionate
share of the production of Four Star which was acquired in the
third quarter of 2005.
In our Onshore region, we increased our 2006 production through
our drilling programs and our acquisition of Medicine Bow in
2005 despite the impact of higher maintenance activity and
delivery delays for two rigs contracted in East Texas reducing
our expected 2006 production. In the Texas Gulf Coast, we were
able to stabilize 2006 production levels after a repositioning
effort in the region in 2004. In the Gulf of Mexico Shelf/south
Louisiana region, production in both 2005 and 2006 was adversely
affected by Hurricanes Katrina and Rita in 2005 and construction
delays on certain new wells in 2006. However, we were successful
in developing projects in the West Cameron area and our Catapult
project that helped offset natural declines. In Brazil, a
contractual reduction of our ownership interest in the
Pescada-Arabaiana fields in early 2006 resulted in a decrease in
production.
2006
Drilling Results
Onshore. We drilled 604 successful gross wells
out of 606 gross wells drilled.
Texas Gulf Coast. We experienced an
88 percent success rate on 49 gross wells drilled.
Gulf of Mexico Shelf and south Louisiana. We
experienced a 82 percent success rate on 17 gross
wells drilled. We placed 10 new wells in production,
including five wells in south Louisiana, and five wells in the
Gulf of Mexico. We expect an additional four wells drilled in
2007 to come on production in early 2007.
Brazil. In the Pinauna Field in the Camamu
Basin, we filed a plan of development, signed a rig contract and
began to drill two exploratory wells in February 2007.
Additionally, in the ES-5 Block in the Espirito Santo Basin, we
continue to discuss a possible exploration well with Petrobras.
Egypt. We were the winning bidder of the South
Mariut Block for $3 million in the second quarter of 2006
and agreed to a $22 million firm working commitment over
three years. The block is about 1.2 million acres and is
located onshore in the western part of the Nile Delta. We expect
to receive formal governmental approvals and sign the concession
agreement during the first quarter of 2007.
Cash Operating Costs. We monitor cash
operating costs to determine the amount of cash required to
produce our natural gas and oil volumes. These costs are
calculated on a per MMcfe basis and are calculated as total
operating expenses less depreciation or depletion, and
amortization expense, other non-cash expense items and the cost
of products and services on our income statement. In 2006, cash
operating costs increased to $1.86/MMcfe from $1.67/MMcfe in
2005. Our operating cost increases were primarily a result of
inflation in the cost of fuel, power, and other services,
increases in subsurface maintenance in certain Onshore fields
and unrecoverable hurricane repair costs, among other items. We
do not expect a significant amount of costs in this segment in
2007 related to Hurricanes Katrina and Rita.
Reserve Replacement Costs / Reserve Replacement
Ratio. We calculate two primary metrics,
(i) a reserve replacement ratio and (ii) a reserve
replacement cost, 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 a reserve
replacement cost 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 ratios as follows:
Reserve replacement ratio
Sum of reserve
additions(1)
Actual production for the
corresponding period
Reserve replacement cost / 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 cost
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, 2006,
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 each of the years ended December 31:
2006
2005
2004
($ / Mcfe)
Reserve replacement costs,
including acquisitions
$
4.17
$
2.75
$
21.85
Reserve replacement costs,
excluding acquisitions
4.19
3.19
N/A(1
)
(% of Production)
Reserve replacement ratio,
including acquisitions
108
%
195
%
11
%
Reserve replacement ratio,
excluding acquisitions
107
93
(10
)
(1)
Not meaningful in 2004 due to
downward revisions in previous estimates of reserves.
In 2006, our reserve replacement costs increased primarily due
to industry service cost inflation, mechanical problems incurred
in executing our drilling program, downward revisions in
previous estimates of reserves due to lower commodity prices at
December 31, 2006, and international capital investments
where proved reserves have yet to be recorded. In 2004, our
reserve replacement costs were negatively impacted by downward
revisions of previous estimates of our reserves. 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, 2006 our average reserve
replacement costs were $3.99/Mcfe including acquisitions and
$5.20/Mcfe excluding acquisitions.
Capital Expenditures. Our capital expenditures
were as follows for the three years ended December 31:
2006
2005
2004
Total oil and gas capital
costs(1)
$
1,193
$
1,462
$
743
Less: acquisition capital
(4
)
(651
)
(102
)
Capital expenditures, excluding
acquisitions
$
1,189
$
811
$
641
(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 2007
For 2007, we anticipate the following on a worldwide basis:
•
Average daily production volumes for the year of approximately
740 MMcfe/d to 795 MMcfe/d, which excludes
approximately 60 MMcfe/d to 65 MMcfe/d from our equity
investment in Four Star. Our goal is to achieve between three
and eight percent average annual production growth over the next
several years.
•
Capital expenditures, excluding acquisitions, between
$1.4 billion and $1.5 billion, which represents a
20 percent increase over 2006. While 85% of the
company’s planned 2007 capital program is allocated to its
domestic program, we plan to spend $215 million in
international capital in 2007, primarily in our Brazil
exploration and development program. In January 2007, we
acquired producing properties and undeveloped acreage in Zapata
County, Texas for $249 million which complement our
existing Texas Gulf Coast operations and provide a re-entry into
the Lobo trend. The assets acquired had net production of
approximately 12 MMcfe/d on the acquisition date. Estimated
proved reserves were approximately 84 Bcfe of which
approximately 73 percent was undeveloped.
•
Average cash operating costs which include production costs,
general and administrative expenses and other expenses of
approximately $1.68/Mcfe to $2.00/Mcfe for the year; and
•
Depreciation, depletion, and amortization rate of between
$2.50/Mcfe and $2.75/Mcfe in the first quarter of 2007 compared
with $2.58/Mcfe in the fourth quarter of 2006.
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, 2006, 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)
Volumes
Price
Volumes
Price
Volumes
Price
Volumes
Natural Gas
2007
78
$
7.70
55
$
8.00
55
$
16.89
110
2008
5
$
3.42
—
—
—
—
—
2009
5
$
3.56
—
—
—
—
—
2010-2012
11
$
3.81
—
—
—
—
—
Oil
2007
192
$
35.15
—
—
—
—
—
(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
“lock-in” locational price differences on a portion of
our natural gas production in Texas and Oklahoma.
Our natural gas fixed price swap, floor and ceiling contracts in
the table above 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. Our oil swaps and approximately 51
TBtu of our natural gas basis swaps are not designated as
hedges. Accordingly, changes in the fair value of these swaps
are not deferred, but are recognized in earnings each period.
The table above does not include (i) derivative contracts
we terminated in the fourth quarter of 2006 on which we will
record an additional $62 million of gains (before income
taxes) in 2007 which are currently deferred in accumulated other
comprehensive income or (ii) contracts entered into by our
Marketing segment as further described on page 53. For the
consolidated impact of the entirety of El Paso’s
production-related price risk management activities on our
liquidity, see the discussion of factors that could impact our
liquidity beginning on page 62.
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:
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 realized prices in 2006
$
(197
)
$
—
$
—
$
(197
)
Impact of hedges
197
—
—
197
Lower production volumes in 2006
(14
)
—
—
(14
)
Oil, Condensate and NGL
Revenue
Higher realized 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 have benefited from our acquisitions in
2005. However, overall production volumes have decreased in our
Texas Gulf Coast and Gulf of Mexico Shelf 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 Shelf 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
Field 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 Shelf 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 periods 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 EBIT for 2005 decreased $38 million as compared to
2004. The table below lists the significant variances in our
operating results in 2005 as compared to 2004:
Variance
Operating
Operating
Revenue
Expense
Other
EBIT
Favorable/(Unfavorable)
(In millions)
Natural Gas Revenue
Higher realized prices in 2005
$
362
$
—
$
—
$
362
Lower volumes in 2005
(133
)
—
—
(133
)
Impact of hedges
(237
)
—
—
(237
)
Oil, Condensate and NGL
Revenue
Higher realized prices in 2005
95
—
—
95
Lower volumes in 2005
(24
)
—
—
(24
)
Impact of hedges
(5
)
—
—
(5
)
Depreciation, Depletion and
Amortization Expense
Higher depletion rate in 2005
—
(110
)
—
(110
)
Lower production volumes in 2005
—
45
—
45
Production
Costs
Higher lease operating costs in
2005
—
(17
)
—
(17
)
Higher production taxes in 2005
—
(34
)
—
(34
)
General and Administrative
Expenses
—
(12
)
—
(12
)
Other
Earnings from investment in Four
Star
—
—
19
19
Other
(6
)
21
(2
)
13
Total Variances
$
52
$
(107
)
$
17
$
(38
)
Operating revenues. During 2005, we benefited
from a strong commodity pricing environment for natural gas and
oil, condensate and NGL. However, losses in our hedging program
for the year ended December 31, 2005 were $260 million
compared to $18 million in 2004. Additionally, we
experienced a nine percent decrease in production volumes versus
the same period in 2004. Although our production volumes
benefited from the acquisitions in 2005 and our acquisition and
consolidation of the remaining interest in UnoPaso in Brazil in
July 2004, our Texas Gulf Coast and Gulf of Mexico Shelf and
south Louisiana regions experienced declines in year over year
production due to normal declines and a lower capital spending
program in these areas over the last several years. In addition,
the Gulf of Mexico Shelf and south Louisiana region was impacted
by Hurricanes Katrina and Rita, while the Texas Gulf Coast
region was impacted by mechanical well failures.
Depreciation, depletion and amortization
expense. During 2005, we experienced higher
depletion rates compared to 2004 as a result of higher finding
and development costs and the cost of acquired reserves
resulting in higher depreciation, depletion and amortization
expense. However, during 2005, the impact of lower production
volumes partially offset the impact of our higher depletion
rates.
Production costs. We experienced higher costs
in 2005 due to the implementation of programs in the first half
of 2005 to improve production in the Texas Gulf Coast and Gulf
of Mexico Shelf and south Louisiana regions, higher salt water
disposal costs, utility expenses, marine transportation costs
and increased operating costs in Brazil due to our July 2004
UnoPaso acquisition and consolidation. Production taxes were
also higher as the result of higher commodity prices in 2005 and
higher tax credits taken in 2004 on high cost natural gas wells.
General and administrative expenses. Our
general and administrative expenses were higher in 2005 than in
2004, primarily due to an increase in direct payroll related
benefits for our employees, and higher legal and insurance costs.
Our 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 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 historical 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 summary of these
events, our remaining contracts and their sensitivity to changes
in commodity prices.
Production-related natural gas and
oil derivatives
Option contracts with various
floor and ceiling prices
Terminated our 2007 natural gas
collars and replaced them with natural gas puts in November
2006. Our collars significantly impacted our results in 2006 due
to changes in natural gas prices and our new puts may have an
impact in the future if volatility continues.
Sold, terminated or entered into
offsetting derivative transactions in 2006 to substantially
eliminate the price risk associated with a significant number of
contracts, which reduces our future earnings exposure to changes
in natural gas prices.
Released or assigned capacity
related to Alliance, TGP and a pipeline serving California,
which should significantly reduce our exposure to future losses.
Low
Long-term gas supply obligations
Primarily ten contracts with
delivery obligations up to 0.7 Bcf/d with expiration dates
ranging from 2008 to 2028.
The majority of our supply
contracts are index-priced.
Overview. Over the past three years, our
operating results and
year-to-year
comparability were significantly impacted by substantial
commodity price fluctuations and changes in the composition of
our portfolio based on actions taken to reduce our exposure to
these commodity price fluctuations and to exit historical
trading activities. In 2004 and 2005, rising natural gas prices
had a significant negative impact on our natural gas and power
derivative contracts resulting in significant losses in those
years. During the past two years, we entered into transactions
to reduce our exposure to commodity prices, including the
divestitures of our Cordova tolling agreement and a majority of
the contracts in our power portfolio in 2005, and the
divestiture of a significant portion of our natural gas
portfolio in 2006. In 2006, we also recorded losses of
$188 million upon paying a third party to assume our
Alliance transportation capacity obligations effective
November 1, 2007, and approximately $133 million in
the third quarter of 2006 on our Midland Cogeneration Venture
(MCV) supply agreement in conjunction with the sale of our
interest in the related power facility. The combination of
actions taken to reduce our exposure and decreases in natural
gas prices improved our operating results in 2006. The tables
below and discussions that follow provide further information
about of 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:
Amount for 2006 includes a
$188 million loss in operating revenues related to Alliance
further discussed below and a $50 million gain in 2004
related to early termination of an LNG contract.
(2)
Amounts for 2006 include the loss
on our MCV contract described above.
(3)
Gross margin consists of revenues
from commodity trading and origination activities less costs of
commodities sold, including changes in the fair value of
derivative contracts.
(4)
In 2006 and 2005, we incurred lower
corporate overhead allocation and general and administrative
expenses based on overall cost reduction efforts at the
corporate level and our reduced level of operations. In 2005, we
recorded $19 million of legal settlements and reserves,
which resulted in increased operating expenses during 2005.
Production-related
Natural Gas and Oil Derivatives
Options and swaps. 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 in addition to those derivative contracts entered
into by our Exploration and Production segment which are
further discussed beginning on page 40. For the
consolidated impact of all of El Paso’s
production-related price risk management activities, refer to
our liquidity discussion beginning on page 52.
As of December 31, 2006, our production-related derivatives
consisted of various option contracts as all of our swap
contracts had expired. 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, 2006:
Floors(1)
Ceilings(1)
Average
Average
Volumes
Price
Volumes
Price
Natural Gas
2007
89
$
7.50
—
$
—
2008
18
$
6.00
18
$
10.00
2009
17
$
6.00
17
$
8.75
Oil
2007
1,009
$
55.00
1,009
$
60.38
2008
930
$
55.00
930
$
57.03
(1)
Volumes presented are TBtu for natural gas and MBbl for
oil. Prices presented are per MMBtu of natural gas and per Bbl
of oil.
During 2006, decreases in commodity prices favorably impacted
the value of our contracts and our EBIT and in 2005, increases
in commodity prices negatively impacted the value of our
contracts and our EBIT. We received approximately
$59 million in 2006 and paid $40 million in 2005
related to contracts that settled during those periods.
During the fourth quarter of 2006, we entered into put contracts
on 89 TBtu of natural gas production in 2007 at a floor price of
$7.50 per MMbtu for which we paid a premium of
$82 million. The premium paid was largely offset by funds
received by our Exploration and Production segment during 2006
upon the termination of 75 TBtu of collars on 2007 natural gas
production. If natural gas and oil prices remain above the floor
prices of our option contracts, our option contracts will expire
without any value and we will expense the premium paid. If
natural gas and oil prices increase above the ceiling prices of
our option contracts, losses will occur since we are obligated
under these contracts to provide natural gas and oil at fixed
prices that are lower than the market price.
Other production-related derivatives. In 2004,
our losses were a result of increases in natural gas prices
relative to fixed priced commodity contracts held at the time.
In the fourth quarter of 2004, we designated those contracts as
accounting hedges and transferred them to our Exploration and
Production segment which reflects those contracts in its
financial results.
Contracts
Related to Historical Trading Operations
Natural gas transportation-related
contracts. As of December 31, 2006, our
transportation contracts provide us with approximately
0.8 Bcf/d of pipeline capacity that require us to pay
approximately $115 million in demand charges in 2007. In
December 2006, we paid a third party $188 million to assume
our obligations under our Alliance capacity contract beginning
November 1, 2007, which will reduce our demand charges to
an average of approximately $46 million annually from 2008
to 2011. 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. These transportation
contracts are accounted for on an accrual basis and impact our
gross margin as delivery or service under the contracts occurs.
The following table is a
summary of our demand charges (in millions) and our percentage
of recovery of these charges for each of the three years ended
December 31:
2006
2005
2004
Alliance:
Demand
charges(1)
$
64
$
65
$
61
Recovery
59
%
93
%
72
%
Enterprise Texas:
Demand charges
$
12
$
26
$
27
Recovery
—
%(2)
8
%
2
%
Other:
Demand
charges(3)
$
49
$
65
$
63
Recovery
92
%
94
%
38
%
(1)
In 2006, excluded from this amount
is the $188 million we paid in conjunction with the sale of
this contract described above.
(2)
In 2006, we were unable to recover
demand charges and incurred $4 million of losses in excess
of the demand charges related to managing the capacity under
these contracts.
(3)
Includes demand charges related to
storage contracts of $1 million, $1 million and
$2 million in 2006, 2005, and 2004.
Other natural gas derivative contracts. In
addition to our transportation-related natural gas contracts, we
have other contracts with third parties that require us to
purchase or deliver natural gas primarily at market prices. Our
exposure to the volatility of gas prices as it relates to our
other natural gas derivative contracts varies from period to
period based on whether we purchase more or less natural gas
than we sell under these contracts. Because we had the right to
purchase more natural gas at fixed prices than we had the
obligation to sell under these contracts and because natural gas
prices increased during 2004, and 2005, the fair value of these
contracts increased. However, natural gas prices decreased
during 2006 resulting in a decrease in fair value of these
contracts. As noted above, during 2006, we divested or entered
into transactions to divest of a substantial portion of these
natural gas contracts, which substantially eliminated our future
cash and earnings exposure to price movements on these contracts.
Our EBIT during 2006 also was impacted by a $49 million
gain associated with the assignment of contracts to supply
natural gas to certain municipalities in Florida and a
mark-to-market
loss in the third quarter of approximately $133 million on
natural gas supply contracts associated with the sale by our
Power segment of its interest in the MCV power plant. Prior
to the sale, we had not recognized the cumulative
mark-to-market
losses on these contracts to the extent of our ownership
interest due to their affiliated nature.
Power Contracts. By the end of 2005, we had
divested or entered into transactions to divest of a substantial
portion of our power contracts, including our Cordova tolling
agreement, which substantially eliminated our cash and earnings
exposure to power price movements on these contracts. Prior to
entering into these transactions to eliminate the price risk
associated with our historical positions, 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.
Our remaining exposure in our power portfolio is related to four
contracts that require us to swap locational differences in
power prices between several 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. We do not have commodity risk associated with these
contracts due to positions we put in place in 2005 and 2006 to
eliminate that risk. During 2006, the fair value of these
contracts increased as the locational difference in power prices
between the PJM east and west regions decreased.
Other. During 2005, a bankruptcy court entered
an order allowing Mohawk River Funding III’s
(MRF III) bankruptcy claims with USGen New England. We
received payment on these claims and recognized a gain of
$17 million in 2005 related to this settlement. During
2004, we recorded a $25 million gain related to the
termination of a power contract with our Power segment, which
was eliminated in El Paso’s consolidated results.
Overview. Our Power segment consists of assets
in Brazil, Asia and Central America. We continue to pursue the
sales of our remaining power investments, including our interest
in the Porto Velho facility in Brazil. As of December 31,2006, our remaining investment, guarantees and letters of credit
related to power projects in this segment totaled approximately
$660 million, which consisted of approximately
$618 million in equity investments and notes receivable and
approximately $42 million in financial guarantees and
letters of credit.
Prior to 2006, our financial results in this segment were
significantly impacted by impairment losses, net of gains
(losses) on the sales of our domestic restructured power
contracts and power facilities. In 2004, we recorded significant
impairment charges based on our decision to exit our domestic
and international power operations including approximately
$590 million related to restructured power contracts and
domestic power facilities and approximately $365 million
related to our international power facilities. In 2005, we
recorded additional impairments, net of gains and losses on
sale, related to our Asian and Central American power facilities
as well as losses on MCV. 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:
2006
2005
2004
(In millions)
EBIT by Area:
Brazil
Impairment of Manaus and Rio Negro
$
—
$
—
$
(183
)
EBIT from operations
64
55
64
Other International
Power
Impairments related to anticipated
sales
(13
)
(176
)
(182
)
Gain on sale of KIECO, PPN and
Chinese plants
1
131
—
EBIT from
operations(1)
(1
)
34
64
Domestic Power
Impairments, net of gains (losses)
on sales
10
(167
)
(590
)
Favorable resolution of bankruptcy
claim
—
53
—
EBIT from operations
—
—
133
Gain on sale of
available-for-sale
investment
(2)
47
40
—
Other(3)
(26
)
(59
)
(53
)
EBIT
$
82
$
(89
)
$
(747
)
(1)
EBIT from operations includes a
$17 million dividend on investment fund recorded in 2005.
(2)
With the disposition of our shares
in 2005 and 2006, we no longer have an interest in International
Commodity Exchange.
(3)
Other consists of indirect expenses
and general and administrative costs. Also includes impairments
and losses on the sales of power turbines of $27 million
and $1 million recorded in 2005 and 2004.
Brazil. As of December 31, 2006, our
remaining investment, guarantees and letters of credit related
to power projects in Brazil were approximately
$555 million. Of this amount, approximately
$315 million relates to our Porto Velho project that sells
power to Eletronorte under two power sales agreements that
expire in 2010 and 2023. Eletronorte has expressed an interest
in acquiring our interest in this power plant. As we evaluate
this potential opportunity, we could be required to record a
loss based on the potential value we may receive if we sell the
facility. During 2006, 2005, and 2004, EBIT from our Porto Velho
operations was $41 million, $23 million, and
$28 million.
The remainder of our exposure in Brazil relates primarily to our
Manaus and Rio Negro power plants, and our interests in the
Bolivia-to-Brazil
and
Argentina-to-Chile
pipelines (see further description in Part I, Item 1,
Business, and Part II, Item 8, Financial Statements
and Supplementary data, Note 18). In 2004, based on new
power contracts that were signed in January 2005, we impaired
our Manaus and Rio Negro facilities. These new contracts
resulted in a decrease in earnings from these projects and, in
addition, provide for the transfer of these facilities to the
power off-taker in early 2008. The Manaus and Rio Negro plants
had earnings from plant operations in 2006,
2005, and 2004 of $17 million, $19 million and
$30 million. Our other Brazilian operations (including our
interests in the
Bolivia-to-Brazil
and
Argentina-to-Chile
pipelines) generated EBIT of $6 million, $13 million,
and $6 million in 2006, 2005 and 2004.
Other International Power. As of
December 31, 2006, we had remaining investments, guarantees
and letters of credit of approximately $105 million related
to power projects in Asia and Central America. We expect to
complete the sale of substantially all of these remaining
international power assets during the first half of 2007, but
any changes in regional political and economic conditions could
negatively impact the anticipated proceeds, which could result
in additional impairments. As noted above, we recorded
impairments and gains on sales during 2004 and 2005 based on the
value received or expected to be received upon closing the sales
of our Asian and Central American assets. Our results during
this period were also negatively impacted by the reduction in
earnings as each facility was sold and by our decision to not
recognize earnings from certain of our Asian and Central
American assets based on our inability to realize those earnings
through their expected selling price. We did not recognize
earnings of approximately $26 million and $30 million
for the years ended 2006 and 2005.
Domestic Power. Upon closing the sales of the
MCV, Capitol District Energy Center Cogeneration
Association(CDECCA) and Berkshire facilities in 2006, we
completed the disposition of our domestic power business which
we began in 2003. We recorded a gain of approximately
$13 million upon the sale of MCV and recorded a
$3 million loss on the sale of our CDECCA and Berkshire
facilities. The disposition of our MCV facility in 2006 also
impacted certain contracts and the financial results in our
Marketing segment. As noted above, during 2004 and 2005 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 impairments on our
investment in MCV in 2004 based on a decline in its value due to
increased fuel costs and recorded our proportionate share of
MCV’s losses based on their impairment of the plant assets
in 2005.
During 2004 and 2005, the divestiture of the assets and
operations of this segment resulted in significant gains and
losses in our operating results. Prior to sale of these assets,
we generated earnings primarily from our general and limited
partner interests in GulfTerra and Enterprise Products Partners
and from gathering and processing assets in south Texas and
south Louisiana. The sales of these assets are further described
in Part II, Item 8, Financial Statements and
Supplementary Data, Note 18. The tables below and
discussion that follows provide the operating results and
additional analysis of significant factors affecting EBIT for
our Field Services segment for each of the years ended
December 31:
2005
2004
(In millions)
Gathering and processing gross
margins(1)
$
25
$
93
Operating expenses
Loss on long-lived assets
(10
)
(507
)
Other operating expenses
(31
)
(87
)
Operating loss
(16
)
(501
)
Earnings from unconsolidated
affiliates
301
618
Other expense
—
(33
)
EBIT
$
285
$
84
2005
2004
(In millions)
Gathering and Processing
Activities
Gathering and processing margins
$
25
$
93
Operating expenses
(8
)
(87
)
Other income
7
11
EBIT
24
17
GulfTerra/Enterprise-related
Items
Assets/interests sold to Gulf
Terra and Enterprise
Sale of GP/LP interests
183
507
Goodwill impairment
—
(480
)
Other
4
(47
)
Equity earnings
—
100
EBIT
187
80
Other Asset Sales
Sale of Javelina investment
111
—
Other
(37
)
(13
)
74
(13
)
EBIT
$
285
$
84
(1)
Gross margins consist of operating
revenues less cost of products sold. We believe that this
measurement is more meaningful for understanding and analyzing
our Field Services segment’s operating results in 2005 and
2004 because commodity costs historically were a significant
factor in the determination of profit from our midstream
activities.
Gathering and Processing Activities. The decreases
in our gross margin in 2005 and in operation and maintenance
expenses were primarily a result of asset sales, including the
sales of our south Texas, north and south Louisiana,
mid-continent and Indian Springs gathering and processing plants.
GulfTerra/Enterprise Related Items. Prior to
2006, we sold a number of assets to GulfTerra. While these sales
decreased our gross margin and operating expenses, they
increased the equity earnings from our general and limited
partner interests in GulfTerra. However, over time, our overall
equity earnings in GulfTerra declined as we sold our interests
in that investment. The effect of significant transactions
related to GulfTerra during 2005 and 2004 were as follows:
•
Gain of $507 million upon the sale of our remaining
50 percent interest in the general partner of GulfTerra to
Enterprise in 2004. As a result of this sale, we also impaired
goodwill recorded on the segment; and
•
Gain of $183 million on the sale of our remaining general
partner and limited partner interests in Enterprise in 2005.
Corporate
and Other Expenses, Net
Our corporate activities include our general and administrative
functions as well as a number of miscellaneous businesses, which
do not qualify as operating segments and are not material to our
current year results. The following is a summary of significant
items impacting the EBIT in our corporate operations for each of
the three years ended December 31:
2006
2005
2004
(In millions)
Change in litigation, insurance
and other reserves
$
(65
)
$
(418
)
$
(81
)
Western Energy Settlement
—
(72
)
(38
)
Restructuring charges
—
(27
)
(91
)
Debt related gains (losses):
Foreign currency fluctuations on
Euro-denominated debt
(20
)
36
(26
)
Early extinguishment/exchange of
debt
(26
)
(29
)
(18
)
Other
23
(11
)
37
Total EBIT
$
(88
)
$
(521
)
$
(217
)
Litigation, Insurance, and Other Reserves. We
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 or unfavorable
settlements against us related to these matters have impacted
and may further impact our future results. In 2005 and 2004, we
recorded significant charges in operation and maintenance
expense to increase our litigation, insurance and other reserves
based on ongoing assessments, developments and evaluations of
the possible outcomes of these matters. In 2005, the most
significant item was a charge in connection with a ruling by an
appellate court that we indemnify a former subsidiary for
certain payments being made under a retiree benefit plan.
Additionally, we incurred charges in 2005 with the final
prepayment of the Western Energy Settlement and charges related
to increased premiums from a mutual insurance company in which
we participate, based primarily on the impact of several
hurricanes in 2004 and 2005. In 2004, we also incurred charges
associated with the Western Energy Settlement obligation and
charges related to our decision to withdraw from another mutual
insurance company in which we were a member.
Restructuring Charges. As further discussed in
Part II, Item 8, Financial Statements and
Supplementary Data, Note 13, we consolidated our
Houston-based operations into one location and during 2005 and
2004 recorded charges of $27 million and $80 million
related to vacating the remaining leased space and signing a
termination agreement on the lease.
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 12, for a further discussion.
In 2006 and 2005, our overall effective tax rate on continuing
operations was significantly different than the statutory rate
due primarily to recording $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.
In 2004, our overall effective tax rate on continuing operations
was significantly different than the statutory rate due
primarily to sales of GulfTerra investment and impairments of
certain of our foreign investments. The sale of GulfTerra
resulted in a significant net taxable gain (compared to a lower
book gain) and thus significant tax expense due to the
non-deductibility of goodwill written off as a result of that
transaction. Additionally, we received no U.S federal income tax
benefit on the impairment of certain of our foreign investments.
For a discussion of our effective tax rates and other tax
matters, see Part II, Item 8, Financial Statements and
Supplementary Data, Note 5.
Discontinued
Operations
Our discontinued operations include our ANR pipeline and related
assets, our gathering and processing operations in south
Louisiana, certain international power operations, petroleum
markets operations and international natural gas and oil
production operations outside of Brazil and Egypt. 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. In February 2007, we sold these assets
and expect to recognize an after-tax gain of approximately
$0.7 billion in the first quarter of 2007.
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. The
impairments of our international power assets and the gain on
the sale of south Louisiana are further discussed in
Part II, Item 8, Financial Statements and
Supplementary Data, Note 2.
Our 2004 income from discontinued operations of $85 million
was related primarily to operations of ANR and related assets
and international power partially offset by other operational
costs.
For a further discussion of our commitments and contingencies,
see Part II, Item 8, Financial Statements and
Supplementary Data, Note 13.
Capital
Resources and Liquidity
Debt Obligations. During 2006, we continued to
reduce our overall debt obligations using cash on hand, cash
generated from operations, proceeds from asset sales and
proceeds from the issuance of common stock. We also restructured
our $3 billion credit agreement. These actions have allowed
us to reduce our debt obligations to $14.7 billion
(excluding discontinued operations) as of December 31,2006. In February 2007, we sold ANR, our Michigan storage assets
and our 50 percent interest in Great Lakes Gas Transmission
to TransCanada and TC Pipelines, LP for approximately
$4.1 billion, including the assumption of approximately
$475 million of debt assumed by the buyer. The sale of ANR
provides approximately $3.3 billion for additional debt
reductions. Following the completion of the sale, we offered to
tender certain of our outstanding debt. For a further discussion
of our debt obligations, see Part II, Item 8,
Financial Statements and Supplementary Data, Note 12.
Available Liquidity. As of December 31,2006, we had available liquidity as follows (in billions):
Over the past few years, we have simplified our capital
structure and our businesses and reduced the amount of liquidity
needed for the normal course of business. However, we could be
required to increase our available liquidity based on certain
factors described below.
Expected 2007 Cash Flows. As noted above, we
will repay a significant amount of debt using the proceeds from
the sale of ANR. We also expect to generate positive operating
cash flows in 2007 which, when supplemented with expected
proceeds from other remaining asset sales will be used for
working capital requirements and to grow and maintain our
businesses through capital expenditures. We currently anticipate
the following capital spending (in billions):
Exploration and
Pipelines
Production(1)
Total
Maintenance
$
0.4
$
1.2
$
1.6
Growth
0.6
0.5
1.1
$
1.0
$
1.7
$
2.7
(1)
Includes approximately
$250 million spent in January 2007 for the acquisition of
natural gas and oil properties.
As of December 31, 2006, our 2007 contractual debt
maturities were approximately $0.8 billion. In the first
half of 2007, we also have approximately $0.6 billion of
debt that the holders can require us to redeem. Subsequent to
year end, the holders of $300 million of these obligations
did not exercise their redemption right and this debt will
mature in 2027. Additionally, we have offered to tender certain
of our debt obligations. To the extent necessary, we may also
use cash on hand, cash flow generated from our operations,
borrowings under our revolvers or new financing transactions for
additional debt retirement.
Significant
Factors That Could Impact Our Liquidity.
Cash Margining Requirements on Derivative
Contracts. Historically we have been required to
post significant cash margin deposits and letters of credit with
the counterparties for the value of a substantial portion of our
natural gas fixed price swap contracts that were at prices below
current market prices. During 2006, approximately
$0.9 billion of posted cash margin deposits were returned
to us resulting from a combination of decreases in commodity
prices and settlement of certain of these contracts and
assignment of contracts in our power portfolio. As a result, a
substantial portion of our remaining margin consists of letters
of credit. In 2007, based on
current prices, we expect approximately $0.2 billion of the
total of $1.1 billion in collateral outstanding at
December 31, 2006 to be returned to us in the form of both
cash margin deposits and letters of credit.
If commodity prices increase, we could be required to post
additional margin, and if prices decrease, we will be entitled
to recover some of this amount earlier than anticipated. Based
on our derivative positions at December 31, 2006, a
$0.10/MMBtu increase in the price of natural gas would result in
an increase in our margin requirements of approximately
$11 million, which consists of $3 million for
transactions that settle in 2007, $5 million for
transactions that settle in 2008 and $3 million for
transactions that settle in 2009 and thereafter. To mitigate any
potential margin requirements should natural gas prices increase
to a level greater than we currently anticipate, we entered into
a $250 million unsecured contingent letter of credit
facility in January 2007 that matures in March 2008 under which
letters of credit are available to us if the average NYMEX gas
price strip for the remaining calendar months through March 2008
reaches $11.75 per MMBtu.
Hurricanes. We continue to repair damages to
our pipeline, exploration and production, and other related
facilities caused by Hurricanes Katrina and Rita in 2005. We
currently estimate the total repair costs will be approximately
$625 million. Our mutual insurance company has indicated
that we will not receive insurance recoveries of some of the
amounts due to exceeding aggregate loss limits per event. We
expect the remaining repair costs to be incurred in 2007 and the
insurance reimbursements to be received in 2007 and 2008. While
we do not believe the unrecovered costs will materially impact
our overall liquidity or financial results, the timing between
expenditures and reimbursements may impact our liquidity from
period to period. The table below provides further detail on
what we have spent to date, our estimated remaining costs, and
insurance recoveries (in millions).
Recoverable
Unrecoverable
Costs
Costs(1)
Total
Cumulative costs through 2006
$
190
$
265
$
455
Estimated remaining costs
75
95
170
Total costs
265
$
360
$
625
Less: Reimbursements to date
(55
)
Expected future reimbursements
$
210
(1)
Includes capital expenditures of
approximately $275 million.
Our mutual insurance company has also indicated that effective
June 1, 2006, the aggregate loss limits on future events
has been reduced to $500 million from $1 billion,
which could further limit our recoveries on future hurricanes or
other insurable events.
Price Risk Management Activities. Our
Exploration and Production and Marketing segments enter into
derivative contracts to provide price protection on a portion of
our anticipated natural gas and oil production. During 2006, we
entered into additional derivative contracts related to a
significant portion of our 2007 natural gas production. The
following table shows as of December 31, 2006, the
contracted volumes and the minimum, maximum and average cash
prices that we will receive under these contracts when combined
with the sale of the underlying production. 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)
Volumes
Price
Volumes
Price
Volumes
Price
Volumes
Natural Gas
2007
78
$
7.70
144
$
7.69
55
$
16.89
110
2008
5
$
3.42
18
$
6.00
18
$
10.00
—
2009
5
$
3.56
17
$
6.00
17
$
8.75
—
2010-2012
11
$
3.81
—
—
—
—
—
Oil
2007
192
$
35.15
1,009
$
55.00
1,009
$
60.38
—
2008
—
—
930
$
55.00
930
$
57.03
—
(1)
Volumes presented are TBtu for
natural gas and MBbl for oil. Prices presented are per MMBtu of
natural gas and per Bbl of oil.
(2)
Our basis swaps effectively
“lock-in” locational price differences on a portion of
our natural gas production in Texas and Oklahoma.
Net proceeds from the sale of
assets and investments
$
0.7
$
1.4
Other
0.2
0.2
0.9
1.6
Continuing financing
activities
Net proceeds from the issuance of
long-term debt
0.4
1.6
Proceeds from issuance of common
and preferred stock
0.5
0.7
Contribution from discontinued
operations(1)
0.2
0.7
1.1
3.0
Total other cash inflows
$
2.0
$
4.6
Cash Outflows
Continuing investing
activities
Capital expenditures
$
2.2
$
1.6
Net cash paid for acquisition
—
1.0
2.2
2.6
Continuing financing
activities
Payments to retire long-term debt
and redeem preferred interests
3.0
1.5
Redemption of preferred stock of a
subsidiary
—
0.3
Dividends and other
0.2
0.2
3.2
2.0
Total other cash outflows
$
5.4
$
4.6
Net change in cash
$
(1.6
)
$
—
(1)
Amounts contributed from
discontinued operations above are net of approximately
$0.2 billion of debt repayments associated with the Macae
power facility.
In 2006, we continued to expand our core pipeline and
exploration and production businesses and reduce our debt
obligations. During 2006 we generated positive operating cash
flow of approximately $1.8 billion, primarily a result of
cash provided by our pipeline and exploration and production
operations, $0.4 billion received from the settlement of
derivative contracts, and the return of approximately
$0.9 billion of broker margins related to our derivative
contracts. We utilized this operating cash flow, along with
proceeds from asset sales and the issuance of long-term debt and
common stock, as well as available cash to (i) fund both
maintenance and growth projects of
approximately $1.0 billion in our pipeline operations and
$1.1 billion in our exploration and production operations
and (ii) repay debt. As noted above, our ability to utilize
cash on hand for debt repayment was based on maintaining lower
levels of cash and available liquidity in the ordinary course of
business due to the simplification of our business and capital
structure.
Off-Balance
Sheet Arrangements
In the course of our business activities, we enter into a
variety of financing arrangements and contractual obligations.
Certain of these arrangements are often referred to as
off-balance sheet arrangements and include guarantees, letters
of credit and other interests in variable interest entities.
Guarantees
We are involved in various joint ventures and other ownership
arrangements that sometimes require additional financial support
that results in the issuance of financial and performance
guarantees. In a financial guarantee, we are obligated to make
payments if the guaranteed party fails to make payments under,
or violates the terms of, the financial arrangement. In a
performance guarantee, we provide assurance that the guaranteed
party will execute on the terms of the contract. If they do not,
we are required to perform on their behalf. For example, if the
guaranteed party is required to purchase services from a third
party and then fails to do so, we would be required to either
purchase these services or make payments to the third party to
compensate them for any losses they incurred because of this
non-performance. We also periodically provide indemnification
arrangements related to assets or businesses we have sold. These
arrangements include, but are not limited to, indemnifications
for income taxes, the resolution of existing disputes,
environmental matters and necessary expenditures to ensure the
safety and integrity of the assets sold.
We record accruals for our guaranty and indemnification
arrangements at their fair value when they are issued and
subsequently adjust those accruals when we believe it is both
probable that we will have to pay amounts under the arrangements
and those amounts can be estimated. As of December 31,2006, we had a liability of $71 million related to
guarantees and indemnification arrangements. These arrangements
had a total stated exposure of $376 million, for which we
are indemnified by third parties for $18 million. These
amounts exclude guarantees for which we have issued related
letters of credit discussed below. Included in the above stated
value of $376 million is approximately $120 million
associated with tax matters, related interest, and other
indemnifications arising out of the sale of our Macae power
facility in 2006.
In addition to the exposures described above, we received a
ruling from a trial court, which was upheld on appeal, that we
are required to indemnify a third party for benefits paid to a
closed group of retirees of one of our former subsidiaries. We
have a liability of approximately $379 million associated
with our estimated exposure under this matter as of
December 31, 2006. For a further discussion of this matter,
see Part II, Item 8 Financial Statements and
Supplementary Data, Notes 13 and 14.
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, 2006, we had
outstanding letters of credit of approximately
$1.4 billion, including $1.1 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, 2006, we do not consolidate
seven 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 18, Investments in,
Earnings from and Transactions with Unconsolidated Affiliates.
Contractual
Obligations
We are party to various contractual obligations, which include
the off-balance sheet arrangements described above. A portion of
these obligations are reflected in our financial statements,
such as 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 and 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, 2006, 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
$
1,360
$
2,225
$
2,559
$
8,616
$
14,760
Interest
1,090
1,997
1,608
9,035
13,730
Liabilities from commodity-based
derivative contracts
278
435
263
226
1,202
Other contractual liabilities
70
44
27
35
176
Operating leases
66
17
4
11
98
Other contractual commitments and
purchase obligations:
Transportation and storage
98
81
68
153
400
Other
424
66
24
26
540
Total contractual obligations
$
3,386
$
4,865
$
4,553
$
18,102
$
30,906
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 12.
Excluded from the amounts in the table above are
$744 million of principal and $703 million of interest
related to ANR which is reported in discontinued operations.
Liabilities from Commodity-Based Derivative
Contracts. These amounts only include the fair
value of our price risk management liabilities. The fair value
of our price risk management assets of $807 million as of
December 31, 2006 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 of $144 million for the four year period ended
December 31, 2010, because these expected contributions are
not contractually required. 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 31,2006.
Operating Leases. For a further discussion of
these obligations, see Part II, Item 8 Financial
Statements and Supplementary Data, Note 13.
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 liabilities are not contractually fixed
as to timing and amount. We have excluded from these amounts
contractual commitments of $223 million related to ANR
which is reported in discontinued operations.
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 collars 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 31,2006:
Maturity
Maturity
Maturity
Maturity
Maturity
Total
Less Than
1 to 3
4 to 5
6 to 10
Beyond
Fair
1 Year
Years
Years
Years
10 Years
Value
(In millions)
Derivatives designated as
hedges(1)
Assets
$
144
$
—
$
—
$
—
$
—
$
144
Liabilities
(17
)
(36
)
(25
)
(5
)
—
(83
)
Total derivatives designated as
hedges
127
(36
)
(25
)
(5
)
—
61
Other commodity-based derivatives
Exchange-traded
positions(1)
Assets
128
208
17
—
—
353
Non-exchange traded positions
Assets
162
66
40
34
8
310
Liabilities
(261
)
(399
)
(238
)
(215
)
(6
)
(1,119
)
Total other commodity-based
derivatives
29
(125
)
(181
)
(181
)
2
(456
)
Total commodity-based derivatives
$
156
$
(161
)
$
(206
)
$
(186
)
$
2
$
(395
)
(1)
These positions are traded on
active exchanges such as the New York Mercantile Exchange, the
International Petroleum Exchange and the London Clearinghouse.
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 2005, we entered
into an agreement to assign the majority of our power derivative
assets to Morgan Stanley and received total proceeds of
$442 million. 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 2005 and 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.
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. 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 NGLs which geological
and engineering data demonstrate, with reasonable certainty, to
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
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, prepares an
independent estimate of a significant portion of our proved
reserves. As of December 31, 2006, of our total proved
reserves, 29 percent were undeveloped and 11 percent
were developed, but non-producing. In addition, the data for a
given field may also change substantially over time as a result
of numerous factors, including additional development activity,
evolving production history and a continual reassessment of the
viability of production under changing economic conditions. As a
result, material revisions to existing reserve estimates occur
from time to time. In addition, the subjective decisions and
variances in available data for various fields 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 drill 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 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 2006
and 2005 and recorded ceiling test charges of $35 million
during 2004.
The ceiling test calculation assumes that the price in effect on
the last day of the quarter is held constant over the life of
the reserves, even though actual prices of natural gas and oil
are volatile and change from period to period. A decline in
commodity prices can impact the results of our ceiling test and
may result in a write-down. A decrease in commodity prices of
10 percent from the price levels at December 31, 2006
would not have resulted in a ceiling test charge in 2006.
Accounting for Legal and Environmental
Reserves. We accrue legal and environmental
reserves when our assessments indicate that it is probable that
a liability has been incurred or an asset will not be recovered
and an amount can be reasonably estimated. Estimates of our
liabilities are based on our evaluation of potential outcomes,
currently available facts, and in the case of environmental
reserves, existing technology and presently enacted laws and
regulations taking into consideration the likely effects of
societal and economic factors, estimates of associated onsite,
offsite and groundwater technical studies and legal costs.
Actual results may differ from our estimates, and our estimates
can be, and often are, revised in the future, either negatively
or positively, depending upon actual outcomes or changes in
expectations based on the facts surrounding each matter.
As of December 31, 2006, we had accrued approximately
$548 million for legal matters, which includes
approximately $379 million associated with an indemnity for
certain retiree benefit payments, which is further discussed
below. We have accrued $314 million for environmental
matters. Our environmental estimates range from approximately
$314 million to approximately $532 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
($27 million). Second, where the most likely outcome cannot
be estimated, a range of costs is established ($287 million
to $505 million) and the lower end of the expected range
has been accrued.
Accounting for Pension and Other Postretirement
Benefits. During the fourth quarter of 2006, we
adopted the 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 this
standard, 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, 2006, our combined
pension plans were over funded by $228 million and our
combined other postretirement benefit plans were under funded by
$209 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 compare our discount rates based on
the average expected timing of our pension and other
postretirement obligations to the maturity profiles of the
Moody’s Corporate Bond Indices and the Citigroup Pension
Discount Curve. Based on these comparisons, we select discount
rates that appropriately reflect the yields included in these
market sources adjusted for the estimated timing of our
obligations.
Actual results may differ from the assumptions included in these
calculations, and as a result, our estimates associated with our
pension and other postretirement benefits can be, and often are,
revised in the future. The income statement impact of the
changes in the assumptions on our related benefit obligations,
along with changes to the plans and other items, are deferred in
accumulated other comprehensive income and amortized into income
over either the period of expected future service of active
participants, or over the lives of the plan participants. The
cumulative amount deferred in accumulated other comprehensive
loss as of December 31, 2006 was approximately
$435 million, net of income taxes. 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, 2006 (in millions):
Pension Benefits
Other Postretirement Benefits
Change in
Change in Net
Net Asset
Liability and Pretax
and Pretax
Accumulated Other
Net Benefit
Accumulated Other
Net Benefit
Comprehensive
Expense (Income)
Comprehensive Loss
Expense (Income)
Income
One percent increase in:
Discount rates
$
(12
)
$
(195
)
$
—
$
(38
)
Expected return on plan assets
(22
)
—
(2
)
—
Rate of compensation increase
2
4
—
—
Health care cost trends
—
—
1
18
One percent decrease in:
Discount rates
$
12
$
232
$
(1
)
$
41
Expected return on plan
assets(1)
22
—
2
—
Rate of compensation increase
(2
)
(3
)
—
—
Health care cost trends
—
—
(1
)
(15
)
(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 $15 million lower for the
year ended December 31, 2006.
As stated in Financial Statements and Supplementary Data,
Note 14, 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. A one percent change in the discount rate
assumption used in the calculation would have changed the
liability (and the related expense) by approximately
$36 million and a one percent change in the health care
cost trend assumption would have changed the liability (and the
related expense) by approximately $49 million as of and for
the year ended December 31, 2006.
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. We adjust these price curves in certain areas (such
as the Pennsylvania-New Jersey-Maryland region) based on our
outlook of the liquidity of these markets which may differ from
that of our derivative counterparties. 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, 2006:
10 Percent Increase
10 Percent Decrease
Fair Value
Fair Value
Change
Fair Value
Change
(In millions)
Derivatives designated as hedges
$
61
$
(19
)
$
(80
)
$
144
$
83
Other commodity-based derivatives
(456
)
(529
)
(73
)
(378
)
78
Total
$
(395
)
$
(548
)
$
(153
)
$
(234
)
$
161
Other significant assumptions that we use in determining the
fair value of our derivative instruments are those related to
time value, anticipated market liquidity and the credit risk of
our counterparties. The assumptions and methodologies we use to
determine the fair values of our derivatives may differ from
those used by our derivative counterparties, 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.
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. If the carrying value of
the asset exceeds the future undiscounted cash flows expected
from the asset, an impairment charge is recorded for the excess
of carrying value of the asset over its fair value. We recorded
impairments of our long-lived assets of $16 million,
$73 million and $1.1 billion and impairments on our
investments in unconsolidated affiliates of $13 million,
$347 million and $397 million during the years ended
December 31, 2006, 2005 and 2004. We also recorded asset
and investment impairments of our discontinued operations of
$13 million, $502 million and $40 million, net of
minority interest during the years ended December 31, 2006,
2005 and 2004. 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.
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 and gas
not used in the operations of our Pipelines segment;
–
Natural gas locational price differences change, affecting our
ability to optimize pipeline transportation capacity contracts
held in our Marketing segment; and
–
Electricity and natural gas price changes and locational pricing
changes, affecting the value of our natural gas contracts and
remaining power contracts held in our Marketing 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
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 8.
Commodity
Price Risk
Production-Related
Derivatives
Our Exploration and Production and Marketing segments attempt to
mitigate commodity price risk and stabilize cash flows
associated with El Paso’s forecasted sales of natural
gas and oil production through the use of derivative natural gas
and oil swaps, basis swaps and option contracts. The table below
presents the hypothetical
sensitivity to changes in fair values arising from immediate
selected potential changes in the quoted market prices of the
derivative commodity instruments used to mitigate these market
risks.
The table below was changed to reflect our current practice of
managing our production-related risks in both our Exploration
and Production and Marketing segments, which includes the use of
all production-related derivative contracts, whether they are
designated as hedges or not. Those contracts that are designated
as hedges will impact our earnings when the sale of the related
hedged items occurs, and, as a result, any gain or loss on these
hedging derivatives would be substantially offset by a
corresponding gain or loss on the underlying hedged commodity
sale, which is not included in the table. Those contracts that
are not designated as hedges will impact our earnings as the
fair value of these derivatives changes. Our production-related
derivatives do not mitigate all of the commodity price risk
related to 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
Our Marketing segment also has various other financial
instruments that are not utilized to mitigate the commodity
price risk associated with our natural gas and oil production.
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 due to
adverse market movements over a defined period of time within a
specified confidence level and allows us to monitor our risk in
comparison to established thresholds. We use what is known as
the historical simulation technique for measuring
Value-at-Risk.
This technique simulates potential outcomes in the value of our
portfolio based on market-based price changes. Our exposure to
changes in fundamental prices over the long-term can vary from
the exposure using the
one-day
assumption in our
Value-at-Risk
simulations. We supplement our
Value-at-Risk
simulations with additional fundamental and market-based price
analyses, including scenario analysis and stress testing to
determine our portfolio’s sensitivity to underlying risks.
These analyses and our
Value-at-Risk
simulations were changed to exclude our production-related
derivatives, which are included in the sensitivity analyses
described above, our Marketing segment’s natural gas
transportation related contracts that are accounted for under
the accrual basis of accounting, and 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 $6 million and $29 million as of
December 31, 2006 and 2005. Our highest, lowest and average
of the month-end values for Value-at-Risk during 2006 was
$14 million, $3 million and $7 million. Our
Value-at-Risk
decreased significantly during 2006 primarily due to the
assignment of certain of our power and natural gas derivatives
to third parties. 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 dates
as well as the total fair value of those securities. The fair
value of the securities has been estimated based on quoted
market prices for the same or similar issues.
Expected Fiscal Year of Maturity of Carrying Amounts
Fair
Carrying
Fair
2007
2008
2009
2010
2011
Thereafter
Total
Value
Amounts
Value
(In millions)
Long-term debt and other
obligations, including current portion — fixed rate
$
1,345
$
642
$
1,363
$
1,228
$
1,143
$
8,372
$
14,093
$
14,891
$
15,278
$
15,619
Average interest rate
7.1
%
6.9
%
7.4
%
8.4
%
7.4
%
7.7
%
Long-term debt and other
obligations, including current portion — variable rate
$
13
$
13
$
214
$
160
$
16
$
180
$
596
$
596
$
1,988
$
1,988
Average interest rate
6.2
%
6.2
%
7.1
%
5.4
%
6.2
%
6.2
%
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, 2006,
we have Euro-denominated debt with a principal amount of
€500 million which matures in 2009. As of
December 31, 2006 and 2005, we had swaps that effectively
converted €350 million and €367 million of
this debt into $402 million and $418 million. The
remaining principal at December 31, 2006 and 2005 of €
150 million and €155 million was subject to
foreign currency exchange risk. A $0.10 change in the Euro
to U.S. dollar exchange rate would result in a
$15 million gain or loss on our unhedged Euro-denominated
debt as of December 31, 2006.
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, 2006. 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, 2006.
Our assessment of the effectiveness of our internal control over
financial reporting as of December 31, 2006 has been
audited by Ernst and 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 sheet of
El Paso Corporation as of December 31, 2006, and the
related consolidated statements of income, comprehensive income,
stockholders’ equity, and cash flows for year then ended.
Our audit also included the financial statement schedule listed
in the Index at Item 15(a) for the year ended
December 31, 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 audit. The financial
statements of Citrus Corp. and Subsidiaries and Four Star
Oil & Gas Company (corporations in which the Company
has a 50% and 43.1% interest, 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 for 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, 2006, and earnings from these investments
represent approximately 24% of income before income taxes from
continuing operations for the year then ended.
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 the financial statements are
free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in
the financial statements. An audit also includes assessing the
accounting principles used and significant estimates made by
management, as well as evaluating the overall financial
statement presentation. We believe that our audit and the
reports of other auditors provide a reasonable basis for our
opinion.
In our opinion, based on our audit 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, 2006,
and the consolidated results of its operations and its cash
flows for the year 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, present fairly in all material respects the
information set forth therein.
As discussed in Note 1 to the consolidated financial
statements, effective January 1, 2006the 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, and 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).
We also have audited, in accordance with the standards of the
Public Company Accounting Oversight Board (United States), the
effectiveness of El Paso Corporation’s internal
control over financial reporting as of December 31, 2006,
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 26,2007 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 management’s assessment, included in the
accompanying Management’s Annual Report on Internal Control
Over Financial Reporting, that El Paso Corporation
maintained effective internal control over financial reporting
as of December 31, 2006, 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. Our responsibility
is to express an opinion on management’s assessment and an
opinion on the effectiveness of 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, evaluating
management’s assessment, testing and evaluating the design
and operating effectiveness of internal control, 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, management’s assessment that El Paso
Corporation maintained effective internal control over financial
reporting as of December 31, 2006, is fairly stated, in all
material respects, based on the COSO criteria. Also, in our
opinion, El Paso Corporation maintained, in all material
respects, effective internal control over financial reporting as
of December 31, 2006, based on the COSO criteria.
We also have audited, in accordance with the standards of the
Public Company Accounting Oversight Board (United States), the
2006 consolidated financial statements of El Paso
Corporation and our report dated February 26, 2007
expressed an unqualified opinion thereon.
In our opinion, the consolidated balance sheet as of
December 31, 2005 and the related consolidated statements
of income, comprehensive income, stockholders’ equity and
cash flows for each of the two years in the period ended
December 31, 2005 present fairly, in all material respects,
the financial position of El Paso Corporation and its
subsidiaries (the “Company”) at December 31,2005, and the results of their operations and their cash flows
for each of the two years in the period ended December 31,2005 in conformity with accounting principles generally accepted
in the United States of America. In addition, in our opinion,
the financial statement schedule for each of the two years in
the period 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 audits. We conducted our audits of these statements in
accordance with the standards of the Public Company Accounting
Oversight Board (United States). Those standards require that we
plan and perform the audit to obtain reasonable assurance about
whether the financial statements are free of material
misstatement. An audit of financial statements includes
examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements, assessing the
accounting principles used and significant estimates made by
management, and evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable
basis for our opinion.
As discussed in the notes to the consolidated financial
statements, the Company adopted FASB Interpretation No. 47,
Accounting for Conditional Asset Retirement Obligations,
on December 31, 2005.
Report of
Independent Registered Public Accounting Firm
To the Stockholders of Four Star Oil & Gas Company:
In our opinion, the accompanying consolidated balance sheets and
the related consolidated statements of income, of
stockholders’ equity and of cash flows present fairly, in
all material respects, the financial position of Four Star
Oil & Gas Company (the “Company”) and its
subsidiary at December 31, 2006 and 2005, and the results
of their operations and their cash flows for each of the three
years in the period ended December 31, 2006, 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 Note 3 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. and
Subsidiaries:
In our opinion, the accompanying consolidated balance sheets and
the related consolidated statements of income, of
stockholders’ equity, of comprehensive income and of cash
flows present fairly, in all material respects, the financial
position of Citrus Corp. and subsidiaries (the
“Company”) at December 31, 2006 and 2005, and the
results of their operations and their cash flows for each of the
three years in the period ended December 31, 2006 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 Benefit Pension and Other Postretirement
Plans - an amendment of FASB Statements No. 87, 88, 106 and
132(R),” as of December 31, 2006.
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
705,833,206 shares in 2006 and 667,082,043 shares in
2005
2,118
2,001
Additional paid-in capital
4,804
4,592
Accumulated deficit
(2,940
)
(3,415
)
Accumulated other comprehensive
loss
(343
)
(332
)
Treasury stock (at cost);
8,715,288 shares in 2006 and 7,620,272 shares in 2005
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
have been adjusted in all periods to reflect the
reclassification of ANR, our Michigan storage assets and our
50 percent interest in Great Lakes Gas Transmission, as
well as our Macae power facility as discontinued operations.
Additionally, 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 18) 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, 2006, we had $8 million of
restricted cash in current assets and $123 million in other
non-current assets. As of December 31, 2005, we had
$92 million of restricted cash in other current assets and
$168 million in other non-current assets.
We establish provisions for losses on accounts and notes
receivable and for natural gas imbalances due from shippers and
operators if we determine that we will not collect all or part
of the outstanding balance. We regularly review collectibility
and establish or adjust our allowance as necessary using the
specific identification method.
Property,
Plant and Equipment
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 the 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 year ended December 31, 2006, we expensed
approximately $19 million as a result of the adoption of
this accounting release, which was approximately $0.02 per basic
and fully diluted share.
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 and dismantlement, restoration and abandonment costs, net
of estimated salvage values; and geological and geophysical
costs incurred that cannot be associated with specific
unevaluated properties or prospects in which we own a direct
interest.
Our capitalized costs, net of related income tax effects, are
limited to a ceiling based on the present value of future net
revenues 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) our long-lived assets’ ability to
generate future cash flows on an undiscounted basis or
(ii) the fair value of our investments in unconsolidated
affiliates. If an impairment is indicated, or if we decide to
sell a long-lived asset or group of assets, we adjust the
carrying values of these assets downward, if necessary, to their
estimated fair value. 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 sales, 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 14.
Effective December 31, 2006, we adopted 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 in accumulated other comprehensive income (loss), a
component of stockholders’ equity, until those gains and
losses are recognized in the income statement. Prior to
December 31, 2006, these deferred amounts were included in
pension and other postretirement assets and liabilities in our
balance sheets, and their reclassification to stockholders’
equity will not impact our pension and other postretirement
benefit expense included in our income statements. For a further
discussion of the impact of the adoption of
SFAS No. 158, see Note 14.
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. For our transportation and storage services, we
recognize reservation revenues on firm contracted capacity
ratably over the contract period regardless of the amount of
natural gas that is transported or stored. For interruptible or
volumetric based services, we record revenues when physical
deliveries of natural gas are made at the agreed upon delivery
point or when gas is injected or withdrawn from the storage
facility. Gas not needed for operations is based on the volumes
we are allowed to retain relative to the amounts of gas we use
for operating purposes. We recognize revenue from gas not used
in operations when we retain the volumes under our tariffs.
Revenues for all services are generally based on the thermal
quantity of gas delivered or subscribed at a price specified in
the contract. We are subject to FERC regulations and, as a
result, revenues we collect in rate proceedings may be subject
to refund. We establish reserves for these potential refunds.
Exploration and Production revenues. Our
Exploration and Production segment derives revenues primarily
through the physical sale of natural gas, oil, condensate and
NGL. Revenues from sales of these products are recorded upon
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 sales.
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 contacts, 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 in 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 historical 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 8 for a further discussion of our price risk
management activities.
Derivatives that we have designated as accounting hedges impact
our revenues or expenses based on the nature and timing of the
transactions that they hedge. Derivatives 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.
Income
Taxes
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.
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 in 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. This
standard and its related interpretations require companies to
measure all employee stock-based compensation awards at fair
value on the date they are granted to employees and recognize
compensation cost in its financial
statements over the requisite service period. Prior to
January 1, 2006, we accounted for these plans 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 16.
We record stock-based compensation expense, excluding amounts
capitalized, as operation and maintenance expense 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. The adoption of SFAS No. 123(R) did
not result in a significant cumulative effect to our financial
statements. However, in 2006, we recognized an incremental
$11 million of additional pre-tax compensation expense,
capitalized approximately $2 million of this expense as
part of fixed assets, recorded $4 million of income tax
benefits and earnings per share decreased by $0.01 per
basic and diluted share resulting from the implementation of
this standard. Additionally, under SFAS No. 123(R),
beginning January 1, 2006, excess tax benefits from the
exercise of stock-based compensation awards are recognized in
cash flows from financing activities. Prior to this date, these
amounts were recorded in cash flows from operating activities.
Our excess tax benefits recorded in 2006, 2005 and 2004 were not
material.
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 historical periods (in
millions, except for per share amounts):
Net loss available to common
stockholders, as reported
$
(633
)
$
(947
)
Add: Stock-based employee
compensation expense included in reported net loss, net of taxes
12
14
Deduct: Total stock-based
compensation expense determined under fair-value based method
for all awards, net of taxes
(19
)
(25
)
Net loss available to common
stockholders, pro forma
$
(640
)
$
(958
)
Loss per share:
Basic and diluted, as reported
$
(0.98
)
$
(1.48
)
Basic and diluted, pro forma
$
(0.99
)
$
(1.50
)
Evaluation
of Prior Period Misstatements in Current Financial
Statements
In December 2006, we adopted the provisions of the
Securities and Exchange Commission’s Staff Accounting
Bulletin (SAB) No. 108, Considering the Effects of Prior
Year Misstatements When Quantifying Misstatements in Current
Year Financial Statements. SAB No. 108 provides
guidance on how to evaluate the impact of financial statement
misstatements from prior periods that have been identified in
the current year. The adoption of these provisions did not have
any impact on our financial statements.
New
Accounting Pronouncements Issued But Not Yet Adopted
As of December 31, 2006, the following accounting standards
and interpretations had not yet been adopted by us.
Accounting for Uncertainty in Income Taxes. In
July 2006, the FASB issued 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 ultimate settlement. The cumulative effect
of applying this interpretation will be recorded as an
adjustment to the beginning balance of retained earnings, or
other components of stockholders’ equity, as appropriate,
in the period of adoption. This interpretation is effective for
fiscal years beginning after December 15, 2006, and we do
not anticipate that it will have a material impact on our
financial statements.
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 be required to adopt the provisions of this standard no
later than 2008, and are currently evaluating the impact, if
any, that it 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. We are currently evaluating the impact, if
any, that the measurement date provisions of this standard will
have on our financial statements.
In February 2007, the FASB issued Statement of Financial
Accounting Standards 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 be required to adopt the provisions of this standard no
later than 2008, and are currently evaluating the impact, if
any, that it will have on our financial statements.
2.
Acquisitions
and Divestitures
Acquisitions
South Texas properties. In January, 2007, we
acquired operated natural gas and oil producing properties and
undeveloped acreage in south Texas, for approximately
$249 million using funds borrowed under our EPEP
$500 million credit facility.
Medicine Bow. In August 2005, we completed the
acquisition of Medicine Bow, a privately held energy company,
for total cash consideration of approximately $0.9 billion.
Medicine Bow owns a 43.1 percent interest in Four Star, an
unconsolidated affiliate. Our proportionate share of the
operating results associated with Four Star is reflected as
earnings from unconsolidated affiliates in our financial
statements (see Note 18).
We have reflected Medicine Bow’s results of operations in
our income statement beginning September 1, 2005. The
following summary unaudited pro forma consolidated results of
operations for the years ended December 31, 2005 and 2004
reflect the combination of our historical income statements with
Medicine Bow’s, adjusted for certain effects of the
acquisition and related funding. These pro forma results are
prepared as if the acquisition had occurred as of the beginning
of the periods presented and are not necessarily indicative of
the operating results that would have occurred had the
acquisition been consummated at that date, nor are they
necessarily indicative of future operating results.
During 2006, 2005 and 2004, we sold a number of assets and
investments in each of our business segments and corporate
operations. The table and discussions below summarize the assets
sold and proceeds from these sales:
2006
2005
2004
(In millions)
Power
$
531
$
625
$
884
Field Services
—
657
1,029
Exploration and Production
122
7
24
Pipelines
3
49
59
Corporate
2
121
16
Total
continuing(1)
658
1,459
2,012
Discontinued
368
577
1,295
Total
$
1,026
$
2,036
$
3,307
(1)
Proceeds exclude returns of
invested capital and cash transferred with the assets sold and
include costs incurred in preparing assets for disposal. These
items increased our sales proceeds by $15 million for the
year ended December 31, 2006, and decreased our sales
proceeds by $35 million and $85 million for the years
ended December 31, 2005 and 2004.
Power. Assets sold consisted primarily of our
interests in MCV and power plants in Brazil, Asia, and Central
America in 2006; interests in our power contract restructuring
entities and power plants in India and Korea in 2005; and
interests in Utility Contract Funding and 31 domestic power
plants in 2004.
Field Services. Assets sold consisted
primarily of our investment in Enterprise and the Javelina
natural gas processing and pipeline assets in 2005 and our
investment in GulfTerra in 2004.
Exploration and Production, Pipelines, and
Corporate. Assets sold consisted primarily of
natural gas and oil properties in south Texas and various
corporate assets in 2006; pipeline facilities and gathering
systems located in the southeastern and western U.S. and
Lakeside Technology Center in 2005; and Brazilian exploration
and production acreage and various corporate assets in 2004.
In February 2007, we sold ANR, our Michigan storage assets, our
50 percent interest in Great Lakes Gas Transmission and a
pipeline lateral located in the northeastern United States. Cash
proceeds from these sales was approximately $3.7 billion.
We expect to record a gain on these sales in 2007.
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, 2006, 2005
and 2004. We also had assets held for sale of approximately
$28 million as of December 31, 2006, which were sold
in February 2007.
ANR and Related Operations. In February 2007,
we sold ANR, our Michigan storage assets and our 50 percent
interest in Great Lakes Gas Transmission to TransCanada
Corporation and TC Pipeline, LP for net cash proceeds of
approximately $3.7 billion as further described above.
International Power Operations. In 2006, our
Board of Directors approved the sale of our interest in Macae, a
wholly owned power plant facility in Brazil. In 2005, our Board
of Directors approved the sale of our Asian and Central American
power asset portfolio. 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. During 2006, we completed the sale of all of our
discontinued international power operations for net proceeds of
approximately $368 million.
South Louisiana Gathering and Processing
Operations. During 2005, our Board of Directors
approved the sale of our south Louisiana gathering and
processing assets, which were part of our Field Services
segment. We completed the sale of these assets in 2005 for net
proceeds of approximately $486 million and recorded a
pre-tax gain of approximately $394 million.
Other. During 2004, our Canadian and certain
other international natural gas and oil production operations
were approved for sale. We completed the sale of substantially
all of these properties in 2004 and 2005 for approximately
$395 million. During 2003, the sales of our petroleum
markets businesses and operations were approved. We completed
the sale of these operations by the end of 2005.
Income Taxes on Discontinued Operations. For
the years ended December 31, 2006, 2005 and 2004, we
incurred income tax expense associated with our discontinued
operations of $274 million, $179 million and
$142 million resulting in an effective tax rate of
approximately 126%, 216% and 63% for these years. These
effective tax rates 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 were only
required to record deferred taxes on individual
assets/liabilities and a portion of our investment in the stock
of one of these companies;
•
In 2005, impairments and operating losses of certain foreign
investments for which no tax benefit was available, dividends
from foreign subsidiaries taxable in the U.S. and state income
taxes; and
•
In 2004, impairments and operating losses of certain foreign
investments, for which no tax benefit was available and state
income taxes.
Our (gain) loss on long-lived assets from continuing operations
consists of realized gains and losses on sales of long-lived
assets and impairments of long-lived assets, including goodwill
and other intangibles. Our asset impairments were primarily the
result of asset sales, unfavorable contract negotiations related
to the assets, and discontinuance of pipeline development
projects based on changing economic conditions. For additional
information on asset impairments on our discontinued operations
and investments in unconsolidated affiliates, see Notes 2
and 18. During each of the three years ended December 31,
our (gain) loss on long-lived assets was as follows:
2006
2005
2004
(In millions)
Net realized (gain) loss
$
2
$
1
$
(16
)
Asset impairments
Power
Brazilian assets
—
—
183
Domestic power assets
—
—
397
Turbines
—
18
1
Pipelines
Pipeline development projects
16
46
—
Field Services
Goodwill impairment
—
—
480
Other
—
9
23
Other
—
—
9
Total asset impairments
16
73
1,093
Loss on long-lived assets
18
74
1,077
Gain on sale of investments in
unconsolidated affiliates, net of impairments
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:
2006
2005
2004
(In millions)
Pretax Income (Loss)
U.S.
$
442
$
(872
)
$
(952
)
Foreign
80
35
(196
)
$
522
$
(837
)
$
(1,148
)
Components of Income Tax
Expense (Benefit)
Current
Federal
$
7
$
(13
)
$
(17
)
State
(15
)
(37
)
33
Foreign
19
22
8
11
(28
)
24
Deferred
Federal
(46
)
(372
)
(133
)
State
32
67
(8
)
Foreign
(6
)
2
1
(20
)
(303
)
(140
)
Total income taxes
$
(9
)
$
(331
)
$
(116
)
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:
2006
2005
2004
(In millions, except rates)
Income taxes at the statutory
federal rate of 35%
$
183
$
(293
)
$
(402
)
Increase (decrease)
Audit settlements
(159
)
(58
)
—
Earnings from unconsolidated
affiliates where we anticipate receiving dividends
(35
)
(36
)
(17
)
State income taxes, net of federal
income tax effect
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, 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.
In 2004, our overall effective tax rate on continuing operations
was significantly different than the statutory rate due
primarily to sales of our GulfTerra investment and impairments
of certain of our foreign investments. The sale of GulfTerra
resulted in a significant net taxable gain (compared to a lower
book gain) and thus significant tax expense due to the
non-deductibility of goodwill written off as a result of that
transaction. The impact of this non-deductible goodwill
increased our tax expense in 2004 by approximately
$139 million. Additionally, we received no U.S federal
income tax benefit on the impairment of certain of our foreign
investments.
Deferred Tax Assets and Liabilities. The
following are the components of our net deferred tax liability
related to continuing operations as of December 31:
2006
2005
(In millions)
Deferred tax liabilities
Property, plant and equipment
$
2,736
$
2,423
Investments in affiliates
555
205
Regulatory and other assets
53
302
Total deferred tax liability
3,344
2,930
Deferred tax assets
Net operating loss and tax credit
carryovers
Federal
1,560
1,098
State
214
204
Foreign
81
49
Environmental liability
144
147
Price risk management activities
284
573
Legal and other reserves
332
266
Other
424
574
Valuation allowance
(127
)
(107
)
Total deferred tax asset
2,912
2,804
Net deferred tax liability
$
432
$
126
Prior to 2004, we had not recorded U.S. deferred tax assets
or liabilities on book versus tax basis differences for a
substantial portion of our international investments based on
our intent to indefinitely reinvest earnings from these
investments outside the U.S. Based on sales negotiations on
certain power assets in Asia, Central America, and India,
however, we have received or expect to receive these sales
proceeds within the U.S. As a result, during the years
ended December 31, 2006, 2005 and 2004, we recorded
U.S. deferred tax assets and liabilities on book versus tax
basis differences in these investments. We also recorded
U.S. deferred tax benefits on the sale of a power asset in
India. As of December 31, 2006 and 2005, we have
U.S. deferred tax assets of $45 million and
$103 million and U.S. deferred tax liabilities of
$2 million and $23 million related to these
investments.
Cumulative undistributed earnings from 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 31,2006, the portion of the cumulative undistributed earnings from
these investments on which we have not recorded U.S. income
taxes was approximately $112 million. For these same
reasons, we have not recorded a provision for U.S. income
taxes on the foreign currency translation adjustments recorded
in accumulated other comprehensive income.
Tax Credit and NOL Carryovers. As of
December 31, 2006, we have U.S. federal alternative
minimum tax credits of $326 million that carryover
indefinitely, $1 million of general business credit
carryovers for which the carryover periods end in various years
from 2010 through 2022 and capital loss carryovers of
$11 million for which the carryover period ends in 2008.
The table below presents the details of our federal and state
net operating loss carryover periods as of December 31,2006:
Carryover Period
2007
2008-2011
2012-2016
2017-2026
Total
(In millions)
U.S. federal net operating
loss
$
—
$
16
$
7
$
3,626
$
3,649
State net operating loss
182
1,013
496
999
2,690
We also had $182 million of foreign net operating loss
carryovers and $56 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. In 2006, we also considered the gain we expected
on the sale of ANR and related assets in our assessment. We
believe it is more likely than not that we will realize the
benefit of our deferred tax assets, net of existing valuation
allowances.
Other Tax Matters. The IRS is currently
auditing El Paso’s 2003 and 2004 tax years. We have
recorded liabilities for tax contingencies associated with these
audits, as well as for proceedings and examinations with other
taxing authorities, which we believe are adequate. As these
matters are finalized, we may be required to adjust our
liability which could significantly increase or decrease our
income tax expense and effective income tax rates in future
periods.
We calculated basic and diluted earnings per common share as
follows for the three years ended December 31:
2006
2005
2004
Basic
Diluted
Basic
Diluted
Basic
Diluted
(In millions, except per share amounts)
Income (loss) from continuing
operations
$
531
$
531
$
(506
)
$
(506
)
$
(1,032
)
$
(1,032
)
Convertible preferred stock
dividends
(37
)
—
(27
)
(27
)
—
—
Income (loss) from continuing
operations available to common stockholders
494
531
(533
)
(533
)
(1,032
)
(1,032
)
Discontinued operations
(56
)
(56
)
(96
)
(96
)
85
85
Cumulative effect of accounting
changes, net of income taxes
—
—
(4
)
(4
)
—
—
Net income (loss) available to
common stockholders
$
438
$
475
$
(633
)
$
(633
)
$
(947
)
$
(947
)
Weighted average common shares
outstanding
678
678
646
646
639
639
Effect of dilutive securities:
Options and restricted stock
—
4
—
—
—
—
Convertible preferred stock
—
57
—
—
—
—
Weighted average common shares
outstanding and dilutive potential common shares
678
739
646
646
639
639
Earnings per common share:
Income (loss) from continuing
operations
$
0.73
$
0.72
$
(0.82
)
$
(0.82
)
$
(1.61
)
$
(1.61
)
Discontinued operations, net of
income taxes
(0.08
)
(0.08
)
(0.15
)
(0.15
)
0.13
0.13
Cumulative effect of accounting
changes, net of income taxes
—
—
(0.01
)
(0.01
)
—
—
Net income (loss)
$
0.65
$
0.64
$
(0.98
)
$
(0.98
)
$
(1.48
)
$
(1.48
)
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
issued in 2005, trust preferred securities, and zero coupon
convertible debentures (which were paid off in April 2006). For
the year ended December 31, 2006, certain employee stock
options, our zero coupon convertible debentures and our trust
preferred securities were antidilutive. For the year ended
December 31, 2005 and 2004, 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 15 and 16.
Long-term financing obligations,
including current maturities
$
14,689
$
15,487
$
17,266
$
17,607
Commodity-based price risk
management derivatives
(395
)
(395
)
(1,416
)
(1,416
)
Interest rate and foreign currency
derivatives
43
43
2
2
Investments
23
23
61
61
As of December 31, 2006 and 2005, 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 8 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.
8.
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, 2006 and 2005. 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(2)
$
(352
)
$
(1,414
)
(1)
Decrease is due primarily to the
sale or assignment of a number of derivative contracts and
significant changes in natural gas and oil prices during 2006.
(2)
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. During 2006 and 2005, 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 as of
December 31, 2006, and 2005.
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 contracts to
limit our exposure to fluctuations in the commodity markets as
well as fluctuations in foreign currency and interest rates with
the objective of realizing a fixed cash flow stream from these
activities. A summary of the impacts of our cash flow hedges
included in accumulated other comprehensive income (loss), net
of income taxes, as of December 31, 2006 and 2005 follows:
Accumulated
Other
Estimated
Comprehensive
Income (Loss)
Final
Income (Loss)
Reclassification
Termination
2006
2005
in
2007(1)
Year
(In millions)
Commodity cash flow
hedges
Held by consolidated entities
$
49
$
(285
)
$
89
2012
Held by unconsolidated affiliates
(4
)
(7
)
(1
)
2013
De-designated(2)
35
—
35
2007
Total commodity cash flow hedges
80
(292
)
123
Interest rate and foreign
currency cash flow hedges
Fixed rate
3
2
1
2015
De-designated
(3
)
(4
)
—
2009
Total foreign currency cash flow
hedges
—
(2
)
1
Total cash flow hedges
$
80
$
(294
)
$
124
(1)
Reclassifications occur upon the
physical delivery of the hedged commodity or if the forecasted
transaction is no longer probable.
(2)
During 2006, we removed the hedging
designation on certain derivatives that hedged approximately 75
Tbtu and 154 MBbls of our natural gas and oil production in
2007.
For the years ended December 31, 2006, 2005 and 2004, we
recognized a net gain of $10 million, and losses of
$5 million and $1 million, net of income taxes, 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 December 31, 2006 and 2005, these
derivatives were as follows (amounts in millions):
Price Risk Management
Weighted
Debt
Asset
(Liability)(1)
Derivative
Average Rate
2006
2005
2006
2005
Fixed-to-floating
swaps
LIBOR + 4.18
%
$
440
$
440
$
(31
)
$
(30
)
Fixed-to-floating
cross currency
swaps(2)
LIBOR + 4.24
%
402
402
67
23
$
36
$
(7
)
(1)
We did not record any
ineffectiveness related to our fair value hedges in 2004, 2005
or 2006.
(2)
As of December 31, 2006 and
2005, these derivatives, when combined with our Euro denominated
debt, converted 350 million Euro of our debt to
$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 historical 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, 2006 and 2005:
“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 54 counterparties as of December 31,2006, most of which are energy marketers. Although most of our
counterparties are not currently rated as below investment
grade, if one of our counterparties fails to perform, we may
recognize an immediate loss in our earnings, as well as
additional financial impacts in the future delivery periods to
the extent a replacement contract at the same prices and
quantities cannot be established.
As of December 31, 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. As of December 31, 2005, two
counterparties, Constellation Energy Commodities Group, Inc. and
Duke Energy Trading and Marketing LLC, comprised 28 percent
and 18 percent of our net financial instrument asset
exposure. 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 subsidiaries and are included in other current and
non-current assets and liabilities on our balance sheets. These
balances are presented on our balance sheets on a gross basis
and are recoverable over various periods. Below are the details
of our regulatory assets and liabilities as of December 31:
2006
2005
(In millions)
Current regulatory assets
$
6
$
4
Non-current regulatory assets
Gross-up
of deferred taxes on capitalized funds used during construction
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
5-27
Gathering and processing systems
Straight-line
40
Transportation equipment
Straight-line
6
Buildings and improvements
Straight-line
4-49
Office and miscellaneous equipment
Straight-line
1-28
(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 cost. As of December 31,2006 and 2005, TGP and EPNG have excess purchase costs
associated with their acquisition. Total excess costs on these
pipelines were approximately $2.5 billion and accumulated
depreciation was approximately $0.4 billion and
$0.3 billion at December 31, 2006 and 2005. 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 December 31, 2006,
2005, and 2004 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 cost on debt amounts capitalized are included as a
reduction of interest expense in our income statements and was
$41 million, $41 million and $35 million during
the years ended December 31, 2006, 2005 and 2004. 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
$28 million, $31 million and $22 million during
the years ended December 2006, 2005 and 2004.
Construction work-in progress. At
December 31, 2006 and 2005, we had approximately
$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, our natural gas
pipelines and related transmission facilities and storage wells,
as well as in our corporate headquarters building. We have
obligations to plug wells when production on those wells is
exhausted or we no longer plan to use them, and when we abandon
them. Our legal obligations associated with our natural gas
transmission facilities relate primarily to purging and sealing
the pipelines if they are abandoned. We also have obligations to
remove hazardous materials associated with our natural gas
transmission facilities and in our corporate headquarters if
these facilities are replaced or renovated. We accrue a
liability for legal obligations based on an estimate of the
timing and amount of their settlement. We are required to
operate and maintain our natural gas pipeline and storage
systems, and intend to do so as long as supply and demand for
natural gas exists, which we expect for the foreseeable future.
Therefore, we believe that the substantial majority of our
natural gas pipeline and storage system assets have
indeterminate lives. We continue to evaluate our asset
retirement obligations and future developments could impact the
amounts we record.
In estimating the liability associated with our asset retirement
obligations, we utilize several assumptions, including
credit-adjusted discount rates ranging from six to eight percent
and a projected inflation rate of 2.5 percent. Changes in
estimate represent changes to the expected amount and timing of
payments to settle our asset retirement obligations. Typically,
these changes primarily 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. 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:
2006
2005
(In millions)
Net asset retirement liability at
January 1
$
252
$
309
Liabilities
settled(1)
(48
)
(92
)
Accretion expense
19
27
Liabilities incurred
5
12
Changes in estimate
15
(12
)
Adoption of
FIN No. 47(2)
—
8
Net asset retirement liability at
December 31
$
243
$
252
(1)
Decrease is due primarily to the
sale of certain domestic natural gas and oil properties in our
Exploration and Production segment in 2005. See Note 2.
(2)
We recorded a charge in 2005 of
$4 million net of income taxes of $2 million as a
cumulative effect of accounting change upon our adoption of
FIN No. 47 (primarily related to our Pipelines segment
and our corporate activities). If we had adopted the provisions
of FIN No. 47 as of January 1, 2004, our net
income for the years ended December 31, 2004 and 2005 would
not have been materially affected.
Included in liabilities related to
discontinued operations on our balance sheet at
December 31, 2005.
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 the 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):
2007
$
1,360
2008
655
2009
1,570
2010
1,392
2011
1,167
Thereafter
8,616
Total long-term financing
obligations, including current maturities
$
14,760
Approximately $600 million of our debt obligations are
redeemable at the option of the holders in the first half of
2007, which is prior to its stated maturity date. As a result,
these amounts are classified as current liabilities in our
balance sheet as of December 31, 2006. Subsequent to this
date, the holders of $300 million of these obligations did
not exercise their redemption right and the debt will mature in
2027.
In addition, approximately $9 billion of our debt
obligations (increasing to approximately $10 billion by the
end of 2008) provide us the ability to call the debt prior
its stated maturity date. If redeemed prior to their stated
maturities, we will be required to pay a make-whole or fixed
premium in addition to repaying the principal and accrued
interest.
In February 2007, we launched a tender offer for certain of our
outstanding debt obligations in conjunction with the closing of
the sale of ANR and related assets.
Credit
Facilities
Available Capacity Under Credit Agreements. As
of December 31, 2006, we had available capacity under our
credit agreements of approximately $1 billion. Of this
amount, $0.4 billion is related to the $500 million
revolving credit agreement of our subsidiary, EPEP and
$0.6 billion is available under our $1.75 billion
credit agreement and our $500 million unsecured revolving
credit facility. In January 2007, we borrowed approximately
$250 million under the EPEP revolving credit facility to
fund the acquisition of additional natural gas and oil
properties.
Credit Agreement Restructuring. In July 2006,
we restructured our $3 billion credit agreement. As part of
this restructuring, we entered into a new $1.75 billion
credit agreement, consisting of a $1.25 billion three-year
revolving credit facility and a $500 million five-year
deposit letter of credit facility. In conjunction with the
restructuring, we recorded a 2006 charge of approximately
$17 million associated with unamortized financing costs on
the previous credit agreement. El Paso and certain of its
subsidiaries have guaranteed the $1.75 billion credit
agreement, which is collateralized by our stock ownership in
CIG, EPNG and TGP who are also eligible borrowers under the
$1.75 billion credit agreement.
Under the $1.25 billion revolving credit facility which
matures in July 2009, we can borrow funds at LIBOR plus 1.75% or
issue letters of credit at 1.75% plus a fee of 0.15% of the
amount issued. We pay an annual commitment fee of 0.375% on any
unused capacity under the revolving credit facility. The terms
of the $500 million deposit letter of credit facility
provide for the ability to issue letters of credit or borrow
amounts as revolving loans which mature in July 2011. We pay
LIBOR plus 2.00% on any amounts borrowed under the deposit
facility, 2.15% on letters of credit, and 2.10% on unused
capacity.
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 2.3% 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.
EPEP Revolving Credit Facility. Under this
$500 million revolving credit agreement, EPEP can borrow
revolving loans or issue letters of credit through its maturity
date in August 2010. Amounts borrowed are classified as
long-term on our balance sheet and carry an interest rate of
LIBOR plus a fixed percentage of 1.25% to 1.875% depending on
utilization. The facility is collateralized by certain of our
natural gas and oil properties.
Contingent Letter of Credit Facility. In
January, 2007, El Paso entered into 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.
$1.75 billion Revolving Credit
Facility. Our covenants under the
$1.75 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 5.75 to 1 at anytime prior to
June 30, 2007. Thereafter it shall not exceed 5.5 to 1
until June 29, 2008 and 5.25 to 1 from June 30, 2008
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 December 31, 2006.
Thereafter it shall not be less than 1.80 to 1 until
June 29, 2008, and 2.00 to 1 from June 30, 2008 until
maturity;
(c)
EPNG, TGP and CIG cannot incur incremental Debt if the
incurrence of this incremental Debt would cause their Debt to
Consolidated EBITDA ratio, each as defined in the credit
agreement, for that particular company to exceed 5.0 to 1; 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 Revolving Credit Facility. 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, EPEP’s
debt to EBITDA, each as defined in the credit agreement, must
not exceed 4.0 to 1, and EPEP’s Collateral Coverage
Ratio (as defined in the credit agreement) must exceed 1.5 to 1.
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 abilities of some of our
subsidiaries to declare and pay dividends and potential
limitations on some of our subsidiaries to participate in our
cash management program, and limitations on some of our
subsidiaries’ ability to prepay debt. Our most restrictive
acceleration provision is $5 million and is associated with
the indenture of one of our subsidiaries. This indenture states
that should an event of default occur resulting in the
acceleration of other debt obligations in excess of
$5 million, the long-term debt obligation containing that
provision could be accelerated. The acceleration of our debt
would adversely affect our liquidity position and in turn, our
financial condition.
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. Many of our
subsidiaries and investments have debt obligations related to
their costs of project construction or acquisition. Several of
our projects have experienced events that have either
constituted or could constitute an event of default under the
loan agreements. This project financing debt is recourse only to
the project company and assets (i.e. without recourse to
El Paso). We do not believe any of these defaults, or other
events that have led to or could lead to events of default at
these projects, will have a material effect on us or our
subsidiaries’ financial statements based on the amounts we
have recorded on our balance sheet for these projects
and/or the
current status of negotiations relating to these projects.
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, 2006, we had outstanding
letters of credit of approximately $1.4 billion. Included
in this amount is $1.1 billion of letters of credit
securing our recorded obligations related to price risk
management activities.
13.
Commitments
and Contingencies
Legal
Proceedings
Shareholder Litigation. Twenty-eight purported
shareholder class action lawsuits have been pending since 2002
and are consolidated in federal court in Houston, Texas. The
consolidated lawsuit alleges violations of federal securities
laws against us and several of our current and former officers
and directors. In November 2006, the parties executed a
definitive settlement agreement in which the parties agreed to
settle these class action lawsuits, subject to final court
approval. Under the terms of the settlement, El Paso and
its insurers will pay a total of $273 million to the
plaintiffs. El Paso has contributed approximately
$48 million and its insurers have contributed approximately
$225 million into an escrow account pending final court
approval of the settlement. An additional $12 million was
separately contributed by a third party under the terms of the
settlement.
ERISA Class Action Suits. In December
2002, a purported class action lawsuit entitled William H.
Lewis, III v. El Paso Corporation,
et al. was filed in the U.S. District
Court for the Southern District of Texas alleging that our
communication with participants in our Retirement Savings Plan
included misrepresentations and omissions similar to those pled
in the consolidated shareholder litigation 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). Formal discovery in this lawsuit is currently
stayed. We have various insurance coverages for this lawsuit,
subject to certain deductibles and
co-pay
obligations. We have established accruals for these matters
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. Our costs and legal exposure related
to this lawsuit are not currently determinable.
Retiree Medical Benefits Matters. We currently
serve as the plan administrator for a medical benefits plan that
covers a closed group of retirees of the Case Corporation who
retired on or before July 1, 1994. Case was formerly a
subsidiary of Tenneco, Inc. that was spun off prior to our
acquisition of Tenneco in 1996. Tenneco retained the obligation
to provide certain medical and prescription drug benefits to
eligible retirees and their spouses. We assumed this obligation
as a result of our merger with Tenneco. 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 are 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 is
obligated to indemnify, defend and hold Case harmless for the
amounts it would be required to pay. In separate rulings in
2004, the court ruled that, pending a trial on the merits, Case
must pay the amounts incurred above the cap and that
El Paso must reimburse Case for those payments. In January
2006, these rulings were upheld on appeal by the U.S. Court
of
Appeals for the 6th Circuit. We will proceed with a trial
on the merits with regard to the issues of whether the cap is
enforceable and what degree of benefits have actually vested.
Until this is resolved, El Paso will indemnify Case for any
payments Case makes above the cap, which are currently about
$1.8 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.
Natural Gas Commodities Litigation. Beginning
in August 2003, several lawsuits have been filed against
El Paso Marketing L.P. (EPM) that allege 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
have been consolidated in federal court in New York for all
pre-trial purposes and are 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.
We have executed settlement an agreement with the plaintiffs,
which is subject to court approval.
The second set of cases, involving similar allegations on behalf
of commercial and residential customers, were transferred to a
multi-district litigation proceeding (MDL) in the
U.S. District Court for Nevada, In re
Western States Wholesale Natural Gas Antitrust
Litigation, dismissed and have been appealed. The third set
of cases also involve similar allegations on behalf of certain
purchasers of natural gas. These include 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. v. AEP
Energy Services Inc. et al. (filed in federal court for
the Eastern District of California in June 2005); Farmland
Industries, Inc. v. Oneok Inc. (filed in state court in
Wyandotte County, Kansas in July 2005); Learjet, Inc. v.
Oneok Inc. (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), 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 Arandell,
et al v. Xcel Energy, et al(filed in the
circuit court of Dane County, Wisconsin in December 2006). The
Leggett and Farmland cases have been dismissed.
The Arandell and Missouri Public Service cases
have been removed to federal court. The remaining cases have all
been transferred to the MDL proceeding. Similar motions to
dismiss have either been filed or are anticipated to be filed in
these cases as well. Our costs and legal exposure related to
these lawsuits and claims are not currently determinable.
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 has 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 May 2005, a
representative appointed by the court issued a recommendation to
dismiss most of the actions. In October 2006, the
U.S. District Judge issued an order dismissing all
mismeasurement 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 MTBE’s potential impact
on water supplies. Some of our subsidiaries are among the
defendants in 70 such lawsuits. These suits have been
consolidated for pre-trial purposes in multi-
district litigation in the U.S. District Court for the
Southern District of New York. The plaintiffs, certain state
attorneys general, various water districts and a limited number
of individual water customers, generally seek remediation of
their groundwater, prevention of future contamination, 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. Our costs and legal
exposure related to these 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.
Iraq Oil Sales. Several government agencies
have been investigating The Coastal Corporation’s and
El Paso’s purchases of crude oil from Iraq under the
United Nations’ Oil for Food Program. These agencies
include the U.S. Attorney for the Southern District of New
York (SDNY), the SEC and the Office of Foreign Assets Control
(OFAC). In February 2007, we entered into agreements with the
SDNY, SEC , and OFAC to resolve their pending investigations of
our participation in the Oil for Food Program. The agreements
obligate us to pay approximately $8 million, with
approximately $6 million intended to be ultimately
transferred to a humanitarian fund for the benefit of the Iraqi
people.
Other Government Investigations. We also
continue to provide information and cooperate with the inquiry
or investigation of the U.S. Attorney and the SEC in
response to requests for information regarding price reporting
of transactional data to the energy trade press and the hedges
of our natural gas production.
Other
Contingencies
EPNG Rate Case. In June 2005, EPNG filed a
rate case with the FERC proposing an increase in revenues of
10.6 percent or $56 million annually over current
tariff rates, new services and revisions to certain terms and
conditions of existing services. On January 1, 2006, the
rates became effective, subject to refund. In March 2006, the
FERC issued an order that generally approved our proposed new
services, which were implemented on June 1, 2006. In
December 2006, EPNG filed settlement of this rate case with the
FERC. The settlement provides benefits for both EPNG and its
customers for a three-year period ending December 31, 2008.
Only one party in the rate case contested the settlement. The
administrative law judge has certified the settlement to the
FERC finding that the settlement could be approved for all
parties or in the alternative that the contesting party could be
severed from the settlement. We have reserved sufficient amounts
to meet EPNG’s refund obligations under the settlement.
Such refunds will be payable within 120 days after approval
by the FERC.
Iraq Imports. In December 2005, the Ministry
of Oil for the State Oil Marketing Organization of Iraq (SOMO)
sent an invoice to one of our subsidiaries with regard to
shipments of crude oil that SOMO alleged were purchased and paid
for by Coastal in 1990. The invoices request an additional
$144 million of payments for such shipments, along with an
allegation of an undefined amount of interest. The invoice
appears to be associated with cargoes that Coastal had purchased
just before the 1990 invasion of Kuwait by Iraq. We have
requested additional information from SOMO to further assist in
our evaluation of the invoice and the underlying facts. In
addition, we are evaluating our legal defenses, including
applicable statute of limitation periods.
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 includes
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 our rates.
In addition to the above matters, we and our subsidiaries and
affiliates are named defendants in numerous lawsuits and
governmental proceedings that arise in the ordinary course of
our business. There are also other regulatory rules and orders
in various stages of adoption, review
and/or
implementation. For each of our outstanding legal and other
contingent matters, we evaluate the merits of the case, our
exposure to the matter, possible legal or settlement strategies
and the likelihood of an unfavorable outcome. If we determine
that an unfavorable outcome is probable and can be estimated, we
establish the necessary accruals. While the outcome of these
matters, 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. However, it is possible that new information or
future developments could require us to reassess our potential
exposure related to these matters and adjust our accruals
accordingly, and these adjustments could be material. As of
December 31, 2006, we had approximately $548 million
accrued, net of related insurance receivables, for outstanding
legal and other contingent matters. We have deposited
$60 million to an escrow account for the shareholder
litigation.
Environmental
Matters
We are subject to federal, state and local laws and regulations
governing environmental quality and pollution control. These
laws and regulations require us to remove or remedy the effect
on the environment of the disposal or release of specified
substances at current and former operating sites. As of
December 31, 2006, we have accrued approximately
$314 million, which has not been reduced by
$31 million for amounts to be paid directly under
government sponsored programs. Our accrual includes
approximately $305 million for expected remediation costs
and associated onsite, offsite and groundwater technical studies
and approximately $9 million for related environmental
legal costs. Of the $314 million accrual, $28 million
was reserved for facilities we currently operate and
$286 million was reserved for non-operating sites
(facilities that are shut down or have been sold) and Superfund
sites.
Our reserve estimates range from approximately $314 million
to approximately $532 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 ($27 million). Second, where the most likely
outcome cannot be estimated, a range of costs is established
($287 million to $505 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 2007, we estimate that our total remediation expenditures
will be approximately $84 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 $21 million in the
aggregate for the years 2007 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 53 active sites under
the 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 31,2006, we have estimated our share of the remediation costs at
these sites to be between $34 million and $58 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 office
and operating equipment. The terms of the agreements vary from
2007 until 2053. As of December 31, 2006, our total
commitments under non-cancellable operating leases were
approximately $98 million which have not been reduced by
minimum sublease rentals of approximately $4 million due in
the future under noncancelable subleases. Minimum annual rental
commitments under our operating leases at December 31,2006, were as follows:
Year Ending December 31,
Operating Leases
(In millions)
2007
$
66
2008
10
2009
7
2010
3
2011
1
Thereafter
11
Total
$
98
Our lease obligations in the table above significantly decrease
after 2007 based upon the expiration of certain lease payments
made in accordance with the termination agreement signed in 2005
related to consolidating our Houston-based operations into one
location. Rental expense on our lease obligations for the years
ended December 31, 2006, 2005, and 2004 was
$43 million, $53 million and $90 million, which
includes $27 million and $80 million in 2005 and 2004
related to consolidating our Houston-based operations.
Guarantees. We are involved in various joint
ventures and other ownership arrangements that sometimes require
additional financial support that results in the issuance of
financial and performance guarantees. In a financial guarantee,
we are obligated to make payments if the guaranteed party fails
to make payments under, or
violates the terms of, the financial arrangement. In a
performance guarantee, we provide assurance that the guaranteed
party will execute on the terms of the contract. If they do not,
we are required to perform on their behalf. We also periodically
provide indemnification arrangements related to assets or
businesses we have sold. These arrangements include, but are not
limited to, indemnification for income taxes, the resolution of
existing disputes, environmental matters, and necessary
expenditures to ensure the safety and integrity of the assets
sold.
As of December 31, 2006, we had recorded obligations of
$71 million related to our guarantees and indemnification
arrangements. These arrangements had a total stated value of
approximately $376 million, for which we are indemnified by
third parties for $18 million. These amounts exclude
guarantees for which we have issued related letters of credit
discussed in Note 12. Included in the above stated value of
$376 million is approximately $120 million associated
with tax matters, related interest and other indemnifications
arising out of the sale of our Macae power facility.
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 31,2006. 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, 2006, we
had firm commitments under transportation and storage capacity
contracts of $400 million and other purchase and capital
commitments (including maintenance, engineering, procurement and
construction contracts) of $540 million.
We also hold cancelable easements or
right-of-way
arrangements from landowners permitting the use of land for the
construction and operation of our pipeline systems. Currently,
our obligation under these easements is not material to the
results of our operations. However, we are currently negotiating
a long-term
right-of-way
agreement with the Navajo Nation which could result in a
significant commitment by us (see Navajo Nation above).
14.
Retirement
Benefits
Overview
of Retirement Benefits
Pension Benefits. Our primary pension plan is
a defined benefit plan that covers substantially all of our
U.S. employees and provides benefits under a cash balance
formula. Certain employees who participated in the prior pension
plans of El Paso, Sonat or Coastal receive the greater of
cash balance benefits or transition benefits under the prior
plan formulas. We do not anticipate making any contributions to
this pension plan in 2007.
In addition to our primary pension plan, we maintain a
Supplemental Executive Retirement Plan (SERP) that provides
additional benefits to selected officers and key management. The
SERP provides benefits in excess of certain IRS limits that
essentially mirror those in the primary pension plan. We also
maintain two other pension plans that are closed to new
participants which provide benefits to former employees of our
previously discontinued coal and convenience store operations.
The SERP and the frozen plans together are referred to below as
other pension plans. We also participate in several
multi-employer pension plans for the benefit of our former
employees who were union members. Our contributions to these
plans during 2006, 2005 and 2004 were not material. We expect to
contribute $5 million to the SERP and $3 million to
the frozen plans in 2007.
During 2004, we recognized a $4 million curtailment benefit
in our pension plans due to a reduction in the number of
employees that participate in our pension plan. The reduction
resulted from asset sales and the severance of employees.
Retirement Savings Plan. We maintain a defined
contribution plan covering all of our U.S. employees. We
match 75 percent of participant basic contributions up to
6 percent of eligible compensation and can make additional
discretionary matching contributions. Amounts expensed under
this plan were approximately $35 million, $30 million
and $16 million for the years ended December 31, 2006,
2005 and 2004.
Other Postretirement Benefits. We provide
postretirement medical benefits for closed groups of retired
employees and limited postretirement life insurance benefits for
current and retired employees. Other postretirement employee
benefits (OPEB) for our regulated pipeline companies are
prefunded to the extent such costs are recoverable through
rates. To the extent actual OPEB costs for our regulated
pipeline companies differ from the amounts recovered in rates, a
regulatory asset or liability is recorded. We expect to
contribute $42 million to our postretirement plans in 2007.
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. We will retain
the other postretirement benefit plans associated with the
retirees of ANR after the sale of these operations in 2007.
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.
The table below provides additional information related to our
pension and other postretirement plans as of September 30,
our measurement date, for our obligations and plan assets and as
of December 31 for the balance sheet amounts:
Accumulated other comprehensive
income (loss), net of income taxes
(450
)
(49
)
15
—
Our accumulated benefit obligation for our defined benefit
pension plans was $2,148 million and $2,216 million as
of December 31, 2006 and 2005. For those pension plans
whose accumulated benefit obligations exceeded the fair value of
plan assets, our projected benefit obligation and accumulated
benefit obligation was $167 million as of December 31,2006 and $176 million as of December 31, 2005 and the
fair value of our plan assets was $110 million and
$99 million as of December 31, 2006 and 2005.
The accumulated postretirement benefit obligation and fair value
of plan assets associated with our other postretirement benefit
plans whose accumulated postretirement benefit obligations
exceeded the fair value of plan assets was $320 million and
$67 million as of December 31, 2006 and $374 million
and $84 million as of December 31, 2005.
Our accumulated other comprehensive income includes
approximately $10 million of unamortized prior service
costs, net of tax. We anticipate that approximately
$25 million of our accumulated other comprehensive loss,
net of tax, will be recognized as a part of our net periodic
benefit cost in 2007.
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
2006
2005
2006
2005
(In millions)
Change in benefit
obligation(1):
Benefit obligation —
beginning of period
$
2,235
$
2,118
$
527
$
541
Service cost
17
22
11
1
Interest cost
118
121
26
29
Participant contributions
—
—
34
34
Actuarial loss (gain)
(37
)
178
(2)
(35
)
(5
)
Benefits paid
(176
)
(203
)
(69
)
(73
)
Other
—
(1
)
—
—
Benefit obligation — end
of period
$
2,157
$
2,235
$
494
$
527
Change in plan assets:
Fair value of plan assets at
beginning of period
$
2,350
$
2,289
$
251
$
220
Actual return on plan
assets(3)
192
255
19
20
Employer contributions
16
9
41
50
Participant contributions
—
—
34
34
Benefits paid
(176
)
(203
)
(69
)
(73
)
Administrative expenses
—
—
—
—
Fair value of plan assets at end
of period
$
2,382
$
2,350
$
276
$
251
Reconciliation of funded status:
Fair value of plan assets at
September 30
$
2,382
$
2,350
$
276
$
251
Less: Benefit
obligation — end of period
2,157
2,235
494
527
Funded status at September 30
225
115
(218
)
(276
)
Fourth quarter contributions and
income
3
2
9
11
Unrecognized net actuarial
loss(4)
—
733
—
20
Unrecognized prior service
cost(4)
—
(9
)
—
(5
)
Net asset (liability) at
December 31
$
228
$
841
$
(209
)
$
(250
)
(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)
Increase is due primarily to
changes in our discount rate and mortality assumptions in 2005.
(3)
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 recognized only to the extent that all of our
remaining unrecognized actual gains and loses exceed the greater
of 10 percent of our projected benefit obligations or
market related value of plan assets.
(4)
Amounts were reclassified to
accumulated other comprehensive income upon the adoption of
SFAS No. 158 in 2006.
Expected Payment of Future Benefits. As of
December 31, 2006, we expect the following payments under
our plans:
Year Ending
Other Postretirement
December 31,
Pension Benefits
Benefits(1)
(In millions)
2007
$
168
$
48
2008
168
47
2009
166
45
2010
166
44
2011
165
43
2012-2016
802
193
Total
$
1,635
$
420
(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. For each of
the years ended December 31, the components of net benefit
cost are as follows:
Pension Benefits
Other Postretirement Benefits
2006
2005
2004
2006
2005
2004
(In millions)
Service cost
$
17
$
22
$
31
$
11
$
1
$
1
Interest cost
118
121
121
26
29
34
Expected return on plan assets
(175
)
(168
)
(187
)
(14
)
(12
)
(11
)
Amortization of net actuarial loss
55
69
47
—
—
4
Amortization of transition
obligation
—
—
—
—
8
8
Amortization of prior service
cost(1)
(2
)
(2
)
(3
)
(1
)
(1
)
(1
)
Settlements, curtailment, and
special termination benefits
—
—
(4
)
—
—
—
Other
—
7
—
(2
)
—
—
Net benefit cost
$
13
$
49
$
5
$
20
$
25
$
35
(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 2006, 2005 and 2004:
Other
Pension Benefits
Postretirement Benefits
2006
2005
2004
2006
2005
2004
(Percent)
(Percent)
Assumptions related to benefit
obligations at September 30:
Discount rate
5.75
5.50
5.50
5.25
Rate of compensation increase
4.00
4.00
Assumptions related to benefit
costs for the year ended December 31:
Discount rate
5.50
5.75
6.00
5.25
5.75
6.00
Expected return on plan
assets(1)
8.00
8.00
8.50
8.00
7.50
7.50
Rate of compensation increase
4.00
4.00
4.00
(1)
The expected return on plan assets
is a pre-tax rate (before a tax rate ranging from
26 percent to 27 percent on other postretirement
benefits) that is primarily based on an expected risk-free
investment return, adjusted for historical risk premiums and
specific risk adjustments associated with our debt and equity
securities. These expected returns were then weighted based on
our target asset allocations of our investment portfolio.
Actuarial estimates for our other postretirement benefit plans
assumed a weighted-average annual rate of increase in the per
capita costs of covered health care benefits of
10.3 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:
2006
2005
(In millions)
One percentage point increase:
Aggregate of service cost and
interest cost
$
1
$
1
Accumulated postretirement benefit
obligation
18
20
One percentage point decrease:
Aggregate of service cost and
interest cost
$
(1
)
$
(1
)
Accumulated postretirement benefit
obligation
(15
)
(18
)
Plan Assets. The following table provides the
target and actual asset allocations in our pension and other
postretirement benefit plans as of September 30:
Pension Plans
Other Postretirement Plans
Asset Category
Target
Actual 2006
Actual 2005
Target
Actual 2006
Actual 2005
(Percent)
(Percent)
Equity
securities(1)
60
66
65
65
63
61
Debt securities
40
33
34
35
33
32
Other
—
1
1
—
4
7
Total
100
100
100
100
100
100
(1)
During 2005, we liquidated all of
the El Paso common stock included in 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 support the benefit obligations to
participants, retirees and beneficiaries exists. In meeting this
objective, the plans seek to achieve a high level of investment
return consistent with a prudent level of
portfolio risk. Investment objectives are long-term in nature
covering typical market cycles of three to five years. Any
shortfall of investment performance compared to investment
objectives is the result of general economic and capital market
conditions.
Other Matters. During the fourth quarter of
2005, we recorded an increase to our legal reserves of
approximately $350 million associated with a closed group
of retirees of the Case Corporation increasing our total
liability to approximately $379 million at
December 31, 2006. A trial court ruled, which was upheld on
appeal, that we are required to indemnify Case for benefits paid
to these retirees. We estimated our liability under this ruling
utilizing actuarial methods similar to those used in estimating
our obligations associated with our other postretirement benefit
plans; however, these legal reserves are not included in the
disclosures related to our pension and other postretirement
benefits above. For a further discussion of this matter, see
Note 13.
15.
Stockholders’
Equity
Common Stock. In May 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. In 2004, we issued
26.4 million shares to satisfy our obligations under the
Western Energy Settlement.
Convertible Perpetual Preferred Stock. In
April 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 after five
years if our common stock is trading at a premium of
130 percent to the conversion price.
The net proceeds of $723 million from the issuance of the
preferred stock, together with cash on hand, was used to prepay
our Western Energy Settlement of approximately $442 million
and to redeem all of the 6 million outstanding shares of
8.25% Series A cumulative preferred stock of our
subsidiary, EPTP 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 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 2006 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:
2006
2005
Cash flow hedges (see Note 8)
$
80
$
(294
)
Pension and other postretirement
benefits (see Note 14)
(435
)
(49
)
Investments available for sale
12
15
Currency translation adjustment
—
(4
)
Total accumulated other
comprehensive loss, net of income taxes
$
(343
)
$
(332
)
16.
Stock-Based
Compensation
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, 2006, approximately 35 million shares
remain available for grant under our current plans. In addition,
we have approximately 22 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.
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, 2006 is presented below:
Total compensation cost related to non-vested option awards not
yet recognized at December 31, 2006 was approximately
$10 million, which is expected to be recognized over a
weighted average period of 11 months. Options exercised
during the year ended December 31, 2006 had a total
intrinsic value of approximately $5 million, generated
$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 years ended
December 31, 2005 and 2004.
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 31,2006, 2005 and 2004 the weighted average grant date fair value
per share of options granted was $4.89, $3.88 and $2.69. Listed
below is the weighted average of each assumption based on grants
in each fiscal year:
2006
2005
2004
Expected Term in Years
6.0
4.8
5.4
Expected Volatility
38
%
42
%
45
%
Expected Dividends
1.3
%
1.5
%
2.1
%
Risk-Free Interest Rate
4.9
%
3.7
%
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 No. 107 and estimate the
expected term of our option awards based on the vesting period
and average remaining contractual term.
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 and performance-based
restricted share awards. 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 2006, 2005 and 2004 was $13.09,
$10.78 and $8.63. The total fair value of shares vested during
2006, 2005 and 2004 was $23.6 million, $14.3 million
and $6.7 million.
During 2006, 2005 and 2004, we recognized approximately
$17 million, $18 million and $23 million of
pre-tax compensation expense, capitalized approximately
$2 million in each year as part of fixed assets and
recorded $6 million, $6 million and $8 million of
income tax benefits related to restricted stock arrangements.
The total unrecognized compensation cost related to these
arrangements at December 31, 2006 was approximately
$22 million, which is expected to be recognized over a
weighted average period of 11 months. Upon adoption of
SFAS No. 123(R), we recorded a cumulative effect of a
change in accounting principle of less than $1 million as a
result of estimating forfeitures for restricted stock on the
date of grant as compared to recognizing forfeitures as they
occur. We also reclassified unearned compensation as additional
paid-in capital on our balance sheet as required by
SFAS No. 123(R).
Employee Stock Purchase Plan. In July 2005, we
reinstated our employee stock purchase plan under
Section 423 of the Internal Revenue Code. The amended and
restated plan allows participating employees the right to
purchase our common stock 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 2006, 2005 and 2004.
17.
Business
Segment Information
As of December 31, 2006, our business consists of
Pipelines, Exploration and Production, Marketing and Power
segments. Prior to 2006, we also had a Field Services segment.
We have reclassified certain operations as discontinued
operations for all periods presented (see Notes 1 and 2).
Our segments are strategic business units that provide a variety
of energy products and services. They are managed separately as
each segment requires different technology and marketing
strategies. Our corporate operations include our general and
administrative functions, 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, 2006, we conducted
our activities primarily through eight wholly owned and five
partially owned interstate transmission systems along with five
underground natural gas storage entities and an LNG terminalling
facility. In February 2007, we sold ANR, our Michigan storage
facilities and our 50 percent interest in Great Lakes Gas
Transmission.
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. Focuses on marketing and managing
the price risks associated with our natural gas and oil
production as well as the management of our remaining historical
trading portfolio.
Power. Primarily consists of our remaining
international power assets. Historically, this segment also had
domestic power activities. We have completed the sale of our
domestic power facilities and sold or announced the sale of
substantially all of our international operations, except for
Brazil. Our primary focus within the Power segment is to manage
the risks associated with our remaining assets in Brazil.
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 2006, 2005 and 2004.
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 as well as substantial investments in unconsolidated
affiliates. We believe EBIT is useful to our investors because
it allows them to more effectively evaluate our 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 extraordinary items,
discontinued operations and the impact of accounting changes,
(ii) income taxes, (iii) interest and debt expense
(iv) distributions on preferred interests of consolidated
subsidiaries and (v) preferred dividends. Also, we exclude
interest and debt expense and distributions on preferred
interests of consolidated subsidiaries so that investors may
evaluate our operating results without regard to our financing
methods or capital structure. EBIT may not be comparable to
measures used by other companies. Additionally, EBIT should be
considered in conjunction with net income and other performance
measures such as operating
income or operating cash flow. Below is a reconciliation of our
EBIT to our income (loss) from continuing operations for the
three years ended December 31:
2006
2005
2004
(In millions)
Segment EBIT
$
1,838
$
979
$
591
Corporate and other
(88
)
(521
)
(217
)
Interest and debt expense
(1,228
)
(1,286
)
(1,497
)
Distributions on preferred
interests of consolidated subsidiaries
—
(9
)
(25
)
Income taxes
9
331
116
Income (loss) from continuing
operations
$
531
$
(506
)
$
(1,032
)
The following tables reflect our segment results as of and for
each of the three years ended December 31:
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.
(3)
Excludes assets of discontinued
operations of $4,133 million (see Note 2).
(4)
Of total foreign assets,
approximately $362 million 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.
(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 $324 million relates to property, plant and
equipment and approximately $1.0 billion relates to
investments in and advances to unconsolidated affiliates.
(6)
Amounts are net of third party
reimbursements of our capital expenditures and returns of
invested capital.
Capital expenditures, and
investments in and advances to unconsolidated affiliates,
net(6)
895
728
—
26
(15
)
10
1,644
Total investments in
unconsolidated affiliates
708
6
—
1,225
305
6
2,250
(1)
Includes eliminations of
intercompany transactions. Our intersegment revenues, along with
our intersegment operating expenses, were incurred in the normal
course of business between our operating segments. We recorded
an intersegment revenue elimination of $236 million and an
operation and maintenance expense elimination of
$25 million, which is included in the “Corporate”
column, to remove intersegment transactions.
(2)
Revenues from external customers
include gains and losses related to our hedging of price risk
associated with our natural gas and oil production. Intersegment
revenues represent sales to our Marketing segment, which is
responsible for marketing our production.
(3)
Relates to intercompany activities
between our continuing operations and our discontinued
operations.
(4)
Excludes assets of discontinued
operations of $5,398 million.
(5)
Of total foreign assets,
approximately $435 million relates to property, plant and
equipment and approximately $1.5 billion relates to
investments in and advances to unconsolidated affiliates.
(6)
Amounts are net of third party
reimbursements of our capital expenditures and returns of
invested capital.
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, 2006
and 2005, our investment balance exceeded the net equity in the
underlying net assets of these investments by $409 million
and $378 million due to these items. The largest 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 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
2006
2005
2006
2005
2006
2005
2004
(Percent)
(In millions)
(In millions)
Domestic:
Four
Star(1)
43
43
$
723
$
754
$
10
$
19
$
—
Citrus
50
50
597
596
62
66
65
Enterprise Products
Partners(2)
—
—
—
—
—
183
6
GulfTerra Energy
Partners(2)
—
—
—
—
—
—
601
Midland Cogeneration
Venture(2)
—
44
—
—
13
(162
)
(171
)
Javelina(2)
—
—
—
—
—
121
15
Other Domestic Investments
various
various
36
47
3
17
22
Total domestic
1,356
1,397
88
244
538
Foreign:
Araucaria
Power(2)
—
60
—
187
2
—
—
Bolivia to Brazil Pipeline
8
8
105
96
11
20
24
San Fernando Pipeline
50
50
57
53
16
14
13
Habibullah
Power(3)(4)
50
50
17
16
1
(13
)
(46
)
Manaus/Rio
Negro(5)
100
100
96
114
17
19
—
Saba Power
Company(3)
94
94
—
—
—
(7
)
(51
)
Porto
Velho(4)
50
50
(34
)
(32
)
2
(16
)
(6
)
Korea Independent Energy
Corporation(2)
—
—
—
—
—
127
22
EGE
Itabo(2)
—
25
—
24
1
(58
)
1
Other Foreign
Investments(4)
various
various
110
310
7
(49
)
(16
)
Total foreign
351
768
57
(37
)
(59
)
Total investments in unconsolidated
affiliates
$
1,707
$
2,165
Total earnings from unconsolidated
affiliates
$
145
$
281
$
479
(1)
Amortization of our purchase cost
in excess of the underlying net assets of Four Star was
$54 million and $20 million during 2006 and 2005.
(2)
We sold our interests in these
investments.
(3)
We have received approval from our
Board of Directors to sell our interest in these investments,
substantially all of which are targeted to close in the first
half of 2007.
(4)
As of December 31, 2006 and
2005, we had outstanding advances and receivables of
$413 million and $385 million related to our foreign
investments of which $25 million and $37 million
related to our investment in Habibullah Power, $350 million
and $331 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 $46 million, $47 million
and $44 million in 2006, 2005 and 2004.
(5)
We deconsolidated these 100% owned
investments in January 2005 upon entering into an agreement that
will transfer ownership of these plants to the power purchaser
in January 2008.
Impairment charges and gains and losses on sales of equity
investments are included in earnings from unconsolidated
affiliates. During 2006, 2005 and 2004, 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 realized gains
(losses) consisted of the following:
Investment or Group
2006
2005
2004
(In millions)
Midland Cogeneration
Venture(1)
$
13
$
(162
)
$
(161
)
Asia power investments
(8
)
(64
)
(182
)
Central and South American power
investments
1
(89
)
—
Domestic power plants
—
—
(44
)
Enterprise/GulfTerra
—
183
507
Javelina
—
111
—
KIECO
—
108
—
Other
—
4
4
$
6
$
91
$
124
(1)
Amounts represent an impairment of
our investment in 2004, recording 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.
Below is summarized financial information of our proportionate
share of the operating results and financial position of our
unconsolidated affiliates, including those in which we hold
greater than a 50 percent interest.
Includes net income of
$20 million, $15 million and $7 million in 2006,
2005 and 2004, related to our proportionate share of affiliates
in which we hold greater than a 50 percent interest.
(2)
Includes total assets of
$417 million, and $485 million as of December 31,2006 and 2005 related to our proportionate share of affiliates
in which we hold greater than a 50 percent interest.
We received distributions and dividends of $177 million and
$203 million in 2006 and 2005, which includes
$38 million and less than $1 million of returns of
capital, from our investments.
The following table shows revenues and charges resulting from
transactions with our unconsolidated affiliates:
2006
2005
2004
(In millions)
Operating
revenue(1)
$
64
$
114
$
194
Other revenue —
management
fees(2)
—
—
3
Cost of
sales(2)
3
7
90
Reimbursement for operating
expenses(2)
—
—
93
Other income
6
9
8
Interest income
46
47
44
(1)
Decrease primarily due to the sale
of investments in our Power segment.
(2)
Decrease in activity during 2005 is
due primarily to the sale of GulfTerra during 2004.
Accounts Receivable Sales Program. During the
third quarter of 2006, we entered into 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, 2006, we sold
approximately $202 million of receivables, received cash of
approximately $108 million, received subordinated
beneficial interests of approximately $91 million, and
recognized a loss of approximately $3 million. In
conjunction with the sale, the QSPEs also issued senior
beneficial interests on the receivables sold to a third party
financial institution, which totaled $111 million on the
closing date. 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 year ended
December 31, 2006.
Matters
that Could Impact Our Investments
International Power. As of December 31,2006, we had equity investments in seven 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, 2006:
Porto Velho ($315 million). The
state-owned facility that purchases power generated by the
facility in Brazil has approached us with the opportunity to
potentially sell them our interest in this power plant. Although
we currently have no indications of an impairment of our
investment, as we evaluate this potential opportunity, we could
be required to record a loss based on the potential value we may
receive.
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
consumption of fuel by the power facility under its power
purchase agreement. We believe the tax authority’s claims
are without merit.
Manaus / Rio Negro ($97 million). We have
an agreement to transfer our ownership of this facility in
Brazil to the power purchaser in January 2008.
Asian and Central American power investments
($105 million). We are in the process of
selling these assets. Any changes in the 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.
Domestic Power. During 2006, we completed the
sales of our remaining investments in domestic power facilities.
We continue to supply gas to MCV under natural gas supply
contracts and recorded a loss in the third quarter of
approximately $133 million on these contracts as they were
no longer with an affiliate. Prior to the sale,
we had not recognized the cumulative
mark-to-market
losses on these contracts to the extent of our ownership
interest due to their affiliated nature. To secure our remaining
obligations under these contracts, we have also issued letters
of credit to MCV for approximately $208 million as of
December 31, 2006.
Investment in Bolivia. We own an
8 percent interest in the Bolivia to Brazil pipeline. As of
December 31, 2006, our total investment and guarantees
related to this pipeline project were 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 recent political events in Bolivia could have on the
Bolivia to Brazil pipeline. 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, 2006, our total investment in this pipeline
project was approximately $23 million. 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 decree could have on the Argentina
to Chile pipeline. As new information becomes available or
future material developments arise, we may be required to record
an impairment of our investment.
Citrus. Citrus Trading Corporation (CTC), a
direct subsidiary of Citrus, in which we own a 50 percent
equity interest, settled a lawsuit in January 2007 million
against Spectra LNG Sales, formerly Duke Energy LNG Sales, Inc.,
for wrongful termination of a gas supply contract that had been
entered into by the parties in 1988. Pursuant to the settlement,
Spectra LNG Sales paid CTC $100 million.
Below are unusual or infrequently occurring items, if any, in
each of the respective quarters of 2006 and 2005:
December 31, 2006. (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. (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 5).
June 30, 2006. Income tax benefit of
$34 million associated with IRS audit settlements
(Note 5).
December 31, 2005. (i) $350 million
charge associated with our retiree medical benefits legal
matters (Note 13) and (ii) net gain of approximately
$400 million on the sale of our south Louisiana processing
facilities in discontinued operations.
September 30, 2005. (i) Proportionate
share of our MCV investment’s losses of approximately
$160 million and (ii) a $109 million gain on sale
of Korean power facility.
June 30, 2005. (i) Impairment of our
Macae power facility in discontinued operations of approximately
$300 million, (ii) $160 million of impairments
on our other international power facilities, and (iii)
approximately $70 million of income recorded upon receipt
of payment under a bankruptcy claim.
March 31, 2005. (i) Gain on sale of
remaining investment in Enterprise for $183 million, (ii)
net losses associated with our other international power
facilities of approximately $75 million, (iii) a
$59 million charge associated with finalizing our Western
Energy settlement, and (iv) approximately $30 million in
income tax benefits primarily a result of IRS audit settlements
(see Note 5).
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
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
2005
Natural gas and oil properties:
Costs subject to amortization
$
14,764
$
371
$
15,135
Costs not subject to amortization
384
107
491
15,148
478
15,626
Less accumulated depreciation,
depletion and amortization
10,955
183
11,138
Net capitalized costs
$
4,193
$
295
$
4,488
(1)
Capitalized costs for Egypt were
$4 million as of December 31, 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):
United
Brazil and
States
Egypt
Worldwide
2006
Property acquisition costs
Proved properties
$
2
$
2
$
4
Unproved properties
34
1
35
Exploration costs
323
53
376
Development costs
738
40
778
Costs expended
1,097
96
1,193
Asset retirement obligation costs
3
—
3
Total costs incurred
$
1,100
$
96
$
1,196
2005
Property acquisition costs
Proved properties
$
643
$
8
$
651
Unproved properties
143
1
144
Exploration costs
143
15
158
Development costs
503
6
509
Costs expended
1,432
30
1,462
Asset retirement obligation costs
1
—
1
Total costs incurred
$
1,433
$
30
$
1,463
Unconsolidated investment in Four
Star(1)
$
769
$
—
$
769
2004
Property acquisition costs
Proved properties
$
33
$
69
$
102
Unproved properties
32
3
35
Exploration costs
185
25
210
Development costs
395
1
396
Costs expended
645
98
743
Asset retirement obligation costs
30
3
33
Total costs incurred
$
675
$
101
$
776
(1)
Amount includes $179 million
of deferred income tax adjustments related to the acquisition of
full-cost pool properties and $217 million related to the
acquisition of our unconsolidated investment in Four Star.
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 $50 million, $47 million and
$44 million for the years ended December 31, 2006,
2005, and 2004. We also capitalized interest of
$30 million, $30 million and $22 million for the
years ended December 31, 2006, 2005 and 2004.
In our January 1, 2007 reserve report, the amounts
estimated to be spent in 2007, 2008 and 2009 to develop our
consolidated worldwide proved undeveloped reserves are
$424 million, $473 million and $243 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 2007 and 2008.
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, 2006, pending
determination of proved reserves (in millions):
Includes capitalized interest of
$24 million, $9 million and $1 million for the
years ended December 31, 2006, 2005, and 2004.
Depreciation, Depletion, and Amortization
Rates. Our total amortization expense per Mcfe
for the United States was $2.43, $2.25 and $1.84 in 2006, 2005,
and 2004 and $2.30, $2.33 and $2.02 for Brazil in 2006, 2005 and
2004. Included in our worldwide depreciation, depletion and
amortization expense is accretion expense of $0.07/Mcfe,
$0.10/Mcfe and $0.08/Mcfe for 2006, 2005 and 2004 for the United
States and $0.03/Mcfe in 2006 and $0.01/Mcfe in 2005 and 2004 in
Brazil attributable to SFAS No. 143.
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, 2006 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,
prepared an estimate on 84 percent of our consolidated
natural gas and oil reserves. Additionally, Ryder Scott prepared
an estimate of 80 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.
Includes downward reserve revisions
of approximately 54 Bcfe related to price and positive
reserve revisions of 39 Bcfe related to performance.
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, 2006.
Results of Operations. Results of operations
from producing activities by fiscal year were as follows at
December 31 (in millions):
Brazil
United
and
States
Egypt
Worldwide
2006
Net Revenues
Sales to external customers
$
608
$
41
$
649
Affiliated sales
1,160
(9
)
1,151
Total
1,768
32
1,800
Cost of products and
services(1)
(58
)
—
(58
)
Production
costs(2)
(318
)
(7
)
(325
)
Depreciation, depletion and
amortization
(611
)
(19
)
(630
)
781
6
787
Income tax expense
(281
)
(2
)
(283
)
Results of operations from
producing activities
$
500
$
4
$
504
Equity earnings from
unconsolidated investment in Four
Star(3)
$
10
$
—
$
10
2005
Net Revenues
Sales to external customers
$
466
$
62
$
528
Affiliated sales
1,268
(9
)
1,259
Total
1,734
53
1,787
Cost of products and
services(1)
(47
)
—
(47
)
Production
costs(2)
(253
)
(8
)
(261
)
Depreciation, depletion and
amortization
(567
)
(45
)
(612
)
867
—
867
Income tax expense
(309
)
—
(309
)
Results of operations from
producing activities
$
558
$
—
$
558
Equity earnings from
unconsolidated investment in Four
Star(3)
$
19
$
—
$
19
2004
Net Revenues
Sales to external customers
$
534
$
26
$
560
Affiliated sales
1,175
—
1,175
Total
1,709
26
1,735
Cost of products and
services(1)
(54
)
—
(54
)
Production
costs(2)
(210
)
—
(210
)
Depreciation, depletion and
amortization
(530
)
(18
)
(548
)
915
8
923
Income tax expense
(333
)
(3
)
(336
)
Results of operations from
producing activities
$
582
$
5
$
587
(1)
Cost of products and services
consists primarily of transportation costs.
(2)
Production cost includes lease
operating costs and production related taxes, including ad
valorem and severance taxes.
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):
10% annual discount for estimated
timing of cash flows
(2,004
)
(219
)
(2,223
)
Standardized measure of discounted
future net cash flows
$
3,888
$
308
$
4,196
Standardized measure of discounted
future net cash flows, including effects of hedging activities
$
3,907
$
305
$
4,212
Unconsolidated Investment in
Four
Star(2)
Standardized measure of discounted
future net cash flows
2006
$
323
$
—
$
323
2005
$
617
—
$
617
(1)
United States excludes
$219 million, ($502) million and ($1) million of
future net cash inflows (outflows) attributable to hedging
activities in the years 2006, 2005 and 2004. Brazil excludes
$4 million and $5 million of future net cash outflows
attributable to hedging activities in 2005 and 2004.
For the calculations in the preceding table, estimated future
cash inflows from estimated future production of proved reserves
were computed using year-end prices of $5.64, $10.08, and $6.22
per MMBtu for natural gas and $61.05, $61.04 and $43.35 per
barrel of oil at December 31, 2006, 2005 and 2004. In the
United States, after adjustments for transportation and other
charges, net prices were $5.33 per Mcf of gas, $51.08 per
barrel of oil and $34.36 per barrel of NGL at
December 31, 2006. 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)
2006
2005
2004
(In millions)
Sales and transfers of natural gas
and oil produced net of
production costs
$
(1,516
)
$
(1,477
)
$
(1,470
)
Net changes in prices and
production costs
(2,891
)
2,884
29
Extensions, discoveries and
improved recovery, less related costs
549
793
268
Changes in estimated future
development costs
(55
)
2
4
Previously estimated development
costs incurred during the period
192
247
156
Revision of previous quantity
estimates
(38
)
47
(453
)
Accretion of discount
827
476
568
Net change in income taxes
1,123
(1,093
)
257
Purchases of reserves in place
4
956
114
Sale of reserves in place
(42
)
(83
)
(75
)
Change in production rates, timing
and other
(289
)
(333
)
(94
)
Net change
$
(2,136
)
$
2,419
$
(696
)
(1)
This disclosure reflects changes in
the standardized measure calculation excluding the effects of
hedging activities.
Amounts reflect the
reclassification of discontinued operations.
(2)
In 2006, relates primarily to the
sale of our accounts receivable under an accounts receivable
sales program. In 2005 and 2004, relates primarily to accounts
written off.
(3)
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.
(4)
Relates primarily to payments for
various litigation reserves (including $442 million and
$602 million related to the Western Energy Settlement),
environmental remediation reserves or revenue crediting and rate
settlement reserves.
CHANGES
IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
As previously reported in our Current Report on
Form 8-K
dated April 18, 2006 (as amended on May 9, 2006), our
audit committee appointed Ernst & Young LLP as our
independent registered public accounting firm for the fiscal
year ending December 31, 2006 and dismissed
PricewaterhouseCoopers LLP. During the fiscal years ended
December 31, 2006 and 2005, there were no
“disagreements with our former accountant” or
“reportable events” as defined in
Item 304(a)(1)(iv) and Item 304(a)(1)(v) of
Regulation S-K.
ITEM 9A.
CONTROLS
AND PROCEDURES
Evaluation
of Disclosure Controls and Procedures
As of December 31, 2006, 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 December 31, 2006.
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 2006.
ITEM 9B.
OTHER
INFORMATION
On February 22, 2007, we closed the previously announced
sale of ANR Pipeline Company, our Michigan storage assets, and
our 50 percent interest in Great Lakes Gas Transmission to
TransCanada Corporation and TC Pipelines, LP. The sales price
was approximately $4.1 billion, which included an
assumption of $475 million of debt by the buyer. We have
presented these operations as discontinued operations in this
Form 10-K
which satisfies our requirement to provide pro forma financial
information related to this sale under Item 9.01 (b)
(1) of
Form 8-K.
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 2007 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 2006, 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 2007 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 2007 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 2007 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 2007 Annual Meeting
of Stockholders is incorporated herein by reference.
The following consolidated financial statements are included in
Part II, Item 8 of this report:
Page
Reports of Independent Registered
Public Accounting Firms
79
Consolidated Statements of Income
84
Consolidated Balance Sheets
85
Consolidated Statements of Cash
Flows
87
Consolidated Statements of
Stockholders’ Equity
88
Consolidated Statements of
Comprehensive Income
89
Notes to Consolidated Financial
Statements
90
2.
Financial statement schedules and
supplementary information required to be submitted
Schedule II —
Valuation and Qualifying Accounts
148
3.
Exhibits
154
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, 2007.
EL PASO CORPORATION
By
/s/ Douglas
L. Foshee
Douglas L. Foshee
President and Chief Executive
Officer
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:
Signature
Title
Date
/s/ Douglas
L. Foshee
Douglas
L. Foshee
President, Chief Executive Officer
and Director (Principal Executive Officer)
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).
4
.D
Tenth Supplemental Indenture dated
as of December 28, 2005 between El Paso Corporation
and HSBC Bank USA, National Association, as trustee
(Exhibit 4.A to our
Form 8-K
filed January 4, 2006).
4
.E
Eleventh Supplemental Indenture
dated as of August 31, 2006, between El Paso
Corporation and HSBC Bank USA, National Association, as trustee
(Exhibit 4.A to our 2006 Third 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
.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);
Amendment No. 1 effective as of July 16, 1999 to the
Stock Option Plan for Non-Employee Directors
(Exhibit 10.G.1 to our 2004
Form 10-K);
Amendment No. 2 effective as of February 7, 2001 to
the Stock Option Plan for Non-Employee Directors
(Exhibit 10.F.1 to our 2001 First Quarter
Form 10-Q);
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); Amendment No. 1 effective as of
February 7, 2001 to the 2001 Stock Option Plan for
Non-Employee Directors (Exhibit 10.G.1 to our 2001
Form 10-K);
Amendment No. 2 effective as of December 4, 2003 to the
2001 Stock Option Plan for Non-Employee Directors
(Exhibit 10.H.1 to our 2003
Form 10-K);
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 (Exhibit 10.1
to our
Form S-8
filed May 20, 1999); Amendment No. 1 effective as of
February 7, 2001 to the 1999 Omnibus Incentive Compensation
Plan (Exhibit 10.V.1 to our 2001 First Quarter
Form 10-Q);
Amendment No. 2 effective as of May 1, 2003 to the 1999
Omnibus Incentive Compensation Plan (Exhibit 10.I.1 to our
2003 Second Quarter
Form 10-Q);
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).
2001 Omnibus Incentive
Compensation Plan effective as of January 29, 2001
(Exhibit 10.1 to our
Form S-8
filed June 29, 2001); Amendment No. 1 effective as of
February 7, 2001 to the 2001 Omnibus Incentive Compensation
Plan (Exhibit 10.J.1 to our 2001
Form 10-K);
Amendment No. 2 effective as of April 1, 2001 to the 2001
Omnibus Incentive Compensation Plan (Exhibit 10.J.1 to our
2002
Form 10-K);
Amendment No. 3 effective as of July 17, 2002 to the
2001 Omnibus Incentive Compensation Plan (Exhibit 10.J.1 to
our 2002 Second Quarter
Form 10-Q);
Amendment No. 4 effective as of May 1, 2003 to the
2001 Omnibus Incentive Compensation Plan (Exhibit 10.J.1 to
our 2003 Second Quarter
Form 10-Q);
Amendment No. 5 effective as of March 8, 2004 to the
2001 Omnibus Incentive Compensation Plan (Exhibit 10.K.1 to our
2003
Form 10-K);
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 (Exhibit 10.K
to our 2001
Form 10-K);
Amendment No. 1 effective as of November 7, 2002 to
the Supplemental Benefits Plan (Exhibit 10.K.1 to our 2002
Form 10-K);
Amendment No. 2 effective as of June 1, 2004 to the
Supplemental Benefits Plan (Exhibit 10.L.1 to our 2004
Form 10-K);
Amendment No. 3 effective December 17, 2004 to the
Supplemental Benefits Plan (Exhibit 10.UU to our 2004 Third
Quarter
Form 10-Q);
Amendment No. 4 to the Supplemental Benefits Plan effective
as of December 31, 2004 (Exhibit 10.I.1 to our 2005
Form 10-K).
+10
.H
Senior Executive Survivor Benefit
Plan Amended and Restated effective as of August 1, 1998
(Exhibit 10.M to our 2004
Form 10-K);
Amendment No. 1 effective as of February 7, 2001 to
the Senior Executive Survivor Benefit Plan (Exhibit 10.I.1
to our 2001 First Quarter
Form 10-Q);
Amendment No. 2 effective as of October 1, 2002 to the
Senior Executive Survivor Benefit Plan (Exhibit 10.L.1 to
our 2002
Form 10-K).
+10
.I
Key Executive Severance Protection
Plan Amended and Restated effective as of August 1, 1998
(Exhibit 10.N to our 2004
Form 10-K);
Amendment No. 1 effective as of February 7, 2001 to
the Key Executive Severance Protection Plan (Exhibit 10.K.1
to our 2001 First Quarter
Form 10-Q);
Amendment No. 2 effective as of November 7, 2002 to
the Key Executive Severance Protection Plan (Exhibit 10.N.1
to our 2002
Form 10-K);
Amendment No. 3 effective as of December 6, 2002 to
the Key Executive Severance Protection Plan (Exhibit 10.N.1
to our 2002
Form 10-K);
Amendment No. 4 effective as of September 2, 2003 to
the Key Executive Severance Protection Plan (Exhibit 10.N.1
to our 2003 Third Quarter
Form 10-Q).
+10
.J
2004 Key Executive Severance
Protection Plan effective as of March 9, 2004
(Exhibit 10.P to our 2003
Form 10-K).
+10
.K
Director Charitable Award Plan
Amended and Restated effective as of August 1, 1998
(Exhibit 10.P to our 2004
Form 10-K);
Amendment No. 1 effective as of February 7, 2001 to
the Director Charitable Award Plan (Exhibit 10.L.1 to our
2001 First Quarter
Form 10-Q);
Amendment No. 2 effective as of December 4, 2003 to
the Director Charitable Award Plan (Exhibit 10.Q.1 to our
2003
Form 10-K).
+10
.L
Strategic Stock Plan Amended and
Restated effective as of December 3, 1999
(Exhibit 10.1 to our
Form S-8
filed January 14, 2000); Amendment No. 1 effective as
of February 7, 2001 to the Strategic Stock Plan
(Exhibit 10.M.1 to our 2001 First Quarter
Form 10-Q);
Amendment No. 2 effective as of November 7, 2002 to the
Strategic Stock Plan; Amendment No. 3 effective as of
December 6, 2002 to the Strategic Stock Plan and Amendment
No. 4 effective as of January 29, 2003 to the
Strategic Stock Plan (Exhibit 10.P.1 to our 2002
Form 10-K);
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);
Termination of the Executive Award Plan of Sonat Inc.
(Exhibit 10.K.1 to our 2000 Second Quarter
Form 10-Q);
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).
Omnibus Plan for Management
Employees Amended and Restated effective as of December 3,1999 (Exhibit 10.1 to our
Form S-8
filed December 18, 2000); Amendment No. 1 effective as
of December 1, 2000 to the Omnibus Plan for Management
Employees (Exhibit 10.1 to our
Form S-8
filed December 18, 2000); Amendment No. 2 effective as
of February 7, 2001 to the Omnibus Plan for Management
Employees (Exhibit 10.U.1 to our 2001 First Quarter
Form 10-Q);
Amendment No. 3 effective as of December 7, 2001 to
the Omnibus Plan for Management Employees (Exhibit 10.1 to
our
Form S-8
filed February 11, 2002); Amendment No. 4 effective as
of December 6, 2002 to the Omnibus Plan for Management
Employees (Exhibit 10.T.1 to our 2002
Form 10-K);
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; Supplement
No. 1 to the Severance Pay Plan effective as of
January 1, 2003; and Amendment No. 1 to Supplement
No. 1 effective as of March 21, 2003
(Exhibit 10.Z to our 2003 First Quarter
Form 10-Q);
Amendment No. 2 to Supplement No. 1 effective as of
June 1, 2003 (Exhibit 10.Z.1 to our 2003 Second Quarter
Form 10-Q);
Amendment No. 3 to Supplement No. 1 effective as of
September 2, 2003 (Exhibit 10.Z.1 to our 2003 Third
Quarter
Form 10-Q);
Amendment No. 4 to Supplement No. 1 effective as of
October 1, 2003 (Exhibit 10.W.1 to our 2003
Form 10-K);
Amendment No. 5 to Supplement No. 1 effective as of
February 2, 2004 (Exhibit 10.W.1 to our 2003
Form 10-K);
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
.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).
+10
.S
Letter Agreement dated
December 18, 2003 between El Paso and Douglas L.
Foshee (Exhibit 10.BB.1 to our 2003
Form 10-K).
+10
.T
Form of Indemnification Agreement
of each member of the Board of Directors effective
November 7, 2002 or the effective date such director was
elected to the Board of Directors, whichever is later
(Exhibit 10.FF to our 2002
Form 10-K).
+10
.U
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 (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
.Z
El Paso Corporation 2005
Omnibus Incentive Compensation Plan (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
.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).
2005 Supplemental Benefits Plan
effective as of January 1, 2005 (Exhibit 10.KK to our
2005
Form 10-K).
10
.CC
Credit Agreement among
El Paso Corporation and El Paso Production
Oil & Gas USA, L.P., as Borrowers, Fortis Capital
Corp., as Administrative Agent, Arranger and Bookrunner, dated
as of November 3, 2005 (Exhibit 10.A to our
Form 8-K
filed November 4, 2005); First Amendment, Consent and
Waiver Agreement, dated as of December 20, 2005, among
El Paso Corporation and El Paso Production
Oil & Gas USA, L.P., as Borrowers, Fortis Capital
Corp., as Administrative Agent for the Lenders, and the several
Lenders party from time to time thereto (Exhibit 10.B to
our
Form 8-K
filed January 4, 2006).
10
.DD
Amended and Restated Credit
Agreement dated as of July 31, 2006, among El Paso
Corporation, Colorado Interstate Gas Company, El Paso
Natural Gas Company, Tennessee Gas Pipeline Company, 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 August 2, 2006).
10
.EE
Amended and Restated Security
Agreement dated as of July 31, 2006, made by El Paso
Corporation, Colorado Interstate Gas Company, 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 August 2, 2006).
*10
.EE.1
Amendment No. 1 dated as of
January 19, 2007 to the Amended and Restated Credit
Agreement dated as of July 31, 2006 among El Paso
Corporation, Colorado Interstate Gas Company, El Paso Natural
Gas Company, Tennessee Gas Pipeline Company, the several banks
and other financial institutions from time to time parties
thereto, and JPMorgan Chase Bank, N.A., as administrative agent
and as collateral agent.
10
.FF
Amended and Restated Parent
Guarantee Agreement dated as of July 31, 2006, made by
El Paso Corporation, in favor of JPMorgan Chase Bank, N.A.,
as Collateral Agent. (Exhibit 10.C to our
Form 8-K
filed August 2, 2006).
10
.GG
Amended and Restated Subsidiary
Guarantee Agreement dated as of July 31, 2006, made by each
of the Subsidiary Guarantors in favor of JPMorgan Chase Bank,
N.A., as Collateral Agent. (Exhibit 10.D to our
Form 8-K
filed August 2, 2006).
10
.HH
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
.II
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
.JJ
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.
